Stone Energy (SGY) 424B3 Prospectus supplement

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.

• 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.

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 SUPPLEMENTALNON-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 andnon-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 materialnon-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 ofnon-GAAP financial information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—SupplementalNon-GAAP Measure.”

PV-10 is anon-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 ofPV-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 neitherPV-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 fromthird-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 REGARDINGFORWARD-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 tosub-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 inbook-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 expectedpre-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 thesix-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 such12-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 asnon-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 inoil-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 ofblow-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 orshut-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 tore-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 ournon-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 sincemid-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 significantshut-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”). TheHP-I interconnects the Phoenix Field through a production buoy that can be disconnected if theHP-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 theHP-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 anddry-dock theHP-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, theHP-I was disconnected from the production buoy and released for dry dock for 28 days. Upon completion of the dry dock, theHP-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 theHP-I to the Phoenix Field for a further five days. Once the buoy was connected, Phoenix Field production remainedshut-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 theHP-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.

TheHP-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, theHP-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 theHP-I could return to the Phoenix Field. During such time period, we would not be able to produce the Phoenix Field. In the event theHP-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 assub-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 anon-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 trailing12-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 theZama-1 well. Data from theZama-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 theZama-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 orshut-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 historical12-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% werenon-producing. Any or all of our proved undeveloped or proved developednon-producing reserves may not be ultimately developed or produced. Furthermore, any or all of our undeveloped and developednon-producing reserves may not be ultimately produced during the time periods we plan or at the costs we budget, which could result in thewrite-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 theshut-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 ournon-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 otherpredecessors-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 ournon-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 fromnon-U.S. operations, we may be subject to the exclusive jurisdiction of courts outside the United States or may not be successful in subjectingnon-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 identifylow-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 ournon-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 somenon-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 othernon-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 theshut-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 LawNo. 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 ofcap-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, certainnon-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 theover-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 theend-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, theend-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 commercialend-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 othernon-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 developednon-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 developednon-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 isshut-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 makenon-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 ournon-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 futurenon-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 ournon-guarantor subsidiaries, thesenon-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 thesenon-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 ournon-U.S. subsidiaries or certain other excluded subsidiaries. Thesenon-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 anynon-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 aone-year period prior to a bankruptcy filing or within 90 days for anynon-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 fornon-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 fornon-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 a180-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 anydebtor-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 apari 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 orpari 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 proposeddebtor-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, thedebtor-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 fornon-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., SECno-action letter (April 13, 1988), Morgan Stanley & Co. Inc., SECno-action letter (June 5, 1991) and Shearman & Sterling, SECno-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 ASU2015-03,Interest—Imputation of Interest (Subtopic835-30):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 anearn-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 theearn-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 anearn-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 makeyear-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. Anynon-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 theHP-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 aremarked-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 theHP-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 theHP-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 theHP-I. Since theHP-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 theHP-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, anon-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 theT-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 theHP-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 theHP-I agreement to process hydrocarbons produced from the Phoenix Field. As a result of amortization of the capital lease liability under theHP-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.

SupplementalNon-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 andnon-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 materialnon-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 aphase-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 securingphased-in compliance in three approximately equal installments during aone-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 tore-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 bynon-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 theHP-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 anon-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 onnon-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 tostate-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 tore-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 aPV-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, ReleaseNos. 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 onyear-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 thesub-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.

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, theHP-I. TheHP-I interconnects with the Phoenix Field through a production buoy that can be disconnected if theHP-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 threeshut-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 theB-5 andB-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 theB-5 andB-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 theHP-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 fiveshut-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 andgas-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 sixshut-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 twoshut-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 MexicoZama-1 exploration well in Block 7, reaching a total depth of 13,480 feet. TheZama-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 anoil-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 theZama-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 recoverablein-kind at a rate of 125% of costs from future production volumes. Production volumes are allocatedin-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%.

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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 DevelopedNon-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 DevelopedNon-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 DevelopedNon-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 DevelopedNon-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 DevelopedNon-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 onyear-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 anon-GAAP financial measure. We believe that the presentation ofPV-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 neitherPV-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 averagefirst-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 toPV-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 theZama-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 and various PUD locations in the shelf. Future development costs associated with our PUD reserves at December 31, 2017 totaled approximately $447.7 million. When considering capital expenditures associated with other exploration projects and abandonment obligations, we expect to fund the development of PUD reserves using cash flows from operations and, if needed, availability under the Bank Credit Facility, in each future annual period prior to the five year expiration. Our 2018 drilling program includes development of PUD reserves, and the conversion rate may not be uniform due to obligatory wells, newly acquired PUD reserves and production performance targets.

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Internal Controls over Reserve Estimates and Reserve Estimation Procedures

At December 31, 2017 and 2016, proved and probable oil, natural gas and NGL reserves attributable to our net interests in oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists, as described in further detail below. At December 31, 2015, proved oil, natural gas and NGL reserves attributable to our net interests in legacy oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers and audited by Ryder Scott Company, L.P. (“Ryder Scott”), independent petroleum engineers and geologists. At December 31, 2015, proved oil, natural gas and NGL reserves attributable to our net interests in oil and natural gas properties acquired in the GCER Acquisition (as defined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting the Comparability of our Financial Condition and Results of Operations—Acquisition History”) and selected Gulf of Mexico Shelf oil and natural gas assets from Stone Energy and its subsidiary, Stone Energy Offshore, L.L.C. acquired in 2014 (the “Stone Acquisition”) were estimated and compiled for reporting purposes by our reservoir engineers and audited by NSAI. For additional information regarding the GCER Acquisition and Stone Acquisition see “Management’s Discussion and Analysis of Financial Conditions and Results of Operations—Factors Affecting the Comparability of our Financial Condition and Results of Operations.”

We are responsible for the adequacy and accuracy of those estimates. These reserve audits included detailed reviews of 100% of our fields and proved reserves and, with respect to the 2016 and 2017 audits, probable reserves.

Our policies regarding internal controls over the determination of reserves estimates require reserves to be in compliance with the Society of Petroleum Engineers (“SPE”) auditing standards for reserve categorization and future producing rates, using the definitions for proved reserves set forth in RegulationS-X Rule4-10(a) and subsequent SEC staff interpretations and guidance. These internal controls, which are intended to ensure reliability of our reserves estimations, include, but are not limited to, the following:

• Reserve information, as well as models used to estimate such reserves, is stored on secure database applications to which only authorized personnel are given access rights consistent with their assigned job function.

• A comparison of historical expenses is made to the lease operating costs in the reserve database.

• Internal reserves estimates are reviewed by well and by area by our reservoir engineers. A variance analysis by well to the previousyear-end reserve report is performed.

• Reserve estimates are reviewed and approved by certain members of senior management, including our President and Chief Executive Officer.

• We engaged NSAI to perform an independent audit of our processes and the reasonableness of our estimates of 100% of our estimates of proved and probable reserves at December 31, 2017 and 2016 and the proved reserves acquired in the Stone Acquisition and GCER Acquisition at December 31, 2015. Our management requires that the independent petroleum engineers and geologist’s and our reserve quantities and calculation of the net present value of the reserves, collectively, vary by no more than 10% in the aggregate, in accordance with SPE auditing standards.

• We engaged Ryder Scott to perform an independent audit of our processes and the reasonableness of our estimates of 100% of our estimates of proved reserves at December 31, 2015, excluding proved reserves acquired in the Stone Acquisition and GCER Acquisition. Our management requires that the independent petroleum engineers and geologist’s and our reserve quantities and calculation of the net present value of the reserves, collectively, vary by no more than 10% in the aggregate, in accordance with SPE auditing standards.

• Data is transferred to NSAI and Ryder Scott through a secure file transfer protocol site.

• Material reserve variances are discussed among NSAI and Ryder Scott, as applicable, our internal reservoir engineers and our Director of Reserves to ensure the best estimate of remaining reserves.

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Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil, natural gas and NGLs that are ultimately recovered.

In the conduct of the reserves audit, NSAI and Ryder Scott did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil, natural gas and NGL production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of NSAI or Ryder Scott that brought into question the validity or sufficiency of any such information or data, NSAI and Ryder Scott did not rely on such information or data until they had satisfactorily resolved their questions relating thereto or had independently verified such information or data. When compared on a well by well basis, some of our estimates are greater and some are less than the estimates of NSAI and Ryder Scott. Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and external estimates are to be expected. Each of NSAI and Ryder Scott determined that its estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule4-10(a)(24) of RegulationS-X. NSAI and Ryder Scott issued unqualified audit opinions on our reserves as of December 31, 2017, 2016 and 2015 based upon their evaluations. NSAI and Ryder Scott concluded that our estimates of reserves were, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE. The NSAI and Ryder Scott reports are included as exhibits to the registration statement of which this prospectus forms a part.

Qualifications of Primary Internal Engineer

Floyd Bone, our Director of Reserves, is the technical person primarily responsible for overseeing the preparation of our internal reserve estimates and for coordinating reserve audits conducted by NSAI and Ryder Scott. Mr. Bone has over 43 years of industry experience with positions of increasing responsibility, including over 36 years as a reserves evaluator or manager. Mr. Bone’s further professional qualifications include a State of Texas Professional Engineering License, extensive internal and external reserve training and asset evaluation. In addition, Mr. Bone is an active participant in industry reserve seminars and professional industry groups, and has been a member of the SPE for over 43 years. Mr. Bone reports directly to our President and Chief Executive Officer.

Technologies Used in Reserve Estimation

The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and/or NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reservoir engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of our reserves is a function of:

• the quality and quantity of available data and the engineering and geological interpretation of that data;

• estimates regarding the amount and timing of future operating costs, development costs and workovers, all of which may vary considerably from actual results;

• future prices of oil, natural gas and NGLs, which may vary considerably from those mandated by the SEC; and

• the judgment of the persons preparing the estimates.

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Drilling Activity

The following table sets forth our drilling activity:

	Year Ended December 31,
	2017				2016				2015
	Gross		Net		Gross		Net		Gross		Net
Productive wells drilled:
Development		—		—		—		—		2.0		1.3
Exploratory(1)		5.0		4.0		1.0		0.7		1.0		0.3
Total		5.0		4.0		1.0		0.7		3.0		1.6
Dry wells drilled:
Development		—		—		—		—		—		—
Exploratory		—		—		—		—		2.0		1.2
Total		—		—		—		—		2.0		1.2

(1) Includes 1.0 gross (0.4 net) exploratory well drilled, but not completed, in Mexico during 2017.

Productive Wells

The number of our productive wells is as follows:

	December 31, 2017
	Gross		Net
Crude oil		104.0		85.5
Natural gas		55.0		37.0
Total		159.0		122.5

Acreage

Gross and net developed and undeveloped acreage is as follows:

	December 31, 2017
	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
United States
Deepwater		60,059		42,086		28,255		26,239		88,314		68,325
Shelf		242,454		177,467		137,090		132,768		379,544		310,235
Total United States		302,513		219,553		165,345		159,007		467,858		378,560
Mexico		—		—		162,904		64,224		162,904		64,224
Total		302,513		219,553		328,249		223,231		630,762		442,784

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Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether or not such acreage contains proved reserves. Included within undeveloped acreage are those leased acres (held by production under the terms of a lease) that are not within the spacing unit containing, or acreage assigned to, the productive well holding such lease. The terms of our leases on undeveloped acreage as of December 31, 2017 were scheduled to expire as shown in the table below (the terms of which may be extended by drilling and production operations):

	Undeveloped Acreage(1)
	Gross		Net
2018		41,645		41,544
2019		222,163		123,482
2020		20,000		20,000
2021		—		—
2022 and beyond		44,441		38,205
Total		328,249		223,231

(1) We have not attributed any PUD reserves to undeveloped acreage for which the lease expiration date precedes the scheduled date for PUD drilling. In addition, we do not anticipate material delay rental or lease extension payments in connection with such acreage.

Crude Oil, Natural Gas and NGL Production, Prices and Production Costs

Our production volumes, average sales prices and average production costs are as follows:

	Year Ended December 31,
	2017			2016			2015
Production Volumes:
Crude oil (MBbls)		7,048			5,126			5,161
Natural gas (MMcf)		16,308			19,001			21,458
NGLs (MBbls)		706			603			588
Total (MBoe)(1)		10,472			8,896			9,325
Percent of Boe from crude oil(1)		67	%		58	%		55	%
Average Sales Price (including commodity derivatives):
Crude oil (MBbls)	$	52.46		$	68.46		$	78.42
Natural gas (MMcf)	$	2.93		$	3.24		$	3.56
NGLs (MBbls)	$	23.59		$	15.81		$	17.90
Total (MBoe)(1)	$	41.46		$	47.44		$	52.72
Average Sales Price (excluding commodity derivatives):
Crude oil (MBbls)	$	48.92		$	38.55		$	47.31
Natural gas (MMcf)	$	3.00		$	2.25		$	2.56
NGLs (MBbls)	$	23.59		$	15.81		$	17.90
Total (MBoe)(1)	$	39.18		$	28.08		$	33.21
Average Production Costs per Boe(1)	$	10.43		$	13.98		$	18.35

(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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Crude Oil, Natural Gas and NGL Production, Prices and Production Costs—Significant Field

The following table sets forth certain information regarding our production volumes, average sales prices and average production costs for the Phoenix Field, which is our only field containing 15% or more of our total estimated proved reserves:

Phoenix Field

	Year Ended December 31,
	2017			2016			2015
Production Volumes:
Crude oil (MBbls)		4,657			2,600			2,302
Natural gas (MMcf)		5,203			3,235			2,789
NGLs (MBbls)		520			312			270
Total (MBoe)(1)		6,044			3,451			3,037
Percent of Boe from crude oil(1)		77	%		75	%		76	%
Average Sales Price (excluding commodity derivatives):
Crude oil (MBbls)	$	48.75		$	37.88		$	47.16
Natural gas (MMcf)	$	3.48		$	2.84		$	3.09
NGLs (MBbls)	$	24.49		$	18.97		$	19.41
Total (MBoe)(1)	$	42.66		$	32.92		$	40.32
Average Production Costs per Boe(1)(2)	$	3.58		$	11.17		$	18.10

(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.

(2) In response to the Tornado II well coming online during the fourth quarter of 2016, we entered into a new production handling agreement (“PHA”) with certain working interest partners. The fees from this PHA were recorded as a reduction to lease operating expense in 2017.

Expenditures and Costs Incurred

For information on property development, exploration and acquisition costs, see Note 12 to our audited historical financial statements included elsewhere in this prospectus.

Title to Properties

We believe that we have satisfactory title to our oil and natural gas properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes and development obligations under oil and natural gas leases. As is customary in the industry in the case of undeveloped properties, often limited investigation of record title is made at the time of acquisition. Title search investigations are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. To the extent title opinions or other investigations reflect defects affecting such undeveloped properties, we are typically responsible for curing any such title defects at our expense.

Price Risk Management Activities

We enter into derivative contracts on our oil and natural gas production primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales. For

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additional information regarding our commodity derivative instruments, see “Management’s Discussion and Analysis of Financial Conditions and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk.”

Significant Customers

Oil and natural gas companies spend capital on exploration, drilling and production operations expenditures, the amount of which is generally dependent on the prevailing view of future oil and natural gas prices which are subject to many external factors which may contribute to significant volatility in future prices. We market substantially all of our oil, natural gas and NGL production from the properties we operate and those we do not operate. Our customers consist primarily of major oil and gas companies, well-established oil and pipeline companies and independent oil and natural gas producers and suppliers. We perform ongoing credit evaluations of our customers and provide allowances for probable credit losses when necessary. For the year ended December 31, 2017, 80% of our oil, natural gas and NGL revenues were attributable to Shell Trading (US) Company, which was the only customer that individually represented 10% or more of our oil, natural gas and NGL revenues.

Competitive Conditions

The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of oil and natural gas leases, equipment and personnel required to find and produce reserves and in the gathering and marketing of oil, natural gas and NGLs. We compete with large integrated oil and natural gas companies as well as independent exploration and production companies. Certain of our competitors may have significantly more financial or other resources available to them. In addition, certain of the larger integrated companies may be better able to respond to industry changes, including price fluctuation, oil and natural gas demand and governmental regulations.

However, we believe our high qualityoil-weighted production base, proven expertise in utilizing seismic technology to identify, evaluate and develop exploitation and exploration opportunities, balanced mix of assets in the Gulf of Mexico deep and shallow waters and significant operating control give us a strong competitive position relative to many of our competitors.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Insurance Matters

Our oil and natural gas operations are subject to risks incident to the operation of oil and gas wells, including but not limited to uncontrolled flows of oil, gas, brine or well fluids into the environment, blowouts, cratering, mechanical difficulties, fires, explosions or other physical damage, pollution or other risks, any of which could result in substantial losses to us. In addition, our oil and natural gas properties are located in the Gulf of Mexico, which makes us more vulnerable to tropical storms and hurricanes. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and the suspension of operations. Damages arising from such occurrences may result in lawsuits asserting large claims. Insurance may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful claim for which we are not fully insured could have a material adverse effect on our financial condition, results of operations and cash flow. Although we obtain insurance against some of these risks, we cannot insure against all possible losses. As a result, any damage or loss not covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flow.

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We have 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. However, not all of our business activities can be insured at the levels we desire because of either limited market availability or unfavorable economics (limited coverage for the underlying cost).

Our general property damage insurance provides varying ranges of coverage based upon several factors, including well counts and the cost of replacement facilities. Our general liability insurance program provides a limit of $250 million for each occurrence and in the aggregate, and includes varying deductibles, our Offshore Pollution Act insurance is also subject to a maximum of up to $150 million for each occurrence and in the aggregate, including a $100,000 retention (100%). Coverage for damage to our assets resulting from a named Gulf of Mexico windstorm, however, is subject to a maximum of $112.5 million per named windstorm and in the aggregate, and is subject to a $25 million per occurrence retention (i.e. $112.5 million limit in excess of $25 million per occurrence). We separately maintain an operators extra expense policy with additional coverage for an amount up to $500 million for Gulf of Mexico deepwater drilling wells, $150 million for Gulf of Mexico shelf drilling wells, $75 million for Gulf of Mexico producing andshut-in wells, $50 million for drilling and workover in inland waters and $25 million for drilling and workover in onshore fields that would cover costs involved in making a well safe after ablow-out or getting the well under control;re-drilling a well to the depth reached prior to the well being out of control or blown out; costs for plugging and abandoning the well; costs forclean-up and containment and for damages caused by contamination and pollution. For our Mexico insurance policies, we maintain $250 million in operators extra expense coverage for operations and $500 million per occurrence and aggregate limit for general liability.

We may increase or decrease insurance coverage around our key strategic assets, including potentially purchasing catastrophic bond instruments. Our highest value assets, which are located in the Phoenix Field, produce through theHP-1 floating production system, which has the capability to disconnect and move away in the event of a storm, mitigating the risk of property damage.

We customarily have reciprocal agreements with our customers and vendors in which each contracting party is responsible for its respective personnel for liability related to work performed for us. Under these agreements, we generally are indemnified against third party claims related to the injury or death of our customers’ or vendors’ personnel, subject to the application of various states’ laws.

Government Regulation

Exploration and development and the production and sale of oil, natural gas and NGLs are subject to extensive federal, state, local and foreign regulations. An overview of these regulations is set forth below. We do not believe that compliance with existing requirements will have a material adverse effect on our financial position, results of operations or cash flows. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or pastnon-compliance with environmental laws or regulations may be discovered. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

General Overview

Our oil and natural gas operations are subject to various federal, state, local and foreign laws and regulations. Generally speaking, these regulations relate to matters that include, but are not limited to:

• location of wells;

• size of drilling and spacing units or proration units;

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• number of wells that may be drilled in a unit;

• unitization or pooling of oil and natural gas properties;

• drilling and casing of wells;

• issuance of permits in connection with exploration, drilling and production;

• well production;

• spill prevention plans;

• protection of private and public surface and ground water supplies;

• emissions permitting or limitations;

• protection of endangered species;

• use, transportation, storage and disposal of fluids and materials incidental to oil and natural gas operations;

• surface usage and the restoration of properties upon which wells have been drilled;

• calculation and disbursement of royalty payments and production taxes;

• requirements for the posting of supplemental bonds or providing other forms of financial assurance for plugging and abandonment obligations;

• plugging and abandoning of wells; and

• transportation of production.

OCS Regulation. Our operations on federal oil and natural gas leases in the Gulf of Mexico are subject to regulation by BSEE and BOEM. These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the Outer Continental Shelf Lands Act (“OCSLA”). These laws and regulations are subject to change, and many new requirements, including those related to safety, permitting and performance, were imposed by BSEE and BOEM subsequent to the April 2010 Deepwater Horizon incident. For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the EPA, lessees must obtain a permit from BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the OCS, calculation of royalty payments and the valuation of production for this purpose, and removal of facilities. These rules are frequently subject to change. 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 ofblow-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”), 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. On October 24, 2017, BSEE announced, in a report published by the Department of the Interior, that it is considering several revisions to the regulations and that it is in the process of determining the most effective way to engage stakeholders in the 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 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 EPA to affect human health and public welfare. Pursuant to the Executive Orders, BOEM is reviewing the proposed air quality rule. On

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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. In addition, under certain circumstances, BSEE may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect our financial condition and operations.

Furthermore, hurricanes in the Gulf of Mexico can have a significant impact on oil and natural gas operations. The effects from past hurricanes have included structural damage to fixed production facilities, semi-submersibles andjack-up drilling rigs. BOEM and BSEE continue to be concerned about the loss of these facilities and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from future storms. In an effort to reduce the potential for future damage, BOEM and BSEE have periodically issued guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures. It is possible that similar, if not more stringent, requirements will be issued by BOEM and BSEE for future hurricane seasons. New requirements, if any, could increase our operating costs and/or capital expenditures.

In addition, in order to cover the various decommissioning obligations of lessees on the OCS, 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 can continue to obtain bonds or other surety in all cases. For example, in a July 2016 NTL, BOEM announced updated financial assurance and risk management requirements for offshore leases. The NTL details procedures to determine a lessee’s ability to carry out its lease obligations—primarily the decommissioning of facilities—and whether to require lessees to furnish additional financial assurance to meet BOEM’s estimate of the lessees decommissioning obligations. The NTL supersedes the agency’s prior practice of allowing operators of a certain net worth to waive the need for supplemental bonds and provides updated criteria for determining a lessee’s ability to self-insure only a small portion of its OCS liabilities based upon the lessee’s financial capacity and financial strength. The NTL also allows lessees to meet their additional financial security requirements pursuant to an individually approved tailored plan, whereby an operator and BOEM agree to set a timeframe for the posting of additional financial assurances. The NTL became effective on September 12, 2016.

We received notice from 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, BOEM rescinded that order and all other sole-liability orders (i.e., orders related to properties for which there is no other current or prior owner who is liable) until further notice. Also, in the first quarter of 2017, BOEM announced that it would extend the implementation timeline for the new NTL by an additional six months. Furthermore, on April 28, 2017, President Trump issued an executive order directing the Secretary of the Interior to review the NTL to determine whether modifications are necessary to ensure operator compliance with lease terms while minimizing unnecessary regulatory burdens. On June 22, 2017, BOEM announced that, pending its review of the NTL, the implementation timeline would be indefinitely extended, subject to certain exceptions.

We remain in active discussions with our government regulators and our industry peers with regard to any future rule making and financial assurance requirements. Notwithstanding BOEM’s July 2016 NTL, BOEM may also bolster 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, including the obligations imposed upon us as a result of the July 2016 NTL, to the extent implemented, as well as any other future BOEM directives, or any other changes to BOEM’s rules applicable to our or our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows, and results of operations.

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Regulation in Shallow Waters Off the Coast of Mexico. Our operations on oil and natural gas blocks in shallow waters off the coast of Mexico’s Veracruz and Tabasco states, and in other Mexican offshore areas where we are assessing other exploration opportunities, are subject to regulation by the Secretariat of Energy (“SENER”), the CNH and other Mexican regulatory bodies. The CNH is responsible for, among other things, overseeing the tender procedures for awarding contracts for the exploration and production of oil and natural gas in Mexican waters, managing and supervising contracts that have been awarded, and approving exploration and production plans. The PSCs that we and our consortium partners have entered into for the development of these acreages contain terms that impose on us the duty to comply with various laws and regulations. These laws and regulations govern, among other things, the exploration and exploitation of hydrocarbons (including certain national content requirements), the treatment, conveyance, marketing, transport and storage of petroleum, and requirements for industrial safety, operational security, and facility decommissioning. Failure to comply can result in the imposition of monetary penalties, revocation of permits, rescission of the relevant PSC, suspension of operations, and ordered decommissioning of offshore facilities and systems. The laws and regulations governing activities in the Mexican energy sector are relatively new, having been significantly reformed in 2013, and the legal regulatory framework continues to evolve as SENER, the CNH and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters.

Environmental Regulations

We are subject to various federal, state, local and foreign regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to, among other things:

• assessing the environmental impact of seismic acquisition, drilling or construction activities;

• the generation, storage, transportation and disposal of waste materials;

• the emission of certain gases into the atmosphere;

• the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations;

• various environmental permitting requirements, such as permits for wastewater discharges;

• the development of emergency response and spill contingency plans; and

• protection of private and public surface and ground water supplies.

Based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and it is possible such expenses will continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters and the cost of compliance could be significant. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, natural resource damages or the issuance of injunctive relief (including orders to cease operations). Both onshore and offshore drilling in certain areas has been opposed by environmental groups and, in certain areas, has been restricted. Moreover, some environmental laws and regulations may impose strict liability, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or third parties. To the extent laws are enacted or other governmental action is taken that prohibits or restricts onshore or offshore drilling or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and financial results could be adversely affected.

We expect to continue making expenditures on a regular basis relating to environmental compliance. We maintain insurance coverage for spills, pollution and certain other environmental risks, although we are not fully

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

Water Discharges. Our discharges into waters of the United States are limited by the federal Clean Water Act (“CWA”) and analogous state laws. The CWA prohibits any discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States, except in compliance with permits issued by federal and state governmental agencies. These discharge permits also include monitoring and reporting obligations. Failure to comply with the CWA, including discharge limits set by permits issued pursuant to the CWA, may also result in administrative, civil or criminal enforcement actions. Violations of the CWA can result suspension, debarment or the imposition of statutory disability, each of which prevents companies and individuals from participating in government contracts and receiving somenon-procurement government benefits. The CWA also requires the preparation of oil spill response plans and spill prevention, control and countermeasure plans.

Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”) holds owners and operators of offshore oil production or handling facilities, including the lessee or permittee of the area where an offshore facility is located, strictly liable for the costs of removing oil discharged into waters of the United States and for certain damages from such spills. OPA assigns joint and several strict liability, without regard to fault, to each liable party for all 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. Although defenses exist to the liability imposed by OPA, they are limited. In addition, BOEM has finalized rules raising OPA’s damages liability cap from $75 million to $134 million. OPA also requires responsible parties to maintain evidence of financial responsibility in prescribed amounts. OPA currently requires a minimum financial responsibility demonstration of between $35 million to $150 million for companies operating on the OCS, although BOEM may increase this amount in certain situations. From time to time, the United States Congress has proposed amendments to OPA raising the financial responsibility requirements. If OPA is amended to increase the minimum level of financial responsibility, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

National Environmental Policy Act. The National Environmental Policy Act (“NEPA”) requires federal agencies, including the Department of the Interior (“DOI”), to consider the impacts their actions have on the human environment, and to prepare detailed statements for major federal actions having the potential to significantly impact the environment. These requirements can lead to additional costs and delays in permitting for operators as the DOI or its bureaus may need to prepare Environmental Assessments (“EA”) and more detailed Environmental Impact Statements (“EIS”) in support of its leasing and other activities that have the potential to significantly affect the quality of the environment. If the EA indicates that no significant impact is likely, then the agency can release a finding of no significant impact and carry on with the proposed action. Otherwise, the agency must then conduct a full-scale EIS. The NEPA process involves public input through comment. These comments, as well as the agency’s analysis of the proposed project, can result in changes to the nature of a proposed project, such as by limiting the scope of the project or requiring resource-specific mitigation. The adequacy of the agency’s NEPA process can be challenged in federal court by process

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participants. This process may result in delaying the permitting and development of projects, and result in increased costs.

Endangered Species Act. The Endangered Species Act (“ESA”) restricts activities that may affect federally identified endangered and threatened species or their habitats. Additionally, the Migratory Bird Treaty Act (“MBTA”) implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. Under the MBTA, the taking, killing or possessing of migratory birds is unlawful without a permit. The Marine Mammal Protection Act similarly prohibits the taking of marine mammals without authorization. We conduct operations on oil and natural gas leases in areas where certain species that are protected by the ESA, MBTA and Marine Mammal Protection Act are known to exist and where other species that potentially could be protected under these statutes. The U.S. Fish and Wildlife Service (the “USFWS”) or the National Marine Fisheries Service may designate critical habitat that it believes is necessary for survival of a threatened or endangered species. A critical habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for oil and natural gas development. These statutes may result in operating restrictions or a temporary, seasonal or permanent ban in affected areas.

Hazardous Substances and Waste Management. The RCRA generally regulates the disposal of solid and hazardous wastes and imposes certain environmental cleanup obligations. Although RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy,” the EPA and state agencies may regulate these wastes as solid wastes. In addition, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. If EPA proposes rulemaking for revised oil and gas regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in increased costs to manage and dispose of generated wastes. Also, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (the “Superfund Law”) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on persons that are considered to have contributed to the release of a “hazardous substance” into the environment. Such “responsible persons” may be subject to joint and several liability under the Superfund Law for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Further, it is not uncommon for coastal landowners or other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Air Emissions. The CAA and comparable state statutes restrict the emission of air pollutants and affect both onshore and offshore oil and natural gas operations. New facilities may be required to obtain separate construction and operating permits before construction work can begin or operations may start, and existing facilities may be required to incur capital costs in order to remain in compliance. Also, the EPA has developed, and continues to develop, more stringent regulations governing emissions of toxic air pollutants, and is considering the regulation of additional air pollutants and air pollutant parameters. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.

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Worker Health and Safety. The Occupational Safety and Health Act (“OSHA”) and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

Climate Change. From time to time, the United States Congress has considered a variety of tax, energy-related or environmental market-based mechanisms to promote or induce the reduction of emissions of greenhouse gases (“GHGs”) by several commercial or industrial sectors. In addition, more than one half of the states already have begun implementing legal measures such as renewable energy requirements or cap and trade programs to reduce emissions of GHGs.

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 GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. The Paris Agreement entered into force on November 4, 2016. In June 2017, President Trump stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. 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.

In addition, the EPA has determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal CAA. The EPA adopted two sets of rules regulating GHG 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 GHGs from certain large stationary sources through preconstruction and operating permit requirements. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, on an annual basis. Currently, our operations include one active floating production unit (theHP-I) that is subject to those EPA GHG reporting requirements.

The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, on an annual basis. Recent regulation of GHGs 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. The EPA’s rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. However, in a March 28, 2017 executive order, President Trump directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. The regulations remain in effect unless revised or repealed by a separate EPA rulemaking in the future, which is likely to be challenged in court.

Environmental Regulation in Shallow Waters Off the Coast of Mexico. Our operations on oil and natural gas blocks in shallow waters off the coast of Mexico’s Veracruz and Tabasco states, and in other Mexican offshore areas where we are assessing other exploration opportunities, are subject to regulation by the Mexican National Agency of Industrial Safety and Environmental Protection of the Hydrocarbons Sector (“ASEA”). We must obtain ASEA-issued permits and comply with ASEA regulations governing hydrocarbon activities, including

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requirements for environmental impact and risk assessments, industrial safety, waste management, water and air emissions, operational security, and facility decommissioning. Under the PSCs, we are jointly and severally liable, along with Sierra and Premier, for the performance of all obligations under the PSCs, including exploration, appraisal, extraction, and abandonment activities and compliance with all environmental regulations. Failure to comply with applicable laws and regulations can result in the imposition of monetary penalties, revocation of permits, suspension of operations, and ordered decommissioning of offshore facilities and systems. The laws and regulations governing the protection of health, safety, and the environment from activities in the Mexican energy sector are relatively new, having been significantly reformed in 2013 and 2014, and the legal regulatory framework continues to evolve as ASEA and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that ASEA or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters.

Federal Regulation of Sales and Transportation of Natural Gas

Our sales of natural gas are affected directly or indirectly by the availability, terms and cost of natural gas transportation. The prices and terms for access to pipeline transportation of natural gas are subject to extensive federal and state regulation. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”) and by regulations and orders promulgated under the NGA and/or NGPA by the Federal Energy Regulatory Commission (“FERC”). In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the United States Congress and by FERC regulations. However, certain offshore gathering and transportation services we rely upon are subject to limited FERC regulation and are regulated by the states.

Pursuant to authority delegated to it by the Energy Policy Act of 2005 (“EPAct 2005”), the FERC promulgated anti-manipulation regulations establishing violation enforcement mechanisms that make it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of FERC to (i) use or employ any device, scheme or artifice to defraud, (ii) make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or (iii) engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any entity. The EPAct 2005 also amended the NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes and regulations, up to $1,213,503 per violation, per day for 2017 (this amount is adjusted annually for inflation). The FERC may also order disgorgement of profits and corrective action. The anti-market manipulation rule does not apply to activities that relate only to intrastate or othernon-jurisdictional sales or gathering, but does apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwisenon-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which includes annual reporting requirements for entities that purchase or sell a certain volume of natural gas in a given calendar year. We believe, however, that neither the EPAct 2005 nor the regulations promulgated by FERC as a result of the EPAct 2005 will affect us in a way that materially differs from the way they affect other natural gas producers, gatherers and marketers with which we compete.

Our sales of oil and natural gas are also subject to market manipulation and anti-disruptive requirements under the Commodity Exchange Act (“CEA”) as amended by the Dodd-Frank Financial Reform Act, and regulations promulgated thereunder by the CFTC. The CFTC prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

The current statutory and regulatory framework governing interstate natural gas transactions is subject to change in the future, and the nature of such changes is impossible to predict. We cannot predict whether new

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legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by the United States Congress, the applicable federal agencies, or the various state legislatures, and what effect, if any, the proposals might have on our operations. The natural gas industry historically has been very heavily regulated. In the past, the federal government regulated the prices at which natural gas could be sold. Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price andnon-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. However, we are subject to reporting requirements imposed by FERC. There is always some risk, however, that the United States Congress may reenact price controls in the future. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines or impose additional reporting or other requirements upon our operations, and we cannot predict what future action the FERC will take. Therefore, there is no assurance that the current regulatory approach recently pursued by the FERC and the United States Congress will continue. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

Federal Regulation of Sales and Transportation of Crude Oil

Our sales of crude oil and condensate are currently not regulated and are made at negotiated prices. There is always some risk, however, that the United States Congress may reenact price controls in the future. We cannot predict whether new legislation to regulate crude oil, or the prices charged for crude oil might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting requirements.

Our ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act, and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. Certain regulations implemented by the FERC in recent years and certain pending rulemaking and other proceedings could result in an increase in the cost of transportation service on certain petroleum products pipelines. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other crude oil and condensate producers with which we compete.

Further, interstate and intrastate common carrier oil pipelines must provide service on anon-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to other crude oil and condensate producers with which we compete.

The FERC also implements the OCSLA pertaining to transportation and pipeline issues, which requires that all pipelines operating on or across the OCS provide nondiscriminatory transportation service. We own and operate pipelines that are located in the OCS and are subject to thenon-discrimination requirements in the OCSLA.

Employees

We had 382 employees at August 21, 2018. We believe that relations with our employees are good.

Legal Proceedings

We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.

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On January 4, 2018 and February 2, 2018, two putative class action complaints challenging the Transactions were filed on behalf of purported Stone stockholders in the U.S. District Court for the District of Delaware. The complaints are captioned John Heinrich v. Stone Energy Corporation, et al., Case1:18-cv-00054-GMS and Allen Miskowiec v. Stone Energy Corporation, et al., Case1:18-cv-00202-RGA. On February 8, 2018, a third putative class action complaint challenging the Transactions was filed on behalf of purported Stone stockholders in the U.S. District Court for the Western District of Louisiana and is captioned Anthony Franchi v. Stone Energy Corporation, et al., Case6:18-cv-00167. The complaints assert, among other things, claims under Sections 14(a) and 20(a) of the Exchange Act against Stone and certain members of its board of directors and challenges the adequacy of the disclosures made in our consent solicitation statement/prospectus on FormS-4 filed by us with the SEC on December 29, 2017. The Miskowiec and Franchi lawsuits also name Talos Energy LLC as an additional defendant and the Franchi lawsuit names Talos Production LLC as additional defendant. The Heinrich lawsuit was dismissed on June 6, 2018. The Miskowiec lawsuit was dismissed on May 15, 2018. The Franchi lawsuit was dismissed on July 25, 2018.

The following proceedings represent previous Stone litigation that was assumed as part of the Stone Combination.

On November 17, 2014, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Notice of Violation (“NOV”) to Stone alleging releases of production fluid and an improper closure of a drill cuttings pit at Stone’s Loomis No. 1 well site in Susquehanna County, Pennsylvania. Prior to this, in September 2014, Stone had transferred ownership of the Loomis No. 1 well site to Southwestern Energy Company (“Southwestern”). PADEP approved the transfer on November 24, 2014, after issuing the NOV to Stone. Stone investigated the allegations found in the NOV and responded to PADEP on January 5, 2015. Reclamation of the site by Southwestern, with the participation of the PADEP and Stone, was completed. The PADEP may impose a penalty in this matter, but the amount of such penalty cannot be reasonably estimated at this time.

On November 8, 2013, a lawsuit was filed against Stone and other namedco-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the lawsuit. In connection with Stone’s filing of bankruptcy in December 2016, Plaquemines Parish dismissed its claims against Stone without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. The Plaquemines Parish lawsuit has been stayed pending the conclusion of trials in five other cases, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone. The Plaquemines Parish lawsuit has been removed to federal district court in the Eastern District of Louisiana.

On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other namedco-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, “the CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the three lawsuits. In connection with Stone’s filing of bankruptcy in December 2016, Jefferson Parish dismissed its claims against Stone in two of the three Jefferson Parish Coastal Zone Management lawsuits without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. The Jefferson Parish lawsuits have been removed to federal district court in the Eastern District of Louisiana.

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Legal proceedings are subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the resolution of some of these matters and may be unable to estimate a range of possible losses or any minimum loss from such matters. See “Note 11—Commitments and Contingencies” to the unaudited interim condensed consolidated financial statements included elsewhere in this prospectus.

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MANAGEMENT

The table below sets forth information regarding the directors of the Company.

Name	Position	Age
Timothy S. Duncan	Chief Executive Officer and Director		45
Gregory A. Beard	Director		46
Christine Hommes	Director		34
Robert M. Tichio	Director		41
Rajen Mahagaokar	Director		32
Neal P. Goldman	Chairman		49
John “Brad” Juneau	Director		58
James M. Trimble	Director		70
Charles M. Sledge	Director		52
Donald R. Kendall, Jr.	Director		66

Directors

Timothy S. Duncan

Mr. Duncan has served as President and Chief Executive Officer of the Company and as a member of the Company’s board of directors since April 2012 and is a founder of the Company. Prior to the Company, Mr. Duncan was the Senior Vice President of Business Development and a founder of Phoenix Exploration in April 2006, where he was responsible for all of Phoenix’s business development evaluations and negotiations, including the sale of the company to a group of buyers led by Apache Corporation. Prior to Phoenix Exploration, Mr. Duncan served as Manager of Reservoir Engineering and Evaluations for Gryphon Exploration. Mr. Duncan also worked in various reservoir engineering and portfolio evaluation functions for Amerada Hess Corporation, Zilkha Energy Company and Pennzoil E&P Company. Mr. Duncan received his BS in Petroleum Engineering from Mississippi State University, where he was honored in 2012 as a Distinguished Fellow of the College of Engineering. Mr. Duncan also received his MBA from the Bauer Executive Program at the University of Houston. He is an active member of the SPE, IPAA and the Young Presidents’ Organization and is a board member of the National Ocean Industries Association (NOIA). Mr. Duncan also serves on various academically focused advisory boards, including the College of Engineering Dean’s Advisory Council and the Foundation Board at Mississippi State University. Mr. Duncan was named as Ernst & Young Entrepreneur of the Year for the Energy and Energy Services sector in the Gulf Coast in June 2016. Based on Mr. Duncan’s significant experience as an officer of oil and gas companies, together with his training as a reservoir engineer and broad industry knowledge, we believe that he possesses the requisite skills to serve as a member of our board of directors.

Gregory A. Beard

Mr. Beard has served as a member of the Company’s board of directors since April 2012. Mr. Beard joined Apollo in June 2010 as the Global Head of Natural Resources and a Senior Partner at Apollo, based in the New York office. Mr. Beard overseas all investment activities in the energy, metal and mining and agriculture sectors. Since Mr. Beard joined Apollo, Apollo’s private equity funds have invested or committed to invest approximately $6.3 billion in natural resources-related investments. Mr. Beard joined Apollo with 19 years of investment experience, the last ten of which were with Riverstone Holdings, LLC (“Riverstone Holdings”) where he was a founding member, Managing Director and lead deal partner in many of the firm’s top oil and gas and energy service investments. While at Riverstone Holdings, Mr. Beard was involved in all aspects of the investment process including sourcing, structuring, monitoring and exiting transactions. Mr. Beard no longer has any affiliation with Riverstone Holdings. Mr. Beard began his career as a Financial Analyst at Goldman, Sachs & Co., where he played an active role in that firm’s energy-sector principal investment activities.

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Mr. Beard has served on the board of directors of many oil and natural gas companies including, Athlon Energy Inc., Belden & Blake Corporation, Canera Resources Inc., Cobalt International Energy, Legend Natural Gas I—IV, Mariner Energy, Phoenix Exploration, Titan Operating, and Vantage Energy. Mr. Beard has also served on the board of directors of various natural resources related companies, including CDM Resource Management, International Logging and NRI Management Group LLC. Mr. Beard currently serves on the board of directors of Apex Energy, LLC, Caelus Energy, CSV Midstream, Double Eagle Energy Holdings, LLC I/II, EP Energy Corporation, Jupiter Resources Inc., Northwoods Energy and Pinnacle Agriculture Holdings, LLC. Mr. Beard received his BA from the University of Illinois at Urbana. Based upon Mr. Beard’s extensive investment and management experience, particularly in the energy sector, his strong financial background and his service on the boards of multiple oil and natural gas exploration and production companies, which have provided him with a deep working knowledge of our operating environment, we believe that he possesses the requisite skills to serve as a member of our board of directors.

Christine Hommes

Ms. Hommes has served as a member of the Company’s board of directors since January 2016. Ms. Hommes joined Apollo in January 2011, where she is currently a Principal, based in the New York office. Prior to joining Apollo, Ms. Hommes was an investment professional at First Reserve, where she was involved in the execution and monitoring of investments in the energy sector. Previously, she worked in the Investment Banking Division at UBS in the Power Group. Ms. Hommes currently serves on the board of directors of Chisholm Oil & Gas, Momentum Minerals, Roundtable Energy and Northwoods Energy. Ms. Hommes graduated summa cum laude from the University of Pennsylvania with a BS in Economics and a BAS in Systems Engineering. We believe that Ms. Hommes’s experience in evaluating financial and strategic options and the operations of companies in our industry make her a valuable member of our board of directors.

Robert M. Tichio

Mr. Tichio has served as a member of the Company’s board of directors since April 2012. Mr. Tichio joined Riverstone Holdings in 2006, where he is currently a Partner and based in New York. Prior to joining Riverstone Holdings, Mr. Tichio was in the Principal Investment Area of Goldman, Sachs & Co., which manages the firm’s private corporate equity investments. Mr. Tichio began his career at J.P. Morgan in the Mergers & Acquisition group where he concentrated on assignments that included public company combinations, asset sales, takeover defenses and leveraged buyouts. Mr. Tichio serves on the board of directors of various private Riverstone portfolio companies and EP Energy Corporation and Centennial Resource Development, Inc.; he previously served on the board of Cona Resources Ltd. (formerly known as Northern Blizzard Resources Inc.) Mr. Tichio received his AB from Dartmouth College, where he serves on the Board of Visitors of the Nelson A. Rockefeller Center, as a Phi Beta Kappa graduate, and later received his MBA with Distinction from Harvard Business School. We believe Mr. Tichio’s extensive energy industry background, particularly his expertise in mergers and acquisitions, brings important experience and skill to our board of directors.

Rajen Mahagaokar

Mr. Mahagaokar has served as a member of the Company’s board of directors since May 2018. Mr. Mahagaokar is a Vice President of Riverstone Holdings LLC and joined Riverstone in 2015. Prior to joining Riverstone, Mr. Mahagaokar was aco-founder and Partner of Marka, LLC from 2012 to 2014. Previously, Mr. Mahagaokar was an investment professional at Silver Lake Kraftwerk from 2012 to 2013. Mr. Mahagaokar began his career in 2008 in the Investment Banking Division at Goldman Sachs in the Natural Resources group and in the Urban Investment Group, a principal investing strategy. He currently serves on the board of directors of EP Energy Corporation. He received his B.A. in Mathematical Economic Analysis from Rice University. We believe Mr. Mahagaokar’s energy industry background and experience in evaluating financial and strategic options and the operations of companies in our industry brings important experience and skill to our board of directors.

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Neal P. Goldman

Mr. Goldman has served as the Chairman of the Company’s board of directors since May 2018 and was previously the Chairman of the board of directors of Stone Energy. Mr. Goldman is currently the Managing Member of SAGE Capital Investments, LLC, a consulting firm specializing in independent board of director services, turnaround consulting, strategic planning, and special situation investments. Mr. Goldman was a Managing Director at Och Ziff Capital Management, L.P. from 2014 to 2016 and a Founding Partner of Brigade Capital Management, LLC from 2007 to 2012, which he helped build to over $12 billion in assets under management. Prior to this, Mr. Goldman was a Portfolio Manager at MacKay Shields, LLC and also held various positions at Salomon Brothers Inc., both as a mergers and acquisitions banker and as an investor in the high yield trading group. Throughout his career, Mr. Goldman has held numerous board representations including roles as an independent member of the boards of directors of Lightsquared, Inc., Pimco Income Strategy Fund I & II, and Catalyst Paper Corporation, as well as a member of the boards of directors of Jacuzzi Brands and NII Holdings, Inc. Mr. Goldman has served on the boards of directors of Midstates Petroleum Company, Inc. since October 2016, Walter Investment Management Corp. (Ditech) since January 2017, and Ultra Petroleum Corp. since April 2017. Mr. Goldman received a BA from the University of Michigan and an MBA from the University of Illinois. Based upon Mr. Goldman’s involvement in strategic planning and his experience on multiple boards, we believe that Mr. Goldman will be a valuable member of our board of directors.

John “Brad” Juneau

Mr. Juneau has served as a member of the Company’s board of directors since May 2018 and was previously a member of Stone Energy’s board of directors from February 2017 to May 2018. Since August 2012 Mr. Juneau has been President, Chief Executive Officer and a director of Contango ORE, Inc. (“Contango”), a publicly traded gold exploration company, and has served as the Chairman of Contango’s board of directors since 2013. Mr. Juneau is the sole manager of the general partner of Juneau Exploration, L.P., a company involved in the exploration and production of oil and natural gas. Prior to forming Juneau Exploration in 1998, Mr. Juneau served as Senior Vice President of exploration for Zilkha Energy Company from 1987 to 1998. Prior to joining Zilkha Energy Company, Mr. Juneau served as a Staff Petroleum Engineer with Texas International Company for three years, where his principal responsibilities included reservoir engineering, as well as acquisitions and evaluations. Prior to that, he was a Production Engineer with Enserch Corporation in Oklahoma City. Mr. Juneau holds a BS in Petroleum Engineering from Louisiana State University. We believe that Mr. Juneau’s extensive energy industry background, particularly his expertise in reservoir engineering and involvement with exploration and production companies, make him a valuable member of our board of directors.

James M. Trimble

Mr. Trimble has served as a member of the Company’s board of directors since May 2018. Prior to that, he served as the Interim Chief Executive Officer and President of Stone Energy from April 2017 until May 2018 and as a member of Stone Energy’s board of directors from February 2017. Mr. Trimble previously served as Chief Executive Officer and President of PDC Energy, Inc., a publicly traded independent natural gas and oil company, from 2011 until 2015. From 2005 until 2010, Mr. Trimble was Managing Director of Grand Gulf Energy, Limited, a public company traded on the Australian Securities Exchange, and President and Chief Executive Officer of Grand Gulf’s U.S. subsidiary Grand Gulf Energy Company LLC, an exploration and development company focused primarily on drilling in mature basins in Texas, Louisiana and Oklahoma. From 2000 through 2004, Mr. Trimble served as Chief Executive Officer of Elysium Energy and then TexCal Energy LLC, both of which were privately held oil and gas companies that he managed through workouts. Prior to this, he was Senior Vice President of Exploration and Production for Cabot Oil and Gas, a publicly traded independent energy company. Mr. Trimble was hired in July 2002 as Chief Executive Officer of TexCal (formerlyTri-Union Development) to manage a distressed oil and gas company through bankruptcy. Mr. Trimble previously served on the boards of directors of Blue Dolphin Energy, an independent oil and gas company with operations in the Gulf of Mexico, from November 2002 until May 2006, Seisgen Exploration LLC, a small

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private exploration and production company operating in southern Texas, from 2008 to 2015, Grand Gulf Energy LTD from 2009 to 2012, PDC Energy from 2009 until June 2016 and C&J Energy Services LTD from March 2016 to January 2017. Mr. Trimble has served on the boards of directors of Callon Petroleum Company since 2014 and Crestone Peak Resources LLC (a private company operating in the DJ Basin of Colorado) since December 2016. Mr. Trimble was an officer of PDC Energy in September 2013, when each of the twelve partnerships for which the company was the managing general partner filed for bankruptcy in the federal bankruptcy court, Northern District of Texas, Dallas Division, and was on the board of C&J Energy Services LTD when it filed for bankruptcy in the court of the Southern District of Texas, Houston Division in July 2016. Mr. Trimble is Registered Professional Engineer and has a BS in Petroleum Engineering from Mississippi State University. Based upon Mr. Trimble’s many years of oil and gas industry executive management experience, including experience as a chief executive officer, and knowledge of current developments and best practices in the industry, we believe Mr. Trimble will bring valuable skills and expertise to our board of directors.

Charles M. Sledge

Mr. Sledge has served as a member of the Company’s board of directors since May 2018 and previously served as a member of Stone Energy’s board of directors since February 2017. Mr. Sledge previously served as the Chief Financial Officer of Cameron International Corporation, an oilfield services company, from 2008 until 2016. Prior to that, Mr. Sledge served as the Corporate Controller of Cameron International Corporation from 2001 until 2008. Mr. Sledge has served on the boards of directors of Templar Energy LLC since January 2017, Vine Resources, Inc. since April 2017, and Expro International since June 2018. We believe that Mr. Sledge’s strong financial background, including his 20 years of experience as a financial executive, will make him a valuable member of our board of directors.

Donald R. Kendall, Jr.

Mr. Kendall Jr. has served as a member of the Company’s board of directors since May 2018. Mr. Kendall is the managing director and chief executive officer of Kenmont Capital Partners, a private investment and advisory firm, since October 1998. Mr. Kendall previously served as president of Cogen Technologies Capital Company, a power generation firm, and concurrently as chairman and chief executive officer of Palmetto partners, an investment management firm, from July 1993 to October 1998. Mr. Kendall serves as a director of American Midstream Partners LP and serves on its audit and conflict committees. For Solar City Corporation Mr. Kendall served as chair of the special and the audit committees and on its compensation committee. Additionally, Mr. Kendall served as chair of the audit, compensation and nominating and governance committees of privately held Stream Energy. We believe that Mr. Kendall’s many years of executive management experience, including experience as a chief executive officer, and his experience on multiple boards, will make him a valuable member of our board of directors.

Director Independence

Under NYSE rules, a “controlled company” is defined as a listed company of which more than 50% of the voting power for the election of directors is held by an individual, a group, or another company. The Company is a controlled company within the meaning of NYSE rules.

As a result of the Stockholders’ Agreement (as defined in “Certain Relationships and Related Party Transactions”) and the Apollo Funds’ and the Riverstone Funds’ voting power, the Company is exempt from complying with NYSE’s requirements that (i) a majority of our board of directors consist of independent directors, (ii) the nominating and corporate governance committee consist entirely of independent directors, and (iii) the compensation committee be composed entirely of independent directors. We have elected not to use these exemptions available to controlled companies, but may do so in the future.

The Stockholders’ Agreement provides that successors to directors not designated by Talos will be nominated by the Governance & Nominating Committee, which must have a majority of Company Independent

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Directors. A Company Independent Director is any director of our board who (i) meets the independence standards under NYSE rules, (ii) is not a director designated by the Apollo Funds or the Riverstone Funds, (iii) is not a current director, officer or employee of the Apollo Funds or the Riverstone Funds or their respective affiliates, (iv) has been determined by the Governance & Nominating Committee not to have any relationship with the Apollo Funds or the Riverstone Funds or their respective affiliates that would be material to the director’s ability to be independent, and (v) is designated by the Governance & Nominating Committee as a “Company Independent Director.”

The board of directors has determined that each of Gregory A. Beard, Christine Hommes, Robert M. Tichio, Neal P. Goldman, John “Brad” Juneau, James M. Trimble, Charles M. Sledge, Donald R. Kendall, Jr. and Rajen Mahagaokar is “independent” pursuant to NYSE rules.

The board of directors is divided into three classes of directors and the directors will serve for staggered three-year terms. The class I directors include Charles M. Sledge, Robert M. Tichio and Gregory A. Beard; the class II directors include Timothy S. Duncan, John “Brad” Juneau and Donald R. Kendall, Jr.; and the class III directors include Neal P. Goldman, James M. Trimble, Christine Hommes and Rajen Mahagaokar.

Board Meetings and Committees

Pursuant to the Company’s certificate of incorporation and bylaws, every act or decision done or made by a majority of the directors present at a meeting duly held at which a quorum is present shall be regarded as the act of the board of directors, unless a greater number is required by law, by the certificate of incorporation, by the bylaws or by the Stockholders’ Agreement.

The board of directors has an Audit Committee, Compensation Committee, Governance & Nominating Committee and Safety Committee.

Audit Committee

The primary responsibilities of the Audit Committee are to oversee the accounting and financial reporting processes of the Company as well as its affiliated and subsidiary companies, and to oversee the internal and external audit processes. The Audit Committee also assists the board of directors in fulfilling its oversight responsibilities by reviewing the financial information which is provided to stockholders and others and the system of internal controls which management and the board of directors have established. The Audit Committee oversees the independent auditors, including their independence and objectivity. However, the Audit Committee members do not act as professional accountants or auditors, and their functions are not intended to duplicate or substitute for the activities of management and the independent auditors. The Audit Committee is empowered to retain independent legal counsel and other advisors as it deems necessary or appropriate to assist the Audit Committee in fulfilling its responsibilities, and to approve the fees and other retention terms of the advisors.

Pursuant to the Stockholders’ Agreement and the Company’s bylaws, the Audit Committee will have at least three directors and all of the directors will be Company Independent Directors. The approval of a majority of the Audit Committee will be required to approve any matter before the Audit Committee. The members of the Audit Committee as of the date of this prospectus are Charles M. Sledge (Chair), Donald R. Kendall, Jr. and John “Brad” Juneau. The board of directors has determined that each of John “Brad” Juneau, Charles M. Sledge and Donald R. Kendall, Jr. meets the additional independence criteria to serve as a member of the Audit Committee of the board of directors and that Charles M. Sledge is an audit committee financial expert and is financially literate.

Compensation Committee

The primary responsibilities of the Compensation Committee are to periodically review and approve the compensation and other benefits for the Company’s employees, officers and independent directors, including

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reviewing and approving corporate goals and objectives relevant to the compensation of the Company’s executive officers in light of those goals and objectives, and setting compensation for these officers based on those evaluations. The Compensation Committee also administers and has discretionary authority over the issuance of stock awards under any stock compensation plans.

The Compensation Committee generally is able to delegate authority to review and approve the compensation of the Company’s employees to certain executive officers, including with respect to stock option or stock appreciation rights grants made under any stock option plans, stock compensation plans or stock appreciation rights plans.

Pursuant to the Stockholders’ Agreement and subject to certain limitations and qualifications, the Compensation Committee will, among other things, determine compensation for the Chief Executive Officer of the Company and all executive officers who report directly to the Chief Executive Officer. The members of the Compensation Committee as of the date of this prospectus are James M. Trimble (Chair), Gregory A. Beard and Rajen Mahagaokar.

Governance & Nominating Committee

The Company’s bylaws provide for a Governance & Nominating Committee, which will be composed of a majority of Company Independent Directors until Section 3.1 of the Stockholders’ Agreement expires. The Governance & Nominating Committee has the full power and authority of the board of directors to take any actions required or permitted to be taken by such committee pursuant to the Stockholders’ Agreement. Any action of the Governance & Nominating Committee may be taken by the affirmative vote of a simple majority of the members of such committee, and no greater vote will be imposed by resolution or action of the board of directors. The unanimous consent of the board of directors will be required to eliminate the Governance & Nominating Committee or to modify or limit the powers granted to the Governance & Nominating Committee.

Pursuant to the Stockholders’ Agreement, the Governance & Nominating Committee will have three directors, including at least two Company Independent Directors.

The Governance & Nominating Committee will, subject to the terms of the Stockholders’ Agreement, assist the board of directors with respect to: (i) the organization and membership and function of the board of directors, including the identification and recommendation of director nominees and the structure and membership of each committee of the board of directors, (ii) corporate governance principles applicable to the Company, and (iii) the Company’s policies and programs that relate to matters of corporate responsibility. The Governance & Nominating Committee is expected, subject to the terms of the Stockholders’ Agreement, to review and make recommendations to the board of directors regarding the composition of the board of directors structure, format and frequency of the meetings. It is expected that the Governance & Nominating Committee will not formally establish any specific, minimum qualifications that must be met by each candidate for the board of directors or specific qualities or skills that are necessary for one or more of the members of the board of directors to possess. However, it is expected that the Governance & Nominating Committee, when considering a potential candidate, will factor into its determination the following qualities of a candidate, among others: professional experience, educational background, knowledge of our business, integrity, professional reputation, independence, wisdom, and ability to represent the best interests of our stockholders. It is also expected that the Governance & Nominating Committee will review and make recommendations to the board of directors regarding the nature, composition and duties of the committees of the board of directors. It is expected that the Governance & Nominating Committee will review and consider stockholder-recommended candidates for nomination to the board of directors. As of the date of this prospectus, the members of the Governance & Nominating Committee are Neal P. Goldman (Chair), Robert M. Tichio and Charles M. Sledge.

Safety Committee

The primary responsibilities of the Safety Committee are to (i) review the Company’s safety programs and policies and recommend any proposed changes to the board of directors, (ii) monitor the Company’s compliance

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with the Company’s safety programs and policies and review the Company’s safety statistics and (iii) review significant public policy and legislative and regulatory issues or trends related to safety matters and provide input to the Company with respect to such policies, issues and trends. It is also expected that the Safety Committee will meet with the Company’s management to review the implementation and effectiveness of the Company’s safety programs and policies. As of the date of this prospectus, the members of the Safety Committee are Christine Hommes (Chair), John “Brad” Juneau and James M. Trimble.

Indemnification of Officers and Directors

The Company’s certificate of incorporation and bylaws require us to indemnify our officers and directors to the fullest extent permitted by the Delaware General Corporation Law (the “DGCL”).

In addition, the Company’s bylaws allow us to purchase and maintain insurance on behalf of any person who is or was serving as a director, officer, employee or agent of the Company or is or was serving at the request of the Company as a director, officer, partner, venturer, proprietor, employee, agent or similar functionary of another corporation, partnership, joint venture, proprietorship, employee benefit plan, trust or other enterprise against any expense, liability or loss asserted against that person and incurred by that person in any such capacity, or arising out of that person’s status as such, whether or not the Company would have the power to indemnify that person against such expense, liability or loss under the Company’s bylaws. We also have and intend to maintain director and officer liability insurance, if available on reasonable terms.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling the Company pursuant to the foregoing provisions, or otherwise, the Company has been informed that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serves, or in the past has served, as a member of the board of directors or compensation committee, or other committee serving an equivalent function, of any entity that has one or more executive officers who serve as members of our board of directors or our compensation committee. None of the members of our compensation committee is, or has ever been, an officer or employee of our company.

Executive Officers of the Company

Biographical Information

Timothy S. Duncan(45)

Mr. Duncan is the President and Chief Executive Officer of the Company. Mr. Duncan has served as President and Chief Executive Officer of Talos and as a member of the Talos board of directors since April 2012 and was a founder of Talos. Prior to Talos, Mr. Duncan was the Senior Vice President of Business Development and a founder of Phoenix Exploration in April 2006, where he was responsible for all of Phoenix’s business development evaluations and negotiations, including the sale of the company to a group of buyers led by Apache Corporation. Prior to Phoenix Exploration, Mr. Duncan served as Manager of Reservoir Engineering and Evaluations for Gryphon Exploration. Mr. Duncan also worked in various reservoir engineering and portfolio evaluation functions for Amerada Hess Corporation, Zilkha Energy Company and Pennzoil E&P Company. Mr. Duncan received his BS in Petroleum Engineering from Mississippi State University, where he was honored in 2012 as a Distinguished Fellow of the College of Engineering. Mr. Duncan also received his MBA from the Bauer Executive Program at the University of Houston. He is an active member of the SPE, IPAA and the Young Presidents’ Organization and is a board member of the National Ocean Industries Association (NOIA) and the Young Presidents’ Organization. Mr. Duncan also serves on various academically focused advisory boards,

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including the College of Engineering Dean’s Advisory Council and the Foundation Board at Mississippi State University. Mr. Duncan was named as Ernst & Young Entrepreneur of the Year Program for the Energy and Energy Services sector in the Gulf Coast in June 2016.

Stephen E. Heitzman(68)

Mr. Heitzman is the Executive Vice President and Chief Operating Officer of the Company. Mr. Heitzman served as Executive Vice President and Chief Operating Officer of Talos since April 2012 and was a founder of Talos. Prior to Talos, Mr. Heitzman was the President and Chief Executive Officer and a founder of Phoenix Exploration Company LP in April 2006. Prior to Phoenix Exploration Company LP, he was a founder and Vice President Operations of Gryphon Exploration and was responsible for the formation, staffing and supervision of Gryphon’s Operations Team from 2000 through January 2006. Mr. Heitzman began his career as a petroleum engineer with Amoco in the Houston area and held various engineering and management positions both domestically and held various engineering and management positions both domestically and internationally, onshore and offshore for various companies including Huffco Indonesia for Roy M. Huffington, Inc. Mr. Heitzman received his BS in Mechanical Engineering from Texas Tech University and is a member if the Texas Tech University Academy of Mechanical Engineers, Petroleum Engineering Academy, Distinguished Engineering Alumni, Key Society, and has more than 45 years of industry experience.

John A. Parker(63)

Mr. Parker is the Executive Vice President of Exploration of the Company. Mr. Parker served as Executive Vice President of Exploration of Talos since April 2012 and is a founder of Talos. Prior to Talos, Mr. Parker was the Senior Vice President of Exploration and a founder of Phoenix Exploration Company LP in April 2006. Prior to Phoenix Exploration Company LP, he was a founder and key contributor to the success of Gryphon Exploration as Exploration Manager of the Texas Shelf. While at Gryphon Exploration, he generated prospects and supervised the prospect generation of the Texas exploration team. Prior to Gryphon Exploration, Mr. Parker worked as an exploration geologist for EOG Resources in the Gulf of Mexico. Mr. Parker started his career at Shell Oil Company where he worked as an exploration geologist in the Gulf Coast onshore. He later worked exploring in international basins at Pecten. Mr. Parker received his BS from Louisiana State University and his MS in Earth Sciences from the University of New Orleans and has more than 34 years of industry experience.

Michael L. HardingII (50)

Mr. Harding is the Executive Vice President, Chief Financial Officer, Chief Accounting Officer and Treasurer of the Company. Mr. Harding served as Senior Vice President and Chief Financial Officer of Talos since December 2015 after becoming Vice President and Chief Accounting Officer of Talos in October 2014 and Chief Accounting Officer and Controller of Talos in April 2012. Mr. Harding is responsible for financial reporting, planning, audit, tax and information technology. Prior to joining Talos in February 2012, Mr. Harding was Manager of Business Development for Consulting Services for Pannell Kerr Forster of Texas, P.C., beginning in December 2010. Mr. Harding served from December 2008 to December 2010 as Vice President and Controller for RigNet, Inc. At Apache Corporation, Mr. Harding served from June 2003 to December 2008 in various levels of accounting management including revenue, capital and regional accounting management in Calgary, Alberta. With El Paso Merchant Energy Group, Mr. Harding served seven years in various accounting management roles including financial derivatives and power asset accounting and planning. Mr. Harding earned his BBA in Accounting from Texas A&M University. Mr. Harding is a member of the AICPA. Mr. Harding also serves on the Advisory Council for Texas A&M University’s McFerrin Center for New Ventures and Entrepreneurship.

William S. Moss III(48)

Mr. Moss is the Executive Vice President, General Counsel and Secretary of the Company. Mr. Moss served as Senior Vice President and General Counsel of Talos from May 2013 to May 2018. Prior to Talos, Mr. Moss

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was a partner at Mayer Brown LLP in Houston where he was the head of the Houston Corporate Practice. Mr. Moss joined Mayer Brown LLP in May 2005. At Mayer Brown LLP, Mr. Moss’s practice focused on mergers and acquisitions, securities offerings and general corporate and securities matters and he represented clients throughout the energy value chain. Mr. Moss joined Talos after having represented Talos as outside counsel in its initial formation and its subsequent acquisition of ERT from Helix in February of 2013. Mr. Moss also represented Phoenix Exploration in its initial formation in April 2006, acquisitions and ultimate sale to a group of buyers led by Apache Corporation. Prior to joining Mayer Brown LLP, Mr. Moss worked at Baker Botts, L.L.P. Mr. Moss has an AB from Dartmouth College, a M. Phil from Cambridge University and a J.D. from the University of Texas School of Law.

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COMPENSATION DISCUSSION AND ANALYSIS

Overview

This Compensation Discussion and Analysis identifies the elements of compensation and explains the compensation objectives and practices for the individuals identified in the following table, who we refer to herein as our “Named Executive Officers,” for the fiscal year ended December 31, 2017 (the “2017 Fiscal Year”).

Name	Principal Position
Timothy S. Duncan	President and Chief Executive Officer
Michael L. Harding II	Executive Vice President and Chief Financial Officer (1)
Stephen E. Heitzman	Executive Vice President and Chief Operating Officer
John A. Parker	Executive Vice President of Exploration
William S. Moss III	Executive Vice President and General Counsel (1)

(1) In connection with the Stone Combination, Mr. Harding and Mr. Moss were each promoted from Senior Vice President to Executive Vice President.

Compensation Objectives and Practices

Historically, the compensation of our Named Executive Officers has been determined by the board of Talos Energy LLC, with input from our Chief Executive Officer regarding the compensation of our Named Executive Officers other than our Chief Executive Officer. In order to attract and retain talented individuals to serve as executive officers and maintain a balance of fixed compensation with short-term and long-term incentive compensation, the board of Talos Energy LLC determined that the following compensatory elements were appropriate for our Named Executive Officers in the 2017 Fiscal Year:

• Base salary;

• Short-term cash incentive awards;

• Long-term equity awards in the form of Series B Units in Talos Energy LLC;

• Health and welfare and retirement benefits; and

• Limited perquisites.

Elements of Compensation for the 2017 Fiscal Year

Base Salary

The base salaries provided to our Named Executive Officers are a fixed portion of their total compensation that reflects their responsibilities, expertise, experience and tenure. After reviewing the Effective Compensation Incorporated 2016 Oil and Gas Exploration and Production Industry Compensation Survey and considering each Named Executive Officer’s responsibilities, experience and performance, the board of Talos Energy LLC, with input from our Chief Executive Officer, determined that increases in each Named Executive Officer’s base salary were appropriate. The table below reflects such increases, which became effective on March 5, 2017. The board of Talos Energy LLC did not benchmark the Named Executive Officer’s compensation; the survey data was one of many considerations taken into account when establishing the base salary levels outlined below.

Name	Base Salary as of December 31, 2016		Base Salary as of December 31, 2017		Percent of Merit Increase
Timothy S. Duncan	$	400,000	$	440,000		10	%
Michael L. Harding II	$	300,000	$	322,500		7.5	%
Stephen E. Heitzman	$	365,000	$	375,950		3	%
John A. Parker	$	365,000	$	375,950		3	%
William S. Moss III	$	365,000	$	375,950		3	%

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Short-Term Cash Incentive Awards

For the 2017 Fiscal Year, we awarded short-term cash incentive awards based one-half on our achievement of company-wide quantitative performance targets and one-half on individual performance evaluations for our Named Executive Officers. The company-wide quantitative performance metrics and targets for the 2017 Fiscal Year were (i) production and reserves metrics, including proved developing producing (“PDP”) production (plus probable reserves), total production, and year-end reserves, each measured in MMBoe; (ii) cost and profitability metrics, including earnings before interest, taxes, depreciation and amortization (“EBITDA”), total direct operating expenses (“DOE”) (not including the HP-I floating vessel) measured in dollars per barrels of oil equivalent (“$/Boe”) and cash costs measured in $/Boe; and (iii) safety metrics, including major safety or compliance events and the ratio of incidents of non-compliance to components (“INC/Component”). The weighting of these company-wide quantitative performance metrics, the 2017 Fiscal Year targets, the actual results for the 2017 Fiscal Year, and the percentage payout of each performance metric for the 2017 Fiscal Year are set forth in the table below.

Company-Wide Performance Metric	Individual Weighting			2017 Fiscal Year Target		Actual Results for 2017 Fiscal Year		2017 Fiscal Year Percentage Payout (1)
Production and Reserves
PDP Production + Performance Probable Cases		3.75	%		10,485 MMBoe		10,143 MMBoe		3.50	%
Total Production		3.75	%		11,412 MMBoe		10,472 MMBoe		3.25	%
Y/E Reserves		10	%		164.20 MMBoe		174.6 MMBoe		11.25	%
Cost and Profitability
EBITDA		10	%	$	292.4 MM	$	256.9 MM		7.50	%
Total DOE (not including HP-I)		7.5	%	$	10.82/Boe	$	10.25/Boe		8.25	%
Cash Costs		7.5	%	$	16.95/Boe	$	17.20/Boe		7.25	%
Safety
No Major Events (Safety or Compliance)		3.75	%		0		0		3.75	%
INC/Component		3.75	%		0.46		0.37		5.25	%
Unadjusted Company-Wide Performance Total		50	%						50	%
									+7.5	%(2)
Adjusted Company-Wide Performance Total									57.5	%

(1) Rounded to the nearest quarter percent

(2) After reviewing the results set forth above, we adjusted the company-wide performance total to 57.5% in light of our achievements in Mexico during the 2017 Fiscal Year.

In addition to the company-wide quantitative performance metrics described above, one-half of each Named Executive Officer’s short-term cash incentive award is determined based on an assessment of their individual performance, which results in an individual performance rating ranging from 1.0 to 5.0, with 3.0 serving as the target for the 2017 Fiscal Year. For the 2017 Fiscal Year, each Named Executive Officer received a 3.6 individual performance rating, which was influenced in substantial part by the contributions each of the Named Executive Officers made toward moving the Stone Combination towards completion.

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The target short-term cash incentive award for each of our Named Executive Officers has historically been set by the board of Talos Energy LLC, with input from our Chief Executive Officer. The individual targets, as a percentage of base salary, and the actual short-term cash incentive award paid for performance for the 2017 Fiscal Year are set forth in the following table for each of our Named Executive Officers. The maximum amount that could become payable under the short-term incentive program for the 2017 Fiscal year was 200% of each Named Executive Officer’s target.

Name	Target Short-Term Cash Incentive (% of Base Salary)			Adjusted Company-Wide Performance Achievement Percentage			Individual Performance Rating Percentage			Actual Short-Term Cash Incentive Award Payment
Timothy S. Duncan		100	%		57.5	%		57.5	%	$	506,000
Michael L. Harding II		75	%		57.5	%		57.5	%	$	278,200
Stephen E. Heitzman		75	%		57.5	%		57.5	%	$	324,300
John A. Parker		75	%		57.5	%		57.5	%	$	324,300
William S. Moss III		75	%		57.5	%		57.5	%	$	324,300

Series B Unit Awards

On June 6, 2017, the board of Talos Energy LLC granted 4,100 restricted Series B Units in Talos Energy LLC to Mr. Duncan pursuant to the terms of the Second Amended and Restated Limited Liability Company Agreement of Talos Energy LLC (the “LLC Agreement”). These awards were granted to Mr. Duncan in recognition of the responsibility inherent in the role of President and Chief Executive Officer and in an attempt to increase his equity compensation to levels more closely aligned with equity compensation provided to individuals in the same role at companies with which we compete for executive talent.

The Series B Units are intended to constitute “profits interests” for federal tax purposes. Eighty percent of Mr. Duncan’s Series B Units vest in equal monthly installments beginning on the last day of the month of grant and continuing on the last day of each month for a total of 48 months, so long as Mr. Duncan remains employed through each vesting date. The remaining 20%, and any portion of the 80% that remains unvested, will only vest upon the occurrence of a Vesting Event (as defined below under “Potential Payments Upon Termination or Change in Control—Series B Unit Award Agreements”). Any portion of the Series B Units that vest on the basis of time and remain unvested as of a Vesting Event will also become vested upon such Vesting Event.

Other Benefits

Health and Welfare Benefits

We offer participation in health and welfare plans to all of our employees, including our Named Executive Officers.

Retirement Benefits

We have not maintained, and do not currently maintain, a defined benefit pension plan or nonqualified deferred compensation plan in which our Named Executive Officers participate. We currently maintain a retirement plan intended to provide benefits under section 401(k) of the Code where employees, including our Named Executive Officers, are allowed to contribute portions of their eligible compensation to a tax-qualified retirement account. We have historically provided discretionary matching contributions equal to 50% of the first 10% of employees’ eligible compensation contributed to the plan. Employees generally become vested in 25% of the matching contributions made to their tax-qualified retirement account per year for four years. Employees become 100% vested in the matching contributions made to their tax-qualified retirement account upon death, disability or retirement on or after normal retirement age (i.e., age 65). Employees may receive a distribution of the vested portion of their tax-qualified retirement accounts upon (i) a termination of employment, (ii) normal retirement, (iii) disability or (iv) death.

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Life Insurance

We provide group term life insurance to all of our employees, including the Named Executive Officers, equal to 2.5 times base salary up to a maximum of $500,0000.

Limited Perquisites

Minimal perquisites have historically been provided to our Named Executive Officers, including limited spousal travel and gym membership reimbursement.

Actions Taken Following Fiscal Year End

Following the end of the 2017 Fiscal Year, we took the following actions with respect to the compensation of our Named Executive Officers. These actions will be discussed more thoroughly in our 2019 proxy statement in accordance with Item 402 of Regulation S-K.

Adjustments to Base Salaries and Short-Term Cash Incentive Award Targets

In August of 2018 our board approved adjustments to the annualized base salary, retroactive to May 10, 2018, and short-term cash incentive award target percentages for each Named Executive Officer to reflect the increased responsibilities of their positions following the Stone Combination. The table below reflects the new annualized base salaries and short-term cash incentive award target percentages for each Named Executive Officer:

Name	Base Salary effective as of May 10, 2018		2018 Target Short-Term Cash Incentive (% of Base Salary)
Timothy S. Duncan	$	650,000		125	%
Michael L. Harding II	$	380,000		80	%
Stephen E. Heitzman	$	400,000		80	%
John A. Parker	$	400,000		80	%
William S. Moss III	$	380,000		80	%

Series B Unit Exchange

In connection with the Stone Combination, the Series B Units in Talos Energy LLC, including those held by our Named Executive Officers, were exchanged for an equivalent number of Series B Units in each of AP Talos Energy LLC and Riverstone Talos Energy Equityco LLC. The Series B Units received in the exchange remain subject to the same terms and conditions applicable to the Series B Units in Talos Energy LLC prior to such exchange, including with respect to vesting.

New Series B Units

In addition to the Series B Units received as a result of the Series B Unit exchange described above, in connection with the Stone Combination, each of our Named Executive Officers received Series B Units in each of AP Talos Energy Debtco LLC and Riverstone Talos Energy Debtco LLC, which are intended to constitute “profits interests” for federal tax purposes. Such Series B Units vest on the schedule that was applicable to the Named Executive Officer’s Series B Units in Talos Energy LLC prior to the Series B Unit exchange as described above under “Elements of Compensation for the 2017 Fiscal Year—Series B Unit Awards.”

Long Term Incentive Plan

Effective as of the Stone Combination, we adopted the Talos Energy Inc. Long Term Incentive Plan (the “LTIP”) to provide a means through which we may attract, retain and motivate qualified individuals as employees,

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directors and consultants, thereby enhancing the profitable growth of us and our affiliates. Subject to adjustment as provided therein, the LTIP originally reserved 5,415,576 shares of Common Stock for potential grants of incentive stock options, nonqualified stock options, stock appreciation rights, restricted stock awards, restricted stock units, stock awards, dividend equivalents, other stock- or cash-based awards and substitute awards.

On August 29, 2018, we granted restricted stock unit (“RSU”) and performance share unit (“PSU”) awards to our Named Executive Officers. The RSU awards vest ratably over the three-year period beginning on May 14, 2018, subject to the Named Executive Officer’s continued employment. The PSU awards vest based on our relative total shareholder return over the three-year performance period commencing on May 14, 2018 and ending on May 13, 2021, subject to the Named Executive Officer’s continued employment through the settlement of the PSU award.

Executive Severance Plan

On August 29, 2018, we adopted the Talos Energy Operating Company LLC Executive Severance Plan (the “Severance Plan”), pursuant to which each of our Named Executive Officers are entitled to receive severance benefits following certain terminations of employment. As a condition to participation in the Executive Severance Plan, each Named Executive Officer agreed to (i) terminate his employment agreement with us, including all rights to severance thereunder and (ii) abide by certain confidentiality, non-solicitation and non-disparagement covenants.

Other Matters

Accounting Treatment of Executive Compensation Decisions

We account for awards of Series B Units in accordance with the Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”), which requires us to estimate the expense of an award of Series B Units over the vesting period applicable to such award. We also account for the RSU and PSU awards in accordance with FASB ASC Topic 718.

Summary Compensation Table

The table below sets forth the annual compensation earned by the Named Executive Officers during the fiscal years ended December 31, 2016 and December 31, 2017.

Name and Principal Position	Year		Salary		Bonus (2)		Option Awards (1)		Non-Equity Incentive Plan Compensation (2)		All Other Compensation (3)		Total
Timothy S. Duncan		2017	$	432,308	$	33,000	$	86,059	$	473,000	$	9,000	$	1,033,367
President and Chief Executive Officer		2016	$	400,000		—	$	51,786	$	430,000	$	9,000	$	890,786
Michael L. Harding II		2017	$	318,173	$	18,143		—	$	260,057	$	9,000	$	605,373
Executive Vice President and Chief Financial Officer		2016	$	300,000		—	$	129,465	$	241,900	$	9,000	$	680,365
Stephen E. Heitzman		2017	$	373,844	$	21,150		—	$	303,150	$	11,942	$	710,086
Executive Vice President and Chief Operating Officer		2016	$	365,000		—		—	$	294,300	$	12,000	$	671,300
John A. Parker		2017	$	373,844	$	21,150		—	$	303,150	$	12,000	$	710,144
Executive Vice President of Exploration		2016	$	365,000		—		—	$	294,300	$	12,000	$	671,300
William S. Moss III		2017	$	373,844	$	21,150		—	$	303,150	$	9,000	$	707,144
Executive Vice President and General Counsel

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(1) Amounts in this column represent the aggregate grant date fair value of Series B Units in Talos Energy LLC granted during the 2017 Fiscal Year to Mr. Duncan, calculated in accordance with FASB ASC Topic 718, disregarding estimated forfeitures. For additional information regarding the assumptions underlying this calculation please see Note 7 to our consolidated financial statements for the fiscal year ended December 31, 2017. We believe that, despite the fact that the Series B Units do not require the payment of an exercise price, they are most similar economically to stock options, and as such, they are properly classified as “options” under the definition provided in Item 402(a)(6)(i) of Regulation S-K as an instrument with an “option-like feature.” See “Elements of Compensation for the 2017 Fiscal Year—Series B Unit Awards” above for additional information regarding these awards.

(2) Short-term cash incentive awards for performance in the 2017 Fiscal Year were paid in March 2018 and are reported in part in the “Bonus” column for the portion of the award reflecting the discretionary upwards adjustment and in part in the “Non-Equity Incentive Plan Compensation” column for the remainder. See “Elements of Compensation for the 2017 Fiscal Year—Short-Term Cash Incentive Awards” above for additional information regarding these awards.

(3) Amounts reported in the “All Other Compensation” column include our match of 401(k) plan contributions in the 2017 Fiscal Year for each Named Executive Officer as shown in the table below. We have previously also disclosed the value of life insurance premiums in the amount of $1,770 for Mr. Duncan in this column for both the 2016 Fiscal Year and 2017 Fiscal Year. Upon further review, we have determined that these premiums should not be reported as a perquisite for Mr. Duncan because we, and not Mr. Duncan or his heirs, are the beneficiary of the policy. As a result, the value of the premiums for the key man life insurance policy were removed from the Summary Compensation Table.

Name	401(k) Plan Company Matching Contributions
Timothy S. Duncan	$	9,000
Michael L. Harding II	$	9,000
Stephen E. Heitzman	$	11,942
John A. Parker	$	12,000
William S. Moss III	$	9,000

Grants of Plan-Based Awards

The following table includes information regarding Series B Unit awards granted to Mr. Duncan and the short-term cash incentive awards granted to our Named Executive Officers, in each case, during the 2017 Fiscal Year.

	Grant Date		Estimated Future Payouts Under Non-Equity Incentive Plan Awards					Estimated Future Payouts Under Equity Incentive Plan Awards						All Other Option Awards: Number of Securities Underlying Options (#) (3)		Exercise or Base Price of Option Awards ($/Sh) (4)		Grant Date Fair Value of Stock and Option Awards ($) (5)
Name			Threshold ($)	Target ($) (1)		Maximum ($)		Threshold (#)		Target (#) (2)		Maximum (#)
Timothy S. Duncan				$	440,000	$	880,000
		6/6/17							—		820		—		3,280		n/a	$	86,059
Michael L. Harding II				$	241,875	$	483,750
Stephen E. Heitzman				$	281,963	$	563,926
John A. Parker				$	281,963	$	563,926
William S. Moss III				$	281,963	$	563,926

(1) Amounts in this column represent the target estimated payouts for short-term cash incentive awards for the 2017 Fiscal Year. There was no threshold payout associated with the short-term cash incentive awards for the 2017 Fiscal Year. The maximum award that could be earned was equal to 200% of each Named Executive Officers target bonus amount.

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(2) Amounts in this column represent Series B Units in Talos Energy LLC granted to Mr. Duncan during the 2017 Fiscal Year that only become vested upon the occurrence of a Vesting Event.

(3) Amounts in this column represent Series B Units granted to Mr. Duncan during the 2017 Fiscal Year which vest ratably on the last day of each month following the date of grant through May 31, 2021, subject to Mr. Duncan’s continued employment.

(4) These equity awards are not traditional options, and therefore, there is no exercise price associated with them.

(5) Amounts in this column represent the aggregate grant date fair value of Series B Units in Talos Energy LLC granted during the 2017 Fiscal Year to Mr. Duncan, calculated in accordance with FASB ASC Topic 718, disregarding estimated forfeitures. For additional information regarding the assumptions underlying this calculation please see Note 7 to our consolidated financial statements for the fiscal year ended December 31, 2017. We believe that, despite the fact that the Series B Units do not require the payment of an exercise price, they are most similar economically to stock options, and as such, they are properly classified as “options” under the definition provided in Item 402(a)(6)(i) of Regulation S-K as an instrument with an “option-like feature.” See “Elements of Compensation for the 2017 Fiscal Year—Series B Unit Awards” above for additional information regarding these awards.

Narrative Disclosure to the Summary Compensation Table and Grants of Plan-Based Awards Table

Employment Agreements

We previously entered into an employment agreement with each of our Named Executive Officers. The agreements with Messrs. Duncan, Heitzman, and Parker became effective on February 3, 2012. The agreement with Mr. Moss became effective on August 30, 2013, and the agreement with Mr. Harding became effective on March 14, 2016. Each agreement has an initial two-year term that automatically renews for successive 12-month periods until terminated in writing by either party at least 30 days prior to a renewal date. The agreements provide our Named Executive Officers with an annual base salary, eligibility to participate in an annual performance bonus plan, entitlement to four weeks of paid vacation per calendar year (five weeks for Mr. Harding) and the right to participate in all other benefit plans and programs for which our executives are generally eligible (including, but not limited to, medical and dental insurance). The employment agreements also provide that our Named Executive Officers will be reimbursed for reasonable documented business-related expenses incurred in the performance of their duties.

Severance benefits provided by these employment agreements are described below in “Potential Payments Upon Termination or Change in Control.” The employment agreements also contain certain restrictive covenants, which require the executives, during and after their employment with us, to preserve and protect our confidential information and work product.

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Outstanding Equity Awards at 2017 Fiscal Year-End

The following table reflects information regarding outstanding unvested Series B Units held by our Named Executive Officers as of December 31, 2017.

	Option Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable			Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) (1)		Option Exercise Price ($) (2)		Option Expiration Date (2)
Timothy S. Duncan		—		—			20,000		n/a		n/a
		—		1,167	(3)		2,000		n/a		n/a
		—		390	(4)		520		n/a		n/a
		—		2,802	(5)		820
Michael L. Harding II		—		—			2,000		n/a		n/a
		—		—			2,000		n/a		n/a
		—		250	(6)		500		n/a		n/a
		—		225	(4)		300		n/a		n/a
		—		11,917	(7)		5,500		n/a		n/a
Stephen E. Heitzman		—		—			20,000		n/a		n/a
John A. Parker		—		—			20,000		n/a		n/a
William S. Moss III		—		—			16,000		n/a		n/a

(1) Amounts in this column represent Series B Units in Talos Energy LLC held by each Named Executive Officer which only become vested upon the occurrence of a Vesting Event.

(2) These equity awards are not traditional options, and therefore, there is no exercise price or expiration date associated with them.

(3) These Series B Units vested on the last day of each month through July 31, 2018.

(4) These Series B Units will vest on the last day of each month through September 30, 2018, subject to the Named Executive Officer’s continued employment.

(5) These Series B Units will vest on the last day of each month through May 31, 2021, subject to the Named Executive Officer’s continued employment.

(6) These Series B Units vested on the last day of each month through June 30, 2018.

(7) These Series B Units will vest on the last day of each month through February 29, 2020, subject to the Named Executive Officer’s continued employment.

Option Exercises and Stock Vested

	Option Awards
Name	Number of Units Acquired on Exercise (#) (1)		Value Realized on Exercise ($) (2)
Timothy S. Duncan		2,998	$	30,755
Michael L. Harding II		6,467	$	57,914
Stephen E. Heitzman		—		—
John A. Parker		—		—
William S. Moss III		10,724	$	63,402

(1) This column reflects the Series B Units held by each Named Executive Officer that vested during the 2017 Fiscal Year. We believe that, despite the fact that the Series B Units do not require the payment of an exercise price, they are most similar economically to stock options, and as such, they are properly classified as “options” under the definition provided in Item 402(a)(6)(i) of Regulation S-K as an instrument with an “option-like feature.”

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(2) The value of the Series B Units reported in this column was estimated using the Stone stock price as of each vesting date and the number of diluted shares in the pro forma business. A probability percentage was then applied estimating the probability as of the measurement date that the Stone Combination would close. The value of the Series B Units prior to July of 2017 is estimated to be zero.

Pension Benefits

We have not maintained, and do not currently maintain, a defined benefit pension plan.

Nonqualified Deferred Compensation

We have not maintained, and do not currently maintain, a nonqualified deferred compensation plan.

Potential Payments Upon Termination or a Change in Control

Employment Agreements

The employment agreements with our Named Executive Officers contain certain severance provisions. Specifically, if a Named Executive Officer’s employment is terminated by us without “Cause,” by the Named Executive Officer for “Good Reason,” or by reason of death or “Disability” (each term as defined in the employment agreement), the officer will receive, subject to the execution, delivery and non-revocation of a release of claims agreement and the officer’s continued compliance with certain restrictive covenants set forth in the employment agreement, (i) continuation of base salary, payable in substantially equal monthly installments, for a period ending on the earliest to occur of (a) 24 months following the termination date, (b) in the event a “Liquidation Event” (as defined in the employment agreement) occurs on or within the first 12 months following the termination date, 12 months following such Liquidation Event, or (c) the date on which the officer accepts an offer of employment or engages in a business venture, in either case, on a substantially full-time basis (whichever of (a), (b) or (c) is applicable, the “Severance Period”), and (ii) if the officer or any of the officer’s dependents were participating in company-maintained group health plans, reimbursement for the employer contribution for coverage under the company-maintained group health plans for the type and level of post-termination coverage elected by the officer and his dependents (the “COBRA Reimbursement”) for the duration of the Severance Period, provided the officer is eligible to, and does timely, elect continuation coverage pursuant to applicable state or federal law (including COBRA) and the applicable company-maintained group health plans continue in effect. If the applicable company-maintained group health plans do not continue in effect for any portion of the Severance Period, a Named Executive Officer will receive an amount equal to the employer contribution for coverage under the company-maintained group health plans for the type and level of post-termination coverage elected by the officer and his dependents, determined immediately prior to the termination of such company-maintained group health plans, for the remainder of the Severance Period. Notwithstanding the foregoing, our obligations under (ii) above shall cease if and when group health coverage under another employer’s plan is made available to a Named Executive Officer.

If a Named Executive Officer’s employment is terminated by us due to nonrenewal of the initial term or a renewal term, the officer will receive, subject to the execution, delivery and non-revocation of a release of claims agreement and the officer’s continued compliance with certain restrictive covenants set forth in the employment agreement, (i) continuation of base salary, payable in substantially equal monthly installments, for a period of 180 days following the termination date (the “Nonrenewal Severance Period”) and (ii) the COBRA Reimbursement for the duration of the Nonrenewal Severance Period. If the applicable company-maintained group health plans do not continue in effect for any portion of the Nonrenewal Severance Period, a Named Executive Officer will receive an amount equal to the employer contribution for coverage under the company-maintained group health plans for the type and level of post-termination coverage elected by the officer and his dependents, determined immediately prior to the termination of such company-maintained group health plans, for the remainder of the Nonrenewal Severance Period. Notwithstanding the foregoing, our obligations under (ii) above shall cease if and when group health coverage under another employer’s plan is made available to a Named Executive Officer.

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Under the employment agreements, if we determine following a termination of employment resulting in a payment of severance that Cause existed on or prior to such termination, then the Talos Board may determine that the Named Executive Officer will not be entitled to any further severance from us and the Named Executive Officer will return to us any severance payments already made.

Under the employment agreements, our Named Executive Officers have also agreed to certain confidentiality, non-solicitation and non-competition covenants. The confidentiality covenants apply during the term of the agreement and continue indefinitely following the Named Executive Officer’s termination of employment. The non-competition covenants generally apply during the term of the agreement and for a period of 24 months following the officer’s termination of employment; provided, that, if a Liquidation Event occurs, such period shall end upon the earlier to occur of (i) 24 months following the officer’s termination date or (ii) 12 months following such Liquidation Event; provided, further, that in the event the employment agreement terminates due to nonrenewal of the initial term or a renewal term, such period shall end 180 days following the officer’s termination date. The non-solicitation covenants generally apply during the term of the agreement and for a period of 12 months following the officer’s termination of employment. In the event of the breach of a restrictive covenant during a Named Executive Officer’s employment with us, the officer could be terminated for Cause (provided that the breach constituted a material violation of the employment agreement). The employment agreements do not prohibit us from waiving a breach of a restrictive covenant.

Series B Unit Award Agreements

If a Named Executive Officer’s employment is terminated for any reason other than by us for “Cause,” he will forfeit all unvested Series B Units in Talos Energy LLC, and Talos Energy LLC will have a right to repurchase any vested Series B Units at Fair Market Value (as defined in the LLC Agreement). If the Named Executive Officer’s employment is terminated by us for Cause, then he will forfeit all Series B Units, whether vested or unvested. For Messrs. Duncan, Parker, and Heitzman’s Series B Units granted on February 3, 2012 and for Mr. Moss’s Series B Units granted on October 1, 2013, “Cause” has the meaning given to such term in the employment agreements. For all other Series B Units, “Cause” means (i) engaging in material mismanagement in providing services to us or our affiliates, (ii) engaging in conduct that could reasonably be expected to be materially injurious to us or our affiliates, (iii) materially breaching the Series B Unit award agreement or the LLC Agreement, (iv) being convicted of, or entering a plea bargain or settlement admitting guilt for, any felony, crime involving moral turpitude, or where, as a result of such crime, the continued employment of the Named Executive Officer would be expected to have a material adverse impact on us or our affiliates, or (v) being the subject of any order obtained or issued by the SEC for any securities violation involving fraud.

In general, any unvested Series B Units granted to our Named Executive Officers will fully vest upon the occurrence of a either of the following events (each, a “Vesting Event”): (i) “Liquidation Event” or “Approved Sale” which results in a “Series A Payout” with respect to each holder of Series A Units in Talos Energy LLC or the occurrence of (ii) a “Public Offering” where Riverstone Equity Partners, L.P. and Apollo Talos Holdings, L.P. (a) receive cash proceeds from the sale of securities received in a reorganization sufficient to result in a Series A Payout (after taking into consideration any prior cash distributions) with respect to Riverstone Equity Partners, L.P. and Apollo Talos Holdings, L.P., or (b) as of the 5th anniversary of the Public Offering, hold securities with a fair market value sufficient to result in a Series A Payout (after taking into consideration any prior cash distributions) with respect to Riverstone Equity Partners, L.P. and Apollo Talos Holdings, L.P.

For purposes of the Series B Units:

• “Liquidation Event” generally includes (i) mergers, business combinations, consolidations, sales of all or substantially all of the assets of Talos Energy LLC following which the pre-transaction members do not hold a majority of the equity securities of the surviving or resulting entity, (ii) sale of more than 75% of the Series A Units in Talos Energy LLC, (iii) a voluntary or involuntary reorganization or entry into bankruptcy or insolvency proceedings, and (iv) the winding up, dissolution or liquidation of Talos Energy LLC;

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• “Approved Sale” generally includes (i) mergers, business combinations, or consolidations following which the pre-transaction members do not hold a majority of the equity securities of the surviving or resulting entity, (ii) sale of all or substantially all of the assets of Talos Energy LLC to one or more third parties, and (iii) sale of all or substantially all of the equity interests in Talos Energy LLC to one or more third parties, in each case initiated by Apollo Talos Holdings, L.P. or Riverstone Equity Partners, L.P.;

• “Series A Payout” occurs when holders of the Series A Units receive distributions which cause the unreturned Series A Unit capital contributions and unpaid Series A Unit preference amount to equal $0; and

• “Public Offering” means the sale in a public offering registered under the Securities Act of the equity securities of Talos Energy LLC (or any successor thereto) or a director or indirect subsidiary of Talos Energy LLC (or any successor thereto).

The following table sets forth the payments and benefits that would be received by our Named Executive Officers pursuant to their employment agreements and Series B Unit award agreements in the event of certain terminations of employment with us or upon certain other events, had such termination or other event occurred on December 31, 2017.

Name	Termination by us without Cause; resignation for Good Reason; death or Disability ($)		Termination as a result of a nonrenewal by us of the employment agreement($) (3)		Vesting Event ($)
Timothy S. Duncan
Cash Severance	$	880,000	$	220,000		—
COBRA Reimbursement (1)	$	36,805	$	9,201		—
Series B Unit Acceleration (2)		—		—	$	806,318
Total	$	916,805	$	229,201	$	806,318
Michael L. Harding II
Cash Severance	$	645,000	$	161,250		—
COBRA Reimbursement (1)	$	36,317	$	9,079		—
Series B Unit Acceleration (2)		—		—	$	660,564
Total	$	681,317	$	170,329	$	660,564
Stephen E. Heitzman
Cash Severance	$	751,900	$	187,975		—
COBRA Reimbursement (1)	$	31,685	$	7,921		—
Series B Unit Acceleration (2)		—		—	$	582,200
Total	$	783,585	$	195,896	$	582,200
John A. Parker
Cash Severance	$	751,900	$	187,975		—
COBRA Reimbursement (1)	$	17,644	$	4,411		—
Series B Unit Acceleration (2)		—		—	$	582,200
Total	$	769,544	$	192,386	$	582,200
William S. Moss III
Cash Severance	$	751,900	$	187,975		—
COBRA Reimbursement (1)	$	41,237	$	10,309		—
Series B Unit Acceleration (2)		—		—	$	465,760
Total	$	793,137	$	198,284	$	465,760

(1) The COBRA Reimbursement amount is based on the premiums in effect as of December 2017, which are assumed for purposes of this table to remain the same throughout the applicable COBRA reimbursement period.

(2) These amounts are calculated by multiplying the number of Series B Units in Talos Energy LLC that would become vested upon the applicable event by $29.11, the fair market value of a Series B Unit in Talos Energy

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LLC as of December 31, 2017. The value of the Series B Units reported in this column was estimated using the Stone stock price as of December 31, 2017 and the number of diluted shares in the pro forma business. A probability percentage was then applied estimating the probability as of the measurement date that the Stone Combination would close.

(3) This column assumes that a nonrenewal of the employment agreements occurred on December 31, 2017; however, a nonrenewal under the terms of the employment agreements can only occur in connection with the end of the applicable employment agreement’s current term.

Executive Severance Plan

Pursuant to the terms of the Severance Plan, upon a termination without “Cause” or a resignation for “Good Reason,” each Named Executive Officer will be eligible to receive: (i) a lump sum cash payment equal to 1.5 (or 2.0 in the case of Mr. Duncan) times the Named Executive Officer’s annualized base salary then in effect; (ii) any earned but unpaid bonus for the year preceding the year of termination based on the our actual performance, paid at the time such bonuses are paid to executives; (iii) a pro-rated bonus for the year of termination based on the our actual performance, paid at the time such bonuses are paid to executives; and (iv) partially subsidized continuation coverage for the Named Executive Officer and his spouse and eligible dependents under our group health plans pursuant to COBRA for 18 months (or 24 months in the case of Mr. Duncan), unless such coverage is earlier terminated in accordance with the terms of the Severance Plan.

Additionally, if a Named Executive Officer’s employment with us terminates as a result of his death or “Disability,” then the Named Executive Officer will be eligible to receive the following benefits: (i) any earned but unpaid bonus for the year preceding the year of termination based on our actual performance, paid at the time such bonuses are paid to executives; and (ii) a pro-rated bonus for the year of termination based on our actual performance, paid at the time such bonuses are paid to executives.

In order to receive any of the foregoing severance benefits under the Severance Plan, a Named Executive Officer must timely execute (and not revoke) a release of claims in favor of us and our affiliates. Further, the Severance Plan requires continued compliance with certain confidentiality, non-solicitation and non-disparagement covenants. If the severance benefits under the Severance Plan would trigger an excise tax for a participant under Section 4999 of the Code, the Severance Plan provides that the Named Executive Officer’s severance benefits will be reduced to a level at which the excise tax is not triggered, unless the Named Executive Officer would receive a greater amount without such reduction after taking into account the excise tax and other applicable taxes.

For purposes of the Severance Plan:

• “Cause” generally means a Named Executive Officer’s (i) material breach of the Severance Plan or other written agreement with us, (ii) material breach of any law applicable to the workplace or employment relationship or any of our material policies or codes of conduct, (iii) gross negligence, willful misconduct, breach of fiduciary duty, fraud, theft or embezzlement, (iv) commission, conviction, indictment or please ofnolo contendre of any felony or crime involving moral turpitude, or (v) willful failure or refusal to perform his obligations pursuant to the Severance Plan or follow any lawful directive from us;

• “Disability” generally means an inability by a Named Executive Officer to perform the essential functions of his position due to physical or mental impairment or other incapacity that continues, or can reasonably be expected to continue, for a period in excess of 120 consecutive days or 180 days, whether or not consecutive, in any 12-month period.

• “Good Reason” generally means (i) a material diminution in a Named Executive Officer’s base salary, authority, duties or responsibilities, (ii) material breach by us of our obligations under the Severance Plan, or (ii) a geographic relocation of the Named Executive Officer’s principal place of employment by more than 50 miles.

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Long Term Incentive Plan Awards

Restricted Stock Unit Awards

Pursuant to the terms of each Named Executive Officer’s RSU award agreement, if a Named Executive Officer’s employment with us is terminated (i) as a result of his death or “Disability” or (ii) within one year following a “Change in Control,” by us without “Cause” or by the Named Executive Officer for “Good Reason,” then, in each case, such Named Executive Officer’s unvested RSUs will become fully vested. If a Named Executive Officer’s employment with us is terminated by us without Cause or by the Named Executive Officer for Good Reason, in each case, prior to a Change in Control or more than one year following a Change in Control, then the portion of such Named Executive Officer’s unvested RSUs that would have vested within the 12-month period following such termination will become vested.

Performance Share Unit Awards

Pursuant to the terms of each Named Executive Officer’s PSU award agreement, if a Named Executive Officer’s employment with us is terminated as a result of his death or Disability, then a pro-rata portion of such Named Executive Officer’s PSUs will become earned based on actual performance calculated through the date of such termination. If a Named Executive Officer’s employment with us is terminated by us without Cause or by the Named Executive Officer for Good Reason, in each case, prior to a Change in Control or more than one year following a Change in Control, then the Named Executive Officer will be deemed to have met the service requirement with respect to a pro-rata portion of his PSUs, and such PSUs will remain outstanding subject to satisfaction of the performance metrics through the end of the performance period. If a Named Executive Officer’s employment with us is terminated within one year following a Change in Control by us without Cause or by the Named Executive Officer for Good Reason, then, in each case, such Named Executive Officer’s PSUs will become earned based on actual performance calculated through the date of such Change in Control.

For purposes of the RSU and PSU award agreements, “Cause,” “Disability,” and “Good Reason” have the meanings given to such terms in the Severance Plan. “Change in Control” generally means the occurrence of any of the following events: (i) acquisition by a person or group of beneficial ownership of 50% or more of our outstanding shares or the combined voting power of our outstanding voting securities; (ii) during any consecutive 12-month period, individuals who constitute our board cease for any reason to constitute at least a majority of our board, excluding any director whose election or nomination was approved by a vote of at least a majority of the then current directors unless such approval occurs as a result of an actual or threatened election contest; (iii) consummation of a business combination in which our outstanding voting securities immediately prior to such business combination do not, immediately following such business combination, continue to represent more than 50% of the then outstanding voting securities; (iv) sale of all or substantially all of our assets; or (v) approval by our stockholders of a complete liquidation or dissolution.

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The following table sets forth the payments and benefits that would be received by our Named Executive Officers pursuant to the terms of the Severance Plan in the event of certain terminations of employment with us, had such termination occurred on December 31, 2017 and the Severance Plan (rather than the employment agreements) been effective at such time. The Severance Plan does not change the treatment of Series B Units reported above. Because the RSUs and PSUs were granted in 2018, no value is associated with those awards on the hypothetical termination of employment on December 31, 2017 reported below.

Name	Termination by us without Cause or resignation for Good Reason		Termination as a result of death or Disability
Timothy S. Duncan
Cash Severance	$	880,000		—
Pro-Rata Annual Bonus (1)	$	506,000	$	506,000
COBRA Reimbursement (2)	$	36,805		—
Total	$	1,422,805	$	506,000
Michael L. Harding II
Cash Severance	$	483,750		—
Pro-Rata Annual Bonus (1)	$	278,200	$	278,200
COBRA Reimbursement (2)	$	27,238		—
Total	$	789,188	$	278,200
Stephen E. Heitzman
Cash Severance	$	563,925		—
Pro-Rata Annual Bonus (1)	$	324,300	$	324,300
COBRA Reimbursement (2)	$	23,764		—
Total	$	911,989	$	324,300
John A. Parker
Cash Severance	$	563,925		—
Pro-Rata Annual Bonus (1)	$	324,300	$	324,300
COBRA Reimbursement (2)	$	13,233		—
Total	$	901,458	$	324,300
William S. Moss III
Cash Severance	$	563,925		—
Pro-Rata Annual Bonus (1)	$	324,300	$	324,300
COBRA Reimbursement (2)	$	30,928		—
Total	$	919,153	$	324,300

(1) These amounts reflect the pro-rata portion of each Named Executive Officer’s annual bonus, which would have been the full amount of such annual bonus had the termination of employment occurred on December 31, 2017.

(2) The COBRA Reimbursement amount is based on the premiums in effect as of December 2017, which are assumed for purposes of this table to remain the same throughout the applicable COBRA reimbursement period.

Director Compensation

Members of the board of Talos Energy LLC did not receive any compensation for their services as directors in 2017.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information known to us, based on filings made under Section 13(d) and 13(g) of the Exchange Act, regarding the beneficial ownership of our common stock as of June 30, 2018 by:

• each person, or group of affiliated persons, who we know to beneficially own more than 5% of our common stock;

• each of our named executive officers;

• each of our directors; and

• all of our executive officers and directors as a group.

Beneficial ownership is determined in accordance with the rules of the SEC. These rules generally attribute beneficial ownership of securities to persons who possess sole or shared voting power or investment power with respect to such securities. Except as otherwise indicated, all persons listed below have sole voting and investment power with respect to the shares beneficially owned by them, subject to applicable community property laws. Unless otherwise indicated, the address of each person or entity named in the table below is c/o Talos Energy Inc., 333 Clay Street, Suite 3300, Houston, Texas 77002.

	Shares Beneficially Owned
	Number		Percent
5% Stockholders
Apollo Funds(1)		19,191,451		35.4	%
Riverstone Funds(2)		14,926,683		27.6	%
MacKay Shields LLC(3)		4,045,851		7.5	%
Franklin Resources(4)		7,209,575		13.3	%
Named Executive Officers and Directors
Timothy S. Duncan(5)		—		—
Stephen E. Heitzman(6)		—		—
John A. Parker(7)		—		—
Michael L. Harding II(8)		—		—
William S. Moss III(9)		—		—
Neal P. Goldman(10)		8,242		*
Christine Hommes		—		—
John “Brad” Juneau(11)		6,181		*
Donald R. Kendall, Jr.(12)		—		—
Rajen Mahagaokar		—		—
Charles M. Sledge(13)		6,181		*
Robert M. Tichio		—		—
James M. Trimble(14)		6,181		*
Gregory A. Beard		—		—
All current directors and executive officers as a group (14 persons)		26,785		*

* Represents beneficial ownership of less than one percent of shares outstanding.

(1) Represents shares of our common stock held of record by AP Talos Energy, LLC (“AP Talos”) and AP Talos Energy Debtco, LLC (“Debtco”). Apollo Talos Holdings, L.P. (“Apollo Holdings”) is the managing member of AP Talos and the manager of Debtco. Apollo Management VII, L.P. (“Management VII”) is the manager of Holdings. AIF VII Management, LLC (“AIF VII”) is the general partner of Management VII. Apollo Management, L.P. (“Apollo Management”) is the sole member and manager of AIF VII. Apollo Management GP, LLC (“Management GP”) is the general partner of Apollo Management. Apollo Management Holdings, L.P. (“Management Holdings”) is the sole member and manager of Management GP. Apollo Management Holdings GP, LLC (“Management Holdings GP”) is the general partner of Management Holdings. Leon Black, Joshua Harris and Marc Rowan are the managers, as well as executive

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officers, of Management Holdings GP, and as such may be deemed to have voting and dispositive control of the shares of common stock held of record by AP Talos and Debtco. The address of each of AP Talos, Debtco and Apollo Holdings is One Manhattanville Road, Suite 201, Purchase, New York 10577. The address of each of Management VII, AIF VII, Apollo Management, Management GP, Management Holdings and Management Holdings GP, and Messrs. Black, Harris and Rowan, is 9 West 57th Street, 43rd Floor, New York, New York 10019. The foregoing information is based on the Schedule 13D filed by Apollo Management Holdings GP, LLC on May 21, 2018.

(2) Represents shares of our common stock held of record by Riverstone Talos Energy Equityco LLC (“Riverstone Equityco”) and Riverstone Talos Energy Debtco LLC (“Riverstone Debtco”). David M. Leuschen and Pierre F. Lapeyre, Jr. are the members of Riverstone Management Group, L.L.C. (“Riverstone Management”), which is the general partner of Riverstone/Gower Mgmt Co Holdings, L.P. (“Riverstone/Gower”), which is the sole member of Riverstone Holdings LLC (“Riverstone Holdings”), which is the sole shareholder of Riverstone Energy GP V Corp (“Riverstone Corp”), which is the managing member of Riverstone Energy GP V, LLC (“Riverstone GP”), which is the general partner of Riverstone Energy Partners V, L.P. (“Riverstone Energy Partners”), which is the general partner of Riverstone Global Energy and Power Fund V (FT), L.P. (“Riverstone Energy Fund”), which is the general partner of Riverstone V Talos Holdings, L.P. (“Riverstone Aggregator”), which is the managing member of Riverstone Equityco and the sole manager of Riverstone Debtco. Riverstone GP is managed by a managing committee consisting of Pierre F. Lapeyre, Jr., David M. Leuschen, E. Bartow Jones, N. John Lancaster, Baran Tekkora, James T. Hackett, Michael B. Hoffman and Robert M. Tichio. As such, each of Riverstone Aggregator, Riverstone Energy Fund, Riverstone Energy Partners, Riverstone GP, Riverstone Corp, Riverstone Holdings, Riverstone/Gower, Riverstone Management, Mr. Leuschen and Mr. Lapeyre may be deemed to have or share beneficial ownership of the shares held directly by Riverstone Equity and Riverstone Debtco. The address of each of the foregoing persons is C/O Riverstone Holdings LLC, 712 Fifth Avenue, 36th Floor, New York, New York 10019. The foregoing information is based on the Schedule 13D filed by Riverstone Talos Energy Equityco LLC on May 21, 2018.

(3) The address of MacKay Shields LLC is 1345 Avenue of Americas, New York, NY 10105. The foregoing information is based on the Schedule 13G filed by MacKay Shields LLC on May 11, 2018.

(4) The shares are beneficially owned by one or more open-or closed-end investment companies or other managed accounts that are investment management clients of investment managers that are direct and indirect subsidiaries (each, an “Investment Management Subsidiary” and, collectively, the “Investment Management Subsidiaries”) of Franklin Resources Inc. (“FRI”). Charles B. Johnson and Rupert H. Johnson, Jr. (the “Principal Shareholders”) each own in excess of 10% of the outstanding common stock of FRI and are the principal stockholders of FRI. FRI and the Principal Shareholders may be deemed to be, for purposes of Rule 13d-3 under the Exchange Act, the beneficial owners of securities held by persons and entities for whom or for which FRI subsidiaries provide investment management services. The address of the foregoing persons is One Franklin Parkway San Mateo, CA 94403. The foregoing information is based on the Schedule 13G filed by Franklin Resources Inc. on May 16, 2018.

(5) For Mr. Duncan, does not include 13,151 unvested restricted stock units (“RSUs”), each of which represent a contingent right to receive one share of our common stock, that will vest ratably on each of May 14, 2019, May 14, 2020 and May 14, 2021.

(6) For Mr. Heitzman, does not include 5,261 unvested RSUs that will vest ratably on each of May 14, 2019, May 14, 2020 and May 14, 2021.

(7) For Mr. Parker, does not include 5,261 unvested RSUs that will vest ratably on each of May 14, 2019, May 14, 2020 and May 14, 2021.

(8) For Mr. Harding, does not include 5,261 unvested RSUs that will vest ratably on each of May 14, 2019, May 14, 2020 and May 14, 2021.

(9) For Mr. Moss, does not include 5,261 unvested RSUs that will vest ratably on each of May 14, 2019, May 14, 2020 and May 14, 2021.

(10) For Mr. Goldman, does not include 6,263 unvested restricted stock units that will vest on May 19, 2019, each of which represent a contingent right to receive 60% of such restricted stock units in shares of our common stock and 40% in cash (“May 2019 RSUs”).

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(11) For Mr. Juneau, does not include 4,175 May 2019 RSUs.

(12) For Mr. Kendall Jr., does not include 4,175 May 2019 RSUs.

(13) For Mr. Sledge, does not include 4,175 May 2019 RSUs.

(14) For Mr. Trimble, does not include 4,175 May 2019 RSUs.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

We or one of our subsidiaries may occasionally enter into transactions with certain “related parties.” Related parties include our executive officers, directors, nominees for directors, a beneficial owner of 5% or more of our common stock and immediate family members of these parties. We refer to transactions involving amounts in excess of $120,000 and in which the related party has a direct or indirect material interest as “related party transactions.”

Stockholders’ Agreement

On the Closing Date, in connection with the Closing, we entered into the Stockholders’ Agreement with certain of the Apollo Funds and the Riverstone Funds, including the the Sponsor Stockholders. The Stockholders’ Agreement provides, among other things, the following:

• Initial Board Composition. Immediately following the Closing, our board of directors consisted of ten directors, with (i) two directors designated by the Apollo Stockholders; (ii) two directors designated by the Riverstone Stockholders; (iii) one director designated by the Apollo Stockholders and the Riverstone Stockholders; (iv) the chief executive officer; and (v) four directors (the “Company Directors”), including theNon-Executive Chairman, that are Company Independent Directors (as defined in the Stockholders’ Agreement) designated by Stone.

• Board Nomination Rights. Each of the Apollo Stockholders and the Riverstone Stockholders will initially have the right to designate two directors for nomination by our board of directors for election and maintain its proportional representation on our board of directors so long as the Apollo Stockholders or the Riverstone Stockholders, as applicable, and their affiliates collectively beneficially own at least (i) 15% of our outstanding common stock or (ii) 50% of our common stock that is issued to the Apollo Funds and the Riverstone Funds, as applicable, at Closing. Upon the Apollo Stockholders and their affiliates ceasing to collectively beneficially own at least (i) 15% of our outstanding common stock or (ii) 50% of our common stock that is issued to the Apollo Funds at Closing, the Apollo Stockholders will have the right to designate one director to our board of directors for so long as the Apollo Stockholders and their affiliates collectively beneficially own at least (i) 5% of our outstanding common stock or (ii) 50% of our common stock that is issued to the Apollo Funds at Closing. Upon the Apollo Stockholders and their affiliates ceasing to collectively beneficially own at least (i) 5% of our outstanding common stock or (ii) 50% of our common stock that is issued to the Apollo Funds at Closing, the Apollo Stockholders will not have a right to designate a director to our board of directors. Upon the Riverstone Stockholders and their affiliates ceasing to collectively beneficially own at least (i) 15% of our outstanding common stock or (ii) 50% of our common stock that is issued to the Riverstone Funds at Closing, the Riverstone Stockholders will have the right to designate one director to our board of directors for so long as the Riverstone Stockholders and their affiliates collectively beneficially own at least (i) 5% of our outstanding common stock or (ii) 50% of our common stock that is issued to the Riverstone Funds at Closing. Upon the Riverstone Stockholders and their affiliates ceasing to collectively beneficially own at least (i) 5% of our outstanding common stock or (ii) 50% of our common stock that is issued to the Riverstone Funds at Closing, the Riverstone Stockholders will not have a right to designate a director to our board of directors.

The successor nominees to the Company Directors shall be selected by the Governance & Nominating Committee of our board of directors, and shall also qualify as Company Directors. The Sponsor Stockholders are required to vote all of their common stock (i) in favor of each nominee nominated by a Sponsor Stockholder pursuant to the Stockholders’ Agreement and (ii) with respect to all other director nominees, in each Sponsor Stockholder’s sole discretion either, (a) in a manner that is proportionate to the manner in which all shares of our common stock are voted by our stockholders other than the Sponsor Stockholders with respect to director elections; or (b) for the Company Directors recommended by the Governance & Nominating Committee of our board of directors.

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• Committee Composition. The Audit Committee of our board of directors shall consist solely of Company Directors, the Compensation Committee of our board of directors shall have at least one Company Director and the Governance & Nominating Committee of our board of directors shall have at least two Company Directors.

• Standstill Provisions. For a period of two years beginning on the Closing Date, the Sponsor Stockholders and their respective affiliates have agreed to refrain from taking certain actions, including (i) participating in the solicitation of proxies in opposition to the Company Directors and (ii) calling a special meeting in respect of the foregoing.

• Transfer Restrictions. For a period of six months beginning on the Closing Date, each of the Apollo Stockholders and Riverstone Stockholders and their respective affiliates may not transfer any shares of our common stock without the consent of the Company Directors. On thesix-month anniversary of the Closing Date, each of the Apollo Stockholders and Riverstone Stockholders and their respective affiliates will be permitted to transfer, from time to time, up to 50% of our common stock issued to the Apollo Funds and Riverstone Funds at the Closing, and on the nine-month anniversary of the Closing Date, each of the Apollo Stockholders and Riverstone Stockholders and their respective affiliates will be permitted to transfer, from time to time, up to 75% of our common stock issued to the Apollo Funds and Riverstone Funds at the closing of the Transactions.

Until the first anniversary of the Closing Date, subject to certain exceptions, neither of the Apollo Stockholders or Riverstone Stockholders may transfer any shares of our common stock to any person or group if, to their knowledge, such person or group would beneficially own in excess of 35% of the total outstanding shares of our common stock following such transfer, without the prior consent of a majority of the Company Directors.

On the first anniversary of the Closing Date, the Apollo Funds and Riverstone Funds will no longer be subject to transfer restrictions in the Stockholders’ Agreement.

• Related Party Transactions. Any transaction in excess of $120,000 in which we or any of our affiliates is a participant and the Apollo Funds or Riverstone Funds or any of their respective affiliates (other than us and our subsidiaries) or any of our directors has a material interest in the transaction must be approved by a majority of the disinterested directors or a majority of the Audit Committee of our board of directors.

Registration Rights Agreement

On the Closing Date, we entered into a Registration Rights Agreement (the “Sponsor Registration Rights Agreement”) with each of the Sponsor Stockholders, Franklin and MacKay Shields relating to the registered resale of our common stock owned by such parties as of Closing (the “Registrable Securities”). Under the Sponsor Registration Rights Agreement, we are required to file a shelf registration statement within 30 days of our receipt of written request by a holder of Registrable Securities (a “Holder”), provided that we will not be required to file a shelf registration statement earlier than 90 days after the Closing. Each Holder will be limited to two demand registrations in any twelve-month period.

The Holders have the right to request that we initiate underwritten offerings of our common stock; provided, that the Apollo Stockholders and Riverstone Stockholders will have the right to demand three underwritten offerings in any twelve-month period, and Franklin and MacKay Shields will only have the collective right to demand one underwritten offering. The Holders have customary piggyback rights with respect to any underwritten offering that we conduct for as long as the Holders own 5% of the Registrable Securities. Each Holder will agree to a90-day lock up with underwriters in the event of an underwritten offering, provided that the lock up will not apply to any Holder who does not have a right to participate in such underwritten offering. The Registration Rights Agreement will terminate with respect to Franklin and MacKay Shields in the event that either Franklin or MacKay Shields ceases to beneficially own 5% or more of the then-outstanding shares of our common stock. The Registration Rights Agreement will otherwise terminate at such time as there are no Registrable Securities outstanding.

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Indemnification Agreements

In connection with the Stone Combination, we entered into indemnification agreements with each of our executive officers and directors. These indemnification agreements require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance certain expenses incurred as a result of any proceeding against them as to which they could be indemnified.

Transaction Fee Agreement

As part of a Transaction Fee Agreement (the “Transaction Fee Agreement”) entered into prior to the Stone Combination between Talos Energy LLC and Apollo Global Management LLC and Riverstone Holdings, LLC (together, the “Sponsors”), Talos Energy LLC previously paid a transaction fee equal to 2% of capital contributions made by each of the Sponsors. For the six months ended June 30, 2018 and 2017, the Sponsors did not make any contributions and thus Talos Energy LLC did not incur or pay transaction fees related to capital contributions. For the years ended December 31, 2017, 2016 and 2015, Talos Energy LLC incurred fees totaling nil, $1.9 million and $1.5 million, respectively, related to the capital contributions received from the Sponsors. In connection with the Stone Combination on the Closing Date, the Transaction Fee Agreement was terminated.

Service Fee Agreement

Prior to the Stone Combination, Talos Energy LLC entered into service fee agreements (the “Service Fee Agreements”) with each of the Sponsors for the provision of certain management consulting and advisory services. Under each agreement, Talos Energy LLC previously paid a fee equal to the higher of (i) a certain percentage of earnings before interest, income taxes, depletion, depreciation and amortization and (ii) a fixed fee payable quarterly; provided, however, such fees were subject in each case to a cap of $0.5 million, in aggregate, for any calendar year. For the six months ended June 30, 2018 and 2017, Talos Energy LLC incurred approximately $0.5 million and $0.3 million, respectively, for these services. For the years ended December 31, 2017, 2016 and 2015, Talos Energy LLC incurred approximately $0.5 million, $0.5 million and $0.5 million, respectively, for these services. In connection with the Stone Combination on the Closing Date, the Service Fee Agreements were terminated.

Contributions and Distributions

During the six months ended June 30, 2018 and 2017, Talos Energy LLC did not receive any cash contributions or make any distributions to the Sponsors. During the year ended December 31, 2017, Talos Energy LLC did not receive any capital contributions from the Sponsors or make any distributions to the Sponsors. During the year ended December 31, 2016, Talos Energy LLC received a $93.8 million ($91.9 million net of $1.9 million of transaction fees) capital contribution from the Sponsors primarily to fund the Sojitz Acquisition. During the year ended December 31, 2015, Talos Energy LLC received a $75.0 million ($73.5 million net of $1.5 million of transaction fees) capital contribution from the Sponsors primarily to fund the DGE Acquisition and to partially fund the $55.0 million extinguishment of the GCER Bank Credit Facility assumed in the GCER Acquisition. For additional information on the Sojitz Acquisition, DGE Acquisition and CGER Acquisition, see “Note 3—Acquisitions” to the Company’s consolidated financial statements for the fiscal year ended December 31, 2017 included elsewhere in this prospectus.

Debt Modification Work Fees

The Company paid $9.3 million in work fees to holders of the Bridge Loans and Stone Notes to exchange into Initial Notes. The Sponsors received $4.1 million and the Franklin Noteholders and the MacKay Noteholders collectively received $3.3 million, respectively, as a result of the work fees paid.

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Legal Fees

We have engaged the law firm Vinson & Elkins L.L.P. to provide legal services to the Company. An immediate family member of William S. Moss III, our Executive Vice President and General Counsel and one of our executive officers, is a partner at Vinson & Elkins L.L.P. For the years ended December 31, 2017, 2016 and 2015 we incurred fees of approximately $424,435, $692,255 and $2,251,512, respectively, for legal services performed by Vinson & Elkins L.L.P.

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THE EXCHANGE OFFER

Terms of the Exchange Offer

We are offering to issue $390,867,820 aggregate principal amount of the Exchange Notes and related guarantees (collectively, the “Exchange Notes”), whose issuance is registered under the Securities Act of 1933, in exchange for our existing $390,867,820 aggregate principal amount of Initial Notes 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 that we propose to issue in this Exchange Offer will be substantially identical to the form and terms of our Initial Notes except that, unlike our Initial Notes, (i) the issuance of the Exchange Notes is registered under the Securities Act, (ii) the Exchange Notes will be freely tradeable by persons who are not our affiliates, and (iii) the Exchange Notes are not entitled to the registration rights applicable to the Initial Notes under the Registration Rights Agreement. In addition, our obligation to pay additional interest on the Initial Notes due to the failure to consummate the Exchange Offer by the date specified in the Registration Rights Agreement does not apply to the Exchange Notes. You should read the description of the Exchange Notes in the section in this prospectus entitled “Description of the Notes.”

Initial Notes may be exchanged only for a minimum principal denomination of $2,000 and in integral multiples of $1.00 in excess thereof.

We reserve the right in our sole discretion to purchase or make offers for any Initial Notes that remain outstanding following the expiration or termination of this Exchange Offer and, to the extent permitted by applicable law, to purchase Initial Notes in the open market or privately negotiated transactions, one or more additional tender or exchange offers or otherwise. The terms and prices of these purchases or offers could differ significantly from the terms of this Exchange Offer.

Expiration Date; Extensions; Amendments; Termination

This Exchange Offer will expire at 5:00 p.m., New York City time, on October 26, 2018, (the 21^st business day following the date of this prospectus) unless we extend it in our sole discretion. The expiration date of this Exchange Offer will be at least 20 business days after the commencement of the Exchange Offer in accordance withRule 14e-1(a) under the Exchange Act.

We expressly reserve the right to delay acceptance of any Initial Notes, extend or terminate this Exchange Offer and not accept any Initial Notes that we have not previously accepted if any of the conditions described below under “—Conditions to the Exchange Offer” have not been satisfied or waived by us. We will notify the exchange agent of any extension by oral notice promptly confirmed in writing or by written notice. We will also notify the holders of the Initial Notes by a press release or other public announcement communicated before 5:00 p.m., New York City time, on the next business day after the previously scheduled expiration date unless applicable laws require us to do otherwise.

We also expressly reserve the right to amend the terms of this Exchange Offer in any manner. If we make any material change, we will promptly disclose this change in a manner reasonably calculated to inform the holders of our Initial Notes of the change, including providing public announcement or giving oral or written notice to these holders. A material change in the terms of this Exchange Offer could include a change in the timing of the Exchange Offer, a change in the exchange agent and other similar changes in the terms of this Exchange Offer. If we make any material change to this Exchange Offer, we will disclose this change by means of a post-effective amendment to the registration statement (which includes this prospectus) and will distribute an amended or supplemented prospectus to each registered holder of Initial Notes. In addition, we will extend this Exchange Offer for up to an additional five to ten business days as required by the Exchange Act, depending on

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the significance of the amendment, if the Exchange Offer would otherwise expire during that period. We will promptly notify the exchange agent by oral notice, promptly confirmed in writing, or written notice of any delay in acceptance, extension, termination or amendment of this Exchange Offer.

Procedures for Tendering Initial Notes

Proper Execution and Delivery of Letters of Transmittal

To tender your Initial Notes in this Exchange Offer, you must useone of the three alternative procedures described below:

(1) Regular delivery procedure: Complete, sign and date the letter of transmittal, or a facsimile of the letter of transmittal. Have the signatures on the letter of transmittal guaranteed if required by the letter of transmittal. Mail or otherwise deliver the letter of transmittal or the facsimile together with the certificates representing the Initial Notes being tendered and any other required documents to the exchange agent before 5:00 p.m., New York City time, on the expiration date;

(2) Book-entry delivery procedure: Send a timely confirmation of a book-entry transfer of your Initial Notes, if this procedure is available, into the exchange agent’s account at DTC in accordance with the procedures for book-entry transfer described under “—Book-Entry Delivery Procedure” below, before 5:00 p.m., New York City time, on the expiration date; or

(3) Guaranteed delivery procedure: If time will not permit you to complete your tender by using the procedures described in (1) or (2) above before the expiration date and this procedure is available, comply with the guaranteed delivery procedures described under “—Guaranteed Delivery Procedure” below.

The method of delivery of the Initial Notes, the letter of transmittal and all other required documents is at your election and risk. Instead of delivery by mail, we recommend that you use an overnight or hand-delivery service. If you choose the mail, we recommend that you use registered mail, properly insured, with return receipt requested.In all cases, you should allow sufficient time to assure timely delivery. You should not send any letters of transmittal or Initial Notes to us. You must deliver all documents to the exchange agent at its address provided below. You may also request your broker, dealer, commercial bank, trust company or nominee to tender your Initial Notes on your behalf.

Only a holder of Initial Notes may tender Initial Notes in this Exchange Offer. A holder is any person in whose name Initial Notes are registered on our books or any other person who has obtained a properly completed bond power from the registered holder.

If you are the 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 Notes, you must contact that registered holder promptly and instruct that registered holder to tender your Notes on your behalf. If you wish to tender your Initial Notes on your own behalf, you must, before completing and executing the letter of transmittal and delivering your Initial Notes, either make appropriate arrangements to register the ownership of these Notes in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time.

You must have any signatures on a letter of transmittal or a notice of withdrawal guaranteed by:

(1) a member firm of a registered national securities exchange or of the Financial, Industry Regulatory Authority, Inc. (“FINRA”);

(2) a commercial bank or trust company having an office or correspondent in the United States; or

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(3) an eligible guarantor institution within the meaning of Rule17Ad-15 under the Exchange Act,unless the Initial Notes are tendered:

(i) by a registered holder or by a participant in DTC whose name appears on a security position listing as the owner, who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal and only if the Exchange Notes are being issued directly to this registered holder or deposited into this participant’s account at DTC; or

(ii) for the account of a member firm of a registered national securities exchange or of FINRA, a commercial bank or trust company having an office or correspondent in the United States or an eligible guarantor institution within the meaning of Rule17Ad-15 under the Exchange Act.

If the letter of transmittal or any bond powers are signed by:

(1) the registered holder(s) of the Initial Notes tendered: the signature must correspond with the name(s) written on the face of the Initial Notes without alteration, enlargement or any change whatsoever.

(2) a participant in DTC: the signature must correspond with the name as it appears on the security position listing as the holder of the Initial Notes.

(3) a person other than the registered holder of any Initial Notes: these Initial Notes must be endorsed or accompanied by bond powers and a proxy that authorize this person to tender the Initial Notes on behalf of the registered holder, in satisfactory form to us as determined in our sole discretion, in each case, as the name of the registered holder or holders appears on the Initial Notes.

(4) trustees, executors, administrators, guardians,attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity: these persons should so indicate when signing. Unless waived by us, evidence satisfactory to us of their authority to so act must also be submitted with the letter of transmittal.

To tender your Initial Notes in this Exchange Offer, you must make the following representations:

(1) you are authorized to tender, sell, assign and transfer the Initial Notes tendered and to acquire Exchange Notes issuable upon the exchange of such tendered Initial Notes, and that we will acquire good and unencumbered title thereto, free and clear of all liens, restrictions, charges and encumbrances and not subject to any adverse claim when the same are accepted by us;

(2) any Exchange Notes acquired by you pursuant to the Exchange Offer are being acquired in the ordinary course of business, whether or not you are the holder;

(3) you or any other person who receives Exchange Notes, whether or not such person is the holder of the Exchange Notes, has no arrangement or understanding with any person to participate in a distribution of such Exchange Notes (within the meaning of the Securities Act) and is not participating in, and does not intend to participate in, the distribution of such Exchange Notes;

(4) you or such other person who receives Exchange Notes, whether or not such person is the holder of the Exchange Notes, is not an “affiliate” (as defined in Rule 405 of the Securities Act) of ours, or if you or such other person is an affiliate, you or such other person will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable;

(5) if you are not a broker-dealer, you represent that you are not engaged in, and do not intend to engage in, a distribution of Exchange Notes; and

(6) if you are a broker-dealer that will receive Exchange Notes for your own account in exchange for Initial Notes that were acquired by you as a result of market-making or other trading activities, you acknowledge that you will deliver a prospectus (or, to the extent permitted by law, make available a prospectus to purchasers) meeting the requirements of the Securities Act in connection with any resale, offer to resell or other transfer of such Exchange Notes.

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You must also warrant that the acceptance of any tendered Initial Notes by us and the issuance of Exchange Notes in exchange therefor shall constitute performance in full of our obligations under the Registration Rights Agreement.

To effectively tender Notes through DTC, the financial institution that is a participant in DTC will electronically transmit its acceptance through the Automated Tender Offer Program. DTC will then edit and verify the acceptance and send an agent’s message to the exchange agent for its acceptance. An agent’s message is a message transmitted by DTC to the exchange agent stating that DTC has received an express acknowledgment from the participant in DTC tendering the Notes that this participant has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce this agreement against this participant.

Book-Entry Delivery Procedure

Any financial institution that is a participant in DTC’s systems may make book-entry deliveries of Initial Notes by causing DTC to transfer these Initial Notes into the exchange agent’s account at DTC in accordance with DTC’s procedures for transfer. To effectively tender the Initial Notes through DTC, the financial institution that is a participant in DTC will electronically transmit its acceptance through the Automated Tender Offer Program. DTC will then edit and verify the acceptance and send an agent’s message to the exchange agent for its acceptance. An agent’s message is a message transmitted by DTC to the exchange agent stating that DTC has received an express acknowledgment from the participant in DTC tendering the Initial Notes that this participant has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce this agreement against this participant. The exchange agent will make a request to establish an account for the Initial Notes at DTC for purposes of the Exchange Offer within two business days after the date of this prospectus.

A delivery of Initial Notes through a book-entry transfer into the exchange agent’s account at DTC will only be effective if an agent’s message, or the letter of transmittal or a facsimile of the letter of transmittal with any required signature guarantees and any other required documents, is transmitted to and received by the exchange agent at the address indicated below under “—Exchange Agent” before the expiration date unless the guaranteed delivery procedures described below are complied with.Delivery of documents to DTC does not constitute delivery to the exchange agent.

Guaranteed Delivery Procedure

If you are a registered holder of Initial Notes and desire to tender your Notes, and (1) these Notes are not immediately available, (2) time will not permit your Notes or other required documents to reach the exchange agent before the expiration date or (3) the procedures for book-entry transfer cannot be completed on a timely basis, you may still tender in this Exchange Offer if:

(1) you tender through a member firm of a registered national securities exchange or of FINRA, a commercial bank or trust company having an office or correspondent in the United States, or an eligible guarantor institution within the meaning of Rule17Ad-15 under the Exchange Act;

(2) before the expiration date, the exchange agent receives a properly completed and duly executed letter of transmittal (or facsimile of the letter of transmittal), and a notice of guaranteed delivery, substantially in the form provided by us, with your name and address as holder of the Initial Notes and the amount of Notes tendered, stating that the tender is being made by that letter and notice and guaranteeing that within 3 NYSE trading days after the expiration date, the certificates for all the Initial Notes tendered, in proper form for transfer, or a book-entry confirmation with an agent’s message, as the case may be, and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent; and

(3) the certificates for all your tendered Initial Notes in proper form for transfer or a book-entry confirmation as the case may be, and all other documents required by the letter of transmittal are received by the exchange agent within 3 NYSE trading days after the expiration date.

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Acceptance of Initial Notes for Exchange; Delivery of Exchange Notes

Your tender of Initial Notes will constitute an agreement between you and us governed by the terms and conditions provided in this prospectus and in the related letter of transmittal.

We will be deemed to have received your tender as of the date when your duly signed letter of transmittal accompanied by your Initial Notes tendered, or a timely confirmation of a book-entry transfer of these Notes into the exchange agent’s account at DTC with an agent’s message, or a notice of guaranteed delivery from an eligible institution is received by the exchange agent.

All questions as to the validity, form, eligibility, including time of receipt, acceptance and withdrawal of tenders will be determined by us in our sole discretion. Our determination will be final and binding.

We reserve the absolute right to reject any and all Initial Notes not properly tendered or any Initial Notes which, if accepted, would, in our opinion or our counsel’s opinion, be unlawful. We also reserve the absolute right to waive any conditions of this Exchange Offer or irregularities or defects in tender as to particular Notes with the exception of conditions to this Exchange Offer relating to the obligations of broker dealers, which we will not waive. If we waive a condition to this Exchange Offer, the waiver will be applied equally to all note holders. Our interpretation of the terms and conditions of this Exchange Offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of Initial Notes must be cured within such time as we shall determine. We, the exchange agent or any other person will be under no duty to give notification of defects or irregularities with respect to tenders of Initial Notes. We and the exchange agent or any other person will incur no liability for any failure to give notification of these defects or irregularities. Tenders of Initial Notes will not be deemed to have been made until such irregularities have been cured or waived. The exchange agent will return without cost to their holders any Initial Notes that are not properly tendered and as to which the defects or irregularities have not been cured or waived promptly following the expiration date.

If all the conditions to the Exchange Offer are satisfied or waived on the expiration date, we will accept all Initial Notes properly tendered and will issue the Exchange Notes promptly thereafter. Please refer to the section of this prospectus entitled “—Conditions to the Exchange Offer” below. For purposes of this Exchange Offer, Initial Notes will be deemed to have been accepted as validly tendered for exchange when, as and if we give oral or written notice of acceptance to the exchange agent.

We will issue the Exchange Notes in exchange for the Initial Notes tendered pursuant to a notice of guaranteed delivery by an eligible institution only against delivery to the exchange agent of the letter of transmittal, the tendered Initial Notes and any other required documents, or the receipt by the exchange agent of a timely confirmation of a book-entry transfer of Initial Notes into the exchange agent’s account at DTC with an agent’s message, in each case, in form satisfactory to us and the exchange agent.

If any tendered Initial Notes are not accepted for any reason provided by the terms and conditions of this Exchange Offer or if Initial Notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted ornon-exchanged Initial Notes will be returned without expense to the tendering holder, or, in the case of Initial Notes tendered by book-entry transfer procedures described above, will be credited to an account maintained with the book-entry transfer facility, promptly after withdrawal, rejection of tender or the expiration or termination of the Exchange Offer.

By tendering into this Exchange Offer, you will irrevocably appoint our designees as yourattorney-in-fact and proxy with full power of substitution and resubstitution to the full extent of your rights on the Initial Notes tendered. This proxy will be considered coupled with an interest in the tendered Initial Notes. This appointment will be effective only when, and to the extent that we accept your Notes in this Exchange Offer. All prior proxies on these Initial Notes will then be revoked and you will not be entitled to give any subsequent proxy. Any proxy

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that you may give subsequently will not be deemed effective. Our designees will be empowered to exercise all voting and other rights of the holders as they may deem proper at any meeting of note holders or otherwise. The Initial Notes will be validly tendered only if we are able to exercise full voting rights on the Initial Notes, including voting at any meeting of the note holders, and full rights to consent to any action taken by the note holders.

Withdrawal of Tenders

Except as otherwise provided in this prospectus, you may withdraw tenders of Initial Notes at any time before 5:00 p.m., New York City time, on the expiration date.

For a withdrawal to be effective, you must send a written or facsimile transmission notice of withdrawal to the exchange agent before 5:00 p.m., New York City time, on the expiration date at the address provided below under “—Exchange Agent” and before acceptance of your tendered Notes for exchange by us.

Any notice of withdrawal must:

(1) specify the name of the person having tendered the Initial Notes to be withdrawn;

(2) identify the Notes to be withdrawn, including, if applicable, the registration number or numbers and total principal amount of these Notes;

(3) be signed by the person having tendered the Initial Notes to be withdrawn in the same manner as the original signature on the letter of transmittal by which these Notes were tendered, including any required signature guarantees, or be accompanied by documents of transfer sufficient to permit the trustee for the Initial Notes to register the transfer of these Notes into the name of the person having made the original tender and withdrawing the tender;

(4) specify the name in which any of these Initial Notes are to be registered, if this name is different from that of the person having tendered the Initial Notes to be withdrawn; and

(5) if applicable because the Initial Notes have been tendered through the book-entry procedure, specify the name and number of the participant’s account at DTC to be credited, if different than that of the person having tendered the Initial Notes to be withdrawn.

We will determine all questions as to the validity, form and eligibility, including time of receipt, of all notices of withdrawal and our determination will be final and binding on all parties. Initial Notes that are withdrawn will be deemed not to have been validly tendered for exchange in this Exchange Offer.

The exchange agent will return without cost to their holders all Initial Notes that have been tendered for exchange and are not exchanged for any reason, promptly after withdrawal, rejection of tender or expiration or termination of this Exchange Offer.

You may retender properly withdrawn Initial Notes in this Exchange Offer by following one of the procedures described under “—Procedures for Tendering Initial Notes” above at any time before 5:00 p.m., New York City time, on the expiration date.

Conditions to the Exchange Offer

We will complete this Exchange Offer only if:

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

(2) 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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(3) there is no stop order issued by the SEC 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;

(4) there is no litigation or threatened litigation which would impair our ability to proceed with this Exchange Offer; and

(5) we obtain all governmental approvals that we deem necessary to complete this Exchange Offer.

These conditions are for our sole benefit. We may assert any one of these conditions regardless of the circumstances giving rise to it and may also waive any one of them, in whole or in part, at any time and from time to time, if we determine in our sole discretion that it has not been satisfied, subject to applicable law. Notwithstanding the foregoing, all conditions to the Exchange Offer must be satisfied or waived before the expiration of this Exchange Offer. If we waive a condition to this Exchange Offer, the waiver will be applied equally to all note holders. We will not be deemed to have waived our rights to assert or waive these conditions if we fail at any time to exercise any of them. Each of these rights will be deemed an ongoing right which we may assert at any time and from time to time.

If we determine that we may terminate this Exchange Offer because any of these conditions is not satisfied, we may:

(1) refuse to accept and return to their holders any Initial Notes that have been tendered;

(2) extend the Exchange Offer and retain all Initial Notes tendered before the expiration date, subject to the rights of the holders of these Notes to withdraw their tenders; or

(3) waive any condition that has not been satisfied and accept all properly tendered Initial Notes that have not been withdrawn or otherwise amend the terms of this Exchange Offer in any respect as provided under the section in this prospectus entitled “—Expiration Date; Extensions; Amendments; Termination.”

Accounting Treatment

We will record the Exchange Notes at the same carrying value as the Initial Notes as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes.

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Exchange Agent

We have appointed Wilmington Trust, National Association as the exchange agent for the Exchange Offer. All executed letters of transmittal should be directed to the exchange agent at the address set forth below. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal should be directed to the exchange agent addressed as follows:

Wilmington Trust, National Association, Exchange Agent

By Registered or Certified Mail, Overnight Delivery:

Rodney Square North

1100 North Market Street

Wilmington, DE 19890

Attention: Workflow Management, 5th Floor

By Facsimile Transmission

(for Eligible Institutions only):

(302)636-4139

Attention: Workflow Management

Fax cover sheets should provide a call back phone number and request a call back, upon receipt.

Other Inquiries of Confirmations:

DTC Desk (DTC2@wilmingtontrust.com)

DELIVERY OF THE LETTER OF TRANSMITTAL TO AN ADDRESS OTHER THAN AS SET FORTH ABOVE OR TRANSMISSION OF SUCH LETTER OF TRANSMITTAL VIA FACSIMILE OTHER THAN AS SET FORTH ABOVE DOES NOT CONSTITUTE A VALID DELIVERY OF THE LETTER OF TRANSMITTAL.

Fees and Expenses

We will bear the expenses of soliciting tenders in this Exchange Offer, including reasonable fees and expenses of the exchange agent and trustee and accounting, legal, printing and related fees and expenses.

We will not make any payments to brokers, dealers or other persons soliciting acceptances of this Exchange Offer. However, we will pay the exchange agent reasonable and customary fees for its services and will reimburse the exchange agent for its reasonableout-of-pocket expenses in connection with this Exchange Offer. We will also pay brokerage houses and other custodians, nominees and fiduciaries their reasonableout-of-pocket expenses for forwarding copies of the prospectus, letters of transmittal and related documents to the beneficial owners of the Initial Notes and for handling or forwarding tenders for exchange to their customers.

We will pay all transfer taxes, if any, applicable to the exchange of Initial Notes in accordance with this Exchange Offer. However, tendering holders will pay the amount of any transfer taxes, whether imposed on the registered holder or any other persons, if:

(1) certificates representing Exchange Notes or Initial Notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be registered or issued in the name of, any person other than the registered holder of the Notes tendered;

(2) tendered Initial Notes are registered in the name of any person other than the person signing the letter of transmittal; or

(3) a transfer tax is payable for any reason other than the exchange of the Initial Notes in this Exchange Offer.

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If you do not submit satisfactory evidence of the payment of any of these taxes or of any exemption from this payment with the letter of transmittal, we will bill you directly the amount of these transfer taxes.

Your Failure to Participate in the Exchange Offer Will Have Adverse Consequences

If you do not exchange your Initial Notes for the Exchange Notes in the Exchange Offer, your Initial Notes will continue to be subject to the provisions of the indenture regarding the transfer and exchange of the Initial Notes and the restrictions on transfer of the Initial Notes described in the legend on your certificates. These transfer restrictions are required because the Initial Notes were issued under an exemption from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws. Therefore, you may not resell your Initial Notes, offer such Notes for resale or otherwise transfer such Notes unless they are subsequently registered or resold under an exemption from the registration requirements of the Securities Act and applicable state securities laws. If you do not exchange your Initial Notes for Exchange Notes in accordance with this Exchange Offer, or if you do not properly tender your Initial Notes in this Exchange Offer, you will not be able to resell, offer to resell or otherwise transfer the Initial Notes unless they are registered under the Securities Act or unless you resell such Notes, offer to resell or otherwise transfer such Notes under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.

In addition, except as set forth in this paragraph, you will not be able to obligate us to register the Initial Notes under the Securities Act. 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; or

• 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 the resale of any Initial Notes that remain outstanding after completion of this Exchange Offer.

Delivery of Prospectus

Each broker-dealer that receives Exchange Notes for its own account 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, must acknowledge that it will deliver a prospectus (or, to the extent permitted by law, make available a prospectus to purchasers) in connection with any resale, resell or offer to transfer of such Exchange Notes. See “Plan of Distribution.”

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DESCRIPTION OF OTHER INDEBTEDNESS

The following sets forth a summary of the terms of the Bank Credit Facility. This summary is not a complete description of all the terms of the agreements governing the Bank Credit Facility.

The Bank Credit Facility

Concurrently with the closing of the Transactions, Holdings entered into a Credit Agreement, (the “Bank Credit Facility”) between Holdings, as borrower, Talos Energy Inc., as holdings, JPMorgan Chase Bank, N.A., as administrative agent, collateral agent, and swingline lender, the other lenders party thereto from time to time (the “Lenders”), and Natixis, New York Branch and The Toronto-Dominion Bank, New York Branch, as issuing banks, and each other issuing bank from time to time party thereto.

The Bank Credit Facility is a senior secured revolving credit facility that provides for aggregate borrowings of up to $1.0 billion, including sublimits of $200.0 million for letters of credit and $10.0 million for swingline loans. The availability under the Bank Credit Facility is subject to a borrowing base (the “Borrowing Base”), which is initially set at $600.0 million. The Bank Credit Facility permits Holdings to increase commitments under the Bank Credit Facility up to a maximum aggregate commitment of $1.5 billion subject to customary restrictions on such increase.

The obligations of Holdings under the Bank Credit Facility are guaranteed by each direct or indirect wholly-owned U.S. restricted subsidiary of Holdings that is a material subsidiary (such entities, the “Bank Credit Facility Guarantors”). The obligations of Holdings and the Bank Credit Facility Guarantors are secured by substantially all assets of Holdings and the Bank Credit Facility Guarantors.

Borrowings under the Bank Credit Facility bear interest at a rate equal to, at Holdings’ option, either (1) a base rate plus an applicable margin ranging between 1.75% per annum and 2.75% per annum, based upon the amount of availability under the Borrowing Base or (2) a LIBOR rate plus an applicable margin ranging between 2.75% per annum and 3.75% per annum, based upon the amount of availability under the Borrowing Base.

The Bank Credit Facility contains customary representations and warranties and customary affirmative and negative covenants, including limits or restrictions on Holdings’ ability to incur liens, incur indebtedness, make certain restricted payments, merge or consolidate and dispose of assets. The Bank Credit Facility requires compliance with customary financial covenants, which are a maximum leverage ratio of 3.00 to 1.00 and a current ratio of 1.00 to 1.00. In addition, the Bank Credit Facility contains customary events of default that entitle the Lenders to cause any or all of Holdings’ indebtedness under the Bank Credit Facility to become immediately due and payable. The events of default (some of which are subject to applicable grace or cure periods), include among other things,non-payment defaults, covenant defaults, cross-defaults to other material indebtedness, bankruptcy and insolvency defaults and material judgment defaults.

The foregoing description of the Bank Credit Facility does not purport to be complete and is subject to and qualified in its entirety by reference to the complete text of the Bank Credit Facility, a copy of which is included as exhibit 10.1 to the registration statement of which this prospectus forms a part.

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DESCRIPTION OF THE NOTES

General

On May 10, 2018, Talos Production LLC, a Delaware limited liability company, and Talos Production Finance Inc., a Delaware corporation (each an “Issuer” and together, the “Issuers”), issued 11.00% Second-Priority Senior Secured Notes due 2022 (the “notes”) under an indenture (the “indenture”), by and among themselves, the Subsidiary Guarantors (as defined below) and Wilmington Trust, National Association, as Trustee and Collateral Agent. Copies of the indenture may be obtained from the Issuers upon request. For purpose of this “Description of the Notes”, the term “notes” shall refer to both the Initial Notes and the Exchange Notes.

The following summary of certain provisions of the indenture, the notes, the Security Documents and the Senior Lien Intercreditor Agreement does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all the provisions of those agreements, including the definitions of certain terms therein. Capitalized terms used in this “Description of the Notes” section and not otherwise defined have the meanings set forth in the section “—Certain Definitions.”

The Issuers will issue Exchange Notes in exchange for Initial Notes, in an initial aggregate principal amount of up to $390,867,820. Following the Issue Date, the Issuers may issue additional notes from time to time. Any offering of additional notes is subject to the covenants described below under the caption “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and “—Certain Covenants—Liens.” The notes and any additional notes subsequently issued under the indenture may, at our election, be treated as a single class for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase;provided that if the additional notes are not fungible with the notes for U.S. federal income tax purposes, the additional notes will have a separate CUSIP number, if applicable. Unless the context otherwise requires, for all purposes of the indenture and this “Description of the Notes,” references to the notes include any additional notes actually issued.

Principal of, premium, if any, and interest on the Exchange Notes will be payable, and the Exchange Notes may be exchanged or transferred, at the office or agency designated by the Issuers (which initially shall be the designated office or agency of the Trustee).

The Exchange Notes will be issued only in fully registered form, without coupons, in minimum denominations of $2,000 and any integral multiple of $1.00 in excess thereof; provided that notes may be issued in denominations of less than $2,000 solely to accommodate book-entry positions that have been created by a DTC participant in denominations of less than $2,000. No service charge will be made for any registration of transfer or exchange of Exchange Notes, but the Issuers may require payment of a sum sufficient to cover any transfer tax or other similar governmental charge payable in connection therewith.

Terms of the Notes

The notes are senior obligations of the Issuers and are secured only by the second-priority security interests in the Collateral described below under “—Security.” The notes will mature on April 3, 2022. Each note bears interest at a rate of 11.00% per annum from the Issue Date or from the most recent date to which interest has been paid or duly provided for, payable semiannually to holders of record at the close of business on April 1 or October 1 immediately preceding the interest payment date on April 15 and October 15 of each year, commencing October 15, 2018.

Optional Redemption

On or after the first anniversary of the Issue Date, the Issuers may redeem the notes at their option, in whole at any time or in part from time to time, upon not less than 30 nor more than 60 days’ prior notice mailed by first

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class mail to each holder’s registered address or delivered electronically if held by DTC, at the following redemption prices (expressed as a percentage of principal amount), plus accrued and unpaid interest and Additional Interest, if any, to, but excluding, the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the12-month period commencing on the anniversary of the Issue Date of the years set forth below:

Period	Redemption Price
2019		105.500	%
2020		102.750	%
2021 and thereafter		100.000	%

In addition, prior to the first anniversary of the Issue Date, the Issuers may redeem the notes at their option, in whole at any time or in part from time to time, upon not less than 30 nor more than 60 days’ prior notice mailed by the Issuers by first class mail to each holder’s registered address, or delivered electronically if held by DTC, at a redemption price equal to 100% of the principal amount of the notes redeemedplus the Applicable Premium as of, and accrued and unpaid interest and Additional Interest, if any, to, but excluding, the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

Notwithstanding the foregoing, at any time and from time to time on or prior to the first anniversary of the Issue Date, the Issuers may redeem in the aggregate up to 35% of the original aggregate principal amount of the notes (calculated after giving effect to any issuance of additional notes) with the net cash proceeds of one or more Equity Offerings (1) by Holdings or (2) by any direct or indirect parent of Holdings to the extent the net cash proceeds thereof are contributed to the common equity capital of Holdings or used to purchase Capital Stock (other than Disqualified Stock) of Holdings, at a redemption price (expressed as a percentage of principal amount thereof) of 111.000%, plus accrued and unpaid interest and Additional Interest, if any, to the redemption date;provided, that such redemption shall occur within 90 days after the date on which any such Equity Offering is consummated upon not less than 30 nor more than 60 days’ notice mailed by the Issuers to each holder of notes being redeemed, or delivered electronically if held by DTC, and otherwise in accordance with the procedures set forth in the indenture.

Notice of any redemption upon any corporate transaction or other event (including any Equity Offering, incurrence of Indebtedness, Change of Control or other transaction) may be given prior to the completion thereof. In addition, any redemption described above or notice thereof may, at the Issuers’ discretion, be subject to one or more conditions precedent, including, but not limited to, completion of a corporate transaction or other event.

Selection of Notes to be Redeemed; Notes Redeemed in Part

In the case of any partial redemption, selection of notes for redemption will be made by the Trustee in compliance with the requirements of the principal national securities exchange, if any, on which the notes are listed (and the Issuers shall notify the Trustee in writing of any such listing), or if the notes are not so listed, on a pro rata basis to the extent practicable or by lot or by such other method as the Trustee shall deem fair and appropriate (and, in each case, in such manner that complies with the requirements of DTC, if applicable);provided that no notes of $2,000 or less shall be redeemed in part. The Trustee shall make the selection from outstanding notes not previously called for redemption. Upon selection, the Trustee will notify the Issuers promptly of the notes or portions of notes to be redeemed. If any note is to be redeemed in part only, the notice of redemption relating to such note shall state the portion of the principal amount thereof to be redeemed. Upon surrender and cancellation of a note that is redeemed in part, the Issuers will execute and the Trustee will authenticate for the holder (at the Issuers’ expense) a new note equal in principal amount to the unredeemed portion of the note surrendered and cancelled. If money sufficient to pay the redemption price of and accrued and unpaid interest on all notes (or portions thereof) to be redeemed on the redemption date is deposited with a paying agent on or before the redemption date and certain other conditions are satisfied, on and after such date, interest will cease to accrue on such notes (or such portions thereof) called for redemption.

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Mandatory Redemption; Offers to Purchase; Open Market Purchases

The Issuers will not be required to make any mandatory redemption or sinking fund payments with respect to the notes. However, under certain circumstances, the Issuers may be required to offer to purchase notes as described under the captions “—Change of Control” and “—Certain Covenants—Asset Sales.” We may at any time and from time to time purchase notes in the open market or otherwise.

Ranking

The indebtedness evidenced by the notes and the Subsidiary Guarantees, respectively, is senior Indebtedness of the Issuers and the Subsidiary Guarantors, rankspari passu in right of payment with all existing and future senior Indebtedness of the Issuers and the Subsidiary Guarantors, and is senior in right of payment to all existing and future Subordinated Indebtedness of the Issuers and the Subsidiary Guarantors. The notes and the Subsidiary Guarantees have the benefit of a second-priority security interest in the Collateral as described under “—Security,” which also secures First-Priority Lien Obligations on a senior basis and Other Second Lien Obligations on apari passu basis, in each case, subject to Permitted Liens and exceptions described under the caption “—Security.”

At June 30, 2018, on an actual basis:

(1) Holdings and its Subsidiaries had $390,867,820 of notes outstanding;

(2) Holdings and its Subsidiaries had $6,060,218 of Stone Notes outstanding, which are unsecured obligations and are effectively junior to the notes to the extent of the value of the collateral securing the notes.; and

(3) Holdings and its Subsidiaries had approximately $240.0 million outstanding under the Credit Agreement (which constitutes First-Priority Obligations), and to all of which the notes are effectively subordinated with respect to the Liens on the Collateral shared by such Indebtedness.

Although the indenture limits the Incurrence of Indebtedness and the issuance of Disqualified Stock by Holdings and its Restricted Subsidiaries, and the issuance of Preferred Stock by the Restricted Subsidiaries of Holdings that are not Subsidiary Guarantors, such limitation is subject to a number of significant qualifications and exceptions. Pursuant to such qualifications and exceptions, Holdings and its Subsidiaries may be able to Incur additional amounts of Indebtedness. Under certain circumstances the amount of such Indebtedness could be substantial and, subject to certain limitations, such Indebtedness may be Secured Indebtedness. See “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and “Certain Covenants—Liens.”

Holdings is a holding company that has no material assets or operations other than the equity in the assets of its Subsidiaries. Unless a Subsidiary is a Subsidiary Guarantor, claims of creditors of such Subsidiary, including trade creditors, and claims of preferred stockholders (if any) of such Subsidiary, generally will have priority with respect to the assets and earnings of such Subsidiary over the claims of creditors of the Issuers, including holders of the notes. The notes, therefore, will be effectively subordinated to holders of indebtedness and other creditors (including trade creditors) and preferred stockholders (if any) of Subsidiaries of Holdings that are not Subsidiary Guarantors.

See “Risk Factors—Risks Related to Our Indebtedness and the Notes—The notes will be structurally subordinated to all liabilities of ournon-guarantor subsidiaries.”

Security

The notes and the related guarantees are secured by second priority security interests (subject to Permitted Liens) in the Collateral.

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The Collateral consists of substantially all of the property and assets, in each case, that are held by any Issuer or Subsidiary Guarantor, to the extent that such assets secure the First-Priority Lien Obligations, subject to the exceptions described below. The Collateral does not include, subject to certain exceptions, (i) any real property (owned or leased) or oil and gas properties (owned or leased), other than the Mortgaged Properties, (ii) motor vehicles or other assets subject to certificates of title and commercial tort claims, (iii) letter of credit rights (other than to the extent a Lien thereon can be perfected by filing a customary financing statement), (iv) any assets over which the granting of security interests in such assets would be prohibited by an enforceable contractual obligation binding on such assets that existed at the time of the acquisition thereof and was not created or made binding on such assets in contemplation or in connection with the acquisition of such assets (except in the case of assets owned on the Issue Date or acquired after the Issue Date with any type of “purchase money” Indebtedness otherwise permitted under the indenture), requirement of law or regulation (in each case, except to the extent such prohibition is unenforceable after giving effect to applicable provisions of the Uniform Commercial Code, other than proceeds thereof, the assignment of which is expressly deemed effective under the Uniform Commercial Code notwithstanding such prohibitions) or to the extent that such security interests would require obtaining the consent of any governmental authority or would result in materially adverse tax consequences as reasonably determined by Holdings, (iv) any foreign collateral or credit support with respect to such foreign collateral (other than any pledged stock of a foreign subsidiary directly owned by an Issuer or any Subsidiary Guarantor and pledged pursuant to the Security Documents), (v) any margin stock and, to the extent prohibited by the terms of any applicable organizational documents, joint venture agreement or shareholders’ agreement, equity interests in any Person other than Wholly-Owned Subsidiaries, (vi) any right, title or interest in any license, contract or agreement to which an Issuer or a Subsidiary Guarantor is a party or any of its right, title or interest thereunder to the extent, but only to the extent, that such a grant would violate the terms of applicable law or of such license, contract or agreement, or result in a breach of the terms of, or constitute a default under, any such license, contract or agreement to which an Issuer or such Subsidiary Guarantor is a party (other than to the extent that any such term would be rendered ineffective pursuant toSection 9-406,9-407,9-408 or9-409 of the Uniform Commercial Code or any other applicable law or regulation (including the Bankruptcy Code) or principles of equity); provided, that immediately upon the ineffectiveness, lapse or termination of any such provision, the Collateral shall include all such rights and interests as if such provision had never been in effect, (vii) any equipment or other asset owned by an Issuer or any Subsidiary Guarantor that is subject to a purchase money lien or a Capitalized Lease Obligation, in each case, not prohibited by the indenture, if the contract or other agreement in which the Lien is granted (or the documentation providing for such Capitalized Lease Obligation) prohibits or requires the consent of any Person other than an Issuer or any Subsidiary Guarantor as a condition to the creation of any other security interest on such equipment or asset and, in each case, such prohibition or requirement is not prohibited by the indenture, (viii) any asset at any time that is not then subject to a Lien securing First-Priority Lien Obligations at such time, (ix) those assets with respect to which, in the reasonable judgment of the applicable agent and the Issuers, evidenced in writing delivered to the applicable agent, the costs or other consequences of obtaining or perfecting such a security interest are excessive in view of the benefits to be obtained by the Secured Parties therefrom and (x) certain other exceptions described in the Security Documents, including the limitation on stock collateral described below (all such excluded assets referred to as “Excluded Assets”). The security interests in the Collateral securing the notes are second in priority to any and all security interests at any time granted to secure the First-Priority Lien Obligations and are also subject to all other Permitted Liens. No control agreements or control arrangements will be required with respect to any assets requiring perfection through control, control agreements or other control arrangements (other than control of pledged capital stock that is certificated to the extent otherwise required to be included in the Collateral), including deposit accounts, securities accounts and commodities accounts. The First Priority Lien Obligations include Secured Bank Indebtedness and related obligations, as well as certain Hedging Obligations and certain other obligations in respect of cash management services. Secured Bank Indebtedness includes the Credit Agreement. The Persons holding First-Priority Lien Obligations may have rights and remedies with respect to the Collateral that, if exercised, could adversely affect the value of the Collateral or the ability of the Collateral Agent to realize or foreclose on the Collateral on behalf of the holders of the notes.

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The Issuers and the Subsidiary Guarantors are able to Incur additional Indebtedness in the future that could share in the Collateral, including additional First Priority-Lien Obligations and additional Indebtedness that would be secured on a pari passu basis with the notes. The amount of such First-Priority Lien Obligations and additional Indebtedness is limited by the covenants described under “—Certain Covenants—Liens” and “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuances of Disqualified Stock and Preferred Stock.” Under certain circumstances, the amount of such First-Priority Lien Obligations and additional Indebtedness could be significant.

Limitations on securities collateral

The Capital Stock and securities of a Subsidiary of Holdings that are owned by an Issuer or any Subsidiary Guarantor will constitute Collateral only to the extent that such Capital Stock and securities can secure the notes without Rule3-10 or Rule3-16 of RegulationS-X under the Securities Act (or any other law, rule or regulation) requiring separate financial statements of such Subsidiary to be filed with the SEC (or any other governmental agency). In the event that Rule3-10 or Rule3-16 of RegulationS-X under the Securities Act requires or is amended, modified or interpreted by the SEC to require (or is replaced with another rule or regulation, or any other law, rule or regulation is adopted, which would require) the filing with the SEC (or any other governmental agency) of separate financial statements of any Subsidiary due to the fact that such Subsidiary’s Capital Stock or securities secure the notes or any Guarantee, then the Capital Stock and/or securities of such Subsidiary shall automatically be deemed not to be part of the Collateral (but only to the extent necessary to not be subject to such requirement). In such event, the Security Documents may be amended or modified, without the consent of the Trustee or any holder of notes, to the extent necessary to release the security interests on the shares of Capital Stock and securities that are so deemed to no longer constitute part of the Collateral.

In the event that Rule3-10 or Rule3-16 of RegulationS-X under the Securities Act is amended, modified or interpreted by the SEC to permit (or is replaced with another rule or regulation, or any other law, rule or regulation is adopted, which would permit) such Subsidiary’s Capital Stock or securities to secure the notes in excess of the amount then pledged without the filing with the SEC (or any other governmental agency) of separate financial statements of such Subsidiary, then the Capital Stock and/or securities of such Subsidiary shall automatically be deemed to be a part of the Collateral (but only to the extent that will not result in such Subsidiary being subject to any such financial statement requirement). In such event, the Security Documents may be amended or modified, without the consent of the Trustee or any holder of notes, to the extent necessary to subject to the Liens under the Security Documents such additional Capital Stock and securities, on the terms contemplated therein.

After-Acquired Property

Upon the acquisition by Holdings or any Subsidiary Guarantor of any First-Priority After-Acquired Property, or upon any additional Restricted Subsidiary becoming a Subsidiary Guarantor that has First-Priority After-Acquired Property, Holdings or such Subsidiary Guarantor shall execute and deliver such mortgages, deeds of trust, security instruments, financing statements and other Security Documents as shall be reasonably necessary to vest in the Collateral Agent a perfected second-priority security interest, subject only to Permitted Liens, in such First-Priority After-Acquired Property and to have such First-Priority After-Acquired Property (but subject to the limitations described in the Security Documents, the Senior Lien Intercreditor Agreement and limitations under applicable local law) added to the Collateral, and thereupon all provisions of the indenture relating to the Collateral shall be deemed to relate to such First-Priority After-Acquired Property to the same extent and with the same force and effect.

Notwithstanding the foregoing, if granting a security interest in any property pursuant to the first paragraph under this heading requires the consent of a third party, Holdings will use commercially reasonable efforts to obtain such consent with respect to such security interest for the benefit of the Collateral Agent on behalf of the Secured Parties. If such third party does not consent to the granting of such security interest after the use of such commercially reasonable efforts, the applicable entity will not be required to provide such security interest.

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Holdings shall review each Reserve Report prepared as of each June 30th and December 31st (which shall be prepared by no later than September 30th of the same year for Reserve Reports as of June 30th and March 31st of the following year for Reserve Reports as of December 31st) and the list of current Mortgaged Properties, to ascertain whether thePV-10 of the Mortgaged Properties (calculated at the time of redetermination) meets the Collateral Coverage Minimum after giving effect to exploration and production activities, acquisitions, dispositions and production. In the event that thePV-10 of the Mortgaged Properties (calculated at the time of review) does not meet the Collateral Coverage Minimum, then the Issuers shall use best efforts, and shall cause the Subsidiary Guarantors to use best efforts to, grant, no later than (i) with respect to the Reserve Report prepared as of December 31st, April 30th of the following fiscal year and (ii) with respect to the Reserve Report prepared as of June 30th, October 31st of the same fiscal year, to the Collateral Agent as security for the Obligations a second-priority Lien interest (subject to Permitted Liens and the Senior Lien Intercreditor Agreement) on additional Oil and Gas Properties not already subject to a Lien of the Security Documents such that, after giving effect thereto, thePV-10 of the Mortgaged Properties (calculated at the time of review) meets the Collateral Coverage Minimum. All such Liens will be created and perfected by and in accordance with the provisions of the Security Documents, including, if applicable, any additional Mortgages. In order to comply with the foregoing, if any Restricted Subsidiary places a Lien on its property and such Subsidiary is not a Guarantor, then it shall become a Guarantor and comply with the provisions of the first two paragraphs under this heading.

Notwithstanding anything herein to the contrary, (i) if the Issuers or any Subsidiary Grantor grants a lien on any assets to secure any Secured Bank Indebtedness, the Issuers or the applicable Subsidiary Guarantor will be required to provide a perfected second-priority security interest in such assets, subject to only Permitted Liens, to secure the Notes Obligations and (ii) if the Issuers or any Subsidiary Guarantor grants a lien on any assets to secure any Other Second-Lien Obligations, the Issuers or the applicable Subsidiary Guarantor will be required to provide a perfected second-priority security interest in such assets, pari passu with such Other Second-Lien Obligations, subject to only Permitted Liens, to secure the Notes Obligations.

Security Documents

The Issuers, the Subsidiary Guarantors and the Collateral Agent have entered into the Security Documents defining the terms of the security interests that secure the notes. These security interests secure the payment and performance when due of all of the Obligations of the Issuers and the Subsidiary Guarantors under the notes, the Subsidiary Guarantees, the indenture and the Security Documents, as provided in the Security Documents.

Subject to the terms of the Security Documents and the indenture, the Issuers and the Subsidiary Guarantors have the right to remain in possession and retain exclusive control of the Collateral securing the notes, to freely operate the Collateral and to collect, invest and dispose of any income therefrom.

Senior Lien Intercreditor Agreement

The Collateral Agent and the RBL Agent have entered into the Senior Lien Intercreditor Agreement, which establishes the subordination of Liens securing the Notes Obligations and Other Second-Lien Obligations to the Liens securing the First-Priority Lien Obligations with respect to the Collateral and which may be amended from time to time, without the consent of the Trustee and the holders of the notes, to add other parties holding, or representing holders of, Other Second-Lien Obligations and other First Priority-Lien Obligations, in each case, to the extent not prohibited to be Incurred under the indenture. The RBL Agent is initially the administrative agent under the Credit Agreement. Pursuant to the terms of the Senior Lien Intercreditor Agreement, at any time at which First-Priority Lien Obligations are outstanding (whether incurred prior to, on or after the Issue Date), the RBL Agent will (subject to the180-day “standstill” period described below) the exclusive right to make the determination by which the Liens in the Collateral will be enforced. Subject to the Standstill Period described below, the Collateral Agent will not be permitted to enforce the security interests except (a) in any Insolvency Proceeding, as necessary or appropriate to file a claim or statement of interest with respect to such notes and

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(b) as necessary to take any action (not adverse to the Liens securing the First-Priority Lien Obligations, the priority status thereof, or the rights of the RBL Agent or any of the First Lien Secured Parties to exercise rights, powers and/or remedies in respect thereof) in order to create, perfect, preserve or protect (but not enforce) its Liens in the Collateral. The Collateral Agent and the holder of the notes and any Other Second-Priority Obligations may also (i) file any necessary or appropriate responsive or defensive pleadings in opposition to any motion, claim, adversary proceeding or other pleading made by any person objecting to or otherwise seeking the disallowance of the claims or Liens of such parties, including any claims secured by the Security Documents, in each case in accordance with the terms of the Senior Lien Intercreditor Agreement, (ii) file any pleadings, objections, motions or agreements which assert rights or interests available to unsecured creditors of the pledgors arising under either any Insolvency Proceeding or applicablenon-bankruptcy law, in each case not inconsistent with the terms of the Senior Lien Intercreditor Agreement or applicable law and (iii) vote on any plan of reorganization or similar dispositive plan proposed in or in connection with any Insolvency Proceeding that is consistent with the terms of the Senior Lien Intercreditor Agreement and make other filings and any arguments, obligations, and motions (including in support of or opposition to, as applicable, the confirmation or approval of any plan of reorganization) that are, in each case, in accordance with the terms of the Senior Lien Intercreditor Agreement. Further, subject to the provisions in the Senior Lien Intercreditor Agreement, after a period of 180 days has elapsed since the date on which the Collateral Agent has delivered to the RBL Agent a written notice of the acceleration of the applicable Second Priority Lien Obligations (the “Standstill Period”), the Collateral Agent may (A) enforce or exercise any rights or remedies (including any right of setoff) with respect to the Collateral or (B) commence any action or proceeding with respect to such rights or remedies if: (i) no holder of First-Priority Lien Obligations shall have commenced or is diligently pursuing the enforcement or exercise of any rights or remedies with respect to a material portion of the Collateral, or shall have sought or requested relief from or modification of the automatic stay or any other stay in any Insolvency Proceeding to enable the commencement and pursuit of such enforcement actions; (ii) any acceleration of the relevant Second Priority Lien Obligations has not been rescinded; and (iii) no Issuer is then a debtor in an Insolvency Proceeding. Notwithstanding the foregoing, (A) the Collateral Agent shall not enforce or exercise any rights or remedies with respect to the Collateral or commence, join with any person in commencing, or petition for or vote in favor of any resolution for, any such action or proceeding if the RBL Agent has commenced and is diligently pursuing (or shall have sought or requested relief from or modification of the automatic stay or any other stay in any Insolvency Proceeding to enable the commencement and pursuit thereof) the enforcement of any rights or remedies with respect to the Collateral or any such action or proceeding (prompt written notice thereof to be given to the Collateral Agent by the RBL Agent) and (B) after the expiration of the Standstill Period, so long as the RBL Agent has not commenced any action to enforce Liens securing the First-Priority Lien Obligations on any material portion of the Collateral, in the event that and for so long as the Collateral Agent has commenced any actions to enforce any rights or remedies with respect to a material portion of the Collateral to the extent permitted by the Senior Lien Intercreditor Agreement and are diligently pursuing such actions, the RBL Agent shall not take any action of a similar nature with respect to such Collateral; provided, that all other provisions of the Senior Lien Intercreditor Agreement (including the turnover provisions) are complied with.

So long as the Discharge of the First-Priority Lien Obligations has not occurred, the Collateral and any other collateral securing the First-Priority Lien Obligations or proceeds thereof received in connection with the disposition of, or collection on, such Collateral or such other collateral upon the exercise of remedies as a secured party shall be applied by the RBL Agent to the applicable holders of the First-Priority Lien Obligations in a manner as specified in the relevant Credit Agreement Documents in accordance with applicable law until the Discharge of the First-Priority Lien Obligations has occurred. At any time upon the Discharge of First-Priority Lien Obligations, subject to the reinstatement of any First-Priority Lien Obligations in accordance with the Senior Lien Intercreditor Agreement, the Collateral Agent, in accordance with the provisions of the indenture and the Security Documents, will distribute all cash proceeds (after payment of the costs of enforcement and collateral administration and any other amounts owed to the Trustee and the Collateral Agent) of the Collateral received by it under the Security Documents for the ratable benefit of the holders of the notes and/or any Other Second Lien Obligations. The proceeds from the sale of the Collateral remaining after the Discharge of First-Priority Lien Obligations may not be sufficient to satisfy the Notes Obligations and any Other Second Lien

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Obligations. By its nature some or all of the Collateral will be illiquid and may have no readily ascertainable market value. Accordingly, the Collateral may not be able to be sold in a short period of time, if saleable. See “Risk Factors—Risks Related to the Collateral—The New Notes and guarantees will be subject to the Intercreditor Agreement that provides the New Notes and the guarantees will be 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.” The Senior Lien Intercreditor Agreement further provides that until the Discharge of First-Priority Lien Obligations has occurred, any Collateral or proceeds thereof received by the trustee, the Collateral Agent or the holders of the notes, in connection with the exercise of any right or remedy (including setoff or recoupment) relating to the Collateral, shall be segregated and held in trust for the benefit of, and forthwith paid over to, the applicable agent of the First-Priority Lien Obligations.

In addition, the Security Documents and the Senior Lien Intercreditor Agreement provide that, prior to the Discharge of First-Priority Lien Obligations, (1) the holders of First-Priority Lien Obligations may direct the RBL Agent to take actions with respect to the manner of realization without any consultation with or the consent of the Trustee, the Collateral Agent or the holders of the notes; (2) the Senior Lien Intercreditor Agreement may be amended, without the consent of the Trustee, the Collateral Agent or the holders of the notes, to add additional secured creditors holding Other Second Lien Obligations or other First-Priority Lien Obligations so long as such modifications are not prohibited by the provisions of the indenture and the Credit Agreement then in effect and (3) in the event that the holders of the First-Priority Lien Obligations enter into any amendment, waiver or consent in respect of or replace any security document securing First-Priority Lien Obligations, then such amendment, waiver, consent or replacement shall apply automatically to any comparable provision of each comparable Security Document without the consent of, and without any action by, the Trustee, the Collateral Agent or the holders of the notes,provided that any such amendment, waiver, consent or replacement does not (i) materially adversely affect the rights of the holders of Second Priority Lien Obligations or their interests in the Collateral to a greater extent than the rights of First- Priority Secured Parties in a like or similar manner (other than by virtue of their relative priorities and rights and obligations under the Senior Lien Intercreditor Agreement) or (ii) adversely affect the rights, duties, protections, privileges, indemnities or immunities of the Collateral Agent. Any provider of additional extensions of credit shall be entitled to rely on the determination of an officer of Holdings that such modifications do not violate the provisions of the Credit Agreement or the indenture then in effect if such determination is set forth in an Officers’ Certificate delivered by Holdings to such provider at its request;provided,however, that such determination will not affect whether or not the Issuers and each other pledgor has complied with its undertakings in the indenture, the Security Documents or the Senior Lien Intercreditor Agreement. Any of the First-Priority Lien Obligations or Second-Priority Lien Obligations may be refinanced to the extent not prohibited by the terms of the indenture and the Credit Agreement;provided that Holdings shall deliver a notice to the RBL Agent and the Collateral Agent if additional obligations have been designated as First-Priority Obligations or Second-Priority Obligations and the agent for such additional obligations shall have become a party to the Senior Lien Intercreditor Agreement.

Further, the Senior Lien Intercreditor Agreement provides that, if the Issuers or any other pledgor are subject to an Insolvency Proceeding, the Collateral Agent and the holders of the notes:

(1) will raise no objection to or otherwise contest (or support any other Person in objecting to or contesting) the Issuers’ or any other pledgor’s, as applicable, (x) use, sale or lease of cash collateral and financing under Section 363 or Section 364 of the Bankruptcy Code or under any other similar law (“DIP Financing”), in each case if the RBL Agent desires to permit such use, sale or lease of cash collateral or (y) to permit the Issuers or any other pledger to obtain a DIP Financing, if the RBL Agent desires to permit such DIP Financing, as applicable,

(2) will not request adequate protection or other relief in connection with any such use of cash collateral or any such DIP Financing,

(3) to the extent the Liens on any Collateral securing the First Priority Lien Obligations (the “First Priority Liens”) are subordinated to or arepari passu with the Liens on such Collateral securing any such DIP

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Financing, will subordinate the Liens on such Collateral securing the notes to the liens securing such DIP Financing (and all Obligations relating thereto, including any“carve-out” from the Collateral granting administrative priority status or Lien priority to secure the payment of fees and expenses of the United States trustee or professionals retained by any debtor or creditors’ committee agreed to by the RBL Agent or the other First Priority Secured Parties) and all adequate protection Liens granted to the RBL Agent, on the same basis as such Liens securing the First Priority Liens are subordinated to the Liens securing the DIP Financing or to confirm the priorities with respect to the First Priority Liens under the Senior Lien Intercreditor Agreement, provided, that the aggregate principal amount of the DIP Financing does not exceed the sum of (i) the aggregate Revolving Outstandings (as defined in the Senior Lien Intercreditor Agreement) outstanding under the Issuer’s then-existing revolving credit facilities and (ii) an amount equal to 50% of the aggregate commitments under such then-existing revolving credit facilities,

(4) will raise no objection to or otherwise contest (or support any other Person in objecting or contesting) (x) any request by the RBL Agent or the holders of First-Priority Lien Obligations for adequate protection in any form or (y) any objection by the RBL Agent or the holders of First-Priority Lien Obligations to any motion, relief, action or proceeding claiming a lack of adequate protection,

(5) will raise no objection to or otherwise contest (or support any other Person in objecting or contesting) any motion for relief from the automatic stay or from any injunction against foreclosure or enforcement in respect of First-Priority Lien Obligations made by the RBL Agent or any holder of First-Priority Lien Obligations, and, so long as First-Priority Lien Obligations are outstanding, will not seek any such relief in respect of the Collateral without the consent of the RBL Agent,

(6) will raise no objection to or otherwise contest (or support any other Person in objecting or contesting) any lawful exercise by any First-Priority Secured Party of the right to credit bid First-Priority Lien Obligations under Section 363(k) of the Bankruptcy Code (or any similar provision under any applicable Bankruptcy Law) or at any sale in foreclosure of Collateral,

(7) will raise no objection to or otherwise contest (or support any other Person in objecting or contesting) any other request for judicial relief made in any court by any First-Priority Secured Party relating to the lawful enforcement of any Lien on Collateral,

(8) will raise no objection to or otherwise contest (or support any other Person in objecting or contesting) any order relating to a sale of Collateral of the Issuers or any pledgor for which the RBL Agent has consented that provides, to the extent the sale is to be free and clear of Liens, that the First Priority Liens and the Liens securing the notes will attach to the proceeds of the sale on the same basis of priority as the First Priority Liens do to the Liens securing the notes in accordance with the Senior Lien Intercreditor Agreement,provided that the Collateral Agent and the holders of the notes may assert any objection to such sale that could be asserted by an unsecured creditor in any Insolvency Proceeding; without limiting the foregoing, the Collateral Agent agrees that it may not raise any objections based on rights afforded by Sections 363(e) and (f) of the Bankruptcy Code to secured creditors with respect to the Liens granted to such person in respect of such assets, and

(9) prior to the Discharge of the First-Priority Lien Obligations, will not assert or enforce any claim under Section 506(c) of the Bankruptcy Code senior to or on a parity with the First Priority Liens for costs or expenses of preserving or disposing of any Collateral and waives any claim it may now or hereafter have arising out of the election by any holder of First-Priority Lien Obligations of the application of Section 1111(b)(2) of the Bankruptcy Code.

Notwithstanding clauses (1), (2) and (4) above, in any Insolvency Proceeding, (i) if the RBL Agent or the holders of First-Priority Lien Obligations (or any subset thereof) are granted adequate protection in the form of a Lien on additional or replacement collateral and/ or a superpriority administrative claim in connection with any DIP Financing or use of cash collateral under the applicable provision of the Bankruptcy Code, then the Collateral Agent or Trustee on behalf of itself or any holder of notes (A) may seek or request adequate protection

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in the form a Lien on such additional or replacement collateral and/or a superpriority administrative claim (as applicable), which Lien or superpriority claim is junior and subordinated to the First Priority Liens and claims with respect thereto and such DIP Financing (and all Obligations relating thereto) on the same basis as the other Liens securing the notes are so junior and subordinated to the First Priority Liens and claims with respect thereto under the Senior Lien Intercreditor Agreement and, except as otherwise provided in this paragraph, (B) agrees that it will not seek or request, without the consent of the RBL Agent adequate protection in any other form, and (ii) in the event the Collateral Agent or Trustee on behalf of itself or any holder of notes receives adequate protection in the form of a Lien on additional or replacement collateral and/or a superpriority administrative claim, then the RBL Agent shall also be granted a senior Lien on such additional or replacement collateral as security for the applicable First-Priority Lien Obligations and any such DIP Financing and/or a superpriority administrative claim (as applicable), and any Lien on such additional or replacement collateral securing the notes and/or superpriority claim granted thereto as adequate protection shall be junior and subordinated to the Liens on such collateral securing the First-Priority Lien Obligations and claims with respect thereto and any such DIP Financing (and all Obligations relating thereto) and any other Liens granted to the holders of First-Priority Lien Obligations as adequate protection, on the same basis as the other Liens securing the notes and claims with respect thereto are so junior and subordinated to the First Priority Liens and claims with respect thereto under the Senior Lien Intercreditor Agreement. See “Risk Factors—Risks Related to the Collateral—If we become the subject of a bankruptcy proceeding, bankruptcy laws may limit your ability to realize value from the collateral.” Without limiting the generality of the foregoing, to the extent that the holders of the First-Priority Lien Obligations are granted adequate protection in the form of payments in the amount of current post-petition fees and expenses, and/or other cash payments, then the Collateral Agent and the holders of the notes shall not be prohibited from seeking and accepting adequate protection in the form of payments in the amount of current post-petition incurred fees and expenses, and/or other cash payments (as applicable), subject to the right of the holders of the First-Priority Lien Obligations to object to the reasonableness of the amounts of fees and expenses or other cash payments so sought by the holders of the notes.

None of the Collateral Agent or any holder of the notes shall oppose or seek to challenge any claim by the RBL Agent or any holder of First-Priority Lien Obligations for allowance in any Insolvency Proceeding of First-Priority Lien Obligations consisting of post-petition interest, fees, or expenses, under Section 506(b) of the Bankruptcy Code or otherwise. Neither the RBL Agent or any holder of the First-Priority Lien Obligations shall oppose or seek to challenge any claim by the Collateral Agent or any holder of the notes for allowance in any Insolvency Proceeding of Notes Obligations consisting of post-petition interest, fees or expenses, under Section 506(b) of the Bankruptcy Code or otherwise, to the extent of the value of the Liens securing the notes on the Collateral, after taking into account the First-Priority Lien Obligations.

No holder of Second-Priority Lien Obligations may support or vote in favor of any plan of reorganization (and each shall be deemed to have voted to reject any plan of reorganization) unless such plan (a) pays off, in cash in full, all First-Priority Lien Obligations, (b) is accepted by the class of holders of First-Priority Lien Obligations voting thereon in accordance with Section 1126 of the Bankruptcy Code, or (c) otherwise provides the holders of First-Priority Lien Obligations with the value of the Collateral in cash or otherwise, prior to any payment or distribution on account of the Second-Priority Lien Obligations.

The Collateral Agent, for itself and on behalf of each holder of the notes and any Other Second Lien Obligations, acknowledges and agrees that (a) the grants of the First Priority Liens pursuant to the Security Documents pursuant to the Credit Agreement and the Collateral Documents and the Collateral Documents constitute two separate and distinct grants of Liens and (b) because of, among other things, their differing rights in the Collateral, the Notes Obligations and any Other Second Lien Obligations are fundamentally different from the First-Priority Lien Obligations and must be separately classified in any plan of reorganization or similar dispositive restructuring plan proposed or confirmed in an Insolvency Proceeding. In addition, the Collateral Agent, for itself and on behalf of each holder of Notes Obligations, agrees that regardless of whether any Post-Petition Claim is allowed or allowable, and without limiting the generality of the Senior Lien Intercreditor Agreement, the Senior Lien Intercreditor Agreement is expressly intended to include, and will include, the “rule

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of explicitness” in that the Senior Lien Intercreditor Agreement will expressly entitle the RBL Agent and such other holders of the First-Priority Lien Obligations, and is intended to provide the RBL Agent and such other holders of the First-Priority Lien Obligations, with the right to receive, in respect of their First-Priority Lien Obligations, payment from the Collateral of all Post-Petition Claims through distributions made therefrom pursuant to the provisions of the Senior Lien Intercreditor Agreement even though any such Post-Petition Claims are not allowed or allowable against the bankruptcy estate of an Issuer or any Subsidiary Guarantor under Section 502(b)(2) or Section 506(b) of the Bankruptcy Code or under any other provision of the Bankruptcy Code or any other Bankruptcy Law. To further effectuate the intent of the parties as provided in the immediately preceding sentences, if it is held that the claims of the holders of First-Priority Lien Obligations and the holders of the notes and any Other Second Lien Obligations in respect of the Collateral constitute only one secured claim (rather than separate classes of senior and junior secured claims), then the holders of First-Priority Lien Obligations shall be entitled to receive, in addition to amounts distributed to them from, or in respect of, the Collateral in respect of principal,pre-petition interest and other claims, all amounts owing in respect of post-petition interest, fees or expenses, irrespective of whether such claim for such amount is allowed or allowable in such Insolvency Proceeding, before any distribution from, or in respect of, any Collateral is made in respect of the Notes Obligations and any Other Second Lien Obligations, and the Collateral Agent, for itself and on behalf of each holder of the notes and any Other Second Lien Obligations will acknowledge and agree to turn over to the RBL Agent amounts otherwise received or receivable by them from the Collateral to the extent necessary to effectuate the intent of this sentence, even if such turnover has the effect of reducing the claim or recovery of the holders of the notes and any Other Second Lien Obligations.

Subject to the terms of the Security Documents, the Issuers and the Subsidiary Guarantors will have the right to remain in possession and retain exclusive control of the Collateral securing the notes and the Guarantees, to freely operate the Collateral and to collect, invest and dispose of any income therefrom. See “Risk Factors—Risks Related to the Collateral—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 New Notes and the guarantees.”

Release of Collateral

The Issuers and the Subsidiary Guarantors are entitled to the releases of property and other assets included in the Collateral from the Liens securing the notes under any one or more of the following circumstances:

(1) to enable us to consummate the disposition of such property or assets to a Person that is not an Issuer or a Subsidiary Guarantor to the extent permitted under the covenant described under “—Certain Covenants—Asset Sales” or not otherwise constituting an Asset Sale;

(2) in respect of the property and assets of a Subsidiary Guarantor, (i) upon the designation of such Subsidiary Guarantor to be an Unrestricted Subsidiary in accordance with the covenant described under “—Certain Covenants—Limitation on Restricted Payments” and the definition of “Unrestricted Subsidiary,” and such Subsidiary Guarantor shall be automatically released from its obligations under the indenture and under the Security Documents or (ii) upon the release or discharge of the Subsidiary Guarantee of such Subsidiary Guarantor in accordance with the last paragraph under “—Subsidiary Guarantees” below;

(3) in respect of the property and assets of the Issuers, upon the release or discharge of the Issuers’ Notes Obligations in accordance with the indenture;

(4) as provided in the Senior Lien Intercreditor Agreement with respect to enforcement actions by the holders of First-Priority Lien Obligations;

(5) as described under “—Amendments and Waivers” below; and

(6) if the notes have been discharged or defeased pursuant to a legal defeasance or covenant defeasance under the indenture as described below under “—Defeasance.”

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The second priority security interests in all Collateral securing the Notes Obligations also will be released upon (i) payment in full of the principal of, together with accrued and unpaid interest on, the notes and all other Obligations under the indenture and the Security Documents (other than contingent or unliquidated obligations or liabilities not then due) that are due and payable at or prior to the time such principal, together with accrued and unpaid interest, are paid (including pursuant to a satisfaction and discharge of the indenture as described below under “—Satisfaction and discharge”) or (ii) a legal defeasance or covenant defeasance under the indenture as described below under “—Defeasance.”

Subsidiary Guarantees

Each of Holdings’ direct and indirect Wholly Owned Restricted Subsidiaries (other than Talos Production Finance Inc.) that are Domestic Subsidiaries and that are borrowers or guarantors under the Credit Agreement will jointly and severally irrevocably and unconditionally guarantee on a senior basis the performance and punctual payment when due, whether at Stated Maturity, by acceleration or otherwise, of all obligations of the Issuers under the indenture and the notes, whether for payment of principal of, premium, if any, or interest and all other monetary obligations of the Issuers under the indenture and the notes (or Additional Interest, if any) on the notes, expenses, indemnification or otherwise (all such obligations guaranteed by such Subsidiary Guarantors being herein called the “Guaranteed Obligations”). The Guaranteed Obligations of all Subsidiary Guarantors shall be secured by security interests (subject to Permitted Liens and Liens permitted under “—Certain Covenants—Liens”) in the Collateral owned by such Subsidiary Guarantor pursuant to the terms of the Security Documents (but subject to the terms and conditions of the Security Documents and the Senior Lien Intercreditor Agreement). Such Subsidiary Guarantors will agree to pay, in addition to the amount stated above, any and all expenses (including reasonable counsel fees and expenses) incurred by the Trustee, the Collateral Agent or the holders in enforcing any rights under the Subsidiary Guarantees.

Each Subsidiary Guarantee is limited to an amount not to exceed the maximum amount that can be guaranteed by the applicable Subsidiary Guarantor without rendering the Subsidiary Guarantee, as it relates to such Subsidiary Guarantor, voidable under applicable law relating to fraudulent conveyance or fraudulent transfer or similar laws affecting the rights of creditors generally or capital maintenance or corporate benefit rules applicable to guarantees for obligations of affiliates. See “Risk Factors—Risks Related to Our Indebtedness and the Notes—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.” After the Issue Date, Holdings will cause each Wholly Owned Restricted Subsidiary (other than an Excluded Subsidiary) and any other Subsidiary that guarantees Indebtedness of Holdings or any of the Subsidiary Guarantors to execute and deliver to the Trustee a supplemental indenture pursuant to which such Subsidiary will guarantee payment of the notes on the same senior basis. See “—Certain Covenants—Future Guarantors.”

Each Subsidiary Guarantee will be a continuing guarantee and shall:

(1) remain in full force and effect until payment in full of all the Guaranteed Obligations;

(2) subject to the next two succeeding paragraphs, be binding upon each such Subsidiary Guarantor and its successors; and

(3) inure to the benefit of and be enforceable by the Trustee, the holders and their successors, transferees and assigns.

Each Subsidiary’s Subsidiary Guarantee will be automatically released upon any of the following:

(1) the sale, disposition, exchange or other transfer (including through merger, consolidation, amalgamation or otherwise) of the Capital Stock (including any sale, disposition or other transfer following which the applicable Subsidiary Guarantor is no longer a Restricted Subsidiary), of the applicable Subsidiary Guarantor if such sale, disposition, exchange or other transfer is made to a person

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that is not an Issuer or a Restricted Subsidiary of Holdings in a transaction that is permitted by the indenture;

(2) the designation of such Subsidiary Guarantor as an Unrestricted Subsidiary in accordance with the covenant described under “—Certain Covenants—Limitation on Restricted Payments” and the definition of “Unrestricted Subsidiary”;

(3) [reserved];

(4) the Issuers’ exercise of their legal defeasance option or covenant defeasance option as described under “—Defeasance” or if the Issuers’ obligations under the indenture are discharged in accordance with the terms of the indenture;

(5) such Subsidiary ceasing to be a Subsidiary as a result of any foreclosure of any pledge or security interest in favor of First-Priority Lien Obligations or other exercise of remedies in respect thereof, subject to, in each case, the application of the proceeds of such foreclosure or exercise of remedies in the manner described in the Senior Lien Intercreditor Agreement; and

(6) as provided under “—Amendments and Waivers.”

Change of Control

Upon the occurrence of a Change of Control, each holder will have the right to require the Issuers to repurchase all or any part of such holder’s notes at a purchase price in cash equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but excluding, the date of repurchase (subject to the right of the holders of record on the relevant record date to receive interest due on the relevant interest payment date), except to the extent the Issuers have previously or concurrently elected to redeem notes as described under “—Optional Redemption.”

In the event that at the time of such Change of Control, the terms of the Bank Indebtedness restrict or prohibit the repurchase of notes pursuant to this covenant, then prior to the delivery of the notice to holdersprovided for in the immediately following paragraph but in any event within 30 days following any Change of Control, the Issuers shall:

(1) repay in full all Bank Indebtedness or, if doing so will allow the purchase of notes, offer to repay in full all Bank Indebtedness and repay the Bank Indebtedness of each lender and/or noteholder who has accepted such offer; or

(2) obtain the requisite consent under the agreements governing the Bank Indebtedness to permit the repurchase of the notes asprovided for in the immediately following paragraph.

See “Risk Factors—Risks Related to Our Indebtedness and the Notes—We may not be able to repurchase the notes upon a change of control.”

Within 30 days following any Change of Control, except to the extent that the Issuers have exercised their right to redeem the notes by delivery of a notice of redemption as described under “—Optional Redemption,” the Issuers shall mail (or otherwise deliver in accordance with the applicable procedures of DTC) a notice (a “Change of Control Offer”) to each holder with a copy to the Trustee stating:

(1) that a Change of Control has occurred and that such holder has the right to require the Issuers to repurchase such holder’s notes at a repurchase price in cash equal to 101% of the principal amount thereof, plus accrued and unpaid interest and Additional Interest, if any, to the date of repurchase (subject to the right of holders of record on a record date to receive interest on the relevant interest payment date);

(2) the circumstances and relevant facts and financial information regarding such Change of Control;

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(3) the repurchase date (which shall be no earlier than 30 days nor later than 60 days from the date such notice is sent);

(4) that unless the Issuers default in making the payment, all notes accepted for repurchase pursuant to the Change of Control Offer will cease to accrue interest on the Change of Control Offer Payment Date;

(5) that holders of notes electing to have any notes repurchased pursuant to a Change of Control Offer will be required to notify the Trustee prior to the close of business on the third Business Day preceding the Change of Control Offer Payment Date; and

(6) the other instructions determined by the Issuers or as reasonably requested by the Trustee, consistent with this covenant, that a holder must follow in order to have its notes purchased.

A Change of Control Offer may be made in advance of a Change of Control, and conditioned upon such Change of Control, if a definitive agreement is in place for the Change of Control at the time of making of the Change of Control Offer.

Notwithstanding the foregoing provisions of this covenant, the Issuers will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by the Issuers and purchases all notes validly tendered and not withdrawn under such Change of Control Offer.

If holders of not less than 90% in aggregate principal amount of the outstanding notes validly tender and do not withdraw such notes in a Change of Control Offer and the Issuers, or any third party making a Change of Control Offer in lieu of the Issuers as described above, purchase all of the notes validly tendered and not withdrawn by such holders, the Issuers or such third party will have the right, upon not less than 30 nor more than 60 days’ prior written notice, given not more than 30 days following such purchase pursuant to the Change of Control Offer described above, to redeem all notes that remain outstanding following such purchase at a price in cash equal to 101% of the principal amount thereof plus accrued and unpaid interest to, but excluding, the date of redemption.

Notes repurchased by the Issuers pursuant to a Change of Control Offer will have the status of notes issued but not outstanding or will be retired and canceled at the option of the Issuers. Notes purchased by a third party pursuant to the preceding paragraphs will have the status of notes issued and outstanding.

The Issuers will comply, to the extent applicable, with the requirements of Section 14(e) of the Exchange Act and any other securities laws or regulations in connection with the repurchase of notes pursuant to this covenant. To the extent that the provisions of any securities laws or regulations conflict with provisions of this covenant, the Issuers will comply with the applicable securities laws and regulations and will not be deemed to have breached their obligations under this covenant by virtue thereof.

The Issuers have no present intention to engage in a transaction involving a Change of Control, although it is possible that the Issuers could decide to do so in the future. Subject to the limitations discussed below, the Issuers could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalizations, that would not constitute a Change of Control under the indenture, but that could increase the amount of indebtedness outstanding at such time or otherwise affect the Issuers’ capital structure or credit rating.

The occurrence of events which would constitute a Change of Control would constitute a default under the Credit Agreement. Future Bank Indebtedness of the Issuers may contain prohibitions on certain events which would constitute a Change of Control or require such Bank Indebtedness to be repurchased upon a Change of Control. Moreover, the exercise by the holders of their right to require the Issuers to repurchase the notes could cause a default under such Bank Indebtedness, even if the Change of Control itself does not, due to the financial

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effect of such repurchase on the Issuers. Finally, the Issuers’ ability to pay cash to the holders upon a repurchase may be limited by the Issuers’ then existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases. See “Risk Factors—Risks Related to Our Indebtedness and the Notes—We may not be able to repurchase the notes upon a change of control.”

The definition of Change of Control includes a phrase relating to the sale, lease or transfer of “all or substantially all” the assets of Holdings and its Subsidiaries taken as a whole. Although there is a developing body of case law interpreting the phrase “substantially all,” under New York law, which governs the indenture, there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require the Issuers to repurchase such notes as a result of a sale, lease or transfer of less than all of the assets of Holdings and its Subsidiaries taken as a whole to another Person or group may be uncertain.

The provisions under the indenture relating to the Issuers’ obligation to make an offer to repurchase the notes as a result of a Change of Control may be waived or modified with the written consent of the holders of a majority in principal amount of the notes.

Certain Covenants

Set forth below are summaries of certain covenants that are contained in the indenture. If on any date following the Issue Date, (i) the notes have Investment Grade Ratings from both Rating Agencies, and (ii) no Default has occurred and is continuing, then, beginning on that day (the occurrence of the events described in the foregoing clauses (i) and (ii) being collectively referred to as a “Covenant Suspension Event”), the covenants specifically listed under the following captions in this “Description of the Notes” section of this prospectus will not be applicable to the notes (collectively, the “Suspended Covenants”):

(1) “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

(2) “—Certain Covenants—Limitation on Restricted Payments”;

(3) “—Certain Covenants—Dividend and Other Payment Restrictions Affecting Subsidiaries”;

(4) “—Certain Covenants—Asset Sales”;

(5) “—Certain Covenants—Transactions with Affiliates”;

(6) clause (4) of the first paragraph of “—Certain Covenants—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets”;

(7) “—Certain Covenants—Future Guarantors;” and

(8) “—Security—After-Acquired Property”

If and while Holdings and its Restricted Subsidiaries are not subject to the Suspended Covenants, the notes will be entitled to substantially less covenant protection. In the event that Holdings and its Restricted Subsidiaries are not subject to the Suspended Covenants under the indenture for any period of time as a result of the foregoing, and on any subsequent date (the “Reversion Date”) one or both of the Rating Agencies withdraw their Investment Grade Rating or downgrade the rating assigned to the notes below an Investment Grade Rating, then Holdings and its Restricted Subsidiaries will thereafter again be subject to the Suspended Covenants under the indenture with respect to future events. The period of time between the Covenant Suspension Event and the Reversion Date is referred to in this description as the “Suspension Period.” The Issuers shall provide the Trustee with written notice of each Covenant Suspension Event or Reversion Date within five Business Days of the occurrence thereof. The Trustee will have no duty to monitor or provide notice to the holders of notes of any Covenant Suspension Event or Reversion Date.

On each Reversion Date, all Indebtedness Incurred, or Disqualified Stock or Preferred Stock issued, during the Suspension Period will be classified as having been Incurred or issued pursuant to the first paragraph of

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“—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” below or one of the clauses set forth in the second paragraph of “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” below (to the extent such Indebtedness or Disqualified Stock or Preferred Stock would be permitted to be Incurred or issued thereunder as of the Reversion Date and after giving effect to Indebtedness Incurred or issued prior to the Suspension Period and outstanding on the Reversion Date). To the extent such Indebtedness or Disqualified Stock or Preferred Stock would not be so permitted to be Incurred or issued pursuant to the first or second paragraph of “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock,” such Indebtedness or Disqualified Stock or Preferred Stock will be deemed to have been outstanding on the Issue Date, so that it is classified as permitted under clause (c) of the second paragraph under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock.” Calculations made after the Reversion Date of the amount available to be made as Restricted Payments under “—Certain Covenants—Limitation on Restricted Payments” will be made as though the covenant described under “—Certain Covenants—Limitation on Restricted Payments” had been in effect since the Issue Date and prior to, but not during, the Suspension Period. Accordingly, Restricted Payments made during the Suspension Period will not reduce the amount available to be made as Restricted Payments under the first paragraph of “—Certain Covenants—Limitation on Restricted Payments.” No Default or Event of Default will be deemed to have occurred on the Reversion Date as a result of any actions taken by Holdings or its Restricted Subsidiaries during the Suspension Period. Within 30 days of such Reversion Date, Holdings must comply with the terms of the covenant described under “—Certain Covenants—Future Guarantors.”

For purposes of the “—Asset Sales” covenant, on the Reversion Date, the unutilized Excess Proceeds amount will be reset to zero.

There can be no assurance that the notes will ever achieve or maintain Investment Grade Ratings.

Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock

The indenture provides that:

(1) Holdings shall not, and shall not permit any of its Restricted Subsidiaries to, directly or indirectly, Incur any Indebtedness (including Acquired Indebtedness) or issue any shares of Disqualified Stock; and

(2) Holdings shall not permit any of its Restricted Subsidiaries (other than a Subsidiary Guarantor) to issue any shares of Preferred Stock;

provided,however, that Holdings and any Subsidiary Guarantor may Incur Indebtedness (including Acquired Indebtedness) or issue shares of Disqualified Stock, and any Restricted Subsidiary of Holdings that is not a Subsidiary Guarantor may Incur Indebtedness (including Acquired Indebtedness), issue shares of Disqualified Stock or issue shares of Preferred Stock, in each case if the Fixed Charge Coverage Ratio of Holdings for the most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is Incurred or such Disqualified Stock or Preferred Stock is issued would have been at least 2.25 to 1.00 determined on apro forma basis (including apro forma application of the net proceeds therefrom), as if the additional Indebtedness had been Incurred (together with any other Indebtedness incurred pursuant to the following paragraph), or the Disqualified Stock or Preferred Stock had been issued (together with any other Disqualified Stock or Preferred Stock issued pursuant to the following paragraph), as the case may be, and the application of proceeds therefrom had occurred at the beginning of such four-quarter period;provided,further, that any Restricted Subsidiary that is not a Subsidiary Guarantor may not Incur Indebtedness or issue shares of Disqualified Stock or Preferred Stock in excess of an amount together with any Refinancing Indebtedness thereof pursuant to clause (o) below, equal to, after givingpro forma effect to such incurrence or issuance (includingpro forma effect to the application of the net proceeds therefrom), $25.0 million (plus, in the case of any Refinancing Indebtedness, the Additional Refinancing Amount).

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The foregoing limitations shall not apply to:

(a) the Incurrence by Holdings or any Restricted Subsidiary of Indebtedness under the Credit Agreement (or any permitted refinancing) not to exceed the greater of (x) $600.0 million and (y) the borrowing base (as defined in and determined from time to time pursuant to the Credit Agreement (or any permitted refinancing thereof));provided, however, that the maximum principal amount of the borrowing base under the Credit Agreement (or any permitted refinancing thereof) shall not exceed either (1) the maximum amount of the borrowing base under the Credit Agreement (or any permitted refinancing thereof) at the time of Incurrence equal to the aggregate lending value to be ascribed to Oil and Gas Properties of the Issuers and the Subsidiary Guarantors against which the lenders thereunder are prepared to provide loans and letters of credit based on customary practices and standards at the time for reserve based loans and which are generally applied at the time by commercial lenders to borrowers in the Oil and Gas Business or (2) the Borrowing Base at the time of Incurrence;provided,further, that the Credit Agreement (or any permitted refinancing thereof) has a lender group that includes one or more commercial financial institutions which engage in oil and gas reserved based lending in the ordinary course of their respective businesses (an “RBL Lending Financial Institution”);provided,further, that theAll-In Yield of such Credit Agreement (or any permitted refinancing thereof) shall not exceed Adjusted LIBOR (as calculated under the Credit Agreement as of the Issue Date)plus 6.00%; provided,further that if the lender group does not include at least one RBL Lending Financial Institution, then the maximum principal amount available under this clause (a) shall not exceed $600.0 million;

(b) the Incurrence by the Issuers and the Subsidiary Guarantors of Indebtedness represented by the notes (including any guarantee thereof (including the Subsidiary Guarantees)) (including Exchange Notes and related guarantees thereof) (not including any additional notes);

(c) Indebtedness existing on the Issue Date (other than Indebtedness described in clauses (a), (b) and (d));

(d) Indebtedness in respect of the Stone Notes, together with any Indebtedness, Disqualified Stock or Preferred Stock Incurred to refund, refinance or defease the Stone Notes, in an aggregate principal amount not exceed the amount of Stone Notes outstanding following the completion of this Exchange Offer (plus, in the case of any Indebtedness, Disqualified Stock or Preferred Stock Incurred to so refund, refinance or defease the Stone Notes, the Additional Refinancing Amount);provided, that any such Indebtedness, Disqualified Stock or Preferred Stock refunding, refinancing or defeasing the Stone Notes constitutes unsecured Indebtedness, Junior Lien Obligations or Other Second-Lien Obligations;provided, further,that to the extent any Indebtedness, Disqualified Stock or Preferred Stock refunding or refinancing the Stone Notes pursuant to this clause (d) is secured, such Indebtedness, Disqualified Stock or Preferred Stock constituting Other Second-Lien Obligations shall be subject to the Senior Lien Intercreditor Agreement and a Customary Intercreditor Agreement and any such Indebtedness, Disqualified Stock or Preferred Stock constituting Junior Lien Obligations shall be subject to a Customary Intercreditor Agreement;provided, further, that any such Indebtedness, Disqualified Stock or Preferred Stock refunding, refinancing or defeasing the Stone Notes shall (1) have a maturity date no earlier than the scheduled maturity of the notes, (2) not have any scheduled amortization of principal prior to the scheduled maturity of the notes (other than scheduled amortization of principal in an amount not to exceed 1.0% per annum), (3) not include covenants and events of default that are materially more restrictive than those contained in the notes and (4) have anAll-in-Yield no greater than theAll-in-Yield of the notes;

(e) Indebtedness Incurred by Holdings or any of its Restricted Subsidiaries constituting reimbursement obligations with respect to letters of credit and bank guarantees issued in the ordinary course of business, including without limitation letters of credit in respect of workers’ compensation claims, health, disability or other benefits to employees or former employees or their families or property, casualty or liability insurance or self-insurance, and letters of credit in connection with the maintenance of, or pursuant to the requirements of, environmental or other permits or licenses from governmental

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authorities, or other Indebtedness with respect to reimbursement type obligations regarding workers’ compensation claims;

(f) Indebtedness arising from agreements of Holdings or any of its Restricted Subsidiaries providing for indemnification, adjustment of purchase price or similar obligations, in each case, Incurred in connection with any acquisition or disposition of any business, assets or a Subsidiary in accordance with the terms of the indenture, other than guarantees of Indebtedness Incurred by any Person acquiring all or any portion of such business, assets or Subsidiary for the purpose of financing such acquisition;

(g) Indebtedness of Holdings to a Restricted Subsidiary;provided that (except in respect of intercompany current liabilities Incurred in the ordinary course of business in connection with the cash management, tax and accounting operations of Holdings and its Subsidiaries) any such Indebtedness owed to a Restricted Subsidiary that is not a Subsidiary Guarantor is subordinated in right of payment to the obligations of the Issuers under the notes;provided,further, that any subsequent issuance or transfer of any Capital Stock or any other event which results in any such Restricted Subsidiary ceasing to be a Restricted Subsidiary or any other subsequent transfer of any such Indebtedness (except to Holdings or another Restricted Subsidiary or any pledge of such Indebtedness constituting a Permitted Lien but not the transfer thereof upon foreclosure) shall be deemed, in each case, to be an Incurrence of such Indebtedness not permitted by this clause (g);

(h) shares of Preferred Stock of a Restricted Subsidiary issued to Holdings or another Restricted Subsidiary;provided that any subsequent issuance or transfer of any Capital Stock or any other event which results in any Restricted Subsidiary that holds such shares of Preferred Stock of another Restricted Subsidiary ceasing to be a Restricted Subsidiary or any other subsequent transfer of any such shares of Preferred Stock (except to Holdings or another Restricted Subsidiary) shall be deemed, in each case, to be an issuance of shares of Preferred Stock not permitted by this clause (h);

(i) Indebtedness of a Restricted Subsidiary to Holdings or another Restricted Subsidiary;provided that if a Subsidiary Guarantor incurs such Indebtedness to a Restricted Subsidiary that is not an Issuer or a Subsidiary Guarantor (except in respect of intercompany current liabilities incurred in the ordinary course of business in connection with the cash management, tax and accounting operations of Holdings and its Subsidiaries), such Indebtedness is subordinated in right of payment to the Subsidiary Guarantee of such Subsidiary Guarantor;provided,further, that any subsequent issuance or transfer of any Capital Stock or any other event which results in any Restricted Subsidiary holding such Indebtedness ceasing to be a Restricted Subsidiary or any other subsequent transfer of any such Indebtedness (except to Holdings or another Restricted Subsidiary or any pledge of such Indebtedness constituting a Permitted Lien but not the transfer thereof upon foreclosure) shall be deemed, in each case, to be an Incurrence of such Indebtedness not permitted by this clause (i);

(j) Hedging Obligations that are not Incurred for speculative purposes but (1) for the purpose of fixing or hedging interest rate risk with respect to any Indebtedness that is permitted by the terms of the indenture to be outstanding; (2) for the purpose of fixing or hedging currency exchange rate risk with respect to any currency exchanges; or (3) for the purpose of fixing or hedging commodity price risk with respect to any commodity purchases or sales (including, without limitation, any commodity Hedging Obligation that is intended in good faith, at inception of execution, to hedge or manage any of the risks related to existing and/or forecasted Hydrocarbon production (whether or not contracted)) and, in each case, extensions or replacements thereof;

(k) obligations (including reimbursement obligations with respect to letters of credit and bank guarantees) in respect of performance, bid, appeal and surety bonds and completion guarantees provided by Holdings or any Restricted Subsidiary in the ordinary course of business or consistent with past practice or industry practice;

(l) Indebtedness or Disqualified Stock of Holdings or Indebtedness, Disqualified Stock or Preferred Stock of any Restricted Subsidiary not otherwise permitted hereunder in an aggregate principal amount or

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liquidation preference, which when aggregated with the principal amount or liquidation preference of all other Indebtedness, Disqualified Stock and Preferred Stock then outstanding and Incurred pursuant to this clause (l), together with any Indebtedness, Disqualified Stock or Preferred Stock Incurred to refund, refinance or defease such Indebtedness, Disqualified Stock or Preferred Stock, does not exceed $50.0 million (plus, in the case of any Indebtedness, Disqualified Stock or Preferred Stock Incurred to so refund, refinance or defease such Indebtedness, Disqualified Stock or Preferred Stock, the Additional Refinancing Amount) (it being understood that any Indebtedness Incurred pursuant to this clause (l) shall cease to be deemed Incurred or outstanding for purposes of this clause (l) but will be deemed Incurred for purposes of the first paragraph under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” from and after the first date on which Holdings, or the Restricted Subsidiary, as the case may be, could have Incurred such Indebtedness under the first paragraph under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” without reliance upon this clause (l));providedthat to the extent Indebtedness Incurred pursuant to this clause (l) is secured, such Indebtedness constituting First-Priority Lien Obligations and Other Second-Lien Obligations will be subject to the Senior Lien Intercreditor Agreement and any Junior Lien Obligations and Other Second-Lien Obligations shall be subject to a Customary Intercreditor Agreement;provided,further, that unsecured Indebtedness and Junior Lien Obligations shall not be exchanged for Other Second-Lien Obligations or Indebtedness that is secured on a senior basis to the notes pursuant to this clause (l);

(m) Indebtedness or Disqualified Stock of Holdings or any Restricted Subsidiary and Preferred Stock of any Restricted Subsidiary not otherwise permitted hereunder in an aggregate principal amount or liquidation preference at any time outstanding not greater than 100.0% of the net cash proceeds received by Holdings and its Restricted Subsidiaries since immediately after the Issue Date from the issue or sale of Equity Interests of Holdings or any direct or indirect parent entity of Holdings (which proceeds are contributed to Holdings or its Restricted Subsidiary) or cash contributed to the capital of Holdings (in each case other than proceeds of Disqualified Stock or sales of Equity Interests to, or contributions received from, Holdings or any of its Subsidiaries) to the extent such net cash proceeds or cash have not been applied pursuant to such clauses to make Restricted Payments or to make other Investments, payments or exchanges pursuant to the second paragraph of “—Certain Covenants—Limitation on Restricted Payments” or to make Permitted Investments (other than Permitted Investments specified in clauses (1) and (3) of the definition thereof);

(n) any guarantee by Holdings or any Restricted Subsidiary of Indebtedness or other obligations of Holdings or any Restricted Subsidiary so long as the Incurrence of such Indebtedness Incurred by Holdings or such Restricted Subsidiary is permitted under the terms of the indenture;provided that (i) if such Indebtedness is by its express terms subordinated in right of payment to the notes or the Subsidiary Guarantee of such Restricted Subsidiary, as applicable, any such guarantee with respect to such Indebtedness shall be subordinated in right of payment to the notes or such Subsidiary Guarantee, as applicable, substantially to the same extent as such Indebtedness is subordinated to the notes or the Subsidiary Guarantee, as applicable and (ii) if such guarantee is of Indebtedness of Holdings, such guarantee is Incurred in accordance with, or not in contravention of, the covenant described under “—Future Guarantors” solely to the extent such covenant is applicable;

(o) the Incurrence by Holdings or any of the Restricted Subsidiaries of Indebtedness or Disqualified Stock or Preferred Stock of a Restricted Subsidiary that serves to refund, refinance or defease any Indebtedness Incurred or Disqualified Stock or Preferred Stock issued as permitted under the first paragraph of this covenant and clauses (b), (c), (d), (m), (o) and (p) of this paragraph up to the outstanding principal amount (or, if applicable, the liquidation preference face amount, or the like) or, if greater, committed amount (only to the extent the committed amount could have been Incurred on the date of initial Incurrence) of such Indebtedness or Disqualified Stock or Preferred Stock, in each case at the time such Indebtedness was Incurred or Disqualified Stock or Preferred Stock was issued pursuant to the first paragraph of this covenant or clauses (b), (c), (d), (m), (o) and (p) of this

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paragraph, or any Indebtedness, Disqualified Stock or Preferred Stock Incurred to so refund, refinance or defease such Indebtedness, Disqualified Stock or Preferred Stock, in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding of the Indebtedness being refinanced (plus, without duplication, any additional Indebtedness Incurred to pay interest, premiums or defeasance costs required by the instruments governing such existing Indebtedness (whether such existing Indebtedness is redeemed pursuant to a tender offer, optional redemption or otherwise) and fees and expenses Incurred in connection therewith) (subject to the following proviso, “Refinancing Indebtedness”) prior to its respective maturity;provided,however, that such Refinancing Indebtedness:

(1) has a Weighted Average Life to Maturity at the time such Refinancing Indebtedness is Incurred which is not less than the shorter of (x) the remaining Weighted Average Life to Maturity of the Indebtedness, Disqualified Stock or Preferred Stock being refunded, refinanced or defeased and (y) the Weighted Average Life to Maturity that would result if all payments of principal on the Indebtedness, Disqualified Stock and Preferred Stock being refunded or refinanced that were due on or after the date that is one year following the last maturity date of any notes then outstanding were instead due on such date (provided that this clause (1) will not apply to any refunding or refinancing of any First-Priority Lien Obligations);

(2) to the extent such Refinancing Indebtedness refinances (a) Indebtedness junior to the notes or a Subsidiary Guarantee, as applicable, such Refinancing Indebtedness is junior to the notes or the Subsidiary Guarantee, as applicable, (b) Disqualified Stock or Preferred Stock, such Refinancing Indebtedness is Disqualified Stock or Preferred Stock or (c) unsecured Indebtedness, such Refinancing Indebtedness is unsecured Indebtedness; and

(3) shall not include (x) Indebtedness of a Restricted Subsidiary that is not a Subsidiary Guarantor that refinances Indebtedness of an Issuer or a Subsidiary Guarantor, or (y) Indebtedness of Holdings or a Restricted Subsidiary that refinances Indebtedness of an Unrestricted Subsidiary;

provided, further,that to the extent Refinancing Indebtedness Incurred pursuant to this clause (o) is secured, such Indebtedness constituting First-Priority Lien Obligations and Other Second-Lien Obligations shall be subject to the Senior Lien Intercreditor Agreement and any such Indebtedness constituting Junior Lien Obligations and Other Second-Lien Obligations shall be subject to a Customary Intercreditor Agreement;

(p) Indebtedness, Disqualified Stock or Preferred Stock of (x) Holdings or any Restricted Subsidiary Incurred to finance an acquisition or (y) Persons that are acquired by Holdings or any Restricted Subsidiary or merged, consolidated or amalgamated with or into Holdings or any Restricted Subsidiary in accordance with the terms of the indenture;provided that after giving effect to such acquisition or merger, consolidation or amalgamation, either:

(1) Holdings would be permitted to Incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of this covenant; or

(2) the Fixed Charge Coverage Ratio of Holdings would be no less than immediately prior to such acquisition or merger, consolidation or amalgamation;

(q) [reserved];

(r) Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument drawn against insufficient funds in the ordinary course of business;provided, that such Indebtedness is extinguished within five Business Days of its Incurrence;

(s) Indebtedness of Holdings or any Restricted Subsidiary supported by a letter of credit or bank guarantee issued pursuant to Bank Indebtedness, in a principal amount not in excess of the stated amount of such letter of credit;

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(t) Indebtedness of Restricted Subsidiaries that are not Subsidiary Guarantors and Indebtedness Incurred on behalf of, or representing guarantees of Indebtedness of, joint ventures of Holdings and any Restricted Subsidiary;provided,however, that the aggregate principal amount of Indebtedness Incurred under this clause (t), when aggregated with the principal amount of all other Indebtedness then outstanding and Incurred pursuant to this clause (t), does not exceed $25.0 million (it being understood that any Indebtedness Incurred pursuant to this clause (t) shall cease to be deemed Incurred or outstanding for purposes of this clause (t) but shall be deemed Incurred for the purposes of the first paragraph of this covenant from and after the first date on which such Restricted Subsidiary could have Incurred such Indebtedness under the first paragraph of this covenant without reliance upon this clause (t));

(u) Indebtedness of Holdings or any Restricted Subsidiary consisting of (1) the financing of insurance premiums or(2) take-or-pay obligations contained in supply arrangements, in each case, in the ordinary course of business; and

(v) Indebtedness consisting of Indebtedness issued by Holdings or a Restricted Subsidiary to current or former officers, directors and employees thereof or any direct or indirect parent thereof, their respective estates, spouses or former spouses, in each case to finance the purchase or redemption of Equity Interests of Holdings or any direct or indirect parent of Holdings to the extent described in clause (4) of the second paragraph of the covenant described under ““—Certain Covenants—Limitation on Restricted Payments.”

For purposes of determining compliance with this covenant:

(1) in the event that an item of Indebtedness, Disqualified Stock or Preferred Stock (or any portion thereof) meets the criteria of more than one of the categories of permitted Indebtedness described in clauses (a) through (v) above or is entitled to be Incurred pursuant to the first paragraph of this covenant, then Holdings shall, in its sole discretion, classify or reclassify, or later divide, classify or reclassify, such item of Indebtedness, Disqualified Stock or Preferred Stock (or any portion thereof) in any manner that complies with this covenant;provided that Indebtedness under the Credit Agreement outstanding on the Issue Date shall be deemed Incurred under clause (a) above and may not be reclassified;

(2) [reserved];

(3) if any Indebtedness denominated in U.S. dollars is exchanged, converted or refinanced into Indebtedness denominated in a foreign currency, then (in connection with such exchange, conversion or refinancing, and thereafter), the U.S. dollar amount limitations set forth in any of clauses (a) through (v) above with respect to such exchange, conversion or refinancing shall be deemed to be the amount of such foreign currency, as applicable, into which such Indebtedness has been exchanged, converted or refinanced at the time of such exchange, conversion or refinancing; and

(4) if any Indebtedness denominated in a foreign currency is exchanged, converted or refinanced into Indebtedness denominated in U.S. dollars, then (in connection with such exchange, conversion or refinancing, and thereafter), the U.S. dollar amount limitations set forth in any of clauses (a) through (v) above with respect to such exchange, conversion or refinancing shall be deemed to be the amount of U.S. dollars into which such Indebtedness has been exchanged, converted or refinanced at the time of such exchange, conversion or refinancing.

Accrual of interest, the accretion of accreted value, the payment of interest or dividends in the form of additional Indebtedness, Disqualified Stock or Preferred Stock, as applicable, amortization of original issue discount, the accretion of liquidation preference and increases in the amount of Indebtedness outstanding solely as a result of fluctuations in the exchange rate of currencies will not be deemed to be an Incurrence of Indebtedness, Disqualified Stock or Preferred Stock for purposes of this covenant. Guarantees of, or obligations in respect of letters of credit relating to, Indebtedness which is otherwise included in the determination of a particular amount of Indebtedness shall not be included in the determination of such amount of Indebtedness;provided that the Incurrence of the Indebtedness represented by such guarantee or letter of credit, as the case may be, was in compliance with this covenant.

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For purposes of determining compliance with any U.S. dollar denominated restriction on the Incurrence of Indebtedness other than asprovided in clauses (3) and (4) above, the U.S. dollar equivalent principal amount of Indebtedness denominated in a foreign currency shall be calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was Incurred, in the case of term debt, or first committed or first Incurred (whichever yields the lower U.S. dollar equivalent), in the case of revolving credit debt.

Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that Subsidiaries that are not Subsidiary Guarantors may Incur pursuant to this covenant shall not exceed an aggregate principal amount or liquidation preference at any time outstanding of $50.0 million.

Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that Holdings and its Restricted Subsidiaries may Incur pursuant to this covenant shall not be deemed to be exceeded, with respect to any outstanding Indebtedness, solely as a result of fluctuations in the exchange rate of currencies.

Limitation on Restricted Payments

The indenture provides that Holdings shall not, and shall not permit any of its Restricted Subsidiaries to, directly or indirectly:

(1) declare or pay any dividend or make any distribution on account of any of Holdings’ or any of its Restricted Subsidiaries’ Equity Interests, including any payment made in connection with any merger, amalgamation or consolidation involving Holdings (other than (A) dividends or distributions payable solely in Equity Interests (other than Disqualified Stock) of Holdings; or (B) dividends or distributions by a Restricted Subsidiary so long as, in the case of any dividend or distribution payable on or in respect of any class or series of securities issued by a Restricted Subsidiary that is not a Wholly Owned Restricted Subsidiary, Holdings or a Restricted Subsidiary receives at least its pro rata share of such dividend or distribution in accordance with its Equity Interests in such class or series of securities);

(2) purchase or otherwise acquire or retire for value any Equity Interests of Holdings or any direct or indirect parent of Holdings held by Persons other than Holdings or a Restricted Subsidiary;

(3) make any principal payment on, or redeem, repurchase, defease or otherwise acquire or retire for value, in each case prior to any scheduled repayment or scheduled maturity, any Subordinated Indebtedness of Holdings or any Subsidiary Guarantor, any Other Second-Lien Obligations or notes owned by Holdings or any Restricted Subsidiary thereof or any of their respective Affiliates, any Junior Lien Obligations of Holdings or any Subsidiary Guarantor and any unsecured Indebtedness representing Indebtedness for borrowed money of Holdings or any Subsidiary Guarantor, (collectively, the “Restricted Indebtedness”) (other than the payment, redemption, repurchase, defeasance, acquisition or retirement of (A) (i) in the case of Indebtedness not owned by Holdings or any Restricted Subsidiary thereof or any of their respective Affiliates, Subordinated Indebtedness, any Junior Lien Obligations and unsecured Indebtedness in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of such payment, redemption, repurchase, defeasance, acquisition or retirement, (ii) in the case of Indebtedness owned by Holdings or any Restricted Subsidiary thereof or any of their respective Affiliates, Subordinated Indebtedness, any Junior Lien Obligations and unsecured Indebtedness in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within 90 days of the date of such payment, redemption, repurchase, defeasance, acquisition or retirement and (B) Indebtedness permitted under clauses (g) and (i) of the second paragraph of the covenant described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”); or

(4) make any Restricted Investment;

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(all such payments and other actions set forth in clauses (1) through (4) above being collectively referred to as “Restricted Payments”), unless, at the time of such Restricted Payment:

(a) no Default shall have occurred and be continuing or would occur as a consequence thereof;

(b) immediately after giving effect to such transaction on apro forma basis, Holdings could Incur $1.00 of additional Indebtedness under the provisions of the first paragraph of the covenant described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

(c) immediately after giving effect to such transaction on a pro forma basis, the Consolidated Leverage Ratio is not greater than 3.00 to 1.00; and

(d) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by Holdings and its Restricted Subsidiaries after the Issue Date (including Restricted Payments permitted by clauses (1), (2) (with respect to the payment of dividends on Refunding Capital Stock (as defined below) pursuant to clause (c) thereof), (6)(c), (8) and (13)(b) of the next succeeding paragraph, but excluding all other Restricted Payments permitted by the next succeeding paragraph), is less than the amount equal to the Cumulative Credit.

“Cumulative Credit” means the sum of (without duplication):

(1) 50% of the Consolidated Net Income of Holdings for the period from the Issue Date to the end of Holdings’ most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (taken as one accounting period, the “Reference Period”) (or in case such Consolidated Net Income for such period is a deficit, minus 100% of such deficit), plus

(2) 100% of the aggregate net proceeds, including cash and the Fair Market Value (as determined in good faith by Holdings) of property other than cash, received by Holdings after the Issue Date (other than net proceeds to the extent such net proceeds have been used to Incur Indebtedness, Disqualified Stock, or Preferred Stock pursuant to clause (m) of the second paragraph of the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”) from the issue or sale of Equity Interests of Holdings or any direct or indirect parent entity of Holdings (excluding Refunding Capital Stock (as defined below), Designated Preferred Stock and Disqualified Stock), including Equity Interests issued upon exercise of warrants or options (other than an issuance or sale to Holdings or a Restricted Subsidiary), plus

(3) 100% of the aggregate amount of contributions to the capital of Holdings received in cash and the Fair Market Value (as determined in good faith by Holdings) of property other than cash after the Issue Date (other than Refunding Capital Stock, Designated Preferred Stock, and Disqualified Stock and other than contributions to the extent such contributions have been used to incur Indebtedness, Disqualified Stock, or Preferred Stock pursuant to clause (m) of the second paragraph of the covenant described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”), plus

(4) 100% of the principal amount of any Indebtedness, or the liquidation preference or maximum fixed repurchase price, as the case may be, of any Disqualified Stock of Holdings or any Restricted Subsidiary issued after the Issue Date (other than Indebtedness or Disqualified Stock issued to a Restricted Subsidiary) which has been converted into or exchanged for Equity Interests in Holdings (other than Disqualified Stock) or any direct or indirect parent of Holdings (provided in the case of any such parent, such Indebtedness or Disqualified Stock is retired or extinguished),plus

(5) 100% of the aggregate amount received by Holdings or any Restricted Subsidiary in cash and the Fair Market Value (as determined in good faith by Holdings) of property other than cash received by Holdings or any Restricted Subsidiary from:

(A) the sale or other disposition (other than to Holdings or a Restricted Subsidiary) of Restricted Investments made by Holdings and its Restricted Subsidiaries and from repurchases and

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redemptions of such Restricted Investments from Holdings and its Restricted Subsidiaries by any Person (other than Holdings or any of its Restricted Subsidiaries) and from repayments of loans or advances, and releases of guarantees, which constituted Restricted Investments,

(B) the sale (other than to Holdings or a Restricted Subsidiary) of the Capital Stock of an Unrestricted Subsidiary, or

(C) a distribution or dividend from an Unrestricted Subsidiary, plus

(6) in the event any Unrestricted Subsidiary has been redesignated as a Restricted Subsidiary or has been merged, consolidated or amalgamated with or into, or transfers or conveys its assets to, or is liquidated into, Holdings or a Restricted Subsidiary, the Fair Market Value (as determined in good faith by Holdings) of the Investment of Holdings or its Restricted Subsidiaries in such Unrestricted Subsidiary (which, if the Fair Market Value of such investment shall exceed $25.0 million, shall be determined by the Board of Directors of Holdings) at the time of such redesignation, combination or transfer (or of the assets transferred or conveyed, as applicable) (other than in each case to the extent that the designation of such Subsidiary as an Unrestricted Subsidiary constituted a Permitted Investment).

The foregoing provisions shall not prohibit:

(1) the payment of any dividend or distribution or the consummation of any irrevocable redemption within 60 days after the date of declaration thereof, if at the date of declaration or the giving notice of such irrevocable redemption, as applicable, such payment would have complied with the provisions of the indenture;

(2) (A) the redemption, repurchase, retirement or other acquisition of any Equity Interests (“Retired Capital Stock”) or Restricted Indebtedness of Holdings, any direct or indirect parent of Holdings or any Subsidiary Guarantor in exchange for, or out of the proceeds of, the substantially concurrent sale of, Equity Interests of Holdings or any direct or indirect parent of Holdings or contributions to the equity capital of Holdings (other than any Disqualified Stock or any Equity Interests sold to a Subsidiary of Holdings) (collectively, including any such contributions, “Refunding Capital Stock”),

(B) the declaration and payment of dividends on the Retired Capital Stock out of the proceeds of the substantially concurrent sale (other than to a Subsidiary of Holdings) of Refunding Capital Stock, and

(C) if immediately prior to the retirement of Retired Capital Stock, the declaration and payment of dividends thereon was permitted under clause (6) of this paragraph and not made pursuant to clause (2)(b), the declaration and payment of dividends on the Refunding Capital Stock (other than Refunding Capital Stock the proceeds of which were used to redeem, repurchase, retire or otherwise acquire any Equity Interests of any direct or indirect parent of Holdings) in an aggregate amount per year no greater than the aggregate amount of dividends per annum that were declarable and payable on such Retired Capital Stock immediately prior to such retirement;

(3) (A) the redemption, repurchase, defeasance or other acquisition or retirement of Subordinated Indebtedness of Holdings or any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, new Indebtedness of Holdings or a Subsidiary Guarantor which is Incurred in accordance with the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” so long as

(w) such new Indebtedness is in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding of the Indebtedness being so redeemed, repurchased, defeased, acquired or retired for value (plus, without duplication, any additional Indebtedness Incurred to pay interest, premiums or defeasance costs, in each case in an amount equal to the amount required by the instruments governing such existing Indebtedness (whether such existing Indebtedness is redeemed pursuant to a tender offer, optional redemption or otherwise), and fees and expenses Incurred in connection therewith),

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(x) such Indebtedness is subordinated to the notes or the related Subsidiary Guarantee, as the case may be, at least to the same extent as such Subordinated Indebtedness so purchased, exchanged, redeemed, repurchased, defeased, acquired or retired for value,

(y) such Indebtedness has a final scheduled maturity date equal to or later than the earlier of (x) the final scheduled maturity date of the Subordinated Indebtedness being so redeemed, repurchased, acquired or retired and (y) 91 days following the last maturity date of any notes then outstanding, and

(z) such Indebtedness has a Weighted Average Life to Maturity at the time Incurred which is not less than the shorter of (x) the remaining Weighted Average Life to Maturity of the Subordinated Indebtedness being so redeemed, repurchased, defeased, acquired or retired and (y) the Weighted Average Life to Maturity that would result if all payments of principal on the Subordinated Indebtedness being redeemed, repurchased, defeased, acquired or retired that were due on or after the date that is one year following the last maturity date of any notes then outstanding were instead due on such date;

(B) the redemption, repurchase, defeasance or other acquisition or retirement of Other Second-Lien Obligations or notes of Holdings or any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, new Indebtedness of Holdings or a Subsidiary Guarantor which is Incurred in accordance with the covenant described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” so long as

(w) such new Indebtedness is in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding of the Indebtedness being so redeemed, repurchased, defeased, acquired or retired for value (plus, without duplication, any additional Indebtedness Incurred to pay interest, premiums or defeasance costs, in each case in an amount equal to the amount required by the instruments governing such existing Indebtedness (whether such existing Indebtedness is redeemed pursuant to a tender offer, optional redemption or otherwise), and fees and expenses Incurred in connection therewith),

(x) such Indebtedness constitutes Other Second-Lien Obligations, notes, Junior Lien Obligations, Subordinated Indebtedness or unsecured Indebtedness,

(y) such Indebtedness has a final scheduled maturity date equal to or later than the earlier of (i) the final scheduled maturity date of the Indebtedness being so redeemed, repurchased, acquired or retired and (ii) 91 days following the last maturity date of any notes then outstanding, and

(z) such Indebtedness has a Weighted Average Life to Maturity at the time Incurred which is not less than the shorter of (i) the remaining Weighted Average Life to Maturity of the Indebtedness being so redeemed, repurchased, defeased, acquired or retired and (ii) the Weighted Average Life to Maturity that would result if all payments of principal on the Indebtedness being redeemed, repurchased, defeased, acquired or retired that were due on or after the date that is one year following the last maturity date of any notes then outstanding were instead due on such date;

(C) the redemption, repurchase, defeasance or other acquisition or retirement of Junior Lien Obligations of Holdings or any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, new Indebtedness of Holdings or a Subsidiary Guarantor which is Incurred in accordance with the covenant described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” so long as

(w) such new Indebtedness is in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding of

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the Indebtedness being so redeemed, repurchased, defeased, acquired or retired for value (plus, without duplication, any additional Indebtedness Incurred to pay interest, premiums or defeasance costs, in each case in an amount equal to the amount required by the instruments governing such existing Indebtedness (whether such existing Indebtedness is redeemed pursuant to a tender offer, optional redemption or otherwise), and fees and expenses Incurred in connection therewith),

(x) such Indebtedness constitutes Junior Lien Obligations, Subordinated Indebtedness or unsecured Indebtedness,

(y) such Indebtedness has a final scheduled maturity date equal to or later than the earlier of (i) the final scheduled maturity date of the Indebtedness being so redeemed, repurchased, acquired or retired and (ii) 91 days following the last maturity date of any notes then outstanding, and

(z) such Indebtedness has a Weighted Average Life to Maturity at the time Incurred which is not less than the shorter of (i) the remaining Weighted Average Life to Maturity of the Indebtedness being so redeemed, repurchased, defeased, acquired or retired and (ii) the Weighted Average Life to Maturity that would result if all payments of principal on the Indebtedness being redeemed, repurchased, defeased, acquired or retired that were due on or after the date that is one year following the last maturity date of any notes then outstanding were instead due on such date;

(D) the redemption, repurchase, defeasance or other acquisition or retirement of unsecured Indebtedness representing Indebtedness for borrowed money of Holdings or any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, new Indebtedness of Holdings or a Subsidiary Guarantor which is Incurred in accordance with the covenant described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” so long as

(w) such new Indebtedness is in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding of the Indebtedness being so redeemed, repurchased, defeased, acquired or retired for value (plus, without duplication, any additional Indebtedness Incurred to pay interest, premiums or defeasance costs, in each case in an amount equal to the amount required by the instruments governing such existing Indebtedness (whether such existing Indebtedness is redeemed pursuant to a tender offer, optional redemption or otherwise), and fees and expenses Incurred in connection therewith),

(x) such Indebtedness constitutes Subordinated Indebtedness or unsecured Indebtedness,

(y) such Indebtedness has a final scheduled maturity date equal to or later than the earlier of (i) the final scheduled maturity date of the Indebtedness being so redeemed, repurchased, acquired or retired and (ii) 91 days following the last maturity date of any notes then outstanding, and

(z) such Indebtedness has a Weighted Average Life to Maturity at the time Incurred which is not less than the shorter of (i) the remaining Weighted Average Life to Maturity of the Indebtedness being so redeemed, repurchased, defeased, acquired or retired and (ii) the Weighted Average Life to Maturity that would result if all payments of principal on the Indebtedness being redeemed, repurchased, defeased, acquired or retired that were due on or after the date that is one year following the last maturity date of any notes then outstanding were instead due on such date,

(4) a Restricted Payment to pay for the repurchase, retirement or other acquisition for value of Equity Interests of Holdings or any direct or indirect parent of Holdings held by any future, present or former employee, director, manager or consultant of Holdings or any direct or indirect parent of Holdings or any Subsidiary of Holdings pursuant to any management equity plan or stock option plan or any other management or employee benefit plan or other agreement or arrangement;provided,however, that the aggregate Restricted Payments made under this clause (4) do not exceed $5.0 million in any calendar year, with unused amounts in any calendar year being permitted to be carried over to succeeding

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calendar years subject to a maximum of $10.0 million in any calendar year;provided,further,however, that such amount in any calendar year may be increased by an amount not to exceed:

(A) the cash proceeds received by Holdings or any of the Restricted Subsidiaries from the sale of Equity Interests (other than Disqualified Stock) of Holdings or any direct or indirect parent of Holdings (to the extent contributed to Holdings) to members of management, directors, managers or consultants of Holdings and its Restricted Subsidiaries or any direct or indirect parent of Holdings (provided that the amount of such cash proceeds utilized for any such repurchase, retirement, other acquisition or dividend will not increase the amount available for Restricted Payments under clause (3) of the definition of “Cumulative Credit”, plus

(B) the cash proceeds of key man life insurance policies received by Holdings or any direct or indirect parent of Holdings (to the extent contributed to Holdings) or the Restricted Subsidiaries after the Issue Date;

provided, that Holdings may elect to apply all or any portion of the aggregate increase contemplated by clauses (a) and (b) above in any calendar year andprovided,further, that cancellation of Indebtedness owing to Holdings or any of its Restricted Subsidiaries from any present or former employees, directors, officers or consultants of Holdings, any Restricted Subsidiary or the direct or indirect parents of Holdings in connection with a repurchase of Equity Interests of Holdings or any of its direct or indirect parents will not be deemed to constitute a Restricted Payment for purposes of this covenant or any other provision of the indenture;

(5) the declaration and payment of dividends or distributions to holders of any class or series of Disqualified Stock of Holdings or any of its Restricted Subsidiaries issued or Incurred in accordance with the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

(6) (A) the declaration and payment of dividends or distributions to holders of any class or series of Designated Preferred Stock (other than Disqualified Stock) issued after the Issue Date;

(B) a Restricted Payment to any direct or indirect parent of Holdings, the proceeds of which will be used to fund the payment of dividends to holders of any class or series of Designated Preferred Stock (other than Disqualified Stock) of any direct or indirect parent of Holdings issued after the Issue Date; provided that the aggregate amount of dividends declared and paid pursuant to this clause (b) does not exceed the net cash proceeds actually received by Holdings from any such sale of Designated Preferred Stock (other than Disqualified Stock) issued after the Issue Date; and

(C) the declaration and payment of dividends on Refunding Capital Stock that is Preferred Stock in excess of the dividends declarable and payable thereon pursuant to clause (2) of this paragraph;

provided,however, in the case of each of (a) and (c) above of this clause (6), that for the most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date of issuance of such Designated Preferred Stock, after giving effect to such issuance (and the payment of dividends or distributions) on apro forma basis (including apro forma application of the net proceeds therefrom), Holdings would have had a Fixed Charge Coverage Ratio of at least 2.25 to 1.00;

(7) [reserved];

(8) [reserved];

(9) [reserved];

(10) other Restricted Payments in an aggregate amount, when taken together with all other Restricted Payments made pursuant to this clause (10) that are at that time outstanding, not to exceed $10.0 million;

(11) [reserved];

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(12) (a) with respect to any taxable period for which Holdings and/or any of its Subsidiaries are members of a consolidated, combined, affiliated, unitary or similar income tax group for U.S. federal and/or applicable state or local income tax purposes of which a direct or indirect parent of Holdings is the common parent, or for which Holdings is a partnership or disregarded entity for U.S. federal income tax purposes that is wholly-owned (directly or indirectly) by a C corporation for U.S. federal and/or applicable state or local income tax purposes, distributions to any direct or indirect parent of Holdings in an amount not to exceed the amount of any U.S. federal, state and/or local income taxes that Holdings and/or its Subsidiaries, as applicable, would have paid for such taxable period had Holdings and/or its Subsidiaries, as applicable, been a stand-alone corporate taxpayer or a stand -alone corporate group; and (b) with respect to any taxable period ending after the Issue Date for which Holdings is a partnership or disregarded entity for U.S. federal income tax purposes (other than a partnership or disregarded entity described in clause (a)), distributions to any direct or indirect parent of Holdings in an amount necessary to permit such direct or indirect parent of Holdings to make a pro rata distribution to its owners such that each direct or indirect owner of Holdings receives an amount from such pro rata distribution sufficient to enable such owner to pay its U.S. federal, state and/or local income taxes (as applicable) attributable to its direct or indirect ownership of Holdings and its Subsidiaries with respect to such taxable period (assuming that each owner is subject to tax at the highest combined marginal federal, state, and/or local income tax rate applicable to any owner for such taxable period and taking into account the deductibility of state and local income taxes for corporations for U.S. federal income tax purposes (and any limitations thereon), the alternative minimum tax, any cumulative net taxable loss of Holdings for prior taxable periods ending after the Issue Date to the extent such loss is of a character that would allow such loss to be available to reduce taxes in the current taxable period (taking into account any limitations on the utilization of such loss to reduce such taxes and assuming such loss had not already been utilized) and the character (e.g., long-term or short-term capital gain or ordinary or exempt) of the applicable income);

(13) any Restricted Payment, if applicable:

(a) in amounts required for any direct or indirect parent of Holdings (but not including any direct or indirect parent of a Public Parent Company) to pay fees and expenses (including franchise or similar taxes) required to maintain its corporate existence, customary salary, bonus and other benefits payable to, and indemnities provided on behalf of, officers and employees of any direct or indirect parent of Holdings (but not including any direct or indirect parent of a Public Parent Company) and general corporate operating and overhead expenses of any direct or indirect parent of Holdings (but not including any direct or indirect parent of a Public Parent Company) in each case to the extent such fees and expenses are attributable to the ownership or operation of Holdings, if applicable, and its Subsidiaries;

(b) in amounts required for any direct or indirect parent of Holdings, if applicable, to pay interest and/or principal on Indebtedness the proceeds of which have been contributed to Holdings or any Restricted Subsidiary and that has been guaranteed by, or is otherwise considered Indebtedness of, Holdings Incurred in accordance with the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”; and

(c) in amounts required for any direct or indirect parent of Holdings (but not including any direct or indirect parent of a Public Parent Company) to pay fees and expenses related to any unsuccessful equity or debt offering of such parent;

(14) repurchases of Equity Interests deemed to occur upon exercise of stock options or warrants if such Equity Interests represent a portion of the exercise price of such options or warrants;

(15) [reserved];

(16) Restricted Payments by Holdings or any Restricted Subsidiary of Holdings to allow the payment of cash in lieu of the issuance of fractional shares upon the exercise of options or warrants or upon the conversion or exchange of Capital Stock of any such Person;

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(17) the repurchase, redemption or other acquisition or retirement for value of any Subordinated Indebtedness pursuant to provisions similar to those described under the captions “—Change of Control” and “—Certain Covenants—Asset Sales”;provided that all notes tendered by holders of the notes in connection with a Change of Control Offer or Asset Sale Offer, as applicable, have been repurchased, redeemed or acquired for value; and

(18) payments or distributions to dissenting stockholders pursuant to applicable law, pursuant to or in connection with a consolidation, amalgamation, merger or transfer of all or substantially all of the assets of Holdings and its Restricted Subsidiaries, taken as a whole, that complies with the covenant described under “—Certain Covenants—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets”;provided that as a result of such consolidation, amalgamation, merger or transfer of assets, Holdings shall have made a Change of Control Offer (if required by the indenture) and that all notes tendered by holders in connection with such Change of Control Offer have been repurchased, redeemed or acquired for value;

provided,however, that at the time of, and after giving effect to, any Restricted Payment permitted under clauses (6)(b), (10) and (13)(b) of this covenant, no Default shall have occurred and be continuing or would occur as a consequence thereof;provided,further, that any Restricted Payments made with property other than cash shall be calculated using the Fair Market Value (as determined in good faith by Holdings) of such property.

As of the Issue Date, all of the Subsidiaries of Holdings shall be Restricted Subsidiaries. Holdings shall not permit any Unrestricted Subsidiary to become a Restricted Subsidiary except pursuant to the definition of “Unrestricted Subsidiary.” For purposes of designating any Restricted Subsidiary as an Unrestricted Subsidiary, all outstanding Investments by Holdings and its Restricted Subsidiaries (except to the extent repaid) in the Subsidiary so designated shall be deemed to be Restricted Payments in an amount determined as set forth in the last sentence of the definition of “Investments.” Such designation shall only be permitted if a Restricted Payment or Permitted Investment in such amount would be permitted at such time and if such Subsidiary otherwise meets the definition of an Unrestricted Subsidiary.

Dividend and Other Payment Restrictions Affecting Subsidiaries

The indenture provides that Holdings shall not, and shall not permit any of its Restricted Subsidiaries to, directly or indirectly, create or otherwise cause or suffer to exist or become effective any consensual encumbrance or consensual restriction on the ability of any Restricted Subsidiary to:

(a) (i) pay dividends or make any other distributions to Holdings or any of its Restricted Subsidiaries (1) on its Capital Stock or (2) with respect to any other interest or participation in, or measured by, its profits; or (ii) pay any Indebtedness owed to Holdings or any of its Restricted Subsidiaries;

(b) make loans or advances to Holdings or any of its Restricted Subsidiaries; or

(c) sell, lease or transfer any of its properties or assets to Holdings or any of its Restricted Subsidiaries;

except in each case for such encumbrances or restrictions existing under or by reason of:

(1) (i) contractual encumbrances or restrictions in effect on the Issue Date and (ii) contractual encumbrances or restrictions pursuant to the Credit Agreement and the other Credit Agreement Documents and, in each case, any similar contractual encumbrances effected by any amendments, modifications, restatements, renewals, supplements, refundings, replacements or refinancings of such agreements or instruments;

(2) the indenture, the notes (and any Exchange Notes) or the Subsidiary Guarantees;

(3) applicable law or any applicable rule, regulation or order;

(4) any agreement or other instrument of a Person acquired by Holdings or any Restricted Subsidiary which was in existence at the time of such acquisition (but not created in contemplation thereof or to

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provide all or any portion of the funds or credit support utilized to consummate such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person and its Subsidiaries, or the property or assets of the Person and its Subsidiaries, so acquired;

(5) contracts or agreements for the sale of assets, including any restriction with respect to a Restricted Subsidiary imposed pursuant to an agreement entered into for the sale or disposition of the Capital Stock or assets of such Restricted Subsidiary;

(6) Secured Indebtedness otherwise permitted to be Incurred pursuant to the covenants described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and “—Liens” that limit the right of the debtor to dispose of the assets securing such Indebtedness;

(7) restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business;

(8) customary provisions in joint venture agreements and other similar agreements entered into in the ordinary course of business;

(9) purchase money obligations for property acquired and Capitalized Lease Obligations in the ordinary course of business that impose restrictions of the nature discussed in clause (c) above on the property so acquired;

(10) customary provisions contained in leases, licenses and other similar agreements entered into in the ordinary course of business;

(11) in the case of clause (c) of the first paragraph of this covenant, any encumbrance or restriction that restricts in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease (including leases governing leasehold interests orFarm-In Agreements orFarm-Out Agreements relating to leasehold interests in Oil and Gas Properties), license or similar contract, or the assignment or transfer of any such lease (including leases governing leasehold interests orFarm-In Agreements orFarm-Out Agreements relating to leasehold interests in Oil and Gas Properties), license (including without limitations, licenses of intellectual property) or other contracts;

(12) [reserved];

(13) other Indebtedness, Disqualified Stock or Preferred Stock (a) of Holdings or any Restricted Subsidiary that is a Subsidiary Guarantor or a Foreign Subsidiary or (b) of any Restricted Subsidiary that is not a Subsidiary Guarantor or a Foreign Subsidiary so long as such encumbrances and restrictions contained in any agreement or instrument will not materially affect the Issuers’ ability to make anticipated principal or interest payments on the notes (as determined in good faith by Holdings);provided that in the case of each of clauses (a) and (b), such Indebtedness, Disqualified Stock or Preferred Stock is permitted to be Incurred subsequent to the Issue Date pursuant to the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

(14) an Investment otherwise permitted by the indenture;

(15) any customary encumbrances or restrictions imposed pursuant to any agreement of the type described in the definition of “Permitted Business Investment”; or

(16) any encumbrances or restrictions of the type referred to in clauses (a), (b) or (c) above imposed by any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of the contracts, instruments or obligations referred to in clauses (1) through (15) above;provided that such amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are, in the good faith judgment of Holdings, no more restrictive with respect to such dividend and other payment restrictions than those contained in the dividend or other payment restrictions prior to such amendment, modification, restatement, renewal, increase, supplement, refunding, replacement or refinancing.

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For purposes of determining compliance with this covenant, (1) the priority of any Preferred Stock in receiving dividends or liquidating distributions prior to dividends or liquidating distributions being paid on common stock shall not be deemed a restriction on the ability to make distributions on Capital Stock and (2) the subordination of loans or advances made to Holdings or a Restricted Subsidiary to other Indebtedness Incurred by Holdings or any such Restricted Subsidiary shall not be deemed a restriction on the ability to make loans or advances.

Asset Sales

The indenture provides that Holdings shall not, and shall not permit any Restricted Subsidiary to, cause or make an Asset Sale, unless (x) Holdings or any of its Restricted Subsidiaries, as the case may be, receives consideration at the time of such Asset Sale at least equal to the Fair Market Value (if the consideration for such Asset Sale is less than or equal to $25.0 million, as determined in good faith by Holdings or if the consideration for such Asset Sale exceeds $25.0 million, as determined by an Independent Financial Advisor) of the assets sold or otherwise disposed of and (y) at least 75% of the consideration therefor received by Holdings or such Restricted Subsidiary, as the case may be, is in the form of Cash Equivalents;provided that the amount of:

(a) any liabilities (as shown on Holdings’ or a Restricted Subsidiary’s most recent balance sheet or in the notes thereto) of Holdings or any Restricted Subsidiary (other than liabilities that are by their terms subordinated to the notes or any Subsidiary Guarantee) that are assumed by the transferee of any such assets or that are otherwise cancelled or terminated in connection with the transaction with such transferee,

(b) any notes or other obligations or other securities or assets received by Holdings or such Restricted Subsidiary from such transferee that are converted by Holdings or such Restricted Subsidiary into cash within 180 days of the receipt thereof (to the extent of the cash received),

(c) with respect to any Asset Sale of Oil and Gas Properties by Holdings or any Restricted Subsidiary, the costs and expenses related to the exploration, development, completion or production of such Oil and Gas Properties and activities related thereto agreed to be assumed by the transferee (or an Affiliate thereof),

(d) [reserved],

(e) [reserved], and

(f) any DesignatedNon-cash Consideration received by Holdings or any Restricted Subsidiary in such Asset Sale having an aggregate Fair Market Value (as determined in good faith by Holdings), taken together with all other DesignatedNon-cash Consideration received pursuant to this clause (f) that is at that time outstanding, not to exceed $25.0 million at the time of the receipt of such DesignatedNon-cash Consideration (with the Fair Market Value of each item of DesignatedNon-cash Consideration being measured at the time received and without giving effect to subsequent changes in value),

shall be deemed to be Cash Equivalents for the purposes of this provision.

Within 365 days of an Issuer’s or any Restricted Subsidiary’s receipt of the Net Proceeds of any Asset Sale, the Issuers or such Restricted Subsidiary may apply the Net Proceeds from such Asset Sale, at its option:

(1) to repay (a) Indebtedness constituting First-Priority Lien Obligations (and, if the Indebtedness repaid is revolving credit Indebtedness, to correspondingly reduce commitments with respect thereto), (b) Indebtedness of a Restricted Subsidiary that is not a Subsidiary Guarantor (provided that the assets disposed of in such Asset Sale were not assets of an Issuer or a Subsidiary Guarantor), (c) Obligations under the notes, (d) other Pari Passu Indebtedness so long as the Net Proceeds from such Asset Sale are with respect to (i) assets that secure such other Pari Passu Indebtedness on a senior basis to the notes

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Obligations or (ii) assets not constituting Collateral or (e) Other Second-Lien Obligations (provided that if an Issuer or any Subsidiary Guarantor shall so reduce Other Second-Lien Obligations under this clause (e) (which for the avoidance of doubt will not constitute Indebtedness under clauses (a), (b), (c) or (d), the Issuers will equally and ratably reduce Obligations under the notes as provided under “Optional Redemption,” through open-market purchases (provided that such purchases are at or above 100% of the principal amount thereof or, in the event that the notes were issued with significant original issue discount, 100% of the accreted value thereof) or by making an offer (in accordance with the procedures set forth below for an Asset Sale Offer) to all holders to purchase at a purchase price equal to 100% of the principal amount thereof (or, in the event that the notes were issued with significant original issue discount, 100% of the accreted value thereof), plus accrued and unpaid interest and Additional Interest, if any, the pro rata principal amount of notes, in each case other than Indebtedness owed to Holdings or an Affiliate of Holdings;

(2) to make an Investment in any one or more businesses (provided that if such Investment is in the form of the acquisition of Capital Stock of a Person, such acquisition results in such Person becoming a Restricted Subsidiary of Holdings), assets, or property or capital expenditures, in each case (a) used or useful in a Similar Business or (b) that replace the properties and assets that are the subject of such Asset Sale;provided that if the assets that were disposed of in the Asset Sale constituted Collateral, the assets acquired must also be Collateral; or

(3) to invest in Additional Assets;provided that if the assets that were disposed of in the Asset Sale constituted Collateral, the Additional Assets must also be Collateral.

Any Net Proceeds from any Asset Sale that are not applied as provided and within the time period set forth in the second paragraph of this covenant (it being understood that any portion of such Net Proceeds used to make an offer to purchase notes, as described in clause (1) above, shall be deemed to have been invested whether or not such offer is accepted) will be deemed to constitute “Excess Proceeds.” When the aggregate amount of Excess Proceeds exceeds $20,000,000, the Issuers shall make an offer to all holders of notes (and, at the option of the Issuers, to holders of any Other Second-Lien Obligations) (an “Asset Sale Offer”) to purchase the maximum principal amount of notes (and such Other Second-Lien Obligations), that is at least $2,000 and an integral multiple of $1.00 in excess thereof that may be purchased out of the Excess Proceeds at an offer price in cash in an amount equal to 100% of the principal amount thereof (or, in the event the notes or such Other Second-Lien Obligations was issued with significant original issue discount, 100% of the accreted value thereof), plus accrued and unpaid interest and Additional Interest, if any (or, in respect of such Other Second-Lien Obligations, such lesser price, if any, as may be provided for by the terms of such Other Second-Lien Obligations), to the date fixed for the closing of such offer, in accordance with the procedures set forth in the indenture. The Issuers will commence an Asset Sale Offer with respect to Excess Proceeds within ten (10) Business Days after the date that Excess Proceeds exceeds $20,000,000 by delivering the notice required pursuant to the terms of the indenture, with a copy to the Trustee. To the extent that the aggregate amount of notes (and such Other Second-Lien Obligations) tendered pursuant to an Asset Sale Offer is less than the Excess Proceeds, the Issuers may use any remaining Excess Proceeds for any purpose that is not prohibited by the indenture. If the aggregate principal amount of notes (and such Other Second-Lien Obligations) surrendered by holders thereof exceeds the amount of Excess Proceeds, the Issuers, upon determination by the Issuers of the aggregate principal amount to be selected, shall select the notes to be purchased in the manner described below. Upon completion of any such Asset Sale Offer, the amount of Excess Proceeds shall be reset at zero.

Pending the final application of any such Net Proceeds pursuant to this covenant, Holdings or such Restricted Subsidiary may temporarily reduce Indebtedness under a revolving credit facility, if any, or otherwise invest such Net Proceeds in any manner not prohibited by the indenture.

The Issuers will comply with the requirements of Rule14e-1 under the Exchange Act and any other securities laws and regulations to the extent such laws or regulations are applicable in connection with the repurchase of the notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict

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with the provisions of the indenture, the Issuers will comply with the applicable securities laws and regulations and shall not be deemed to have breached its obligations described in the indenture by virtue thereof.

If more notes (and such Pari Passu Indebtedness) are tendered pursuant to an Asset Sale Offer than the Issuers are required to purchase, selection of such notes for purchase shall be made by the Issuers in compliance with the requirements of the principal national securities exchange, if any, on which such notes are listed (and the Issuers shall notify the Trustee of any such listing), or if such notes are not so listed, on a pro rata basis, to the extent practicable, by lot or by such other method as the Issuers shall deem fair and appropriate (and in such manner as complies with the requirements of DTC, if applicable);provided that no notes of $2,000 or less shall be purchased in part. Selection of such Pari Passu Indebtedness shall be made pursuant to the terms of such Pari Passu Indebtedness.

Notices of an Asset Sale Offer shall be mailed by the Issuers by first class mail, postage prepaid, or otherwise delivered in accordance with the applicable procedures of DTC, at least 30 but not more than 60 days before the purchase date to each holder of notes at such holder’s registered address, with a copy to the Trustee. If any note is to be purchased in part only, any notice of purchase that relates to such note shall state the portion of the principal amount thereof that has been or is to be purchased.

Transactions with Affiliates

The indenture provides that Holdings shall not, and shall not permit any of its Restricted Subsidiaries to, directly or indirectly, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction or series of transactions, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate of Holdings (each of the foregoing, an “Affiliate Transaction”) involving aggregate consideration in excess of $2.0 million, unless:

(a) such Affiliate Transaction is on terms that are not materially less favorable to Holdings or the relevant Restricted Subsidiary than those that could have been obtained in a comparable transaction by Holdings or such Restricted Subsidiary with an unrelated Person;

(b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $10.0 million, Holdings delivers to the Trustee a resolution adopted in good faith by the majority of the Board of Directors of Holdings, approving such Affiliate Transaction and set forth in an Officers’ Certificate certifying that such Affiliate Transaction complies with clause (a) above; and

(c) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $25.0 million, Holdings delivers to the Trustee a letter from an Independent Financial Advisor stating that such transaction is fair to Holdings or such Restricted Subsidiary from a financial point of view.

The foregoing provisions will not apply to the following:

(1) transactions between or among Holdings and/or any of its Restricted Subsidiaries (or an entity that becomes a Restricted Subsidiary as a result of such transaction) and any merger, consolidation or amalgamation of Holdings and any direct parent of Holdings;provided that such parent shall have no material liabilities and no material assets other than cash, Cash Equivalents and the Capital Stock of Holdings and such merger, consolidation or amalgamation is otherwise in compliance with the terms of the indenture and effected for a bona fide business purpose;

(2) Restricted Payments permitted by the provisions of the covenant described under “—Limitation on Restricted Payments” and Permitted Investments;

(3) the payment of reasonable and customary fees and reimbursement of expenses paid to, and indemnityprovided on behalf of, officers, directors, managers, employees or consultants of Holdings, any

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Restricted Subsidiary, or any direct or indirect parent of Holdings (but not including any direct or indirect parent of a Public Parent Company);

(4) transactions in which Holdings or any Restricted Subsidiary, as the case may be, delivers to the Trustee a letter from an Independent Financial Advisor stating that such transaction is fair to Holdings or such Restricted Subsidiary from a financial point of view or meets the requirements of clause (a) of the preceding paragraph;

(5) payments or loans (or cancellation of loans) to officers, directors, managers, employees or consultants of Holdings, any Restricted Subsidiary, or any direct or indirect parent of Holdings (but not including any direct or indirect parent of a Public Parent Company) which are approved by a majority of the Board of Directors of Holdings in good faith;

(6) any agreement as in effect as of the Issue Date or any amendment thereto (so long as any such agreement together with all amendments thereto, taken as a whole, is not more disadvantageous to the holders of the notes in any material respect than the original agreement as in effect on the Issue Date) or any transaction contemplated thereby as determined in good faith by Holdings;

(7) [reserved];

(8) the execution of the Transactions, and the payment of all fees and expenses related to the Transactions (but not including fees and expenses paid to theCo-Investors, other than reimbursement of certain expenses to Franklin Advisers, Inc., MacKay Shields LLC and any of their respective Affiliates);

(9) (a) transactions with customers, clients, suppliers or purchasers or sellers of goods or services, or transactions otherwise relating to the purchase or sale of goods or services, in each case in the ordinary course of business and otherwise in compliance with the terms of the indenture, which are fair to Holdings and its Restricted Subsidiaries in the reasonable determination of the Board of Directors or the senior management of Holdings, or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party or (b) transactions with joint ventures or Unrestricted Subsidiaries entered into in the ordinary course of business and consistent with past practice or industry norm;

(10) [reserved];

(11) the issuance of Equity Interests (other than Disqualified Stock) of Holdings to any Person;

(12) the issuances of securities or other payments, awards or grants in cash, securities or otherwise pursuant to, or the funding of, employment arrangements, stock option and stock ownership plans or similar employee benefit plans approved by the Board of Directors of Holdings or any direct or indirect parent of Holdings or of a Restricted Subsidiary, as appropriate, in good faith;

(13) the entering into of any tax sharing agreement or arrangement that complies with clause (12) of the second paragraph of the covenant described under “—Limitation on Restricted Payments”;

(14) any contribution to the capital of Holdings;

(15) transactions permitted by, and complying with, the provisions of the covenant described under “—Certain Covenants—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets”;

(16) transactions between Holdings or any of its Restricted Subsidiaries and any Person, a director or manager of which is also a director or manager of Holdings or any direct or indirect parent of Holdings;provided,however, that such director or manager abstains from voting as a director or manager of Holdings or such direct or indirect parent, as the case may be, on any matter involving such other Person;provided,further, that such transaction is not with an Unrestricted Subsidiary;

(17) pledges of Equity Interests of Unrestricted Subsidiaries;

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(18) the formation and maintenance of any consolidated group or subgroup for tax, accounting or cash pooling or management purposes in the ordinary course of business;

(19) any employment agreements entered into by Holdings or any of its Restricted Subsidiaries in the ordinary course of business;

(20) [reserved];

(21) [reserved];

(22) transactions undertaken in good faith (as certified by a responsible financial or accounting officer of Holdings in an Officers’ Certificate) for the purpose of improving the consolidated tax efficiency of Holdings and its Subsidiaries and not for the purpose of circumventing any covenant set forth in the indenture;

(23) [reserved]; and

(24) customary agreements and arrangements with oil and gas royalty trusts and master limited partnership agreements that comply with the affiliate transaction provisions of such royalty trust or master limited partnership agreement.

Liens

The indenture provides that Holdings will not, and will not permit any Restricted Subsidiary to, directly or indirectly, create, Incur or suffer to exist any Lien (except Permitted Liens) on any asset or property of Holdings or such Restricted Subsidiary securing Indebtedness of Holdings or any of its Restricted Subsidiaries.

For purposes of determining compliance with this covenant, (A) a Lien securing an item of Indebtedness need not be permitted solely by reference to one category of permitted Liens described in the definition of “Permitted Liens” or pursuant to the first paragraph of this covenant but may be permitted in part under any combination thereof and (B) in the event that a Lien securing an item of Indebtedness, Disqualified Stock or Preferred Stock (or any portion thereof) meets the criteria of one or more of the categories of permitted Liens described in the definition of “Permitted Liens”, Holdings shall, in its sole discretion, classify or reclassify, or later divide, classify or reclassify, such Lien securing such item of Indebtedness (or any portion thereof) in any manner that complies with this covenant and will only be required to include the amount and type of such Lien or such item of Indebtedness secured by such Lien in one of the clauses of the definition of “Permitted Liens” and such Lien securing such item of Indebtedness will be treated as being Incurred or existing pursuant to only one of such clauses.

With respect to any Lien securing Indebtedness that was permitted to secure such Indebtedness at the time of the Incurrence of such Indebtedness, such Lien shall also be permitted to secure any Increased Amount of such Indebtedness. The “Increased Amount” of any Indebtedness means any increase in the amount of such Indebtedness in connection with any accrual of interest, the accretion of accreted value, the amortization of original issue discount, the payment of interest in the form of additional Indebtedness with the same terms or in the form of common stock of Holdings, the payment of dividends on Preferred Stock in the form of additional shares of Preferred Stock of the same class, accretion of original issue discount or liquidation preference and increases in the amount of Indebtedness outstanding solely as a result of fluctuations in the exchange rate of currencies or increases in the value of property securing Indebtedness described in clause (3) of the definition of “Indebtedness.”

Reports and Other Information

The indenture provides that notwithstanding that Holdings may not be subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act or otherwise report on an annual and quarterly basis on forms provided for such annual and quarterly reporting pursuant to rules and regulations promulgated by the SEC,

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Holdings will file with the SEC (and provide the Trustee and holders with copies thereof, without cost to each holder, within 15 days after it files them with the SEC):

(1) within the time period specified in the SEC’s rules and regulations fornon-accelerated filers, annual reports on Form10-K (or any successor or comparable form) containing the information that would have been required to be contained therein (or required in such successor or comparable form) if Holdings were subject to Section 13 or 15(d) of the Exchange Act, except to the extent permitted to be excluded by the SEC;

(2) within the time period specified in the SEC’s rules and regulations fornon-accelerated filers, reports on Form10-Q (or any successor or comparable form) containing the information that would have been required to be contained therein (or required in such successor or comparable form) if Holdings were subject to Section 13 or 15(d) of the Exchange Act, except to the extent permitted to be excluded by the SEC;

(3) promptly from time to time after the occurrence of an event required to be therein reported (and in any event within the time period specified in the SEC’s rules and regulations), such other reports onForm 8-K (or any successor or comparable form) that would have been required if Holdings were subject to Section 13 or 15(d) of the Exchange Act; and

(4) subject to the foregoing, any other information, documents and other reports which Holdings would be required to file with the SEC if it were subject to Section 13 or 15(d) of the Exchange Act;

provided,however, that Holdings shall not be so obligated to file such reports with the SEC if the SEC does not permit such filing, in which event Holdings will make available such information to prospective purchasers of notes in addition to providing such information to the Trustee and the holders, in each case within 15 days after the time Holdings would be required to file such information with the SEC if it were subject to Section 13 or 15(d) of the Exchange Act. In addition to providing such information to the Trustee, Holdings shall make available to the holders, prospective investors and securities analysts the information required to be provided pursuant to the foregoing clauses (1), (2) and (3), by posting such information to its website or on IntraLinks or any comparable online data system or website.

If Holdings has designated any of its Subsidiaries as an Unrestricted Subsidiary, then the annual and quarterly information required pursuant to clauses (1) and (2) of the first paragraph of this covenant shall include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, of the financial condition and results of operations of Holdings and its Restricted Subsidiaries separate from the financial condition and results of operations of such Unrestricted Subsidiaries.

Notwithstanding the foregoing, Holdings will not be required to furnish any information, certificates or reports required by Items 307 or 308 of RegulationS-K prior to the effectiveness of the Exchange Offer Registration Statement or Shelf Registration Statement, as applicable.

In the event that:

(1) the rules and regulations of the SEC permit Holdings and any direct or indirect parent of Holdings to report at such parent entity’s level on a consolidated basis and such parent entity is not engaged in any business in any material respect other than incidental to its ownership, directly or indirectly, of the capital stock of Holdings, or

(2) any direct or indirect parent of Holdings is or becomes a Guarantor of the notes,

consolidated reporting at such parent entity’s level in a manner consistent with that described in this covenant for Holdings will satisfy this covenant, and Holdings is permitted to satisfy its obligations in this covenant with respect to financial information relating Holdings by furnishing financial information relating to such direct or indirect parent;provided that such financial information is accompanied by consolidating information that

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explains in reasonable detail the differences between the information relating to such direct or indirect parent and any of its Subsidiaries other than Holdings and its Subsidiaries, on the one hand, and the information relating to Holdings, the Subsidiary Guarantors and the other Subsidiaries of Holdings on a standalone basis, on the other hand. In addition, Holdings will make such information available to prospective investors upon request.

Holdings will make such information available to prospective investors upon request. Holdings shall, for so long as any notes remain outstanding during any period when neither it nor another Reporting Entity is subject to Section 13 or 15(d) of the Exchange Act, or otherwise permitted to furnish the SEC with certain information pursuant to Rule12g3-2(b) of the Exchange Act, it will furnish to the holders of the notes and to prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Notwithstanding the foregoing, Holdings will be deemed to have furnished the reports and information referred to above to the Trustee and the holders if Holdings has filed such reports with the SEC via the EDGAR filing system (or any successor system) and such reports are publicly available. In addition, the requirements of this covenant shall be deemed satisfied (1) prior to the commencement of the Exchange Offer contemplated by the Registration Rights Agreement relating to the notes or the effectiveness of the Shelf Registration Statement, by the filing with the SEC of the Exchange Offer Registration Statement or Shelf Registration Statement in accordance with the provisions of such Registration Rights Agreement, and any amendments thereto, if such registration statement and/or amendments thereto are filed at times that otherwise satisfy the time requirements set forth in the first paragraph of this covenant or (2) the posting of reports and information that would be required to be provided to the holders on Holdings’ website (or that of any of Holdings’ parent companies). The Trustee shall have no obligation to monitor whether the Issuers post such reports, information and documents on the SEC’s EDGAR filing system or Holdings’ (or that of any of Holdings’ parent companies) website, or collect any such information from the SEC’s EDGAR filing system or Holdings’ (or that of any of Holdings’ parent companies) website.

Holdings will also hold quarterly conference calls, beginning with the first full fiscal quarter ending after the Issue Date, for all holders of the notes, prospective investors and securities analysts to discuss such financial information no later than ten Business Days after the distribution of such information required by clauses (1) or (2) of the first paragraph of this covenant and, prior to the date of each such conference call, will announce the time and date of such conference call and either include all information necessary to access the call or inform holders of the notes, prospective investors and securities analysts how they can obtain such information, including, without limitation, the applicable password or login information (if applicable).

The Trustee shall have no liability or responsibility for the content, filing or timeliness of any report delivered or filed under or in connection with the indenture or the transactions contemplated thereby. Delivery of such reports, information and documents to the Trustee is for informational purposes only, and the Trustee’s receipt thereof shall not constitute constructive notice of any information contained therein or determinable from information contained therein, including the Issuers’ compliance with any of their covenants under the indenture (as to which the Trustee is entitled to rely exclusively on Officer’s Certificates).

Future Guarantors

The indenture provides that Holdings will cause (i) each Wholly Owned Restricted Subsidiary (other than any Excluded Subsidiary), (ii) any Subsidiary that ceases to be an Excluded Subsidiary and is a Wholly Owned Restricted Subsidiary and (iii) any other Subsidiary that guarantees any Indebtedness of either of the Issuers or any of the Subsidiary Guarantors to execute and deliver to the Trustee a supplemental indenture pursuant to which such Subsidiary will guarantee the Issuers’ Obligations under the notes and the indenture on the terms and conditions set forth in the indenture, a joinder to the Collateral Agreement, and, to the extent required pursuant to the covenant described under “—Security—After-Acquired Property,” a joinder agreement to each applicable Security Document or new Security Documents, and, if required by the Senior Lien Intercreditor Agreement, a joinder to the Senior Lien Intercreditor Agreement.

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Each Subsidiary Guarantee will be limited to an amount not to exceed the maximum amount that can be guaranteed by that Subsidiary Guarantor without rendering the Subsidiary Guarantee or the indenture, as it relates to such Subsidiary Guarantor, voidable under applicable law relating to fraudulent conveyance or fraudulent transfer or similar laws affecting the rights of creditors generally or capital maintenance or corporate benefit rules applicable to guarantees for obligations of affiliates.

Each Subsidiary Guarantee shall be released in accordance with the provisions of the indenture described under “—Subsidiary Guarantees.”

Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets

The indenture provides that Holdings may not, directly or indirectly, consolidate, amalgamate or merge with or into or wind up or convert into (whether or not Holdings is the surviving Person), or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets in one or more related transactions, to any Person unless:

(1) Holdings is the surviving person or the Person formed by or surviving any such consolidation, amalgamation, merger, winding up or conversion (if other than Holdings) or to which such sale, assignment, transfer, lease, conveyance or other disposition will have been made is a corporation, partnership or limited liability company organized or existing under the laws of the United States, any state thereof, the District of Columbia, or any territory thereof (Holdings or such Person, as the case may be, being herein called the “Successor Company”);

(2) the Successor Company (if other than Holdings) expressly assumes all the obligations of Holdings under the indenture, the Security Documents and the Registration Rights Agreement pursuant to supplemental indentures;

(3) immediately after givingpro forma effect to such transaction (and treating any Indebtedness which becomes an obligation of the Successor Company, or any Restricted Subsidiary as a result of such transaction as having been Incurred by the Successor Company or such Restricted Subsidiary at the time of such transaction) no Default shall have occurred and be continuing;

(4) immediately after givingpro forma effect to such transaction, as if such transaction had occurred at the beginning of the applicable four-quarter period (and treating any Indebtedness which becomes an obligation of the Successor Company, or any Restricted Subsidiary as a result of such transaction as having been Incurred by the Successor Company, or such Restricted Subsidiary at the time of such transaction), either

(a) the Successor Company would be permitted to Incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”; or

(b) the Fixed Charge Coverage Ratio for the Successor Company and its Restricted Subsidiaries would be no less than such ratio for Holdings and its Restricted Subsidiaries immediately prior to such transaction;

(5) if Holdings is not the Successor Company, each Subsidiary Guarantor, unless it is the other party to the transactions described above, shall have by supplemental indenture confirmed that its Subsidiary Guarantee shall apply to such Person’s obligations under the indenture and the notes; and

(6) the Successor Company shall have delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that such consolidation, merger, amalgamation or transfer and such supplemental indentures (if any) comply with the indenture.

The Successor Company (if other than Holdings) will succeed to, and be substituted for, Holdings under the indenture and the notes, and in such event Holdings shall be automatically released and discharged from its

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obligations under the indenture and the notes. Notwithstanding the foregoing clauses (3) and (4) of this covenant, (a) Holdings or any Restricted Subsidiary may merge, consolidate or amalgamate with or transfer all or part of its properties and assets to Holdings or to a Restricted Subsidiary, and (b) Holdings may merge, consolidate or amalgamate with an Affiliate incorporated solely for the purpose of reincorporating Holdings in another state of the United States, the District of Columbia or any territory of the United States or may convert into a corporation, partnership or limited liability company, so long as the amount of Indebtedness of Holdings and its Restricted Subsidiaries is not increased thereby. This covenant will not apply to a sale, assignment, transfer, conveyance or other disposition of assets between or among Holdings and the Restricted Subsidiaries.

For purposes of this “Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets” only, the sale, assignment, transfer, lease, conveyance or other disposition of all or substantially all of the properties and assets of one or more Subsidiaries of Holdings, which properties and assets, if held by Holdings instead of such Subsidiaries, would constitute all or substantially all the properties and assets of Holdings on a consolidated basis, shall be deemed to be the transfer of all or substantially all the properties and assets of Holdings.

The indenture further provides that, subject to certain provisions in the indenture governing release of a Subsidiary Guarantee upon the sale, disposition, exchange or other transfer of a Restricted Subsidiary of Holdings that is a Subsidiary Guarantor, no Subsidiary Guarantor shall, and Holdings shall not permit any Subsidiary Guarantor to, consolidate, amalgamate or merge with or into or wind up into (whether or not such Subsidiary Guarantor is the surviving Person), or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets in one or more related transactions to, any Person unless:

(1) either (a) such Subsidiary Guarantor is the surviving Person or the Person formed by or surviving any such consolidation, amalgamation or merger (if other than such Subsidiary Guarantor) or to which such sale, assignment, transfer, lease, conveyance or other disposition shall have been made is a company, corporation, partnership or limited liability company (in the case of such Subsidiary Guarantor) or similar entity organized or existing under the laws of the United States, any state thereof, the District of Columbia, or any territory thereof, (such Subsidiary Guarantor or such Person, as the case may be, being herein called the “Successor Subsidiary Guarantor”) and the Successor Subsidiary Guarantor (if other than such Subsidiary Guarantor) expressly assumes all the obligations of such Subsidiary Guarantor under the indenture and the notes or the Subsidiary Guarantee, as applicable, pursuant to a supplemental indenture, or (b) such sale or disposition or consolidation, amalgamation or merger is not in violation of the covenant described above under the caption “—Certain Covenants—Asset Sales”; and

(2) the Successor Subsidiary Guarantor (if other than such Subsidiary Guarantor) shall have delivered or caused to be delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that such consolidation, amalgamation, merger or transfer and such supplemental indenture (if any) comply with the indenture.

Except as otherwise provided in the indenture, the Successor Subsidiary Guarantor (if other than such Subsidiary Guarantor) will succeed to, and be substituted for, such Subsidiary Guarantor under the indenture and the notes or the Subsidiary Guarantee, as applicable, and such Subsidiary Guarantor will automatically be released and discharged from its obligations under the indenture and its Subsidiary Guarantee. Notwithstanding the foregoing, (1) a Subsidiary Guarantor may merge, amalgamate or consolidate with an Affiliate incorporated solely for the purpose of reincorporating such Subsidiary Guarantor in another state of the United States, the District of Columbia or any territory of the United States or may convert into a limited liability company, corporation, partnership or similar entity organized or existing under the laws of another state of the United States, the District of Columbia or any territory of the United States so long as the amount of Indebtedness of such Subsidiary Guarantor is not increased thereby and (2) a Subsidiary Guarantor may merge, amalgamate or consolidate with an Issuer or another Subsidiary Guarantor.

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In addition, notwithstanding the foregoing, a Subsidiary Guarantor may consolidate, amalgamate or merge with or into or wind up into, liquidate, dissolve, or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets to an Issuer or any Subsidiary Guarantor.

Defaults

An “Event of Default” is defined in the indenture as:

(1) a default in any payment of interest (including any Additional Interest) on any note when the same becomes due and payable and such default continues for a period of 30 days;

(2) a default in the payment of principal or premium, if any, of any note when due at its Stated Maturity, upon optional redemption, upon required repurchase, upon declaration or otherwise;

(3) failure by Holdings for 60 days after receipt of written notice given by the Trustee or the holders of not less than 30% in aggregate principal amount of the notes then outstanding (with a copy to the Trustee) to comply with any of its obligations, covenants or agreements contained in the provisions of the indenture described in “Certain Covenants—Reports and Other Information”;

(4) the failure by Holdings or any of the Restricted Subsidiaries for 30 days after written notice given by the Trustee or the holders of not less than 30% in principal amount of the notes then outstanding (with a copy to the Trustee) to comply with its other obligations, covenants or agreements (other than a default referred to in clauses (1), (2) or (3) above or (10) below) contained in the notes, the indenture or the Security Documents;

(5) the failure by Holdings or any Significant Subsidiary (or any group of Subsidiaries that together would constitute a Significant Subsidiary) to pay any Indebtedness (other than Indebtedness owing to Holdings or a Restricted Subsidiary) within any applicable grace period after final maturity or the acceleration of any such Indebtedness by the holders thereof because of a default, in each case, if the total amount of such Indebtedness unpaid or accelerated exceeds $25.0 million or its foreign currency equivalent (the “cross acceleration provision”);

(6) certain events of bankruptcy, insolvency or reorganization of Holdings or a Significant Subsidiary (or any group of Subsidiaries that together would constitute a Significant Subsidiary) (the “bankruptcy provisions”);

(7) failure by Holdings or any Significant Subsidiary (or any group of Subsidiaries that together would constitute a Significant Subsidiary) to pay final judgments aggregating in excess of $25.0 million or its foreign currency equivalent (net of any amounts which are covered by enforceable insurance policies issued by solvent carriers), which judgments are not discharged, waived or stayed for a period of 60 days (the “judgment default provision”);

(8) the Subsidiary Guarantee of a Significant Subsidiary (or any group of Subsidiaries that together would constitute a Significant Subsidiary) with respect to the notes ceases to be in full force and effect (except as contemplated by the terms thereof) or an Issuer or any Subsidiary Guarantor that qualifies as a Significant Subsidiary (or any group of Subsidiaries that together would constitute a Significant Subsidiary) denies or disaffirms its obligations under the indenture or any Subsidiary Guarantee with respect to the notes and such Default continues for 10 days;

(9) unless such Liens have been released in accordance with the provisions of the indenture, the Security Documents or the Senior Lien Intercreditor Agreement, Liens in favor of the holders of the notes with respect to Collateral with a Fair Market Value in excess of $100.0 million cease to be valid or enforceable and such Default continues for 30 days, or an Issuer shall assert or any Subsidiary Guarantor shall assert, in any pleading in any court of competent jurisdiction, that any such security interest is invalid or unenforceable and, in the case of any Subsidiary Guarantor, Holdings fails to cause such Subsidiary Guarantor to rescind such assertions within 30 days after Holdings has actual knowledge of such assertions; or

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(10) there is a failure by Holdings to comply for 15 days after receipt of written notice given by the Trustee or the holders of not less than 30% in aggregate principal amount of the notes then outstanding (with a copy to the Trustee) with any of its obligations, covenants or agreements under the first paragraph described under “—Certain Covenants—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets.”

The foregoing will constitute Events of Default whatever the reason for any such Event of Default and whether it is voluntary or involuntary or is effected by operation of law or pursuant to any judgment, decree or order of any court or any order, rule or regulation of any administrative or governmental body.

However, a default under clause (3), (4) or (10) above will not constitute an Event of Default until the Trustee or the holders of 30% in principal amount of outstanding notes (with a copy to the Trustee) notify the Issuers of the Default and the Issuers do not cure such Default within the time specified in clause (3), (4) or (10) as applicable, after receipt of such notice.

If an Event of Default (other than a Default relating to certain events of bankruptcy, insolvency or reorganization of Holdings) occurs and is continuing, the Trustee or the holders of at least 30% in principal amount of outstanding notes (with a copy to the Trustee) by notice to the Issuers may declare the principal of, premium, if any, and accrued but unpaid interest on all the notes to be due and payable. Upon the Trustee’s or the holders’ of at least 30% in principal amount of outstanding notes notification to the Issuers of such a declaration, such principal and interest will be due and payable immediately. If an Event of Default relating to certain events of bankruptcy, insolvency or reorganization of the Issuers occurs, the principal of, premium, if any, and interest on all the notes shall ipso facto become and be immediately due and payable without any declaration or other act on the part of the Trustee or any holders. The holders of a majority in principal amount of outstanding notes by notice to the Trustee may rescind an acceleration and its consequences if the rescission would not conflict with any judgment or decree and if all existing Events of Default have been cured or waived except nonpayment of principal or interest that has become due solely because of acceleration. No such rescission shall affect any subsequent Default or impair any right consequent thereto.

In the event of any Event of Default specified in clause (5) of the first paragraph above, such Event of Default and all consequences thereof (excluding, however, any resulting payment default) will be annulled, waived and rescinded, automatically and without any action by the Trustee or the holders of the notes, if within 20 days after such Event of Default arose the Issuers deliver an Officers’ Certificate to the Trustee stating that (x) the Indebtedness or guarantee that is the basis for such Event of Default has been discharged or (y) the holders thereof have rescinded or waived the acceleration, notice or action (as the case may be) giving rise to such Event of Default or (z) the default that is the basis for such Event of Default has been cured, it being understood that in no event shall an acceleration of the principal amount of the notes as described above be annulled, waived or rescinded upon the happening of any such events.

If the notes are accelerated or otherwise become due prior to their maturity date, in each case, as a result of an Event of Default (including, but not limited to, upon the occurrence of a bankruptcy or insolvency event (including the acceleration of claims by operation of law)) on or after the first anniversary of the Issue Date, the amount of principal of, accrued and unpaid interest and premium on the notes that becomes due and payable shall equal the optional redemption price, plus accrued and unpaid interest to such date, applicable with respect to an optional redemption of the notes, in effect on the date of such acceleration as if such acceleration were an optional redemption of the notes accelerated. If the notes are accelerated or otherwise become due prior to their maturity date, in each case, as a result of an Event of Default (including, but not limited to, upon the occurrence of a bankruptcy or insolvency event (including the acceleration of claims by operation of law)) prior to the first anniversary of the Issue Date, the amount of principal of, accrued and unpaid interest and premium on the notes that becomes due and payable shall equal 100% of the principal amount of the notes prepaid plus the Applicable Premium in effect on the date of such acceleration, plus accrued and unpaid interest to such date, as if such acceleration were an optional redemption of the notes accelerated.

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In case an Event of Default occurs and is continuing, the Trustee will be under no obligation to exercise any of the rights or powers under the indenture or the Security Documents at the written request or direction of any of the holders unless such holders have offered to the Trustee indemnity or security satisfactory to it against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium (if any) or interest when due, no holder may pursue any remedy with respect to the indenture, the notes or the Security Documents unless:

(1) such holder has previously given the Trustee written notice that an Event of Default is continuing,

(2) holders of at least 30% in principal amount of the outstanding notes have requested in writing that the Trustee pursue the remedy,

(3) such holders have offered the Trustee security or indemnity satisfactory to it against any loss, liability or expense,

(4) the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity, and

(5) the holders of a majority in principal amount of the outstanding notes have not given the Trustee a direction inconsistent with such request within such60-day period.

Subject to certain restrictions, the holders of a majority in principal amount of outstanding notes are given the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any trust or power conferred on the Trustee. The Trustee, however, may refuse to follow any direction that conflicts with law or the indenture or that the Trustee determines is unduly prejudicial to the rights of any other holder (it being understood that the Trustee does not have an affirmative duty to ascertain whether or not such actions or forbearances are unduly prejudicial to such holder) or that would involve the Trustee in personal liability. Prior to taking any action under the indenture, the Trustee will be entitled to indemnification satisfactory to it in its sole discretion against all liabilities, losses and expenses caused by taking or not taking such action.

The indenture provides that if a Default occurs and is continuing and is actually known to a Trust Officer, the Trustee must mail, or deliver electronically if held by the Depository, to each holder of the notes notice of the Default within the later of 90 days after it occurs or 30 days after it is actually known to a Trust Officer or written notice of it is received by the Trustee at the Corporate Trust Office. Except in the case of a Default in the payment of principal of, premium (if any) or interest on any note, the Trustee may withhold notice if and so long as it in good faith determines that withholding notice is in the interests of the noteholders. In addition, Holdings is required to deliver to the Trustee, annually, a certificate indicating whether the signers thereof know of any Default that occurred during the previous year and whether such Default is continuing and, if so, proposed steps to cure such Default. Holdings also is required to deliver to the Trustee, within 30 days after the occurrence thereof, written notice of any event which would constitute certain Defaults, their status and what action Holdings is taking or proposes to take in respect thereof.

Amendments and Waivers

Subject to certain exceptions, the indenture, the notes, the Subsidiary Guarantees, the Security Documents, the Senior Lien Intercreditor Agreement and/or any Customary Intercreditor Agreements may be amended with the consent of the holders of at least a majority in principal amount of the notes then outstanding voting as a single class (including consents obtained in connection with a tender offer or exchange for the notes) and any past default or compliance with any provisions may be waived with the consent of the holders of at least a majority in principal amount of the notes then outstanding. However, without the consent of each holder of an outstanding note affected, no amendment may, among other things:

(1) reduce the amount of notes whose holders must consent to an amendment;

(2) reduce the rate of or extend the time for payment of interest on any note;

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(3) reduce the principal of or extend the Stated Maturity of any note;

(4) reduce the premium payable (if any) upon the redemption of any note or change the time at which any note may be redeemed as described under “—Optional Redemption” above;

(5) make any note payable in money other than that stated in such note;

(6) expressly subordinate the notes or any Subsidiary Guarantee to any other Indebtedness of an Issuer or any Subsidiary Guarantor;

(7) impair the contractual right of any holder to receive payment of principal of, premium, if any, and interest on such holder’s notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such holder’s notes;

(8) make any change in the amendment provisions which require each holder’s consent or in the waiver provisions; or

(9) make any change in the provisions dealing with the application of proceeds of Collateral in the Senior Lien Intercreditor Agreement, the Security Documents or the indenture that would adversely affect the holders of notes.

Except as expressly provided by the indenture or the Security Documents, without the consent of the holders of at least 66.67% in aggregate principal amount of the notes then outstanding, no amendment may modify or release the Subsidiary Guarantee of any Significant Subsidiary in any manner adverse to the holders of the notes. Without the consent of the holders of at least 66.67% in aggregate principal amount of the notes then outstanding, no amendment or waiver may release all or substantially all of the Collateral from the Lien of the Security Documents with respect to the notes.

Without the consent of any holder, the Issuers, the Trustee and the Collateral Agent may amend the indenture, the notes, the Subsidiary Guarantees, the Security Documents, the Senior Lien Intercreditor Agreement and/or a Customary Intercreditor Agreement to cure any ambiguity, omission, mistake, defect or inconsistency, to provide for the assumption by a Successor Company (with respect to an Issuer) of the obligations of an Issuer under the indenture, the notes, the Security Documents, the Senior Lien Intercreditor Agreement and a Customary Intercreditor Agreement, to provide for the assumption by a Successor Subsidiary Guarantor (with respect to any Subsidiary Guarantor), as the case may be, of the obligations of a Subsidiary Guarantor under the indenture, its Subsidiary Guarantee, the Security Documents, the Senior Lien Intercreditor Agreement and a Customary Intercreditor Agreement, to provide for uncertificated notes in addition to or in place of certificated notes (provided that the uncertificated notes are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated notes are described in Section 163(f)(2)(B) of the Code), to add a Subsidiary Guarantee or collateral with respect to the notes, to release Collateral or a Subsidiary Guarantee as permitted by the indenture, the Security Documents or, the Senior Lien Intercreditor Agreement, to add additional secured creditors holding First-Priority Lien Obligations, Other Second-Lien Obligations or Junior Lien Obligations so long as such obligations are not prohibited by the indenture, to add to the covenants of the Issuers or any Subsidiaries for the benefit of the holders or to surrender any right or power conferred upon the Issuers or any Subsidiary, to comply with any requirement of the SEC in connection with qualifying or maintaining the qualification of the indenture under the Trust Indenture Act of 1939 (the “TIA”), to make any change that does not adversely affect the rights of any holder, to make certain changes to the indenture to provide for the issuance of additional notes or Exchange Notes, which shall have terms substantially identical in all material respects to the Initial Notes, and which shall be treated, together with any outstanding Initial Notes, as a single issue of Securities, or to effect any provision of the indenture.

The Senior Lien Intercreditor Agreement or any Customary Intercreditor Agreement may be amended without the consent of any holder of notes, the Trustee or the Collateral Agent in connection with the permitted entry into the Senior Lien Intercreditor Agreement of any class of additional secured creditors holding Other Second-Lien Obligations, First-Priority Lien Obligations or Junior Lien Obligations to effectuate such entry into

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the Senior Lien Intercreditor Agreement or any Customary Intercreditor Agreement and to make the lien of such class equal and ratable with, as applicable, the lien of the First-Priority Lien Obligations, the Other Second-Lien Obligations or Junior Lien Obligations, in each case, to the extent such First-Priority Lien Obligations, Other Second-Lien Obligations or Junior Lien Obligations are expressly permitted to be incurred pursuant to the indenture.

The consent of the noteholders is not necessary under the indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment.

No Personal Liability of Directors, Officers, Employees, Managers and Stockholders

No director, officer, employee, manager, incorporator or holder of any Equity Interests in Holdings or of any Subsidiary Guarantor or any direct or indirect parent companies, as such, will have any liability for any obligations of Holdings or any Subsidiary Guarantor under the notes, the indenture or the Subsidiary Guarantees, as applicable, or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.

Transfer and Exchange

A noteholder may transfer or Exchange Notes in accordance with the indenture. Upon any transfer or exchange, the registrar and the Trustee may require a noteholder, among other things, to furnish appropriate endorsements and transfer documents and the Issuers may require a noteholder to pay any taxes required by law or permitted by the indenture. The Issuers are not required to transfer or exchange any notes selected for redemption or to transfer or exchange any notes for a period of 15 days prior to a selection of notes to be redeemed or between a record date and the related interest payment date. The notes will be issued in registered form and the registered holder of a note will be treated as the owner of such note for all purposes.

Satisfaction and Discharge

The indenture will be discharged and will cease to be offurther effect (except as to surviving rights, indemnities and immunities of the Trustee and rights of registration or transfer or exchange of notes, as expresslyprovided for in the indenture) as to all outstanding notes when:

(1) either (a) all the notes theretofore authenticated and delivered (except lost, stolen or destroyed notes which have been replaced or paid and notes for whose payment money has theretofore been deposited in trust or segregated and held in trust by the Issuers and thereafter repaid to the Issuers or discharged from such trust) have been delivered to the Trustee for cancellation or (b) all of the notes (i) have become due and payable, (ii) will become due and payable at their Stated Maturity within one year or (iii) if redeemable at the option of the Issuers, are to be called for redemption within one year under arrangements satisfactory to the Trustee for the giving of notice of redemption by the Trustee in the name, and at the expense, of the Issuers, and the Issuers have irrevocably deposited or caused to be deposited with the Trustee funds in U.S. dollars in an amount sufficient to pay and discharge the entire Indebtedness on the notes not theretofore delivered to the Trustee for cancellation, for principal of, premium, if any, and interest on the notes to the date of deposit (in the case of notes that have become due and payable) or to the date of maturity or redemption, as applicable, together with irrevocable written instructions from the Issuers directing the Trustee to apply such funds to the payment thereof at maturity or redemption, as the case may be;provided that upon any redemption that requires the payment of the Applicable Premium, the amount deposited shall be sufficient for purposes of the indenture to the extent that an amount is deposited with the Trustee equal to the Applicable Premium calculated as of the date of the notice of redemption, with any deficit as of the date of the redemption only required to be deposited with the Trustee on or prior to the date of the redemption;

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(2) the Issuers and/or the Subsidiary Guarantors have paid all other sums payable under the indenture; and

(3) the Issuers have delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel stating that all conditions precedent under the indenture relating to the satisfaction and discharge of the indenture have been complied with.

Defeasance

Subject to the survival of certain terms and subject to certain conditions to defeasance, the Issuers at any time may terminate all of their obligations under the notes and the indenture with respect to the holders of the notes (“legal defeasance”), except for certain obligations, including those respecting the defeasance trust and obligations to register the transfer or exchange of the notes, to replace mutilated, destroyed, lost or stolen notes and to maintain a registrar and paying agent in respect of the notes and the rights, indemnities and immunities of the Trustee. The Issuers at any time may terminate their obligations under the covenants described under “—Certain Covenants” for the benefit of the holders of the notes, the operation of the cross acceleration provision, the bankruptcy provisions with respect to Significant Subsidiaries, the judgment default provision described under “—Defaults” (but only to the extent that those provisions relate to the Defaults with respect to the notes) and the undertakings and covenants contained under “—Change of Control” and “—Certain Covenants—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets” (“covenantdefeasance”) for the benefit of the holders of the notes. If the Issuers exercise their legal defeasance option or their covenant defeasance option, each Subsidiary Guarantor will be released from all of its obligations with respect to its Subsidiary Guarantee and the Security Documents.

The Issuers may exercise their legal defeasance option notwithstanding its prior exercise of the covenant defeasance option. If the Issuers exercise their legal defeasance option, payment of the notes so defeased may not be accelerated because of an Event of Default with respect thereto. If the Issuers exercise their covenant defeasance option, payment of the notes so defeased may not be accelerated because of an Event of Default specified in clause (3), (4), (5), (6) (with respect only to Significant Subsidiaries), (7), (8), (9) or (10) under “—Defaults” or because of the failure of Holdings to comply with clause (4) under “—Certain Covenants—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets.”

In order to exercise their defeasance option, the Issuers must irrevocably deposit in trust (the “defeasance trust”) with the Trustee money or U.S. Government Obligations for the payment of principal, premium (if any) and interest on the notes to redemption or maturity, as the case may be, and must comply with certain other conditions, including delivery to the Trustee of an Opinion of Counsel to the effect that holders of the notes will not recognize income, gain or loss for U.S. federal income tax purposes as a result of such deposit and defeasance and will be subject to U.S. federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred (and, in the case of legal defeasance only, such Opinion of Counsel must be based on a ruling of the Internal Revenue Service or change in applicable U.S. federal income tax law);provided that upon any redemption that requires the payment of the Applicable Premium, the amount deposited shall be sufficient for purposes of the indenture to the extent that an amount is deposited with the Trustee equal to the Applicable Premium calculated as of the date of the notice of redemption, with any deficit as of the date of the redemption only required to be deposited with the Trustee on or prior to the date of the redemption. Notwithstanding the foregoing, the Opinion of Counsel required by the immediately preceding sentence with respect to a legal defeasance need not be delivered if all of the notes not theretofore delivered to the Trustee for cancellation (x) have become due and payable or (y) will become due and payable at their Stated Maturity within one year under arrangements satisfactory to the Trustee for the giving of notice of redemption by the Trustee in the name, and at the expense, of the Issuers.

Concerning the Trustee

Wilmington Trust, National Association is the Trustee and Collateral Agent under the indenture and has been appointed by the Issuers as registrar and a paying agent with regard to the notes.

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Governing Law

The indenture provides that it and the notes will be governed by, and construed in accordance with, the laws of the State of New York.

Certain Definitions

“Acquired Indebtedness” means, with respect to any specified Person:

(1) Indebtedness of any other Person existing at the time such other Person is merged, consolidated or amalgamated with or into or became a Restricted Subsidiary of such specified Person, and

(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

Acquired Indebtedness will be deemed to have been Incurred, with respect to clause (1) of the preceding sentence, on the date such Person becomes a Restricted Subsidiary and, with respect to clause (2) of the preceding sentence, on the date of consummation of such acquisition of such assets.

“Additional Assets” means:

(1) any properties or assets used or useful in the Oil and Gas Business;

(2) capital expenditures by Holdings or a Restricted Subsidiary in the Oil and Gas Business;

(3) the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by Holdings or another Restricted Subsidiary; or

(4) Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary;

provided,however, that, in the case of clauses (3) and (4), such Restricted Subsidiary is primarily engaged in the Oil and Gas Business.

“Additional Refinancing Amount” means, in connection with the Incurrence of any Indebtedness, Disqualified Stock or Preferred Stock Incurred to refund, refinance or defease any existing Indebtedness, Disqualified Stock or Preferred Stock, the aggregate principal amount of additional Indebtedness, Disqualified Stock or Preferred Stock Incurred to pay interest, premiums or defeasance costs, in each case in an amount equal to the amount required by the instruments governing such existing Indebtedness (whether such existing Indebtedness is redeemed pursuant to a tender offer, optional redemption or otherwise), and fees and expenses Incurred in connection therewith.

“Adjusted Consolidated Net Tangible Assets” means (without duplication), as of the date of determination, the remainder of:

(a) the sum of:

(i) estimated discounted future net revenues from proved oil and gas reserves of Holdings and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any provincial, territorial, state, federal or foreign income taxes, as estimated by Holdings in a reserve report prepared as of the end of Holdings’ most recently completed fiscal year for which audited financial statements are available, as increased by, as of the date of determination, the estimated discounted future net revenues from (A) estimated proved oil and gas reserves acquired since such year end, which reserves were not reflected in such year end reserve report, and (B) estimated oil and gas reserves attributable to upward revisions of estimates of proved oil and gas reserves (including the impact to discounted future net revenues related to development costs previously estimated in the last year end reserve report, but only to the extent such costs were actually incurred since the date of the last year end reserve report) since such year end due to exploration, development, exploitation or other activities, increased by the

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accretion of discount from the date of the last year end reserve report to the date of determination and decreased by, as of the date of determination, the estimated discounted future net revenues from (C) estimated proved oil and gas reserves included in the last year end reserve report that shall have been produced or disposed of since such year end, and (D) estimated oil and gas reserves included therein that are subsequently removed from the proved oil and gas reserves of Holdings and its Restricted Subsidiaries as so calculated due to downward revisions of estimates of proved oil and gas reserves since such year end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, provided, that (x) in the case of such year end reserve report and any adjustments since such year end pursuant to clauses (A), (B) and (D), the estimated discounted future net revenues from proved oil and gas reserves shall be determined in their entirety using oil, gas and other hydrocarbon prices and costs that are either (1) calculated in accordance with SEC guidelines and, with respect to such adjustments under clauses (A), (B) or (D), calculated with such prices and costs as if the end of the most recent fiscal quarter preceding the date of determination for which such information is available to Holdings were year end or (2) if Holdings so elects at any time, calculated in accordance with the foregoing clause (1), except that when pricing of future net revenues of proved oil and gas reserves under SEC guidelines is not based on a contract price and is instead based upon benchmark, market or posted pricing, the pricing for each month of estimated future production from such proved oil and gas reserves not subject to contract pricing shall be based upon NYMEX (or successor) published forward prices for the most comparable hydrocarbon commodity applicable to such production month (adjusted for energy content, quality and basis differentials, with such basis differentials determined as provided in the definition of “Borrowing Base” and giving application to the last sentence of such definition hereto), as such forward prices are published as of the year end date of such reserve report or, with respect to post-year end adjustments under clauses (A), (B) or (D), the last day of the most recent fiscal quarter preceding the date of determination, (y) the pricing of estimated proved reserves that have been produced or disposed since year end as set forth in clause (D) shall be based upon the applicable pricing elected for the prior year end reserve report as provided in clause (x), and (z) in each of cases (A), (B), (C) and (D) as estimated by Holdings’ petroleum engineers or any independent petroleum engineers engaged by Holdings for that purpose;

(ii) the capitalized costs that are attributable to Oil and Gas Properties of Holdings and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on Holdings’ books and records as of a date no earlier than the date of Holdings’ latest annual or quarterly consolidated financial statements;

(iii) the Net Working Capital on a date no earlier than the date of Holdings’ latest annual or quarterly consolidated financial statements;

(iv) assets related to commodity risk management activities less liabilities related to commodity risk management activities, in each case to the extent that such assets and liabilities arise in the ordinary course of the Oil and Gas Business; and

(v) the greater of (A) the net book value of other tangible assets (including, without limitation, investments in unconsolidated Restricted Subsidiaries and mineral rights held under lease or other contractual arrangement) of Holdings and its Restricted Subsidiaries, as of a date no earlier than the date of Holdings’ latest annual or quarterly consolidated financial statements, and (B) the appraised value, as estimated by independent appraisers within the immediately preceding 12 months, of other tangible assets (including, without limitation, investments in unconsolidated Restricted Subsidiaries and mineral rights held under lease or other contractual arrangement) of Holdings and its Restricted Subsidiaries, as of a date no earlier than the date of Holdings’ latest audited consolidated financial statements (it being understood that Holdings shall not be required to obtain any appraisal of any assets); minus

(b) the sum of:

(i) any amount included in clauses (a)(i) through (a)(v) above that is attributable to minority interests;

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(ii) any net gas balancing liabilities of Holdings and its Restricted Subsidiaries reflected in Holdings’ latest audited consolidated financial statements;

(iii) to the extent included in clause (a)(i) above, the estimated discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices and costs as provided in clause (a)(i)), attributable to reserves which are required to be delivered to third parties to fully satisfy the obligations of Holdings and its Restricted Subsidiaries with respect to Volumetric Production Payments (determined, if applicable, using the schedules specified with respect thereto); and

(iv) to the extent included in clause (a)(i) above, the estimated discounted future net revenues, calculated in accordance with SEC guidelines (utilizing prices and costs as provided in clause (a)(i)), attributable to reserves subject to Dollar Denominated Production Payments which, based on the estimates of production and price assumptions included in determining the estimated discounted future net revenues specified in clause (a)(i) above, would be necessary to fully satisfy the payment obligations of Holdings and its Restricted Subsidiaries with respect to Dollar Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

If Holdings changes its method of accounting from the full cost method of accounting to the successful efforts or a similar method, “Adjusted Consolidated Net Tangible Assets” will continue to be calculated as if Holdings were still using the full cost method of accounting.

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control” (including, with correlative meanings, the terms “controlling,” “controlled by” and “under common control with”), as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise.

“Aggregate Special Cap” means an amount equivalent to 20% of EBITDA for the applicable four quarter period, prior to giving effect to the exclusions,add-backs and operating expense reductions and other operating improvements or synergies that are subject to the Aggregate Special Cap.

“All-in Yield” means the yield payable to all lenders providing the applicable Indebtedness in the primary syndication thereof, whether in the form of interest rate, premiums, margin, original issue discount,up-front fees, rate floors or otherwise;provided, that original issue discount andup-front fees shall be equated to interest rate assuming a4-year life to maturity (or, if less, the remaining life of such loans); and,provided, further, that“All-in Yield” shall not include arrangement, commitment, underwriting, structuring or similar fees paid to arrangers for such loans (not to exceed 2.00%) or customary consent fees for an amendment paid generally to consenting lenders, default rate of 2.00%, customary administrative agency and collateral agency fees, changes in the underlying LIBOR rate (or similar rate) or base rate not caused by any amendment, supplement, modification, or replacement to such Indebtedness, and customary letter of credit issuance fees.

“Applicable Premium” means the excess of (A) the present value of all remaining required interest payments through the first anniversary of the Issue Date (excluding accrued and unpaid interest), plus the present value of the redemption price of the notes being redeemed set forth in Paragraph 5 of the note, assuming a redemption date of the first anniversary of the Issue Date, in each case computed by the Issuers using a discount rate equal to the Treasury Rate plus 50 basis pointsover (B) the then outstanding principal amount of the notes being redeemed. For purposes of this definition, “Treasury Rate” means the rate per annum equal to the yield to maturity at the time of computation of the United States Treasury securities with a constant maturity as compiled and published in the most recent Federal Reserve Statistical ReleaseH-15 (519) that has become publicly available at least two (2) Business Days prior to such time (or, if such Statistical Release is no longer published, any publicly available source of similar market data) most nearly equal to the period from such date of prepayment to the first anniversary of the Issue Date;provided,however, that if the period from such date of

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prepayment to the first anniversary of the Issue Date is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearestone-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given.

“Approved Petroleum Engineers” shall mean (a) Netherland, Sewell & Associates, Inc., (b) Ryder Scott Company, L.P., (c) W. D. Van Gonten & Co. Petroleum Engineering, (d) DeGolyer and MacNaughton, (e) Cawley, Gillespie & Associates, Inc., (f) Miller and Lents, Ltd. and (g) at the Issuers’ option, any other independent petroleum engineers selected by the Issuers and reasonably acceptable to the administrative agent under the Credit Agreement governing Indebtedness incurred under clause (a) of the second paragraph under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock.”

“Asset Sale” means:

(1) the sale, conveyance, transfer or other disposition (whether in a single transaction or a series of related transactions) of property or assets (including by way of Production Payments and Reserve Sales and Sale/ Leaseback Transactions) (other than an operating lease entered into in the ordinary course of the Oil and Gas Business) (each referred to in this definition as a “disposition”); or

(2) the issuance or sale of Equity Interests (other than directors’ qualifying shares and shares issued to foreign nationals or other third parties to the extent required by applicable law) of any Restricted Subsidiary (other than to Holdings or another Restricted Subsidiary) (whether in a single transaction or a series of related transactions),

in each case other than:

(a) a disposition of cash, Cash Equivalents or Investment Grade Securities or obsolete, damaged or worn out property or equipment in the ordinary course of business;

(b) the disposition of all or substantially all of the assets of Holdings in a manner permitted pursuant to the provisions described under “—Certain Covenants—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets” or any disposition that constitutes a Change of Control;

(c) any Restricted Payment or Permitted Investment that is permitted to be made, and is made, under the covenant described under “—Certain Covenants—Limitation on Restricted Payments”;

(d) any disposition of assets of Holdings or any Restricted Subsidiary or issuance or sale of Equity Interests of Holdings or any Restricted Subsidiary, which assets or Equity Interests so disposed or issued have an aggregate Fair Market Value (as determined in good faith by Holdings) of less than $15.0 million,provided that dispositions pursuant to this clause (d) shall not exceed $20.0 million in any 12 month consecutive period;

(e) any disposition of property or assets, or the issuance of securities, by a Restricted Subsidiary to Holdings or by Holdings or a Restricted Subsidiary to a Restricted Subsidiary;

(f) [reserved];

(g) foreclosure or any similar action with respect to any property or other asset of Holdings or any of the Restricted Subsidiaries;

(h) [reserved];

(i) the lease, assignment or sublease of, or any transfer related to a “reverse build to suit” or similar transaction in respect of, any real or personal property in the ordinary course of business;

(j) the disposition of (i) inventory and other goods held for sale, including Hydrocarbons and other mineral products in the ordinary course of business, (ii) obsolete, worn out, used or surplus equipment,

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vehicles and other assets (other than accounts receivable) in the ordinary course of business (including any asset (other than Oil and Gas Properties) that is no longer necessary, used or useful for the business of Holdings or its Restricted Subsidiaries or is replaced by equipment of at least comparable value and use), and (iii) dispositions to landlords of improvements made to leased real property pursuant to customary terms of leases entered into in the ordinary course of business;

(k) any grant in the ordinary course of business of any license of patents, trademarks,know-how or any other intellectual property;

(l) in the ordinary course of business, any swap of assets, or lease, assignment or sublease of any real or personal property, in exchange for services (including in connection with any outsourcing arrangements) of comparable or greater value or usefulness to the business of Holdings and the Restricted Subsidiaries as a whole, as determined in good faith by Holdings;

(m) [reserved];

(n) any financing transaction with respect to property built or acquired by Holdings or any Restricted Subsidiary after the Issue Date, including any Sale/Leaseback Transaction or asset securitization permitted by the indenture;

(o) dispositions in connection with Permitted Liens;

(p) any disposition of Capital Stock of a Restricted Subsidiary pursuant to an agreement or other obligation with or to a Person (other than Holdings or a Restricted Subsidiary) from whom such Restricted Subsidiary was acquired or from whom such Restricted Subsidiary acquired its business and assets (having been newly formed in connection with such acquisition), made as part of such acquisition and in each case comprising all or a portion of the consideration in respect of such sale or acquisition;

(q) the sale of any property in a Sale/Leaseback Transaction within twelve months of the acquisition of such property;

(r) dispositions of receivables in connection with the compromise, settlement or collection thereof in the ordinary course of business or in bankruptcy or similar proceedings and exclusive of factoring or similar arrangements;

(s) any surrender, expiration or waiver of contract rights or oil and gas leases or the settlement, release, recovery on or surrender of contract, tort or other claims of any kind;

(t) [reserved];

(u) any Production Payments and Reserve Sales;provided that any such Production Payments and Reserve Sales, other than incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to an Issuer or a Restricted Subsidiary, shall have been created, incurred, issued, assumed or guaranteed in connection with the financing of, and within 60 days after the acquisition of, the property that is subject thereto;

(v) the abandonment,farm-out pursuant to aFarm-Out Agreement, lease or sublease of developed or underdeveloped Oil and Gas Properties owned or held by an Issuer or any Restricted Subsidiary in the ordinary course of business and which are usual and customary in the Oil and Gas Business generally or in the geographic region in which such activities occur; and

(w) a disposition (whether or not in the ordinary course of business) of any Oil and Gas Property or interest therein to which no proved or probable reserves are attributable at the time of such disposition.

provided that, notwithstanding anything above to the contrary, no Production Payment and Reserve Sale shall be deemed to not constitute an Asset Sale pursuant to clauses (a) through (w) above, other than pursuant to clauses (d) and (u) above.

“Authorized Officer” means as to any Person, the Chairman of the Board of Directors, the President, the Chief Executive Officer, the Chief Financial Officer, the Chief Operating Officer, any Executive Vice President,

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Senior Vice President or Vice President, the Treasurer, the Assistant or Vice Treasurer, the Vice President-Finance, the General Counsel, the Secretary, the Assistant Secretary and any manager, managing member or general partner, in each case, of such Person, and any other senior officer designated as such in writing to the Trustee by such Person. Any document delivered under the indenture that is signed by an Authorized Officer shall be conclusively presumed to have been authorized by all necessary corporate, limited liability company, partnership and/or other action on the part of an Issuer or any Subsidiary Guarantor and such Authorized Officer shall be conclusively presumed to have acted on behalf of such Person.

“Bank Indebtedness” means any and all amounts payable under or in respect of (a) the Credit Agreement and the other Credit Agreement Documents, as amended, restated, supplemented, waived, replaced (whether or not upon termination, and whether with the original lenders or otherwise), repaid, refunded, refinanced or otherwise modified from time to time (including after termination of the Credit Agreement), including any agreement extending the maturity thereof, refinancing or replacing all or any portion of the Indebtedness under such agreement or agreements or any successor or replacement agreement or agreements or increasing the amount loaned or issued thereunder or altering the maturity thereof, including principal, premium (if any), interest (including interest accruing on or after the filing of any petition in bankruptcy or for reorganization relating to Holdings whether or not a claim for post-filing interest is allowed in such proceedings), fees, charges, expenses, reimbursement obligations, guarantees and all other amounts payable thereunder or in respect thereof and (b) whether or not the Indebtedness referred to in clause (a) remains outstanding, if designated by Holdings to be included in this definition, one or more (A) debt facilities or commercial paper facilities, providing for revolving credit loans, term loans, reserve based loans, or letters of credit, (B) debt securities, indentures or other forms of debt financing (including convertible or exchangeable debt instruments or bank guarantees or bankers’ acceptances), or (C) instruments or agreements evidencing any other Indebtedness, in each case, with the same or different borrowers or issuers and, in each case, as amended, supplemented, modified, extended, restructured, renewed, refinanced, restated, replaced or refunded in whole or in part from time to time.

“Bankruptcy Code” means Title 11 of the United States Code.

“Bankruptcy Law” means the Bankruptcy Code or any similar federal, state or foreign bankruptcy, insolvency or receivership law for the relief of debtors.

“Board of Directors” means, as to any Person, the board of directors or managers, as applicable, of such Person (or, if such Person is a partnership, the board of directors or other governing body of the general partner of such Person) or any duly authorized committee thereof. In the case of Holdings, the Board of Directors of Holdings shall be deemed to include the Board of Directors of Holdings or any direct or indirect parent of Holdings, as appropriate.

“Borrowing Base” means, at any date of determination, an amount equal to the amount of (a) 65% of the net present value discounted at 9% of proved developed producing (PDP) reserves, plus (b) 35% of the net present value discounted at 9% of proved developednon-producing (PDNP) reserves, plus (c) 25% of the net present value discounted at 9% of proven undeveloped (PUD) reserves, plus or minus (d) 65% of the net present value discounted at 9% of the future receipts expected to be paid to or by Holdings and its Restricted Subsidiaries under commodity hedging agreements (other than basis differential commodity hedging agreements), netted against the price described below, plus or minus (e) 65% of the net present value discounted at 9% of the future receipts expected to be paid to or by Holdings and its Restricted Subsidiaries under basis differential commodity hedging agreements, in each case for Holdings and its Restricted Subsidiaries, and (i) for purposes of clauses (a) through (d) above, as estimated by Holdings in a reserve report prepared by Holdings’ petroleum engineers applying the relevant NYMEX (or successor) published forward prices for the most comparable hydrocarbon commodity adjusted for relevant energy content, quality and basis differentials (before any state or federal or other income tax) and (ii) for purposes of clauses (d) and (e) above, as estimated by Holdings applying, if available, the relevant NYMEX (or successor) published forward basis differential or, if such NYMEX (or successor) forward basis differential is unavailable, in good faith based on historical basis differential (before any state or federal or other income tax). For

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any months beyond the term included in published NYMEX (or successor) forward pricing, the price used will be equal to the last published contract escalated at 1.5% per annum.

“Business Day” means a day other than a Saturday, Sunday or other day on which banking institutions are authorized or required by law to close in New York City.

“Calculation Date” shall have the meaning set forth in the definition of “Fixed Charge Coverage Ratio.”

“Capital Stock” means:

(1) in the case of a corporation, corporate stock or shares;

(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

(3) in the case of a partnership or limited liability company, partnership or membership interests (whether general or limited); and

(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person.

“Capitalized Lease Obligation” means, at the time any determination thereof is to be made, the amount of the liability in respect of a capital lease that would at such time be required to be capitalized and reflected as a liability on a balance sheet (excluding the footnotes thereto) in accordance with GAAP;provided that any obligations of Holdings or its Restricted Subsidiaries, or of a special purpose or other entity not consolidated with Holdings and its Restricted Subsidiaries, either existing on the Issue Date or created prior to any recharacterization described below (or any refinancings thereof) (i) that were not included on the consolidated balance sheet of Holdings as capital lease obligations and (ii) that are subsequently recharacterized as capital lease obligations or, in the case of such a special purpose or other entity becoming consolidated with Holdings and its Restricted Subsidiaries, due to a change in accounting treatment or otherwise, shall for all purposes not be treated as Capitalized Lease Obligations or Indebtedness.

“Capitalized Software Expenditures” shall mean, for any period, the aggregate of all expenditures (whether paid in cash or accrued as liabilities) by a Person and its Restricted Subsidiaries during such period in respect of licensed or purchased software or internally developed software and software enhancements that, in conformity with GAAP, are or are required to be reflected as capitalized costs on the consolidated balance sheet of such Person and such Restricted Subsidiaries.

“Cash Equivalents” means:

(1) U.S. dollars, pounds sterling, euros, the national currency of any member state in the European Union or such local currencies held by an entity from time to time in the ordinary course of business;

(2) securities issued or directly and fully guaranteed or insured by the U.S. government or any country that is a member of the European Union or any agency or instrumentality thereof in each case maturing not more than two years from the date of acquisition;

(3) certificates of deposit, time deposits and eurodollar time deposits with maturities of one year or less from the date of acquisition, bankers’ acceptances, in each case with maturities not exceeding one year and overnight bank deposits, in each case with any commercial bank having capital and surplus in excess of $250.0 million and whose long-term debt is rated “A” or the equivalent thereof by Moody’s or S&P (or reasonably equivalent ratings of another internationally recognized ratings agency);

(4) repurchase obligations for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above;

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(5) commercial paper issued by a corporation (other than an Affiliate of Holdings) rated at least“A-1” or the equivalent thereof by Moody’s or S&P (or reasonably equivalent ratings of another internationally recognized ratings agency) and in each case maturing within one year after the date of acquisition;

(6) readily marketable direct obligations issued by any state of the United States of America or any political subdivision thereof having one of the two highest rating categories obtainable from either Moody’s or S&P (or reasonably equivalent ratings of another internationally recognized ratings agency) in each case with maturities not exceeding two years from the date of acquisition;

(7) Indebtedness issued by Persons (other than the Significant Issue Date Equityholders or any of their Affiliates) with a rating of “A” or higher from S&P or“A-2” or higher from Moody’s (or reasonably equivalent ratings of another internationally recognized ratings agency) in each case with maturities not exceeding two years from the date of acquisition; and

(8) investment funds investing at least 95% of their assets in securities of the types described in clauses (1) through (7) above.

“CFC” means a “controlled foreign corporation” within the meaning of Section 957 of the Code.

“Change of Control” means the occurrence of either of the following:

(1) the sale, lease or transfer, in one or a series of related transactions, of all or substantially all the assets of Holdings and its Subsidiaries, taken as a whole, to a Person other than any of the Permitted Holders; or

(2) Holdings becomes aware (by way of a report or any other filing pursuant to Section 13(d) of the Exchange Act, proxy, vote, written notice or otherwise) of the acquisition by any Person or group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, or any successor provision), including any group acting for the purpose of acquiring, holding or disposing of securities (within the meaning of Rule13d-5(b)(1) under the Exchange Act), other than any of the Permitted Holders, in a single transaction or in a related series of transactions, by way of merger, consolidation, amalgamation or other business combination or purchase of beneficial ownership (within the meaning of Rule13d-3 under the Exchange Act, or any successor provision), of more than 50% of the total voting power of the Voting Stock of Holdings.

“Code” means the Internal Revenue Code of 1986, as amended.

“Co-Investors” shall mean the Significant Issue Date Equityholders, excluding in each case any of their respective operating portfolio companies.

“Collateral” means all property subject or purported to be subject, from time to time, to a Lien under any Security Documents.

“Collateral Agent” means Wilmington Trust, National Association, acting in its capacity as “Collateral Agent” under the indenture and under the Security Documents and any successor thereto in such capacity.

“Collateral Agreement” means the Collateral Agreement (Second Lien) among the Issuers, each Subsidiary Guarantor and the Collateral Agent, entered into on the Issue Date, as may be amended, restated, supplemented or otherwise modified from time to time in accordance with its terms and in accordance with the indenture.

“Collateral Coverage Minimum” means that the Mortgaged Properties shall represent at least 90% of thePV-10 of the Issuers’ and the Subsidiary Guarantors’ total Proved Reserves and at least 90% of thePV-10 of the Issuers’ and the Subsidiary Guarantors’ total Proved Developed Producing Reserves, in each case, included in the most recent Reserve Report prepared as of each June 30th and December 31st of each fiscal year.

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“Consolidated Depreciation, Depletion and Amortization Expense” means, with respect to any Person for any period, the total amount of depreciation, depletion and amortization expense, including accretion on asset retirement obligations in accordance with ASC 410 Asset Retirement and Environmental Obligations, the amortization of intangible assets, deferred financing fees and Capitalized Software Expenditures and amortization of unrecognized prior service costs and actuarial gains and losses related to pensions and other post-employment benefits, of such Person and its Restricted Subsidiaries for such period on a consolidated basis and otherwise determined in accordance with GAAP.

“Consolidated Interest Expense” means, with respect to any Person for any period, the sum, without duplication, of:

(1) consolidated interest expense of such Person and its Restricted Subsidiaries for such period, to the extent such expense was deducted in computing Consolidated Net Income (including amortization of original issue discount, the interest component of Capitalized Lease Obligations, and net payments and receipts (if any) pursuant to interest rate Hedging Obligations and excluding amortization of deferred financing fees, any interest attributable to Dollar Denominated Production Payments, debt issuance costs, commissions, fees and expenses, expensing of any bridge, commitment or other financing fees andnon-cash interest expense attributable to movement in mark to market valuation of Hedging Obligations or other derivatives (in each case permitted hereunder) under GAAP);plus

(2) consolidated capitalized interest of such Person and its Restricted Subsidiaries for such period, whether paid or accrued;plus

(3) [reserved];minus

(4) interest income for such period.

For purposes of this definition, interest on a Capitalized Lease Obligation shall be deemed to accrue at an interest rate reasonably determined by Holdings to be the rate of interest implicit in such Capitalized Lease Obligation in accordance with GAAP.

“Consolidated Leverage Ratio” means, as of any date of determination, the ratio of (a) Consolidated Total Indebtedness as of the last day of the then applicable Test Period to (b) EBITDA for such Test Period. In the event that Holdings or any of its Restricted Subsidiaries Incurs, repays, repurchases or redeems any Indebtedness or issues, repurchases or redeems Disqualified Stock or Preferred Stock subsequent to the commencement of the period for which the Consolidated Leverage Ratio is being calculated but prior to the event for which the calculation of the Consolidated Leverage Ratio is made (the “Leverage Ratio Calculation Date”), then the Consolidated Leverage Ratio shall be calculated giving pro forma effect to such Incurrence, repayment, repurchase or redemption of Indebtedness, or such issuance, repurchase or redemption of Disqualified Stock or Preferred Stock, as if the same had occurred at the beginning of the applicable four-quarter period;provided that Holdings may elect pursuant to an Officers’ Certificate delivered to the Trustee to treat all or any portion of the commitment under any Indebtedness as being Incurred at such time, in which case any subsequent Incurrence of Indebtedness under such commitment shall not be deemed, for purposes of this calculation, to be an Incurrence at such subsequent time.

For purposes of making the computation referred to above, Investments, acquisitions, dispositions, mergers, amalgamations, consolidations and discontinued operations (as determined in accordance with GAAP), in each case with respect to an operating unit of a business, and any operational changes that Holdings or any Restricted Subsidiary has determined to make and/or made during the four-quarter reference period or subsequent to such reference period and on or prior to or simultaneously with the Leverage Ratio Calculation Date shall be calculated on a pro forma basis assuming that all such Investments, acquisitions, dispositions, mergers, amalgamations, consolidations, discontinued operations and other operational changes (and the change in EBITDA resulting therefrom) had occurred on the first day of the four-quarter reference period. If since the beginning of such period any Person that subsequently became a Restricted Subsidiary or was merged with or

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into Holdings or any Restricted Subsidiary since the beginning of such period shall have made any Investment, acquisition, disposition, merger, consolidation, amalgamation, discontinued operation or operational change, in each case with respect to an operating unit of a business, that would have required adjustment pursuant to this definition, then the Consolidated Leverage Ratio shall be calculated giving pro forma effect thereto for such period as if such Investment, acquisition, disposition, discontinued operation, merger, amalgamation, consolidation or operational change had occurred at the beginning of the applicable four-quarter period. If since the beginning of such period any Restricted Subsidiary is designated an Unrestricted Subsidiary or any Unrestricted Subsidiary is designated a Restricted Subsidiary, then the Consolidated Leverage Ratio shall be calculated giving pro forma effect thereto for such period as if such designation had occurred at the beginning of the applicable four-quarter period.

For purposes of this definition, whenever pro forma effect is to be given to any event, the pro forma calculations shall be made in good faith by a responsible financial or accounting officer of Holdings. Any such pro forma calculation may include adjustments appropriate, in the reasonable good faith determination of Holdings as set forth in an Officers’ Certificate, to reflect operating expense reductions and other operating improvements or synergies reasonably expected to result from the applicable event on or prior to the date that is 12 months after such applicable event; provided that the aggregate amount of operating expense reductions and other operating improvements or synergies added to EBITDA pursuant to this paragraph or the third paragraph of the definition of Fixed Charge Coverage Ratio, plus the aggregate amount of cash items excluded and resulting in an increase to Consolidated Net Income pursuant to clause (1) in the definition of Consolidated Net Income, plus the aggregate amount of cash items added back to EBITDA pursuant to clause (6) in the definition of EBITDA, shall not exceed, in any applicable four quarter period, the Aggregate Special Cap.

If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest on such Indebtedness shall be calculated as if the rate in effect on the Leverage Ratio Calculation Date had been the applicable rate for the entire period (taking into account any Hedging Obligations applicable to such Indebtedness if such Hedging Obligation has a remaining term in excess of 12 months). Interest on a Capitalized Lease Obligation shall be deemed to accrue at an interest rate reasonably determined by a responsible financial or accounting officer of Holdings to be the rate of interest implicit in such Capitalized Lease Obligation in accordance with GAAP. For purposes of making the computation referred to above, interest on any Indebtedness under a revolving credit facility computed on a pro forma basis shall be computed based upon the average daily balance of such Indebtedness during the applicable period. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a Eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or, if none, then based upon such optional rate chosen as Holdings may designate.

For purposes of this definition, any amount in a currency other than U.S. dollars will be converted to U.S. dollars based on the average exchange rate for such currency for the most recent twelve month period immediately prior to the date of determination in a manner consistent with that used in calculating EBITDA for the applicable period.

“Consolidated Net Income” means, with respect to any Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis;provided,however, that, without duplication:

(1) any (a) netafter-tax extraordinary or nonrecurring gains or losses (less all fees and expenses relating thereto) or expenses or charges, (b) any severance expenses, acquisition integration costs, expenses or charges related to any issuance of Equity Interests, Investment, acquisition, disposition, recapitalization or issuance, repayment, refinancing, amendment or modification of Indebtedness (in each case, whether or not successful) and (c) hurricane costs and charges, shall be excluded;provided that the aggregate amount of cash items excluded and resulting in an increase to Consolidated Net Income pursuant to this clause (1), plus the aggregate amount of cash items added back to EBITDA pursuant to

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clause (6) in the definition of EBITDA, plus the aggregate amount of operating expense reductions and other operating improvements or synergies added to EBITDA pursuant to the third paragraph of the definition of Fixed Charge Coverage Ratio or the third paragraph of the definition of Consolidated Leverage Ratio, shall not exceed, in any applicable four quarter period, the Aggregate Special Cap;

(2) effects of purchase accounting adjustments (including the effects of such adjustments pushed down to such Person and such Subsidiaries) in amounts required or permitted by GAAP, resulting from the application of purchase accounting or the amortization orwrite-off of any amounts thereof, net of taxes, shall be excluded;

(3) the Net Income for such period shall not include the cumulative effect of a change in accounting principles during such period;

(4) any netafter-tax income or loss (less all fees and expenses or charges relating thereto) from disposed, abandoned, transferred, closed or discontinued operations or fixed assets and any netafter-tax gains or losses on disposal of disposed, abandoned, transferred, closed or discontinued operations or fixed assets or attributable to business dispositions or other asset dispositions other than in the ordinary course of business (as determined in good faith by management of Holdings) shall be excluded;

(5) [reserved];

(6) any netafter-tax gains or losses (less all fees and expenses or charges relating thereto) attributable to the early extinguishment of indebtedness, Hedging Obligations or other derivative instruments shall be excluded;

(7) the Net Income for such period of any Person that is not a Subsidiary of such Person, or is an Unrestricted Subsidiary, or that is accounted for by the equity method of accounting, shall be included only to the extent of the amount of dividends or distributions or other payments paid in cash (or to the extent converted into cash) to the referent Person or a Restricted Subsidiary thereof in respect of such period;

(8) solely for the purpose of determining the amount available for Restricted Payments under clause (1) of the definition of Cumulative Credit contained in “—Certain Covenants—Limitation on Restricted Payments,” the Net Income for such period of any Restricted Subsidiary (other than any Subsidiary Guarantor) shall be excluded to the extent that the declaration or payment of dividends or similar distributions by such Restricted Subsidiary of its Net Income is not at the date of determination permitted without any prior governmental approval (which has not been obtained) or, directly or indirectly, by the operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, unless such restrictions with respect to the payment of dividends or similar distributions have been legally waived;provided that the Consolidated Net Income of such Person shall be increased by the amount of dividends or other distributions or other payments actually paid in cash (or converted into cash) by any such Restricted Subsidiary to such Person, to the extent not already included therein;

(9) an amount equal to the amount of Tax Distributions actually made to any parent or equity holder of such Person in respect of such period in accordance with clause (12) of the second paragraph under “—Certain Covenants—Limitation on Restricted Payments” shall be included as though such amounts had been paid as income taxes directly by such Person for such period;

(10) any impairment charges or asset write-offs, in each case pursuant to GAAP, the amortization of intangibles arising pursuant to GAAP, and any impairment charges, asset write-offs or write-down, including ceiling test write downs, on Oil and Gas Properties under GAAP or SEC guidelines shall be excluded;

(11) anynon-cash expense realized or resulting from stock option plans, employee benefit plans or post-employment benefit plans, or grants or sales of stock, stock appreciation or similar rights, stock options, restricted stock, preferred stock or other rights shall be excluded;

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(12) [reserved];

(13) [reserved];

(14) [reserved];

(15) [reserved];

(16) any currency translation gains and losses related to currency remeasurements of Indebtedness, and any net loss or gain resulting from hedging transactions for currency exchange risk, shall be excluded; and

(17) (a) to the extent covered by insurance and actually reimbursed, or, so long as such Person has made a determination that there exists reasonable evidence that such amount will in fact be reimbursed by the insurer and only to the extent that such amount is (a) not denied by the applicable carrier in writing within 180 days and (b) in fact reimbursed within 365 days of the date of such evidence (with a deduction for any amount so added back to the extent not so reimbursed within 365 days), expenses with respect to liability or casualty events or business interruption shall be excluded and (b) amounts estimated in good faith to be received from insurance in respect of lost revenues or earnings in respect of liability or casualty events or business interruption shall be included (with a deduction for amounts actually received up to such estimated amount to the extent included in Net Income in a future period less a deduction for any amounts so added back to the extent not so received within 365 days).

Notwithstanding the foregoing, for the purpose of the covenant described under “—Certain Covenants—Limitation on Restricted Payments” only, there shall be excluded from Consolidated Net Income any dividends, repayments of loans or advances or other transfers of assets from Unrestricted Subsidiaries or Restricted Subsidiaries to the extent such dividends, repayments or transfers increase the amount of Restricted Payments permitted under such covenant pursuant to clauses (4) and (5) of the definition of Cumulative Credit contained therein.

“ConsolidatedNon-Cash Charges” means, with respect to any Person for any period, thenon-cash expenses (other than Consolidated Depreciation, Depletion and Amortization Expense) of such Person and its Restricted Subsidiaries reducing Consolidated Net Income of such Person for such period on a consolidated basis and otherwise determined in accordance with GAAP,provided that if any suchnon-cash expenses represent an accrual or reserve for potential cash items in any future period, the cash payment in respect thereof in such future period shall be subtracted from EBITDA in such future period to the extent paid, but excluding from this proviso, for the avoidance of doubt, amortization of a prepaid cash item that was paid in a prior period.

“Consolidated Taxes” means, with respect to any Person for any period, the provision for taxes based on income, profits or capital, including, without limitation, state, franchise, property and similar taxes, foreign withholding taxes (including penalties and interest related to such taxes or arising from tax examinations) and any Tax Distributions taken into account in calculating Consolidated Net Income.

“Consolidated Total Indebtedness” means, as of any date of determination, an amount equal to the sum (without duplication) of (1) the aggregate principal amount of all outstanding Indebtedness of Holdings and the Restricted Subsidiaries (excluding any undrawn letters of credit) consisting of Capitalized Lease Obligations, bankers’ acceptances and Indebtedness for borrowed money, plus (2) the aggregate amount of all outstanding Disqualified Stock of Holdings and the Restricted Subsidiaries and all Preferred Stock of Restricted Subsidiaries, with the amount of such Disqualified Stock and Preferred Stock equal to the greater of their respective voluntary or involuntary liquidation preferences, in each case determined on a consolidated basis in accordance with GAAP.

“Contingent Obligations” means, with respect to any Person, any obligation of such Person guaranteeing any leases, dividends or other obligations that do not constitute Indebtedness (“primary obligations”) of any other

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Person (the “primary obligor”) in any manner, whether directly or indirectly, including, without limitation, any obligation of such Person, whether or not contingent:

(1) to purchase any such primary obligation or any property constituting direct or indirect security therefor,

(2) to advance or supply funds:

(a) for the purchase or payment of any such primary obligation; or

(b) to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency of the primary obligor; or

(3) to purchase property, securities or services primarily for the purpose of assuring the owner of any such primary obligation of the ability of the primary obligor to make payment of such primary obligation against loss in respect thereof.

“Contractual Requirement” means any term, covenant, condition or provision of any indenture, loan agreement, lease agreement, mortgage, deed of trust, agreement or other instrument to which Holdings or any of the Restricted Subsidiaries is a party or by which it or any of its property or assets is bound.

“Corporate Trust Office” means the designated office of the Trustee in the United States of America at which at any time its corporate trust business shall be administered, or such other address as the Trustee may designate from time to time by notice to the holders and the Issuers, or the principal corporate trust office of any successor Trustee (or such other address as such successor Trustee may designate from time to time by notice to the holders and the Issuers).

“Credit Agreement” means (i) the Credit Agreement to be entered into on the Issue Date among Holdings, as borrower, Talos Energy, Inc., as holdings, JPMorgan Chase Bank, N.A., as administrative agent, collateral agent, and swingline lender, the other lenders party thereto from time to time, and Natixis, New York Branch and The Toronto-Dominion Bank, New York Branch, as issuing banks, and each other issuing bank from time to time party thereto, as amended, restated, supplemented, waived, replaced (whether or not upon termination, and whether with the original lenders or otherwise), repaid, refunded, refinanced or otherwise modified from time to time, including any agreement extending the maturity thereof, refinancing or replacing all or any portion of the Indebtedness under such agreement or agreements or any successor or replacement agreement or agreements or increasing the amount loaned or issued thereunder or altering the maturity thereof;provided, that in no event shall any lenders under the Credit Agreement include (i) any affiliates of each of Apollo Global Management, LLC or Riverstone Holdings LLC or (ii) any funds managed, advised orsub-advised by the persons described in the foregoing clause (i).

“Credit Agreement Documents” means the collective reference to the Credit Agreement, any notes issued pursuant thereto and the guarantees thereof, and the collateral documents relating thereto, as amended, supplemented, restated, renewed, refunded, replaced, restructured, repaid, refinanced or otherwise modified, in whole or in part, from time to time.

“Customary Intercreditor Agreement” means (a) in connection with the incurrence of Pari Passu Indebtedness that is to be secured by Liens on all or a portion of the Collateral securing such Pari Passu Indebtedness that shall rank equal in priority to the Liens on the Collateral securing the Notes Obligations, an intercreditor agreement among the Trustee, the Collateral Agent and one or more agents for holders of such Pari Passu Indebtedness in the form delivered by the Issuers to the Trustee and Collateral Agent providing that, inter alia, the Liens on all or a portion of the Collateral in favor of the Collateral Agent shall be pari passu to such Liens in favor of such agent for holders of Pari Passu Indebtedness, provided that such intercreditor agreement shall provide that the largest series of Pari Passu Indebtedness by outstanding principal amount shall control the enforcement of rights and remedies with respect to the Collateral and such intercreditor agreement shall otherwise contain customary terms consistent with then prevailing market terms as determined in good faith by

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the Issuers (and a joinder to the Senior Lien Intercreditor Agreement shall be executed with respect to such Pari Passu Indebtedness) and (b) to the extent executed in connection with the incurrence of Indebtedness secured by junior Liens, an intercreditor agreement substantially in the form of the Senior Lien Intercreditor Agreement where the Notes Obligations shall be the senior obligations thereunder (with such modifications as may be necessary or appropriate in light of prevailing market conditions and are not materially adverse to the holders of Notes, taken as a whole).

“Debt Exchange Agreement” means that certain exchange agreement, dated as of November 21, 2017, among the Issuers, Stone Energy Corporation, the lenders listed on the signature pages thereto, the noteholders listed on the signature pages thereto, providing for the exchange of the notes for the Issuers’ 11.00% Second Lien Bridge Loans and for the Stone Notes.

“Default” means any event which is, or after notice or passage of time or both would be, an Event of Default.

“DesignatedNon-cash Consideration” means the Fair Market Value (as determined in good faith by Holdings) ofnon-cash consideration received by Holdings or a Restricted Subsidiary in connection with an Asset Sale that is so designated as DesignatedNon-cash Consideration pursuant to an Officers’ Certificate, setting forth the basis of such valuation, less the amount of Cash Equivalents received in connection with a subsequent sale of such DesignatedNon-cash Consideration.

“Designated Preferred Stock” means Preferred Stock of Holdings or any direct or indirect parent of Holdings (other than Disqualified Stock), that is issued for cash (other than to Holdings or any of its Subsidiaries or an employee stock ownership plan or trust established by Holdings or any of its Subsidiaries) and is so designated as Designated Preferred Stock, pursuant to an Officers’ Certificate, on the issuance date thereof.

“Discharge of First-Priority Lien Obligations” means, except to the extent otherwise provided in the Senior Lien Intercreditor Agreement, with respect to any First-Priority Lien Obligations, (a) payment in full in immediately available funds of the principal of, and interest (including interest accruing on or after the commencement of an Insolvency Proceeding, whether or not such interest would be allowed in the proceeding) accrued on, all outstanding Indebtedness included in such First-Priority Lien Obligations after or concurrently with the termination of all commitments to extend credit thereunder (other than, if applicable, pursuant to cash management agreements or hedge agreements secured by such First-Priority Lien Obligations, in each case as permitted under the relevant document evidencing such First-Priority Lien Obligation or as to which reasonably satisfactory arrangements have been made with the relevant bank providing such cash management or hedges), (b) with respect to any letters of credit or letters of credit guaranties that may be outstanding in respect of any First-Priority Lien Obligations, termination or delivery of cash collateral, backstop letters of credit or other credit support in respect thereof in an amount and manner in compliance with the relevant document evidencing such First-Priority Lien Obligation, and (c) payment in full in immediately available funds of any other First-Priority Lien Obligations that are due and payable or otherwise accrued and owing at or prior to the time such principal and interest are paid (other than in respect of contingent indemnification and expense reimbursement claims not then due); provided that the Discharge of First-Priority Lien Obligations shall not be deemed to have occurred if such payments are made with the proceeds other First-Priority Lien Obligations that constitute an exchange or replacement for or a refinancing of such First- Priority Lien Obligations.

“Disqualified Stock” means, with respect to any Person, any Capital Stock of such Person which, by its terms (or by the terms of any security into which it is convertible or for which it is redeemable or exchangeable), or upon the happening of any event:

(1) matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise (other than as a result of a change of control or asset sale),

(2) is convertible or exchangeable for Indebtedness or Disqualified Stock of such Person, or

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(3) is redeemable at the option of the holder thereof, in whole or in part (other than solely as a result of a change of control or asset sale),

in each case prior to 91 days after the earlier of the maturity date applicable to any notes or the date the notes are no longer outstanding;provided,however, that only the portion of Capital Stock which so matures or is mandatorily redeemable, is so convertible or exchangeable or is so redeemable at the option of the holder thereof prior to such date shall be deemed to be Disqualified Stock;provided,further,however, that if such Capital Stock is issued to any employee or to any plan for the benefit of employees of Holdings or its Subsidiaries or by any such plan to such employees, such Capital Stock shall not constitute Disqualified Stock solely because it may be required to be repurchased by such Person in order to satisfy applicable statutory or regulatory obligations or as a result of such employee’s termination, death or disability;provided,further, that any class of Capital Stock of such Person that by its terms authorizes such Person to satisfy its obligations thereunder by delivery of Capital Stock that is not Disqualified Stock shall not be deemed to be Disqualified Stock.

“Dollar Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Domestic Subsidiary” means a Restricted Subsidiary that is not a Foreign Subsidiary.

“EBITDA” means, with respect to any Person for any period, the Consolidated Net Income of such Person and its Restricted Subsidiaries for such period plus, without duplication, to the extent the same was deducted in calculating Consolidated Net Income:

(1) Consolidated Taxes;plus

(2) Fixed Charges;plus

(3) Consolidated Depreciation, Depletion and Amortization Expense;plus

(4) ConsolidatedNon-Cash Charges;plus

(5) hurricane costs and charges (for the avoidance of doubt, without duplication of amounts excluded and resulting in an increase to Consolidated Net Income pursuant to clause (1) in the definition of Consolidated Net Income);plus

(6) business optimization expenses and other restructuring charges, reserves or expenses (which, for the avoidance of doubt, shall include, without limitation, the effect of inventory optimization programs, facility closures, facility consolidations, retention, systems establishment costs, contract termination costs, future lease commitments and excess pension charges);provided that the aggregate amount of cash items added back to EBITDA pursuant to this clause (6), plus the aggregate amount of cash items excluded and resulting in an increase to Consolidated Net Income pursuant to clause (1) in the definition of Consolidated Net Income, plus the aggregate amount of operating expense reductions and other operating improvements or synergies added to EBITDA pursuant to the third paragraph of the definition of Fixed Charge Coverage Ratio or the third paragraph of the definition of Consolidated Leverage Ratio, shall not exceed, in any applicable four quarter period, the Aggregate Special Cap;plus

(7) [reserved];plus

(8) any costs or expense Incurred pursuant to any management equity plan or stock option plan or any other management or employee benefit plan or agreement or any stock subscription or shareholder agreement, to the extent that such cost or expenses are funded with cash proceeds contributed to the capital of Holdings or a Subsidiary Guarantor or net cash proceeds of an issuance of Equity Interests of Holdings (other than Disqualified Stock) solely to the extent that such net cash proceeds are excluded from the calculation of the Cumulative Credit;plus

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(9) the amount of any management, monitoring, consulting, transaction and advisory fees and related expenses paid to the Significant Issue Date Equityholders (or any accruals relating to such fees and related expenses) during such period to the extent otherwise permitted by the covenant described under “—Certain Covenants—Transactions with Affiliates”, including, if applicable, the amount of termination fees paid pursuant to clause (20) thereof, in an aggregate amount not to exceed $500,000 in any calendar year pursuant to this clause (9);plus

(10) [reserved];plus

(11) [reserved];plus

(12) exploration expenses or costs (to the extent Holdings adopts the “successful efforts” method); andless, without duplication, to the extent the same increased Consolidated Net Income,

(13) the sum of (x) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments and (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar Denominated Production Payments; and

(14) non-cash items increasing Consolidated Net Income for such period (excluding the recognition of deferred revenue or any items which represent the reversal of any accrual of, or cash reserve for, anticipated cash charges that reduced EBITDA in any prior period and any items for which cash was received in a prior period).

“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

“Equity Offering” means any public or private sale after the Issue Date of common Capital Stock or Preferred Stock of Holdings or any direct or indirect parent of Holdings, as applicable (other than Disqualified Stock), other than:

(1) public offerings with respect to Holdings’ or such direct or indirect parent’s common stock registered on FormS-4 or FormS-8; and

(2) issuances to any Subsidiary of Holdings.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.

“Exchange Notes” means the notes of the Issuers issued pursuant to the indenture in exchange for, and in an aggregate principal amount equal to or not in excess of, the Initial Notes or any additional notes, if applicable, in compliance with the terms of the Registration Rights Agreement.

“Exchange Offer Registration Statement” means the registration statement filed with the SEC in connection with the Registered Exchange Offer.

“Excluded Subsidiary” means (a) any Unrestricted Subsidiary, (b) any Subsidiary that is not a Wholly Owned Subsidiary (for so long as such Subsidiary remains anon-Wholly Owned Subsidiary), (c) any Foreign Subsidiary, (d) any FSHCO, (e) any Domestic Subsidiary that is a direct or indirect Subsidiary of a Foreign Subsidiary and (e) any Subsidiary (other than a Significant Subsidiary) that (i) did not, as of the last day of the fiscal quarter of Holdings most recently ended, have assets with a value in excess of 5.0% of the Total Assets or revenues representing in excess of 5.0% of total revenues of Holdings and the Restricted Subsidiaries on a consolidated basis as of such date and (ii) taken together with all other such Subsidiaries as of the last day of the fiscal quarter of Holdings most recently ended, did not have assets with a value in excess of 10.0% of the Total Assets or revenues representing in excess of 10.0% of total revenues of Holdings and the Restricted Subsidiaries on a consolidated basis as of such date.

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“Fair Market Value” means, with respect to any asset or property, the price which could be negotiated in an arm’s length transaction, for cash, between a willing seller and a willing and able buyer, neither of whom is under undue pressure or compulsion to complete the transaction.

“Farm-In Agreement” means an agreement whereby a Person agrees to pay all or a share of the drilling, completion or other expenses of one or more exploratory or development wells (which agreement may be subject to a maximum payment obligation, after which expenses are shared in accordance with the working or participation interests therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well or wells as all or a part of the considerationprovided in exchange for an ownership interest in an Oil and Gas Property.

“Farm-Out Agreement” means aFarm-In Agreement, viewed from the standpoint of the party that transfers an ownership interest to another.

“First-Priority After-Acquired Property” means any property of Holdings or any Subsidiary Guarantor that secures any Secured Bank Indebtedness that is not already subject to the Lien under the Security Documents.

“First-Priority Lien Obligations” means (i) all Secured Bank Indebtedness that is secured by the Collateral on a senior basis to the Liens securing the Notes Obligations and (ii) all other obligations of Holdings or any of its Restricted Subsidiaries in respect of Hedging Obligations or obligations in respect of cash management services that is secured by the Collateral on a senior basis to the Liens securing the Notes Obligations, in each case owing to a Person that is a holder of Secured Bank Indebtedness or an Affiliate of such holder at the time of entry into such Hedging Obligations or obligations in respect of cash management services.

“Fixed Charge Coverage Ratio” means, with respect to any Person for any period, the ratio of EBITDA of such Person for such period to the Fixed Charges of such Person for such period. In the event that Holdings or any of its Restricted Subsidiaries Incurs, repays, repurchases or redeems any Indebtedness or issues, repurchases or redeems Disqualified Stock or Preferred Stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated but prior to the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio shall be calculated givingpro forma effect to such Incurrence, repayment, repurchase or redemption of Indebtedness, or such issuance, repurchase or redemption of Disqualified Stock or Preferred Stock, as if the same had occurred at the beginning of the applicable four-quarter period;provided that Holdings may elect pursuant to an Officers’ Certificate delivered to the Trustee to treat all or any portion of the commitment under any Indebtedness as being Incurred at such time, in which case any subsequent Incurrence of Indebtedness under such commitment shall not be deemed, for purposes of this calculation, to be an Incurrence at such subsequent time.

For purposes of making the computation referred to above, Investments, acquisitions, dispositions, mergers, amalgamations, consolidations and discontinued operations (as determined in accordance with GAAP), in each case with respect to an operating unit of a business, and any operational changes that Holdings or any Restricted Subsidiary has determined to make and/or made during the four-quarter reference period or subsequent to such reference period and on or prior to or simultaneously with the Calculation Date shall be calculated on apro forma basis assuming that all such Investments, acquisitions, dispositions, mergers, amalgamations, consolidations, discontinued operations and other operational changes (and the change of any associated fixed charge obligations and the change in EBITDA resulting therefrom) had occurred on the first day of the four-quarter reference period. If since the beginning of such period any Person that subsequently became a Restricted Subsidiary or was merged with or into Holdings or any Restricted Subsidiary since the beginning of such period shall have made any Investment, acquisition, disposition, merger, consolidation, amalgamation, discontinued operation or operational change, in each case with respect to an operating unit of a business, that would have required adjustment pursuant to this definition, then the Fixed Charge Coverage Ratio shall be calculated givingpro forma effect thereto for such period as if such Investment, acquisition, disposition, discontinued operation, merger, amalgamation, consolidation or operational change had occurred at the beginning of the applicable four-quarter

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period. If since the beginning of such period any Restricted Subsidiary is designated an Unrestricted Subsidiary or any Unrestricted Subsidiary is designated a Restricted Subsidiary, then the Fixed Charge Coverage Ratio shall be calculated givingpro forma effect thereto for such period as if such designation had occurred at the beginning of the applicable four-quarter period.

For purposes of this definition, whenever pro forma effect is to be given to any event, the pro forma calculations shall be made in good faith by a responsible financial or accounting officer of Holdings. Any such pro forma calculation may include adjustments appropriate, in the reasonable good faith determination of Holdings as set forth in an Officers’ Certificate, to reflect operating expense reductions and other operating improvements or synergies reasonably expected to result from the applicable event on or prior to the date that is 12 months after such applicable event;provided that the aggregate amount of operating expense reductions and other operating improvements or synergies added to EBITDA pursuant to this paragraph or the third paragraph of the definition of Consolidated Leverage Ratio, plus the aggregate amount of cash items excluded and resulting in an increase to Consolidated Net Income pursuant to clause (1) in the definition of Consolidated Net Income, plus the aggregate amount of cash items added back to EBITDA pursuant to clause (6) in the definition of EBITDA, shall not exceed, in any applicable four quarter period, the Aggregate Special Cap.

If any Indebtedness bears a floating rate of interest and is being givenpro forma effect, the interest on such Indebtedness shall be calculated as if the rate in effect on the Calculation Date had been the applicable rate for the entire period (taking into account any Hedging Obligations applicable to such Indebtedness if such Hedging Obligation has a remaining term in excess of 12 months). Interest on a Capitalized Lease Obligation shall be deemed to accrue at an interest rate reasonably determined by a responsible financial or accounting officer of Holdings to be the rate of interest implicit in such Capitalized Lease Obligation in accordance with GAAP. For purposes of making the computation referred to above, interest on any Indebtedness under a revolving credit facility computed on apro forma basis shall be computed based upon the average daily balance of such Indebtedness during the applicable period. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a Eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or, if none, then based upon such optional rate chosen as Holdings may designate.

For purposes of this definition, any amount in a currency other than U.S. dollars will be converted to U.S. dollars based on the average exchange rate for such currency for the most recent twelve month period immediately prior to the date of determination in a manner consistent with that used in calculating EBITDA for the applicable period.

“Fixed Charges” means, with respect to any Person for any period, the sum, without duplication, of: (1) Consolidated Interest Expense (excluding amortization orwrite-off of deferred financing costs) of such Person for such period, and (2) all cash dividend payments (excluding items eliminated in consolidation) on any series of Preferred Stock or Disqualified Stock of such Person and its Restricted Subsidiaries.

“Foreign Subsidiary” means a Restricted Subsidiary not organized or existing under the laws of the United States of America or any state thereof or the District of Columbia.

“FSHCO” shall mean any Domestic Subsidiary that owns (directly or through its Subsidiaries) no material assets other than the Equity Interests of one or more Foreign Subsidiaries that are CFCs.

“GAAP” means generally accepted accounting principles in the United States set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as have been approved by a significant segment of the accounting profession, which are in effect on the Issue Date. For the purposes of the indenture, the term “consolidated” with respect to any Person shall mean such Person consolidated with its Restricted Subsidiaries, and shall not include any Unrestricted Subsidiary, but the interest of such Person in an Unrestricted Subsidiary will be accounted for as an Investment.

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“guarantee” means a guarantee (other than by endorsement of negotiable instruments for collection in the ordinary course of business), direct or indirect, in any manner (including, without limitation, letters of credit and reimbursement agreements in respect thereof), of all or any part of any Indebtedness or other obligations.

“Hedging Obligations” means, with respect to any Person, the obligations of such Person under:

(1) currency exchange, interest rate or commodity swap agreements (including commodity swaps, commodity options, forward commodity contracts, basis differential swaps, spot contracts, fixed price physical delivery contracts or other similar agreements or arrangements in respect of Hydrocarbons), currency exchange, interest rate or commodity cap agreements and currency exchange, interest rate or commodity collar agreements; and

(2) other agreements or arrangements designed to protect such Person against fluctuations in currency exchange, interest rates or commodity prices.

Notwithstanding the foregoing, agreements or obligations to physically sell any commodity at any index based price shall not be considered Hedging Obligations.

“holder” or “noteholder” means the Person in whose name a note is registered on the Registrar’s books.

“Holdings” means Talos Production LLC, together with its successors or assigns.

“Hydrocarbons” means oil, natural gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

“Incur” means issue, assume, guarantee, incur or otherwise become liable for;provided,however, that any Indebtedness or Capital Stock of a Person existing at the time such person becomes a Subsidiary (whether by merger, amalgamation, consolidation, acquisition or otherwise) shall be deemed to be Incurred by such Person at the time it becomes a Subsidiary.

“Indebtedness” means, with respect to any Person:

(1) the principal and premium (if any) of any indebtedness of such Person, whether or not contingent, (a) in respect of borrowed money, (b) evidenced by bonds, notes, debentures or similar instruments or letters of credit or bankers’ acceptances (or, without duplication, reimbursement agreements in respect thereof), (c) representing the deferred and unpaid purchase price of any property (except any such balance that constitutes (i) a trade payable or similar obligation to a trade creditor Incurred in the ordinary course of business, (ii) anyearn-out obligations until such obligation becomes a liability on the balance sheet of such Person in accordance with GAAP and (iii) liabilities accrued in the ordinary course of business), which purchase price is due more than six months after the date of placing the property in service or taking delivery and title thereto, (d) in respect of Capitalized Lease Obligations, or (e) representing any Hedging Obligations, if and to the extent that any of the foregoing indebtedness would appear as a liability on a balance sheet (excluding the footnotes thereto) of such Person prepared in accordance with GAAP;

(2) to the extent not otherwise included, any obligation of such Person to be liable for, or to pay, as obligor, guarantor or otherwise, the obligations referred to in clause (1) of another Person (other than by endorsement of negotiable instruments for collection in the ordinary course of business); and

(3) to the extent not otherwise included, Indebtedness of another Person secured by a Lien on any asset owned by such Person (whether or not such Indebtedness is assumed by such Person);provided,however, that the amount of such Indebtedness will be the lesser of: (a) the Fair Market Value (as determined in good faith by Holdings) of such asset at such date of determination, and (b) the amount of such Indebtedness of such other Person;

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provided,however, that notwithstanding the foregoing, Indebtedness shall be deemed not to include (1) Contingent Obligations Incurred in the ordinary course of business and not in respect of borrowed money; (2) deferred or prepaid revenues; (3) purchase price holdbacks in respect of a portion of the purchase price of an asset to satisfy warranty or other unperformed obligations of the respective seller; (4) [reserved]; (5) [reserved]; (6) Production Payments and Reserve Sales; (7) any obligation of a Person in respect of aFarm-In Agreement or similar arrangement whereby such Person agrees to pay all or a share of the drilling, completion or other expenses of an exploratory or development well (which agreement may be subject to a maximum payment obligation, after which expenses are shared in accordance with the working or participation interest therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well in exchange for an ownership interest in an oil or gas property; (8) any obligations under Hedging Obligations;provided that such agreements are entered into for bona fide hedging purposes of Holdings or its Restricted Subsidiaries (as determined in good faith by the Board of Directors or senior management of Holdings, whether or not accounted for as a hedge in accordance with GAAP) and, in the case of any foreign exchange contract, currency swap agreement, futures contract, option contract or other similar agreement, such agreements are related to business transactions of Holdings or its Restricted Subsidiaries entered into in the ordinary course of business and, in the case of any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement, such agreements substantially correspond in terms of notional amount, duration and interest rates, as applicable, to Indebtedness of Holdings or its Restricted Subsidiaries Incurred without violation of the indenture; (9) obligations in respect of surety and bonding requirements of Holdings and its Restricted Subsidiaries; and(10) in-kind obligations relating to net oil, natural gas liquids or natural gas balancing positions arising in the ordinary course of business.

Notwithstanding anything in the indenture to the contrary, Indebtedness shall not include, and shall be calculated without giving effect to, the effects of Statement of Financial Accounting Standards No. 133 and related interpretations to the extent such effects would otherwise increase or decrease an amount of Indebtedness for any purpose under the indenture as a result of accounting for any embedded derivatives created by the terms of such Indebtedness; and any such amounts that would have constituted Indebtedness under the indenture but for the application of this sentence shall not be deemed an Incurrence of Indebtedness under the indenture.

“Independent Financial Advisor” means an accounting, appraisal or investment banking firm or consultant, in each case of nationally recognized standing, that is, in the good faith determination of Holdings, qualified to perform the task for which it has been engaged.

“Insolvency Proceeding” means (a) any voluntary or involuntary case or proceeding under any Bankruptcy Law with respect to any of the Issuers or the Subsidiary Guarantors, (b) any other voluntary or involuntary insolvency, reorganization or bankruptcy case or proceeding, or any receivership, liquidation, reorganization or other similar case or proceeding with respect to any Issuer or a Subsidiary Guarantor or with respect to any of its assets, (c) any liquidation, dissolution, reorganization or winding up of any Issuer or a Subsidiary Guarantor whether voluntary or involuntary and whether or not involving insolvency or bankruptcy (except to the extent permitted by the Credit Agreement or Notes Documents, as applicable) or (d) any assignment for the benefit of creditors or any other marshaling of assets and liabilities of any Issuer or a Subsidiary Guarantor.

“Investment Grade Rating” means a rating equal to or higher than Baa3 (or the equivalent) by Moody’s andBBB- (or the equivalent) by S&P, or an equivalent rating by any other Rating Agency.

“Investment Grade Securities” means:

(1) securities issued or directly and fully guaranteed or insured by the U.S. government or any agency or instrumentality thereof (other than Cash Equivalents),

(2) securities that have a rating equal to or higher than Baa3 (or equivalent) by Moody’s andBBB- (or equivalent) by S&P, but excluding any debt securities or loans or advances between and among Holdings and its Subsidiaries,

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(3) investments in any fund that invests exclusively in investments of the type described in clauses (1) and (2) which fund may also hold immaterial amounts of cash pending investment and/or distribution, and

(4) corresponding instruments in countries other than the United States customarily utilized for high quality investments and in each case with maturities not exceeding two years from the date of acquisition.

“Investments” means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of loans (including guarantees), advances or capital contributions (excluding accounts receivable, trade credit and advances to customers and commission, travel and similar advances to officers, employees and consultants made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities issued by any other Person and investments that are required by GAAP to be classified on the balance sheet of such Person in the same manner as the other investments included in this definition to the extent such transactions involve the transfer of cash or other property. For purposes of the definition of “Unrestricted Subsidiary” and the covenant described under “—Certain Covenants—Limitation on Restricted Payments”:

(1) “Investments” shall include the portion (proportionate to Holdings’ equity interest in such Subsidiary) of the Fair Market Value (as determined in good faith by Holdings) of the net assets of a Subsidiary of Holdings at the time that such Subsidiary is designated an Unrestricted Subsidiary;provided, however, that upon a redesignation of such Subsidiary as a Restricted Subsidiary, Holdings shall be deemed to continue to have a permanent “Investment” in an Unrestricted Subsidiary equal to an amount (if positive) equal to:

(a) Holdings’ “Investment” in such Subsidiary at the time of such redesignation less

(b) the portion (proportionate to Holdings’ equity interest in such Subsidiary) of the Fair Market Value (as determined in good faith by Holdings) of the net assets of such Subsidiary at the time of such redesignation; and

(2) any property transferred to or from an Unrestricted Subsidiary shall be valued at its Fair Market Value (as determined in good faith by Holdings) at the time of such transfer, in each case as determined in good faith by the Board of Directors of Holdings.

“Issue Date” means the date on which the notes are originally issued.

“Junior Lien Obligations” means the Obligations with respect to other Indebtedness permitted to be Incurred under the indenture, which is by its terms intended to be secured by the Collateral on a basis junior to the notes;provided such Lien is permitted to be Incurred under the indenture.

“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or similar encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law (including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction);provided that in no event shall an operating lease be deemed to constitute a Lien.

“Management Group” means the group consisting of the directors, managers, executive officers and other management personnel of Holdings or any direct or indirect parent of Holdings, as the case may be, on the Issue Date together with (1) any new directors or managers whose election by such boards of directors or managers or whose nomination for election by the shareholders of Holdings or any direct or indirect parent of Holdings, as applicable, was approved by a vote of a majority of the directors or managers of Holdings or any direct or indirect parent of Holdings, as applicable, then still in office who were either directors or managers on the Issue Date or whose election or nomination was previously so approved and (2) executive officers and other

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management personnel of Holdings or any direct or indirect parent of Holdings, as applicable, hired at a time when the directors or managers on the Issue Date together with the directors or managers so approved constituted a majority of the directors or managers of Holdings or any direct or indirect parent of Holdings, as applicable.

“Moody’s” means Moody’s Investors Service, Inc. or any successor to the rating agency business thereof.

“Mortgaged Properties” means each parcel of real estate and improvements thereto with respect to which a Mortgage is required to be granted on the Issue Date pursuant to the Debt Exchange Agreement or thereafter pursuant to the covenant described under “—Security—After-Acquired Property.”

“Mortgages” means, collectively, the mortgages, trust deeds, deeds of trust, deeds to secure debt, assignment ofas-extracted collateral, fixture filing and other security documents delivered with respect to Mortgaged Properties substantially in the form attached as an exhibit to the indenture (with such changes thereto as may be necessary to account for local law matters).

“Net Income” means, with respect to any Person, the net income (loss) of such Person and its Restricted Subsidiaries, determined in accordance with GAAP and before any reduction in respect of Preferred Stock dividends.

“Net Proceeds” means the aggregate cash proceeds received by Holdings or any Restricted Subsidiary in respect of any Asset Sale (including, without limitation, any cash received in respect of or upon the sale or other disposition of any DesignatedNon-cash Consideration received in any Asset Sale and any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise, but only as and when received, but excluding the assumption by the acquiring person of Indebtedness relating to the disposed assets or other consideration received in any othernon-cash form), net of the direct costs relating to such Asset Sale and the sale or disposition of such DesignatedNon-cash Consideration (including, without limitation, legal, accounting and investment banking fees, and brokerage and sales commissions), and any relocation expenses Incurred as a result thereof, taxes paid or payable as a result thereof (including Tax Distributions and after taking into account any available tax credits or deductions and any tax sharing arrangements related solely to such disposition), amounts required to be applied to the repayment of principal, premium (if any) and interest on Indebtedness required (other than pursuant to clause (1) of the second paragraph of the covenant described under “—Certain Covenants—Asset Sales”) to be paid as a result of such transaction, amounts paid in connection with the termination of Hedging Obligations related to Indebtedness repaid with such proceeds or hedging oil, natural gas and natural gas liquid production in notional volumes corresponding to the Oil and Gas Properties subject to such Asset Sale, and any deduction of appropriate amounts to beprovided by Holdings as a reserve in accordance with GAAP against any liabilities associated with the asset disposed of in such transaction and retained by Holdings after such sale or other disposition thereof, including, without limitation, pension and other post-employment benefit liabilities and liabilities related to environmental matters or against any indemnification obligations associated with such transaction.

“Net Working Capital” means (a) all current assets of Holdings and its Restricted Subsidiaries, except current assets from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business less (b) all current liabilities of Holdings and its Restricted Subsidiaries, except current liabilities (i) associated with asset retirement obligations relating to Oil and Gas Properties, (ii) included in Indebtedness and (iii) any current liabilities from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, in each case as set forth in the consolidated financial statements of Holdings prepared in accordance with GAAP.

“Notes Documents” means the indenture, the notes, the Subsidiary Guarantees, the Security Documents and the Senior Lien Intercreditor Agreement and any Customary Intercreditor Agreement.

“Notes Obligations” means Obligations in respect of the notes, the indenture, the Subsidiary Guarantees and the Security Documents, including, for the avoidance of doubt, Obligations in respect of Exchange Notes and guarantees thereof.

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“Obligations” means any principal, interest, penalties, fees, indemnifications, reimbursements (including, without limitation, reimbursement obligations with respect to letters of credit and bankers’ acceptances), damages and other liabilities payable under the documentation governing any Indebtedness;provided, that Obligations with respect to the notes shall not include fees or indemnifications in favor of third parties other than the Trustee, the Collateral Agent and the holders of the notes.

“Officers’ Certificate” means a certificate signed on behalf of Holdings by two Authorized Officers of Holdings, one of whom must be the principal executive officer, the principal financial officer, the treasurer or the principal accounting officer of Holdings, which meets the requirements set forth in the indenture.

“Oil and Gas Business” means:

(1) the business of acquiring, exploring, exploiting, developing, producing, operating and disposing of interests in oil, natural gas, natural gas liquids, liquefied natural gas and other Hydrocarbons and mineral properties or products produced in association with any of the foregoing;

(2) the business of gathering, marketing, distributing, treating, processing, storing, refining, selling and transporting of any production from such interests or properties and products produced in association therewith and the marketing of oil, natural gas, other Hydrocarbons and minerals obtained from unrelated Persons;

(3) any other related energy business, including power generation and electrical transmission business, directly or indirectly, from oil, natural gas and other Hydrocarbons and minerals produced substantially from properties in which Holdings or its Restricted Subsidiaries, directly or indirectly, participate;

(4) any business relating to oil field sales and service; and

(5) any business or activity relating to, arising from, or necessary, appropriate, incidental or ancillary to the activities described in the foregoing clauses (1) through (4) of this definition.

“Oil and Gas Properties” means all properties, including equity or other ownership interests therein, owned by a Person which contain or are believed to contain oil and gas reserves or other reserves of Hydrocarbons.

“Opinion of Counsel” means a written opinion from legal counsel who is reasonably acceptable to the Trustee. The counsel may be an employee of or counsel to Holdings.

“Other Second-Lien Obligations” means other Indebtedness of Holdings and its Restricted Subsidiaries that is equally and ratably secured with the notes as permitted by the indenture and is designated by Holdings as an Other Second-Lien Obligation in an Officer’s Certificate delivered to the trustee; provided that the authorized representative of the holders of such Pari Passu Indebtedness (and any Obligations in respect of such Pari Passu Indebtedness) shall have become a party to (and such holders shall be bound by) the terms of the Senior Lien Intercreditor Agreement and a Customary Intercreditor Agreement.

“Pari Passu Indebtedness” means: (a) with respect to an Issuer, the notes and any Indebtedness which rankspari passu in right of payment to the notes; and (b) with respect to any Subsidiary Guarantor, its Subsidiary Guarantee and any Indebtedness which rankspari passu in right of payment to such Subsidiary Guarantor’s Subsidiary Guarantee.

“Permitted Business Investment” means any Investment and/or expenditure made in the ordinary course of business and which are of a nature that is or shall have become customary in the Oil and Gas Business generally or in the geographic region in which such activities occur, including investments or expenditures for actively exploiting, exploring for, acquiring, developing, producing, processing, gathering, marketing, distributing, storing, or transporting oil, natural gas or other Hydrocarbons and minerals (including with respect to plugging and abandonment) through agreements, transactions, interests or arrangements which permit one to share risks or

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costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including:

(1) Investments in ownership interests (including equity or other ownership interests) in oil, natural gas, other Hydrocarbons and minerals properties, liquefied natural gas facilities, processing facilities, gathering systems, pipelines, storage facilities or related systems or ancillary real property interests;

(2) Investments in the form of or pursuant to operating agreements, working interests, royalty interests, mineral leases, processing agreements,Farm-In Agreements,Farm-Out Agreements, contracts for the sale, transportation or exchange of oil, natural gas, other Hydrocarbons and minerals, production sharing agreements, participation agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements, stockholder agreements and other similar agreements (including for limited liability companies) with third parties; and

(3) Investments in direct or indirect ownership interests in drilling rigs and related equipment, including, without limitation, transportation equipment.

“Permitted Holders” means, at any time, each of (i) theCo-Investors, (ii) the Management Group, (iii) any direct or indirect parent entity of Holdings as of the Issue Date, (iv) any Person that has no material assets other than the Capital Stock of Holdings and, directly or indirectly, holds or acquires 100% of the total voting power of the Voting Stock of Holdings, and of which no other Person or group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, or any successor provision), other than any of the other Permitted Holders specified in clauses (i) and (ii) above, holds more than 50% of the total voting power of the Voting Stock thereof and (v) any group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, or any successor provision) the members of which include any of the Permitted Holders specified in clauses (i) and (ii) above and that, directly or indirectly, hold or acquire beneficial ownership of the Voting Stock of Holdings (a “Permitted Holder Group”), so long as (1) each member of the Permitted Holder Group has voting rights proportional to the percentage of ownership interests held or acquired by such member and (2) no Person or other “group” (other than Permitted Holders specified in clauses (i) and (ii) above) beneficially owns more than 50% on a fully diluted basis of the Voting Stock held by the Permitted Holder Group. Any Person or group whose acquisition of beneficial ownership constitutes a Change of Control in respect of which a Change of Control Offer is made in accordance with the requirements of the indenture will thereafter, together with its Affiliates, constitute an additional Permitted Holder.

“Permitted Investments” means:

(1) any Investment in Holdings or any Restricted Subsidiary;provided however, that the primary business of such Restricted Subsidiary is the Oil and Gas Business;

(2) any Investment in Cash Equivalents or Investment Grade Securities;

(3) any Investment by Holdings or any Restricted Subsidiary in a Person if as a result of such Investment (a) such Person becomes a Restricted Subsidiary, or (b) such Person, in one transaction or a series of related transactions, is merged, consolidated or amalgamated with or into, or transfers or conveys all or substantially all of its assets to, or is liquidated into, Holdings or a Restricted Subsidiary;

(4) any Investment in securities or other assets not constituting Cash Equivalents and received in connection with an Asset Sale made pursuant to the provisions of “—Certain Covenants—Asset Sales” or any other disposition of assets not constituting an Asset Sale;

(5) any Investment existing on, or made pursuant to binding commitments existing on, the Issue Date or an Investment consisting of any extension, modification or renewal of any Investment existing on the Issue Date;provided that the amount of any such Investment may be increased (x) as required by the terms of such Investment as in existence on the Issue Date or (y) as otherwise permitted under the indenture;

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(6) advances to employees, taken together with all other advances made pursuant to this clause (6), not to exceed $2.0 million at any one time outstanding;

(7) any Investment acquired by Holdings or any Restricted Subsidiary (a) in exchange for any other Investment or accounts receivable held by Holdings or such Restricted Subsidiary in connection with or as a result of a bankruptcy, workout, reorganization or recapitalization of the issuer of such other Investment or accounts receivable, or (b) as a result of a foreclosure by Holdings or any Restricted Subsidiary with respect to any secured Investment or other transfer of title with respect to any secured Investment in default;

(8) Hedging Obligations permitted under clause (j) of the second paragraph of the covenant described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

(9) [reserved];

(10) additional Investments by Holdings or any Restricted Subsidiary having an aggregate Fair Market Value (as determined in good faith by Holdings), taken together with all other Investments made pursuant to this clause (10) that are at that time outstanding, not to exceed $37.5 million (with the Fair Market Value of each Investment being measured at the time made and without giving effect to subsequent changes in value);provided,however, that if any Investment pursuant to this clause (10) is made in any Person that is not Holdings or a Restricted Subsidiary at the date of the making of such Investment and such Person becomes Holdings or a Restricted Subsidiary after such date, such Investment shall thereafter be deemed to have been made pursuant to clause (1) above and shall cease to have been made pursuant to this clause (10) for so long as such Person continues to be Holdings or a Restricted Subsidiary;

(11) loans and advances to officers, directors, managers or employees for business related travel expenses, moving expenses and other similar expenses, in each case Incurred in the ordinary course of business or consistent with past practice or to fund such person’s purchase of Equity Interests of Holdings or any direct or indirect parent of Holdings;

(12) Investments the payment for which consists of Equity Interests of Holdings (other than Disqualified Stock) or any direct or indirect parent of Holdings, as applicable;provided, however, that such Equity Interests will not increase the amount available for Restricted Payments under clause (3) of the definition of Cumulative Credit contained in “—Certain Covenants—Limitation on Restricted Payments”;

(13) any transaction to the extent it constitutes an Investment that is permitted by and made in accordance with the provisions of the second paragraph of the covenant described under “—Certain Covenants—Transactions with Affiliates” (except transactions described in clauses (2), (4), (6), (9)(b) and (16) of such paragraph);

(14) Investments consisting of the licensing or contribution of intellectual property pursuant to joint marketing arrangements with other Persons;

(15) (x) guarantees issued in accordance with the covenants described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and “—Certain Covenants—Future Guarantors,” including, without limitation, any guarantee or other obligation issued or Incurred under the Credit Agreement in connection with any letter of credit issued for the account of Holdings or any of its Subsidiaries (including with respect to the issuance of, or payments in respect of drawings under, such letters of credit) and (y) guarantees of performance or other obligations (other than Indebtedness) arising in the ordinary course in the Oil and Gas Business, including obligations under Hydrocarbon exploration, development, joint operating and related agreements and licenses, concessions or operating leases related to the Oil and Gas Business;

(16) Investments consisting of or to finance purchases and acquisitions of inventory, supplies, materials, services or equipment or purchases of contract rights or licenses or leases of intellectual property;

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(17) [reserved];

(18) [reserved];

(19) [reserved];

(20) Investments of a Restricted Subsidiary acquired after the Issue Date or of an entity merged into, amalgamated with, or consolidated with Holdings or a Restricted Subsidiary in a transaction that is not prohibited by the first paragraph of the covenant described under “—Certain Covenants—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets” after the Issue Date to the extent that such Investments were not made in contemplation of such acquisition, merger, amalgamation or consolidation and were in existence on the date of such acquisition, merger, amalgamation or consolidation;

(21) any Investment in any Subsidiary of Holdings or any joint venture in connection with intercompany cash management arrangements or related activities arising in the ordinary course of business; and

(22) Permitted Business Investments.

“Permitted Liens” means, with respect to any Person:

(1) pledges or deposits by such Person under workmen’s compensation laws, unemployment insurance laws or similar legislation, or good faith deposits in connection with bids, tenders, contracts (other than for the payment of Indebtedness) or leases to which such Person is a party, or deposits to secure plugging and abandonment obligations or public or statutory obligations of such Person or deposits of cash or U.S. government bonds to secure surety or appeal bonds to which such Person is a party, or deposits as security for contested taxes or import duties or for the payment of rent, in each case Incurred in the ordinary course of business;

(2) Liens imposed by law, such as landlord’s, carriers’, warehousemen’s, mechanics’, materialmen’s, repairmen’s, construction or other like Liens securing obligations that are not overdue by more than 30 days or that are being contested in good faith by appropriate proceedings or other Liens arising out of judgments or awards against such Person with respect to which such Person shall then be proceeding with an appeal or other proceedings for review;

(3) Liens for taxes, assessments or other governmental charges not yet due or payable or that are being contested in good faith by appropriate proceedings;

(4) Liens (A) in favor of issuers of performance and surety bonds or bid bonds or with respect to other regulatory requirements or letters of credit issued pursuant to the request of and for the account of such Person in the ordinary course of its business and (B) securing other obligations in respect of surety and bonding requirements in connection with the Transactions;

(5) minor survey exceptions, minor encumbrances, easements or reservations of, or rights of others for, licenses,rights-of-way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning or other restrictions as to the use of real properties or Liens incidental to the conduct of the business of such Person or to the ownership of its properties which were not Incurred in connection with Indebtedness and which do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of such Person;

(6) (A) Liens on assets of a Restricted Subsidiary that is not a Subsidiary Guarantor securing Indebtedness of such Restricted Subsidiary permitted to be Incurred pursuant to the covenant described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

(B) Liens securing Indebtedness Incurred under the Credit Agreement, including any letter of credit facility relating thereto, that was permitted to be incurred under clause (a) of the second paragraph described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

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(C) Liens securing Indebtedness permitted to be Incurred pursuant to clause (p) of the second paragraph of the covenant described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”; provided that in the case of clause (p), such Lien extends only to the assets acquired and, after giving effect to such acquisition, on a pro forma basis, the Fixed Charge Coverage Ratio of Holdings for the most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is Incurred or such Disqualified Stock or Preferred Stock is issued would have been at least 2.25 to 1.00;

(D) Liens securing the Notes Obligations issued on the Issue Date; and

(E) Liens securing Other Second-Lien Obligations permitted to be Incurred pursuant to clause (d) of the second paragraph of the covenant described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

(7) Liens existing on the Issue Date (other than Liens in favor of the lenders under the Credit Agreement and Liens securing the Notes Obligations);

(8) Liens on assets, property or shares of stock of a Person at the time such Person becomes a Subsidiary;provided,however, that such Liens are not created or Incurred in connection with, or in contemplation of, such other Person becoming such a Subsidiary;provided,further,however, that such Liens may not extend to any other property owned by Holdings or any Restricted Subsidiary;

(9) Liens on assets or property at the time Holdings or a Restricted Subsidiary acquired the assets or property, including any acquisition by means of a merger, amalgamation or consolidation with or into Holdings or any Restricted Subsidiary;provided,however, that such Liens are not created or Incurred in connection with, or in contemplation of, such acquisition;provided,further,however, that the Liens may not extend to any other property owned by Holdings or any Restricted Subsidiary (other than pursuant to after acquired property clauses in effect with respect to such Lien at the time of acquisition on property of the type that would have been subject to such Lien notwithstanding the occurrence of such acquisition);

(10) Liens securing Indebtedness or other obligations of Holdings or a Restricted Subsidiary owing to Holdings or another Restricted Subsidiary permitted to be Incurred in accordance with the covenant described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

(11) Liens securing Hedging Obligations not Incurred in violation of the indenture;provided that with respect to Hedging Obligations relating to Indebtedness, such Lien extends only to the property securing such Indebtedness;

(12) Liens on specific items of inventory or other goods and proceeds of any Person securing such Person’s obligations in respect of bankers’ acceptances issued or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;

(13) leases and subleases of real property which do not materially interfere with the ordinary conduct of the business of Holdings or any of the Restricted Subsidiaries;

(14) Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by Holdings and the Restricted Subsidiaries in the ordinary course of business;

(15) Liens in favor of Holdings or any Subsidiary Guarantor;

(16) [reserved];

(17) deposits made in the ordinary course of business to secure liability to insurance carriers;

(18) Liens on the Equity Interests of Unrestricted Subsidiaries;

(19) grants of software and other technology licenses in the ordinary course of business;

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(20) Liens to secure any refinancing, refunding, extension, renewal or replacement (or successive refinancings, refundings, extensions, renewals or replacements) as a whole, or in part, of any Indebtedness secured by any Lien referred to in the foregoing clauses (6), (7), (8), (9), (10), (11) and (15);provided,however, that (w) such new Lien shall be limited to all or part of the same property that secured the original Lien (plus improvements on such property), (x) the Indebtedness secured by such Lien at such time is not increased to any amount greater than the sum of (A) the outstanding principal amount or, if greater, committed amount of the Indebtedness described under clauses (6), (7), (8), (9), (10), (11) and (15) at the time the original Lien became a Permitted Lien under the indenture, and (B) an amount necessary to pay any interest, premiums or defeasance costs required by the instruments governing such existing Indebtedness (whether such existing Indebtedness is redeemed pursuant to a tender offer, optional redemption or otherwise) and fees and expenses Incurred in connection therewith, (y) if the Indebtedness being refinanced, refunded, extended, renewed or replaced is secured by a Lien that is junior to the Liens securing the notes, such new Lien shall be junior to the Liens securing the notes and (z) if the Indebtedness being refinanced, refunded, extended, renewed or replaced is secured by a lien that is pari passu to the Liens securing the notes, such new Lien shall be either pari passu or junior to the Liens securing the notes;

(21) Liens on equipment of Holdings or any Restricted Subsidiary granted in the ordinary course of business to Holdings’ or such Restricted Subsidiary’s client at which such equipment is located;

(22) judgment and attachment Liens not giving rise to an Event of Default and notices of lis pendens and associated rights related to litigation being contested in good faith by appropriate proceedings and for which adequate reserves have been made;

(23) Liens arising out of conditional sale, title retention, consignment or similar arrangements for the sale of goods entered into in the ordinary course of business;

(24) Liens (A) Incurred to secure cash management services or to implement cash pooling arrangements in the ordinary course of business and (B) on cash and Cash Equivalents and letters of credit securing any surety and bonding requirements;

(25) other Liens securing obligations the outstanding principal amount of which does not, taken together with the principal amount of all other obligations secured by Liens Incurred under this clause (25) that are at that time outstanding, exceed $50.0 million;providedthat First-Priority Lien Obligations and Other Second-Lien Obligations secured under this clause (25) shall be subject to the Senior Lien Intercreditor Agreement and any Junior Lien Obligations and Other Second-Lien Obligations secured under this clause (25) shall be subject to a Customary Intercreditor Agreement;provided, further, that unsecured Indebtedness and Junior Lien Obligations shall not be exchanged for Other Second-Lien Obligations or Indebtedness that is secured on a senior basis to the notes pursuant to this clause (25);

(26) any encumbrance or restriction (including put and call arrangements) with respect to Capital Stock of any joint venture or similar arrangement pursuant to any joint venture or similar agreement;

(27) any amounts held by a trustee in the funds and accounts under an indenture securing any revenue bonds issued for the benefit of Holdings or any Restricted Subsidiary, under any indenture or other debt agreement issued in escrow pursuant to customary escrow arrangements pending the release thereof, or under any indenture or other debt agreement pursuant to customary discharge, redemption or defeasance provisions;

(28) Liens arising by virtue of any statutory or common law provisions relating to banker’s Liens, rights ofset-off or similar rights and remedies as to deposit accounts or other funds maintained with a depository or financial institution;

(29) Liens arising out of judgments or awards against such Person with respect to which such Person shall then be proceeding with any appeal or other proceedings for review;

(30) Liens (i) in favor of credit card companies pursuant to agreements therewith and (ii) in favor of customers;

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(31) Liens in respect of Production Payments and Reserve Sales;

(32) Liens arising underFarm-Out Agreements,Farm-In Agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, joint venture agreements, partnership agreements, operating agreements, royalties, royalty trusts, master limited partnerships, working interests, net profits interests, joint interest billing arrangements, participation agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements which are customary in the Oil and Gas Business;provided, however, in all instances that such Liens are limited to the assets that are the subject of the relevant agreement, program, order, trust, partnership or contract;providedfurther such Liens shall not secure Indebtedness for borrowed money;

(33) Liens on pipelines or pipeline facilities that arise by operation of law;

(34) any (a) interest or title of a lessor or sublessor under any lease, liens reserved in oil, gas or other Hydrocarbons, minerals, leases for bonus, royalty or rental payments and for compliance with the terms of such leases; (b) restriction or encumbrance that the interest or title of such lessor or sublessor may be subject to (including, without limitation, ground leases or other prior leases of the demised premises, mortgages, mechanics’ liens, tax liens and easements); or (c) subordination of the interest of the lessee or sublessee under such lease to any restrictions or encumbrance referred to in the preceding clause (b); and

(35) Liens securing Junior Lien Obligations,provided that the notes are secured on a senior priority basis to the obligations so secured until such time as such obligations are no longer secured by a Lien;provided furtherthat Junior Lien Obligations secured under this clause (35) shall be subject to a Customary Intercreditor Agreement.

“Person” means any individual, corporation, partnership, limited liability company, joint venture, association, joint stock company, trust, unincorporated organization, government or any agency or political subdivision thereof or any other entity.

“Petroleum Industry Standards” shall mean the Definitions for Oil and Gas Reserves promulgated by the Society of Petroleum Engineers (or any generally recognized successor) as in effect at the time in question.

“Post-Petition Claims” means, collectively, interest, fees, costs, expenses and other charges that pursuant to any Credit Agreement Document continue to accrue after the commencement of any Insolvency Proceeding.

“Preferred Stock” means any Equity Interest with preferential right of payment of dividends or upon liquidation, dissolution, or winding up.

“Prior Notes Exchange” means the exchange on April 3, 2017 of the Issuers’ 9.75% Senior Notes due 2018 for the Issuers’ 11.00% Second Lien Bridge Loans.

“Production Payments and Reserve Sales” means the grant or transfer by Holdings or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), partnership or other interest in Oil and Gas Properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including any such grants or transfers.

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“Proved Developed Reserves” shall mean oil and gas reserves that, in accordance with Petroleum Industry Standards, are classified as both “Proved Reserves” and one of the following: (a) “Developed Producing Reserves” or (b) “DevelopedNon-Producing Reserves.”

“Proved Reserves” shall mean oil and gas reserves that, in accordance with Petroleum Industry Standards, are classified as both “Proved Reserves” and one of the following: (a) “Developed Producing Reserves”, (b) “DevelopedNon-Producing Reserves” or (c) “Undeveloped Reserves”.

“Public Parent Company” means any direct or indirect parent company of Holdings that has any class of its Capital Stock listed for trading on a United States national securities exchange.

“PV-10” shall mean, with respect to any Proved Reserves expected to be produced from any Oil and Gas Properties, the net present value, discounted at 10% per annum, of the future net revenues expected to accrue to the Issuers’ and the Subsidiary Guarantors’ collective interests in such reserves during the remaining expected economic lives of such reserves, calculated in accordance with the most recent Bank Price Deck (as defined in the Credit Agreement) provided to Holdings by the administrative agent under the Credit Agreement governing Indebtedness incurred under clause (a) of the second paragraph described under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” pursuant to Section 2.14(i) of such Credit Agreement (or any analogous provision).

“Rating Agency” means (1) each of Moody’s and S&P and (2) if Moody’s or S&P ceases to rate the notes for reasons outside of Holdings’ control, a “nationally recognized statistical rating organization” within the meaning of Rule17g-1 under the Exchange Act selected by Holdings or any direct or indirect parent of Holdings as a replacement agency for Moody’s or S&P, as the case may be.

“RBL Agent” means the agent for secured parties holding First-Priority Lien Obligations, as appointed pursuant to the Senior Lien Intercreditor Agreement. The RBL Agent is initially the administrative agent under the Credit Agreement.

“Registration Rights Agreement” means, with respect to the Initial Notes issued on the Issue Date, the Registration Rights Agreement dated the Issue Date, among the Issuers, the Subsidiary Guarantors party thereto and certain holders of the notes.

“Reserve Report” shall mean a reserve engineers’ report, internally prepared by Holdings and audited by an Approved Petroleum Engineer, with respect to the Oil and Gas Properties of the Issuers and the Subsidiary Guarantors, or any other reserve report in form and substance reasonably equivalent (as determined in good faith by Holdings), setting forth, as of each June 30th or December 31st the Proved Reserves and the Proved Developed Reserves attributable to the Oil and Gas Properties of the Issuers and the Subsidiary Guarantors, together with a projection of the rate of production and future net revenues, operating expenses (including production taxes and ad valorem expenses) and capital expenditures with respect thereto as of such date, based upon the most recent Bank Price Deck (as defined in the Credit Agreement) provided to Holdings by the administrative agent under the Credit Agreement pursuant to Section 2.14(i) thereof (or any analogous provision).

“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Subsidiary” means, with respect to any Person, any Subsidiary of such Person other than an Unrestricted Subsidiary of such Person. Unless otherwise indicated in this “Description of the Notes,” all references to Restricted Subsidiaries shall mean Restricted Subsidiaries of Holdings.

“S&P” means S&P Global Ratings or any successor to the rating agency business thereof.

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“Sale/Leaseback Transaction” means an arrangement relating to property now owned or hereafter acquired by Holdings or a Restricted Subsidiary whereby Holdings or such Restricted Subsidiary transfers such property to a Person and Holdings or such Restricted Subsidiary leases it from such Person, other than leases between Holdings and a Restricted Subsidiary or between Restricted Subsidiaries.

“SEC” means the Securities and Exchange Commission.

“Second Priority Lien Obligations” means (a) the Notes Obligations and (b) all Other Second-Lien Obligations.

“Secured Bank Indebtedness” means any Bank Indebtedness that is secured by a Permitted Lien Incurred or deemed Incurred pursuant to (i) clause (6)(B) of the definition of Permitted Liens or (ii) clause (25) of the definition of Permitted Liens that is secured by Liens on the Collateral that are pari passu with the Liens securing Indebtedness described in clause (i).

“Secured Indebtedness” means any Consolidated Total Indebtedness secured by a Lien.

“Secured Parties” means, collectively, the Trustee, the Collateral Agent and the holders of the notes.

“Securities Act” means the Securities Act of 1933, as amended, and the rules and regulations of the SEC promulgated thereunder.

“Security Documents” means the security agreements, pledge agreements, collateral assignments, mortgages and related agreements, as amended, supplemented, restated, renewed, refunded, replaced, restructured, repaid, refinanced or otherwise modified from time to time, creating the security interests in the Collateral for the benefit of the Collateral Agent and the other Secured Parties as contemplated by the indenture.

“Senior Lien Intercreditor Agreement” means (i) the intercreditor agreement among the RBL Agent, the Collateral Agent, and the other parties from time to time party thereto, entered into on the Issue Date, as it may be amended, restated, supplemented or otherwise modified from time to time or (ii) any replacement thereof that contains terms not materially less favorable to the holders of the notes than the intercreditor agreement referred to in clause (i).

“Significant Subsidiary” means any Restricted Subsidiary that would be a “Significant Subsidiary” of Holdings within the meaning of Rule1-02 under RegulationS-X promulgated by the SEC (or any successor provision).

“Similar Business” means a business, the majority of whose revenues are derived from the activities of Holdings and its Subsidiaries as of the Issue Date or any business or activity that is reasonably similar or complementary thereto or a reasonable extension, development or expansion thereof or ancillary thereto.

“Significant Issue Date Equityholders” means (i) each of Apollo Global Management, LLC, Riverstone Holdings LLC, Franklin Advisers, Inc., MacKay Shields LLC and any of their respective Affiliates other than any portfolio companies (collectively, the “Equity Investor”) and (ii) any Person that forms a group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, or any successor provision) with the Equity Investor;provided that the Equity Investor (x) owns a majority of the voting power and (y) controls a majority of the Board of Directors of Holdings.

“Stated Maturity” means, with respect to any security, the date specified in such security as the fixed date on which the final payment of principal of such security is due and payable, including pursuant to any mandatory redemption provision (but excluding any provision providing for the repurchase of such security at the option of the holder thereof upon the happening of any contingency beyond the control of the issuer unless such contingency has occurred).

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“Stone Notes” means the 7.500% Senior Secured Notes due 2022 issued by Stone Energy Corporation pursuant to that certain indenture, dated as of February 28, 2017, by and among Stone Energy Corporation, as issuer thereunder, Stone Energy Offshore, L.L.C., as subsidiary guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee.

“Subordinated Indebtedness” means (a) with respect to an Issuer, any Indebtedness of such Issuer which is by its terms subordinated in right of payment to the notes, and (b) with respect to any Subsidiary Guarantor, any Indebtedness of such Subsidiary Guarantor which is by its terms subordinated in right of payment to its Subsidiary Guarantee.

“Subsidiary” means, with respect to any Person, (1) any corporation, association or other business entity (other than a partnership, joint venture or limited liability company) of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof is at the time of determination owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person or a combination thereof, and (2) any partnership, joint venture or limited liability company of which (x) more than 50% of the capital accounts, distribution rights, total equity and voting interests or general and limited partnership interests, as applicable, are owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person or a combination thereof, whether in the form of membership, general, special or limited partnership interests or otherwise, and (y) such Person or any Subsidiary of such Person is a controlling general partner or otherwise controls such entity.

“Subsidiary Guarantee” means any guarantee of the obligations of the Issuers under the indenture and the notes by any Subsidiary Guarantor in accordance with the provisions of the indenture.

“Subsidiary Guarantor” means any Subsidiary that Incurs a Subsidiary Guarantee;provided that upon the release or discharge of such Person from its Subsidiary Guarantee in accordance with the indenture, such Subsidiary ceases to be a Subsidiary Guarantor.

“Tax Distributions” means any distributions described in clause (12) of the covenant entitled “—Certain Covenants—Limitation on Restricted Payments.”

“Test Period” means on any date of determination, four consecutive fiscal quarters of Holdings then last ended (taken as one accounting period) for which financial statements have been delivered pursuant to the first paragraph under “—Certain Covenants— Reports and Other Information”;provided that prior to the first date financial statements have been delivered pursuant to the first paragraph under “—Certain Covenants— Reports and Other Information,” the Test Period in effect shall be the four fiscal quarter period ended December 31, 2017.

“Total Assets” means the total consolidated assets of Holdings and the Restricted Subsidiaries, as shown on the most recent balance sheet of Holdings, without giving effect to any amortization of the amount of intangible assets since September 30, 2012, calculated on apro forma basis after giving effect to any subsequent acquisition or disposition of a Person or business.

“Transaction Expenses” means any fees or expenses incurred or paid by Holdings or any of its Subsidiaries in connection with the Transactions, the indenture and the other Notes Documents and the transactions contemplated thereby.

“Transactions” means, collectively, (i) the Prior Notes Exchange, (ii) the combination of Talos Energy LLC and its subsidiaries with Stone Energy Corporation pursuant to the Transaction Agreement, dated as of November 21, 2017 and (iii) the execution and delivery of the indenture, the payment of Transaction Expenses and the other transactions contemplated by the Transaction Agreement, the Debt Exchange Agreement, the indenture and the Notes Documents.

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“Trust Officer” means:

(1) any officer within the corporate trust department of the Trustee, including any vice president, assistant vice president, trust officer, assistant trust officer or any other officer of the Trustee who customarily performs functions similar to those performed by the Persons who at the time shall be such officers, respectively, or to whom any corporate trust matter is referred because of such person’s knowledge of and familiarity with the particular subject and who will have direct responsibility for the administration of the indenture, and

(2) who shall have direct responsibility for the administration of the indenture.

“Trustee” means the party named as such in the indenture until a successor replaces it and, thereafter, means the successor.

“Uniform Commercial Code” or “UCC” means the New York Uniform Commercial Code as in effect from time to time.

“Unrestricted Subsidiary” means:

(1) any Subsidiary of Holdings that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of Holdings in the mannerprovided below; and

(2) any Subsidiary of an Unrestricted Subsidiary;

Holdings may designate any Subsidiary of Holdings (including any newly acquired or newly formed Subsidiary) to be an Unrestricted Subsidiary unless such Subsidiary or any of its Subsidiaries owns any Equity Interests or Indebtedness of, or owns or holds any Lien on any property of, Holdings or any other Subsidiary of Holdings that is not a Subsidiary of the Subsidiary to be so designated;provided,however, that

(i) the Subsidiary to be so designated and its Subsidiaries do not at the time of designation have and do not thereafter Incur any Indebtedness pursuant to which the lender has recourse to any of the assets of Holdings or any of the Restricted Subsidiaries (other than pursuant to customary Liens or related arrangements under any oil and gas royalty trust or master limited partnership); and

(ii)   (a) the Subsidiary to be so designated has total consolidated assets of $1,000 or less; or

(b) if such Subsidiary has consolidated assets greater than $1,000, then such designation would be permitted under the covenant described under “—Certain Covenants—Limitation on Restricted Payments.”

Holdings may designate any Unrestricted Subsidiary to be a Restricted Subsidiary;provided,however, that immediately after giving effect to such designation:

(x) (1) Holdings could Incur $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test described in the first paragraph under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock,” or (2) the Fixed Charge Coverage Ratio of Holdings and its Restricted Subsidiaries would be no less than such ratio immediately prior to such designation, in each case on apro forma basis taking into account such designation, and

(y) no Event of Default shall have occurred and be continuing.

Any such designation by Holdings shall be evidenced to the Trustee by promptly filing with the Trustee a copy of the resolution of the Board of Directors or any committee thereof of Holdings giving effect to such designation and an Officers’ Certificate certifying that such designation complied with the foregoing provisions.

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“U.S. Government Obligations” means securities that are:

(1) direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged, or

(2) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America, the timely payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States of America,

which, in each case, are not callable or redeemable at the option of the issuer thereof, and shall also include a depository receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act) as custodian with respect to any such U.S. Government Obligations or a specific payment of principal of or interest on any such U.S. Government Obligations held by such custodian for the account of the holder of such depository receipt;provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the U.S. Government Obligations or the specific payment of principal of or interest on the U.S. Government Obligations evidenced by such depository receipt.

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertaking and obligations in connection therewith.

“Voting Stock” of any Person as of any date means the Capital Stock of such Person that is at the time entitled to vote in the election of the Board of Directors of such Person.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness or Disqualified Stock or Preferred Stock, as the case may be, at any date, the quotient obtained by dividing (1) the sum of the products of the number of years from the date of determination to the date of each successive scheduled principal payment of such Indebtedness or redemption or similar payment with respect to such Disqualified Stock or Preferred Stock multiplied by the amount of such payment, by (2) the sum of all such payments.

“Wholly Owned Restricted Subsidiary” is any Wholly Owned Subsidiary that is a Restricted Subsidiary.

“Wholly Owned Subsidiary” of any Person means a Subsidiary of such Person 100% of the outstanding Capital Stock or other ownership interests of which (other than directors’ qualifying shares or shares required pursuant to applicable law) shall at the time be owned by such Person or by one or more Wholly Owned Subsidiaries of such Person.

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CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS

The following discussion is a summary of certain U.S. federal income tax considerations relevant to the exchange of Initial Notes for Exchange Notes, but does not purport to be a complete analysis of all potential tax effects. The discussion is based upon the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of Exchange Notes. We cannot assure you that the Internal Revenue Service will not challenge one or more of the tax consequences described in this discussion, and we have not obtained, nor do we intend to obtain, a ruling from the Internal Revenue Service or an opinion of counsel with respect to the U.S. federal income tax consequences described herein. Some holders, including financial institutions, dealers in securities or currencies, traders that mark to market, former citizens or long-term residents of the United States, persons who hold their Initial Notes as part of a hedge, straddle or conversion transaction, insurance companies, regulated investment companies, real estate investment trusts, entities treated as partnerships for U.S. federal income tax purposes and holders of interests therein, persons whose functional currency is not the U.S. dollar, persons subject to the alternative minimum tax, ortax-exempt entities may be subject to special rules not discussed below.

We believe that the exchange of the Initial Notes for the Exchange Notes will not be an exchange or otherwise a taxable event to a holder for U.S. federal income tax purposes. Accordingly, a holder will not recognize gain or loss upon receipt of an Exchange Note in exchange for an Initial Note in the exchange, and the holder’s basis and holding period in the Exchange Note will be the same as its basis and holding period in the corresponding Initial Note immediately before the exchange.

We recommend that each holder consult its own tax advisor as to the particular tax consequences of exchanging such holder’s Initial Notes for Exchange Notes, including the applicability and effect of any foreign, state, local or other tax laws or U.S. federal estate or gift tax considerations.

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PLAN OF DISTRIBUTION

Each broker-dealer that receives Exchange Notes for its own account pursuant to the Exchange Offer in exchange for Initial Notes acquired as a result of market making or other trading activities may be deemed to be an “underwriter” within the meaning of the Securities Act and, therefore, must deliver a prospectus (or, to the extent permitted by law, make available a prospectus to purchasers) meeting the requirements of the Securities Act in connection with any resales, offers to resell or other transfers of the Exchange Notes received by it in connection with the Exchange Offer. Accordingly, each such broker-dealer must acknowledge in the letter of transmittal that it will deliver a prospectus (or, to the extent permitted by law, make available a prospectus to purchasers) meeting the requirements of the Securities Act in connection with any resale of such Exchange Notes. The letter of transmittal states that by acknowledging that it will deliver, and by delivering a prospectus (or, to the extent permitted by law, make available a prospectus to purchasers), a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

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 as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the expiration of this Exchange Offer, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale or to any broker-dealer that requests such documents in the letter of transmittal.

We will not receive any proceeds from any sale of Exchange Notes by broker-dealers. Exchange Notes received by broker-dealers for their own account pursuant to this Exchange Offer may be sold from time to time in one or more transactions in theover-the-counter market, in negotiated transactions, through the writing of options on the Exchange Notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer and/or the purchasers of any such Exchange Notes. Any broker-dealer that resells Exchange Notes that were received by it for its own account pursuant to this Exchange Offer and any broker or dealer that participates in a distribution of such Exchange Notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of Exchange Notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act.

We have agreed to pay all expenses incident to the Exchange Offer other than commissions or concessions or fees and expenses of counsel of any brokers or dealers.

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LEGAL MATTERS

Paul, Weiss, Rifkind, Wharton & Garrison LLP, New York, New York, will pass on the validity of the Exchange Notes and guarantees offered in this Exchange Offer.    

EXPERTS

Talos Energy

The consolidated financial statements of Talos Energy Inc. (formerly known as Talos Energy LLC) for the years ended December 31, 2017 and 2016 appearing in this registration statement (form S-4) and prospectus, have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon, included therein. Such consolidated financial statements are included herein in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

Prior to the Transactions, Talos Energy Inc. (“Talos Energy”) was controlled by Apollo Global Management, LLC (“Apollo”) through May 10, 2018. Talos Energy and its historical financial statements were not subject to the U.S. Securities and Exchange Commission (“SEC”) and Public Company Accounting Oversight Board (United States) (“PCAOB”) auditor independence rules. The historical financial statements of Talos Energy, the target for purposes of the Transactions, were conducted in accordance with U.S. generally accepted auditing standards and subject to the American Institute of Certified Public Accountants (“AICPA”) independence rules. Upon completion of the Transactions, Talos Energy was deemed the accounting acquirer and as such, its historical 2015, 2016 and 2017 financial statements were required to be presented as the predecessor in subsequent SEC filings, audited in accordance with PCAOB audit standards, and subject to SEC auditor independence rules. Ernst & Young LLP (“EY”) converted their historical audits of Talos Energy to SEC and PCAOB standards.

In November 2016, a fund controlled by Apollo acquired a controlling interest in a company unrelated to Talos Energy (Apollo portfolio company or “APC”) resulting in APC becoming an affiliate of Talos Energy by virtue of being under common control and subject to the SEC and PCAOB auditor independence rules relative to EY’s audits of Talos Energy’s consolidated financial statements conducted in accordance with the PCAOB standards. EY has provided certain non-audit advisory services for APC, including managed services and a tax service that included a contingent fee arrangement. Once APC became an affiliate of Talos Energy in November 2016, the managed services and the contingent fee arrangement provided to APC was inconsistent with the SEC’s and PCAOB’s auditor independence rules relative to EY’s audits of Talos Energy’s consolidated financial statements pursuant to PCAOB standards. The managed services were terminated and the contingent fee arrangement was converted to an appropriate fee arrangement in November 2017. Fees from these engagements from November 2016 to November 2017 were not material to EY or APC. None of the professionals who provided or were involved with the aforementioned engagements were or are a member of the EY audit engagement team with respect to the PCAOB audits of Talos Energy’s consolidated financial statements. The operations and related financial results of APC had no impact on Talos Energy’s operations or its consolidated financial statements. The managed services and contingent fee arrangement were not in any way related to the operations, and did not affect, the consolidated financial statements of Talos Energy. In addition, the results of the managed services and contingent fee arrangement were not subject to audit by EY.

In April 2018, it was determined that a service team in EY France ( EY member firm) provided internal audit co-sourcing services during November and December 2017 to an Apollo portfolio company (“APC 2”) controlled by an Apollo fund and thus an affiliate of Talos Energy by virtue of being under common control. The service ceased in December 2017. Fees from this engagement were not material to EY or APC 2. None of the professionals who provided or were involved with the aforementioned engagement were or are a member of the EY audit engagement team with respect to the PCAOB audits of Talos Energy’s consolidated financial

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statements. The operations and related financial results of APC 2 had no impact on Talos Energy’s operations or its consolidated financial statements. The co-sourcing services were not in any way related to the operations, and did not affect, the consolidated financial statements of Talos Energy. In addition, the results of the co-sourcing services were not subject to audit by EY.

In 2016, a staff level employee of EY in the United States provided audit services to Talos Energy while holding a de minimis financial relationship with an affiliate of Talos Energy. Additionally, during 2016 and 2017, four employees of EY or an associated firm held financial relationships with certain affiliates of Talos Energy while providing non-audit services to other sister affiliates of Talos Energy. Each of these individuals were deemed to be covered persons pursuant to the SEC and PCAOB independence rules as it pertains to EY’s audits of Talos Energy performed pursuant to PCAOB standards. None of the financial relationships related to investments in Talos Energy. These matters had no impact on Talos Energy’s operations or its consolidated financial statements. Upon identification of the covered person financial relationship matters, the respective financial relationships were either disposed of or rolled over, or the individual was removed from the related non-audit service engagement team.

In 2017 and 2018, two EY professionals provided non-audit services to sister affiliates of Talos Energy causing them to be deemed covered persons pursuant to the SEC and PCAOB independence rules as it pertains to EY’s audits of Talos Energy performed pursuant to PCAOB standards. The EY professionals reported part-time dual employment with another sister affiliate of Talos Energy. Under the SEC and PCAOB auditor independence rules, covered persons cannot have employment relationships with an audit client or any affiliate of the audit client. Neither of these individuals provided service to Talos Energy. These matters had no impact on Talos Energy’s operations or its consolidated financial statements. Upon identification of the covered person employment relationship matters, the respective employment relationships were terminated in late 2017 and early 2018, respectively.

After careful consideration of the facts and circumstances and the applicable independence rules, EY has concluded that (i) the aforementioned matters will not impair EY’s ability to exercise objective and impartial judgment in connection with its audits of Talos Energy’s consolidated financial statements and (ii) a reasonable investor with knowledge of all relevant facts and circumstances would conclude that EY has been and is capable of exercising objective and impartial judgment on all issues encompassed within its audit engagements.

The Talos Energy Board has reviewed and considered the impact that these matters may have on EY’s independence with respect to Talos Energy under the applicable SEC and PCAOB independence rules. After considering all the facts and circumstances, the Talos Energy Board concluded that these matters have not and will not impair EY’s ability to exercise objective and impartial judgment on all issues encompassed with their audit engagements and a reasonable investor with knowledge of all relevant facts and circumstances would reach the same conclusion.

Reserve Engineers

Certain information with respect to the oil and gas reserves associated with Talos Energy’s oil and natural gas properties that is derived from the reports of Netherland, Sewell & Associates, Inc (“NSAI”) and Ryder Scott Company, L.P. has been included in this prospectus upon the authority of said firm as an expert with respect to the matters covered by such report and in giving such report.

Stone Energy

The consolidated financial statements of Stone Energy Corporation as of December 31, 2017 (Successor) and 2016 (Predecessor) and for the period March 1, 2017 through December 31, 2017 (Successor), the period January 1, 2017 through February 28, 2017 (Predecessor), and the years ended December 31, 2016 and 2015 (Predecessor), appearing in this Prospectus and Registration Statement, have been audited by Ernst & Young

237

LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

Estimates of Stone Energy Corporation’s oil and natural gas reserves related to Stone Energy Corporation’s properties as of December 31, 2017 included in this prospectus were based upon reserve reports prepared by independent petroleum engineers, NSAI. These estimates have been included in this prospectus upon the authority of such firm as an expert in such matters.

238

WHERE YOU CAN FIND MORE INFORMATION

We are subject to the informational requirements of the Exchange Act and file reports, proxy statements and other information with the SEC. We have also filed with SEC a registration statement on FormS-4 to register the Exchange Notes. This prospectus, which forms part of the registration statement, does not contain all of the information included in that registration statement. For further information about us and the Exchange Notes offered in this prospectus, including the indenture governing the Notes and the form of Notes, you should refer to the registration statement and its exhibits. You may read and copy any of the documents that we file, with the SEC at the SEC’s Public Reference Room, 100 F Street, N.E., Washington, D.C. 20549. Copies of these reports, proxy statements and other information that we file with the SEC may be obtained at prescribed rates from the Public Reference Section of the SEC at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at1-800-SEC-0330 for further information on the operation of the Public Reference Room. In addition, the SEC maintains a web site that contains reports, proxy statements and other information regarding registrants, such as us, that file electronically with the SEC. The address of this web site is http://www.sec.gov.

We have not authorized anyone to provide you with any information other than that contained in this prospectus or in a document to which we expressly have referred you. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. You should assume that the information appearing in this prospectus is accurate only as of the date on the front cover of this prospectus.

239

INDEX TO FINANCIAL STATEMENTS

Talos Energy Inc. (formerly known as Talos Energy LLC)
Consolidated Financial Statements of Talos Energy Inc. for the year ended December 31, 2017
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets	F-3
Consolidated Statements of Operations	F-4
Consolidated Statements of Changes in Equity	F-5
Consolidated Statements of Cash Flows	F-6
Notes to Consolidated Financial Statements	F-7
Unaudited Condensed Consolidated Financial Statements of Talos Energy Inc. for the six months ended June 30, 2018
Condensed Consolidated Balance Sheets	F-44
Condensed Consolidated Statements of Operations	F-45
Condensed Consolidated Statements of Changes in Equity	F-46
Condensed Consolidated Statements of Cash Flows	F-47
Notes to Unaudited Condensed Consolidated Financial Statements	F-48
Unaudited Pro Forma Condensed Combined Statement of Operations for the year ended December 31, 2017	F-74
Notes to the Unaudited Pro Forma Condensed Combined Statement of Operations for the year ended December 31, 2017	F-75
Unaudited Pro Forma Condensed Combined Statement of Operations for the six months ended June 30, 2018	F-83
Notes to the Unaudited Pro Forma Condensed Combined Statement of Operations for the six months ended June 30, 2018	F-84
Stone Energy Corporation
Report of Independent Registered Public Accounting Firm	F-86
Consolidated Balance Sheet as December 31, 2017 and 2016	F-87
Consolidated Statement of Operations for the Period March  1, 2017 through December 31, 2017, the Period January 1, 2017 through February 28, 2017 and the Years Ended December 31, 2016 and 2015	F-88
Consolidated Statement of Comprehensive Income (Loss) for the Period March 1, 2017 through December 31, 2017, the Period January 1, 2017 through February 28, 2017 and the Years Ended December 31, 2016 and 2015	F-89
Consolidated Statement of Changes in Stockholders’ Equity for the Period March 1, 2017 through December 31, 2017, the Period January 1, 2017 through February 28, 2017 and the Years ended December 31, 2016 and 2015	F-90
Consolidated Statement of Cash Flows for the Period March  1, 2017 through December 31, 2017, the Period January 1, 2017 through February 28, 2017 and the Years Ended December 31, 2016 and 2015	F-91
Notes to Consolidated Financial Statements	F-92
Condensed Consolidated Balance Sheet as of March  31, 2018 and December 31, 2017	F-140
Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2018, the Period March 1, 2017 through March 31, 2017 and the Period January 1, 2017 through February 28, 2017	F-141
Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2018, the Period March 1, 2017 through December 31, 2017 and the Period January 1, 2017 through February 28, 2017	F-142
Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2018, the Period March 1, 2017 through March 31, 2017 and the Period January 1, 2017 through February 28, 2017	F-143
Notes to Condensed Consolidated Financial Statements	F-144

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Talos Energy Inc. (formerly known as Talos Energy LLC)

Opinion on the Financial Statements:

We have audited the accompanying consolidated balance sheets of Talos Energy Inc. (formerly known as Talos Energy LLC), (the Company) as of December 31, 2017 and 2016, the related statements of consolidated operations, changes in equity and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion:

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2010.

Houston, Texas

March 14, 2018, except for Note 11 and Note 15, as to which the date is September 14, 2018.

F-2

TALOS ENERGY INC.

(FORMERLY KNOWN AS TALOS ENERGY LLC)

CONSOLIDATED BALANCE SHEETS

(In thousands)

	Year Ended December 31,
	2017			2016
ASSETS
Current assets:
Cash and cash equivalents	$	32,191		$	32,231
Restricted cash		1,242			1,202
Accounts receivable
Trade, net		62,871			52,764
Joint interest, net		13,613			14,673
Other		12,486			12,400
Assets from price risk management activities		1,563			20,176
Prepaid assets		17,931			18,420
Inventory		840			1,093
Other current assets		2,148			2,492
Total current assets		144,885			155,451
Property and equipment:
Proved properties		2,440,811			2,235,835
Unproved properties, not subject to amortization		72,002			72,360
Other property and equipment		8,857			8,531
Total property and equipment		2,521,670			2,316,726
Accumulated depreciation, depletion and amortization		(1,430,890	)		(1,273,538	)
Total property and equipment, net		1,090,780			1,043,188
Other long-term assets:
Assets from price risk management activities		345			293
Other well equipment		2,577			12,744
Other assets		706			622
Total assets	$	1,239,293		$	1,212,298
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	72,681		$	31,230
Accrued liabilities		87,973			49,916
Accrued royalties		24,208			23,293
Current portion of long-term debt		24,977			—
Current portion of asset retirement obligations		39,741			33,556
Liabilities from price risk management activities		49,957			27,147
Accrued interest payable		8,742			11,376
Other current liabilities		15,188			14,666
Total current liabilities		323,467			191,184
Long-term debt, net of discount and deferred financing costs		672,581			701,175
Asset retirement obligations		174,992			186,493
Liabilities from price risk management activities		18,781			8,755
Other long-term liabilities		103,559			117,705
Total liabilities		1,293,380			1,205,312
Commitments and contingencies (Note 10)
Equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of December 31, 2017 and December 31, 2016		—			—
Common stock $0.01 par value; 270,000,000 shares authorized; 31,244,085 shares issued and outstanding as of December 31, 2017 and December 31, 2016		312			312
Additional paid-in capital		489,870			489,870
Accumulated deficit		(544,269	)		(483,196	)
Total stockholders’ equity (deficit)		(54,087	)		6,986
Total liabilities and equity	$	1,239,293		$	1,212,298

F-3

TALOS ENERGY INC.

(FORMERLY KNOWN AS TALOS ENERGY LLC)

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

	Year Ended December 31,
	2017			2016			2015
Revenues:
Oil revenue	$	344,781		$	197,583		$	244,167
Natural gas revenue		48,886			42,705			55,026
NGL revenue		16,658			9,532			10,523
Other		2,503			8,934			5,890
Total revenue		412,828			258,754			315,606
Operating expenses:
Direct lease operating expense		109,180			124,360			171,095
Insurance		10,743			13,101			17,965
Production taxes		1,460			1,958			3,311
Total lease operating expense		121,383			139,419			192,371
Workover and maintenance expense		32,825			24,810			29,752
Depreciation, depletion and amortization		157,352			124,689			212,689
Write-down of oil and natural gas properties		—			—			603,388
Accretion expense		19,295			21,829			19,395
General and administrative expense		36,673			28,686			35,662
Total operating expenses		367,528			339,433			1,093,257
Operating income (loss)		45,300			(80,679	)		(777,651	)
Interest expense		(80,934	)		(70,415	)		(51,544	)
Price risk management activities income (expense)		(27,563	)		(57,398	)		182,196
Other income		329			405			314
Net loss	$	(62,868	)	$	(208,087	)	$	(646,685	)
Net income (loss) per common share:
Basic	$	(2.01	)	$	(7.99	)	$	(26.20	)
Diluted	$	(2.01	)	$	(7.99	)	$	(26.20	)
Weighted average common shares outstanding:
Basic		31,244			26,036			24,685
Diluted		31,244			26,036			24,685

F-4

TALOS ENERGY INC.

(FORMERLY KNOWN AS TALOS ENERGY LLC)

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(In thousands)

	Common Stock		Additional Paid-In Capital		Retained Earnings (Accumulated Deficit)			Total Stockholders’ Equity (Deficit)
Balance at January 1, 2015	$	215	$	324,576	$	365,711		$	690,502
Contributions from Sponsors, net		43		73,457		—			73,500
Equity based compensation		—		—		3,578			3,578
Net loss		—		—		(646,685	)		(646,685	)
Balance at December 31, 2015		258		398,033		(277,396	)		120,895
Contributions from Sponsors, net		54		91,837		—			91,891
Equity based compensation		—		—		2,287			2,287
Net loss		—		—		(208,087	)		(208,087	)
Balance at December 31, 2016		312		489,870		(483,196	)		6,986
Equity based compensation		—		—		1,795			1,795
Net loss		—		—		(62,868	)		(62,868	)
Balance at December 31, 2017	$	312	$	489,870	$	(544,269	)	$	(54,087	)

F-5

TALOS ENERGY INC.

(FORMERLY KNOWN AS TALOS ENERGY LLC)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2017			2016			2015
Cash flows from operating activities:
Net loss	$	(62,868	)	$	(208,087	)	$	(646,685	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion, amortization and accretion expense		176,647			146,518			232,084
Write-down of oil and natural gas properties		—			—			603,388
Impairment		260			218			2,106
Amortization of deferred financing costs and original issue discount		2,383			5,996			4,955
Equity based compensation, net of amounts capitalized		875			1,083			1,719
Price risk management activities (income) expense		27,563			57,398			(182,196	)
Net cash receipts on settled derivative instruments		23,834			172,182			181,927
Settlement of asset retirement obligations		(32,573	)		(23,689	)		(79,798	)
Changes in operating assets and liabilities:
Accounts receivable		(9,132	)		(20,096	)		32,231
Other current assets		(4,441	)		(3,040	)		9,244
Accounts payable		2,409			(68,042	)		(77,022	)
Other current liabilities		46,364			51,240			55,659
Other non-current assets and liabilities, net		4,732			4,442			754
Net cash provided by operating activities		176,053			116,123			138,366
Cash flows from investing activities:
Exploration, development and other capital expenditures		(155,177	)		(113,032	)		(245,716	)
Cash paid for acquisitions, net of cash acquired		(2,464	)		(85,886	)		(39,423	)
Net cash used in investing activities		(157,641	)		(198,918	)		(285,139	)
Cash flows from financing activities:
Redemption of 2018 Senior Notes		(1,000	)		—			—
Proceeds from Bank Credit Facility		10,000			15,000			120,000
Repayment of Bank Credit Facility		(15,000	)		(10,000	)		(30,000	)
Repayment of GCER Bank Credit Facility		—			—			(55,000	)
Deferred financing costs		—			—			(269	)
Payments of capital lease		(12,412	)		(5,267	)		—
Contributions from Sponsors		—			93,750			75,000
Distributions to Sponsors		—			(1,859	)		(1,500	)
Net cash provided by (used in) financing activities		(18,412	)		91,624			108,231
Net increase (decrease) in cash, cash equivalents and restricted cash		—			8,829			(38,542	)
Cash, cash equivalents and restricted cash:
Balance, beginning of period		33,433			24,604			63,146
Balance, end of period	$	33,433		$	33,433		$	24,604

F-6

TALOS ENERGY INC.

(FORMERLY KNOWN AS TALOS ENERGY LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017

Note 1—Formation and Basis of Presentation

Formation and Nature of Business

Talos Energy LLC was formed in 2011. Upon formation, Talos Energy Operating Company LLC; Talos Energy Offshore LLC; Talos Energy Operating GP, LLC; Talos Energy Holdings LLC; and Talos Production LLC became wholly-owned subsidiaries of Talos Energy LLC. Talos Production Finance Inc. was formed on January 15, 2013 as a wholly-owned subsidiary of Talos Energy LLC. Unless otherwise indicated or the context otherwise requires, references in this report to “us,” “we,” “our” or the “Company” are to Talos Energy LLC and its wholly-owned subsidiaries. On February 6, 2013, we acquired all of the equity of Energy Resource Technology GOM, LLC (“ERT”) and its subsidiary from Helix Energy Solutions Group, Inc. (“Helix”) for approximately $625.2 million (inclusive of purchase price and working capital adjustments of approximately $15.2 million), and payments for ongoing guarantees from Helix to third-parties. Additionally, the Company agreed to assign Helix an overriding royalty interest in certain properties acquired in the transaction at closing. We refer to this purchase as the “ERT Acquisition.” The ERT Acquisition was effective December 1, 2012 and closed on February 6, 2013. Prior to the closing of the ERT Acquisition, Energy Resource Technology GOM, Inc. and its wholly-owned subsidiary, CKB Petroleum, Inc., were each converted into Delaware limited liability companies, and as a result changed their names to Energy Resource Technology GOM, LLC and CKB Petroleum, LLC, respectively.

On February 3, 2012, the Company completed a transaction with funds affiliated with, and controlled by, Apollo Global Management LLC (together with its consolidated subsidiaries, “Apollo”), funds affiliated with, and controlled by, Riverstone Holdings, LLC (together with its affiliates, “Riverstone” and together with Apollo, our “Sponsors”) and members of management pursuant to which the Company received a private equity capital commitment, which may be increased up to $600 million with approval from the Company’s Board of Directors.

Prior to the closing of the ERT Acquisition, our Sponsors and members of management had invested an aggregate of approximately $325 million in the Company to fund a portion of the ERT Acquisition as well as to fund other asset purchases. In connection with the ERT Acquisition, the Company also issued $300 million aggregate principal amount of 9.75% Senior Notes due February 15, 2018 (the “2018 Senior Notes”) at a discount of 0.975%, (see Note 6—Debt).

The Company commenced commercial operations on February 6, 2013. Prior to February 6, 2013, the Company had incurred certain general and administrative expenses associated with the start-up of its operations.

We are a technically driven independent exploration and production company with operations in the Gulf of Mexico and in the shallow waters off the coast of Mexico. Our focus in the Gulf of Mexico is the exploration, acquisition 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. The Company shall continue until it is liquidated or dissolved in accordance with the Limited Liability Company Agreement of Talos Energy LLC, as amended and restated (the “LLC Agreement”).

Basis of Presentation and Consolidation

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include each subsidiary from the date of

F-7

inception. All material intercompany transactions have been eliminated. All adjustments that are of a normal, recurring nature and are necessary to fairly present the Company’s financial position, results of operations and cash flows for the periods are reflected.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.

During September 2015, the Company expanded its acreage position to include two shallow water exploration blocks off the coast of Mexico and drilled our first well in July 2017. The business activities in Mexico have been combined with the United States and reported as one segment. See additional information in “Note 4—Property, Plant and Equipment.”

Recently Adopted Accounting Standards

In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01,Business Combinations (Topic 805)—Clarifying the Definition of a Business. This ASU clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU provide a screen that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, they are not a business, which reduces the number of transactions that need to be evaluated further. The update is effective for public entities for annual and interim periods beginning after December 31, 2017, but allows for early adoption provided the transaction date occurs before the issuance of the ASU, only when the transaction has not been reported in previously issued financials. The Company early adopted the amendments for the transaction completed on December 20, 2016. See additional information in “Note 3—Acquisitions.”

In November 2016, the FASB issued ASU 2016-18,Statement of Cash Flows (Topic 230): Restricted Cash. The amendments in this ASU require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. The Company early adopted ASU 2016-18 as of January 1, 2017 and the adoption was applied retrospective to 2016 and 2015. As a result of the adoption, the Company reclassified $10.2 million and $7.2 million change in restricted cash during the years ended December 31, 2016 and 2015, respectively, from the investing section of the consolidated statements of cash flows to the net change in cash, cash equivalents and restricted cash balance.

Recently Issued Accounting Standards

In February 2016, the FASB issued ASU 2016-02,Leases (Topic 842).This ASU supersedes the lease requirements in Topic 840 and requires that a lessee recognize a right-of-use asset and lease liability for leases that do not meet the definition of a short-term lease. The right-of-use asset and lease liability are to be measured on the balance sheet at the present value of the lease payments. For income statement purposes, ASU 2016-02retains a dual model requiring leases to be classified as either operating or finance within our statements ofoperations. Lease costs for operating leases are recognized as a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. For finance leases, interest expense is recognized on the lease liability separately from amortization of the right-to-use asset. ASU 2016-02 does not apply to leases

F-8

for oil and natural gas properties, but does apply to equipment used to explore and develop oil and natural gas reserves. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09,Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Topic 615,Revenue Recognition, and industry-specific guidance in Subtopic 932-605,Extractive Activities—Oil and Gas—Revenue Recognition, and requires an entity to recognize revenue when it transfers promised goods and services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods and services. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2017. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect initially applying ASU 2014-09 recognized at the date of initial application. We are in the process of finalizing our implementation of ASU 2014-09 and does not anticipate the adoption will have a material effect.

Note 2—Summary of Significant Accounting Policies

Below are the Company’s significant accounting policies.

Cash and Cash Equivalents

We reflect our cash as cash and cash equivalents on our consolidated balance sheets. We consider all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost plus accrued interest, which approximates fair value.

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts receivable are stated at the historical carrying amount net of an allowance for uncollectible accounts of $5.9 million at December 31, 2017 and $4.9 million at December 31, 2016, which approximates fair value. We establish provisions for losses on accounts receivable and for natural gas imbalances with other parties if we believe that we will not collect all or part of the outstanding balance. On a quarterly basis we review collectability and establish or adjust our allowance as necessary using the specific identification method.

Other Current Assets

Other current assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”). The deposits are estimates related to royalties which we are required to pay the ONRR within thirty days of the production rate. On a monthly basis we adjust the deposit based on actual royalty payments remitted to the ONRR.

Inventory

Inventory primarily represents oil in lease tanks and line fill in pipelines. Our inventory is stated at the net realizable value. Sales of oil are accounted for by a weighted average cost method whereby oil sold from inventory is relieved at the weighted average cost of oil remaining in inventory.

Revenue Recognition and Imbalances

We record revenues from the sale of oil, natural gas and natural gas liquids (“NGLs”) based on quantities of production sold to purchasers under short-term contracts (less than 12 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.

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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 December 31, 2017, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.7 million. At December 31, 2016, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.8 million. At December 31, 2015, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.6 million.

We record the gross amount of reimbursements for costs from third parties as other revenues whenever the Company is the primary obligor with respect to the source of such costs, has discretion in the selection of how the related costs are incurred and when it has 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.

Accounting for Oil and Natural Gas Activities

The Company follows 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. In August 2016, the Company entered into a capital lease for the use of the Helix Producer I (“HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy, and recorded a $124.3 million capital lease asset. Since the HP-I is utilized in our oil and natural gas development activities, the asset is included within proved property and subject to the ceiling test calculation described below. Due to the inclusion within proved properties, the HP-I is depleted as part of the full cost pool. See Note 10—Commitments and Contingencies for additional information.

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 percent, 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 the consolidated statement of operations and an increase to accumulated depreciation, depletion and amortization on our consolidated balance sheets. 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

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calculation each quarter. In accordance with the Securities and Exchange Commission (“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 resulted in a write-down of our oil and natural gas properties of nil, nil and $603.4 million during the years ended December 31, 2017, 2016 and 2015, respectively.

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 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 were $10.3 million, $9.1 million and $10.5 million in the years ended December 31, 2017, 2016 and 2015, respectively.

Other Property and Equipment

Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures, computer hardware and software. Acquisitions, renewals and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to five years.

Other Well Equipment Inventory

Other well equipment inventory primarily represents the cost of equipment to be used in our oil and natural gas drilling and development activities such as drilling pipe, tubular and certain wellhead equipment. When this inventory is supplied to wells, the cost of this inventory is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants. Our inventory is stated at net realizable value. We recorded $0.3 million, $0.2 million, $2.1 million of impairment to adjust inventory to net realizable value, which was expensed and reflected in workover/maintenance expense, during the years ended December 31, 2017, 2016 and 2015, respectively.

Fair Value Measure of Financial Instruments

Financial instruments generally consist of cash and cash equivalents, restricted cash, accounts receivable, commodity derivatives, accounts payable and debt. 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.

Current 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 is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly

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transaction between market participants. The Company follows 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.

Level 3—Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its 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 ten 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.

Price Risk Management Activities

The Company uses commodity derivatives to manage market risks resulting from fluctuations in prices of oil and natural gas. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.

Commodity derivatives are recorded on the consolidated balance sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in price risk management activities income (expense) in the consolidated statements of operations. We classify cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of our oil and natural gas operations, they are classified as cash flows from operating activities. We do not enter into derivative agreements for trading or other speculative purposes.

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The fair value of commodity derivatives reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation, market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be favorable or unfavorable.

Equity Based Compensation

Certain of our employees participate in the equity based compensation plan of the Company. We measure all employee equity based compensation awards at fair value as calculated using an option pricing method for valuing such securities on the date awards are granted to our employees and recognize compensation cost on a straight-line basis in our financial statements over the vesting period of each grant according to Accounting Standards Codification 718,Compensation—Stock Compensation.

Income Taxes

The Company is a limited liability company and not subject to federal or state income tax (in most states). As such, the Company is not a taxpaying entity for federal income tax purposes and accordingly, does not recognize any expense for such taxes. The federal income tax liability resulting from the Company’s activities is the responsibility of the Company’s Sponsors and other Unit holders. The Company is subject to state income taxes in certain jurisdictions and under applicable state laws taxes are estimated to be immaterial.

We operate in the shallow waters off the coast of Mexico under a different legal form. As a result, income taxes are provided for based upon the tax laws and rates in effect in the foreign tax authorities.

Deferred income tax assets and liabilities are recorded for the expected future tax consequences of events that are recognized in our financial statements or tax returns. A valuation allowance is established to reduce deferred tax assets when it is more likely than not that the overall deferred tax asset will not be realized. At December 31, 2017 and December 31, 2016, the Company has a valuation allowances of $4.0 million and $2.3 million, which is the amount of deferred tax assets.

Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents, restricted cash, accounts receivable and commodity derivatives.

Cash and cash equivalents and restricted cash balances are maintained in financial institutions, which, at times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has experienced no losses on these accounts.

Commodity derivatives are entered into with registered swap dealers, majority of which participate in our senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has experienced no losses due to counterparty default on these instruments.

We market substantially all of our oil and natural gas production from properties we operate and those we do not operate. The majority of our oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. Our customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. We perform ongoing credit evaluations of our customers and provide allowances for probable credit losses when

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necessary. The percent of consolidated revenue of major customers, those whose total represented 10% or more of our oil, natural gas and NGL revenues, was as follows:

	Year Ended December 31,
	2017			2016			2015
Shell Trading (US) Company		80	%		68	%		68	%
Chevron U.S.A Inc.		*	*		14	%		16	%

** less than 10%

While the loss of Shell Trading (US) Company and Chevron U.S.A. Inc. as buyers might have a material effect on the Company in the short term, we believe that the Company would be able to obtain other customers for its oil, natural gas and NGL production.

Supplementary Cash Flow Information

Supplementary cash flow information for each period presented was as follows (in thousands):

	Year Ended December 31,
	2017		2016		2015
Supplemental Non-Cash Transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	40,626	$	13,832	$	30,125
Fair value of assets acquired	$	—	$	—	$	75,519
Fair value of liabilities assumed	$	—	$	—	$	75,519
Capital lease transaction	$	—	$	124,300	$	—
Supplemental Cash Flow Information:
Interest paid, net of amounts capitalized	$	47,994	$	55,254	$	37,247

Note 3—Acquisitions

2017 Merger Announcement

Merger with Stone Energy

On November 21, 2017, the Company executed an agreement to combine with Stone Energy Corporation (“Stone”) to form Talos Energy, Inc. in an all-stock transaction, which is expected to occur during the second quarter of 2018. The transaction has been unanimously approved by both our and Stone’s Board of Directors. Under the terms of the agreement, each outstanding share of Stone common stock will be exchanged for one share of Talos Energy, Inc. common stock and the current Talos Energy stakeholders will be issued an aggregate of approximately 34.2 million common shares. At closing, our stakeholders will own 63% and Stone’s shareholders will own 37% of the combined company. Talos Energy, Inc. is expected to trade on the New York Stock Exchange under the ticker symbol “TALO.”

2016 Acquisitions

The acquisition below qualified as an asset acquisition that requires, among other items, that the cost of the assets acquired and liabilities assumed to be recognized on the balance sheet by allocating the asset cost on a relative fair value basis. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments

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and estimates by the Company’s management at the time of the valuation. Transaction costs incurred on an asset acquisition are capitalized as a component of the assets acquired and any contingent consideration is recognized as the contingency is resolved.

Acquisition of Additional Working Interest in the Phoenix Field

On December 20, 2016, we purchased an additional 15% working interest in the Phoenix Field from Sojitz Energy Venture Inc. (“Sojitz”) for 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 our 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 the Company’s 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. We refer to the acquisition of assets from Sojitz as the “Sojitz Acquisition.”

As of December 31, 2017, the Company recorded $2.5 million in post-closing adjustments related to activity between the effective date and closing date of the acquisition.

The following table below presents the allocation of the purchase price (inclusive of post-closing adjustments) to the assets acquired and liabilities assumed, based on their relative fair values on December 20, 2016 (in thousands):

Allocation of the Purchase Price	December 20, 2016
Proved properties	$	77,967
Unproved properties, not subject to amortization		11,133
Other short and long-term assets		2,380
Asset retirement obligations		(3,242	)
Cash Paid	$	88,238

2015 Acquisitions

The acquisitions below qualified as business combinations and were accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates by the Company’s management at the time of the valuation.

Acquisition of Additional Working Interest in Our Motormouth Discovery from Deep Gulf Energy III, LLC

On April 8, 2015, the Company entered into a supplemental agreement and first amendment to a previous participation agreement dated July 1, 2014 with Deep Gulf Energy III, LLC (“DGE”) to acquire a 25% working interest in the Motormouth discovery located in the Phoenix Field in exchange for $38.5 million in cash, the assumption of estimated asset retirement obligations and the right to participate in an additional 10% working interest in our 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. Our 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. We refer to the acquisition of assets from DGE as the “DGE Acquisition.”

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We completed the final purchase price allocation in 2015 which was calculated as follow (in thousands):

Allocation of the Purchase Price	April 8, 2015
Proved properties	$	24,316
Unproved properties, not subject to amortization		14,643
Asset retirement obligations		(442	)
Cash Paid	$	38,517

Revenue attributable to the assets acquired in the DGE Acquisition during the year ended December 31, 2015 was $1.9 million. The presentation of net income attributable to the assets acquired from DGE is impracticable due to the integration of the operations upon acquisition.

Acquisition of Gulf Coast Energy Resources, LLC

On March 31, 2015, the Company completed the acquisition of 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, the Company 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, the Company 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. The Company 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 completed the final purchase price allocation in 2015 which was calculated as follow (in thousands):

Allocation of the Purchase Price	March 31, 2015
Current assets	$	12,748
Proved properties		38,680
Unproved properties, not subject to amortization		22,637
Other non-current assets		536
Total assets acquired		74,601
Current portion of asset retirement obligations		107
Other current liabilities		18,632
Asset retirement obligations		744
Long-term debt, net of discount(1)		55,000
Other long-term liabilities(2)		118
Total liabilities assumed		74,601
Net assets acquired	$	—

(1) The long-term debt, net of discount assumed represents $55.0 million in borrowings under GCER’s senior reserve-based revolving credit facility (“GCER Bank Credit Facility”).

(2) The other long-term liabilities assumed includes $0.1 million to recognize an estimated liability as of the acquisition date for the contingent consideration arrangement if the oil and natural gas assets acquired meet certain targets within the subsequent five years. The fair value of the contingent consideration was calculated using a Monte Carlo simulation analysis. Significant inputs to the analysis are based, in part, on inputs not observable in the market and thus represent Level 3 measurements in the fair value hierarchy.

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These inputs include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates by the Company’s management at the time of the valuation. The maximum potential payment under the contingent consideration arrangement is $6.5 million.

The fair value, as adjusted, of the current assets acquired includes the following receivables (in thousands):

	March 31, 2015
	Gross Receivable		Expected Uncollectable Amount			Fair Value
Trade receivables	$	3,104	$	—		$	3,104
Joint interest receivables	$	3,484	$	(323	)	$	3,161
Other receivables	$	196	$	—		$	196

Revenue and net loss attributable to the assets acquired in the GCER Acquisition during the year ended December 31, 2015 was $12.6 million and $9.7 million, respectively. Revenues were reduced by production costs of the assets acquired and for estimated depletion and accretion expense in calculating net loss. Depletion expense was calculated by applying the Company’s depletion rate on proved oil and natural gas properties per Boe to production attributable to the acquired assets. Accretion on the asset retirement obligation was calculated using the Company’s credit-adjusted risk-free interest rate. Total non-cash depletion and accretion expense included in the net loss for the year ended December 31, 2015 was $15.6 million.

Note 4—Property, Plant and Equipment

Proved Properties. The Company’s interests in oil and natural gas properties are located primarily in the United States Gulf of Mexico deep and shallow waters. We follow the full cost method of accounting for our oil and natural gas exploration and development activities. In August 2016, the Company entered into a capital lease for the use of the HP-I and recorded a $124.3 million capital lease asset. Since the HP-I is utilized in our oil and natural gas development activities, the asset is included within proved property, subject to the ceiling test calculation described below and is depleted as part of the full cost pool.

Pursuant to SEC Regulation S-X, Rule 4-10, under the full cost method of accounting, our capitalized oil and natural gas costs are limited to a ceiling based on the present value of future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized. We perform this ceiling test calculation each quarter utilizing SEC Pricing. During 2017 and 2016, our ceiling test computations did not result in a write-down of our U.S oil and natural gas properties. At September 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and natural gas properties of $279.3 million based on SEC Pricing, of $61.22 per Bbl of oil, $3.29 per Mcf of natural gas and $20.65 per Bbl of NGLs. At December 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and natural gas properties of $324.1 million based on SEC Pricing of $50.72 per Bbl of oil, $2.75 per Mcf of natural gas and $17.60 per Bbl of NGLs.

Unproved Properties. Unproved capitalized costs of oil and natural gas properties excluded from amortization relate to unevaluated properties associated with acquisitions, leases awarded in the Gulf of Mexico federal lease sales, certain geological and geophysical costs, costs associated with certain exploratory wells in progress and capitalized interest. Unproved properties also include costs associated with the two blocks awarded on September 4, 2015 to the Company together with Sierra Oil & Gas S. de R.L de C.V. (“Sierra”) and Premier Oil Plc (“Premier”), the (“Consortium”), located in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states, by the National Hydrocarbons Commission (“CNH”).

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The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2017, by the year in which such costs were incurred (in thousands):

			Year Ended December 31,
	Total		2017		2016		2015		2014 and Prior
Acquisition	$	23,871	$	—	$	3,845	$	4,089	$	15,937
Exploration		48,131		27,137		7,174		2,621		11,199
Total unproved properties, not subject to amortization	$	72,002	$	27,137	$	11,019	$	6,710	$	27,136

The excluded costs will be included in the amortization base as properties are evaluated and proved reserves are established or impairment is determined. We expect this process to occur over the next five years.

In March 2017, the Company was the apparent high bidder on six blocks in connection with the Gulf of Mexico Federal Lease Sale 247 held by the Bureau of Ocean Energy Management (“BOEM”). The six blocks were awarded to the Company during the second quarter 2017. The Company paid BOEM approximately $2.6 million during the first and second quarter of 2017 for the awarded leases and for first year’s lease rentals.

Capitalized Interest.Interest expense in our financial statements is reflected net of capitalized interest. We capitalize interest on the costs associated with drilling and completing wells until production begins. The interest rate used is the weighted average interest rate of our outstanding borrowings. Capitalized interest for the years ended December 31, 2017, 2016 and 2015 was $0.6 million, $0.4 million and $3.9 million, respectively.

Capitalized Overhead.General and administrative expense in our financial statements is reflected net of capitalized overhead. We capitalize overhead costs that are directly related to exploration, acquisition and development activities. Capitalized overhead for the years ended December 31, 2017, 2016 and 2015 was $13.7 million, $12.5 million and $14.1 million, respectively.

Asset Retirement Obligations.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.

In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate in the table below represent changes to the expected amount and timing of payments to settle our asset retirement obligations. Typically, these changes result from obtaining new information about the timing of our obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense in our consolidated statements of operations. If we incur an amount different from the amount accrued for decommissioning obligations, we recognize the difference as an adjustment to proved properties.

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The discounted asset retirement obligations included in the consolidated balance sheets in current and non-current liabilities, and the changes in that liability during the each of the years ended December 31, were as follows (in thousands):

	Year Ended December 31,
	2017			2016
Asset retirement obligations at January 1	$	220,049		$	226,690
Fair value of asset retirement obligations acquired		699			6,445
Obligations settled		(32,573	)		(23,689	)
Accretion expense		19,295			21,829
Obligations incurred		4,213			1,014
Changes in estimate(1)		3,050			(12,240	)
Asset retirement obligations at December 31	$	214,733		$	220,049
Less: Current portion at December 31		(39,741	)		(33,556	)
Noncurrent portion at December 31	$	174,992		$	186,493

(1) The reduction during the year ended December 31, 2016 was primarily attributable to a reduction in service costs.

Note 5—Financial Instruments

The following table presents the carrying amounts and estimated fair values of financial instruments (in thousands):

	December 31, 2017						December 31, 2016
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
11.00% Bridge Loans—due April 2022	$	169,838		$	172,023		$	—		$	—
9.75% Senior Notes—due July 2022	$	100,681		$	102,000		$	—		$	—
9.75% Senior Notes—due February 2018	$	24,977		$	24,977		$	294,964		$	137,850
Bank Credit Facility	$	402,062		$	403,000		$	406,211		$	408,000
Derivatives	$	(66,830	)	$	(66,830	)	$	(15,433	)	$	(15,433	)

As of December 31, 2017 and 2016, the carrying amounts of cash and cash equivalents, accounts receivable, restricted cash and accounts payable approximate their fair values because of the short-term nature of these instruments.

Bridge Loans, 2022 Senior Notes and 2018 Senior Notes.The $172.0 million aggregate principal amount of 11% senior secured second-priority bridge loans due April 3, 2022 (“Bridge Loans”), $102.0 million aggregate principal amount of 9.75% senior notes due July 5, 2022 (“2022 Senior Notes”) and $25.0 million aggregate principal amount of 9.75% senior notes due February 15, 2018 (“2018 Senior Notes”) are reported on the consolidated balance sheet at their carrying value net of discount and deferred financing costs (see Note 6—Debt). The fair value of our Bridge Loans is estimated as face value as no market has developed and the holders of the Bridge Loans were the largest holders of the 2018 Senior Notes prior to the April 3, 2017 conversion. The fair value of the 2022 Senior Notes and 2018 Senior Notes are estimated to equal the face value based on the April 3, 2017 conversion and May 15, 2017 redemption of $1.0 million of the 2018 Senior Notes at par. These fair values represent Level 2 fair value measurements (see Note 6—Debt).

Bank Credit Facility.The Bank Credit Facility is reported on the consolidated balance sheet at its carrying value net of deferred financing costs (see Note 6—Debt). The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under our Bank Credit Facility since it is secured by the company’s reserves and the interest rates are variable and reflective of market rates.

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Oil and natural gas derivatives. We attempt to mitigate a portion of our commodity price risk and stabilize cash flows associated with sales of oil and natural gas production through the use of oil and natural gas swaps and costless collars. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from the counterparties. These two-way collars provide risk protection if oil prices fall below certain levels, but may limit incremental income from favorable price movements above certain limits. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on the 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) in the consolidated statements of operations in each period.

The following table presents the impact that derivatives not qualifying as hedging instruments had on our consolidated statements of operations (in thousands):

	Year Ended December 31,
	2017			2016			2015
Price risk management activities income (expense)(1)	$	(27,563	)	$	(57,398	)	$	182,196

(1) The Company received net cash settlements of $23.8 million, $172.2 million and $181.9 million for the years ended December 31, 2017, 2016 and 2015, respectively.

The following table reflects the contracted volumes and weighted average prices we will receive under our derivative contracts as of December 31, 2017:

Production Period	Instrument Type		Average Daily Volumes			Weighted Average Swap Price
Crude Oil—WTI:				(Bbls	)		(per Bbl	)
January 2018—December 2018		Swap		24,804		$	53.79
January 2019—December 2019		Swap		15,866		$	53.17
Natural Gas—Henry Hub NYMEX:				(MMBtu	)		(per MMBtu	)
January 2018—December 2018		Swap		26,346		$	3.00
January 2019—December 2019		Swap		10,146		$	2.99

Subsequent event.The following table reflects the contracted volumes and weighted average prices we will receive under our derivative contracts entered into subsequent to December 31, 2017, which are not reflected in the table above:

Production Period	Instrument Type		Average Daily Volumes			Weighted Average Swap Price
Crude Oil—WTI:				(Bbls	)		(per Bbl	)
January 2019—June 2019		Swap		1,008		$	56.25

The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):

	December 31, 2017
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas swaps	$	—	$	1,908		$	—	$	1,908
Liabilities:
Oil and natural gas swaps		—		(68,738	)		—		(68,738	)
Total net liability	$	—	$	(66,830	)	$	—	$	(66,830	)

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	December 31, 2016
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas swaps and costless collars	$	—	$	20,469		$	—	$	20,469
Liabilities:
Oil and natural gas swaps and costless collars		—		(35,902	)		—		(35,902	)
Total net liability	$	—	$	(15,433	)	$	—	$	(15,433	)

Financial Statement Presentation. Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although we have master netting arrangements with our counterparties, we present our derivative financial instruments on a gross basis in our consolidated balance sheets. On derivative contracts recorded as assets in the table below, we are exposed to the risk the counterparties may not perform. The following table presents the fair value of derivative financial instruments at December 31, 2017 and 2016 (in thousands):

	December 31, 2017		December 31, 2016
Assets from price risk management activities—current:
Oil and natural gas derivatives	$	1,563	$	20,176
Assets from price risk management activities—non-current:
Oil and natural gas derivatives	$	345	$	293
Liabilities from price risk management activities—current:
Oil and natural gas derivatives	$	49,957	$	27,147
Liabilities from price risk management activities—non-current:
Oil and natural gas derivatives	$	18,781	$	8,755

Credit Risk. We are subject to the risk of loss on our financial instruments as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We enter into International Swaps and Derivative Association agreements with counterparties to mitigate this risk, when possible. We also maintain credit policies with regard to our counterparties to minimize our overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of our counterparties’ credit exposures; (iii) the use of contractual language that affords us netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk. Our assets and liabilities from commodity price risk management activities at December 31, 2017 represent derivative instruments from eight counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating ofBBB-or better) credit rating and seven of which are parties under our Bank Credit Facility. We enter into derivatives directly with these third parties and, subject to the terms of our Bank Credit Facility, are not required to post collateral or other securities for credit risk in relation to the derivative activities.

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Note 6—Debt

A summary of the detail comprising the Company’s debt and the related book values for the respective periods presented is as follows (in thousands):

Description	December 31, 2017			December 31, 2016
11.00% Bridge Loans—due April 2022
Principal	$	172,023		$	—
Deferred financing costs, net of amortization		(2,185	)		—
9.75% Senior Notes—due July 2022
Principal		102,000			—
Deferred financing costs, net of amortization		(1,319	)		—
9.75% Senior Notes—due February 2018
Principal		24,977			300,000
Original issue discount, net of amortization		—			(806	)
Deferred financing costs, net of amortization		—			(4,230	)
Bank Credit Facility—due February 2019		403,000			408,000
Deferred financing costs, net of amortization		(938	)		(1,789	)
Total debt	$	697,558		$	701,175
Less: Current portion of long-term debt		(24,977	)		—
Long-term debt, net of discount and deferred financing costs	$	672,581		$	701,175

On April 3, 2017 (the “Closing Date”), the Company entered into an Exchange Agreement (the “Exchange Agreement”) pursuant to which Bain Capital Credit LP, GSO Capital Partners LP and certain affiliates of our Sponsors (the “Exchanging Noteholders”) exchanged some of the 2018 Senior Notes for Bridge Loans (as described below). Certain affiliates of the Sponsors also exchanged some of the 2018 Senior Notes for 2022 Senior Notes (as described below).

The exchange of debt instruments 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 2018 Senior Notes is computed and applied prospectively. Costs incurred with third parties directly related to the modification are expensed as incurred. The Company incurred approximately $4.3 million of transaction fees which were expensed and reflected in general and administrative expense during the year ended December 31, 2017, respectively.

Bridge Loans.On the Closing Date, the Company exchanged $172.0 million of the 2018 Senior Notes for $172.0 million of Bridge Loans issued under a second lien bridge loan agreement, dated as of the Closing Date (the “Credit Agreement”), by and among the Company, the lenders party thereto and Wilmington Trust, National Association, as administrative agent and collateral agent. Of the $172.0 million exchanged, the Sponsors held $39.8 million. The Bridge Loans mature on the fifth anniversary of the Closing Date.

The obligations under the Credit Agreement are second-priority secured obligations behind the Bank Credit Facility. The obligations are secured by substantially all of the Company’s assets. The Company will pay interest on amounts outstanding under the Credit Agreement at 11.0% per annum, semiannually on April 15 and October 15 of each year, which commenced October 15, 2017.

The Company may redeem up to 35% of the aggregate principal amount of the Bridge Loans at a price equal to 111% of the aggregate principal amount plus accrued and unpaid interest, if any, at any time prior to April 3, 2018. The Company may redeem the Bridge Loans, in whole or in part, on or after April 3, 2018 at the redemption prices set forth in the Credit Agreement.

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The Credit Agreement contains covenants that limit the Company’s ability (and their restricted subsidiaries’ ability) to, among other things: (i) incur additional indebtedness or issue certain preferred shares; (ii) pay dividends and make certain other restricted payments; (iii) create restrictions on the payment of dividends or other distributions to the Company from its restricted subsidiaries; (iv) create liens on certain assets to secure debt; (v) make certain investments; (vi) engage in transactions with affiliates; (vii) engage in sales of assets and subsidiary stock; and (viii) transfer all or substantially all of its assets or enter into merger or consolidation transactions. The Credit Agreement does not contain a financial maintenance covenant. The Credit Agreement also provides for certain customary events of default, which, if any of such defaults occurs, would permit or require the principal, premium (if any), interest or other monetary obligations on all of the then outstanding Bridge Loans to become due and payable. The Bridge Loans contain customary quarterly and annual reporting, financial and administrative covenants.

2022 Senior Notes.On the Closing Date, the Company exchanged $102.0 million of the 2018 Senior Notes for $102.0 million of 2022 Senior Notes issued under a new indenture, dated as of the Closing Date (the “Indenture”), between the Company, as issuer, the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee. The 2022 Senior Notes mature on July 5, 2022. The Company will pay interest on the 2022 Senior Notes at 9.75% per annum, semiannually on February 15 and August 15 of each year, which commenced August 15, 2017.

The Company may redeem up to 35% of the aggregate principal amount of the 2022 Senior Notes at a price equal to 109.75% of the aggregate principal amount plus accrued and unpaid interest, if any, at any time prior to April 3, 2018. The Company may redeem the 2022 Senior Notes, in whole or in part, on or after April 3, 2018 at the redemption prices set forth in the Indenture. The remainder of the terms of the 2022 Senior Notes are substantially similar to the terms of the 2018 Senior Notes.

2018 Senior Notes. The 2018 Senior Notes were issued pursuant to an indenture dated February 6, 2013 among the Company and one of our wholly-owned subsidiaries, as issuers, the subsidiary guarantors party thereto and the trustee. The 2018 Senior Notes pay interest on February 15 and August 15 of each year. The 2018 Senior Notes are fully and unconditionally guaranteed by certain of our wholly-owned subsidiaries. The indenture governing the 2018 Senior Notes applies certain limitations on our ability and the ability of our subsidiaries to, among other things, (i) incur or guarantee additional indebtedness; (ii) pay dividends or distributions on, or redeem or repurchase capital investment and make other restricted payments; (iii) make investments; (iv) consummate certain asset sales; (v) engage in transactions with affiliates; (vi) grant or assume liens; and (vii) consolidate, merge or transfer all or substantially all of our assets. The 2018 Senior Notes contain customary quarterly and annual reporting, financial and administrative covenants. In addition to the exchange of some of the 2018 Senior Notes for Bridge Loans and 2022 Senior Notes, the Company redeemed $1.0 million of the 2018 Senior Notes on May 15, 2017.

Subsequent event.On February 15, 2018, the Company redeemed the remaining $25.0 million aggregate principal amount of the 2018 Senior Notes at par.

Bank Credit Facility. The Company maintains a Bank Credit Facility with a syndicate of financial institutions, which has been amended periodically. The Bank Credit Facility provides a revolving credit facility with a borrowing capacity up to the lesser of (i) the borrowing base (as defined in the Bank Credit Facility) and (ii) aggregate lender commitments. The Bank Credit Facility matures on February 6, 2019.

The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. In addition, the Company is obligated to pay a commitment fee rate based on the borrowing base usage of 0.375% to 0.50%. The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a consolidated debt to adjusted EBITDA figure of no greater than 3.50 to 1.00. The Bank Credit Facility is secured

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by substantially all of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by certain of our wholly-owned subsidiaries.

The Bank Credit Facility provides for determination of the borrowing base based on the Company’s proved producing reserves and a portion of its proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually in the spring and fall, with the last redetermination on May 16, 2017.

On January 10, 2017, we paid down $15.0 million under our Bank Credit Facility, and on April 3, 2017, we borrowed $10.0 million from our Bank Credit Facility.

In May 2017, the lenders under our Bank Credit Facility reaffirmed the borrowing base at $475.0 million during their regular semi-annual redetermination. In conjunction with the reaffirmation of the borrowing base, the Company executed the Eighth Amendment to the Bank Credit Facility effective May 16, 2017. The Eighth Amendment includes (i) an increase to the consolidated total debt to EBITDAX (as defined in the Bank Credit Facility) ratio covenant from 3.50 to 1.0 to 3.75 to 1.0 each quarter from September 30, 2017 to March 31, 2018 and (ii) a requirement to execute control agreements for all deposit accounts, securities accounts and commodities accounts in the name of the borrowers and guarantors. On October 31, 2017, the Company executed the Ninth Amendment to the Bank Credit Facility deferring the borrowing base redetermination to January 2018 to fully assess the reserve impact of our recent Tornado II discovery.

As of December 31, 2017, the Company’s borrowing base was set at $475.0 million, of which no more than $200 million can be used as letters of credit. As of December 31, 2017, the Bank Credit Facility had approximately $67.1 million of undrawn commitments (taking into account $4.9 million letters of credit and $403.0 million drawn under the Bank Credit Facility). We were in compliance with all debt covenants at December 31, 2017.

Subsequent event.On January 24, 2018, at our election we executed the Tenth Amendment to the Bank Credit Facility deferring the next borrowing base redetermination to May 31, 2018 in response to our recently announced combination with Stone.

Note 7—Employee Incentive Programs

Employee Share Ownership Program

The LLC Agreement established Series A, Series B and Series C Units. Series B Units are generally intended to be used as incentives for Talos Energy LLC employees. Talos Energy LLC is initially authorized to issue 1 million Series B Units and may issue more under the LLC Agreement.

With the exception of distributions to cover the assumed tax liability of the Series B Unit holders, Series B Units do not participate in cash distributions prior to vesting and until Series A Units have received cumulative cash distributions equal to (i) the original cash contributed to Talos Energy LLC for such Series A Units and (ii) 8% returns, compounded annually (the “Aggregate Series A Payout”), and Series C Units have received $25 million in cash distributions.

After issuance, 80% of the Series B Units vest on a monthly basis over a four year period, subject to continued employment. The remaining 20% of the Series B Units fully vest (a) upon the occurrence of a Liquidation Event or an Approved Sale, as defined in the LLC Agreement, that results in an Aggregate Series A Payout or (b) in the case of a public offering upon the occurrence of an Aggregate Series A Payout.

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We had 992,850 Series B Units outstanding at December 31, 2017, 980,250 Series B Units outstanding at December 31, 2016 and 906,000 Series B Units outstanding at December 31, 2015. A summary of the Series B Unit activity for the years ended December 31, 2017, 2016 and 2015 is presented below.

	Number of Series B Units			Weighted Average Estimated Fair Value per Unit
Non-vested at December 31, 2014		642,355		$	21.04
Vested		(175,196	)		20.43
Forfeited or cancelled		(92,500	)		22.08
Non-vested at December 31, 2015		374,659		$	21.07
Granted		147,000			4.11
Vested		(122,455	)		17.95
Forfeited or cancelled		(72,750	)		21.22
Non-vested at December 31, 2016		326,454		$	14.57
Granted		35,100			20.99
Vested		(104,614	)		17.16
Forfeited or cancelled		(22,500	)		15.10
Non-vested at December 31, 2017		234,440		$	14.32

For accounting and financial reporting purposes, the Series B Units are deemed to be equity awards, and the compensation expense related to these awards is recorded on a straight-line basis over the vesting period in the Company’s consolidated financial statements and is reflected as a corresponding credit to equity. In the years ended December 31, 2017, 2016 and 2015, we recognized approximately $0.9 million, $1.1 million and $1.7 million, respectively, in compensation expense included in general and administrative expense and capitalized approximately $0.9 million, $1.2 million and $1.9 million, respectively, into our oil and natural gas properties. The Series B Units issued were valued using the option pricing method for valuing securities. In this method, the rights and claims of each security are modeled as a portfolio of Black-Scholes-Merton call options written on the total equity of the Company. The fair value of each grant was estimated at the date of grant using the following weighted-average assumptions:

	2017 Grants			2016 Grants
Assumed value of equity (in thousands)	$	789,426		$	196,280
Risk-free rate of interest		1.16	%		1.11	%
Expected time to a liquidity event (in years)		1			3
Expected volatility of equity		40	%		70	%
Discount for lack of marketability		25	%		34	%

The total value of the equity is calculated in an iterative process that results in the Series A Units being valued at par. The risk-free rate of interest is based on the U.S. Treasury yield curve on the grant date. The expected time to a liquidity event is based on a weighted average calculation of management’s estimate considering market conditions and expectations. The expected volatility of equity is based on the volatility of the assets of similar publicly traded companies using a Black-Scholes-Merton model. The discount for lack of marketability is based on the restrictions on the Series B Units and the volatility of the Series B Units using a Black-Scholes-Merton model.

Our unrecognized compensation expense at December 31, 2017 is approximately $3.4 million. Of this amount, approximately $1.1 million of the unrecognized compensation expense will continue to be recognized on a straight-line basis over the remainder of the four year requisite service period. The remaining $2.2 million related to 135,712 Series B Units will be recognized (a) upon the occurrence of a Liquidation Event or an Approved Sale, as defined in the LLC Agreement, that results in an Aggregate Series A Payout or (b) in the case

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of a public offering upon the occurrence of an Aggregate Series A Payout. The weighted-average period over which the unrecognized compensation expense will be recognized is 24 months. At December 31, 2017, the Company has 7,150 Series B units authorized but not yet issued.

Note 8—Income Taxes

The Company is a limited liability company and not subject to federal income tax or state income tax (in most states). As such, the Company is not a taxpaying entity for federal income tax purposes and accordingly, does not recognize any expense for such taxes. The federal income tax liability resulting from the Company’s activities is the responsibility of the Company’s Sponsors and other Unit holders. The Company is subject to state income taxes in certain jurisdictions and under applicable state laws taxes are estimated to be immaterial

We operate in the shallow waters off the coast of Mexico under a different legal form. As a result, we are subject to foreign tax authorities. Although the Company is subject to foreign income taxes, the Company incurred only foreign expenses in Mexico during the years ended December 31, 2017, 2016 and 2015. The Company is subject to foreign income taxes and under the foreign tax law and treaties among these governments taxes are estimated to be immaterial.

Deferred income tax assets and liabilities are recorded for the expected future tax consequences of events that are recognized in our financial statements or tax returns. At December 31, 2017, the Company recorded a deferred tax asset mostly related to the foreign tax loss carry forward. A valuation allowance is established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax asset will not be realized. The Company believes it is more likely than not that the overall deferred tax asset will not be realized. At December 31, 2017 and December 31, 2016, the Company has a valuation allowance of $4.0 million and $2.3 million, respectively, which is the amount of deferred tax asset.

Foreign tax loss carryforwards at December 31, 2017 was $13.4 million. The foreign tax loss carryforwards will start to expire in 2025.

On December 22, 2017, the President signed into Public Law No. 115-97 (“Tax Act”), “an Act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018.” Tax Act makes broad and complex changes to the U.S. tax code. Since Talos is a limited liability company and treated as a pass-through entity for federal tax purposes and in most states, the Company did not recognize any income tax impact from the new Tax Act.

Note 9—Related Party Transactions

Transaction Fee Agreement.As part of the agreements with Apollo and Riverstone, the Company pays a transaction fee equal to 2% of capital contributions made by each of our Sponsors. For the years ended December 31, 2017, 2016 and 2015 we incurred fees totaling nil, $1.9 million and $1.5 million, respectively, related to the capital contributions received from our Sponsors.

Service Fee Agreement. The Company entered into service fee agreements with each of our Sponsors for the provision of certain management consulting and advisory services. Under each agreement, the Company pays a fee equal to the higher of (i) a certain percentage of earnings before interest, income taxes, depletion, depreciation and amortization and (ii) a fixed fee payable quarterly, provided, however, such fees shall not exceed in each case $0.5 million, in aggregate, for any calendar year. For the years ended December 31, 2017, 2016 and 2015, we incurred approximately $0.5 million, $0.5 million and $0.5 million, respectively, for these services. These fees are recognized in general and administrative expense on the consolidated statement of operations.

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Contributions and Distributions. During the year ended December 31, 2017, the Company did not receive any capital contributions from our Sponsors or make any distributions to our Sponsors. During the year ended December 31, 2016, the Company received a $93.8 million ($91.9 million net of $1.9 million of transaction fees) capital contribution from our Sponsors primarily to fund the Sojitz Acquisition (see Note 3—Acquisitions). During the year ended December 31, 2015, the Company received a $75.0 million ($73.5 million net of $1.5 million of transaction fees) capital contribution from our Sponsors primarily to fund the DGE Acquisition and to partially fund the $55.0 million extinguishment of the GCER Bank Credit Facility assumed in the GCER Acquisition (see Note 3—Acquisitions).

Note 10—Commitments and Contingencies

Capital Lease

On August 2, 2016, ERT executed a seven-year lease agreement (the “Agreement”), effective June 1, 2016, with Helix for use of the HP-I to process hydrocarbons produced from the Phoenix Field. Under the terms of the Agreement, the Company will pay Helix an annual fixed demand charge of $49.0 million during the first two years and $45.0 million thereafter. If certain uptime rates are achieved, the Company will pay Helix a quarterly incentive payment of $0.5 million during the first two years of the agreement and $0.8 million thereafter.

The Agreement replaces the previous lease agreement for the HP-I, which provided that ERT would pay Helix (i) a fixed annual demand fee of $33.0 million and (ii) a 10% throughput charge on the net consideration payable to ERT under a sales contract for the sale of hydrocarbons processed through the HP-I.

The Agreement with Helix is accounted for as a capital lease. The Company initially recorded both a capital lease asset and obligation of $124.3 million on our consolidated balance sheet. As of December 31, 2017, the balance of the capital lease obligation on the consolidated balance sheet is $106.6 million, of which $12.9 million is included in other current liabilities and $93.7 million is included in other long-term liabilities. As a result of the Agreement being accounted for as a capital lease, the lease payments are reflected as (i) a reduction of the capital lease obligation, (ii) interest expense and (iii) direct lease operating expense.

As of December 31, 2017, minimum lease commitments for our capital lease for the years ended December 31 are as follows (in thousands):

2018	$	46,667
2019		45,000
2020		45,000
2021		45,000
2022		45,000
Thereafter		18,750
Total minimum lease payments		245,417
Less amount represented lease operating expenses		(63,607	)
Less amount represented interest		(75,189	)
Present value of minimum lease payments		106,621
Less current maturities of capital lease obligations		(12,952	)
Long-term capital lease obligations	$	93,669

Legal Proceedings and Other Contingencies

In August 2015, we became aware of a potential unauthorized discharge on our Vermilion 195 platform in connection with an operation to bleed off production casing pressure. We immediately initiated an internal investigation of the alleged matter and concluded that an unauthorized discharge had occurred. We terminated

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the individuals that were determined to be responsible for the discharge. We also self-reported the matter to the U.S. Environmental Protection Agency (“EPA”) on September 17, 2015.

On November 30, 2015, ERT was charged with two violations of Outer Continental Shelf Lands Act (“OCSLA”) in connection with hot work and blowout preventer testing activities, and with two violations of the Clean Water Act (“CWA”) for the self-reported activities surrounding overboard discharge sampling and unpermitted discharges, as described above.

On January 6, 2016, ERT plead guilty to two violations of the Clean Water for self-reported activities surrounding overboard discharge sampling and unpermitted discharges and two violations of OSCLA. On April 6, 2016, the United States District Court for the Eastern District of Louisiana 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 Safety and Environmental Compliance Program. As a result of ERT’s conviction for violations of the CWA, ERT was debarred and cannot enter into contracts with or receive benefits from the federal government, until the EPA reinstates ERT by certifying that ERT has corrected the conditions giving rise to the Clean Water convictions. EPA also imposed discretionary suspension and proposed debarment on Talos Production LLC, Talos Energy Offshore LLC and Talos Energy LLC as affiliates of ERT. On November 23, 2016, EPA terminated and administratively closed the suspension as to each of the three entities previously suspended. On August 29, 2017, EPA certified that the conditions giving rise to ERT’s conviction were corrected, and its debarment was lifted.

Performance Obligations

Regulations with respect to offshore operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities and to guarantee the execution of the minimum work program under the Mexico production sharing contracts. As of December 31, 2017 and 2016, we had secured performance bonds totaling approximately $287.8 million and $338.2 million, respectively. As of December 31, 2017 and 2016, we had $4.9 million and $4.0 million, respectively, in letters of credit issued under our Bank Credit Facility.

In July 2016, the BOEM announced updated financial assurance and risk management requirements for offshore leases. The Notice to Lessees (“NTL”) details procedures to determine a lessee’s ability to carry out its lease obligations—primarily the decommissioning of Outer Continental Shelf (“OCS”) facilities—and whether to require lessees to furnish additional financial assurance to meet BOEM’s estimate of the lessees decommissioning obligations. The NTL supersedes the agency’s prior practice of allowing operators of a certain net worth to waive the need for supplemental bonds and provides updated criteria for determining a lessee’s ability to self-insure its OCS liabilities based upon the lessee’s financial capacity and financial strength. The NTL also allows lessees to meet their additional financial security requirements through the submission of a tailored plan, whereby an operator and BOEM agree to set a timeframe for the posting of additional financial assurances. In the first quarter of 2017, BOEM announced that it will extend the implementation timeline for the new NTL by an additional six months. Sole-liability leaseholders will have 60 days from the date of receipt of an order requiring additional financial security to comply. For all other holdings, leaseholders will have 120 days from the date they receive an order to provide additional security, if required. Alternatively, lessees can provide a tailored financial plan to BOEM, which will permit the use of forms of financial security other than surety bonds and pledges of treasury securities and allow companies to phase in funding of the additional security. We received notice from BOEM on December 29, 2016 ordering the Company to secure financial assurances in the form of additional security in the amount of $0.5 million. Subsequent to the December 29, 2016 order, BOEM has rescinded that order and all others dated December 29, 2016 until further notice. We remain in active discussion with our government regulators and industry peers with regard to any future rule making and financial assurance requirements. Notwithstanding BOEM’s July 2016 NTL, BOEM may also bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The future cost of

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compliance with our existing supplemental bonding requirements, the July 2016 NTL, as well as any other future BOEM directives or any other changes to BOEM’s rules applicable to us or our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows, and results of operations.

Subsequent event. On January 23, 2018, the Company canceled $22.3 million in performance bonds in response to receiving confirmation from the CNH that the Consortium had fulfilled its obligation under the minimum work program in Block 7.

Other Commitments

On February 19, 2013, we signed a three-year agreement to use Helix’s Q4000 vessel (the “Q4000”) or equivalent substitute, a dynamic positioning semi-submersible vessel specifically designed for well intervention and construction. The contract was effective beginning on January 1, 2015 and was amended January 9, 2017. The Q4000 is expected to be utilized for certain deep water well intervention and decommissioning activities for properties operated by the Company. Under the amended terms of the agreement, the Company will pay Helix a base vessel day work rate based on the number of days contracted at a minimum of 20 days per contract year through 2019. As of December 31, 2017 the total estimated minimum payments in 2018 and 2019 are approximately $6.5 million and $6.7 million, respectively.

We had no drilling rig commitments with a term that exceed one year as of December 31, 2017. Future minimum payments for drilling rig commitments as of December 31, 2017 were $3.9 million.

Subsequent event. On February 8, 2018, the Company amended a previous agreement to use the Ensco 75, a jackup drilling rig, to execute a portion of the Company’s 2018 drilling program. Under the terms of the amendment, the Company will pay Ensco a base vessel day work rate based on the number of days contracted for 60 additional days during 2018. The estimated payments in 2018 are approximately $7.8 million, which includes the $3.9 million related to the agreement prior to the amendment.

Office Lease Obligations

On December 13, 2017, we entered into an eleven year operating lease beginning August 2018 for office space at Three Allen Center in Houston, Texas. In addition to the office lease executed in 2017, we have office leases in Houston, Texas; Dallas, Texas; Dulac, Louisiana and Mexico. Total future minimum lease payments in 2018, 2019, 2020, 2021 and thereafter are $4.1 million, $4.3 million, $3.8 million, $3.8 million and $30.5 million, respectively.

Note 11—Condensed Consolidating Financial Information

Talos Energy Inc. (“Parent”) owns no operating assets and has no operations independent of its subsidiaries. Talos Production LLC and Talos Production Finance Inc. (“Subsidiary Issuers”) are 100% owned by the Parent. The Subsidiary Issuers issued 11.00% Second-Priority Senior Secured Notes (“11.00% Notes”) on May 10, 2018, which are fully and unconditionally guaranteed, jointly and severally, by the Parent and certain 100% owned subsidiaries (“Guarantors”) on a senior secured basis. Certain of the Company’s subsidiaries which are accounted for on a consolidated basis do not guarantee the 11.00% Notes (“Non-Guarantors”).

The following condensed consolidating financial information presents the financial information of the Company on an unconsolidated stand-alone basis and its combined subsidiary issuers, combined guarantor and combined non-guarantor subsidiaries as of and for the periods indicated. As described in Note 15 –Subsequent Change in Reporting Entity and Financial Statement Presentation, the Company retrospectively adjusted its consolidated equity to reflect the legal capital of Talos Energy Inc. for all periods presented. Such financial information may not necessarily be indicative of the Company’s results of operations, cash flows, or financial position had these subsidiaries operated as independent entities.

F-29

TALOS ENERGY INC.

(FORMERLY KNOWN AS TALOS ENERGY LLC)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2017

(In thousands)

	Parent			Subsidiary Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	22,315		$	7,806		$	2,070		$	—		$	32,191
Restricted cash		—			—			1,242			—			—			1,242
Accounts receivable, net
Trade, net		—			—			62,871			—			—			62,871
Joint interest, net		—			—			11,659			1,954			—			13,613
Other		—			938			5,863			5,685			—			12,486
Assets from price risk management activities		—			1,406			157			—			—			1,563
Prepaid assets		—			—			17,919			12			—			17,931
Inventory		—			—			840			—			—			840
Other current assets		—			—			2,148			—			—			2,148
Total current assets		—			24,659			110,505			9,721			—			144,885
Property and equipment:
Proved properties		—			—			2,440,811			—			—			2,440,811
Unproved properties, not subject to amortization		—			—			41,259			30,743			—			72,002
Other property and equipment		—			7,266			1,580			11			—			8,857
Total property and equipment		—			7,266			2,483,650			30,754			—			2,521,670
Accumulated depreciation, depletion and amortization		—			(6,355	)		(1,424,527	)		(8	)		—			(1,430,890	)
Total property and equipment, net		—			911			1,059,123			30,746			—			1,090,780
Other long-term assets:
Assets from price risk management activities		—			345			—			—			—			345
Other well equipment inventory		—			—			2,577			—			—			2,577
Investments in subsidiaries		(54,087	)		697,663			—			—			(643,576	)		—
Other assets		—			364			326			16			—			706
Total assets	$	(54,087	)	$	723,942		$	1,172,531		$	40,483		$	(643,576	)	$	1,239,293
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	—		$	1,124		$	70,458		$	1,099		$	—		$	72,681
Accrued liabilities		—			6,516			80,464			993			—			87,973
Accrued royalties		—			—			24,208			—			—			24,208
Current portion of long-term debt		—			24,977			—			—			—			24,977
Current portion of asset retirement obligations		—			—			39,741			—			—			39,741
Liabilities from price risk management activities		—			46,580			3,377			—			—			49,957
Accrued interest payable		—			8,742			—			—			—			8,742
Other current liabilities		—			—			15,188			—			—			15,188
Total current liabilities		—			87,939			233,436			2,092			—			323,467
Long-term debt, net of discount and deferred financing costs		—			672,581			—			—			—			672,581
Asset retirement obligations		—			—			174,992			—			—			174,992
Liabilities from price risk management activities		—			17,509			1,272			—			—			18,781
Other long-term liabilities		—			—			103,559			—			—			103,559
Total liabilities		—			778,029			513,259			2,092			—			1,293,380
Commitments and Contingencies (Note 10)
Stockholders’ equity (deficit)		(54,087	)		(54,087	)		659,272			38,391			(643,576	)		(54,087	)
	$	(54,087	)	$	723,942		$	1,172,531		$	40,483		$	(643,576	)	$	1,239,293

F-30

TALOS ENERGY INC.

(FORMERLY KNOWN AS TALOS ENERGY LLC)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2016

(In thousands)

	Parent		Subsidiary Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	24,349		$	5,550		$	2,332		$	—		$	32,231
Restricted cash		—		—			1,202			—			—			1,202
Accounts receivable, net
Trade, net		—		—			52,764			—			—			52,764
Joint interest, net		—		—			7,569			7,104			—			14,673
Other		—		9,476			531			2,393			—			12,400
Assets from price risk management activities		—		20,176			—			—			—			20,176
Prepaid assets		—		—			18,411			9			—			18,420
Inventory		—		—			1,093			—			—			1,093
Other current assets		—		—			2,492			—			—			2,492
Total current assets		—		54,001			89,612			11,838			—			155,451
Property and equipment:
Proved properties		—		—			2,235,835			—			—			2,235,835
Unproved properties, not subject to amortization		—		—			64,949			7,411			—			72,360
Other property and equipment		—		7,007			1,513			11			—			8,531
Total property and equipment		—		7,007			2,302,297			7,422			—			2,316,726
Accumulated depreciation, depletion and amortization		—		(4,954	)		(1,268,580	)		(4	)		—			(1,273,538	)
Total property and equipment, net		—		2,053			1,033,717			7,418			—			1,043,188
Other long-term assets:
Assets from price risk management activities		—		293			—			—			—			293
Other well equipment inventory		—		—			12,744			—			—			12,744
Investments in subsidiaries		6,986		700,385			—			—			(707,371	)		—
Other assets		—		48			574			—			—			622
Total assets	$	6,986	$	756,780		$	1,136,647		$	19,256		$	(707,371	)	$	1,212,298
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	—	$	133		$	27,570		$	3,527		$	—		$	31,230
Accrued liabilities		—		1,208			48,318			390			—			49,916
Accrued royalties		—		—			23,293			—			—			23,293
Current portion of asset retirement obligations		—		—			33,556			—			—			33,556
Liabilities from price risk management activities		—		27,147			—			—			—			27,147
Accrued interest payable		—		11,376			—			—			—			11,376
Other current liabilities		—		—			14,666			—			—			14,666
Total current liabilities		—		39,864			147,403			3,917			—			191,184
Long-term debt, net of discount and deferred financing costs		—		701,175			—			—			—			701,175
Asset retirement obligations		—		—			186,493			—			—			186,493
Liabilities from price risk management activities		—		8,755			—			—			—			8,755
Other long-term liabilities		—		—			117,705			—			—			117,705
Total liabilities		—		749,794			451,601			3,917			—			1,205,312
Commitments and Contingencies (Note 10)
Stockholders’ equity (deficit)		6,986		6,986			685,046			15,339			(707,371	)		6,986
	$	6,986	$	756,780		$	1,136,647		$	19,256		$	(707,371	)	$	1,212,298

F-31

TALOS ENERGY INC.

(FORMERLY KNOWN AS TALOS ENERGY LLC)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2017

(In thousands)

	Parent			Subsidiary Issuers			Guarantors			Non- Guarantors			Elimination		Consolidated
Revenues:
Oil revenue	$	—		$	—		$	344,781		$	—		$	—	$	344,781
Natural gas revenue		—			—			48,886			—			—		48,886
NGL revenue		—			—			16,658			—			—		16,658
Other		—			—			2,503			—			—		2,503
Total revenue		—			—			412,828			—			—		412,828
Operating expenses:
Direct lease operating expense		—			—			109,180			—			—		109,180
Insurance		—			—			10,743			—			—		10,743
Production taxes		—			—			1,460			—			—		1,460
Total lease operating expense		—			—			121,383			—			—		121,383
Workover and maintenance expense		—			—			32,825			—			—		32,825
Depreciation, depletion and amortization		—			1,401			155,947			4			—		157,352
Accretion expense		—			—			19,295			—			—		19,295
General and administrative expense		—			21,882			14,172			619			—		36,673
Total operating expenses		—			23,283			343,622			623			—		367,528
Operating income (loss)		—			(23,283	)		69,206			(623	)		—		45,300
Interest expense		—			(48,236	)		(30,252	)		(2,446	)		—		(80,934	)
Price risk management activities expense		—			(22,998	)		(4,565	)		—			—		(27,563	)
Other income (expense)		—			600			(333	)		62			—		329
Equity earnings from subsidiaries		(62,868	)		31,049			—			—			31,819		—
Net income (loss)	$	(62,868	)	$	(62,868	)	$	34,056		$	(3,007	)	$	31,819	$	(62,868	)

F-32

TALOS ENERGY INC.

(FORMERLY KNOWN AS TALOS ENERGY LLC)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2016

(In thousands)

	Parent			Subsidiary Issuers			Guarantors			Non- Guarantors			Elimination		Consolidated
Revenues:
Oil revenue	$	—		$	—		$	197,583		$	—		$	—	$	197,583
Natural gas revenue		—			—			42,705			—			—		42,705
NGL revenue		—			—			9,532			—			—		9,532
Other		—			—			8,934			—			—		8,934
Total revenue		—			—			258,754			—			—		258,754
Operating expenses:
Direct lease operating expense		—			—			124,360			—			—		124,360
Insurance		—			—			13,101			—			—		13,101
Production taxes		—			—			1,958			—			—		1,958
Total lease operating expense		—			—			139,419			—			—		139,419
Workover and maintenance expense		—			—			24,810			—			—		24,810
Depreciation, depletion and amortization		—			1,553			123,132			4			—		124,689
Accretion expense		—			—			21,829			—			—		21,829
General and administrative expense		—			13,204			15,044			438			—		28,686
Total operating expenses		—			14,757			324,234			442			—		339,433
Operating loss		—			(14,757	)		(65,480	)		(442	)		—		(80,679	)
Interest expense		—			(47,291	)		(19,680	)		(3,444	)		—		(70,415	)
Price risk management activities expense		—			(57,398	)		—			—			—		(57,398	)
Other income (expense)		—			—			430			(25	)		—		405
Equity earnings from subsidiaries		(208,087	)		(88,641	)		—			—			296,728		—
Net income (loss)	$	(208,087	)	$	(208,087	)	$	(84,730	)	$	(3,911	)	$	296,728	$	(208,087	)

F-33

TALOS ENERGY INC.

(FORMERLY KNOWN AS TALOS ENERGY LLC)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2015

(In thousands)

	Parent			Subsidiary Issuers			Guarantors			Non- Guarantors			Elimination		Consolidated
Revenues:
Oil revenue	$	—		$	—		$	244,167		$	—		$	—	$	244,167
Natural gas revenue		—			—			55,026			—			—		55,026
NGL revenue		—			—			10,523			—			—		10,523
Other		—			—			5,890			—			—		5,890
Total revenue		—			—			315,606			—			—		315,606
Operating expenses:
Direct lease operating expense		—			—			171,095			—			—		171,095
Insurance		—			—			17,965			—			—		17,965
Production taxes		—			—			3,311			—			—		3,311
Total lease operating expense		—			—			192,371			—			—		192,371
Workover and maintenance expense		—			—			29,752			—			—		29,752
Depreciation, depletion and amortization		—			1,528			211,161			—			—		212,689
Write-down of oil and natural gas properties		—			—			603,388			—			—		603,388
Accretion expense		—			—			19,395			—			—		19,395
General and administrative expense		—			19,630			14,541			1,491			—		35,662
Total operating expenses		—			21,158			1,070,608			1,491			—		1,093,257
Operating loss		—			(21,158	)		(755,002	)		(1,491	)		—		(777,651	)
Interest expense		—			(46,235	)		(4,080	)		(1,229	)		—		(51,544	)
Price risk management activities income		—			182,196			—			—			—		182,196
Other income		—			129			176			9			—		314
Equity earnings from subsidiaries		(646,685	)		(761,617	)		—			—			1,408,302		—
Net income (loss)	$	(646,685	)	$	(646,685	)	$	(758,906	)	$	(2,711	)	$	1,408,302	$	(646,685	)

F-34

TALOS ENERGY INC.

(FORMERLY KNOWN AS TALOS ENERGY LLC)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2017

(In thousands)

	Parent		Subsidiary Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	—	$	(30,245	)	$	204,419		$	1,879		$	—		$	176,053
Cash flows from investing activities:
Exploration, development, and other capital expenditures		—		(260	)		(132,317	)		(22,600	)		—			(155,177	)
Cash paid for acquisitions, net of cash acquired		—		—			(2,464	)		—			—			(2,464	)
Investments in subsidiaries		—		(577,055	)		—			—			577,055			—
Distributions from subsidiaries		—		611,526			6,041			—			(617,567	)		—
Net cash provided by (used in) investing activities		—		34,211			(128,740	)		(22,600	)		(40,512	)		(157,641	)
Cash flows from financing activities:
Redemption of 2018 Senior Notes		—		(1,000	)		—			—			—			(1,000	)
Proceeds from Bank Credit Facility		—		10,000			—			—			—			10,000
Repayment of Bank Credit Facility		—		(15,000	)		—			—			—			(15,000	)
Payments of capital lease		—		—			(12,412	)		—			—			(12,412	)
Capital contributions		—		—			550,555			26,500			(577,055	)		—
Distributions to subsidiaries		—		—			(611,526	)		(6,041	)		617,567			—
Net cash provided by (used in) financing activities		—		(6,000	)		(73,383	)		20,459			40,512			(18,412	)
Net increase (decrease) in cash, cash equivalents and restricted cash		—		(2,034	)		2,296			(262	)		—			—
Cash, cash equivalents and restricted cash:
Balance, beginning of period		—		24,349			6,752			2,332			—			33,433
Balance, end of period	$	—	$	22,315		$	9,048		$	2,070		$	—		$	33,433

F-35

TALOS ENERGY INC.

(FORMERLY KNOWN AS TALOS ENERGY LLC)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2016

(In thousands)

	Parent			Subsidiary Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	—		$	124,698		$	(2,806	)	$	(5,769	)	$	—		$	116,123
Cash flows from investing activities:
Exploration, development, and other capital expenditures		—			(301	)		(106,647	)		(6,084	)		—			(113,032	)
Cash paid for acquisitions, net of cash acquired		—			—			(85,886	)		—			—			(85,886	)
Investments in subsidiaries		(91,891	)		(524,192	)		—			—			616,083			—
Distributions from subsidiaries		—			411,074			—			—			(411,074	)		—
Net cash provided by (used in) investing activities		(91,891	)		(113,419	)		(192,533	)		(6,084	)		205,009			(198,918	)
Cash flows from financing activities:
Proceeds from Bank Credit Facility		—			15,000			—			—			—			15,000
Repayment of Bank Credit Facility		—			(10,000	)		—			—			—			(10,000	)
Payments of capital lease		—			—			(5,267	)		—			—			(5,267	)
Capital contributions		—			—			599,630			16,453			(616,083	)		—
Distributions to subsidiaries		—			—			(408,050	)		(3,024	)		411,074			—
Contributions from Sponsors		93,750			—			—			—			—			93,750
Distributions to Sponsors		(1,859	)		—			—			—			—			(1,859	)
Net cash provided by (used in) financing activities		91,891			5,000			186,313			13,429			(205,009	)		91,624
Net increase (decrease) in cash, cash equivalents and restricted cash		—			16,279			(9,026	)		1,576			—			8,829
Cash, cash equivalents and restricted cash:
Balance, beginning of period		—			8,070			15,778			756			—			24,604
Balance, end of period	$	—		$	24,349		$	6,752		$	2,332		$	—		$	33,433

F-36

TALOS ENERGY INC.

(FORMERLY KNOWN AS TALOS ENERGY LLC)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2015

(In thousands)

	Parent			Subsidiary Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Cash flows from operating activities:
Net cash provided by operating activities	$	—		$	81,598		$	55,946		$	822		$	—		$	138,366
Cash flows from investing activities:
Exploration, development, and other capital expenditures		—			(2,380	)		(242,203	)		(1,133	)		—			(245,716	)
Cash paid for acquisitions, net of cash acquired		—			—			(39,423	)		—			—			(39,423	)
Investments in subsidiaries		(73,500	)		(579,822	)		—			—			653,322			—
Distributions from subsidiaries		—			300,891			—			—			(300,891	)		—
Net cash provided by (used in) investing activities		(73,500	)		(281,311	)		(281,626	)		(1,133	)		352,431			(285,139	)
Cash flows from financing activities:
Proceeds from Bank Credit Facility		—			120,000			—			—			—			120,000
Repayment of Bank Credit Facility		—			(30,000	)		—			—			—			(30,000	)
Repayment of GCER Bank Credit Facility		—			—			(55,000	)		—			—			(55,000	)
Deferred financing costs		—			(269	)		—			—			—			(269	)
Capital contributions		—			73,500			578,643			1,179			(653,322	)		—
Distributions to subsidiaries		—			—			(300,779	)		(112	)		300,891			—
Contributions from Sponsors		75,000			—			—			—			—			75,000
Distributions to Sponsors		(1,500	)		—			—			—			—			(1,500	)
Net cash provided by (used in) financing activities		73,500			163,231			222,864			1,067			(352,431	)		108,231
Net increase (decrease) in cash, cash equivalents and restricted cash		—			(36,482	)		(2,816	)		756			—			(38,542	)
Cash, cash equivalents and restricted cash
Balance, beginning of period		—			44,552			18,594			—			—			63,146
Balance, end of period	$	—		$	8,070		$	15,778		$	756		$	—		$	24,604

F-37

Note 12—Selected Quarterly Financial Data (Unaudited)

Unaudited quarterly financial data are as follows (in thousands):

	March 31			June 30			September 30			December 31
Quarter Ended 2017
Revenues	$	101,824		$	95,426		$	99,962		$	115,616
Operating income	$	7,287		$	6,314		$	13,329		$	18,370
Price risk management activities income (expense)	$	45,893		$	38,995		$	(28,086	)	$	(84,365	)
Net income (loss)	$	34,462		$	24,607		$	(36,177	)	$	(85,760	)
Quarter Ended 2016
Revenues	$	50,656		$	67,405		$	63,775		$	76,918
Operating loss	$	(40,011	)	$	(20,697	)	$	(12,868	)	$	(7,103	)
Price risk management activities income (expense)	$	12,924		$	(48,930	)	$	11,350		$	(32,742	)
Net loss	$	(40,799	)	$	(84,715	)	$	(22,219	)	$	(60,354	)

Note 13—Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs

Aggregate amounts of capitalized costs relating to our oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion, depreciation and amortization as of the dates indicated are presented below (in thousands):

	December 31,
	2017			2016
Proved properties	$	2,440,811		$	2,235,835
Unproved oil and gas properties, not subject to amortization		72,002			72,360
Total oil and gas properties		2,512,813			2,308,195
Less: Accumulated depletion and amortization		(1,423,829	)		(1,268,276	)
Net capitalized costs	$	1,088,984		$	1,039,919
Depletion and amortization rate per Boe	$	14.85		$	13.82

Included in the depletable basis of our proved oil and gas properties is the estimate of our proportionate share of asset retirement costs relating to these properties which are also reflected as asset retirement obligations in the accompanying consolidated balance sheets. At December 31, 2017 and 2016 our oil and gas asset retirement obligations totaled $214.7 million and $220.0 million, respectively.

F-38

Costs Incurred for Property Acquisition, Exploration and Development Activities

The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year.

	Year Ended December 31,
	2017		2016		2015
Property acquisition costs:
Proved properties	$	1,108	$	77,906	$	68,463
Unproved properties, not subject to amortization		5,778		15,919		39,265
Total property acquisition costs		6,886		93,825		107,728
Exploration costs		82,887		27,807		25,908
Development costs		114,846		195,869		228,257
Total costs incurred	$	204,619	$	317,501	$	361,893

Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves

We have employed full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Our engineering reserve estimates were prepared based upon interpretation of production performance data and sub-surface information obtained from the drilling of existing wells. Our Director of Reserves, internal reservoir engineers and geologists analyzed and prepared reserve estimates on all of our oil and natural gas fields. All of the Company’s proved oil, natural gas and NGL reserves are located offshore in the Gulf of Mexico and lower Gulf Coast regulated by the United States, the State of Louisiana, or the State of Texas.

At December 31, 2017 and 2016, 100% of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil and natural gas properties were estimated and complied for reporting purposes by our reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists. At December 31, 2015, 100% of proved oil, natural gas and NGL reserves attributable to our net interests in legacy oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers and audited by Ryder Scott, independent petroleum engineers and geologists and 100% of proved oil, natural gas and NGL reserves attributable to the assets acquired in the GCER Acquisition were estimated and compiled for reporting purposes by our reservoir engineers and audited by NSAI.

F-39

The following table presents our estimated proved reserves at our net ownership interest:

	Oil (MBbls)			Gas (MMcf)			NGL (MBbls)			Oil Equivalent (MBoe)
Total proved reserves at December 31, 2014		46,120			136,232			4,096			72,921
Revision of previous estimates		(3,435	)		(22,580	)		207			(6,991	)
Production		(5,161	)		(21,458	)		(588	)		(9,325	)
Purchases of reserves		4,029			30,527			385			9,502
Extensions and discoveries		4,801			6,503			481			6,366
Total proved reserves at December 31, 2015		46,354			129,224			4,581			72,473
Revision of previous estimates		(1,712	)		10,024			(352	)		(394	)
Production		(5,126	)		(19,001	)		(603	)		(8,896	)
Purchases of reserves		11,128			11,208			950			13,946
Extensions and discoveries		21,722			19,149			1,660			26,573
Total proved reserves at December 31, 2016		72,366			150,604			6,236			103,702
Revision of previous estimates		(2,673	)		(15,860	)		250			(5,067	)
Production		(7,048	)		(16,308	)		(706	)		(10,472	)
Extensions and discoveries		10,159			9,220			767			12,462
Total proved reserves at December 31, 2017		72,804			127,656			6,547			100,625
Total proved developed reserves as of:
December 31, 2015		33,016			90,432			3,383			51,471
December 31, 2016		45,753			96,122			4,032			65,805
December 31, 2017		37,460			77,577			3,315			53,704
Total proved undeveloped reserves as of:
December 31, 2015		13,338			38,792			1,198			21,002
December 31, 2016		26,613			54,482			2,204			37,897
December 31, 2017		35,344			50,079			3,232			46,921

(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.

During 2017, the Company added 12.5 MMBoe of estimated proved reserves from extensions and discoveries primarily from drilling our Tornado II exploration prospect. These were offset by a decrease of 10.5 MMBoe of production and 5.1 MMBoe of negative performance revisions.

During 2016, the Company added 13.9 MMBoe of estimated proved reserves through the purchase of reserves from the asset transaction of the Sojitz Acquisition. The Company also added 26.6 MMBoe of estimated proved reserves from extensions and discoveries from successful drilling of the Tornado exploration well in the Phoenix Field.

During 2015, the Company added 9.5 MMBoe of estimated proved reserves through purchases of reserves consisting of 5.1 MMBoe and 4.4 MMBoe in estimated proved reserves acquired in the GCER Acquisition and DGE Acquisition, respectively. Downward revisions of previous estimates of 7.0 MMBoe were primarily due to the significant decline in commodity prices resulting in uneconomic reserves.

F-40

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The following table reflects the standardized measure of discounted future net cash flows relating to our interest in proved oil, natural gas and NGL reserves (in thousands):

	December 31,
	2017			2016			2015
Future cash inflows	$	4,308,863		$	3,390,612		$	2,786,828
Future costs:
Production		(815,509	)		(775,354	)		(1,363,585	)
Development and abandonment		(823,164	)		(664,254	)		(646,161	)
Future net cash flows before income taxes		2,670,190			1,951,004			777,082
Future income tax expense		—			—			—
Future net cash flows before income taxes		2,670,190			1,951,004			777,082
Discount at 10% annual rate		(862,521	)		(614,969	)		(174,101	)
Standardized measure of discounted future net cash flows	$	1,807,669		$	1,336,035		$	602,981

Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of our derivative instruments. See the following table for base prices used in determining the standardized measure:

	Year Ended December 31,
	2017		2016		2015
Oil price per Bbl	$	51.36	$	40.02	$	50.72
Natural gas prices per Mcf	$	3.20	$	2.66	$	2.75
NGL price per Bbl	$	24.64	$	14.96	$	17.60

Future net cash flows are discounted at the prescribed rate of 10%. We caution that actual future net cash flows may vary considerably from these estimates. Although our estimates of total proved reserves, development costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves.

F-41

Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to our proved oil, natural gas and NGL reserves are as follows (in thousands):

	Year Ended December 31,
	2017			2016			2015
Standardized measure, beginning of year	$	1,336,035		$	602,981		$	1,888,958
Changes during the year:
Sales, net of production costs		(288,942	)		(114,625	)		(117,344	)
Net change in prices and production costs		555,100			80,174			(1,879,436	)
Changes in future development costs		(156,282	)		2,292			92,182
Development costs incurred		146,687			108,484			273,532
Accretion of discount		133,603			60,298			188,896
Net change in income taxes		—			—			—
Purchases of reserves		—			222,581			229,052
Extensions and discoveries		328,565			479,833			91,722
Sales of reserves		—			—			—
Net change due to revision in quantity estimates		(113,629	)		(5,685	)		(103,842	)
Changes in production rates (timing) and other		(133,468	)		(100,298	)		(60,739	)
Total		471,634			733,054			(1,285,977	)
Standardized measure, end of year	$	1,807,669		$	1,336,035		$	602,981

Note 14—Subsequent Events

Derivative Contracts

For additional information, see Note 5—Financial Instruments.

Bank Credit Facility

For additional information, see Note 6—Debt.

2018 Senior Notes

For additional information, see Note 6—Debt.

Performance Obligations

For additional information, see Note 10—Commitments and Contingencies.

Other Commitments

For additional information, see Note 10—Commitments and Contingencies.

Note 15—Subsequent Change in Reporting Entity and Financial Statement Presentation

On May 10, 2018, Talos Energy Inc. consummated the transactions contemplated by that certain Transaction Agreement, dated as of November 21, 2017 (the “Transaction Agreement”), as discussed in Note 3—Acquisitions, among Stone, Talos Energy Inc., Sailfish Merger Sub Corporation, Talos Energy LLC and Talos Production LLC, pursuant to which, among other items, each of Stone, Talos Production LLC and Talos Energy LLC became wholly-owned subsidiaries of Talos Energy Inc. (the “Stone Combination”). In connection with the Stone Combination on May 10, 2018, the Transaction Fee Agreement and the Service Fee Agreement, as discussed in Note 9, were terminated.

F-42

The financial information included in the financial statements is that of Talos Energy LLC prior to the Stone Combination because the Stone Combination was consummated after the period covered by these financial statements. Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP. In connection with the Transactions, the Series A, Series B and Series C Units were exchanged for an equivalent number of units in each of an entity affiliated with Apollo Management VII, L.P. and Apollo Commodities Management, L.P. and an entity affiliated with Riverstone Energy Partners V, L.P., each of which hold common stock of the Company. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Statement of Changes in Equity to reflect the legal capital of Talos Energy Inc. and the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination as such the financial statements are named Talos Energy Inc. (formerly known as Talos Energy LLC).

F-43

TALOS ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

	June 30, 2018			December 31, 2017
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	78,860		$	32,191
Restricted cash		1,244			1,242
Accounts receivable
Trade, net		100,824			62,871
Joint interest, net		8,394			13,613
Other		7,091			12,486
Assets from price risk management activities		499			1,563
Prepaid assets		51,698			17,931
Inventory		—			840
Income tax receivable		16,212			—
Other current assets		3,910			2,148
Total current assets		268,732			144,885
Property and equipment:
Proved properties		3,412,875			2,440,811
Unproved properties, not subject to amortization		103,836			72,002
Other property and equipment		28,884			8,857
Total property and equipment		3,545,595			2,521,670
Accumulated depreciation, depletion and amortization		(1,547,656	)		(1,430,890	)
Total property and equipment, net		1,997,939			1,090,780
Other long-term assets:
Assets from price risk management activities		234			345
Other well equipment		9,021			2,577
Other assets		8,143			706
Total assets	$	2,284,069		$	1,239,293
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	38,731		$	72,681
Accrued liabilities		155,902			87,973
Accrued royalties		28,508			24,208
Current portion of long-term debt		434			24,977
Current portion of asset retirement obligations		94,334			39,741
Liabilities from price risk management activities		154,722			49,957
Accrued interest payable		7,454			8,742
Other current liabilities		15,541			15,188
Total current liabilities		495,626			323,467
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs		627,968			672,581
Asset retirement obligations		320,044			174,992
Liabilities from price risk management activities		31,766			18,781
Other long-term liabilities		122,820			103,559
Total liabilities		1,598,224			1,293,380
Commitments and contingencies (Note 11)
Equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized; no shares issued or outstanding as of June 30, 2018 and December 31, 2017		—			—
Common stock $0.01 par value; 270,000,000 shares authorized; 54,155,768 and 31,244,085 shares issued and outstanding as of June 30, 2018 and December 31, 2017, respectively		542			312
Additional paid-in capital		1,323,604			489,870
Accumulated deficit		(638,301	)		(544,269	)
Total stockholders’ equity (deficit)		685,845			(54,087	)
Total liabilities and equity	$	2,284,069		$	1,239,293

F-44

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per common share amounts)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Revenues:
Oil revenue	$	180,161		$	78,719		$	307,854		$	162,487
Natural gas revenue		16,448			12,888			29,171			26,062
NGL revenue		7,297			3,436			12,731			7,069
Other		—			383			—			1,632
Total revenue		203,906			95,426			349,756			197,250
Operating expenses:
Direct lease operating expense		34,060			28,871			58,975			56,735
Insurance		4,259			2,688			6,934			5,409
Production taxes		564			380			955			645
Total lease operating expense		38,883			31,939			66,864			62,789
Workover and maintenance expense		17,714			8,225			24,619			17,047
Depreciation, depletion and amortization		67,726			36,157			116,766			76,088
Accretion expense		9,492			5,321			14,252			10,509
General and administrative expense		30,880			7,470			39,460			17,216
Total operating expenses		164,695			89,112			261,961			183,649
Operating income		39,211			6,314			87,795			13,601
Interest expense		(21,678	)		(20,805	)		(41,420	)		(39,577	)
Price risk management activities income (expense)		(91,176	)		38,995			(143,152	)		84,888
Other income (expense)		(1,269	)		103			(1,078	)		157
Total other income (expense)		(114,123	)		18,293			(185,650	)		45,468
Income (loss) before income taxes		(74,912	)		24,607			(97,855	)		59,069
Income tax expense (benefit)		—			—			—			—
Net income (loss)	$	(74,912	)	$	24,607		$	(97,855	)	$	59,069
Net income (loss) per common share:
Basic	$	(1.69	)	$	0.79		$	(2.59	)	$	1.89
Diluted	$	(1.69	)	$	0.79		$	(2.59	)	$	1.89
Weighted average common shares outstanding:
Basic		44,336			31,244			37,826			31,244
Diluted		44,336			31,244			37,826			31,244

F-45

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In thousands)

(Unaudited)

	Common Stock		Additional Paid-In Capital		Retained Earnings (Accumulated Deficit)			Total Stockholders’ Equity (Deficit)
Balance at January 1, 2018	$	312	$	489,870	$	(544,269	)	$	(54,087	)
Cumulative effect adjustment (Note 1)		—		—		(325	)		(325	)
Sponsor Debt Exchange		29		101,971		—			102,000
Stone Combination		201		731,763		—			731,964
Equity based compensation		—		—		4,148			4,148
Net loss		—		—		(97,855	)		(97,855	)
Balance at June 30, 2018	$	542	$	1,323,604	$	(638,301	)	$	685,845

F-46

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended June 30,
	2018			2017
Cash flows from operating activities:
Net income (loss)	$	(97,855	)	$	59,069
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, amortization and accretion expense		131,018			86,597
Amortization of deferred financing costs and original issue discount		2,607			1,629
Equity based compensation, net of amounts capitalized		1,559			495
Price risk management activities (income) expense		143,152			(84,888	)
Net cash receipts (payments) on settled derivative instruments		(54,056	)		13,668
Settlement of asset retirement obligations		(43,896	)		(10,915	)
Changes in operating assets and liabilities:
Accounts receivable		19,462			27,814
Other current assets		(13,576	)		1,127
Accounts payable		(53,126	)		10,885
Other current liabilities		52,543			(16,961	)
Other non-current assets and liabilities, net		19,279			(3,257	)
Net cash provided by operating activities		107,111			85,263
Cash flows from investing activities:
Exploration, development and other capital expenditures		(140,968	)		(62,535	)
Cash acquired in (paid for) acquisitions		293,001			(2,244	)
Net cash provided by (used in) investing activities		152,033			(64,779	)
Cash flows from financing activities:
Redemption of Senior Notes and other long-term debt		(25,046	)		(1,000	)
Proceeds from Bank Credit Facility		294,000			—
Repayment of Bank Credit Facility		(54,000	)		—
Proceeds from Old Bank Credit Facility		—			10,000
Repayment of Old Bank Credit Facility		(403,000	)		(15,000	)
Deferred financing costs		(17,469	)		—
Payments of capital lease		(6,958	)		(5,870	)
Net cash used in financing activities		(212,473	)		(11,870	)
Net increase in cash, cash equivalents and restricted cash		46,671			8,614
Cash, cash equivalents and restricted cash:
Balance, beginning of period		33,433			33,433
Balance, end of period	$	80,104		$	42,047
Supplemental Non-Cash Transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	38,205		$	30,712
Supplemental Cash Flow Information:
Interest paid, net of amounts capitalized	$	23,635		$	25,405

F-47

TALOS ENERGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

Note 1—Formation and Basis of Presentation

Formation and Nature of Business

Talos Energy Inc. (“Talos” or the “Company”) is 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. The Company’s 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 the Company high impact exploration opportunities in an emerging basin. The Company uses its access to an extensive seismic database and its deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. The Company’s 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 May 10, 2018 (the “Closing Date”), the Company (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”), the Company, Sailfish Merger Sub Corporation (“Merger Sub”), Talos Energy LLC and Talos Production LLC, pursuant to which, among other items, each of Stone, Talos Production LLC and Talos Energy LLC became wholly-owned subsidiaries of the Company (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 the following: (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. and Apollo Commodities Management, L.P. with respect to Series I (“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”).

Concurrently with the consummation of the Transaction Agreement, the Company consummated the transactions contemplated by the certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”), among the Company, Stone, the Talos Issuers (defined below), the various lenders and noteholders of the Talos 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 (“9.75% Senior Notes”) issued by Talos Production LLC and Talos Production Finance, Inc. (together, the “Talos Issuers”) to the Company in exchange for an aggregate of 2,874,049 shares of Common Stock (the “Sponsor Debt Exchange”); (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 (“11.00% Senior Secured Notes”) and (iii) Franklin Noteholders and

F-48

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 11.00% Senior Secured Notes.

As a result of the closing of the transactions contemplated by the Transaction Agreement and the Exchange Agreement (the “Transactions”) the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Closing Date.

Unless otherwise indicated or the context otherwise requires, references herein to “us,” “we,” “our” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries.

Basis of Presentation and Consolidation

The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) as applied to interim financial statements and include each subsidiary from the date of inception. Because this is an interim periodic report presented using a condensed format, it does not include all of the annual disclosures required by GAAP. Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP. Accordingly, the historical financial and operating data of Talos Energy Inc., 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. These condensed consolidated financial statements should be read in conjunction with Talos Energy LLC’s audited financial statements and the notes thereto for the year ended December 31, 2017, which are included elsewhere in this prospectus. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Statement of Changes in Equity and the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the business combination. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos. All intercompany transactions have been eliminated. All adjustments that are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the interim periods are reflected herein. The results for any interim period are not necessarily indicative of the expected results for the entire year. The Company has evaluated subsequent events through the date the condensed consolidated financial statements were issued.

For presentation purposes, as of June 30, 2018, certain balances previously disclosed as “Accounts payable” and “Other current assets” have been reclassified to “Accrued liabilities” and “Prepaid assets”, respectively. The corresponding balances as of December 31, 2017 of $73.5 million and $7.3 million were reclassified to “Accrued liabilities” and “Prepaid assets”, respectively. The balance sheet reclass between “Accounts payable” and “Accrued liabilities” is related to estimates of operating costs incurred but not yet invoiced.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.

During September 2015, the Company expanded its acreage position to include two shallow water exploration blocks off the coast of Mexico and drilled its first well in those blocks in July 2017. The business activities in Mexico, which are currently deemed immaterial, have been combined with the United States and reported as one segment. See additional information in Note 4—Property, Plant and Equipment.

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Recently Adopted Accounting Standards

Impact of the Adoption of ASC 606—Revenue from Contracts with Customers

On January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) 606,Revenue from Contracts with Customers using the modified retrospective approach. ASC 606 supersedes the revenue recognition requirements in Topic 615,Revenue Recognition, and industry-specific guidance in Subtopic 932-605,Extractive Activities—Oil and Gas—Revenue Recognition.The new standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for these goods and services.

The Company records 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.

The Company does not disclose the value of unsatisfied performance obligations for contracts with an original expected length of one year or less or contracts for which variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

Gas Imbalances. Under previous accounting guidance, the Company used the entitlement method to account for sales and production. Under the entitlement method, revenue was recorded based on the Company’s entitled share of production with any difference recorded as an imbalance on the condensed consolidated balance sheet. Upon the adoption of ASC 606, revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an underlying property. The change in accounting method from the entitlements method to the sales method resulted in an immaterial cumulative-effect adjustment to members’ deficit on the date of adoption.

Production Handling Fees. Under previous accounting guidance, the Company presented certain reimbursements for costs from certain third parties as other revenue on the condensed consolidated statement of operations. Upon the adoption of ASC 606, the reimbursements are presented as a reduction of direct lease operating expense on the condensed consolidated statement of operations. The impact of the reclassification for the three and six months ended June 30, 2018 was immaterial.

Recently Issued Accounting Standards

In February 2016, the Financial Accounting Standards Boards (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02,Leases (Topic 842).This ASU supersedes the lease requirements in Topic 840,Leases, and requires that a lessee recognize a right-of-use asset and lease liability for leases that do not meet the definition of a short-term lease. The right-of-use asset and lease liability are to be measured on the balance sheet at the present value of the lease payments. For income statement purposes, ASU 2016-02 retains a dual model requiring leases to be classified as either operating or finance within the Company’s condensed consolidated statements of operations. Lease costs for operating leases are recognized as a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. For finance leases, interest expense is recognized on the lease liability separately from amortization of the right-to-use asset. ASU 2016-02 does not apply to leases for oil and natural gas properties, but does apply to equipment used to explore and develop oil and natural gas reserves. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company is currently assessing the impact of ASU 2016-02 which includes an analysis of existing contracts and current accounting policies and disclosures that will change as a result of the adoption. Appropriate systems, controls and processes to support the recognition and disclosure requirements of the ASU 2016-02 are also being evaluated. The Company is currently evaluating the impact of this ASU on its

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condensed consolidated financial statements. The Company plans to adopt ASU 2016-02 effective January 1, 2019.

Note 2—Summary of Significant Accounting Policies

Below are the Company’s significant accounting policies that have been implemented or changed since December 31, 2017.

Income Taxes

Prior to the Stone Combination, Talos Energy LLC was a partnership for federal income tax purposes and was not subject to federal income tax or state income tax (in most states). As such, Talos Energy LLC was not a taxpaying entity for 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 federal and state income taxes. The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. Changes in tax laws are recorded in the period they are enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the consolidated balance sheets.

The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating our valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, and the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations.

The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expenses, respectively.

Earnings Per Common Share

Basic earnings per common share (“EPS”) is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of restricted stock unit grants and outstanding warrants. See Note 9—Earnings Per Share for additional information.

Share-Based Compensation

The Company records share-based compensation associated with restricted stock units in general and administrative expense on the condensed consolidated statement of operations, net of amounts capitalized to oil and gas properties. Share-based compensation expense is based on the grant date fair value of issued restricted stock units recognized over the vesting period of the instrument. For each restricted stock unit grant, the Company determines whether the awards represent equity or liability based awards. The fair value of equity awards are determined based on the close price of the stock on the grant date. The fair value of the liability awards are remeasured at each reporting date based on the close price of the stock at such date, until the date of settlement. See Note 7—Employee Benefits Plans and Share Based Compensationfor additional information.

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Note 3—Acquisitions

Combination Between Talos Energy LLC and Stone Energy Corporation

On May 10, 2018, the Company consummated the Transactions contemplated by the Transaction Agreement and the Exchange Agreement, pursuant to which, among other things, Talos Energy LLC and Stone became wholly-owned subsidiaries of the Company. Substantially concurrent with the consummation of the Transactions, the name of the Company was changed from Sailfish Energy Holdings Corporation to Talos Energy Inc. The combination was executed as an all-stock transaction whereby the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Closing Date.

The purchase price of $732.0 million is based on the closing price of Stone common stock and common warrants immediately prior to closing. The following table summarizes the purchase price (in thousands, except per share data):

Stone Energy common stock—issued and outstanding as of May 9, 2018		20,038
Stone Energy common stock price	$	35.49
Common stock value	$	711,149
Stone Energy common stock warrants—issued and outstanding as of May 9, 2018		3,528
Stone Energy common stock warrants price	$	5.90
Common stock warrants value	$	20,815
Total consideration and fair value	$	731,964

The Company incurred approximately $76.2 million of transaction related costs, of which, $20.1 million was expensed and reflected in general and administrative expense on the condensed consolidated statement of operations. The remaining $56.1 million was the result of (i) $9.3 million in work fees paid to holders of the 11.00% Senior Secured Notes reflected as a debt discount reducing long-term debt on the condensed consolidated balance sheet and (ii) $46.8 million in fees for seismic use agreements for change in control provisions and reflected in proved properties on the condensed consolidated balance sheet.

The Stone Combination qualified as a business combination and was accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the condensed consolidated balance sheet at their fair values as of the acquisition date, May 10, 2018. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates at the time of the valuation.

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While the Company has substantially completed the determination of the fair values of the assets acquired and liabilities assumed, the Company is still finalizing the fair value analysis related to oil and natural gas properties and the related asset retirement obligations. The Company anticipates finalizing the determination of the fair values by December 31, 2018. The following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on May 10, 2018 (in thousands):

Current assets(1)	$	377,155
Property and equipment		876,500
Other long-term assets		18,928
Current liabilities		(130,121	)
Long-term debt		(235,416	)
Other long-term liabilities		(175,082	)
Allocated purchase price	$	731,964

(1) Includes $293.0 million of cash acquired. The fair values of current assets acquired includes trade receivables and joint interest receivables of $43.3 million and $3.5 million, respectively, which the Company expects all to be realizable.

Pro Forma Financial Information (Unaudited)

The following supplemental pro forma information (in thousands, except per common share amounts), presents the condensed consolidated results of operations for the three and six months ended June 30, 2018 and 2017 as if the Stone Combination had occurred on January 1, 2017. The unaudited proforma information was derived from historical combined statements of operations of the Company and Stone and adjusted to include (i) depletion and accretion expense applied to the adjusted basis of the oil and natural gas properties acquired (ii) interest expense to reflect the debt transactions contemplated by the Exchange Agreement and (iii) general and administrative expense adjusted for transaction related costs incurred. This information does not purport to be indicative of results of operations that would have occurred had the Stone Combination occurred on January 1, 2017, nor is such information indicative of any expected future results of operations.

	Three Months Ended June 30,					Six Months Ended June 30,
	2018			2017		2018			2017
Revenue	$	244,453		$	166,669	$	471,652		$	340,939
Net income (loss)	$	(45,696	)	$	19,032	$	(51,211	)	$	66,518
Basic and diluted net income (loss) per common share	$	(0.84	)	$	0.35	$	(0.95	)	$	1.23

Material, non-recurring adjustments included in pro forma net income (loss) above consist of historical Stone results adjusted to exclude a divestiture of oil and natural gas properties during 2017.

Note 4—Property, Plant and Equipment

Proved Properties. The Company’s interests in oil and natural gas properties are located in the United States (“U.S.”) primarily in the Gulf of Mexico deep and shallow waters. The Company follows the full cost method of accounting for its oil and natural gas exploration and development activities.

Pursuant to SEC Regulation S-X, Rule 4-10, under the full cost method of accounting, the Company’s capitalized oil and natural gas costs, net of related deferred taxes, are limited to a ceiling based on the present value of future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized. The Company performs this ceiling test calculation each quarter utilizing SEC pricing. At June 30, 2018, the Company’s ceiling test computation of its

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U.S. oil and natural gas properties was based on SEC pricing of $60.03 per Bbl of oil, $2.90 per Mcf of natural gas and $28.26 per Bbl of NGLs. During the three and six months ended June 30, 2018 and 2017, the Company’s ceiling test computation did not result in a write-down of its U.S. oil and natural gas properties.

Unproved Properties. Unproved capitalized costs of oil and natural gas properties excluded from amortization relate to unevaluated properties associated with acquisitions, leases awarded in the Gulf of Mexico federal lease sales, certain geological and geophysical costs, costs associated with certain exploratory wells in progress and capitalized interest. Unproved properties also include costs associated with two blocks awarded on September 4, 2015 to the Company, together with the Company’s working interest partners, located in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states, by the National Hydrocarbons Commission (“CNH”).

Capitalized Overhead.General and administrative expense in the Company’s financial statements is reflected net of capitalized overhead. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities. Capitalized overhead for the three months ended June 30, 2018 and 2017 was $4.5 million and $3.1 million, respectively. Capitalized overhead for the six months ended June 30, 2018 and 2017 was $7.5 million and $6.5 million, respectively.

Asset Retirement Obligations.The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when it no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount it will incur to plug, abandon, replace, remove and/or remediate the associated assets at the end of their productive lives. See Note 11—Commitments and Contingencies relating to performance bonds associated with plugging and abandoning wells.

In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate in the table below represent changes to the expected amount and timing of payments to settle the Company’s asset retirement obligations. Typically, these changes result from obtaining new information about the timing of the Company’s obligations to plug, abandon and remediate oil and natural gas wells and related infrastructure and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense on the condensed consolidated statements of operations. If the Company incurs an amount different from the amount accrued for decommissioning obligations, the Company recognizes the difference as an adjustment to proved properties.

The discounted asset retirement obligations included on the condensed consolidated balance sheets in current and non-current liabilities and the changes to that liability during the six months ended June 30, 2018 were as follows (in thousands):

Asset retirement obligations at January 1, 2018	$	214,733
Fair value of asset retirement obligations assumed		220,637
Obligations settled		(43,896	)
Accretion expense		14,252
Obligations incurred		120
Changes in estimate		8,532
Asset retirement obligations at June 30, 2018	$	414,378
Less: Current portion		94,334
Long-term portion	$	320,044

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Note 5—Financial Instruments

The following table presents the carrying amounts and estimated fair values of financial instruments (in thousands):

	June 30, 2018						December 31, 2017
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
11.00% Second-Priority Senior Secured Notes—due April 2022(1)	$	380,042		$	410,411		$	—		$	—
7.50% Senior Secured Notes—due May 2022	$	6,060		$	5,999		$	—		$	—
Bank Credit Facility—due May 2022(1)	$	231,522		$	240,000		$	—		$	—
11.00% Bridge Loans—due April 2022(1)	$	—		$	—		$	169,838		$	172,023
9.75% Senior Notes—due July 2022(1)	$	—		$	—		$	100,681		$	102,000
9.75% Senior Notes—due February 2018	$	—		$	—		$	24,977		$	24,977
Old Bank Credit Facility—due February 2019(1)	$	—		$	—		$	402,062		$	403,000
Oil and Natural Gas Derivatives	$	(185,755	)	$	(185,755	)	$	(66,830	)	$	(66,830	)

(1) The carrying amounts are net of discount and deferred financing costs.

As of June 30, 2018 and December 31, 2017, the carrying amounts of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair values because of the short-term nature of these instruments.

11.00% Second-Priority Senior Secured Notes—due April 2022.The $390.9 million aggregate principal amount of 11.00% Senior Secured Notes are reported on the condensed consolidated balance sheet as of June 30, 2018 at their carrying value, net of original issue discount and deferred financing costs (see Note 6—Debt). The fair value of the 11.00% Senior Secured Notes are estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.

7.50% Senior Secured Notes—due May 2022. The $6.1 million aggregate principal amount of 7.50% Stone Senior Notes are reported on the condensed consolidated balance sheet as of June 30, 2018 at their carrying value (see Note 6—Debt). The fair value of the 7.50% Senior Secured Notes are estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.

Bank Credit Facility—due May 2022.On May 10, 2018, in connection with the Stone Combination, the Company’s senior reserve-based revolving credit facility (“Old Bank Credit Facility”) was repaid and terminated, and the Company executed a new bank credit facility with an initial borrowing base of $600.0 million (“Bank Credit Facility”). The Old Bank Credit Facility was repaid with borrowings from the Bank Credit Facility and cash acquired in the Stone Combination. The Company’s Bank Credit Facility is reported on the condensed consolidated balance sheet as of June 30, 2018 at its carrying value net of deferred financing costs (see Note 6—Debt). The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the Company’s Bank Credit Facility since it is secured by the Company’s reserves and the interest rates are variable and reflective of market rates (representing a Level 2 fair value measurement).

Oil and natural gas derivatives. The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production through the use of oil and natural gas swaps, put contracts and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and sold call option with no net premiums paid to or received from the counterparties. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on the condensed consolidated balance sheet at fair

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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.

The following table presents the impact that derivatives not qualifying as hedging instruments had on the Company’s condensed consolidated statements of operations (in thousands):

	Three Months Ended June 30,					Six Months Ended June 30,
	2018			2017		2018			2017
Price risk management activities income (expense)(1)	$	(91,176	)	$	38,995	$	(143,152	)	$	84,888

(2) The Company paid $33.6 million and received $9.2 million in net cash settlements for the three months ended June 30, 2018 and 2017, respectively, and paid $54.1 million and received $13.7 million in net cash settlements for the six months ended June 30, 2018 and 2017, respectively.

The following table reflects the contracted volumes and weighted average prices the Company will receive under its derivative contracts as of June 30, 2018:

Production Period	Instrument Type		Average Daily Volumes			Weighted Average Swap Price			Weighted Average Put Price			Weighted Average Call Price
Crude Oil—WTI:				(Bbls	)		(per Bbl	)		(per Bbl	)		(per Bbl	)
July 2018—December 2018		Swap		29,615		$	54.06		$	—		$	—
July 2018—December 2018		Collar		1,000		$	—		$	45.00		$	55.35
July 2018—December 2018		Put		2,000		$	—		$	49.50		$	—
January 2019—December 2019		Swap		23,130		$	54.14		$	—		$	—
Natural Gas—Henry Hub NYMEX:				(MMBtu	)		(per MMBtu	)		(per MMBtu	)		(per MMBtu	)
July 2018—December 2018		Swap		23,747		$	3.01		$	—		$	—
July 2018—December 2018		Collar		6,000		$	—		$	2.75		$	3.24
January 2019—December 2019		Swap		10,146		$	2.99		$	—		$	—

The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):

	June 30, 2018
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	733		$	—	$	733
Liabilities:
Oil and natural gas derivatives		—		(186,488	)		—		(186,488	)
Total net liability	$	—	$	(185,755	)	$	—	$	(185,755	)

	December 31, 2017
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	1,908		$	—	$	1,908
Liabilities:
Oil and natural gas derivatives		—		(68,738	)		—		(68,738	)
Total net liability	$	—	$	(66,830	)	$	—	$	(66,830	)

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Financial Statement Presentation. Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although the Company has master netting arrangements with its counterparties, the Company presents its derivative financial instruments on a gross basis on its condensed consolidated balance sheets. On derivative contracts recorded as assets in the table below, the Company is exposed to the risk the counterparties may not perform. The following table presents the fair value of derivative financial instruments at June 30, 2018 and December 31, 2017 (in thousands):

	June 30, 2018		December 31, 2017
Assets from price risk management activities—current:
Oil and natural gas derivatives	$	499	$	1,563
Assets from price risk management activities—non-current:
Oil and natural gas derivatives	$	234	$	345
Liabilities from price risk management activities—current:
Oil and natural gas derivatives	$	154,722	$	49,957
Liabilities from price risk management activities—non-current:
Oil and natural gas derivatives	$	31,766	$	18,781

Credit Risk. The Company is subject to the risk of loss on its financial instruments as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. The Company entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at June 30, 2018 represent derivative instruments from eight counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and six of which are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these third parties and, subject to the terms of the Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities.

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Note 6—Debt

A summary of the detail comprising the Company’s debt and the related book values for the respective periods presented is as follows (in thousands):

Description	June 30, 2018			December 31, 2017
11.00% Second-Priority Senior Secured Notes—due April 2022
Principal	$	390,868		$	—
Original issue discount, net of amortization		(8,906	)		—
Deferred financing costs, net of amortization		(1,920	)		—
7.50% Senior Secured Notes—due May 2022
Principal		6,060			—
Bank Credit Facility—due May 2022
Principal		240,000			—
Deferred financing costs, net of amortization		(8,478	)		—
4.20% Building Loan—due November 2030
Principal		10,778			—
11.00% Bridge Loans—due April 2022
Principal		—			172,023
Deferred financing costs, net of amortization		—			(2,185	)
9.75% Senior Notes—due July 2022
Principal		—			102,000
Deferred financing costs, net of amortization		—			(1,319	)
9.75% Senior Notes—due February 2018
Principal		—			24,977
Old Bank Credit Facility—due February 2019		—			403,000
Deferred financing costs, net of amortization		—			(938	)
Total debt	$	628,402		$	697,558
Less: current portion of long-term debt		(434	)		(24,977	)
Long-term debt, net of discount and deferred financing costs	$	627,968		$	672,581

In connection with the Stone Combination, the Company 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 to the Company 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 11.00% Senior Secured Notes and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Stone Senior Notes for $137.4 million aggregate principal amount of 11.00% Senior Secured Notes. An additional $81.5 million of 7.50% Stone Senior Notes held by non-affiliates were also exchanged for 11.00% Senior Secured Notes pursuant to an exchange offer and consent solicitation in connection with the Stone Combination.

The exchange of 7.50% Stone Senior Notes for 11.00% Senior Secured 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 11.00% Senior Secured Notes is computed and applied prospectively. Costs incurred with third parties directly related to the modification are expensed as incurred. The Company incurred approximately $3.9 million and $4.5 million of transaction fees related to the modification which were expensed and reflected in general and administrative expense during the three months and six months ended June 30, 2018, respectively. The Company 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.

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11.00% Second-Priority Senior Secured Notes—due April 2022. The 11.00% Senior Secured 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 11.00% Senior Secured 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, the Company may, at its option, redeem all or a portion of the 11.00% Senior Secured Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 11.00% Senior Secured Notes at redemption prices decreasing annually from 105.5% to 100.0% plus accrued and unpaid interest.

The indenture governing the 11.00% Senior Secured Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur additional indebtedness or issue certain preferred shares; (ii) pay dividends and make certain other restricted payments; (iii) create restrictions on the payment of dividends or other distributions to the Company from its restricted subsidiaries; (iv) create liens on certain assets to secure debt; (v) make certain investments; (vi) engage in sales of assets and subsidiary stock; (vii) transfer all or substantially all of its assets or enter into merger or consolidation transactions; and (viii) engage in transactions with affiliates. The 11.00% Senior Secured Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at June 30, 2018.

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 11.00% Senior Secured 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, the Company may, at its 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, the Company 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—due May 2022.The Company 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 bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%. In addition, the Company is obligated to pay a commitment fee of 0.50% on the unfunded portion of the commitments under the Bank Credit Facility. The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a total debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 each quarter beginning on or after September 30, 2018. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter beginning on or after September 30, 2018. According to the Bank Credit Facility, undrawn commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by substantially all of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by certain of the Company’s wholly-owned subsidiaries and each direct parent of the Company.

The Bank Credit Facility provides for determination of the borrowing base based on the Company’s proved producing reserves and a portion of its 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, the Company completed the first redetermination and the borrowing base was reaffirmed at $600.0 million. The next redetermination will occur in October 2018 and scheduled redeterminations will occur each April and October thereafter.

F-59

As of June 30, 2018, the Company’s borrowing base was set at $600.0 million, of which no more than $200 million can be used as letters of credit. The amount the Company is 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. The Company was 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 the Company’s initial drawdown under the Bank Credit Facility was used to partially repay outstanding borrowings under the Old Bank Credit Facility upon its termination in connection with the Stone Combination.

Building Loan—due November 2030. In connection with the Stone Combination, the Company assumed Stone’s 4.20% term loan maturing on November 20, 2030 (the “Building Loan”). 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 the Company’s two Lafayette, Louisiana office buildings. Under the financial covenants of the Building Loan, the Company 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. The Company is in compliance with all covenants under the Building Loan as of June 30, 2018.

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 subsidiaries, as 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.

Note 7—Employee Benefits Plans and Share-Based Compensation

Stone Change of Control and Severance Plans

In connection with the Transactions, the Company maintains the Stone Energy Corporation Executive Severance Plan and Stone Energy Corporation Employee Severance Plan, which provides for the payment of severance and change in control benefits to certain individuals who, prior to the transaction, were executive officers of Stone and all full-time employees of Talos Petroleum LLC (f/k/a Stone Energy Corporation), in each case upon an involuntary termination within twelve months of Closing. The Company incurred $7.5 million of severance expense reflected in general and administrative expense on the condensed consolidated statement of operations for the three and six months ended June 30, 2018. Approximately $5.1 million of such expense remained unpaid at June 30, 2018.

Long Term Incentive Plan

Overview. In connection with the Closing, the Company adopted the Talos Energy Inc. Long Term Incentive Plan (the “LTIP”), pursuant to which the Company may issue to its employees, directors and consultants various forms of share-based compensation including stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards or any combination of the foregoing. The Company is authorized to grant awards of up to 5,415,576 shares of the Company’s common stock for awards under the LTIP. As of June 30, 2018, no shares have been issued.

Restricted Stock Units. On May 21, 2018, the Company granted 22,963 restricted stock units (“RSUs”) to non-employee directors. These RSUs will vest on May 19, 2019, subject to such non-employee director’s continued service. These RSUs represent a contingent right to receive 60% in Common Stock and the remaining 40% in cash following vesting. The total unrecognized compensation cost related to these RSUs at June 30, 2018 was approximately $0.7 million, which is expected to be recognized over a weighted average period of eleven months. Of the $0.7 million in unrecognized compensation cost, $0.3 million relates to liability awards and will be subsequently remeasured at each reporting period.

F-60

Talos Energy LLC Series B Units

Prior to the Stone Combination, the Limited Liability Company Agreement of Talos Energy LLC (the “LLC Agreement”) established Series A, Series B and Series C Units. Series B Units were generally intended to be used as incentives for Company employees. Series B Units do not participate in distributions prior to vesting or until Series A Units have received cumulative distributions equal to (i) the original cash contributed to the Company for such Series A Units and (ii) an 8% return, compounded annually (the “Aggregate Series A Payout”), and Series C Units have received $25.0 million in distributions. In connection with the Transactions, the Series A, Series B and Series C Units as described in Note 7 were exchanged for an equivalent number of units in each of an entity affiliated with the Apollo Funds and an entity affiliated with the Riverstone Funds, each of which hold Common Stock of the Company. The modification did not result in incremental value to the Series B Units.

For accounting and financial reporting purposes, the Series B Units are deemed to be equity awards, and the compensation expense related to these awards is recorded on a straight-line basis over the vesting period in the Company’s consolidated financial statements and is reflected as a corresponding credit to “Accumulated deficit” on the condensed consolidated balance sheet. During the six months ended June 30, 2018 and 2017, the Company recognized approximately $0.2 million and $0.5 million, respectively, as compensation expense included in general and administrative expense on the condensed consolidated statement of operations and capitalized approximately $0.2 million and $0.5 million, respectively, into its oil and natural gas properties on the condensed consolidated balance sheet.

The Company’s unrecognized compensation expense at June 30, 2018 is approximately $2.9 million. Of this amount, approximately $0.7 million of the unrecognized compensation expense will continue to be recognized on a straight-line basis over the remainder of the four year requisite service period. The remaining $2.2 million will be recognized upon an Aggregate Series A Payout. The weighted-average period over which the unrecognized compensation expense for the Series B Units will be recognized is 21 months.

New Talos Energy LLC Series B Units

In connection with the transactions contemplated in the Exchange Agreement on May 10, 2018, an entity affiliated with the Apollo Funds and an entity affiliated with the Riverstone Funds, each of which hold Common Stock in the Company as a result of the Sponsor debt modification, established new Series A Units (“New Series A Units”) and new Series B Units (“New Series B Units”). The New Series B Units are generally intended to be used as incentives for Company employees.

The New Series B Units do not participate in distributions prior to vesting or until the New Series A Units have received cumulative distributions of $102.0 million. After issuance, 80% of the New Series B Units vest on a monthly basis over a four year period based on the initial vesting schedule of the original Series B Units, subject to continued employment. All unvested New Series B Units fully vest upon the cumulative distribution of $102.0 million.

For accounting and financial reporting purposes, the New Series B Units are deemed to be equity awards, and the compensation expense related to these awards is recorded on a straight-line basis over the vesting period in the Company’s consolidated financial statements and is reflected as a corresponding credit to “Accumulated deficit”. Accelerated vesting was recognized in May 2018 to account for months between the grant date of the original Series B Units and the grant date of the New Series B Units. For the six months ended June 30, 2018 and 2017, the Company recognized approximately $1.3 million and nil, respectively, of compensation expense included in general and administrative expense on the condensed consolidated statement of operations and capitalized approximately $2.3 million and nil, respectively, into its oil and natural gas properties on the condensed consolidated balance sheet.

The New Series B Units issued were valued using the option pricing method for valuing securities. In this method, the rights and claims of each security are modeled as a portfolio of Black-Scholes-Merton call options

F-61

written on the total equity of the entities affiliated with the Apollo Funds and Riverstone Funds. The total value of the equity is calculated in an iterative process that results in the New Series A Units being valued at par. The risk-free rate of interest is based on the U.S. Treasury yield curve on the grant date. The expected time to a liquidity event is based on a weighted average calculation of management’s estimate considering market conditions and expectations. The expected volatility of equity is based on the volatility of the assets of similar publicly traded companies using a Black-Scholes-Merton model. The discount for lack of marketability is based on the restrictions on the New Series B Units and the volatility of the New Series B Units using a Black-Scholes-Merton model.

The Company’s unrecognized compensation expense at June 30, 2018 is approximately $2.4 million. Of this amount, approximately $0.3 million of the unrecognized compensation expense will continue to be recognized on a straight-line basis over the remainder of the four year requisite service period. The remaining $2.1 million will be recognized upon the New Series A Units receiving the cumulative distribution. The weighted-average period over which the unrecognized compensation expense will be recognized is eleven months.

Note 8—Income Taxes

Prior to the Stone Combination, Talos Energy LLC was a partnership for federal income tax purposes and was not subject to federal income tax or state income tax (in most states). As such, Talos Energy LLC was not a taxpaying entity for federal income tax purposes and accordingly, did not recognize any expense for such states. Talos Energy LLC’s operations in the shallow waters off the coast of Mexico are conducted under a different legal form and are subject to foreign income taxes.

In connection with completing the Stone Combination, Talos Energy LLC was contributed to the Company, which is subject to federal and state income taxes. The Company is also subject to foreign income taxes. Due to the change in tax status, deferred taxes are recorded for differences in book and tax basis. The Company’s differences in its book and tax basis in its assets and liabilities is primarily related to different cost recovery periods utilized for book and tax purposes for the Company’s oil and natural gas properties, asset retirement obligation and net operating loss carryforwards. The Company’s tax basis in assets exceeds its book basis in assets, resulting in a deferred tax asset. A valuation allowance is established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax asset will not be realized. The Company believes it is more likely than not that the net deferred tax asset will not be realized and therefore has recorded a valuation allowance. Due to the valuation allowance, the tax expense resulting from the initial book and tax basis difference from the change in tax status is zero. The Company accounted for the book and tax basis difference from the Stone Combination in acquisition accounting. Due to the valuation allowance, the net income tax impact is zero.

As part of the Stone Combination, entities related to the Apollo Funds and Riverstone Funds contributed entities that were under common control to the Company. At June 30, 2018, the Company also estimated a net deferred tax asset related to tax loss carryforwards and differences in book and tax basis of assets. The net deferred tax asset and valuation allowance from the contribution is accounted for in equity. The Company believes it is more likely than not that the net deferred tax asset will not be realized and therefore has recorded a valuation allowance.

The deferred tax balance is based on preliminary calculations and on information available to management at the time such estimates were made. Further analysis will be made upon filing the tax returns that will result in a change to the net deferred tax impact recorded. Due to the valuation allowance, the net result is expected to be zero.

F-62

A summary of deferred tax balances as of June 30, 2018 is presented in the table below (in thousands):

Deferred tax asset	$	213,029
Deferred tax liability		(82,805	)
Net deferred tax asset		130,224
Valuation allowance		(130,224	)
Net deferred tax asset	$	—

As a result of the Stone Combination, the Company acquired a current income tax receivable of $16.2 million primarily related to the carryback of specified liability losses.

Note 9—Earnings Per Share

Basic earnings per share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted earnings per share include the impact of restricted stock unit grants and outstanding warrants.

For the three and six months ended June 30, 2018, the Company incurred net losses and accordingly excluded all potentially dilutive securities from the determination of diluted earnings per share as their impact on loss per common share was antidilutive. As of June 30, 2018, the Company had approximately 3.5 million of outstanding warrants. These warrants have an exercise price of $42.04 per share and a term of four years.

Note 10—Related Party Transactions

Contributions and Distributions. During the six months ended June 30, 2018 and 2017, the Company did not receive any cash contributions or make any distributions to Apollo Global Management LLC and Riverstone Holdings, LLC (the “Sponsors”).

Transaction Fee Agreement.As part of the agreements with Sponsors, the Company paid a transaction fee equal to 2% of capital contributions made by each Sponsor. For the six months ended June 30, 2018 and 2017, the Sponsors did not make any capital contributions and thus the Company did not incur or pay transaction fees related to capital contributions. In connection with the Stone Combination on May 10, 2018, the Transaction Fee Agreement was terminated.

Service Fee Agreement. The Company entered into service fee agreements with each of its Sponsors for the provision of certain management consulting and advisory services. Under each agreement, the Company pays a fee equal to the higher of (i) a certain percentage of earnings before interest, income taxes, depletion, depreciation and amortization and (ii) a fixed fee payable quarterly, provided, however, such fees shall not exceed in each case $0.5 million, in aggregate, for any calendar year. For the six months ended June 30, 2018 and 2017, the Company incurred approximately $0.5 million and $0.3 million, respectively, for these services. For the three months ended June 30, 2018 and 2017, the Company incurred $0.4 million and $0.2 million, respectively, for these services. These fees are recognized in general and administrative expense on the condensed consolidated statements of operations. In connection with the Stone Combination on May 10, 2018, the Service Fee Agreement was terminated.

Debt Modification Work Fees.The Company paid $9.3 million in work fees to holders of the 11.00% Bridge Loans and 7.50% Stone Senior Notes to exchange into 11.00% Senior Secured Notes. The Sponsors received $4.1 million and the Franklin Noteholders and McKay Noteholders received $3.3 million, respectively, as a result of the work fees paid.

F-63

Note 11—Commitments and Contingencies

Capital Lease

As of June 30, 2018, the balance of the capital lease obligation on the condensed consolidated balance sheet was $99.7 million, of which $12.7 million is included in “other current liabilities” and $87.0 million is included in “other long-term liabilities”.

Performance Obligations

As of June 30, 2018, the Company had secured performance bonds primarily related to plugging and abandonment of wells, removal of facilities and to guarantee the completion of the minimum work program related to the Mexico Production Sharing Contracts (“PSCs”) totaling approximately $569.3 million. The Mexico PSCs govern the exploration and extraction of the hydrocarbons in Mexico with the CNH. As of June 30, 2018, the Company has not posted any collateral on the outstanding performance bonds.

Legal Proceedings

The Company is named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. The Company does not expect that these matters, individually or in the aggregate, will have a material adverse effect on its financial condition.

Other Commitments

On February 8, 2018, the Company amended a previous agreement to use the Ensco 75, a jackup drilling rig, to execute a portion of its 2018 drilling program. Under the terms of the amended agreement, the Company will pay Ensco a base vessel day work rate based on the number of days contracted for a minimum of 120 days during 2018, for approximately $7.8 million. On June 1, 2018, the Company exercised its option for an additional 90 days during 2018 for approximately $6.3 million. Total commitments for 2018 for the Ensco 75 are $14.1 million.

On June 18, 2018, the Company entered into an agreement for the Ensco 8503 drilling rig to execute a portion of its 2018 deepwater drilling program commencing November 1, 2018. Under the terms of the agreement, the Company will pay Ensco an operating day work rate based on the number of days contracted for a minimum of 100 days. Total commitments for 2018 and 2019 are $7.9 million and $5.1 million, respectively.

In connection with the Stone Combination, the Company entered into seismic use agreements totaling $46.8 million. As of June 30, 2018, the outstanding payments due are approximately $29.8 million consisting of $6.6 million, $10.9 million, $9.9 million and $2.4 million for the remainder of 2018, 2019, 2020 and 2021, respectively.

Note 12—Condensed Consolidating Financial Information

Talos owns no operating assets and has no operations independent of its subsidiaries and owns 100% of the Talos Issuers. The Talos Issuers issued 11.00% Senior Secured Notes on May 10, 2018, which are fully and unconditionally guaranteed, jointly and severally, by Talos and certain 100% owned subsidiaries (“Guarantors”) on a senior secured basis. Certain of the Company’s subsidiaries which are accounted for on a consolidated basis do not guarantee the 11.00% Senior Secured Notes (“Non-Guarantors”).

The following condensed consolidating financial information presents the financial information of the Company on an unconsolidated stand-alone basis and its combined subsidiary issuers, combined guarantor and combined non-guarantor subsidiaries as of and for the periods indicated. As described in Note 1 –Formation andBasis of Presentation, the Company retrospectively adjusted its consolidated equity to reflect the legal capital of Talos for all periods presented. Such financial information may not necessarily be indicative of the Company’s results of operations, cash flows, or financial position had these subsidiaries operated as independent entities.

F-64

TALOS ENERGY INC.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF JUNE 30, 2018

(In thousands)

(Unaudited)

	Talos		Talos Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	35,385		$	40,940		$	2,535		$	—		$	78,860
Restricted cash		—		—			1,244			—			—			1,244
Accounts receivable, net
Trade, net		—		—			100,824			—			—			100,824
Joint interest, net		—		—			6,638			1,756			—			8,394
Other		—		—			832			6,259			—			7,091
Assets from price risk management activities		—		478			21			—			—			499
Prepaid assets		—		—			51,672			26			—			51,698
Income tax receivable		—		—			16,212			—			—			16,212
Other current assets		—		—			3,910			—			—			3,910
Total current assets		—		35,863			222,293			10,576			—			268,732
Property and equipment:
Proved properties		—		—			3,412,875			—			—			3,412,875
Unproved properties, not subject to amortization		—		—			70,590			33,246			—			103,836
Other property and equipment		—		27,293			1,580			11			—			28,884
Total property and equipment		—		27,293			3,485,045			33,257			—			3,545,595
Accumulated depreciation, depletion and amortization		—		(7,080	)		(1,540,566	)		(10	)		—			(1,547,656	)
Total property and equipment, net		—		20,213			1,944,479			33,247			—			1,997,939
Other long-term assets:
Assets from price risk management activities		—		234			—			—			—			234
Other well equipment inventory		—		—			9,021			—			—			9,021
Investments in subsidiaries		685,845		1,440,601			—			—			(2,126,446	)		—
Other assets		—		364			7,712			67			—			8,143
Total assets	$	685,845	$	1,497,275		$	2,183,505		$	43,890		$	(2,126,446	)	$	2,284,069
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	—	$	9,894		$	28,728		$	109		$	—		$	38,731
Accrued liabilities		—		4,235			150,206			1,461			—			155,902
Accrued royalties		—		—			28,508			—			—			28,508
Current portion of long-term debt		—		434			—			—			—			434
Current portion of asset retirement obligations		—		—			94,334			—			—			94,334
Liabilities from price risk management activities		—		141,118			13,604			—			—			154,722
Accrued interest payable		—		7,064			390			—			—			7,454
Other current liabilities		—		—			15,541			—			—			15,541
Total current liabilities		—		162,745			331,311			1,570			—			495,626
Long-term debt, net of discount and deferred financing costs		—		621,908			6,060			—			—			627,968
Asset retirement obligations		—		—			320,044			—			—			320,044
Liabilities from price risk management activities		—		26,777			4,989			—			—			31,766
Other long-term liabilities		—		—			122,820			—			—			122,820
Total liabilities		—		811,430			785,224			1,570			—			1,598,224
Commitments and Contingencies (Note 10)
Stockholders’ equity (deficit)		685,845		685,845			1,398,281			42,320			(2,126,446	)		685,845
	$	685,845	$	1,497,275		$	2,183,505		$	43,890		$	(2,126,446	)	$	2,284,069

F-65

TALOS ENERGY INC.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2017

(In thousands)

	Talos			Talos Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	22,315		$	7,806		$	2,070		$	—		$	32,191
Restricted cash		—			—			1,242			—			—			1,242
Accounts receivable, net
Trade, net		—			—			62,871			—			—			62,871
Joint interest, net		—			—			11,659			1,954			—			13,613
Other		—			938			5,863			5,685			—			12,486
Assets from price risk management activities		—			1,406			157			—			—			1,563
Prepaid assets		—			—			17,919			12			—			17,931
Inventory		—			—			840			—			—			840
Other current assets		—			—			2,148			—			—			2,148
Total current assets		—			24,659			110,505			9,721			—			144,885
Property and equipment:
Proved properties		—			—			2,440,811			—			—			2,440,811
Unproved properties, not subject to amortization		—			—			41,259			30,743			—			72,002
Other property and equipment		—			7,266			1,580			11			—			8,857
Total property and equipment		—			7,266			2,483,650			30,754			—			2,521,670
Accumulated depreciation, depletion and amortization		—			(6,355	)		(1,424,527	)		(8	)		—			(1,430,890	)
Total property and equipment, net		—			911			1,059,123			30,746			—			1,090,780
Other long-term assets:
Assets from price risk management activities		—			345			—			—			—			345
Other well equipment inventory		—			—			2,577			—			—			2,577
Investments in subsidiaries		(54,087	)		697,663			—			—			(643,576	)		—
Other assets		—			364			326			16			—			706
Total assets	$	(54,087	)	$	723,942		$	1,172,531		$	40,483		$	(643,576	)	$	1,239,293
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	—		$	1,124		$	70,458		$	1,099		$	—		$	72,681
Accrued liabilities		—			6,516			80,464			993			—			87,973
Accrued royalties		—			—			24,208			—			—			24,208
Current portion of long-term debt		—			24,977			—			—			—			24,977
Current portion of asset retirement obligations		—			—			39,741			—			—			39,741
Liabilities from price risk management activities		—			46,580			3,377			—			—			49,957
Accrued interest payable		—			8,742			—			—			—			8,742
Other current liabilities		—			—			15,188			—			—			15,188
Total current liabilities		—			87,939			233,436			2,092			—			323,467
Long-term debt, net of discount and deferred financing costs		—			672,581			—			—			—			672,581
Asset retirement obligations		—			—			174,992			—			—			174,992
Liabilities from price risk management activities		—			17,509			1,272			—			—			18,781
Other long-term liabilities		—			—			103,559			—			—			103,559
Total liabilities		—			778,029			513,259			2,092			—			1,293,380
Commitments and Contingencies (Note 10)
Stockholders’ equity (deficit)		(54,087	)		(54,087	)		659,272			38,391			(643,576	)		(54,087	)
	$	(54,087	)	$	723,942		$	1,172,531		$	40,483		$	(643,576	)	$	1,239,293

F-66

TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE THREE MONTHS ENDED JUNE 30, 2018

(In thousands)

(Unaudited)

	Talos			Talos Issuers			Guarantors			Non- Guarantors			Elimination		Consolidated
Revenues:
Oil revenue	$	—		$	—		$	180,161		$	—		$	—	$	180,161
Natural gas revenue		—			—			16,448			—			—		16,448
NGL revenue		—			—			7,297			—			—		7,297
Total revenue		—			—			203,906			—			—		203,906
Operating expenses:
Direct lease operating expense		—			—			34,060			—			—		34,060
Insurance		—			—			4,259			—			—		4,259
Production taxes		—			—			564			—			—		564
Total lease operating expense		—			—			38,883			—			—		38,883
Workover and maintenance expense		—			—			17,714			—			—		17,714
Depreciation, depletion and amortization		—			384			67,341			1			—		67,726
Accretion expense		—			—			9,492			—			—		9,492
General and administrative expense		—			13,804			16,854			222			—		30,880
Total operating expenses		—			14,188			150,284			223			—		164,695
Operating income (loss)		—			(14,188	)		53,622			(223	)		—		39,211
Interest expense		—			(14,399	)		(6,891	)		(388	)		—		(21,678	)
Price risk management activities expense		—			(89,970	)		(1,206	)		—			—		(91,176	)
Other income (expense)		—			(1,358	)		132			(43	)		—		(1,269	)
Equity earnings from subsidiaries		(74,912	)		45,003			—			—			29,909		—
Net income (loss)	$	(74,912	)	$	(74,912	)	$	45,657		$	(654	)	$	29,909	$	(74,912	)

F-67

TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE SIX MONTHS ENDED JUNE 30, 2018

(In thousands)

(Unaudited)

	Talos			Talos Issuers			Guarantors			Non- Guarantors			Elimination		Consolidated
Revenues:
Oil revenue	$	—		$	—		$	307,854		$	—		$	—	$	307,854
Natural gas revenue		—			—			29,171			—			—		29,171
NGL revenue		—			—			12,731			—			—		12,731
Total revenue		—			—			349,756			—			—		349,756
Operating expenses:
Direct lease operating expense		—			—			58,975			—			—		58,975
Insurance		—			—			6,934			—			—		6,934
Production taxes		—			—			955			—			—		955
Total lease operating expense		—			—			66,864			—			—		66,864
Workover and maintenance expense		—			—			24,619			—			—		24,619
Depreciation, depletion and amortization		—			725			116,039			2			—		116,766
Accretion expense		—			—			14,252			—			—		14,252
General and administrative expense		—			18,398			20,567			495			—		39,460
Total operating expenses		—			19,123			242,341			497			—		261,961
Operating income (loss)		—			(19,123	)		107,415			(497	)		—		87,795
Interest expense		—			(26,627	)		(13,957	)		(836	)		—		(41,420	)
Price risk management activities expense		—			(139,217	)		(3,935	)		—			—		(143,152	)
Other income (expense)		—			(1,208	)		85			45			—		(1,078	)
Equity earnings from subsidiaries		(97,855	)		88,320			—			—			9,535		—
Net income (loss)	$	(97,855	)	$	(97,855	)	$	89,608		$	(1,288	)	$	9,535	$	(97,855	)

F-68

TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE THREE MONTHS ENDED JUNE 30, 2017

(In thousands)

(Unaudited)

	Talos		Talos Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Revenues:
Oil revenue	$	—	$	—		$	78,719		$	—		$	—		$	78,719
Natural gas revenue		—		—			12,888			—			—			12,888
NGL revenue		—		—			3,436			—			—			3,436
Other		—		—			383			—			—			383
Total revenue		—		—			95,426			—			—			95,426
Operating expenses:
Direct lease operating expense		—		—			28,871			—			—			28,871
Insurance		—		—			2,688			—			—			2,688
Production taxes		—		—			380			—			—			380
Total lease operating expense		—		—			31,939			—			—			31,939
Workover and maintenance expense		—		—			8,225			—			—			8,225
Depreciation, depletion and amortization		—		353			35,803			1			—			36,157
Accretion expense		—		—			5,321			—			—			5,321
General and administrative expense		—		3,775			3,531			164			—			7,470
Total operating expenses		—		4,128			84,819			165			—			89,112
Operating income (loss)		—		(4,128	)		10,607			(165	)		—			6,314
Interest expense		—		(11,487	)		(7,695	)		(1,623	)		—			(20,805	)
Price risk management activities income		—		36,040			2,955			—			—			38,995
Other income (expense)		—		150			(87	)		40			—			103
Equity earnings from subsidiaries		24,607		4,032			—			—			(28,639	)		—
Net income (loss)	$	24,607	$	24,607		$	5,780		$	(1,748	)	$	(28,639	)	$	24,607

F-69

TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE SIX MONTHS ENDED JUNE 30, 2017

(In thousands)

(Unaudited)

	Talos		Talos Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Revenues:
Oil revenue	$	—	$	—		$	162,487		$	—		$	—		$	162,487
Natural gas revenue		—		—			26,062			—			—			26,062
NGL revenue		—		—			7,069			—			—			7,069
Other		—		—			1,632			—			—			1,632
Total revenue		—		—			197,250			—			—			197,250
Operating expenses:
Direct lease operating expense		—		—			56,735			—			—			56,735
Insurance		—		—			5,409			—			—			5,409
Production taxes		—		—			645			—			—			645
Total lease operating expense		—		—			62,789			—			—			62,789
Workover and maintenance expense		—		—			17,047			—			—			17,047
Depreciation, depletion and amortization		—		722			75,364			2			—			76,088
Accretion expense		—		—			10,509			—			—			10,509
General and administrative expense		—		10,166			6,621			429			—			17,216
Total operating expenses		—		10,888			172,330			431			—			183,649
Operating income (loss)		—		(10,888	)		24,920			(431	)		—			13,601
Interest expense		—		(23,501	)		(14,723	)		(1,353	)		—			(39,577	)
Price risk management activities expense		—		81,541			3,347			—			—			84,888
Other income (expense)		—		300			(162	)		19			—			157
Equity earnings from subsidiaries		59,069		11,617			—			—			(70,686	)		—
Net income (loss)	$	59,069	$	59,069		$	13,382		$	(1,765	)	$	(70,686	)	$	59,069

F-70

TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE SIX MONTHS ENDED JUNE 30, 2018

(In thousands)

(Unaudited)

	Talos		Talos Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	—	$	(54,941	)	$	160,304		$	1,748		$	—		$	107,111
Cash flows from investing activities:
Exploration, development, and other capital expenditures		—		(20,027	)		(117,667	)		(3,274	)		—			(140,968	)
Cash paid for acquisitions, net of cash acquired		—		—			293,001			—			—			293,001
Investments in subsidiaries		—		(384,089	)		—			—			384,089			—
Distributions from subsidiaries		—		677,573			9			—			(677,582	)		—
Net cash provided by (used in) investing activities		—		273,457			175,343			(3,274	)		(293,493	)		152,033
Cash flows from financing activities:
Redemption of 2018 Senior Notes		—		(24,977	)		(69	)		—			—			(25,046	)
Proceeds from Bank Credit Facility		—		294,000			—			—			—			294,000
Repayment of Bank Credit Facility		—		(54,000	)		—			—			—			(54,000	)
Repayment of Old Bank Credit Facility		—		(403,000	)		—						—			(403,000	)
Deferred financing costs		—		(17,469	)		—			—			—			(17,469	)
Payments of capital lease		—		—			(6,958	)		—			—			(6,958	)
Capital contributions		—		—			382,089			2,000			(384,089	)		—
Distributions to subsidiary issuer		—		—			(677,573	)		(9	)		677,582			—
Net cash provided by (used in) financing activities		—		(205,446	)		(302,511	)		1,991			293,493			(212,473	)
Net increase (decrease) in cash, cash equivalents and restricted cash		—		13,070			33,136			465			—			46,671
Cash, cash equivalents and restricted cash:
Balance, beginning of period		—		22,315			9,048			2,070			—			33,433
Balance, end of period	$	—	$	35,385		$	42,184		$	2,535		$	—		$	80,104

F-71

TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE SIX MONTHS ENDED JUNE 30, 2017

(In thousands)

(Unaudited)

	Talos		Talos Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	—	$	(16,268	)	$	84,651		$	16,880		$	—		$	85,263
Cash flows from investing activities:
Exploration, development, and other capital expenditures		—		(73	)		(54,770	)		(7,692	)		—			(62,535	)
Cash paid for acquisitions, net of cash acquired		—		—			(2,244	)		—			—			(2,244	)
Investments in subsidiaries		—		(287,689	)		—			—			287,689			—
Distributions from subsidiaries		—		292,580			1,527			—			(294,107	)		—
Net cash provided by (used in) investing activities		—		4,818			(55,487	)		(7,692	)		(6,418	)		(64,779	)
Cash flows from financing activities:
Redemption of 2018 Senior Notes		—		(1,000	)		—			—			—			(1,000	)
Proceeds from Bank Credit Facility		—		10,000			—			—			—			10,000
Repayment of Bank Credit Facility		—		(15,000	)		—			—			—			(15,000	)
Payments of capital lease		—		—			(5,870	)		—			—			(5,870	)
Capital contributions		—		—			279,689			8,000			(287,689	)		—
Distributions to subsidiaries		—		—			(292,580	)		(1,527	)		294,107			—
Net cash provided by (used in) financing activities		—		(6,000	)		(18,761	)		6,473			6,418			(11,870	)
Net increase (decrease) in cash, cash equivalents and restricted cash		—		(17,450	)		10,403			15,661			—			8,614
Cash, cash equivalents and restricted cash:
Balance, beginning of period		—		24,349			6,752			2,332			—			33,433
Balance, end of period	$	—	$	6,899		$	17,155		$	17,993		$	—		$	42,047

F-72

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

The following unaudited pro forma condensed combined statement of operations of Talos Energy Inc. presents the combination of the historical financial information of Talos Energy and Stone Energy adjusted to give effect to the Transactions. In addition, the Stone Energy historical financial information was adjusted to give effect to an asset disposition and their emergence from bankruptcy. The unaudited pro forma condensed combined statement of operations for the fiscal year ended December 31, 2017 combines the historical consolidated statements of operations of Talos Energy and Stone Energy, giving effect to the Transactions, asset disposition and emergence from bankruptcy as if they had been consummated on January 1, 2017. Defined terms used in this unaudited pro forma condensed combined statement of operations have the meanings given to them elsewhere in this prospectus.

The Transaction Agreement contemplates that a series of transactions will occur on the Closing Date, including (i) the merger of an indirect, wholly owned subsidiary of Stone Energy with and into Stone Energy, with Stone Energy surviving the merger as a direct wholly owned subsidiary of Talos Energy Inc., (ii) the contribution of 100% of the equity interests in Talos Production LLC to Talos Energy Inc. in exchange for shares of Talos Energy Inc. common stock, (iii) the contribution of $102 million in aggregate principal amount of the 9.75% Senior Notes due 2022 issued by the Talos Issuers (the “2022 Senior Notes”) to Talos Energy Inc. by the Apollo Funds and the Riverstone Funds in exchange for shares of Talos Energy Inc. common stock, (iv) the exchange of the Bridge Loans for newly issued 11% second lien notes issued by the Talos Issuers, and (v) the exchange of the Stone Notes for newly issued 11% second lien notes issued by the Talos Issuers. Each stockholder of Stone Energy will receive one share of Talos Energy Inc. common stock for each share of Stone Energy common stock. After the completion of the Transactions, holders of Stone Energy common stock immediately prior to the Merger will hold 37% of the outstanding Talos Energy Inc. common stock and Talos Energy stakeholders will hold 63% of the outstanding Talos Energy Inc. common stock.

The accompanying unaudited pro forma condensed combined statement of operations was derived by making certain adjustments to the historical financial statements listed above. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the Transactions, asset disposition and emergence from bankruptcy, and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma condensed combined statement of operations.

The unaudited pro forma condensed combined statement of operations and related notes are presented for illustrative purposes only and should not be relied upon as an indication of operating results that Talos Energy Inc. would have achieved if the Transactions, asset disposition and emergence from bankruptcy had taken place on the specified date. In addition, future results may vary significantly from the results reflected in the unaudited pro forma condensed combined statement of operations and should not be relied on as an indication of the future results of Talos Energy Inc.

F-73

Talos Energy Inc.

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Year Ended December 31, 2017

(In thousands, except per share amounts)

				Stone Energy Historical
	Talos Energy Historical			Successor March 1, 2017 through December 31, 2017			Predecessor January 1, 2017 through February 28, 2017			Stone Energy Pro Forma Adjustments			Stone Energy Business Combination			Exchange Agreement			Pro Forma Combined
										Note 2			Note 2			Note 2
Revenues:
Oil revenue	$	344,781		$	211,792		$	45,837		$	(2,239	)(a)	$	—		$	—		$	600,171
Natural gas revenue		48,886			18,874			13,476			(9,580	)(a)		—			—			71,656
NGL revenue		16,658			9,610			8,706			(6,768	)(a)		—			—			28,206
Other		2,503			10,008			903			(799	)(a)		—			—			12,615
Total revenue		412,828			250,284			68,922			(19,386	)		—			—			712,648
Operating expenses:
Direct lease operating expense		109,180			29,691			13,166			(8,773	)(a)		—			—			143,264
Insurance		10,743			5,284			963			(145	)(a)		—			—			16,845
Production taxes and other		1,460			629			682			(546	)(a)		—			—			2,225
Total lease operating expense		121,383			35,604			14,811			(9,464	)		—			—			162,334
Workover / maintenance expense		32,825			18,909			1,624			(143	)(a)		—			—			53,215
Depreciation, depletion and amortization		157,352			99,890			37,429			(15,751	)(a)		46,319	(c)		—			325,239
Write-down of oil and gas properties		—			256,435			—						(256,435	)(d)		—			—
Accretion expense		19,295			21,151			5,447			(263	)(a)		814	(e)		—			46,444
General and administrative expense		36,673			55,862			11,637			—			(10,963	)(f)		—			93,209
Restructuring fees		—			739			—			—			—			—			739
Other operational expenses		—			3,359			530			—			—			—			3,889
Total operating expenses		367,528			491,949			71,478			(25,621	)		(220,265	)		—			685,069
Gain (loss) on Appalachia Properties divestiture		—			(105	)		213,453			(213,348	)(a)		—			—			—
Operating income (loss)		45,300			(241,770	)		210,897			(207,113	)		220,265			—			27,579
Interest expense		(80,934	)		(11,744	)		—			—			—			(6,999	)(h)		(99,677	)
Price risk management activities income (expense)		(27,563	)		(13,388	)		(1,778	)		—			—			—			(42,729	)
Other income (expense)		329			924			(12,976	)		10,800	(b)		—			—			(923	)
Reorganization items, net		—			—			437,744			(437,744	)(b)		—			—			—
Income (loss) before income taxes		(62,868	)		(265,978	)		633,887			(634,057	)		220,265			(6,999	)		(115,750	)
Provision (benefit) for income taxes:
Current		—			(18,339	)		3,570			—			—	(g)		—			(14,769	)
Deferred		—			—			—			—			—	(g)		—			—
Total income taxes		—			(18,339	)		3,570			—			—			—			(14,769	)
Net income (loss)	$	(62,868	)	$	(247,639	)	$	630,317		$	(634,057	)	$	220,265		$	(6,999	)	$	(100,981	)
Basic income (loss) per share				$	(12.38	)	$	110.99											$	(1.86	)
Diluted income (loss) per share				$	(12.38	)	$	110.99											$	(1.86	)
Average shares outstanding					19,997			5,634												54,157	(i)
Average shares outstanding assuming dilution					19,997			5,634												54,157	(i)

F-74

NOTES TO THE UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

Note 1—Basis of Presentation

Overview

The unaudited pro forma condensed combined statement of operations of Talos Energy Inc. presents the combination of the historical financial information of Talos Energy LLC and Stone Energy adjusted to give effect to the Transactions. Additionally, the Stone Energy historical financial information was adjusted to give effect to an asset disposition and their emergence from bankruptcy. The unaudited pro forma condensed combined statement of operations for the fiscal year ended December 31, 2017 combines the historical consolidated statements of operations of Talos Energy and Stone Energy, giving effect to the Transactions, asset disposition and emergence from bankruptcy as if they had been consummated on January 1, 2017. The Transactions and other adjustments are described in Note 2—Pro Forma Adjustments and Assumptions to these unaudited pro forma condensed combined financial statements.

The unaudited pro forma condensed combined statement of operations should be read in conjunction with (i) Stone Energy’s historical consolidated financial statements and related notes for the year ended December 31, 2017 included elsewhere in this prospectus and (ii) Talos Energy’s historical consolidated financial statements and related notes for the year ended December 31, 2017, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this prospectus.

Certain reclassifications have been made to the Stone Energy historical financial statements to reflect the comparability of financial information. However, the pro forma condensed combined statement of operations may not reflect all adjustments necessary to conform the accounting policies of Stone Energy to those of Talos Energy due to the limitations on the availability of information as of the date of this prospectus.

The pro forma adjustments represent management’s estimates based on information available as of the date of this prospectus and are subject to change as additional information becomes available and additional analyses are performed. The pro forma financial statements do not reflect the impact of possible revenue or earnings enhancements, cost savings from operating efficiencies or synergies, or asset dispositions. Also, the pro forma financial statements do not reflect possible adjustments related to restructuring or integration activities that have yet to be determined or transaction or other costs following the Transactions that are not expected to have a continuing impact. Further, one-time transaction-related expenses anticipated to be incurred prior to, or concurrent with, Closing the Transactions are not included in the pro forma statements of operations. However, the impact of such transaction expenses is reflected in the pro forma balance sheet as an increase to accumulated deficit and an increase to accounts payable.

Preliminary Estimated Purchase Price

The unaudited pro forma condensed combined statement of operations was prepared using the acquisition method of accounting with Talos Energy as the accounting acquirer of Stone Energy. Under the acquisition method of accounting, the purchase price is allocated to the identifiable tangible and intangible assets acquired and liabilities assumed based on their respective fair values, with any excess purchase price allocated to goodwill. Talos Energy has not completed the detailed valuation studies necessary to compute the fair value estimates of Stone Energy’s assets acquired and liabilities assumed and the related allocations of purchase price, nor has it identified all adjustments necessary to conform Stone Energy’s accounting policies to Talos Energy’s accounting policies. Talos Energy Inc. expects to complete the purchase price allocation after considering the appraisal of Stone Energy’s assets at the level of detail necessary to finalize the required purchase price allocation, which will be no later than one year from Closing. The purchase price utilized in the allocation will be based on the closing price of Stone Energy common stock and common stock warrants immediately prior to Closing. The pro forma adjustments included herein may be revised as additional information becomes available

F-75

and as additional analyses are performed. The final purchase price allocation may be different than that reflected in the preliminary pro forma purchase price allocation presented herein, and this difference may be material. The pro forma purchase price allocation is preliminary and was based on an estimate of the fair values of the tangible and intangible assets and liabilities related to Stone Energy and the closing price of Stone Energy common stock of $32.16 and common stock warrants of $5.00 on December 29, 2017.

The following table summarizes the preliminary estimate of the purchase price (in thousands, except per share data):

Stone Energy common stock—issued and outstanding as of December 31, 2017(1):		19,998
Stone Energy common stock price(1)	$	32.16
Common stock value	$	643,136
Stone Energy common stock warrants		3,529
Stone Energy common stock warrant price(1)	$	5.00
Common stock warrants value	$	17,645
Total consideration and fair value	$	660,781

(1) The final purchase price will be based on the fair value of the issued and outstanding shares of Stone Energy common stock and Stone Energy common stock warrants as of the Closing Date. The estimated fair value of Stone Energy common stock and common stock warrants is based on their respective closing prices as of December 29, 2017, which will be adjusted as of the final Closing Date. A 10% increase or decrease in the trading price of the Stone Energy common stock and common stock warrants would increase or decrease the total purchase price by approximately $66.1 million, respectively. The potential change in the purchase price will likely affect the value allocated to property and equipment as the value of the underlying estimated oil and natural gas reserve volumes is dependent upon commodity prices on the Closing Date.

Preliminary Estimated Purchase Price Allocation

The following table summarizes the allocation of the preliminary estimate of the purchase price to the assets acquired and liabilities assumed (in thousands):

Stone Energy fair values:
Current assets	$	365,772
Property and equipment		795,349
Other long-term assets		50,324
Current liabilities		(172,326	)
Long-term debt		(235,561	)
Other long-term liabilities		(142,777	)
Allocated purchase price	$	660,781

Note 2—Pro Forma Adjustments and Assumptions

The following adjustments and assumptions were made in the preparation of the unaudited pro forma condensed combined statements of operations:

(a) Reflects the pro forma impact of Stone Energy’s sale of approximately 86,000 net acres in the Appalachian regions of Pennsylvania and West Virginia (collectively, the “ Appalachia Properties”), on February 27, 2017, to EQT Corporation, through its wholly owned subsidiary EQT Production Company. The divestiture adjustments eliminate the revenue, total lease operating expense, workover / maintenance expense and depletion of oil and gas properties directly attributable to the Appalachia Properties as if the sale occurred on January 1, 2017. The pro forma adjustment also eliminates

F-76

accretion expense attributable to asset retirement obligations for the Appalachia Properties as well as the gain on the disposition.

(b) Reflects the elimination of reorganization items for liabilities settled, net of amounts incurred, subsequent to the Stone Energy Chapter 11 of Title 11 bankruptcy filing, as a direct result of Stone Energy’s Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates, dated December 28, 2016 (the “Plan”). The Plan became effective on February 28, 2017, on which date Stone Energy emerged from bankruptcy.

(c) Reflects changes in depletion that would have been recorded with respect to the allocated fair values attributable to proved oil and natural gas properties acquired as a result of the application of the full cost method of accounting for oil and natural gas activities following the Transactions. The pro forma depletion rates for the year ended December 31, 2017 were estimated using the proved property amounts based on the preliminary purchase price allocation and estimates of reserves at December 31, 2017, adjusted for actual production. The pro forma depletion rates were applied to production volumes for the Talos Energy and Stone Energy properties for the respective periods.

(d) Reflects the elimination of the ceiling test write-down of oil and natural gas properties recognized by Stone Energy as a result of a pro forma ceiling test calculation. The pro forma ceiling test calculation was performed using the pro forma combined present value of future net revenues from proved reserves discounted at 10%, plus the estimated fair value of combined unproved oil and natural gas properties based on the preliminary purchase price allocation. For the year ended December 31, 2017, there would have been no ceiling test write-down on oil and natural gas properties recognized when considering the combined proved oil and natural gas properties.

(e) Reflects the pro forma adjustment to accretion expense on the combined asset retirement obligation calculated using Talos Energy’s credit-adjusted risk-free interest rates.

(f) Reflects the elimination of direct, incremental costs of the Transactions, which are already reflected in the historical financial statements of Talos Energy and Stone Energy during the year ended December 31, 2017.

(g) Reflects a net impact of zero related to the acquired deferred taxes associated with the business combination on the pro forma adjustments described herein, based on a blended federal and state statutory income tax rate of 21%. Based upon all available evidence, it is more likely than not that the deferred tax assets will not be realized. As such, a valuation allowance is recorded to reduce the combined deferred tax asset balance to zero. The change in tax status is reflected in the pro forma condensed combined statement of operations and balance sheet. The overall impact is zero. Adjustments to the valuation allowance were recorded to offset the net changes of the deferred tax asset of the combined deferred taxes of Talos Energy and Stone Energy.

(h) Reflects an increase in interest expense associated with (i) the increase in coupon for the exchanged 2022 Secured Notes and (ii) the interest expense capitalized by Stone Energy based on review of the Stone Energy and Talos Energy accounting policies, partially offset by (iii) the Sponsor Debt Exchange whereby the Apollo Funds and the Riverstone Funds will contribute $102 million in aggregate principal amount of their 2022 Senior Notes to New Talos for shares of New Talos common stock and (iv) the $103 million reduction in the outstanding borrowings on the pro forma revolving line of credit after giving effect to the consummation of the Transactions (see (j) below). The following table separately quantifies each adjustment made to interest expense presented in the pro forma financial statements (in thousands):

Change in Stone Notes coupon rate(i)	$	13,398
Stone Energy capitalized interest(ii)		6,451
Equitize 2022 Senior Notes(iii)		(11,220	)
Revolving line of credit(iv)		(1,630	)
Interest expense pro forma adjustment	$	6,999

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Interest on borrowings under the pro forma revolving line of credit is based on a current rate of 4.82%. These borrowings bear interest at variable rates and are subject to interest rate risk. A 1/8% change to the interest rate would result in a change in interest expense related to variable rate financing of $0.5 million for the year ended December 31, 2017.

(i) The weighted average basic and diluted shares of common stock outstanding was calculated assuming that shares of Stone Energy common stock outstanding as of December 31, 2017 (19,998,019 shares) and the vesting of Stone Energy restricted stock units (39,828 shares, net of shares withheld for taxes) will constitute the number of shares of New Talos that will equal the Stone Energy stockholders’ expected ownership of 37% in New Talos. The table below illustrates the share for share exchange of shares of Stone Energy common stock for shares of New Talos common stock and the issuance of shares of New Talos common stock to Talos Energy stakeholders (in thousands).

	Talos Energy Inc. Shares at Closing		Percent Ownership
Stone Energy stockholders		19,998
Stone Energy unvested shares		40
Total Stone Energy shares exchanged		20,038		37	%
Talos Energy stakeholders		34,119		63	%
Total Talos Energy Inc. shares issued		54,157

Note 3—Pro Forma Supplemental Oil and Natural Gas Reserve Information

The following schedules reflect Talos Energy and Stone Energy’s combined supplemental information regarding oil and natural gas producing activities, giving effect to the Transactions as if the closing of the Transactions had occurred on January 1, 2017. The following estimates of proved oil and natural gas reserves, both developed and undeveloped, represent combined estimated quantities of crude oil and natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and natural gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively minor expenditures are required for completion.

As described in tickmark (a) of Note 2—Pro Forma Adjustments and Assumptions, proved reserves related to the divestiture of Stone Energy’s Appalachia Properties have been excluded from the following schedules.

There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production, the amount and timing of development expenditures and underlying future cash flows, including many factors beyond the property owner’s control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree subjective, the quantities of oil, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil, natural gas and NGLs sales prices may each differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. The standardized measure shown below represents estimates only and should not be construed as the current market value of the estimated oil, natural gas and NGL reserves.

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Pro Forma Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves

The following table presents pro forma estimated proved reserves at the net ownership interest:

	Talos Energy Historical												Stone Energy Historical
	Oil (MBbls)			Gas (MMcf)			NGL (MBbls)			MBoe			Oil (MBbls)			Gas (MMcf)			NGL (MBbls)			MBoe
Total proved reserves at December 31, 2016		72,366			150,604			6,236			103,702			22,384			61,088			2,822			35,388
Revision of previous estimate		(2,673	)		(15,860	)		250			(5,067	)		4,512			(1,790	)		(36	)		4,176
Production		(7,048	)		(16,308	)		(706	)		(10,472	)		(5,020	)		(9,182	)		(481	)		(7,031	)
Extensions and discoveries		10,159			9,220			767			12,462			—			—			—			—
Total proved reserves at December 31, 2017		72,804			127,656			6,547			100,625			21,876			50,116			2,305			32,533
Total proved developed reserves at December 31, 2017		37,460			77,577			3,315			53,704			20,275			37,946			1,689			28,288

	Pro Forma Combined
	Oil (MBbls)			Gas (MMcf)			NGL (MBbls)			MBoe
Total proved reserves at December 31, 2016		94,750			211,692			9,058			139,090
Revision of previous estimate		1,839			(17,650	)		214			(891	)
Production		(12,068	)		(25,490	)		(1,187	)		(17,503	)
Extensions and discoveries		10,159			9,220			767			12,462
Total proved reserves at December 31, 2017		94,680			177,772			8,852			133,158
Total proved developed reserves at December 31, 2017		57,735			115,523			5,004			81,992

New Talos reserves at December 31, 2017 decreased by 5.9 MMBoe to 133.2 MMBoe from 139.1 MMBoe, a 4% decrease. The change was primarily due to:

Revisions of Previous Estimates. Talos Energy’s estimated proved reserves were reduced by 5.1 MMBoe due to negative performance revisions offset by 4.2 MMBoe positive well performance revisions for Stone Energy’s estimated proved reserves in the Gulf of Mexico.

Extensions and Discoveries. Talos Energy added 12.5 MMBoe of estimated proved reserves from extensions and discoveries primarily from the successful drilling of the Tornado exploration well in the Phoenix Field located in Green Canyon 281.

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The following table reflects the pro forma standardized measure of discounted future net cash flows at the net ownership interest in proved oil, natural gas and NGL reserves (in thousands):

	December 31, 2017
	Talos Energy Historical			Stone Energy Historical			Pro Forma Combined
Future cash inflows	$	4,308,863		$	1,264,809		$	5,573,672
Future costs:
Production		(815,509	)		(497,538	)		(1,313,047	)
Development and abandonment		(823,164	)		(431,752	)		(1,254,916	)
Future net cash flows before income taxes		2,670,190			335,519			3,005,709
Future income tax expense		—			—			—
Future net cash flows		2,670,190			335,519			3,005,709
Discount at 10% annual rate		(862,521	)		57,591			(804,930	)
Standardized measure of discounted future net cash flows	$	1,807,669		$	393,110		$	2,200,779

Future cash inflows are computed by applying the appropriate average 12 month commodity prices as based on the price of oil, natural gas and NGLs on the first day of each month during the year, adjusted for location and quality differentials on a property-by-property basis, to year-end quantities of proved reserves. See the following table for base prices used in determining the standardized measure:

	Year Ended December 31, 2017
	Talos Energy Historical		Stone Energy Historical
Oil price per Bbl	$	51.36	$	50.05
Natural gas price per Mcf	$	3.20	$	2.34
NGL price per Bbl	$	24.64	$	22.90

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Pro Forma Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the pro forma standardized measure of discounted future net cash flows attributable to the proved oil, natural gas, and NGL reserves are as follows (in thousands):

	Year Ended December 31, 2017
	Talos Energy Historical			Stone Energy Historical			Pro Forma Combined
Standardized measure, beginning of year	$	1,336,035		$	231,525		$	1,567,560
Changes during the year:
Sales, net of production		(288,942	)		(201,768	)		(490,710	)
Net change in prices and production costs		555,100			83,647			638,747
Changes in future development costs		(156,282	)		108,867			(47,415	)
Development costs incurred		146,687			—			146,687
Accretion of discount		133,603			52,901			186,504
Extensions and discoveries		328,565			—			328,565
Net change due to revision of quantity estimates		(113,629	)		133,011			19,382
Changes in production rates (timing) and other		(133,468	)		(15,073	)		(148,541	)
Total		471,634			161,585			633,219
Standardized measure, end of year	$	1,807,669		$	393,110		$	2,200,779

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UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

The following unaudited pro forma condensed combined statement of operations of Talos Energy Inc. (“Talos Energy”) presents the combination of the historical financial information of Talos Energy, Talos Energy LLC and Stone Energy Corporation (“Stone Energy”) adjusted to give effect to the transactions described below (collectively, the “transactions” or the “business combination”) that were consummated in connection with the closing of the transactions contemplated by that certain Transaction Agreement, dated as of November 21, 2017 (the “Transaction Agreement”), among Talos Energy, Stone Energy, Sailfish Merger Sub Corporation, Talos Energy LLC and Talos Production LLC (“Talos Production”). The unaudited pro forma condensed combined statement of operations for the six months ended June 30, 2018 combines the historical consolidated statement of operations of Talos Energy for the six months ended June 30, 2018, which reflects the historical financial results of Talos Energy LLC from January 1, 2018 to May 9, 2018 and of Talos Energy from May 10, 2018 to June 30, 2018, and Stone Energy for the period from January 1, 2018 to May 9, 2018, giving effect to the transactions as if they had been consummated on January 1, 2018.

On May 10, 2018 (the “Closing Date”), a series of transactions contemplated by the Transaction Agreement were consummated (the “Closing”), including (i) the merger of an indirect, wholly owned subsidiary of Stone Energy with and into Stone Energy, with Stone Energy surviving the merger as a direct wholly owned subsidiary of Talos Energy, (ii) the contribution of 100% of the equity interests in Talos Production to Talos Energy in exchange for shares of Talos Energy common stock, (iii) the contribution of $102 million in aggregate principal amount of 9.75% senior notes due July 5, 2022 (“2022 Senior Notes”) issued by Talos Production and Talos Production Finance Inc. (collectively, the “Talos Issuers”) to Talos Energy by entities controlled by or affiliated with Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (collectively, the “Apollo Funds”), and Riverstone Energy Partners V, L.P. (collectively, the “Riverstone Funds”) in exchange for shares of Talos Energy common stock (the “Sponsor Debt Exchange”), (iv) the exchange of the 11% senior secured second-priority bridge loans due April 3, 2022 issued by the Talos Issuers (the “Bridge Loans”) for newly issued 11% second lien notes of the Talos Issuers (the “New Second Lien Notes”), and (v) the exchange of 7.50% senior secured notes due 2022 issued by Stone Energy (“2022 Secured Notes”) for New Second Lien Notes. Each stockholder of Stone Energy received one share of Talos Energy common stock for each share of Stone Energy common stock. Immediately after the Closing of the transactions, holders of Stone Energy common stock immediately prior to the Closing held 37% of the outstanding Talos Energy common stock and Talos Energy LLC stakeholders held 63% of the outstanding Talos Energy common stock.

The accompanying unaudited pro forma condensed combined statement of operations was derived by making certain adjustments to the historical statements of operations listed above. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma condensed combined financial statements.

The unaudited pro forma condensed combined statement of operations and related notes are presented for illustrative purposes only and should not be relied upon as an indication of operating results that Talos Energy would have achieved if the transactions had taken place on the specified date. In addition, future results may vary significantly from the results reflected in the unaudited pro forma condensed combined financial statements and should not be relied on as an indication of the future results of Talos Energy.

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Talos Energy Inc.

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Six Months Ended June 30, 2018

(In thousands, except per share amounts)

	Talos Energy Inc. Historical			Stone Energy Historical			Stone Energy Business Combination			Exchange Agreement			Pro Forma Combined
							Note 2			Note 2
Revenues:
Oil revenue	$	307,854		$	110,198		$	—		$	—		$	418,052
Natural gas revenue		29,171			7,206			—			—			36,377
NGL revenue		12,731			4,492			—			—			17,223
Total revenue		349,756			121,896			—			—			471,652
Operating expenses:
Direct lease operating expense		58,975			14,222			—			—			73,197
Insurance		6,934			2,492			—			—			9,426
Production taxes and other		955			(2,130	)		—			—			(1,175	)
Total lease operating expense		66,864			14,584			—			—			81,448
Workover / maintenance expense		24,619			6,550			—			—			31,169
Depreciation, depletion and amortization		116,766			29,215			1,828	(a)		—			147,809
Accretion expense		14,252			6,238			3,696	(b)		—			24,186
General and administrative expense		39,460			25,101			(31,272	)(c)		—			33,289
Total operating expenses		261,961			81,688			(25,748	)		—			317,901
Operating income		87,795			40,208			25,748			—			153,751
Interest expense		(41,420	)		(4,914	)		—			7,754	(e)		(38,580	)
Price risk management activities expense		(143,152	)		(24,213	)		—			—			(167,365	)
Other income		(1,078	)		2,061			—			—			983
Income (loss) before income taxes		(97,855	)		13,142			25,748			7,754			(51,211	)
Income tax expense (benefit)		—			—			—	(d)		—			—
Net income (loss)	$	(97,855	)	$	13,142		$	25,748		$	7,754		$	(51,211	)
Basic income (loss) per share	$	(1.81	)										$	(0.95	)
Diluted income (loss) per share	$	(1.81	)										$	(0.95	)
Average shares outstanding		54,156												54,156
Average shares outstanding assuming dilution		54,156												54,156

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NOTES TO THE UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

Note 1—Basis of Presentation

Overview

The unaudited pro forma condensed combined statement of operations of Talos Energy presents the combination of the historical statement of operations of Talos Energy (including Talos Energy LLC from January 1, 2018 to May 9, 2018) and Stone Energy adjusted to give effect to the transactions. The unaudited pro forma condensed combined statement of operations for the six months ended June 30, 2018 combines the historical consolidated statements of operations of Talos Energy for the six months ended June 30, 2018, which reflects the historical financial results of Talos Energy LLC from January 1, 2018 to May 9, 2018 and of Talos Energy from May 10, 2018 to June 30, 2018, and Stone Energy for the period from January 1, 2018 to May 9, 2018, giving effect to the transactions as if they had been consummated on January 1, 2018. The transactions and other adjustments are described in Note 2—Pro Forma Adjustments and Assumptions to the unaudited pro forma condensed combined statement of operations.

The unaudited pro forma condensed combined statement of operations should be read in conjunction with (i) Stone Energy’s historical condensed consolidated financial statements and related notes for the three months ended March 31, 2018 included elsewhere in this prospectus and (ii) Talos Energy’s historical condensed consolidated financial statements and related notes for the six months ended June 30, 2018 included elsewhere in this prospectus. Certain reclassifications have been made to the Stone Energy historical financial statements to reflect the comparability of financial information.

The pro forma adjustments represent management’s estimates based on information available as of the date of this prospectus and are subject to change as additional information becomes available and additional analyses are performed. The unaudited pro forma condensed combined statement of operations does not reflect the impact of possible revenue or earnings enhancements, cost savings from operating efficiencies or synergies, or asset dispositions. Also, the unauditied pro forma condensed combined statement of operations does not reflect possible adjustments related to restructuring or integration activities that have yet to be determined or transaction or other costs following the transactions that are not expected to have a continuing impact. Further, one-time transaction-related expenses or costs incurred prior to, or concurrent with, Closing of the transactions are not included in the unaudited pro forma condensed combined statements of operations.

Note 2—Pro Forma Adjustments and Assumptions

The following adjustments and assumptions were made in the preparation of the unaudited pro forma condensed combined statements of operations:

(a) Reflects changes in depletion that would have been recorded with respect to the allocated fair values attributable to proved oil and natural gas properties acquired as a result of the application of the full cost method of accounting for oil and natural gas activities following the Closing of the transactions. The pro forma depletion rates for the six months ended June 30, 2018 were estimated using the proved property amounts and estimates of reserves at June 30, 2018, adjusted for actual production. The pro forma depletion rates were applied to production volumes for the respective periods.

(b) Reflects the pro forma adjustment to accretion expense on the combined asset retirement obligation calculated using Talos Energy’s credit-adjusted risk-free interest rate.

(c) Reflects the elimination of direct, incremental costs of the transactions, which are reflected in the historical financial statements of Talos Energy (including Talos Energy LLC) and Stone Energy during the six months ended June 30, 2018.

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(d) Reflects a net impact of zero related to the acquired deferred taxes associated with the business combination on the pro forma adjustments described herein, based on a blended federal and state statutory income tax rate of 21%. Based upon all available evidence, it is more likely than not that the deferred tax assets will not be realized. As such, a valuation allowance is recorded to reduce the combined deferred tax asset balance to zero. The change in tax status is reflected in the unaudited pro forma condensed combined statement of operations. The overall impact is zero.

(e) Reflects a decrease in interest expense associated with (i) the Sponsor Debt Exchange whereby the Apollo Funds and the Riverstone Funds contributed $102 million in aggregate principal amount of their 2022 Senior Notes to Talos Energy for shares of Talos Energy common stock, (ii) accrued interest associated with the 2022 Senior Notes, (iii) the $109 million reduction in the outstanding borrowings on the pro forma revolving line of credit after giving effect to the Closing of the transactions, partially offset by (iv) the increase in coupon for the exchanged 2022 Secured Notes and (v) impact of aligning the interest expense capitalization policy. The following table separately quantifies each adjustment made to interest expense presented in the unaudited pro forma financial condensed combined statements (in thousands):

Contribution of 2022 Senior Notes(i)	$	(6,482	)
Accrued Interest from 2022 Senior Notes(ii)		(3,582	)
Revolving line of credit(iii)		(2,361	)
Change in Stone Energy 2022 secured notes coupon rate(iv)		2,667
Alignment of capitalized interest accounting policy(v)		2,004
Interest expense pro forma adjustment	$	(7,754	)

Interest on borrowings under the pro forma revolving line of credit is based on a current rate of 5.34%. These borrowings bear interest at variable rates and are subject to interest rate risk. A 1/8% change to the interest rate would result in a change in interest expense related to variable rate financing of $0.2 million for the six months ended June 30, 2018.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors

Stone Energy Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Stone Energy Corporation (the Company) as of December 31, 2017 (Successor) and 2016 (Predecessor), the related consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity and cash flows for the period March 1, 2017 through December 31, 2017 (Successor), the period January 1, 2017 through February 28, 2017 (Predecessor), and the years ended December 31, 2016 and 2015 (Predecessor), and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017 (Successor) and 2016 (Predecessor), and the results of its operations and its cash flows for the period March 1, 2017 through December 31, 2017 (Successor), the period January 1, 2017 through February 28, 2017 (Predecessor), and the years ended December 31, 2016 and 2015 (Predecessor), in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 9, 2018 expressed an unqualified opinion thereon.

Company Reorganization

As discussed in Note 1 to the consolidated financial statements, on February 15, 2017, the Bankruptcy Court entered an order confirming the plan of reorganization, which became effective on February 28, 2017. Accordingly, the accompanying consolidated financial statements have been prepared in conformity with Accounting Standards Codification 852-10, Reorganizations, for the Successor as a new entity with assets, liabilities and a capital structure having carrying amounts not comparable with prior periods as described in Note 1.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2002.

New Orleans, Louisiana

March 9, 2018

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STONE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEET

(In thousands of dollars)

	Successor			Predecessor
	December 31, 2017			December 31, 2016
Assets
Current assets:
Cash and cash equivalents	$	263,495		$	190,581
Restricted cash		18,742			—
Accounts receivable		39,258			48,464
Fair value of derivative contracts		879			—
Current income tax receivable		36,260			26,086
Other current assets		7,138			10,151
Total current assets		365,772			275,282
Oil and gas properties, full cost method of accounting:
Proved		713,157			9,616,236
Less: accumulated depreciation, depletion and amortization		(353,462	)		(9,178,442	)
Net proved oil and gas properties		359,695			437,794
Unevaluated		102,187			373,720
Other property and equipment, net of accumulated depreciation of $2,561 and $27,418, respectively		17,275			26,213
Other assets, net of accumulated depreciation and amortization of $5,360 at December 31, 2016		13,844			26,474
Total assets	$	858,773		$	1,139,483
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	54,226		$	19,981
Undistributed oil and gas proceeds		5,142			15,073
Accrued interest		1,685			809
Fair value of derivative contracts		8,969			—
Asset retirement obligations		79,300			88,000
Current portion of long-term debt		425			408
Other current liabilities		22,579			18,602
Total current liabilities		172,326			142,873
Long-term debt		235,502			352,376
Asset retirement obligations		133,801			154,019
Fair value of derivative contracts		3,085			—
Other long-term liabilities		5,891			17,315
Total liabilities not subject to compromise		550,605			666,583
Liabilities subject to compromise		—			1,110,182
Total liabilities		550,605			1,776,765
Commitments and contingencies
Stockholders’ equity:
Predecessor common stock ($.01 par value; authorized 30,000,000 shares; issued 5,610,020 shares)		—			56
Predecessor treasury stock (1,658 shares, at cost)		—			(860	)
Predecessor additional paid-in capital		—			1,659,731
Successor common stock ($.01 par value; authorized 60,000,000 shares; issued 19,998,019 shares)		200			—
Successor additional paid-in capital		555,607			—
Accumulated deficit		(247,639	)		(2,296,209	)
Total stockholders’ equity		308,168			(637,282	)
Total liabilities and stockholders’ equity	$	858,773		$	1,139,483

The accompanying notes are an integral part of this balance sheet.

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STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
							2016			2015
Operating revenue:
Oil production	$	211,792		$	45,837		$	281,246		$	416,497
Natural gas production		18,874			13,476			64,601			83,509
Natural gas liquids production		9,610			8,706			28,888			32,322
Other operational income		10,008			903			2,657			4,369
Derivative income, net		—			—			—			7,952
Total operating revenue		250,284			68,922			377,392			544,649
Operating expenses:
Lease operating expenses		49,800			8,820			79,650			100,139
Transportation, processing and gathering expenses		4,084			6,933			27,760			58,847
Production taxes		629			682			3,148			6,877
Depreciation, depletion and amortization		99,890			37,429			220,079			281,688
Write-down of oil and gas properties		256,435			—			357,431			1,362,447
Accretion expense		21,151			5,447			40,229			25,988
Salaries, general and administrative expenses		47,817			9,629			58,928			69,384
Incentive compensation expense		8,045			2,008			13,475			2,242
Restructuring fees		739			—			29,597			—
Other operational expenses		3,359			530			55,453			2,360
Derivative expense, net		13,388			1,778			810			—
Total operating expenses		505,337			73,256			886,560			1,909,972
Gain (loss) on Appalachia Properties divestiture		(105	)		213,453			—			—
Income (loss) from operations		(255,158	)		209,119			(509,168	)		(1,365,323	)
Other (income) expense:
Interest expense		11,744			—			64,458			43,928
Interest income		(998	)		(45	)		(550	)		(580	)
Other income		(1,156	)		(315	)		(1,439	)		(1,783	)
Other expense		1,230			13,336			596			434
Reorganization items, net		—			(437,744	)		10,947			—
Total other (income) expense		10,820			(424,768	)		74,012			41,999
Income (loss) before income taxes		(265,978	)		633,887			(583,180	)		(1,407,322	)
Provision (benefit) for income taxes:
Current		(18,339	)		3,570			(5,674	)		(44,096	)
Deferred		—			—			13,080			(272,311	)
Total income taxes		(18,339	)		3,570			7,406			(316,407	)
Net income (loss)	$	(247,639	)	$	630,317		$	(590,586	)	$	(1,090,915	)
Basic income (loss) per share	$	(12.38	)	$	110.99		$	(105.63	)	$	(197.45	)
Diluted income (loss) per share	$	(12.38	)	$	110.99		$	(105.63	)	$	(197.45	)
Average shares outstanding		19,997			5,634			5,591			5,525
Average shares outstanding assuming dilution		19,997			5,634			5,591			5,525

The accompanying notes are an integral part of this statement.

F-88

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017		Year Ended December 31,
						2016			2015
Net income (loss)	$	(247,639	)	$	630,317	$	(590,586	)	$	(1,090,915	)
Other comprehensive income (loss), net of tax effect:
Derivatives		—			—		(24,025	)		(62,758	)
Foreign currency translation		—			—		6,073			(2,605	)
Comprehensive income (loss)	$	(247,639	)	$	630,317	$	(608,538	)	$	(1,156,278	)

The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)

	Common Stock			Treasury Stock			Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Balance, December 31, 2014 (Predecessor)	$	55		$	(860	)	$	1,633,801		$	(614,708	)	$	83,315		$	1,101,603
Net loss		—			—			—			(1,090,915	)		—			(1,090,915	)
Adjustment for fair value accounting of derivatives, net of tax		—			—			—			—			(62,758	)		(62,758	)
Adjustment for foreign currency translation, net of tax		—			—			—			—			(2,605	)		(2,605	)
Lapsing of forfeiture restrictions of restricted stock		—			—			(2,638	)		—			—			(2,638	)
Amortization of stock compensation expense		—			—			17,524			—			—			17,524
Balance, December 31, 2015 (Predecessor)		55			(860	)		1,648,687			(1,705,623	)		17,952			(39,789	)
Net loss		—			—			—			(590,586	)		—			(590,586	)
Adjustment for fair value accounting of derivatives, net of tax		—			—			—			—			(24,025	)		(24,025	)
Adjustment for foreign currency translation, net of tax		—			—			—			—			6,073			6,073
Lapsing of forfeiture restrictions of restricted stock and granting of stock awards		1			—			(732	)		—			—			(731	)
Amortization of stock compensation expense		—			—			11,776			—			—			11,776
Balance, December 31, 2016 (Predecessor)		56			(860	)		1,659,731			(2,296,209	)		—			(637,282	)
Net income		—			—			—			630,317			—			630,317
Lapsing of forfeiture restrictions of restricted stock and granting of stock awards		—			—			(172	)		—			—			(172	)
Amortization of stock compensation expense		—			—			3,527			—			—			3,527
Balance, February 28, 2017 (Predecessor)		56			(860	)		1,663,086			(1,665,892	)		—			(3,610	)
Cancellation of Predecessor equity		(56	)		860			(1,663,086	)		1,665,892			—			3,610
Balance, February 28, 2017 (Predecessor)		—			—			—			—			—			—
Issuance of Successor common stock and warrants		200			—			554,537			—			—			554,737
Balance, February 28, 2017 (Successor)		200			—			554,537			—			—			554,737
Net loss		—			—			—			(247,639	)		—			(247,639	)
Lapsing of forfeiture restrictions of restricted stock		—			—			(19	)		—			—			(19	)
Amortization of stock compensation expense		—			—			1,272			—			—			1,272
Stock issuance costs - Talos combination		—			—			(183	)					—			(183	)
Balance, December 31, 2017 (Successor)	$	200		$	—		$	555,607		$	(247,639	)	$	—		$	308,168

The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from Jan. 1, 2017 through Feb. 28, 2017			Year Ended December 31,
							2016			2015
Cash flows from operating activities:
Net income (loss)	$	(247,639	)	$	630,317		$	(590,586	)	$	(1,090,915	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		99,890			37,429			220,079			281,688
Write-down of oil and gas properties		256,435			—			357,431			1,362,447
Accretion expense		21,151			5,447			40,229			25,988
Deferred income tax provision (benefit)		—			—			13,080			(272,311	)
(Gain) loss on sale of oil and gas properties		105			(213,453	)		—			—
Settlement of asset retirement obligations		(80,671	)		(3,641	)		(20,514	)		(72,382	)
Non-cash stock compensation expense		1,252			2,645			8,443			12,324
Excess tax benefits		—			—			—			(1,586	)
Non-cash derivative expense		15,548			1,778			1,471			16,440
Non-cash interest expense		4			—			18,404			17,788
Non-cash reorganization items		—			(458,677	)		8,332			—
Other non-cash expense		1,245			172			6,248			—
Change in current income taxes		(13,744	)		3,570			20,088			(37,377	)
(Increase) decrease in accounts receivable		2,455			6,354			(1,412	)		43,724
(Increase) decrease in other current assets		4,648			(2,274	)		(3,493	)		1,767
Decrease in inventory		—			—			—			1,304
Increase (decrease) in accounts payable		17,113			(4,652	)		1,026			(14,582	)
Increase (decrease) in other current liabilities		10,677			(9,653	)		9,897			(25,936	)
Investment in derivative contracts		(2,416	)		(3,736	)		—			—
Other		3,023			2,490			(10,135	)		(907	)
Net cash provided by (used in) operating activities		89,076			(5,884	)		78,588			247,474
Cash flows from investing activities:
Investment in oil and gas properties		(65,282	)		(8,754	)		(237,952	)		(522,047	)
Proceeds from sale of oil and gas properties, net of expenses		20,633			505,383			—			22,839
Investment in fixed and other assets		(163	)		(61	)		(1,266	)		(1,549	)
Change in restricted funds		56,805			(75,547	)		1,046			179,467
Net cash provided by (used in) investing activities		11,993			421,021			(238,172	)		(321,290	)
Cash flows from financing activities:
Proceeds from bank borrowings		—			—			477,000			5,000
Repayments of bank borrowings		—			(341,500	)		(135,500	)		(5,000	)
Proceeds from building loan		—			—			—			11,770
Repayments of building loan		(337	)		(24	)		(423	)		—
Cash payment to noteholders		—			(100,000	)		—			—
Stock issuance costs - Talos combination		(184	)		—			—			—
Debt issuance costs		—			(1,055	)		(900	)		(68	)
Excess tax benefits		—			—			—			1,586
Net payments for share-based compensation		(19	)		(173	)		(762	)		(3,127	)
Net cash provided by (used in) financing activities		(540	)		(442,752	)		339,415			10,161
Effect of exchange rate changes on cash		—			—			(9	)		(74	)
Net change in cash and cash equivalents		100,529			(27,615	)		179,822			(63,729	)
Cash and cash equivalents, beginning of period		162,966			190,581			10,759			74,488
Cash and cash equivalents, end of period	$	263,495		$	162,966		$	190,581		$	10,759
Supplemental cash flow information:
Cash paid for interest, net of amount capitalized	$	(10,256	)		—		$	(32,130	)	$	(34,394	)
Cash refunded for income taxes, net of amounts paid		5,420			—			25,762			7,212

The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Stone Energy Corporation (“Stone” or the “Company”) is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the Gulf of Mexico (the “GOM”) Basin since our incorporation in 1993 and have established technical and operational expertise in this area. We leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific plays of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia. At December 31, 2016, we had producing properties and acreage in the Marcellus and Utica Shales in Appalachia. In connection with our restructuring efforts, we completed the sale of the Appalachia Properties (as defined inNote 2 – Reorganization) to EQT Corporation, through its wholly owned subsidiary EQT Production Company (“EQT”), on February 27, 2017 for net cash consideration of approximately $522.5 million. SeeNote 2 – Reorganization andNote 4 – Divestiturefor additional information on the sale of the Appalachia Properties. We were incorporated in 1993 as a Delaware corporation. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508. We have an additional office in New Orleans, Louisiana.

Pending Combination with Talos

On November 21, 2017, Stone and certain of its subsidiaries entered into a series of related agreements pertaining to a business combination with Talos Energy LLC (“Talos Energy”) and its indirect wholly owned subsidiary Talos Production LLC (“Talos Production” and, together with Talos Energy, “Talos”). Talos Energy is controlled indirectly by entities controlled by Apollo Management VII, L.P. (“Apollo VII”), Apollo Commodities Management, L.P., with respect to Series I (together with Apollo VII, “Apollo Management”) and Riverstone Energy Partners V, L.P. (“Riverstone”).

Stone, Sailfish Energy Holdings Corporation (“New Talos”), a direct wholly owned subsidiary of Stone, and Sailfish Merger Sub Corporation, a direct wholly owned subsidiary of New Talos, entered into a Transaction Agreement (the “Transaction Agreement”) with Talos on November 21, 2017, which contemplates a series of transactions (the “Transactions”) occurring on the date of closing of the Transaction Agreement (the “Closing”) that will result in such business combination. Stone and Talos will become wholly owned subsidiaries of New Talos. At the time of the Closing, the parties intend that New Talos will become a publicly traded entity named Talos Energy, Inc. The Transactions include (i) the contribution of 100% of the equity interests in Talos Production to New Talos in exchange for shares of New Talos common stock, (ii) the contribution by entities controlled by or affiliated with Apollo Management (the “Apollo Funds”) and Riverstone (the “Riverstone Funds”) of $102 million in aggregate principal amount of 9.75% Senior Notes due 2022 issued by Talos Production and Talos Production Finance Inc. (together, the “the Talos Issuers”) to New Talos in exchange for shares of New Talos common stock, (iii) the exchange of the second lien bridge loans due 2022 issued by the Talos Issuers for newly issued 11% second lien notes issued by the Talos Issuers, and (iv) the exchange of the 7.50% Senior Second Lien Notes due 2022 (the “2022 Second Lien Notes”) issued by Stone for newly issued 11% second lien notes issued by the Talos Issuers.

Under the terms of the Transaction Agreement, each outstanding share of Stone common stock will be exchanged for one share of New Talos common stock and the current Talos stakeholders (including the Apollo Funds and the Riverstone Funds) will be issued an aggregate of approximately 34.1 million common shares of New Talos. After the completion of the Transactions contemplated by the Transaction Agreement, holders of Stone common stock immediately prior to the combination will collectively hold 37% of the outstanding New Talos common stock and Talos Energy stakeholders will hold 63% of the outstanding New Talos common stock. Outstanding warrants to acquire Stone common stock will become warrants to acquire New Talos common stock with terms and conditions substantially identical to their existing terms and conditions.

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The combination was unanimously approved by the boards of directors of Stone and Talos Energy. Completion of the combination is subject to the approval of Stone shareholders, the consummation of a tender offer and consent solicitation for Stone’s 2022 Second Lien Notes, certain regulatory approvals and other customary conditions. Franklin Advisers, Inc. and MacKay Shields LLC, as investment managers for approximately 53% of the outstanding common shares of Stone as of September 30, 2017, entered into voting agreements to vote in favor of the combination, subject to certain conditions. The Transaction Agreement contains certain termination rights for Stone and Talos Energy. Stone may be required to pay a termination fee and to reimburse transaction expenses to Talos Energy if the Transaction Agreement is terminated under certain circumstances. The combination is expected to close in the second quarter of 2018. We cannot provide any assurance that the combination will be completed on the terms or timeline currently contemplated, or at all.

Reorganization and Emergence from Voluntary Chapter 11 Proceedings

On December 14, 2016 (the “Petition Date”), the Company and its subsidiaries Stone Energy Offshore, L.L.C. (“Stone Offshore”) and Stone Energy Holding, L.L.C. (together with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) seeking relief under the provisions of Chapter 11 of Title 11 (“Chapter 11”) of the United States Bankruptcy Code (the “Bankruptcy Code”). On February 15, 2017, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates, dated December 28, 2016 (the “Plan”), as modified by the Confirmation Order, and on February 28, 2017, the Plan became effective (the “Effective Date”) and the Debtors emerged from bankruptcy, with the bankruptcy cases then being closed by Final Decree Closing Chapter 11 Cases and Terminating Claims Agent Services entered by the Bankruptcy Court on April 20, 2017. SeeNote 2 – Reorganization for additional details.

Upon emergence from bankruptcy, the Company adopted fresh start accounting in accordance with the provisions of Accounting Standards Codification (“ASC”) 852, “Reorganizations”, which resulted in the Company becoming a new entity for financial reporting purposes on the Effective Date. As a result of the adoption of fresh start accounting, the Company’s consolidated financial statements subsequent to February 28, 2017 will not be comparable to its financial statements prior to that date. SeeNote 3 – Fresh Start Accounting for further details on the impact of fresh start accounting on the Company’s consolidated financial statements.

References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.

Summary of Significant Accounting Policies

A summary of significant accounting policies followed in the preparation of the accompanying consolidated financial statements is set forth below.

Basis of Presentation:

The financial statements include our accounts and the accounts of our wholly owned subsidiaries, Stone Offshore, Stone Energy Holding, L.L.C. and Stone Energy Canada, ULC. On August 29, 2016, our subsidiaries SEO A LLC and SEO B LLC were merged into Stone Offshore. On December 2, 2016, Stone Energy Canada, ULC was dissolved. All intercompany balances have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation.

Reorganization and Fresh Start Accounting:

For periods subsequent to the Chapter 11 filing, but prior to emergence, ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the

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ongoing operations of the business. Accordingly, professional fees and other expenses incurred in the Chapter 11 cases, and unamortized debt issuance costs, premiums and discounts associated with debt classified as liabilities subject to compromise, have been recorded as reorganization items on the consolidated statement of operations for the applicable periods. In addition, pre-petition obligations that were to be impacted by the Chapter 11 process were classified on the consolidated balance sheet at December 31, 2016 as liabilities subject to compromise. SeeNote 2 – Reorganization and Note 3 – Fresh Start Accountingfor more information regarding reorganization items and liabilities subject to compromise.

Upon emergence from bankruptcy, the Company qualified for and adopted fresh start accounting in accordance with the provisions of ASC 852, as (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the post-petition liabilities and allowed claims. The Company applied fresh start accounting as of February 28, 2017. Fresh start accounting required the Company to present its assets, liabilities and equity as if it were a new entity upon emergence from bankruptcy, with no beginning retained earnings or deficit as of the fresh start reporting date. The new entity is referred to as Successor or Successor Company, and includes the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to Predecessor or Predecessor Company relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.

The Chapter 11 proceedings did not include our former foreign subsidiary Stone Energy Canada, ULC. This subsidiary had no significant activity during 2016, except for the reclassification of approximately $6.1 million of losses related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the substantial liquidation of Stone Energy Canada, ULC. Stone Energy Canada, ULC was dissolved on December 2, 2016.

Use of Estimates:

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (“GAAP”) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and on various assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects are uncertain and, accordingly, these estimates may change as new events occur, as additional information is obtained and as the Company’s operating environment changes. Actual results could differ from those estimates. Estimates are used primarily when accounting for depreciation, depletion and amortization (“DD&A”) expense, unevaluated property costs, estimated future net cash flows from proved reserves, costs to abandon oil and gas properties, income taxes, accruals of capitalized costs, operating costs and production revenue, capitalized general and administrative costs and interest, insurance recoveries, estimated fair value of derivative contracts, contingencies and fair value estimates, including estimates of reorganization value, enterprise value and the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting.

Fair Value Measurements:

U.S. GAAP establishes a framework for measuring fair value and requires certain disclosures about fair value measurements. As of December 31, 2017 and 2016, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities.

On February 28, 2017, the Company emerged from bankruptcy and adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start

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accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh start reporting date, February 28, 2017. SeeNote 3 – Fresh Start Accounting for a detailed discussion of the fair value approaches used by the Company.

Cash and Cash Equivalents:

We consider all money market funds and highly liquid investments in overnight securities through our commercial bank accounts, which result in available funds on the next business day, to be cash and cash equivalents. On December 31, 2017, we had $18.7 million of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the terms of the Amended Credit Agreement (as defined inNote 13 – Debt).

Oil and Gas Properties:

We follow the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration, development and estimated abandonment costs, including certain related employee and general and administrative costs (less any reimbursements for such costs) and interest incurred for the purpose of finding oil and gas are capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Employee, general and administrative costs that are capitalized include salaries and all related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties, as well as all other directly identifiable general and administrative costs associated with such activities, such as rentals, utilities and insurance. We capitalize a portion of the interest costs incurred on our debt based upon the balance of our unevaluated property costs and our weighted-average borrowing rate. Employee, general and administrative costs associated with production operations and general corporate activities are expensed in the period incurred. Additionally, workover and maintenance costs incurred solely to maintain or increase levels of production from an existing completion interval are charged to lease operating expense in the period incurred.

U.S. GAAP allows the option of two acceptable methods for accounting for oil and gas properties. The successful efforts method is the allowable alternative to the full cost method. The primary differences between the two methods are in the treatment of exploration costs, the computation of DD&A expense and the assessment of impairment of oil and gas properties. Under the full cost method, all exploratory costs are capitalized, while under the successful efforts method, exploratory costs associated with unsuccessful exploratory wells and all geological and geophysical costs are expensed. Under the full cost method, DD&A expense is computed on cost centers represented by entire countries, while under the successful efforts method, cost centers are represented by properties, or some reasonable aggregation of properties with common geological structural features or stratigraphic condition, such as fields or reservoirs. Under the full cost method, oil and gas properties are subject to the ceiling test as discussed below while under the successful efforts method oil and gas properties are assessed for impairment in accordance with ASC 360.

We amortize our investment in oil and gas properties through DD&A expense using the units of production (the “UOP”) method. Under the UOP method, the quarterly provision for DD&A expense is computed by dividing production volumes for the period by the total proved reserves as of the beginning of the period (beginning of period reserves being determined by adding production to the end of period reserves), and applying the respective rate to the net cost of proved oil and gas properties, including future development costs.

Under the full cost method, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges 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 discounted cash flows.

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Sales of oil and gas properties are accounted for as adjustments to net oil and gas properties with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

Asset Retirement Obligations:

U.S. GAAP requires us to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment at the end of an oil and gas property’s useful life. The application of this rule requires the use of management’s estimates with respect to future abandonment costs, inflation, timing of abandonment and cost of capital. U.S. GAAP requires that our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.

Other Property and Equipment:

Our office buildings in Lafayette, Louisiana are being depreciated on the straight-line method over their estimated useful lives of 39 years.

Derivative Instruments and Hedging Activities:

Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. Accordingly, the contracts were recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. Monthly settlements of effective hedges were reflected in revenue from oil and natural gas production. With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements of these derivative contracts are recorded in earnings through derivative income (expense).

Earnings Per Common Share:

Under U.S. GAAP, certain instruments granted in share-based payment transactions are considered participating securities prior to vesting and are therefore required to be included in the earnings allocation in calculating earnings per share under the two-class method. Companies are required to treat unvested share-based payment awards with a right to receive non-forfeitable dividends as a separate class of securities in calculating earnings per share.

Production Revenue:

We recognize production revenue under the entitlements method of accounting. Under this method, revenue is deferred for deliveries in excess of our net revenue interest, while revenue is accrued for undelivered or underdelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. SeeRecently Issued Accounting Standards below.

Income Taxes:

Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting and income tax purposes. For financial reporting purposes, all exploratory and development expenditures related to evaluated projects, including future abandonment costs, are capitalized and amortized using the UOP method. For income tax purposes, only the leasehold, geological and geophysical and equipment costs relative to successful wells are

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capitalized and recovered through DD&A, although for 2015, 2016 and 2017, special provisions allowed for current deductions for the cost of certain equipment. Generally, most other exploratory and development costs are charged to expense as incurred; however, we follow certain provisions of the Internal Revenue Code (the “IRC”) that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion, different reporting methods for sales of oil and gas reserves in place, different reporting methods used in the capitalization of employee, general and administrative and interest expense, and different reporting methods for employee compensation. SeeNote 12 – Income Taxes for a discussion of the effects of the December 22, 2017 enactment of the Tax Cuts and Jobs Act.

Share-Based Compensation:

We record share-based compensation using the grant date fair value of issued stock options, stock awards, restricted stock and restricted stock units over the vesting period of the instrument. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The fair value of stock awards, restricted stock and restricted stock units is typically determined based on the average of our high and low stock prices on the grant date.

Combination Transaction Costs:

In general, acquisition-related costs are expensed in the periods in which the costs are incurred and the services are rendered. However, some direct costs of an acquisition, such as the cost of registering and issuing equity securities to effect a business combination, are recorded as a reduction of additional paid-in-capital when incurred.

Recently Issued Accounting Standards:

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers (Topic 606)” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers including the disaggregation of revenue and remaining performance obligations. The standard may be applied retrospectively or using a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application, and is effective for interim and annual periods beginning on or after December 15, 2017.

We adopted this new standard on January 1, 2018 using the modified retrospective approach. The adoption of the standard did not have a material effect on our financial position, results of operations or cash flows, but will result in increased disclosures related to revenue recognition policies and disaggregation of revenues.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)” to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public companies for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. We are currently evaluating the effect that this new standard may have on our financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-09, “Compensation – Stock Compensation (Topic 718)” to simplify several aspects of the accounting for share-based payment transactions, including the income tax

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consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. ASU 2016-09 became effective for us on January 1, 2017. Under ASU 2016-09, we elected to not apply a forfeiture estimate and will recognize a credit in compensation expense to the extent awards are forfeited. The implementation of this new standard did not have a material effect on our financial statements or related disclosures.

In August 2017, the FASB issued ASU 2017-12, “Derivatives and Hedging (Topic 815)” to improve the financial reporting of hedging relationships to better reflect an entity’s hedging strategies. The standard expands an entity’s ability to apply hedge accounting for both non-financial and financial risk components and amends the presentation and disclosure requirements. Additionally, ASU 2017-12 eliminates the need to separately measure and report hedge ineffectiveness and generally requires the entire change in fair value of a hedging instrument to be recorded in the same income statement line as the earnings effect of the hedged item. The standard is effective for public companies for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted. The standard must be adopted by applying a modified retrospective approach to existing designated hedging relationships as of the adoption date, with a cumulative effect adjustment recorded to opening retained earnings as of the initial adoption date. We are currently evaluating the effect that this new standard may have on our financial statements and related disclosures.

NOTE 2 — REORGANIZATION

On December 14, 2016, the Debtors filed the Bankruptcy Petitions seeking relief under the provisions of Chapter 11 of the Bankruptcy Code to pursue a prepackaged plan of reorganization. On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan, and on February 28, 2017, the Plan became effective and the Debtors emerged from bankruptcy.

Prior to filing the Bankruptcy Petitions, on October 20, 2016, the Debtors and certain holders of the Company’s 1 ³⁄₄% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”) and the Company’s 7 ¹⁄₂% Senior Notes due 2022 (the “2022 Notes”) (collectively, the “Notes” and the holders thereof, the “Noteholders”) and the lenders (the “Banks”) under the Fourth Amended and Restated Credit Agreement, dated as of June 24, 2014, as amended, modified, or otherwise supplemented from time to time (the “Pre-Emergence Credit Agreement”), entered into an Amended and Restated Restructuring Support Agreement (the “A&R RSA”). The A&R RSA contained certain covenants on the part of the Company and the Noteholders and Banks who are signatories to the A&R RSA, including that such Noteholders and Banks would support the Company’s sale of Stone’s producing properties and acreage, including approximately 86,000 net acres, in the Appalachia regions of Pennsylvania and West Virginia (the “Appalachia Properties”) to TH Exploration III, LLC, an affiliate of Tug Hill, Inc. (“Tug Hill”), pursuant to the terms of a Purchase and Sale Agreement dated October 20, 2016, as amended on December 9, 2016 (the “Tug Hill PSA”) for a purchase price of at least $350 million and approval of the Bankruptcy Court. Pursuant to the terms of the Tug Hill PSA, Stone agreed to sell the Appalachia Properties to Tug Hill for $360 million in cash, subject to customary purchase price adjustments.

Pursuant to Bankruptcy Court orders dated January 11, 2017 and January 31, 2017, two additional bidders were allowed to participate in competitive bidding on the Appalachia Properties. On January 18, 2017, the Bankruptcy Court approved certain bidding procedures (the “Bidding Procedures”) in connection with the sale of the Appalachia Properties. In accordance with the Bidding Procedures, Stone conducted an auction for the sale of the Appalachia Properties on February 8, 2017 and upon conclusion, selected the final bid submitted by EQT, with a final purchase price of $527 million in cash, subject to customary purchase price adjustments and approval by the Bankruptcy Court, with an upward adjustment to the purchase price of up to $16 million in an amount equal to certain downward adjustments, as the prevailing bid. On February 9, 2017, the Company entered into a purchase and sale agreement with EQT (the “EQT PSA”), reflecting the terms of the prevailing bid and on February 10, 2017, the Bankruptcy Court entered a sale order approving the sale of the Appalachia Properties to EQT. We completed the sale of the Appalachia Properties to EQT on February 27, 2017 for net cash consideration of approximately $522.5 million. At the close of the sale of the Appalachia Properties, the Tug Hill

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PSA was terminated, and the Company used a portion of the cash consideration received to pay Tug Hill a break-up fee and expense reimbursements totaling approximately $11.5 million, which is recognized as other expense in the statement of operations for the period of January 1, 2017 through February 28, 2017 (Predecessor). SeeNote 4 – Divestiture for additional information on the sale of the Appalachia Properties.

Upon emergence from bankruptcy, pursuant to the terms of the Plan, the following significant transactions occurred:

• Shares of the Predecessor Company’s issued and outstanding common stock immediately prior to the Effective Date were cancelled, and on the Effective Date, reorganized Stone issued an aggregate of 20.0 million shares of new common stock (the “New Common Stock”).

• The Predecessor Company’s 2022 Notes and 2017 Convertible Notes were cancelled and the holders of such notes received their pro rata share of (a) $100 million of cash, (b) 19.0 million shares of New Common Stock, representing 95% of the New Common Stock and (c) $225 million of the 2022 Second Lien Notes.

• The Predecessor Company’s common stockholders received their pro rata share of 1.0 million shares of the New Common Stock, representing 5% of the New Common Stock, and warrants to purchase approximately 3.5 million shares of New Common Stock. The warrants have an exercise price of $42.04 per share and a term of four years, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company.

• The Predecessor Company’s Pre-Emergence Credit Agreement was amended and restated as the Amended Credit Agreement (as defined inNote 13 – Debt). The obligations owed to the lenders under the Pre-Emergence Credit Agreement were converted to obligations under the Amended Credit Agreement.

• All claims of creditors with unsecured claims, other than claims by the holders of the 2022 Notes and 2017 Convertible Notes, including vendors, were unaltered and paid in full in the ordinary course of business to the extent such claims were undisputed.

For further information regarding the equity and debt instruments of the Predecessor Company and the Successor Company, seeNote 5 – Stockholders’ Equity andNote 13 – Debt.

NOTE 3 — FRESH START ACCOUNTING

Upon emergence from bankruptcy, the Company qualified for and adopted fresh start accounting in accordance with the provisions of ASC 852, “Reorganizations” as (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the post-petition liabilities and allowed claims. SeeNote 2 – Reorganization for the terms of the Plan. The Company applied fresh start accounting as of February 28, 2017. Fresh start accounting required the Company to present its assets, liabilities and equity as if it were a new entity upon emergence from bankruptcy, with no beginning retained earnings or deficit as of the fresh start reporting date. As described inNote 1 – Organization and Summary of Significant Accounting Policies, the new entity is referred to as Successor or Successor Company, and includes the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to Predecessor or Predecessor Company relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.

Reorganization Value

Under fresh start accounting, reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately after

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restructuring. Upon application of fresh start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values.

The Company’s reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s long-term debt and stockholders’ equity. In support of the Plan, the Company estimated the enterprise value of the core assets (as defined in the Plan) of the Successor Company to be in the range of $300 million to $450 million, which was subsequently approved by the Bankruptcy Court. This valuation analysis was prepared using reserve information, development schedules, other financial information and financial projections and applying standard valuation techniques, including net asset value analysis, precedent transactions analyses and public comparable company analyses. Based on the estimates and assumptions used in determining the enterprise value, the Company ultimately estimated the enterprise value of the Successor Company’s core assets to be approximately $420 million.

Valuation of Assets

The Company’s principal assets are its oil and gas properties, which the Company accounts for under the full cost accounting method. With the assistance of valuation experts, the Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the bankruptcy emergence date.

The fair value analysis performed by valuation experts was based on the Company’s estimates of reserves as developed internally by the Company’s reserve engineers. For purposes of estimating the fair value of the Company’s proved, probable and possible reserves, an income approach was used, which estimated fair value based on the anticipated cash flows associated with the Company’s reserves, risked by reserve category and discounted using a weighted average cost of capital of 12.5%. The discount factor was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar market participants.

Future revenues were based upon forward strip oil and natural gas prices as of the emergence date, adjusted for differentials realized by the Company, and adjusted for a 2% annual escalation after 2021. Development and operating costs were based on the Company’s recent cost trends adjusted for inflation. The discounted cash flow models also included estimates not typically included in proved reserves such as depreciation and income tax expenses. The proved reserve locations were limited to wells expected to be drilled in the Company’s five year development plan.

As a result of this analysis, the Company concluded the fair value of its proved reserves was $380.8 million and the fair value of its probable and possible reserves was $16.8 million as of the Effective Date. The Company also reviewed its undeveloped leasehold acreage and inventory. An analysis of comparable market transactions indicated a fair value of undeveloped acreage and inventory totaling $80.2 million. These amounts are reflected in theFresh Start Adjustments item number 12 below. The fair value of the Company’s asset retirement obligations was estimated at $290.1 million and was based on estimated plugging and abandonment costs as of the Effective Date, adjusted for inflation and discounted at the Successor Company’s credit-adjusted risk free rate of 12%.

See further discussion inFresh Start Adjustments below for details on the specific assumptions used in the valuation of the Company’s various other assets.

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The following table reconciles the enterprise value per the Plan to the estimated fair value (for fresh start accounting purposes) of the Successor Company’s common stock as of February 28, 2017 (in thousands, except per share value):

	February 28, 2017
Enterprise value	$	419,720
Plus: Cash and other assets		371,278
Less: Fair value of debt		(236,261	)
Less: Fair value of warrants		(15,648	)
Fair value of Successor common stock	$	539,089
Shares issued upon emergence		20,000
Per share value	$	26.95

The following table reconciles the enterprise value per the Plan to the estimated reorganization value as of the Effective Date (in thousands):

	February 28, 2017
Enterprise value	$	419,720
Plus: Cash and other assets		371,278
Plus: Asset retirement obligations (current and long-term)		290,067
Plus: Working capital and other liabilities		58,055
Reorganization value of Successor assets	$	1,139,120

Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond our control. Accordingly, the estimates set forth herein are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized.

Condensed Consolidated Balance Sheet

The adjustments set forth in the following condensed consolidated balance sheet reflect the effects of the transactions contemplated by the Plan and carried out by the Company (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or

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other amounts of the assets and liabilities as well as significant assumptions or inputs. The following table reflects the reorganization and application of ASC 852 on our consolidated balance sheet as of February 28, 2017 (in thousands):

	Predecessor Company			Reorganization Adjustments			Fresh Start Adjustments			Successor Company
Assets
Current assets:
Cash and cash equivalents	$	198,571		$	(35,605	)(1)	$	—		$	162,966
Restricted cash		—			75,547	(1)		—			75,547
Accounts receivable		42,808			9,301	(2)		—			52,109
Fair value of derivative contracts		1,267			—			—			1,267
Current income tax receivable		22,516			—			—			22,516
Other current assets		11,033			875	(3)		(124	)(12)		11,784
Total current assets		276,195			50,118			(124	)		326,189
Oil and gas properties, full cost method of accounting:
Proved		9,633,907			(188,933	)(1)		(8,774,122	)(12)		670,852
Less: accumulated DD&A		(9,215,679	)		—			9,215,679	(12)		—
Net proved oil and gas properties		418,228			(188,933	)		441,557			670,852
Unevaluated		371,140			(127,838	)(1)		(146,292	)(12)		97,010
Other property and equipment, net		25,586			(101	)(4)		(4,423	)(13)		21,062
Fair value of derivative contracts		1,819			—			—			1,819
Other assets, net		26,516			(4,328	)(5)		—			22,188
Total assets	$	1,119,484		$	(271,082	)	$	290,718		$	1,139,120
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	20,512		$	—		$	—		$	20,512
Undistributed oil and gas proceeds		5,917			(4,139	)(1)		—			1,778
Accrued interest		266			—			—			266
Asset retirement obligations		92,597			—			—			92,597
Fair value of derivative contracts		476			—			—			476
Current portion of long-term debt		411			—			—			411
Other current liabilities		17,032			(195	)(6)		—			16,837
Total current liabilities		137,211			(4,334	)		—			132,877
Long-term debt		352,350			(116,500	)(7)		—			235,850
Asset retirement obligations		151,228			(8,672	)(1)		54,914	(14)		197,470
Fair value of derivative contracts		653			—			—			653
Other long-term liabilities		17,533			—			—			17,533
Total liabilities not subject to compromise		658,975			(129,506	)		54,914			584,383
Liabilities subject to compromise		1,110,182			(1,110,182	)(8)		—			—
Total liabilities		1,769,157			(1,239,688	)		54,914			584,383
Commitments and contingencies Stockholders’ equity:
Common stock (Predecessor)		56			(56	)(9)		—			—
Treasury stock (Predecessor)		(860	)		860	(9)		—			—
Additional paid-in capital (Predecessor)		1,660,810			(1,660,810	)(9)		—			—
Common stock (Successor)		—			200	(10)		—			200
Additional paid-in capital (Successor)		—			554,537	(10)		—			554,537
Accumulated deficit		(2,309,679	)		2,073,875	(11)		235,804	(15)		—
Total stockholders’ equity		(649,673	)		968,606			235,804			554,737
Total liabilities and stockholders’ equity	$	1,119,484		$	(271,082	)	$	290,718		$	1,139,120

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Reorganization Adjustments

1. Reflects the net cash proceeds received from the sale of the Appalachia Properties in connection with the Plan and net cash payments made as of the Effective Date from implementation of the Plan (in thousands):

Sources:
Net cash proceeds from sale of Appalachia Properties(a)	$	512,472
Total sources		512,472
Uses:
Cash transferred to restricted account(b)		75,547
Break-up fee to Tug Hill		10,800
Repayment of outstanding borrowings under Pre-Emergence Credit Agreement		341,500
Repayment of 2017 Convertible Notes and 2022 Notes		100,000
Other fees and expenses(c)		20,230
Total uses		548,077
Net uses	$	(35,605	)

(a) The closing of the sale of the Appalachia Properties occurred on February 27, 2017, but as emergence was contingent on such closing, the effects of the transaction are reflected as reorganization adjustments. SeeNote 4 – Divestiture for additional details on the sale. Total consideration received for the sale of the Appalachia Properties of $522.5 million included cash consideration of $512.5 million received at closing and a $10.0 million indemnity escrow which was released subsequent to emergence from bankruptcy (seeReorganization Adjustments item number 2 below).

(b) Reflects the movement of $75.0 million of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the provisions of the Amended Credit Agreement (as defined inNote 13 – Debt), and $0.5 million held in a restricted cash account for certain cure amounts in connection with the Chapter 11 proceedings.

(c) Other fees and expenses include approximately $15.2 million of emergence and success fees, $2.7 million of professional fees and $2.4 million of payments made to seismic providers in settlement of their bankruptcy claims.

2. Reflects a receivable for a $10.0 million indemnity escrow with release delayed until emergence from bankruptcy, net of a $0.7 million reimbursement to Tug Hill in connection with the sale of the Appalachia Properties (seeNote 4 – Divestiture).

3. Reflects the payment of a claim to a seismic provider as a prepayment/deposit.

4. Reflects the sale of vehicles in connection with the sale of the Appalachia Properties.

5. Reflects the write-off of $2.6 million of unamortized debt issuance costs related to the Pre-Emergence Credit Agreement and the reversal of a $1.8 million prepayment made to Tug Hill in October 2016.

6. Reflects the accrual of $2.0 million in expected bonus payments under the KEIP (as defined inNote 15 – Employee Benefit Plans) and a $0.4 million termination fee in connection with the early termination of an office lease, less the settlement of a property tax accrual of $2.6 million in connection with the sale of the Appalachia Properties.

7. Reflects the repayment of $341.5 million of outstanding borrowings under the Pre-Emergence Credit Agreement and the issuance of $225 million of 2022 Second Lien Notes as part of the settlement of the Predecessor Company 2017 Convertible Notes and 2022 Notes.

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8. Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):

1 3⁄4% Senior Convertible Notes due 2017	$	300,000
7 1⁄2% Senior Notes due 2022		775,000
Accrued interest		35,182
Liabilities subject to compromise of the Predecessor Company		1,110,182
Cash payment to senior noteholders		(100,000	)
Issuance of 2022 Second Lien Notes to former holders of the senior notes		(225,000	)
Fair value of equity issued to unsecured creditors		(539,089	)
Fair value of warrants issued to unsecured creditors		(15,648	)
Gain on settlement of liabilities subject to compromise	$	230,445

9. Reflects the cancellation of the Predecessor Company’s common stock, treasury stock and additional paid-in capital.

10. Reflects the issuance of Successor Company equity. In accordance with the Plan, the Successor Company issued 19.0 million shares of New Common Stock to the former holders of the 2017 Convertible Notes and the 2022 Notes and 1.0 million shares of New Common Stock to the Predecessor Company’s common stockholders. These amounts are subject to dilution by warrants issued to the Predecessor Company common stockholders, totaling approximately 3.5 million shares, with an exercise price of $42.04 per share and a term of four years. The fair value of the warrants was estimated at $4.43 per share using a Black-Scholes-Merton valuation model.

11. Reflects the cumulative impact of the reorganization adjustments discussed above (in thousands):

Gain on settlement of liabilities subject to compromise	$	230,445
Professional and other fees paid at emergence		(10,648	)
Write-off of unamortized debt issuance costs		(2,577	)
Other reorganization adjustments		(1,915	)
Net impact to reorganization items		215,305
Gain on sale of Appalachia Properties		213,453
Cancellation of Predecessor Company equity		1,662,282
Other adjustments to accumulated deficit		(17,165	)
Net impact to accumulated deficit	$	2,073,875

Fresh Start Adjustments

12. Fair value adjustments to oil and gas properties, associated inventory and unproved acreage. See above for a detailed discussion of the fair value methodology.

13. Fair value adjustment for an office building owned by the Company. The income and sales comparison approaches were used in determining the fair value, using anticipated future earnings and an appropriate expected rate of return, as well as relying upon recent sales or offerings of similar assets.

14. Fair value adjustments to the Company’s asset retirement obligations using estimated plugging and abandonment costs as of the Effective Date, adjusted for inflation and discounted at the Successor Company’s credit-adjusted risk free rate.

15. Reflects the cumulative effect of the fresh start accounting adjustments discussed above.

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Reorganization Items

Reorganization items represent liabilities settled, net of amounts incurred subsequent to the Chapter 11 filing as a direct result of the Plan and are classified as “Reorganization items, net” in the Company’s consolidated statement of operations. The following table summarizes reorganization items, net (in thousands):

	Predecessor
	Period from January 1, 2017 through February 28, 2017
Gain on settlement of liabilities subject to compromise	$	230,445
Fresh start valuation adjustments		235,804
Reorganization professional fees and other expenses		(20,403	)
Write-off of unamortized debt issuance costs		(2,577	)
Other reorganization items		(5,525	)
Gain on reorganization items, net	$	437,744

The cash payments for reorganization items for the period from January 1, 2017 through February 28, 2017 include approximately $10.6 million of emergence and success fees and approximately $8.9 million of other reorganization professional fees and expenses paid on the Effective Date.

NOTE 4 — DIVESTITURE

On February 27, 2017, we completed the sale of the Appalachia Properties to EQT for net cash consideration of approximately $522.5 million, representing gross proceeds of $527.0 million adjusted downward by approximately $4.5 million for purchase price adjustments for operations related to the Appalachia Properties after June 1, 2016, the effective date of the transaction. A portion of the consideration received from the sale of the Appalachia Properties was used to fund the Company’s cash payment obligations under the Plan. SeeNote 2 – Reorganization.

At December 31, 2016, the estimated proved oil and natural gas reserves associated with these assets totaled 18 MMBoe (million barrels of oil equivalent), which represented approximately 34% of the Predecessor Company’s total estimated proved oil and natural gas reserves, on a volume equivalent basis. We no longer have assets or operations in Appalachia. Since accounting for the sale of these oil and gas properties as a reduction of the capitalized costs of oil and gas properties would have significantly altered the relationship between capitalized costs and proved reserves, we recognized a gain on the sale of $213.5 million during the period from January 1, 2017 through February 28, 2017 (Predecessor). The gain on the sale of the Appalachia Properties is computed as follows (in thousands):

Net consideration received for sale of Appalachia Properties	$	522,472
Add: Release of funds held in suspense		4,139
Transfer of asset retirement obligations		8,672
Other adjustments, net		2,597
Less: Transaction costs		(7,087	)
Carrying value of properties sold		(317,340	)
Gain on sale	$	213,453

The carrying value of the properties sold was determined by allocating total capitalized costs within the U.S. full cost pool between properties sold and properties retained based on their relative fair values.

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NOTE 5 — STOCKHOLDERS’ EQUITY

Common Stock

As discussed inNote 2 – Reorganization, upon emergence from bankruptcy, all existing shares of Predecessor common stock were cancelled, and the Successor Company issued an aggregate of 20.0 million shares of New Common Stock, par value $0.01 per share, to the Predecessor Company’s existing common stockholders and holders of the 2017 Convertible Notes and the 2022 Notes pursuant to the Plan.

Warrants

As discussed inNote 2 – Reorganization, the Predecessor Company’s existing common stockholders received warrants to purchase approximately 3.5 million shares of New Common Stock. The warrants have an exercise price of $42.04 per share and a term of four years, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company. The Company allocated $15.6 million of the enterprise value to the warrants which is reflected in “Successor additional paid-in capital” on the audited consolidated balance sheet at December 31, 2017 (Successor).

NOTE 6 — EARNINGS PER SHARE

On February 28, 2017, upon emergence from Chapter 11 bankruptcy, the Company’s Predecessor equity was cancelled and new equity was issued. Additionally, the Predecessor Company’s 2017 Convertible Notes were cancelled. SeeNote 2 – Reorganization andNote 5 – Stockholders’ Equity for further details.

The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods (in thousands, except per share amounts):

	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
							2016			2015
Income (numerator):
Basic:
Net income (loss)	$	(247,639	)	$	630,317		$	(590,586	)	$	(1,090,915	)
Net income attributable to participating securities		—			(4,995	)		—			—
Net income (loss) attributable to common stock - basic	$	(247,639	)	$	625,322		$	(590,586	)	$	(1,090,915	)
Diluted:
Net income (loss)	$	(247,639	)	$	630,317		$	(590,586	)	$	(1,090,915	)
Net income attributable to participating securities		—			(4,995	)		—			—
Net income (loss) attributable to common stock - diluted	$	(247,639	)	$	625,322		$	(590,586	)	$	(1,090,915	)
Weighted average shares (denominator):
Weighted average shares - basic		19,997			5,634			5,591			5,525
Dilutive effect of stock options		—			—			—			—
Dilutive effect of warrants		—			—			—			—
Dilutive effect of convertible notes		—			—			—			—
Weighted average shares - diluted		19,997			5,634			5,591			5,525
Basic income (loss) per share	$	(12.38	)	$	110.99		$	(105.63	)	$	(197.45	)
Diluted income (loss) per share	$	(12.38	)	$	110.99		$	(105.63	)	$	(197.45	)

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All outstanding stock options were considered antidilutive during the period from January 1, 2017 through February 28, 2017 (Predecessor) (10,400 shares) because the exercise price of the options exceeded the average price of our common stock for the applicable period. During the years ended December 31, 2016 (Predecessor) (12,900 shares) and December 31, 2015 (Predecessor) (14,400 shares) all outstanding stock options were considered antidilutive because we had net losses for such years. On February 28, 2017, upon emergence from bankruptcy, all outstanding stock options were cancelled. SeeNote 16 – Share-Based Compensation.

On February 28, 2017, upon emergence from bankruptcy, the Predecessor Company’s existing common stockholders received warrants to purchase common stock of the Successor Company. SeeNote 2 – Reorganization. For the period of March 1, 2017 through December 31, 2017 (Successor), all outstanding warrants (approximately 3.5 million) were considered antidilutive because we had a net loss for such period.

The Predecessor Company had no outstanding restricted stock units. The board of directors of the Successor Company (the “Board”) received grants of restricted stock units on March 1, 2017. SeeNote 16 – Share-Based Compensation.For the period from March 1, 2017 through December 31, 2017 (Successor), all outstanding restricted stock units (62,137) were considered antidilutive because we had a net loss for such period.

For the period from January 1, 2017 through February 28, 2017 (Predecessor), the average price of our common stock was less than the effective conversion price for the 2017 Convertible Notes, resulting in no dilutive effect on the diluted earnings per share computation for such period. For the years ended December 31, 2016 and 2015 (Predecessor), the 2017 Convertible Notes had no dilutive effect on the diluted earnings per share computation as we had net losses for such years. On February 28, 2017, upon emergence from bankruptcy, the 2017 Convertible Notes were cancelled. SeeNote 2 – Reorganization.

During the period from March 1, 2017 through December 31, 2017 (Successor), 1,195 shares of common stock of the Successor Company were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock for employees. During the period from January 1, 2017 through February 28, 2017 (Predecessor) and the years ended December 31, 2016 and 2015 (Predecessor), 47,390, 79,621 and 41,375 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock and granting of stock awards for employees and nonemployee directors.

NOTE 7 — ACCOUNTS RECEIVABLE

In our capacity as operator for our co-venturers, we incur drilling and other costs that we bill to the respective parties based on their working interests. We also receive payments for these billings and, in some cases, for billings in advance of incurring costs. Our accounts receivable are comprised of the following amounts (in thousands):

	Successor		Predecessor
	As of December 31, 2017		As of December 31, 2016
Other co-venturers	$	2,656	$	3,532
Trade		34,980		42,944
Unbilled accounts receivable		820		591
Other		802		1,397
Total accounts receivable	$	39,258	$	48,464

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NOTE 8 — CONCENTRATIONS

Sales to Major Customers

Our production is sold on month-to-month contracts at prevailing prices. We obtain credit protections, such as parental guarantees, from certain of our purchasers. The following table identifies customers from whom we derived 10% or more of our total oil and natural gas revenue during the indicated periods:

	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
							2016			2015
Phillips 66 Company		74	%		56	%		68	%		53	%
Shell Trading (US) Company		15	%		7	%		10	%		13	%
Williams Ohio Valley Midstream LLC		—	%		12	%		2	%		9	%
Conoco		—	%		11	%		5	%		2	%

The maximum amount of credit risk exposure at December 31, 2017 (Successor) relating to these customers was $30.5 million.

We believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to market future oil and natural gas production.

Production and Reserve Volumes – Unaudited

All of our estimated proved reserve volumes at December 31, 2017 (Successor) and approximately 88% of our production during 2017 were associated with our GOM deep water, conventional shelf and deep gas properties. We closed the sale of the Appalachia Properties on February 27, 2017 and no longer have assets or operations in Appalachia (see Note 4 – Divestiture).

Cash and Cash Equivalents

A substantial portion of our cash balances are not federally insured.

NOTE 9 — DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Our hedging strategy is designed to protect our near and intermediate term cash flows from future declines in oil and natural gas prices. This protection is essential to capital budget planning, which is sensitive to expenditures that must be committed to in advance, such as rig contracts and the purchase of tubular goods. We enter into derivative transactions to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. We do not enter into derivative transactions for trading purposes.

All derivatives are recognized as assets or liabilities on the balance sheet and are measured at fair value. At the end of each quarterly period, these derivatives are marked-to-market. If the derivative does not qualify or is not designated as a cash flow hedge, subsequent changes in the fair value of the derivative are recognized in earnings through derivative income (expense) in the statement of operations. If the derivative qualifies and is designated as a cash flow hedge, subsequent changes in the fair value of the derivative are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Monthly settlements of effective cash flow hedges are reflected in revenue from oil and natural gas production. Monthly settlements of ineffective hedges and derivatives not designated or that do not qualify for hedge accounting are recognized in earnings through derivative income (expense). The resulting cash flows from all monthly settlements are reported as cash flows from operating activities.

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Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. A small portion of our cash flow hedges were typically determined to be ineffective because oil and natural gas price changes in the markets in which we sell our products were not 100% correlative to changes in the underlying price basis indicative in the derivative contract. We had no outstanding derivatives at December 31, 2016. With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements of these derivative contracts will be recorded in earnings through derivative income (expense).

We have entered into put contracts, fixed-price swaps and collar contracts with various counterparties for a portion of our expected 2018 and 2019 oil and natural gas production from the Gulf Coast Basin. All of our derivative transactions have been carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative instruments involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The counterparties to all of our derivative instruments have an “investment grade” credit rating. We monitor the credit ratings of our derivative counterparties on an ongoing basis. Although we typically enter into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, we may not realize the benefit of some of our derivative instruments and incur a loss. At March 9, 2018, our derivative instruments were with four counterparties, two of which accounted for approximately 64% of our contracted volumes. Currently, all of our outstanding derivative instruments are with lenders under our current bank credit facility.

Put contracts are purchased at a rate per unit of hedged production that fluctuates with the commodity futures market. The historical cost of the put contract represents our maximum cash exposure. We are not obligated to make any further payments under the put contract regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if the New York Mercantile Exchange (“NYMEX”) prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above the floor. Swaps typically provide for monthly payments by us if prices rise above the swap price or monthly payments to us if prices fall below the swap price. Collar contracts typically require payments by us if the NYMEX average closing price is above the ceiling price or payments to us if the NYMEX average closing price is below the floor price. Settlements for our oil put contracts, oil collar contracts and fixed-price oil swaps are based on an average of the NYMEX closing price for West Texas Intermediate crude oil during the entire calendar month. Settlements for our natural gas collar contracts and fixed-price natural gas swaps are based on the NYMEX price for the last day of a respective contract month.

The following tables illustrate our derivative positions for calendar years 2018 and 2019 as of March 9, 2018:

		Put Contracts (NYMEX)
		Oil
		Daily Volume (Bbls/d)		Price ($ per Bbl)
2018	January - December		1,000	$	54.00
2018	January - December		1,000		45.00

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		Fixed-Price Swaps (NYMEX)
		Oil
		Daily Volume (Bbls/d)		Swap Price ($ per Bbl)
2018	January - December		1,000	$	52.50
2018	January - December		1,000		51.98
2018	January - December		1,000		53.67
2019	January - December		1,000		51.00
2019	January - December		1,000		51.57
2019	January - December		2,000		56.13

		Collar Contracts (NYMEX)
		Natural Gas						Oil
		Daily Volume (MMBtus/d)		Floor Price ($ per MMBtu)		Ceiling Price ($ per MMBtu)		Daily Volume (Bbls/d)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)
2018	January - December		6,000	$	2.75	$	3.24		1,000	$	45.00	$	55.35

Derivatives not designated or not qualifying as hedging instruments

The following table discloses the location and fair value amounts of derivatives not designated or not qualifying as hedging instruments, as reported in our balance sheet, at December 31, 2017 (Successor) (in thousands). We had no outstanding hedging instruments at December 31, 2016 (Predecessor).

Fair Value of Derivatives Not Designated or Not Qualifying as Hedging Instruments at

December 31, 2017

(Successor)

	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	879	Current liabilities: Fair value of derivative contracts	$	8,969
	Long-term assets: Fair value of derivative contracts		—	Long-term liabilities: Fair value of derivative contracts		3,085
		$	879		$	12,054

Gains or losses related to changes in fair value and cash settlements for derivatives not designated or not qualifying as hedging instruments are recorded as derivative income (expense) in the statement of operations.

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The following table discloses the before tax effect of our derivatives not designated or not qualifying as hedging instruments on the statement of operations for the indicated periods (in thousands):

Gain (Loss) Recognized in Derivative Income (Expense)

	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended
Description							December 31, 2016		December 31, 2015
Commodity contracts:
Cash settlements	$	2,161		$	—		$	—	$	17,385
Change in fair value		(15,549	)		(1,778	)		—		(12,146	)
Total gains (losses) on derivatives not designated or not qualifying as hedging instruments	$	(13,388	)	$	(1,778	)	$	—	$	5,239

Derivatives qualifying as hedging instruments

None of our derivative contracts outstanding as of December 31, 2017 (Successor) were designated as accounting hedges. We had no outstanding derivatives at December 31, 2016 (Predecessor). During 2016 and 2015, we had outstanding derivatives that were designated and qualified as hedging instruments. The following table discloses the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the years ended December 31, 2016 and 2015 (Predecessor) (in thousands):

Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations

for the Years Ended December 31, 2016 and 2015

(Predecessor)

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives			Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion)(a)			Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
				Location			Location
	2016				2016			2016
Commodity contracts	$	(1,648	)	Operating revenue - oil/natural gas production	$	35,457	Derivative income (expense), net	$	(810	)
Total	$	(1,648	)		$	35,457		$	(810	)
	2015				2015			2015
Commodity contracts	$	52,630		Operating revenue - oil/natural gas production	$	149,955	Derivative income (expense), net	$	2,713
Total	$	52,630			$	149,955		$	2,713

(a) For the year ended December 31, 2016, effective hedging contracts increased oil revenue by $23,747 and increased natural gas revenue by $11,710. For the year ended December 31, 2015, effective hedging contracts increased oil revenue by $135,617 and increased natural gas revenue by $14,338.

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Offsetting of derivative assets and liabilities

Our derivative contracts are subject to netting arrangements. It is our policy to not offset our derivative contracts in presenting the fair value of these contracts as assets and liabilities in our balance sheet. The following table presents the potential impact of the offset rights associated with our recognized assets and liabilities at December 31, 2017 (Successor) (in thousands):

	As Presented Without Netting			Effects of Netting			With Effects of Netting
Current assets: Fair value of derivative contracts	$	879		$	(879	)	$	—
Long-term assets: Fair value of derivative contracts		—			—			—
Current liabilities: Fair value of derivative contracts		(8,969	)		879			(8,090	)
Long-term liabilities: Fair value of derivative contracts		(3,085	)		—			(3,085	)

We had no outstanding derivative contracts at December 31, 2016 (Predecessor).

NOTE 10 — FAIR VALUE MEASUREMENTS

U.S. GAAP establishes a fair value hierarchy that has three levels based on the reliability of the inputs used to determine the fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

As of December 31, 2017 (Successor) and 2016 (Predecessor), we held certain financial assets that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. The income approach is used in this determination utilizing the third party’s proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy, and our collar and put contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars and puts are the volatility impacts in the pricing model as it relates to the call portion of the collar and the floor of the put. For a more detailed description of our derivative instruments, seeNote 9 – Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.

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The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2017 (Successor) (in thousands):

	Fair Value Measurements Successor as of December 31, 2017
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	5,081	$	5,081	$	—	$	—
Derivative contracts		879		—		—		879
Total	$	5,960	$	5,081	$	—	$	879

	Fair Value Measurements Successor as of December 31, 2017
Liabilities	Total		Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative contracts	$	12,054	$	—	$	10,110	$	1,944
Total	$	12,054	$	—	$	10,110	$	1,944

We had no liabilities measured at fair value on a recurring basis at December 31, 2016. The following table presents our assets that are measured at fair value on a recurring basis at December 31, 2016 (Predecessor) (in thousands):

	Fair Value Measurements Predecessor as of December 31, 2016
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	8,746	$	8,746	$	—	$	—
Total	$	8,746	$	8,746	$	—	$	—

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The table below presents a reconciliation for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the period from March 1, 2017 through December 31, 2017 (Successor) and the period from January 1, 2017 through February 28, 2017 (Predecessor) (in thousands):

	Hedging Contracts, net
	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017
Beginning balance	$	3,087		$	—
Total gains/(losses) (realized or unrealized):
Included in earnings		(5,201	)		(649	)
Included in other comprehensive income		—			—
Purchases, sales, issuances and settlements		1,049			3,736
Transfers in and out of Level 3		—			—
Ending balance	$	(1,065	)	$	3,087
The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at December 31, 2017	$	(4,699	)

The fair value of cash and cash equivalents approximated book value at December 31, 2017 and 2016. Upon emergence from bankruptcy on February 28, 2017, the 2017 Convertible Notes and 2022 Notes were cancelled, and the Company issued the 2022 Second Lien Notes. As of December 31, 2016, the fair value of the liability component of the 2017 Convertible Notes was approximately $293.5 million. As of December 31, 2016, the fair value of the 2022 Notes was approximately $465.0 million. As of December 31, 2017, the fair value of the 2022 Second Lien Notes was approximately $227.3 million.

The fair values of the 2022 Notes and the 2022 Second Lien Notes were determined based on quotes obtained from brokers, which represent Level 1 inputs. We applied fair value concepts in determining the liability component of the 2017 Convertible Notes at inception and at December 31, 2016. The fair value of the liability was estimated using an income approach. The significant inputs in these determinations were market interest rates based on quotes obtained from brokers and represent Level 2 inputs.

On February 28, 2017, the Company emerged from bankruptcy and adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh start reporting date, February 28, 2017. SeeNote 3 – Fresh Start Accounting for a detailed discussion of the fair value approaches used by the Company. The inputs utilized in the valuation of our most significant asset, our oil and gas properties, included mostly unobservable inputs, which fall within Level 3 of the fair value hierarchy.

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NOTE 11 — ASSET RETIREMENT OBLIGATIONS

Upon emergence from bankruptcy, as discussed inNote 3 – Fresh Start Accounting, the Company adopted fresh start accounting which included the adjustment of asset retirement obligations to estimated fair values at February 28, 2017. The following table presents the change in our asset retirement obligations during the indicated periods (in thousands, inclusive of current portion):

	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
							2016			2015
Beginning balance	$	290,067		$	242,019		$	225,866		$	316,409
Liabilities incurred		2,280			—			2,338			15,933
Liabilities settled		(81,197	)		(3,641	)		(19,630	)		(72,713	)
Divestment of properties		—			(8,672	)		—			(248	)
Accretion expense		21,151			5,447			40,229			25,988
Revision of estimates		(19,200	)		—			(6,784	)		(59,503	)
Fair value fresh start adjustment		—			54,914			—			—
Asset retirement obligations, end of period	$	213,101		$	290,067		$	242,019		$	225,866

NOTE 12 — INCOME TAXES

An analysis of our deferred taxes follows (in thousands):

	Successor			Predecessor
	As of December 31, 2017			As of December 31, 2016
Tax effect of temporary differences:
Net operating loss carryforwards	$	66,304		$	201,557
Oil and gas properties		12,035			85,772
Asset retirement obligations		44,751			85,312
Stock compensation		278			3,294
Derivatives		3,110			—
Accrued incentive compensation		2,269			954
Debt issuance costs		644			7,480
Other		1,600			441
Total deferred tax assets (liabilities)		130,991			384,810
Valuation allowance		(130,991	)		(384,810	)
Net deferred tax assets (liabilities)	$	—		$	—

Upon our emergence from bankruptcy, pursuant to the terms of the Plan, a substantial portion of the Company’s pre-petition debt was extinguished (seeNote 2 – Reorganization). For tax purposes, absent an exception, a debtor recognizes cancellation of indebtedness income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The IRC provides that a debtor in a bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. After consideration of the market value of the Company’s equity

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upon emergence from Chapter 11 bankruptcy proceedings, the estimated amount of U.S. CODI is approximately $257 million, which will reduce the value of the Company’s U.S. net operating losses. The actual reduction in tax attributes does not occur until the first day of the Company’s tax year subsequent to the date of emergence, or January 1, 2018. The estimated results of the attribute reduction have been reflected in the Company’s ending balance of deferred tax assets for the year ended December 31, 2017 (Successor). The Successor Company also has various state net operating loss carryforwards that are subject to reduction as a result of the CODI being excluded from taxable income, however, subsequent to the sale of the Appalachia Properties, our state income tax exposure is not expected to be material.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). Generally effective for tax years 2018 and beyond, the Tax Act makes broad and complex changes to the IRC, including, but not limited to, (i) reducing the U.S. federal corporate tax rate from 35% to 21%; (ii) eliminating the corporate alternative minimum tax (“AMT”) and changing how existing AMT credits are realized; (iii) creating a new limitation on deductible interest expense; and (iv) changing rules related to uses and limitation of net operating loss carryforwards created in tax years beginning after December 31, 2017. As of December 31, 2017, we have not completed our accounting for the tax effects of enactment of the Tax Act. However, we have made a reasonable estimate of the effects on our existing deferred tax balances and recognized a provisional amount of $87.3 million to remeasure our deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. This amount is included as a component of income tax expense (benefit) from continuing operations and is fully offset by the related adjustment to our valuation allowance. We are still analyzing certain aspects of the Tax Act and refining our calculations, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts.

We estimate that we had ($18.3) million and $3.6 million, respectively, of current federal income tax expense (benefit) for the periods of March 1, 2017 through December 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor). For the years ended December 31, 2016 and 2015 (Predecessor) we had ($5.7) million and ($44.1) million, respectively, of current federal income tax (benefits). There was no deferred income tax expense (benefit) recorded for the periods of March 1, 2017 through December 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor). For the years ended December 31, 2016 and 2015 (Predecessor), we recorded a deferred income tax expense (benefit) of $13.1 million and ($272.3) million, respectively. The deferred income tax benefit in 2015 was a result of our losses before income taxes attributable primarily to ceiling test write-downs of our oil and gas properties (seeNote 22 – Supplemental Information on Oil and Natural Gas Operations – Unaudited). We had current income tax receivables of $36.3 million and $26.1 million at December 31, 2017 (Successor) and 2016 (Predecessor), respectively, both of which related to expected tax refunds from the carryback of net operating losses to previous tax years. We received $20.6 million of the tax refund subsequent to December 31, 2017.

For tax reporting purposes, our net operating loss carryforwards totaled approximately $315.7 million at December 31, 2017 (net of the aforementioned CODI reduction). If not utilized, such carryforwards would begin to expire in 2035 and would fully expire in 2036. Additionally, IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future U.S. taxable income in the event of a change in ownership. The Company’s emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of IRC Section 382. Accordingly, we estimate that approximately $127 million of our net operating loss carryforwards will be subject to the annual IRC Section 382 limitation, with the remaining $189 million of net operating loss carryforwards being unlimited.

In addition, we had approximately $1.2 million in statutory depletion deductions available for tax reporting purposes that may be carried forward indefinitely. Recognition of a deferred tax asset associated with these and other carryforwards is dependent upon our evaluation that it is more likely than not that the asset will ultimately be realized. As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined during 2015 that it was more likely than not that a portion of our deferred

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tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. As of December 31, 2017 (Successor), our valuation allowance totaled $131.0 million. Our assessment of the realizability of our deferred tax assets is based on the weight of all available evidence, both positive and negative, including future reversals of deferred tax liabilities.

The following table provides a reconciliation of the statutory federal income tax rate to the Company’s effective income tax rate as a percentage of income before income taxes for the indicated periods:

	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
							2016			2015
Income tax expense computed at the statutory federal income tax rate		35.0	%		35.0	%		35.0	%		35.0	%
Tax Act rate change		(32.8	)		—			—			—
State taxes		(0.7	)		0.3			0.2			0.6
Change in valuation allowance		5.3			(37.8	)		(35.0	)		(12.8	)
IRC Sec. 162(m) limitation		0.4			—			(0.3	)		(0.1	)
Tax deficits on stock compensation		(0.6	)		0.6			(0.7	)		(0.1	)
Reorganization fees		0.3			2.5			(0.3	)		—
Other		—			—			(0.2	)		(0.1	)
Effective income tax rate		6.9	%		0.6	%		(1.3	)%		22.5	%

There were no income taxes allocated to accumulated other comprehensive income for the periods of March 1, 2017 through December 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor). Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges amounted to ($13.1) million, ($35.7) million for the years ended December 31, 2016 and 2015 (Predecessor), respectively.

As of December 31, 2017 (Successor), we had unrecognized tax benefits of $491 thousand. If recognized, all of our unrecognized tax benefits would impact our effective tax rate. A reconciliation of the total amounts of unrecognized tax benefits follows (in thousands):

	Successor		Predecessor
	Period from March 1, 2017 through December 31, 2017		Period from January 1, 2017 through February 28, 2017
Total unrecognized tax benefits, beginning balance	$	491	$	491
Increases (decreases) in unrecognized tax benefits as a result of:
Tax positions taken during a prior period		—		—
Tax positions taken during the current period		—		—
Settlements with taxing authorities		—		—
Lapse of applicable statute of limitations		—		—
Total unrecognized tax benefits, ending balance	$	491	$	491

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Our unrecognized tax benefits pertain to a proposed state income tax audit adjustment. We believe that our unrecognized tax benefits may be reduced to zero within the next 12 months upon completion and ultimate settlement of the examination.

It is our policy to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expenses, respectively. We recognized $33 thousand and $7 thousand, respectively, of interest expense and no penalties related to uncertain tax positions for the periods of March 1, 2017 through December 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor). We recognized $46 thousand of interest expense and no penalties related to uncertain tax positions for the year ended December 31, 2016 (Predecessor). We recognized $131 thousand of interest expense and no penalties related to uncertain tax positions for the year ended December 31, 2015 (Predecessor). The liabilities for unrecognized tax benefits and accrued interest payable are components of other current liabilities on our balance sheet.

The tax years 2014 through 2017 remain subject to examination by major tax jurisdictions.

NOTE 13 — DEBT

Our debt balances (net of related unamortized discounts and debt issuance costs) as of December 31, 2017 and 2016 were as follows (in thousands):

	Successor			Predecessor
	December 31, 2017			December 31, 2016
7 1⁄2% Senior Second Lien Notes due 2022	$	225,000		$	—
1 3⁄4% Senior Convertible Notes due 2017		—			300,000
7 1⁄2% Senior Notes due 2022		—			775,000
Predecessor revolving credit facility		—			341,500
4.20% Building Loan		10,927			11,284
Total debt	$	235,927		$	1,427,784
Less: current portion of long-term debt		(425	)		(408	)
Less: liabilities subject to compromise		—			(1,075,000	)
Long-term debt	$	235,502		$	352,376

Reorganization

On December 14, 2016, the Debtors filed Bankruptcy Petitions seeking relief under Chapter 11 of the Bankruptcy Code to pursue a prepackaged plan of reorganization. The 2017 Convertible Notes and 2022 Notes were impacted by the Chapter 11 process and were classified in the accompanying consolidated balance sheet at December 31, 2016 as liabilities subject to compromise under the provisions of ASC 852, “Reorganizations”. On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan, and on February 28, 2017, the Plan became effective and the Debtors emerged from bankruptcy. Upon emergence from bankruptcy, pursuant to the terms of the Plan, the Predecessor Company’s 2017 Convertible Notes and 2022 Notes were cancelled, the Predecessor Company’s Pre-Emergence Credit Agreement was amended and restated, and the Company issued the 2022 Second Lien Notes.

Current Portion of Long-Term Debt

As of December 31, 2017 (Successor), the current portion of long-term debt of $0.4 million represented principal payments due within one year on the 4.20% Building Loan (the “Building Loan”).

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Reclassification of Debt

The face values of the 2017 Convertible Notes of $300 million and the 2022 Notes of $775 million were reclassified as liabilities subject to compromise in the accompanying consolidated balance sheet at December 31, 2016 (Predecessor). SeeNote 1 – Organization and Summary of Significant Accounting Policies.

Successor Revolving Credit Facility

On the Effective Date, pursuant to the terms of the Plan, the Company entered into the Fifth Amended and Restated Credit Agreement with the lenders party thereto and Bank of America, N.A. (as amended from time to time, the “Amended Credit Agreement”), as administrative agent and issuing lender, which amended and replaced the Company’s Pre-Emergence Credit Agreement. The Amended Credit Agreement provides for a reserve-based revolving credit facility and matures on February 28, 2021.

The Company’s available borrowings under the Amended Credit Agreement were initially set at $150 million until the first borrowing base redetermination in November 2017. On November 8, 2017, the borrowing base under the Amended Credit Agreement was redetermined to $100 million. On December 31, 2017, the Company had no outstanding borrowings and $12.6 million of outstanding letters of credit, leaving $87.4 million of availability under the Amended Credit Agreement. Interest on loans under the Amended Credit Agreement is calculated using the London Interbank Offering Rate (“LIBOR”) or the base rate, at the election of the Company, plus, in each case, an applicable margin. The applicable margin is determined based on borrowing base utilization and ranges from 2.00% to 3.00% per annum for base rate loans and 3.00% to 4.00% per annum for LIBOR loans.

The borrowing base under the Amended Credit Agreement is redetermined semi-annually, in May and November, by the lenders, in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times each in any calendar year, to have the borrowing base redetermined. Subject to certain exceptions, the Amended Credit Agreement is required to be guaranteed by all of the material domestic direct and indirect subsidiaries of the Company. As of December 31, 2017, the Amended Credit Agreement is guaranteed by Stone Offshore. The Amended Credit Agreement is secured by substantially all of the Company’s and its subsidiaries’ assets.

The Amended Credit Agreement provides for customary optional and mandatory prepayments, affirmative and negative covenants and events of default, including limitations on the incurrence of debt, liens, restrictive agreements, mergers, asset sales, dividends, investments, affiliate transactions and restrictions on commodity hedging. During the continuance of certain events of default, the lenders may take a number of actions, including declaring the entire amount then outstanding under the Amended Credit Agreement due and payable (in the event of certain insolvency-related events, the entire amount then outstanding under the Amended Credit Agreement will become automatically due and payable). The Amended Credit Agreement also requires maintenance of certain financial covenants, including (i) a consolidated funded debt to EBITDA ratio of not more than 2.75x for the test period ending March 31, 2017, 2.50x for the test period ending June 30, 2017, 3.00x for the test period ending September 30, 2017, 2.75x for the test period ending December 31, 2017, 2.50x for the test periods ending March 31, 2018, June 30, 2018, September 30, 2018 and December 31, 2018, respectively, 2.75x for the test period ending March 31, 2019, 3.00x for the test period ending June 30, 2019, 3.50x for the test periods ending September 30, 2019 and December 31, 2019, respectively, 3.00x for the test period ending March 31, 2020, 2.75x for the test periods ending June 30, 2020 and September 30, 2020, respectively, and 2.50x for the test periods ending December 31, 2020 and March 31, 2021, respectively, (ii) a consolidated interest coverage ratio of not less than 2.75 to 1.00, and (iii) a requirement to maintain minimum liquidity of at least 20% of the borrowing base. We were in compliance with all covenants under the Amended Credit Agreement as of December 31, 2017.

Predecessor Revolving Credit Facility

On June 24, 2014, the Predecessor Company entered into the Pre-Emergence Credit Agreement with the lenders party thereto and Bank of America, N.A., as administrative agent and issuing lender, with commitments

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totaling $900 million (subject to borrowing base limitations). The borrowing base under the Pre-Emergence Credit Agreement prior to its amendment and restatement as the Amended Credit Agreement was $150 million. Interest on loans under the Pre-Emergence Credit Agreement was calculated using the LIBOR rate or the base rate, at our election. The margin for loans at the LIBOR rate was determined based on borrowing base utilization and ranged from 1.500% to 2.500%.

Prior to emergence from bankruptcy, the Predecessor Company had $341.5 million of outstanding borrowings and $12.5 million of outstanding letters of credit under the Pre-Emergence Credit Agreement. At emergence, the outstanding borrowings were paid in full and the $12.5 million of outstanding letters of credit were converted to obligations under the Amended Credit Agreement.

Building Loan

On November 20, 2015, we entered into an approximately $11.8 million term loan agreement, the Building Loan, maturing on November 20, 2030. There were no changes to the terms of the Building Loan pursuant to the Plan. 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 $73,000 commencing on December 20, 2015. As of December 31, 2017, the outstanding balance under the Building Loan totaled $10.9 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 were in compliance with all covenants under the Building Loan as of December 31, 2017.

Successor 2022 Second Lien Notes

On the Effective Date, pursuant to the terms of the Plan, the Successor Company entered into an indenture by and among the Company, Stone Offshore, as guarantor (the “Guarantor”), and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (the “2022 Second Lien Notes Indenture”), and issued $225 million of the Company’s 2022 Second Lien Notes pursuant thereto.

Interest on the 2022 Second Lien Notes accrues at a rate of 7.50% per annum payable semi-annually in arrears on May 31 and November 30 of each year in cash, beginning November 30, 2017. At December 31, 2017, $1.4 million had been accrued in connection with the May 31, 2018 interest payment. The 2022 Second Lien Notes are secured on a second lien priority basis by the same collateral that secures the Amended Credit Agreement, including the Company’s oil and natural gas properties, and are guaranteed by the Guarantor. The 2022 Second Lien Notes mature on May 31, 2022. Pursuant to the terms of the Intercreditor Agreement (as defined below), the security interest in those assets that secure the 2022 Second Lien Notes and the related guarantee are contractually subordinated to liens thereon that secure the Company’s Amended Credit Agreement and certain other permitted obligations as set forth in the 2022 Second Lien Notes Indenture. Consequently, the 2022 Second Lien Notes and the related guarantee are effectively subordinated to the Amended Credit Agreement and such other permitted secured indebtedness to the extent of the value of such assets.

At any time prior to May 31, 2020, the Company may, at its option, on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2022 Second Lien Notes issued under the 2022 Second Lien Notes Indenture at a redemption price of 107.5% of the principal amount of the 2022 Second Lien Notes, plus accrued and unpaid interest to the redemption date, with an amount of cash equal to the net cash proceeds of certain equity offerings; provided that at least 65% of the aggregate principal amount of the 2022 Second Lien Notes as of the Effective Date remains outstanding after each such redemption. On or after May 31, 2020, the Company may redeem all or part of the 2022 Second Lien Notes at redemption prices (expressed as percentages of the principal amount) equal to (i) 105.625% for the twelve-month period beginning on May 31, 2020;

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(ii) 105.625% for the twelve-month period beginning on May 31, 2021; and (iii) 100.000% for the twelve-month period beginning on May 31, 2022 and at any time thereafter, in each case, plus accrued and unpaid interest at the redemption date. In addition, at any time prior to May 31, 2020, the Company may redeem all or a part of the 2022 Second Lien Notes at a redemption price equal to 100% of the principal amount of the 2022 Second Lien Notes to be redeemed plus a make-whole premium, plus accrued and unpaid interest to the redemption date.

The 2022 Second Lien Notes Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt and issue preferred stock; (ii) make payments or distributions on account of the Company’s or its restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of the Company’s restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates, and (vii) merge or consolidate with another company. These covenants are subject to a number of important exceptions and qualifications. At any time when the 2022 Second Lien Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc., and no Default (as defined in the 2022 Second Lien Notes Indenture) has occurred and is continuing, many of these covenants will terminate.

The 2022 Second Lien Notes Indenture also provides for certain events of default. In the case of an event of default arising from certain events of bankruptcy, insolvency or reorganization with respect to the Company or any of the Company’s restricted subsidiaries that is a significant subsidiary, or any group of the Company’s restricted subsidiaries that, taken as a whole, would constitute a significant subsidiary of the Company, all outstanding 2022 Second Lien Notes will become due and immediately payable without further action or notice. If any other event of default occurs and is continuing, the trustee of the 2022 Second Lien Notes or the holders of at least 25% in aggregate principal amount of the then outstanding 2022 Second Lien Notes may declare all the 2022 Second Lien Notes to be due and payable immediately.

Intercreditor Agreement

On the Effective Date, Bank of America, N.A., as priority lien agent, The Bank of New York Mellon Trust Company, N.A., as second lien collateral agent, and The Bank of New York Mellon Trust Company, N.A., as the 2022 Second Lien Notes trustee, entered into an intercreditor agreement, which was acknowledged and agreed to by the Company and the Guarantor (the “Intercreditor Agreement”) to govern the relationship of holders of the 2022 Second Lien Notes, the lenders under the Amended Credit Agreement and holders of other priority lien obligations, with respect to collateral and certain other matters.

Predecessor Senior Notes

2017 Convertible Notes.On March 6, 2012, the Predecessor Company issued in a private offering $300 million in aggregate principal amount of the 2017 Convertible Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended. The 2017 Convertible Notes were convertible into cash, shares of our common stock or a combination of cash and shares of our common stock, based on an initial conversion rate of 23.4449 shares of our common stock per $1,000 principal amount of 2017 Convertible Notes, which corresponded to an initial conversion price of approximately $42.65 per share of our common stock at the time of the issuance of the 2017 Convertible Notes. On June 10, 2016, we completed a1-for-10 reverse stock split with respect to our common stock and proportional adjustments were made to the conversion price and shares as they relate to the 2017 Convertible Notes, resulting in a conversion rate of 2.34449 shares of our common stock with a corresponding conversion price of $426.50 per share.

The 2017 Convertible Notes were due on March 1, 2017. Upon emergence from bankruptcy on February 28, 2017, pursuant to the Plan, the $300 million of debt related to the 2017 Convertible Notes was cancelled. SeeNote 2 – Reorganization for additional details.

During the year ended December 31, 2016 (Predecessor), we recognized $15.4 million of interest expense for the amortization of the discount and $1.5 million of interest expense for the amortization of debt issuance

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costs related to the 2017 Convertible Notes. During the year ended December 31, 2015 (Predecessor), we recognized $15.0 million of interest expense for the amortization of the discount and $1.4 million of interest expense for the amortization of debt issuance costs related to the 2017 Convertible Notes.

2022 Notes.On November 8, 2012 and November 27, 2013, respectively, the Predecessor Company completed the public offering of $300 million and $475 million aggregate principal amount of the 2022 Notes.The 2022 Notes were scheduled to mature on November 15, 2022. Upon emergence from bankruptcy, pursuant to the Plan, the $775 million of debt related to the 2022 Notes was cancelled. SeeNote 2 – Reorganization for additional details.

Deferred Financing Cost and Interest Cost

In accordance with the provisions of ASC 852, we recognized a charge of approximately $8.3 million to write-off the remaining unamortized debt issuance costs, discounts and premiums related to the 2017 Convertible Notes and 2022 Notes, which is included in reorganization items in the accompanying consolidated statement of operations for the year ended December 31, 2016 (Predecessor). Additionally, we recognized a charge of approximately $2.6 million to write-off the remaining unamortized debt issuance costs related to the Pre-Emergence Credit Agreement as of the Petition Date, which is included in reorganization items in the consolidated statement of operations during the period from January 1, 2017 through February 28, 2017 (Predecessor). SeeNote 1 – Organization and Summary of Significant Accounting Policies and Note 3 – Fresh Start Accounting for additional details.

At December 31, 2017 (Successor) and December 31, 2016 (Predecessor), approximately $59 thousand and $63 thousand, respectively, of unamortized debt issuance costs were deducted from the carrying amount of the Building Loan. At December 31, 2016 (Predecessor), approximately $2.8 million of debt issuance costs related to the Pre-Emergence Credit Agreement were classified as other assets.

Prior to the filing of the Bankruptcy Petitions, the costs associated with the 2017 Convertible Notes were being amortized over the life of the notes using a method that applied an effective interest rate of 7.51%. The costs associated with the November 2012 issuance and November 2013 issuance of the 2022 Notes were being amortized over the life of the notes using a method that applied effective interest rates of 7.75% and 7.04%, respectively. The costs associated with the Pre-Emergence Credit Agreement were being amortized on a straight-line basis over the term of the facility. The costs associated with the issuance of the Building Loan are being amortized using the effective interest method over the term of the Building Loan.

Total interest cost incurred, before capitalization, on all obligations for the period from March 1, 2017 through December 31, 2017 (Successor) was $15.7 million. Total interest cost incurred, before capitalization, on all obligations for the years ended December 31, 2016 and 2015 (Predecessor) was $91.1 million and $85.3 million, respectively. In accordance with the accounting guidance in ASC 852, we accrued interest on the 2017 Convertible Notes and 2022 Notes only up to the Petition Date, and such amounts were included as liabilities subject to compromise in our consolidated balance sheet at December 31, 2016 (Predecessor). Accordingly, there was no interest expense recognized on the 2017 Convertible Notes or the 2022 Notes after the Bankruptcy Petitions were filed.

NOTE 14 — ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts, and accordingly, changes in the fair value of the derivative were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. We had no outstanding derivative contracts at December 31, 2016.

During the periods from March 1, 2017 through December 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor), we entered into various commodity derivative contracts (seeNote 9 –

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Derivative Instruments and Hedging Activities). With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements of these derivative contracts will be recorded in earnings through derivative income (expense).

During the year ended December 31, 2016, we reclassified a $6.1 million loss related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the liquidation of our former foreign subsidiary, Stone Energy Canada, ULC.

The following tables include the changes in accumulated other comprehensive income (loss) by component for the years ended December 31, 2016 and 2015 (Predecessor) (in thousands):

	Cash Flow Hedges			Foreign Currency Items			Total
For the Year Ended December 31, 2016 (Predecessor)
Beginning balance, net of tax	$	24,025		$	(6,073	)	$	17,952
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		(1,648	)		—			(1,648	)
Foreign currency translations		—			(8	)		(8	)
Income tax effect		581			—			581
Net of tax		(1,067	)		(8	)		(1,075	)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production		35,457			—			35,457
Other operational expenses		—			(6,081	)		(6,081	)
Income tax effect		(12,499	)		—			(12,499	)
Net of tax		22,958			(6,081	)		16,877
Other comprehensive income (loss), net of tax		(24,025	)		6,073			(17,952	)
Ending balance, net of tax	$	—		$	—		$	—

	Cash Flow Hedges			Foreign Currency Items			Total
For the Year Ended December 31, 2015 (Predecessor)
Beginning balance, net of tax	$	86,783		$	(3,468	)	$	83,315
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		52,630			—			52,630
Foreign currency translations		—			(2,605	)		(2,605	)
Income tax effect		(19,096	)		—			(19,096	)
Net of tax		33,534			(2,605	)		30,929
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production		149,955			—			149,955
Derivative income, net		1,170			—			1,170
Income tax effect		(54,833	)		—			(54,833	)
Net of tax		96,292			—			96,292
Other comprehensive loss, net of tax		(62,758	)		(2,605	)		(65,363	)
Ending balance, net of tax	$	24,025		$	(6,073	)	$	17,952

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NOTE 15 — EMPLOYEE BENEFIT PLANS

We entered into deferred compensation and disability agreements with certain of our former officers. The benefits under the deferred compensation agreements vested after certain periods of employment, and at December 31, 2017 (Successor), the liability for such vested benefits was approximately $0.9 million and is recorded in current and other long-term liabilities. The deferred compensation plan is described further below.

The following is a brief description of each incentive compensation plan applicable to our employees:

Annual Incentive Cash Compensation Plans

In 2016, we replaced our historical long-term cash and equity-based incentive compensation programs with the 2016 Performance Incentive Compensation Plan (the “2016 Annual Incentive Plan”), pursuant to which incentive cash bonuses were calculated based on the achievement of certain strategic objectives for each quarter of 2016. On July 25, 2017, the Board approved the Stone Energy Corporation 2017 Annual Incentive Compensation Plan (the “2017 Annual Incentive Plan”) for all salaried employees (other than the interim chief executive officer) of the Company. The 2017 Annual Incentive Plan is a performance-based short-term cash incentive program that provides award opportunities based on the Company’s annual performance in certain performance measures as defined by the Board. The 2017 Annual Incentive Plan replaced the Company’s Amended and Restated Revised Annual Incentive Compensation Plan, which was adopted in November 2007, and the 2016 Annual Incentive Plan.

For the period from March 1, 2017 through December 31, 2017 (Successor), Stone incurred expenses of $7.0 million, net of amounts capitalized, related to incentive compensation cash bonuses. Stone incurred expenses of $13.5 million and $2.2 million, net of amounts capitalized, for each of the years ended December 31, 2016 and 2015 (Predecessor), respectively, related to incentive compensation cash bonuses. These charges are reflected in incentive compensation expense on the statement of operations.

Key Executive Incentive Plan

Pursuant to the terms of the Executive Claims Settlement Agreement, the Company’s executives agreed to waive their claims related to the Company’s 2016 Annual Incentive Plan, and in exchange therefor, the Company adopted the Stone Energy Corporation Key Executive Incentive Plan (“KEIP”), in which the Company’s executives were allowed to participate. Payments to the Company’s executives under the KEIP were limited to $2.0 million, or the equivalent of the target bonus under the 2016 Annual Incentive Plan for the fourth quarter of 2016. The KEIP payments of $2.0 million are reflected in incentive compensation expense on the statement of operations for the period from January 1, 2017 through February 28, 2017 (Predecessor).

Retention Award Agreement

On July 25, 2017, the Board approved retention awards and the form of Stone Energy Corporation Retention Award Agreement (the “Retention Award Agreement”) and authorized the Company to enter into Retention Award Agreements with certain executive officers and employees of the Company. The Retention Award Agreement provides for a retention award to certain individuals to be paid in a lump sum cash payment within 30 days of the earliest to occur of (i) the first anniversary (June 1, 2018) of the effective date of the Retention Award Agreement, subject to the individual remaining employed by the Company or a subsidiary of the Company on such date, (ii) a change in control of the Company or (iii) a termination of the individual’s employment with the Company (a) due to death, (b) by the Company without “cause” or (c) by the individual for “good reason.” We recognized a charge of $1.0 million for the period from March 1, 2017 through December 31, 2017 (Successor), representing a prorated portion of estimated retention awards through December 31, 2017. This charge is reflected in incentive compensation expense on the statement of operations.

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Transaction Bonus Agreement

On November 21, 2017, the Board approved transaction bonuses and the form of Stone Energy Corporation Transaction Bonus Agreement (the “Transaction Bonus Agreement”) and authorized the Company to enter into Transaction Bonus Agreements with certain of our executive officers and other employees of the Company. The Transaction Bonus Agreements provide for a lump sum cash payment within 30 days of a “change in control” (as defined in the Transaction Bonus Agreement) if the individual remains employed with the Company through the date of the “change in control” or is terminated prior to the change in control (i) due to death, (ii) by the Company without “cause” (as defined below) (including due to disability), or (iii) by the individual for “good reason” (as defined in the Transaction Bonus Agreement). The Transaction Bonus Agreements were entered into in connection with the Talos combination.

2017 Long-Term Incentive Plan

On the Effective Date, pursuant to the Plan, the Stone Energy Corporation 2017 Long-Term Incentive Plan (the “2017 LTIP”) became effective, replacing the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (As Amended and Restated December 17, 2015). The types of awards that may be granted under the 2017 LTIP include stock options, restricted stock, restricted stock units, dividend equivalents and other forms of awards granted or denominated in shares of New Common Stock, as well as certain cash-based awards. The maximum number of shares of New Common Stock that may be issued or transferred pursuant to awards under the 2017 LTIP is 2,614,379. As of March 9, 2018, other than the grant of 62,137 restricted stock units to the Board (seeNote 16 – Share-Based Compensation), there have been no other issuances or awards of stock under the 2017 LTIP.

401(k) and Deferred Compensation Plans

The Stone Energy 401(k) Profit Sharing Plan provides eligible employees with the option to defer receipt of a portion of their compensation and we may, at our discretion, match a portion or all of the employee’s deferral. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each employee. An employee is 20% vested in matching contributions (if any) for each year of service and is fully vested upon five years of service. For the period from March 1, 2017 through December 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor), Stone contributed $0.6 million and $0.3 million, respectively, to the plan. For the years ended December 31, 2016 and 2015 (Predecessor), Stone contributed $1.2 million and $1.6 million, respectively, to the plan.

The Stone Energy Corporation Deferred Compensation Plan (the “Deferred Compensation Plan”) provides eligible executives and employees with the option to defer up to 100% of their eligible compensation for a calendar year. Historically, we could, at our discretion, match a portion or all of the participant’s deferral based upon a percentage determined by our Board. In 2016, the compensation committee of the Predecessor board adopted an amendment to the Deferred Compensation Plan that removed our ability to make matching contributions under such plan. Our Board may still elect to make discretionary profit sharing contributions to the plan. To date, there have been no matching or discretionary profit sharing contributions made by Stone under the Deferred Compensation Plan. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each participant. At December 31, 2017 (Successor) and December 31, 2016 (Predecessor), plan assets of $5.1 million and $8.7 million, respectively, were included in other assets. An equal amount of plan liabilities were included in other long-term liabilities.

Change of Control and Severance Plans

On July 25, 2017, the Board approved the Stone Energy Corporation Executive Severance Plan (the “Executive Severance Plan”), which provides for the payment of severance and change in control benefits to the executive officers (other than the interim chief executive officer) of the Company. The Executive Severance Plan

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replaced the Stone Energy Corporation Executive Severance Plan dated December 13, 2016. Pursuant to the Executive Severance Plan, if a covered executive officer is terminated (i) by the Company without “cause” or (ii) by the executive officer for “good reason” (each, an “Involuntary Termination”), the executive officer will receive (i) a lump sum cash payment in an amount equal to 1.0x or 1.5x the executive officer’s annual base salary, (ii) a lump sum cash payment equal to 100% of the executive officer’s annual bonus opportunity, at target, prorated by the number of days that have elapsed from January 1 of that calendar year, (iii) six months of health benefit continuation for the executive officer and the executive officer’s dependents, at a cost to the participant that is equal to the cost for an active employee for similar coverage, (iv) accelerated vesting of any outstanding and unvested equity awards, (v) certain outplacement services and (vi) any unpaid portion of the executive officer’s annual pay as of the date of the Involuntary Termination. The Executive Severance Plan was amended on November 21, 2017 in connection with the proposed Talos combination to provide, among other things, that if a participant in the plan experiences a qualifying termination of employment during the twelve month period following Closing, such participant’s target bonus will be no less than such participant’s target bonus for the 2017 calendar year.

On July 25, 2017, the Board approved the Stone Energy Corporation Employee Severance Plan (the “2017 Employee Severance Plan”). The 2017 Employee Severance Plan covers all full-time employees other than officers. Severance is triggered by an involuntary termination of employment on and during the twelve-month period following a change of control. Employees who are terminated within the scope of the 2017 Employee Severance Plan will be entitled to certain payments and benefits including the following: (i) a lump sum equal to (1) weekly pay times full years of service, plus (2) one week’s pay for each full $10 thousand of annual pay, but the sum of (1) and (2) cannot be less than 12 weeks of pay or greater than 52 weeks of pay, (ii) continued health plan coverage for 6 months at a cost to the participant that is equal to the cost for an active employee for similar coverage, (iii) a prorated portion of the employee’s targeted bonus for the year, and (iv) reasonable outplacement services consistent with current HR practices. The 2017 Employee Severance Plan was amended on November 21, 2017 in connection with the proposed Talos combination to provide, among other things, that if a participant in the plan experiences a qualifying termination of employment during the twelve month period following Closing, such participant’s target bonus will be no less than such participant’s target bonus for the 2017 calendar year. The 2017 Employee Severance Plan replaced the Stone Energy Corporation Employee Change of Control Severance Plan, dated December 7, 2007.

NOTE 16 — SHARE-BASED COMPENSATION

On the Effective Date, pursuant to the Plan, the 2017 LTIP became effective. As discussed inNote 15 – Employee Benefit Plans, the types of awards that may be granted under the 2017 LTIP include stock options, restricted stock, restricted stock units, dividend equivalents and other forms of awards granted or denominated in shares of New Common Stock, as well as certain cash-based awards.

We record share-based compensation expense for share-based compensation awards based on the fair value on the date of grant. Compensation expense for share-based compensation awards is recognized in our statement of operations on a straight-line basis over the vesting period of the award. Under the full cost method of accounting, we capitalize a portion of employee and general and administrative costs (including share-based compensation). Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at net cash provided by operating activities in our statement of cash flows. The capitalized portion is not included in net cash used in investing activities.

Under U.S. GAAP, if tax deductions exceed book compensation expense, then excess tax benefits are credited to additional paid-in capital to the extent realized. If book compensation expense exceeds tax deductions, the tax deficit results in either a reduction in additional paid-in capital and/or an increase in income tax expense, depending on the pool of available excess tax benefits to offset such deficit. There were no adjustments to additional paid-in capital related to the net tax effect of stock option exercises and restricted stock vesting in 2017, 2016 or 2015. During the period from March 1, 2017 through December 31, 2017 (Successor),

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the period from January 1, 2017 through February 28, 2017 (Predecessor) and the years ended December 31, 2016 and 2015 (Predecessor), respectively, $2.5 million, $2.7 million, $4.1 million and $1.3 million of tax deficits were charged to income tax expense.

Predecessor Share-Based Compensation

For the period from January 1, 2017 through February 28, 2017 (Predecessor), we incurred $3.5 million of share-based compensation expense, all of which related to stock awards and restricted stock issuances, and of which a total of approximately $0.9 million was capitalized into oil and gas properties. For the year ended December 31, 2016 (Predecessor), we incurred $11.6 million of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately $3.1 million was capitalized into oil and gas properties. For the year ended December 31, 2015 (Predecessor), we incurred $17.9 million of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately $5.6 million was capitalized into oil and gas properties.

Stock Options. All outstanding stock options at December 31, 2016 related to executive share-based awards that were cancelled upon emergence from bankruptcy. There were no stock option grants during the period from January 1, 2017 through February 28, 2017. The following tables include Predecessor Company stock option activity during the years ended December 31, 2016 and 2015:

	Year Ended December 31, 2016 (Predecessor)
	Number of Options			Wgtd. Avg. Exercise Price		Wgtd. Avg. Term		Aggregate Intrinsic Value
Options outstanding, beginning of period		14,447		$	269.25
Granted		—			—
Exercised		—			—
Forfeited		—			—
Expired		(1,500	)		477.45
Options outstanding, end of period		12,947			245.13		1.4 years	$	—
Options exercisable, end of period		12,947			245.13		1.4 years		—
Options unvested, end of period		—			—		—		—

	Year Ended December 31, 2015 (Predecessor)
	Number of Options			Wgtd. Avg. Exercise Price		Wgtd. Avg. Term		Aggregate Intrinsic Value
Options outstanding, beginning of period		20,497		$	339.36
Granted		—			—
Exercised		—			—
Forfeited		—			—
Expired		(6,050	)		506.76
Options outstanding, end of period		14,447			269.25		2.1 years	$	—
Options exercisable, end of period		14,447			269.25		2.1 years		—
Options unvested, end of period		—			—		—		—

Restricted Stock and Other Stock Awards.Immediately prior to emergence, the vesting of all Predecessor outstanding, unvested share-based awards for non-executive employees was accelerated and, as a result, all

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unrecognized compensation cost related to such awards was recognized. Upon emergence from bankruptcy, all Predecessor outstanding, unvested restricted shares held by the Company’s executives were cancelled and exchanged for a proportionate share of the 5% of New Common Stock, plus a proportionate share of the warrants for ownership of up to 15% of the Successor Company’s common equity. Vesting continued in accordance with the applicable vesting provisions of the original awards (seeSuccessor Share-Based Compensation below).

During the period from January 1, 2017 through February 28, 2017, 10,404 shares (valued at $69 thousand) of Predecessor Company stock were issued, representing grants of stock to the board of directors of the Predecessor Company. During the years ended December 31, 2016 and 2015, we issued 31,313 shares (valued at $0.3 million) and 141,872 shares (valued at $23.7 million), respectively, of Predecessor Company restricted stock or stock awards.

The following table includes Predecessor Company restricted stock and stock award activity during the period from January 1, 2017 through February 28, 2017 and the years ended December 31, 2016 and 2015:

	Predecessor
	Period from January 1, 2017 through February 28, 2017					Year Ended December 31,
						2016					2015
	Number of Restricted Shares			Wgtd. Avg. Fair Value Per Share		Number of Restricted Shares			Wgtd. Avg. Fair Value Per Share		Number of Restricted Shares			Wgtd. Avg. Fair Value Per Share
Restricted stock outstanding, beginning of period		81,090		$	205.34		180,239		$	208.17		129,848		$	299.45
Issuances		10,404			6.67		31,313			8.93		141,872			167.21
Lapse of restrictions or granting of stock awards		(73,276	)		186.37		(117,406	)		158.79		(63,745	)		296.00
Forfeitures		(194	)		169.40		(13,056	)		200.06		(27,736	)		223.80
Restricted stock outstanding, end of period		18,024		$	169.42		81,090		$	205.34		180,239		$	208.17

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Successor Share-Based Compensation

Restricted Stock and Other Stock Awards.As discussed above, upon emergence from bankruptcy, all Predecessor outstanding, unvested restricted shares held by the Company’s executives were cancelled and exchanged for proportionate shares of New Common Stock. Vesting continued in accordance with the applicable vesting provisions of the original awards, with remaining compensation expense based on the fresh start fair value of $26.95 per share (seeNote 3 – Fresh Start Accounting).For the period from March 1, 2017 through December 31, 2017 (Successor), we incurred approximately $0.1 million of share-based compensation expense related to these restricted shares. The restricted stock outstanding on December 31, 2017 became fully vested on January 15, 2018. The following table includes Successor Company restricted stock and stock award activity during the period from March 1, 2017 through December 31, 2017:

	Period from March 1, 2017 through December 31, 2017
	Number of Restricted Shares			Wgtd. Avg. Fair Value Per Share
Restricted stock outstanding at February 28, 2017 (Predecessor)		18,024		$	169.42
Restricted stock outstanding at March 1, 2017 (Successor)		3,176		$	26.95
Issuances		—			—
Lapse of restrictions		(2,083	)		21.78
Forfeitures		—			—
Restricted stock outstanding at December 31, 2017 (Successor)		1,093		$	26.95

Restricted Stock Units. On March 1, 2017, the Board received grants of restricted stock units under the 2017 LTIP. The restricted stock units are scheduled to vest in full on the day prior to the annual meeting of the Company’s stockholders in May 2018, subject to: (i) the director’s continued service on the board through thevesting date, and (ii) earlier vesting upon the occurrence of a change of control event or the termination of thedirector’s service due to death or removal from the board without cause. A total of 62,137 restricted stock units were granted with an aggregate grant date fair value of $1.7 million, based on a per share grant date fair value of $26.95. During the period from March 1, 2017 through December 31, 2017 (Successor), we incurred approximately $1.2 million of share-based compensation expense related to these restricted stock units. As of December 31, 2017, there was $0.5 million of unrecognized compensation cost related to such restricted stock units, with a current weighted average remaining vesting period of approximately four months.

NOTE 17 — REDUCTION IN WORKFORCE

During the second quarter of 2017, we implemented workforce reduction plans to better align our employee base with current business needs, resulting in a reduction of approximately 20% of our total workforce. The workforce reductions were complete as of July 31, 2017. In connection with the reductions, we recognized a charge of $5.7 million, consisting primarily of severance payments to affected employees and payment of related employer payroll taxes. This charge is reflected in SG&A expenses on the statement of operations for the period from March 1, 2017 through December 31, 2017 (Successor).

In addition to the workforce reduction costs, during the second quarter of 2017, we recognized a charge of $3.0 million for severance costs related to the sale of the Appalachia Properties and the retirement of the prior chief executive officer of the Company. These severance costs are reflected in SG&A expenses on the statement of operations for the period from March 1, 2017 through December 31, 2017 (Successor).

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NOTE 18 — FEDERAL ROYALTY RECOVERY

In July 2017, we received a federal royalty recovery totaling $14.1 million as part of a multi-year federal royalty refund claim. Approximately $9.6 million of the refund was recognized as other operational income and $4.5 million as a reduction of lease operating expenses during the period from March 1, 2017 through December 31, 2017 (Successor). Included in SG&A expenses for the period from March 1, 2017 through December 31, 2017 (Successor) is a $3.9 million success-based consulting fee incurred in connection with the federal royalty recovery.

NOTE 19 — OTHER OPERATIONAL EXPENSES

Other operational expenses for the period of March 1, 2017 through December 31, 2017 (Successor) of $3.4 million included approximately $2.1 million of stacking charges for the Pompano platform rig. For the year ended December 31, 2016 (Predecessor), other operational expenses of $55.5 million included approximately $17.7 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, an Appalachian drilling rig and the platform rig at Pompano, a $20.0 million charge related to the termination of our deep water drilling rig contract with Ensco and $9.9 million in charges related to the terminations of offshore vessel and Appalachian drilling rig contracts. Also included in other operational expenses for the year ended December 31, 2016 (Predecessor) is a $6.1 million loss on the liquidation of our former foreign subsidiary, Stone Energy Canada, ULC, representing cumulative foreign currency translation adjustments, which were reclassified from accumulated other comprehensive income. SeeNote 14 – Accumulated Other Comprehensive Income (Loss).

NOTE 20 — COMBINATION TRANSACTION COSTS

In connection with the pending combination with Talos, we have incurred approximately $6.2 million in transaction costs, consisting primarily of legal and financial advisor costs. These costs are included in SG&A expense on our statement of operations for the period from March 1, 2017 through December 31, 2017 (Successor). Additionally, we have incurred approximately $0.2 million of direct costs for purposes of registering equity securities to effect the Talos combination. These direct costs are recorded as a reduction of additional paid-in-capital during the period from March 1, 2017 through December 31, 2017 (Successor). SeeNote 1 – Organization and Summary of Significant Accounting Policies for more information on the pending combination.

NOTE 21 — COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.

Leases

We lease office facilities in Lafayette and New Orleans, Louisiana under the terms of non-cancelable leases expiring on various dates in 2018. We also lease certain equipment on our oil and gas properties typically on a month-to-month basis. The minimum net commitment for 2018 under our leases, subleases and contracts at December 31, 2017 totaled $0.3 million.

Payments related to our lease obligations were $0.5 million for the period from March 1, 2017 through December 31, 2017 (Successor) and $0.1 million for the period of January 1, 2017 through February 28, 2017 (Predecessor). Payments related to our lease obligations for the years ended December 31, 2016 and 2015 (Predecessor) were approximately $0.7 million and $3.1 million, respectively.

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Other Commitments and Contingencies

On March 21, 2016, we received notice letters from the Bureau of Ocean Energy Management (“BOEM”) stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at such time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM towards finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately $115 million in surety bonds in favor of BOEM, third-party bonds, and letters of credit, all relating to our offshore abandonment obligations.

In July 2016, BOEM issued a Notice to Lessees (the “NTL”), with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurances by offshore lessees. The NTL details procedures to determine a lessee’s ability to carry out its lease obligations (primarily the decommissioning of OCS facilities) and whether to require lessees to furnish additional financial assurances to meet BOEM’s estimate of the lessees decommissioning obligations. The NTL supersedes the agency’s prior practice of allowing operators of a certain net worth to waive the need for supplemental bonds and provides updated criteria for determining a lessee’s ability to self-insure only a small portion of its OCS liabilities based upon the lessee’s financial capacity and financial strength. The NTL also allows lessees to meet their additional financial security requirements pursuant to an individually approved tailored plan, whereby an operator and BOEM agree to set a timeframe for the posting of additional financial assurances.

We received a self-insurance letter from BOEM dated September 30, 2016 stating that we were not eligible to self-insure any of our additional security obligations. We received a proposal letter from BOEM dated October 20, 2016 indicating that additional security may be required. The September 30, 2016 self-insurance determination letter was rescinded by BOEM on March 24, 2017.

In the first quarter of 2017, BOEM announced that it would extend the implementation timeline for the July 2016 NTL by an additional six months. Furthermore, on April 28, 2017, President Trump issued an executive order directing the Secretary of the Interior to review the NTL to determine whether modifications are necessary to ensure operator compliance with lease terms while minimizing unnecessary regulatory burdens. On June 22, 2017, BOEM announced that, pending its review of the NTL, the implementation timeline would be indefinitely extended, subject to certain exceptions. At this time, it is uncertain when, or if, the July 2016 NTL will be implemented or whether a revised NTL might be proposed. A revised tailored plan may require incremental financial assurance or bonding for non-sole liability properties, dependent on adjustments following ongoing discussions with BOEM and the Bureau of Safety and Environmental Enforcement, and any modifications to the proposed NTL. There is no assurance that our current tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan.

In connection with our exploration and development efforts, we are contractually committed to the acquisition of seismic data in the amount of $8.6 million to be incurred over the next two years.

The Oil Pollution Act (“OPA”) imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under the OPA and a final rule adopted by BOEM in August 1998, responsible parties of covered offshore facilities that have a worst case oil spill of more than 1,000 barrels must demonstrate financial responsibility in amounts ranging from at least $10 million in specified state waters to at least $35 million in Outer Continental Shelf waters, with higher amounts of up to $150 million in certain limited circumstances where BOEM believes such a level is justified by the risks posed by the operations, or if the worst case oil-spill discharge volume possible at the facility may exceed the applicable threshold volumes specified under BOEM’s final rule. In addition, BOEM has finalized rules that raise OPA’s damages liability cap from $75 million to $133.7 million.

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NOTE 22 — SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS – UNAUDITED

At December 31, 2017 and 2016, our oil and gas properties were located in the United States (onshore and offshore). On February 27, 2017, we completed the sale of the Appalachia Properties in connection with our restructuring (seeNote 4 – Divestiture). During 2015, we discontinued our business development effort in Canada.

With the adoption of fresh start accounting, the Company recorded its oil and gas properties at fair value as of February 28, 2017. The Company’s proved, probable and possible reserves and unevaluated properties (including inventory) were assigned values of $380.8 million, $16.8 million and $80.2 million, respectively. SeeNote 3 – Fresh Start Accounting for a discussion of the valuation approach used.

Costs Incurred

United States. The following table discloses the total amount of capitalized costs and accumulated DD&A relative to our proved and unevaluated oil and natural gas properties located in the United States (in thousands):

	Successor			Predecessor
	December 31, 2017			December 31, 2016
Proved properties	$	713,157		$	9,572,082
Unevaluated properties		102,187			373,720
Total proved and unevaluated properties		815,344			9,945,802
Less accumulated depreciation, depletion and amortization		(353,462	)		(9,134,288	)
Balance, end of year	$	461,882		$	811,514

The following table sets forth certain information regarding the costs incurred in our acquisition, exploratory and development activities in the United States during the periods indicated (in thousands):

	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
							2016			2015
Costs incurred during the period (capitalized):
Acquisition costs, net of sales of unevaluated properties	$	(8,371	)	$	(324	)	$	3,923		$	(14,158	)
Exploratory costs		12,079			2,055			17,891			104,169
Development costs(1)		33,356			12,547			102,665			266,982
Salaries, general and administrative costs		7,495			2,976			21,753			27,984
Interest		3,927			2,524			26,634			41,339
Less: overhead reimbursements		(1,004	)		—			(521	)		(913	)
Total costs incurred during the period, net of divestitures	$	47,482		$	19,778		$	172,345		$	425,403

(1) Includes net changes in capitalized asset retirement costs of ($17,446), $0, ($4,461) and ($43,901), respectively.

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The following table discloses operational expenses incurred during the periods indicated relative to our oil and natural gas producing activities located in the United States (in thousands):

	Successor		Predecessor
	Period from March 1, 2017 through December 31, 2017		Period from January 1, 2017 through February 28, 2017		Year Ended December 31,
					2016		2015
Lease operating expenses	$	49,800	$	8,820	$	79,650	$	100,139
Transportation, processing and gathering expenses		4,084		6,933		27,760		58,847
Production taxes		629		682		3,148		6,877
Accretion expense		21,151		5,447		40,229		25,988
Expensed costs – United States	$	75,664	$	21,882	$	150,787	$	191,851

The following table sets forth certain information relative to the amortization of our investment in oil and gas properties and the impairment of our oil and gas properties in the United States for the periods indicated (in thousands, except per unit amounts):

	Successor		Predecessor
	Period from March 1, 2017 through December 31, 2017		Period from January 1, 2017 through February 28, 2017		Year Ended December 31,
					2016		2015
Provision for DD&A	$	97,027	$	36,751	$	215,737	$	277,088
Write-down of oil and gas properties	$	256,435	$	—	$	357,079	$	1,314,817
DD&A per Boe	$	16.61	$	17.05	$	16.10	$	19.15

At March 31, 2017 (Successor), our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $256.4 million based on twelve-month average prices, net of applicable differentials, of $45.40 per Bbl of oil, $2.24 per Mcf of natural gas and $19.18 per Bbl of NGLs. The write-down at March 31, 2017 is reflected in the statement of operations of the Successor Company for the period from March 1, 2017 through December 31, 2017 and was primarily due to differences between the trailing twelve-month average pricing assumption used in calculating the ceiling test and the forward prices used in fresh start accounting to estimate the fair value of our oil and gas properties on the fresh start reporting date of February 28, 2017. Weighted average commodity prices used in the determination of the fair value of our oil and gas properties for purposes of fresh start accounting were $56.01 per Bbl of oil, $2.52 per Mcf of natural gas and $14.18 per Bbl of NGLs, net of applicable differentials.

Since none of our derivatives as of March 31, 2017 were designated as cash flow hedges (seeNote 9 – Derivative Instruments and Hedging Activities), the write-down at March 31, 2017 was not affected by hedging. The 2016 and 2015 write-downs were decreased by $50.7 million and $143.9 million, respectively, as a result of hedges.

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The following table discloses net costs incurred (evaluated) on our unevaluated properties located in the United States for the periods indicated (in thousands):

	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
							2016			2015
Net costs incurred (evaluated) during period:
Acquisition costs	$	(9,155	)	$	959		$	(71,378	)	$	(115,767	)
Exploration costs		10,405			(6,063	)		(21,579	)		(16,315	)
Capitalized interest		3,927			2,524			26,634			41,339
	$	5,177		$	(2,580	)	$	(66,323	)	$	(90,743	)

Under fresh start accounting, our oil and gas properties were recorded at fair value as of February 28, 2017. The following table discloses financial data associated with unevaluated costs (United States) for the Successor Company at December 31, 2017 (in thousands):

	Successor		Net Costs Incurred During the Period from March 1, 2017 through December 31, 2017			Successor
	March 1, 2017					December 31, 2017
Acquisition costs	$	58,359	$	(9,155	)	$	49,204
Exploration costs		38,651		10,405			49,056
Capitalized interest		—		3,927			3,927
Total unevaluated costs	$	97,010	$	5,177		$	102,187

Approximately 34 specifically identified drilling projects are included in unevaluated costs at December 31, 2017 and are expected to be evaluated in the next four years. The excluded costs will be included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined.

Canada. During 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. Upon a more complete evaluation of this project and in response to the significant decline in commodity prices, we discontinued our business development effort in Canada during 2015 and recognized a full impairment of our Canadian oil and gas properties. The following table discloses certain financial data relative to our oil and gas activities located in Canada (in thousands):

	Predecessor
	Year Ended December 31,
	2016			2015
Oil and gas properties – Canada:
Balance, beginning of year	$	42,484		$	36,579
Costs incurred during the year (capitalized):
Acquisition costs		(498	)		(2,862	)
Exploratory costs		2,168			8,767
Total costs incurred during the year		1,670			5,905
Balance, end of year (fully evaluated at December 31, 2016 and 2015)	$	44,154		$	42,484

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	Predecessor
	Year Ended December 31,
	2016			2015
Accumulated DD&A:
Balance, beginning of year	$	(42,484	)	$	—
Foreign currency translation adjustment		(1,318	)		5,146
Write-down of oil and gas properties		(352	)		(47,630	)
Balance, end of year	$	(44,154	)	$	(42,484	)
Net capitalized costs – Canada	$	—		$	—

Proved Oil and Natural Gas Quantities

Our estimated net proved oil and natural gas reserves at December 31, 2017 have been prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”). Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective dates. There are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the market value of the oil and gas properties or the cost that would be incurred to obtain equivalent reserves.

The following table sets forth an analysis of the estimated quantities of net proved oil (including condensate), natural gas and NGL reserves, all of which are located onshore and offshore the continental United States. Estimated proved oil, natural gas and NGL reserves are prepared in accordance with the SEC’s rule, “Modernization of Oil and Gas Reporting,” using a historical twelve-month average pricing assumption.

	Oil (MBbls)			NGLs (MBbls)			Natural Gas (MMcf)			Oil, Natural Gas and NGLs (MBoe)
Estimated proved developed and undeveloped reserves:
As of December 31, 2014 (Predecessor)		42,397			27,817			493,843			152,520
Revisions of previous estimates		(6,818	)		(20,777	)		(362,102	)		(87,945	)
Extensions, discoveries and other additions		862			11			1,499			1,123
Purchase of producing properties		685			1,808			26,136			6,849
Sale of reserves		(859	)		—			(1,061	)		(1,036	)
Production		(5,991	)		(2,401	)		(36,457	)		(14,468	)
As of December 31, 2015 (Predecessor)		30,276			6,458			121,858			57,043
Revisions of previous estimates		(751	)		6,352			24,858			9,744
Extensions, discoveries and other additions		63			2			45			73
Production		(6,308	)		(2,183	)		(29,441	)		(13,398	)
As of December 31, 2016 (Predecessor)		23,280			10,629			117,320			53,462
Revisions of previous estimates		730			(2	)		1,242			935
Sale of reserves		(826	)		(7,417	)		(52,992	)		(17,075	)
Production		(908	)		(408	)		(5,037	)		(2,156	)
As of February 28, 2017 (Predecessor)		22,276			2,802			60,533			35,166
Revisions of previous estimates		3,769			(94	)		(2,801	)		3,208
Production		(4,169	)		(403	)		(7,616	)		(5,841	)
As of December 31, 2017 (Successor)		21,876			2,305			50,116			32,533

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	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Oil, Natural Gas and NGLs (MBoe)
Estimated proved developed reserves:
As of December 31, 2015 (Predecessor)		21,734		4,784		90,262		41,562
As of December 31, 2016 (Predecessor)		18,269		9,255		90,741		42,647
As of February 28, 2017 (Predecessor)		18,344		1,515		35,865		25,836
As of December 31, 2017 (Successor)		20,275		1,689		37,946		28,288
Estimated proved undeveloped reserves:
As of December 31, 2015 (Predecessor)		8,542		1,674		31,596		15,481
As of December 31, 2016 (Predecessor)		5,011		1,374		26,579		10,815
As of February 28, 2017 (Predecessor)		3,932		1,287		24,668		9,330
As of December 31, 2017 (Successor)		1,601		616		12,170		4,245

The following narrative provides the reasons for the significant changes in the quantities of our estimated proved reserves by year.

2017 Periods. Revisions of previous estimates were primarily the result of positive well performance (4 MMBoe). The sale of reserves represents the sale of the Appalachia Properties (17 MMBoe) in connection with our restructuring (seeNote 4 – Divestiture).

Year Ended December 31, 2016. Revisions of previous estimates were primarily the result of positive reserve report gas pricing changes extending the economic limits of the reservoirs (15 MMBoe) primarily in Appalachia, slightly offset by negative well performance (6 MMBoe).

Year Ended December 31, 2015.Revisions of previous estimates were primarily the result of the significant decline in commodity prices resulting in uneconomic reserves (95 MMBoe) primarily in Appalachia, slightly offset by positive well performance (7 MMBoe). Purchase of producing properties related to increases in our netrevenue and working interests in multiple wells in the Mary field in Appalachia resulting from the finalization of participation elections made by partners and potential partners in certain units.

F-136

Standardized Measure of Discounted Future Net Cash Flows

The following tables present the standardized measure of discounted future net cash flows related to estimated proved oil, natural gas and NGL reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2017. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil, natural gas and NGL reserves. Prices are based on either the historical twelve-month average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. Our GOM Basin properties represented 100% of our estimated proved oil and natural gas reserves and standardized measure of discounted future net cash flows at December 31, 2017. The standardized measure of discounted future net cash flows and changes therein are as follows (in thousands, except average prices):

	Standardized Measure
	Successor December 31, 2017			Predecessor December 31,
				2016			2015
Future cash inflows	$	1,264,809		$	1,236,097		$	1,921,329
Future production costs		(497,538	)		(480,815	)		(651,396	)
Future development costs		(431,752	)		(638,988	)		(679,355	)
Future income taxes		—			—			—
Future net cash flows		335,519			116,294			590,578
10% annual discount		57,591			109,628			13,259
Standardized measure of discounted future net cash flows	$	393,110		$	225,922		$	603,837
Average prices related to proved reserves:
Oil (per Bbl)	$	50.05		$	40.15		$	51.16
NGLs (per Bbl)		22.90			9.46			16.40
Natural gas (per Mcf)		2.34			1.71			2.19

F-137

	Changes in Standardized Measure
	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period From January 1, 2017 through February 28, 2017			Year Ended December 31,
							2016			2015
Standardized measure at beginning of period	$	303,086		$	225,922		$	603,837		$	1,418,792
Sales and transfers of oil, natural gas and NGLs produced, net of production costs		(164,612	)		(46,137	)		(223,948	)		(340,477	)
Changes in price, net of future production costs		66,192			17,455			(448,861	)		(237,747	)
Extensions and discoveries, net of future production and development costs		—			—			5,243			1,573
Changes in estimated future development costs, net of development costs incurred during the period		88,111			20,756			54,406			731,115
Revisions of quantity estimates		96,454			36,557			139,759			(1,458,652	)
Accretion of discount		30,309			22,592			60,384			174,456
Net change in income taxes		—			—			—			325,768
Purchases of reserves in-place		—			—			—			3,493
Sales of reserves in-place		—			14,584			—			—
Changes in production rates due to timing and other		(26,430	)		11,357			35,102			(14,484	)
Net change in standardized measure		90,024			77,164			(377,915	)		(814,955	)
Standardized measure at end of period	$	393,110		$	303,086		$	225,922		$	603,837

NOTE 23 — SUMMARIZED QUARTERLY FINANCIAL INFORMATION – UNAUDITED

The Company’s results of operations by quarter are as follows (in thousands, except per share amounts):

	Predecessor			Successor
	Period from January 1, 2017 through February 28, 2017			Period from March 1, 2017 through March 31, 2017			2017 Quarter Ended
							June 30			Sept. 30			Dec. 31
Operating revenue	$	68,922		$	25,809		$	76,722		$	79,525		$	76,327
Income (loss) from operations	$	209,119		$	(258,594	)	$	(4,519	)	$	2,653		$	5,302
Net income (loss)	$	630,317		$	(259,613	)	$	(6,461	)	$	1,297		$	17,138
Basic income (loss) per share	$	110.99		$	(12.98	)	$	(0.32	)	$	0.06		$	0.86
Diluted income (loss) per share	$	110.99		$	(12.98	)	$	(0.32	)	$	0.06		$	0.86
Write-down of oil and gas properties	$	—		$	256,435		$	—		$	—		$	—
Gain (loss) on Appalachia Properties divestiture	$	213,453		$	—		$	27		$	(132	)	$	—
Reorganization items(1)	$	(437,744	)	$	—		$	—		$	—		$	—
Other expense	$	13,336		$	—		$	814		$	47		$	369

F-138

(1) SeeNote 3 – Fresh Start Accounting for additional details.

	Predecessor 2016 Quarter Ended
	March 31			June 30			Sept. 30			Dec. 31
Operating revenue	$	80,677		$	89,319		$	94,427		$	113,107
Loss from operations	$	(172,150	)	$	(174,656	)	$	(72,128	)	$	(90,234	)
Net loss	$	(188,784	)	$	(195,761	)	$	(89,635	)	$	(116,406	)
Basic loss per share	$	(33.89	)	$	(35.05	)	$	(16.01	)	$	(20.76	)
Diluted loss per share	$	(33.89	)	$	(35.05	)	$	(16.01	)	$	(20.76	)
Write-down of oil and gas properties	$	129,204		$	118,649		$	36,484		$	73,094
Restructuring fees	$	953		$	9,436		$	5,784		$	13,424
Other operational expenses(1)	$	12,527		$	27,680		$	9,059		$	6,187
Reorganization items	$	—		$	—		$	—		$	10,947

(1) SeeNote 19 – Other Operational Expenses for additional details.

NOTE 24 — NEW YORK STOCK EXCHANGE COMPLIANCE

On May 17, 2016, we were notified by the New York Stock Exchange (the “NYSE”) that our average global market capitalization had been less than $50 million over a consecutive 30 trading-day period at the same time that our stockholders’ equity was less than $50 million, which is non-compliant with Section 802.01B of the NYSE Listed Company Manual. On June 30, 2016, we submitted our 18-month business plan for curing the average market capitalization and stockholders’ equity deficiencies to the NYSE, and on August 4, 2016, the NYSE accepted the Plan. All of our quarterly updates to the business plan were accepted by the NYSE. Since March 1, 2017, the first day of trading subsequent to the effective date of the Company’s plan of reorganization, the Successor Company has maintained a market capitalization above $50 million.

On August 24, 2017, we were notified by the NYSE that we are back in compliance with their continued listing standards as a result of the Company’s consistent positive performance with respect to the original business plan submission and the achievement of compliance with the average global market capitalization and stockholders’ equity listing requirements over the past two quarters. In accordance with the NYSE’s Listed Company Manual, we will be subject to a 12-month follow up period within which the Company will be reviewed to ensure that the Company does not fall below any of the NYSE’s continued listing standards.

F-139

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

(In thousands of dollars)

	Successor
	March 31, 2018			December 31, 2017
	(Unaudited)			(Note 1)
Assets
Current assets:
Cash and cash equivalents	$	277,842		$	263,495
Restricted cash		—			18,742
Accounts receivable		36,378			39,258
Fair value of derivative contracts		417			879
Current income tax receivable		16,212			36,260
Other current assets		6,901			7,138
Total current assets		337,750			365,772
Oil and gas properties, full cost method of accounting:
Proved		713,304			713,157
Less: accumulated depreciation, depletion and amortization		(374,063	)		(353,462	)
Net proved oil and gas properties		339,241			359,695
Unevaluated		118,365			102,187
Other property and equipment, net		16,544			17,275
Other assets, net		14,066			13,844
Total assets	$	825,966		$	858,773
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	20,088		$	54,226
Undistributed oil and gas proceeds		4,283			5,142
Accrued interest		6,038			1,685
Fair value of derivative contracts		13,147			8,969
Asset retirement obligations		56,428			79,300
Current portion of long-term debt		430			425
Other current liabilities		13,552			22,579
Total current liabilities		113,966			172,326
Long-term debt		235,394			235,502
Asset retirement obligations		140,226			133,801
Fair value of derivative contracts		4,564			3,085
Other long-term liabilities		5,743			5,891
Total liabilities		499,893			550,605
Commitments and contingencies
Stockholders’ equity:
Common stock ($.01 par value; authorized 60,000,000 shares; issued 19,998,701 and 19,998,019 shares, respectively)		200			200
Additional paid-in capital		555,940			555,607
Accumulated deficit		(230,067	)		(247,639	)
Total stockholders’ equity		326,073			308,168
Total liabilities and stockholders’ equity	$	825,966		$	858,773

The accompanying notes are an integral part of this balance sheet.

F-140

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

	Successor						Predecessor
	Three Months Ended March 31, 2018			Period from March 1, 2017 through March 31, 2017			Period from January 1, 2017 through February 28, 2017
Operating revenue:
Oil production	$	73,261		$	20,027		$	45,837
Natural gas production		4,900			2,210			13,476
Natural gas liquids production		3,188			777			8,706
Other operational income		27			149			903
Derivative income, net		—			2,646			—
Total operating revenue		81,376			25,809			68,922
Operating expenses:
Lease operating expenses		14,380			4,740			8,820
Transportation, processing and gathering expenses		783			144			6,933
Production taxes		(2,201	)		65			682
Depreciation, depletion and amortization		21,333			15,847			37,429
Write-down of oil and gas properties		—			256,435			—
Accretion expense		4,287			2,901			5,447
Salaries, general and administrative expenses		12,556			3,322			9,629
Incentive compensation expense		387			—			2,008
Restructuring fees		—			288			—
Other operational expenses		179			661			530
Derivative expense, net		9,548			—			1,778
Total operating expenses		61,252			284,403			73,256
Gain on Appalachia Properties divestiture		—			—			213,453
Income (loss) from operations		20,124			(258,594	)		209,119
Other (income) expense:
Interest expense		3,537			1,190			—
Interest income		(1,539	)		(40	)		(45	)
Other income		(203	)		(131	)		(315	)
Other expense		21			—			13,336
Reorganization items, net		—			—			(437,744	)
Total other (income) expense		1,816			1,019			(424,768	)
Income (loss) before income taxes		18,308			(259,613	)		633,887
Provision (benefit) for income taxes:
Current		—			—			3,570
Total income taxes		—			—			3,570
Net income (loss)	$	18,308		$	(259,613	)	$	630,317
Basic income (loss) per share	$	0.91		$	(12.98	)	$	110.99
Diluted income (loss) per share	$	0.91		$	(12.98	)	$	110.99
Average shares outstanding		19,998			19,997			5,634
Average shares outstanding assuming dilution		19,998			19,997			5,634

The accompanying notes are an integral part of this statement.

F-141

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)

(Unaudited)

	Common Stock			Treasury Stock			Additional Paid-In Capital			Accumulated Deficit			Total Stockholders’ Equity
Balance, December 31, 2016 (Predecessor)	$	56		$	(860	)	$	1,659,731		$	(2,296,209	)	$	(637,282	)
Net income		—			—			—			630,317			630,317
Lapsing of forfeiture restrictions of restricted stock and granting of stock awards		—			—			(172	)		—			(172	)
Amortization of stock compensation expense		—			—			3,527			—			3,527
Balance, February 28, 2017 (Predecessor)		56			(860	)		1,663,086			(1,665,892	)		(3,610	)
Cancellation of Predecessor equity		(56	)		860			(1,663,086	)		1,665,892			3,610
Balance, February 28, 2017 (Predecessor)		—			—			—			—			—
Issuance of Successor common stock and warrants		200			—			554,537			—			554,737
Balance, February 28, 2017 (Successor)		200			—			554,537			—			554,737
Net loss		—			—			—			(247,639	)		(247,639	)
Lapsing of forfeiture restrictions of restricted stock		—			—			(19	)		—			(19	)
Amortization of stock compensation expense		—			—			1,272			—			1,272
Stock issuance costs - Talos combination		—			—			(183	)		—			(183	)
Balance, December 31, 2017 (Successor)		200			—			555,607			(247,639	)		308,168
Cumulative effect adjustment (see Note 13)		—			—			—			(736	)		(736	)
Net income		—			—			—			18,308			18,308
Lapsing of forfeiture restrictions of restricted stock		—			—			(15	)		—			(15	)
Amortization of stock compensation expense		—			—			348			—			348
Balance, March 31, 2018 (Successor)	$	200		$	—		$	555,940		$	(230,067	)	$	326,073

The accompanying notes are an integral part of this statement.

F-142

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

(Unaudited)

	Successor						Predecessor
	Three Months Ended March 31, 2018			Period from March 1, 2017 through March 31, 2017			Period from January 1, 2017 through February 28, 2017
Cash flows from operating activities:
Net income (loss)	$	18,308		$	(259,613	)	$	630,317
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		21,333			15,847			37,429
Write-down of oil and gas properties		—			256,435			—
Accretion expense		4,287			2,901			5,447
Gain on sale of oil and gas properties		—			—			(213,453	)
Settlement of asset retirement obligations		(20,734	)		(17,600	)		(3,641	)
Non-cash stock compensation expense		348			17			2,645
Non-cash derivative (income) expense		6,119			(2,484	)		1,778
Non-cash interest expense		1			—			—
Non-cash reorganization items		—			—			(458,677	)
Other non-cash expense		22			—			172
Change in current income taxes		20,049			—			3,570
Decrease in accounts receivable		2,144			6,728			6,354
(Increase) decrease in other current assets		237			964			(2,274	)
Increase (decrease) in accounts payable		(13,701	)		3,015			(4,652	)
Increase (decrease) in other current liabilities		(5,534	)		1,672			(9,653	)
Investment in derivative contracts		—			(2,140	)		(3,736	)
Other		(393	)		4,904			2,490
Net cash provided by (used in) operating activities		32,486			10,646			(5,884	)
Cash flows from investing activities:
Investment in oil and gas properties		(37,081	)		(5,584	)		(8,754	)
Proceeds from sale of oil and gas properties, net of expenses		320			10,770			505,383
Investment in fixed and other assets		—			(2	)		(61	)
Net cash provided by (used in) investing activities		(36,761	)		5,184			496,568
Cash flows from financing activities:
Repayments of bank borrowings		—			—			(341,500	)
Repayments of building loan		(105	)		(36	)		(24	)
Cash payment to noteholders		—			—			(100,000	)
Debt issuance costs		—			—			(1,055	)
Net payments for share-based compensation		(15	)		—			(173	)
Net cash used in financing activities		(120	)		(36	)		(442,752	)
Net change in cash, cash equivalents and restricted cash		(4,395	)		15,794			47,932
Cash, cash equivalents and restricted cash, beginning of period		282,237			238,513			190,581
Cash, cash equivalents and restricted cash, end of period	$	277,842		$	254,307		$	238,513

The accompanying notes are an integral part of this statement.

F-143

STONE ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 – FINANCIAL STATEMENT PRESENTATION

Interim Financial Statements

The condensed consolidated financial statements of Stone Energy Corporation (“Stone” or the “Company”) and its subsidiaries as of March 31, 2018 (Successor) and for the three months ended March 31, 2018 (Successor) and the periods from March 1, 2017 through March 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor) are unaudited and reflect all adjustments (consisting only of normal recurring adjustments), which are, in the opinion of management, necessary for a fair presentation of the financial position and operating results for the interim periods. The condensed consolidated balance sheet as of December 31, 2017 (Successor) has been derived from the audited financial statements as of that date contained in our financial statements for the year ended December 31, 2017. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto, although, as described below, such prior financial statements will not be comparable to the interim financial statements due to the adoption of fresh start accounting on February 28, 2017. For additional information, seeNote 3 – Fresh Start Accounting. The results of operations for the three months ended March 31, 2018 (Successor) are not necessarily indicative of future financial results. Certain prior period amounts have been reclassified to conform to current period presentation.

Pending Combination with Talos

On November 21, 2017, Stone and certain of its subsidiaries entered into a series of related agreements pertaining to a business combination with Talos Energy LLC (“Talos Energy”) and its indirect wholly owned subsidiary Talos Production LLC (“Talos Production” and, together with Talos Energy, “Talos”). Talos Energy is controlled indirectly by entities controlled by Apollo Management VII, L.P. (“Apollo VII”), Apollo Commodities Management, L.P., with respect to Series I (together with Apollo VII, “Apollo Management”) and Riverstone Energy Partners V, L.P. (“Riverstone”).

Stone, Sailfish Energy Holdings Corporation (“New Talos”), a direct wholly owned subsidiary of Stone, and Sailfish Merger Sub Corporation, a direct wholly owned subsidiary of New Talos, entered into a Transaction Agreement (the “Transaction Agreement”) with Talos on November 21, 2017, which contemplates a series of transactions (the “Transactions”) occurring on the date of closing of the Transaction Agreement (the “Closing”) that will result in such business combination. Stone and Talos will become wholly owned subsidiaries of New Talos. At the time of the Closing, the parties intend that New Talos will become a publicly traded entity named Talos Energy Inc. The Transactions include (i) the contribution of 100% of the equity interests in Talos Production to New Talos in exchange for shares of New Talos common stock, (ii) the contribution by entities controlled by or affiliated with Apollo Management (the “Apollo Funds”) and Riverstone (the “Riverstone Funds”) of $102 million in aggregate principal amount of 9.75% Senior Notes due 2022 issued by Talos Production and Talos Production Finance Inc. (together, the “the Talos Issuers”) to New Talos in exchange for shares of New Talos common stock, (iii) the exchange of the second lien bridge loans due 2022 issued by the Talos Issuers for newly issued 11.0% second lien notes issued by the Talos Issuers, and (iv) the exchange of the 7.50% Senior Second Lien Notes due 2022 (the “2022 Second Lien Notes”) issued by Stone for newly issued 11.0% second lien notes issued by the Talos Issuers.

Under the terms of the Transaction Agreement, each outstanding share of Stone common stock will be exchanged for one share of New Talos common stock and the current Talos stakeholders (including the Apollo Funds and the Riverstone Funds) will be issued an aggregate of approximately 34.1 million shares of New Talos common stock. After the completion of the Transactions contemplated by the Transaction Agreement, holders of Stone common stock immediately prior to the combination will collectively hold 37% of the outstanding New

F-144

Talos common stock and Talos Energy stakeholders will hold 63% of the outstanding New Talos common stock. Outstanding warrants to acquire Stone common stock will become warrants to acquire New Talos common stock with terms and conditions substantially identical to their existing terms and conditions. The combination was unanimously approved by the boards of directors of Stone and Talos Energy.

On March 20, 2018, the Talos Issuers launched an offer to exchange (the “Exchange Offer”) Stone’s outstanding 2022 Second Lien Notes for newly issued 11.0% second lien notes due 2022 of the Talos Issuers. Concurrently with the Exchange Offer, the Talos Issuers solicited and received sufficient consents from the holders of the 2022 Second Lien Notes to adopt certain proposed amendments to the indenture governing the 2022 Second Lien Notes (the “Stone Notes Indenture”) and to release the collateral securing the obligations under the 2022 Second Lien Notes. Stone entered into supplemental indentures related to the amendments and the release of collateral. The supplemental indentures, which will not become operative until the tendered 2022 Second Lien Notes are accepted for exchange by the Talos Issuers, will amend the Stone Notes Indenture to, among other things, eliminate or modify substantially all of the restrictive covenants, certain reporting obligations, certain events of default and related provisions contained in the Stone Notes Indenture and to release the collateral securing the 2022 Second Lien Notes.

Pursuant to a consent solicitation statement/prospectus dated April 9, 2018, which was included as part of a Registration Statement on Form S-4 filed by New Talos, Stone solicited written consents from its stockholders to adopt the Transaction Agreement, and thereby approve and adopt the Transactions. As of May 3, 2018, stockholders party to voting agreements with Stone and Talos Energy that owned 10,212,937 shares of Stone common stock as of April 5, 2018 had delivered written consents adopting the Transaction Agreement, and thereby approving and adopting the Transactions. The Stone stockholders that delivered written consents collectively own approximately 51.1% of the outstanding shares of Stone common stock. As a result, no further action by any Stone stockholder is required under applicable law or otherwise to adopt the Transaction Agreement, and thereby approve and adopt the Transactions.

The combination is expected to close on or about May 10, 2018. We cannot provide any assurance that the combination will be completed on the terms or timeline currently contemplated, or at all. The above is a summary of the material terms of the Transactions and is qualified in its entirety by reference to the New Talos Registration Statement on Form S-4 (which became effective on April 9, 2018).

Reorganization and Emergence from Voluntary Reorganization Under Chapter 11 Proceedings

On December 14, 2016, the Company and certain of its subsidiaries (the “Debtors”) filed voluntary petitions in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) to pursue a prepackaged plan of reorganization (the “Plan”) under the provisions of Chapter 11 of the United States Bankruptcy Code. On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan, and on February 28, 2017, the Plan became effective (the “Effective Date”) and the Debtors emerged from bankruptcy. SeeNote 2 – Reorganization for additional details.

Upon emergence from bankruptcy, the Company adopted fresh start accounting in accordance with the provisions of Accounting Standards Codification (“ASC”) 852, “Reorganizations”, which resulted in the Company becoming a new entity for financial reporting purposes on the Effective Date. As a result of the adoption of fresh start accounting, the Company’s unaudited condensed consolidated financial statements subsequent to February 28, 2017 will not be comparable to its financial statements prior to that date. SeeNote 3 – Fresh Start Accounting for further details on the impact of fresh start accounting on the Company’s unaudited condensed consolidated financial statements. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.

F-145

Use of Estimates

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects are uncertain and, accordingly, these estimates may change as new events occur, as additional information is obtained and as the Company’s operating environment changes. Actual results could differ from those estimates. Estimates are used primarily when accounting for depreciation, depletion and amortization (“DD&A”) expense, unevaluated property costs, estimated future net cash flows from proved reserves, costs to abandon oil and gas properties, income taxes, accruals of capitalized costs, operating costs and production revenue, capitalized general and administrative costs and interest, insurance recoveries, estimated fair value of derivative contracts, contingencies and fair value estimates, including estimates of reorganization value, enterprise value and the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting.

Recently Adopted Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers (Topic 606)” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The new standard supersedes current revenue recognition requirements and industry-specific guidance. Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. We adopted this new standard on January 1, 2018 using the modified retrospective approach by recognizing the cumulative effect of initially applying the new standard as an adjustment to the opening balance of accumulated deficit. We implemented the necessary changes to our business processes, systems and controls to support recognition and disclosure of this ASU upon adoption. The adoption of the standard did not have a material effect on our financial position, results of operations or cash flows, but did result in increased disclosures related to revenue recognition policies and disaggregation of revenues. SeeNote 13 – Revenue Recognition for additional information.

In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230) – Restricted Cash”, which requires that amounts generally described as restricted cash be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows. We adopted this new standard on January 1, 2018. Retrospective presentation was required. The adoption of the standard did not have a material effect on our financial position, results of operations or cash flows. In accordance with ASU 2016-18, we have included restricted cash as part of the beginning-of-period and end-of-period cash balances on the condensed consolidated statement of cash flows. At February 28, 2017 (Predecessor) and March 31, 2017 (Successor), we had restricted cash of $75.5 million and $74.1 million, respectively. We had no restricted cash at March 31, 2018 (Successor). For the period from January 1, 2017 through February 28, 2017 (Predecessor) and the period from March 1, 2017 through March 31, 2017 (Successor), removing the change in restricted funds from the condensed consolidated statement of cash flows resulted in an increase of $75.5 million and a decrease of $1.5 million, respectively, in our net cash provided by investing activities.

Recently Issued Accounting Standards

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)” to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public companies for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. We are currently evaluating the effect that this new standard may have on our financial statements and related disclosures.

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In August 2017, the FASB issued ASU 2017-12, “Derivatives and Hedging (Topic 815)” to improve the financial reporting of hedging relationships to better reflect an entity’s hedging strategies. The standard expands an entity’s ability to apply hedge accounting for both non-financial and financial risk components and amends the presentation and disclosure requirements. Additionally, ASU 2017-12 eliminates the need to separately measure and report hedge ineffectiveness and generally requires the entire change in fair value of a hedging instrument to be recorded in the same income statement line as the earnings effect of the hedged item. The standard is effective for public companies for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted. The standard must be adopted by applying a modified retrospective approach to existing designated hedging relationships as of the adoption date, with a cumulative effect adjustment recorded to opening retained earnings as of the initial adoption date. We are currently evaluating the effect that this new standard may have on our financial statements and related disclosures.

NOTE 2 – REORGANIZATION

In connection with our reorganization, we sold certain producing properties and acreage, including approximately 86,000 net acres, in the Appalachia regions of Pennsylvania and West Virginia (the “Appalachia Properties”) to EQT Corporation, through its wholly-owned subsidiary EQT Production Company (“EQT”), on February 27, 2017, for net cash consideration of approximately $522.5 million. A portion of the consideration received from the sale of the Appalachia Properties was used to fund the Company’s cash payment obligations under the Plan, as described below. Additionally, the Company used a portion of the cash consideration received to pay TH Exploration III, LLC, an affiliate of Tug Hill, Inc. (“Tug Hill”), a break-up fee and expense reimbursements totaling approximately $11.5 million related to the termination of a purchase and sale agreement for the Appalachia Properties prior to the sale to EQT. SeeNote 5 – Divestiture for additional information on the sale of the Appalachia Properties.

Upon emergence from bankruptcy, pursuant to the terms of the Plan, the following significant transactions occurred:

• Shares of the Predecessor Company’s issued and outstanding common stock immediately prior to the Effective Date were cancelled, and on the Effective Date, reorganized Stone issued an aggregate of 20.0 million shares of new common stock (the “New Common Stock”).

• The Predecessor Company’s 7 ¹⁄₂% Senior Notes due 2022 (the “2022 Notes”) and 1 ³⁄₄% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”) were cancelled and the holders of such notes received their pro rata share of (a) $100 million of cash, (b) 19.0 million shares of the New Common Stock, representing 95% of the New Common Stock and (c) $225 million of 2022 Second Lien Notes.

• The Predecessor Company’s common stockholders received their pro rata share of 1.0 million shares of the New Common Stock, representing 5% of the New Common Stock, and warrants to purchase approximately 3.5 million shares of New Common Stock. The warrants have an exercise price of $42.04 per share and a term of four years, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company.

• The Predecessor Company’s Fourth Amended and Restated Credit Agreement, dated as of June 24, 2014, as amended, modified, or otherwise supplemented from time to time (the “Pre-Emergence Credit Agreement”) was amended and restated as the Amended Credit Agreement (as defined inNote 8 – Debt). The obligations owed to the lenders under the Pre-Emergence Credit Agreement were converted to obligations under the Amended Credit Agreement

• All claims of creditors with unsecured claims, other than the claims by the holders of the 2022 Notes and 2017 Convertible Notes, including vendors, were unaltered and paid in full in the ordinary course of business to the extent the claims were undisputed.

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NOTE 3 – FRESH START ACCOUNTING

Upon emergence from bankruptcy, the Company qualified for and adopted fresh start accounting in accordance with the provisions of ASC 852, “Reorganizations” as (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the post-petition liabilities and allowed claims. SeeNote 2 – Reorganization for the terms of the Plan. The Company applied fresh start accounting as of February 28, 2017. Fresh start accounting required the Company to present its assets, liabilities and equity as if it were a new entity upon emergence from bankruptcy, with no beginning retained earnings or deficit as of the fresh start reporting date. As described inNote 1 – Financial Statement Presentation, the new entity is referred to as Successor or Successor Company, and includes the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to Predecessor or Predecessor Company relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.

Reorganization Value

Under fresh start accounting, reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately after restructuring. Upon application of fresh start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values.

The Company’s reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s long-term debt and stockholders’ equity. In support of the Plan, the Company estimated the enterprise value of the core assets (as defined in the Plan) of the Successor Company to be in the range of $300 million to $450 million, which was subsequently approved by the Bankruptcy Court. This valuation analysis was prepared using reserve information, development schedules, other financial information and financial projections and applying standard valuation techniques, including net asset value analysis, precedent transactions analyses and public comparable company analyses. Based on the estimates and assumptions used in determining the enterprise value, the Company ultimately estimated the enterprise value of the Successor Company’s core assets to be approximately $420 million.

Valuation of Assets

The Company’s principal assets are its oil and gas properties, which the Company accounts for under the full cost accounting method. With the assistance of valuation experts, the Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the bankruptcy emergence date.

The fair value analysis performed by valuation experts was based on the Company’s estimates of reserves as developed internally by the Company’s reserve engineers. For purposes of estimating the fair value of the Company’s proved, probable and possible reserves, an income approach was used, which estimated fair value based on the anticipated cash flows associated with the Company’s reserves, risked by reserve category and discounted using a weighted average cost of capital of 12.5%. The discount factor was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar market participants.

Future revenues were based upon forward strip oil and natural gas prices as of the emergence date, adjusted for differentials realized by the Company, and adjusted for a 2% annual escalation after 2021. Development and operating costs were based on the Company’s recent cost trends adjusted for inflation. The discounted cash flow models also included estimates not typically included in proved reserves such as depreciation and income tax expenses. The proved reserve locations were limited to wells expected to be drilled in the Company’s five year development plan.

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As a result of this analysis, the Company concluded the fair value of its proved reserves was $380.8 million and the fair value of its probable and possible reserves was $16.8 million as of the Effective Date. The Company also reviewed its undeveloped leasehold acreage and inventory. An analysis of comparable market transactions indicated a fair value of undeveloped acreage and inventory totaling $80.2 million. These amounts are reflected in theFresh Start Adjustments item number 12 below. The fair value of the Company’s asset retirement obligations was estimated at $290.1 million and was based on estimated plugging and abandonment costs as of the Effective Date, adjusted for inflation and discounted at the Successor Company’s credit-adjusted risk free rate of 12%.

See further discussion inFresh Start Adjustments below for details on the specific assumptions used in the valuation of the Company’s various other assets.

The following table reconciles the enterprise value per the Plan to the estimated fair value (for fresh start accounting purposes) of the Successor Company’s common stock as of February 28, 2017 (in thousands, except per share value):

	February 28, 2017
Enterprise value	$	419,720
Plus: Cash and other assets		371,278
Less: Fair value of debt		(236,261	)
Less: Fair value of warrants		(15,648	)
Fair value of Successor common stock	$	539,089
Shares issued upon emergence		20,000
Per share value	$	26.95

The following table reconciles the enterprise value per the Plan to the estimated reorganization value as of the Effective Date (in thousands):

	February 28, 2017
Enterprise value	$	419,720
Plus: Cash and other assets		371,278
Plus: Asset retirement obligations (current and long-term)		290,067
Plus: Working capital and other liabilities		58,055
Reorganization value of Successor assets	$	1,139,120

Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond our control. Accordingly, the estimates set forth herein are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized.

Condensed Consolidated Balance Sheet

The adjustments set forth in the following condensed consolidated balance sheet reflect the effects of the transactions contemplated by the Plan and carried out by the Company (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or

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other amounts of the assets and liabilities as well as significant assumptions or inputs. The following table reflects the reorganization and application of ASC 852 on our consolidated balance sheet as of February 28, 2017 (in thousands):

	Predecessor Company			Reorganization Adjustments				Fresh Start Adjustments					Successor Company
Assets
Current assets:
Cash and cash equivalents	$	198,571		$	(35,605	)	(1)	$	—				$	162,966
Restricted cash		—			75,547		(1)		—					75,547
Accounts receivable		42,808			9,301		(2)		—					52,109
Fair value of derivative contracts		1,267			—				—					1,267
Current income tax receivable		22,516			—				—					22,516
Other current assets		11,033			875		(3)		(124	)	(12	)		11,784
Total current assets		276,195			50,118				(124	)				326,189
Oil and gas properties, full cost method of accounting:
Proved		9,633,907			(188,933	)	(1)		(8,774,122	)	(12	)		670,852
Less: accumulated DD&A		(9,215,679	)		—				9,215,679		(12	)		—
Net proved oil and gas properties		418,228			(188,933	)			441,557					670,852
Unevaluated		371,140			(127,838	)	(1)		(146,292	)	(12	)		97,010
Other property and equipment, net		25,586			(101	)	(4)		(4,423	)	(13	)		21,062
Fair value of derivative contracts		1,819			—				—					1,819
Other assets, net		26,516			(4,328	)	(5)		—					22,188
Total assets	$	1,119,484		$	(271,082	)		$	290,718				$	1,139,120
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	20,512		$	—			$	—				$	20,512
Undistributed oil and gas proceeds		5,917			(4,139	)	(1)		—					1,778
Accrued interest		266			—				—					266
Asset retirement obligations		92,597			—				—					92,597
Fair value of derivative contracts		476			—				—					476
Current portion of long-term debt		411			—				—					411
Other current liabilities		17,032			(195	)	(6)		—					16,837
Total current liabilities		137,211			(4,334	)			—					132,877
Long-term debt		352,350			(116,500	)	(7)		—					235,850
Asset retirement obligations		151,228			(8,672	)	(1)		54,914		(14)			197,470
Fair value of derivative contracts		653			—				—					653
Other long-term liabilities		17,533			—				—					17,533
Total liabilities not subject to compromise		658,975			(129,506	)			54,914					584,383
Liabilities subject to compromise		1,110,182			(1,110,182	)	(8)		—					—
Total liabilities		1,769,157			(1,239,688	)			54,914					584,383
Commitments and contingencies Stockholders’ equity:
Common stock (Predecessor)		56			(56	)	(9)		—					—
Treasury stock (Predecessor)		(860	)		860		(9)		—					—
Additional paid-in capital (Predecessor)		1,660,810			(1,660,810	)	(9)		—					—
Common stock (Successor)		—			200		(10)		—					200
Additional paid-in capital (Successor)		—			554,537		(10)		—					554,537
Accumulated deficit		(2,309,679	)		2,073,875		(11)		235,804		(15)			—
Total stockholders’ equity		(649,673	)		968,606				235,804					554,737
Total liabilities and stockholders’ equity	$	1,119,484		$	(271,082	)		$	290,718				$	1,139,120

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Reorganization Adjustments

1. Reflects the net cash proceeds received from the sale of the Appalachia Properties in connection with the Plan and net cash payments made as of the Effective Date from implementation of the Plan (in thousands):

Sources:
Net cash proceeds from sale of Appalachia Properties(a)	$	512,472
Total sources		512,472
Uses:
Cash transferred to restricted account(b)		75,547
Break-up fee to Tug Hill		10,800
Repayment of outstanding borrowings under Pre-Emergence Credit Agreement		341,500
Repayment of 2017 Convertible Notes and 2022 Notes		100,000
Other fees and expenses(c)		20,230
Total uses		548,077
Net uses	$	(35,605	)

(a) The closing of the sale of the Appalachia Properties occurred on February 27, 2017, but as emergence was contingent on such closing, the effects of the transaction are reflected as reorganization adjustments. SeeNote 5 – Divestiture for additional details on the sale. Total consideration received for the sale of the Appalachia Properties of $522.5 million included cash consideration of $512.5 million received at closing and a $10.0 million indemnity escrow which was released subsequent to emergence from bankruptcy (seeReorganization Adjustments item number 2 below).

(b) Reflects the movement of $75.0 million of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the provisions of the Amended Credit Agreement (as defined inNote 8 – Debt), and $0.5 million held in a restricted cash account for certain cure amounts in connection with the Chapter 11 proceedings.

(c) Other fees and expenses include approximately $15.2 million of emergence and success fees, $2.7 million of professional fees and $2.4 million of payments made to seismic providers in settlement of their bankruptcy claims.

2. Reflects a receivable for a $10.0 million indemnity escrow with release delayed until emergence from bankruptcy, net of a $0.7 million reimbursement to Tug Hill in connection with the sale of the Appalachia Properties (seeNote 2 – Reorganization).

3. Reflects the payment of a claim to a seismic provider as a prepayment/deposit.

4. Reflects the sale of vehicles in connection with the sale of the Appalachia Properties.

5. Reflects the write-off of $2.6 million of unamortized debt issuance costs related to the Pre-Emergence Credit Agreement and the reversal of a $1.8 million prepayment made to Tug Hill in October 2016.

6. Reflects the accrual of $2.0 million in expected bonus payments under the Key Executive Incentive Plan and a $0.4 million termination fee in connection with the early termination of an office lease, less the settlement of a property tax accrual of $2.6 million in connection with the sale of the Appalachia Properties.

7. Reflects the repayment of $341.5 million of outstanding borrowings under the Pre-Emergence Credit Agreement and the issuance of $225 million of 2022 Second Lien Notes as part of the settlement of the Predecessor Company 2017 Convertible Notes and 2022 Notes.

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8. Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):

1 3⁄4% Senior Convertible Notes due 2017	$	300,000
7 1⁄2% Senior Notes due 2022		775,000
Accrued interest		35,182
Liabilities subject to compromise of the Predecessor Company		1,110,182
Cash payment to senior noteholders		(100,000	)
Issuance of 2022 Second Lien Notes to former holders of the senior notes		(225,000	)
Fair value of equity issued to unsecured creditors		(539,089	)
Fair value of warrants issued to unsecured creditors		(15,648	)
Gain on settlement of liabilities subject to compromise	$	230,445

9. Reflects the cancellation of the Predecessor Company’s common stock, treasury stock and additional paid-in capital.

10. Reflects the issuance of Successor Company equity. In accordance with the Plan, the Successor Company issued 19.0 million shares of New Common Stock to the former holders of the 2017 Convertible Notes and the 2022 Notes and 1.0 million shares of New Common Stock to the Predecessor Company’s common stockholders. These amounts are subject to dilution by warrants issued to the Predecessor Company common stockholders, totaling approximately 3.5 million shares, with an exercise price of $42.04 per share and a term of four years. The fair value of the warrants was estimated at $4.43 per share using a Black-Scholes-Merton valuation model.

11. Reflects the cumulative impact of the reorganization adjustments discussed above (in thousands):

Gain on settlement of liabilities subject to compromise	$	230,445
Professional and other fees paid at emergence		(10,648	)
Write-off of unamortized debt issuance costs		(2,577	)
Other reorganization adjustments		(1,915	)
Net impact to reorganization items		215,305
Gain on sale of Appalachia Properties		213,453
Cancellation of Predecessor Company equity		1,662,282
Other adjustments to accumulated deficit		(17,165	)
Net impact to accumulated deficit	$	2,073,875

Fresh Start Adjustments

12. Fair value adjustments to oil and gas properties, associated inventory and unproved acreage. See above for a detailed discussion of the fair value methodology.

13. Fair value adjustment for an office building owned by the Company. The income and sales comparison approaches were used in determining the fair value, using anticipated future earnings and an appropriate expected rate of return, as well as relying upon recent sales or offerings of similar assets.

14. Fair value adjustments to the Company’s asset retirement obligations using estimated plugging and abandonment costs as of the Effective Date, adjusted for inflation and discounted at the Successor Company’s credit-adjusted risk free rate.

15. Reflects the cumulative effect of the fresh start accounting adjustments discussed above.

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Reorganization Items

Reorganization items represent liabilities settled, net of amounts incurred subsequent to the Chapter 11 filing as a direct result of the Plan and are classified as “Reorganization items, net” in the Company’s unaudited condensed consolidated statement of operations. The following table summarizes reorganization items, net (in thousands):

	Predecessor
	Period from January 1, 2017 through February 28, 2017
Gain on settlement of liabilities subject to compromise	$	230,445
Fresh start valuation adjustments		235,804
Reorganization professional fees and other expenses		(20,403	)
Write-off of unamortized debt issuance costs		(2,577	)
Other reorganization items		(5,525	)
Gain on reorganization items, net	$	437,744

The cash payments for reorganization items for the period from January 1, 2017 through February 28, 2017 include approximately $10.6 million of emergence and success fees and approximately $8.9 million of other reorganization professional fees and expenses paid on the Effective Date.

NOTE 4 – EARNINGS PER SHARE

On February 28, 2017, upon emergence from Chapter 11 bankruptcy, the Company’s Predecessor equity was cancelled and new equity was issued. Additionally, the Predecessor Company’s 2017 Convertible Notes were cancelled. SeeNote 2 – Reorganization for further details.

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The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods (in thousands, except per share amounts):

	Successor						Predecessor
	Three Months Ended March 31, 2018			Period from March 1, 2017 through March 31, 2017			Period from January 1, 2017 through February 28, 2017
Income (numerator):
Basic:
Net income (loss)	$	18,308		$	(259,613	)	$	630,317
Net income attributable to participating securities		(57	)		—			(4,995	)
Net income (loss) attributable to common stock - basic	$	18,251		$	(259,613	)	$	625,322
Diluted:
Net income (loss)	$	18,308		$	(259,613	)	$	630,317
Net income attributable to participating securities		(56	)		—			(4,995	)
Net income (loss) attributable to common stock - diluted	$	18,252		$	(259,613	)	$	625,322
Weighted average shares (denominator):
Weighted average shares - basic		19,998			19,997			5,634
Dilutive effect of stock options		—			—			—
Dilutive effect of warrants		—			—			—
Dilutive effect of convertible notes		—			—			—
Weighted average shares - diluted		19,998			19,997			5,634
Basic income (loss) per share	$	0.91		$	(12.98	)	$	110.99
Diluted income (loss) per share	$	0.91		$	(12.98	)	$	110.99

All outstanding stock options were considered antidilutive during the period from January 1, 2017 through February 28, 2017 (Predecessor) (10,400 shares) because the exercise price of the options exceeded the average price of our common stock for the applicable period. On February 28, 2017, upon emergence from bankruptcy, all outstanding stock options were cancelled.

On February 28, 2017, upon emergence from bankruptcy, the Predecessor Company’s existing common stockholders received warrants to purchase common stock of the Successor Company. SeeNote 2 – Reorganization. For the three months ended March 31, 2018 (Successor), all outstanding warrants (approximately 3.5 million) were considered antidilutive because the exercise price of the warrants exceeded the average price of our common stock for the applicable period. For the period of March 1, 2017 through March 31, 2017 (Successor), all outstanding warrants (approximately 3.5 million) were antidilutive because we had a net loss for such period.

The Predecessor Company had no outstanding restricted stock units. The board of directors of the Successor Company (the “Board”) received grants of restricted stock units on March 1, 2017. For the period from March 1, 2017 through March 31, 2017 (Successor), all outstanding restricted stock units (62,137) were considered antidilutive because we had a net loss for such period.

For the period from January 1, 2017 through February 28, 2017 (Predecessor), the average price of our common stock was less than the effective conversion price for the 2017 Convertible Notes, resulting in no dilutive effect on the diluted earnings per share computation for such period. On February 28, 2017, upon emergence from bankruptcy, the 2017 Convertible Notes were cancelled. SeeNote 2 – Reorganization.

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During the three months ended March 31, 2018 (Successor), 682 shares of common stock of the Successor Company were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock for employees. During the period from March 1, 2017 through March 31, 2017 (Successor), we had no issuances of shares of our common stock. During the period from January 1, 2017 through February 28, 2017 (Predecessor), 47,390 shares of Predecessor Company common stock were issued from authorized shares upon the granting of stock awards and the lapsing of forfeiture restrictions of restricted stock for employees and nonemployee directors.

NOTE 5 – DIVESTITURE

On February 27, 2017, we completed the sale of the Appalachia Properties to EQT for net cash consideration of approximately $522.5 million. We no longer have assets or operations in Appalachia. Since accounting for the sale of these oil and gas properties as a reduction of the capitalized costs of oil and gas properties would have significantly altered the relationship between capitalized costs and reserves, we recognized a gain on the sale of $213.5 million during the period from January 1, 2017 through February 28, 2017 (Predecessor), computed as follows (in thousands):

Net consideration received for sale of Appalachia Properties		$	522,472
Add:	Release of funds held in suspense		4,139
	Transfer of asset retirement obligations		8,672
	Other adjustments, net		2,597
Less:	Transaction costs		(7,087	)
	Carrying value of properties sold		(317,340	)
Gain on sale		$	213,453

The carrying value of the properties sold was determined by allocating total capitalized costs within the U.S. full cost pool between properties sold and properties retained based on their relative fair values.

NOTE 6 – INVESTMENT IN OIL AND GAS PROPERTIES

Under the full cost method of accounting, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for designated cash flow hedges 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 discounted cash flows.

At March 31, 2018 (Successor), the present value of the estimated future net cash flows from proved reserves was based on twelve-month average prices, net of applicable differentials, of $53.04 per Bbl of oil, $2.28 per Mcf of natural gas and $25.27 per Bbl of natural gas liquids (“NGLs”). Using these prices, the Company’s net capitalized costs of proved oil and natural gas properties at March 31, 2018 (Successor) did not exceed the ceiling amount.

At March 31, 2017 (Successor), our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $256.4 million based on twelve-month average prices, net of applicable differentials, of $45.40 per Bbl of oil, $2.24 per Mcf of natural gas and $19.18 per Bbl of NGLs. The write-down at March 31, 2017 is reflected in the statement of operations of the Successor Company for the period from March 1, 2017 through March 31, 2017 and was primarily due to differences between the trailing twelve-month average pricing assumption used in calculating the ceiling test and the forward prices used in fresh start accounting to estimate the fair value of our oil and gas properties on the fresh start reporting date of February 28, 2017. Weighted

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average commodity prices used in the determination of the fair value of our oil and gas properties for purposes of fresh start accounting were $56.01 per Bbl of oil, $2.52 per Mcf of natural gas and $14.18 per Bbl of NGLs, net of applicable differentials. Since none of our derivatives as of March 31, 2017 were designated as cash flow hedges (seeNote 7 – Derivative Instruments and Hedging Activities), the write-down at March 31, 2017 was not affected by hedging.

NOTE 7 – DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Our hedging strategy is designed to protect our near and intermediate term cash flows from future declines in oil and natural gas prices. This protection is essential to capital budget planning, which is sensitive to expenditures that must be committed to in advance, such as rig contracts and the purchase of tubular goods. We enter into derivative transactions to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. We do not enter into derivative transactions for trading purposes.

All derivatives are recognized as assets or liabilities on the balance sheet and are measured at fair value. At the end of each quarterly period, these derivatives are marked-to-market. If the derivative does not qualify or is not designated as a cash flow hedge, subsequent changes in the fair value of the derivative are recognized in earnings through derivative income (expense) in the statement of operations. If the derivative qualifies and is designated as a cash flow hedge, subsequent changes in the fair value of the derivative are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Monthly settlements of effective hedges are reflected in revenue from oil and natural gas production. Monthly settlements of ineffective hedges and derivatives not designated or that do not qualify for hedge accounting are recognized in earnings through derivative income (expense). The resulting cash flows from all monthly settlements are reported as cash flows from operating activities. With respect to our 2017, 2018 and 2019 commodity derivative contracts, we elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements of these derivative contracts have been, or will be, recorded in earnings through derivative income (expense).

We have entered into put contracts, fixed-price swaps and collar contracts with various counterparties for a portion of our expected 2018 and 2019 oil and natural gas production from the Gulf Coast Basin. All of our derivative transactions have been carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative instruments involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The counterparties to all of our derivative instruments have an “investment grade” credit rating. We monitor the credit ratings of our derivative counterparties on an ongoing basis. Although we typically enter into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, we may not realize the benefit of some of our derivative instruments and incur a loss. At May 7, 2018, our derivative instruments were with four counterparties, two of which accounted for approximately 64% of our contracted volumes. Currently, all of our outstanding derivative instruments are with lenders under our current bank credit facility.

Put contracts are purchased at a rate per unit of hedged production that fluctuates with the commodity futures market. The historical cost of the put contract represents our maximum cash exposure. We are not obligated to make any further payments under the put contract regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if the New York Mercantile Exchange (“NYMEX”) prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above the floor. Swaps typically provide for monthly payments by us if prices rise above the swap price or monthly payments to us if prices fall below the swap price. Collar contracts typically require payments by us if the NYMEX average closing price is above the ceiling price or payments to us if the NYMEX average closing price is below the floor price. Settlements for our oil put contracts, oil collar contracts and fixed-price oil swaps are based on an average of the NYMEX closing price for West Texas Intermediate crude oil during the entire calendar month. Settlements for our natural gas collar contracts are based on the NYMEX price for the last day of a respective contract month.

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The following tables illustrate our derivative positions for calendar years 2018 and 2019 as of May 7, 2018:

		Put Contracts (NYMEX)
		Oil
		Daily Volume (Bbls/d)		Price ($ per Bbl)
2018	January - December		1,000	$	54.00
2018	January - December		1,000		45.00

		Fixed-Price Swaps (NYMEX)
		Oil
		Daily Volume (Bbls/d)		Swap Price ($ per Bbl)
2018	January - December		1,000	$	52.50
2018	January - December		1,000		51.98
2018	January - December		1,000		53.67
2019	January - December		1,000		51.00
2019	January - December		1,000		51.57
2019	January - December		2,000		56.13

		Collar Contracts (NYMEX)
		Natural Gas						Oil
		Daily Volume (MMBtus/d)		Floor Price ($ per MMBtu)		Ceiling Price ($ per MMBtu)		Daily Volume (Bbls/d)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)
2018	January - December		6,000	$	2.75	$	3.24		1,000	$	45.00	$	55.35

Derivatives not designated or not qualifying as hedging instruments

The following tables disclose the location and fair value amounts of derivatives not designated or not qualifying as hedging instruments, as reported in our balance sheet, at March 31, 2018 (Successor) and December 31, 2017 (Successor) (in thousands).

Fair Value of Derivatives Not Designated or Not Qualifying as Hedging Instruments at
March 31, 2018
(Successor)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	417	Current liabilities: Fair value of derivative contracts	$	13,147
	Long-term assets: Fair value of derivative contracts		—	Long-term liabilities: Fair value of derivative contracts		4,564
		$	417		$	17,711
Fair Value of Derivatives Not Designated or Not Qualifying as Hedging Instruments at
December 31, 2017
(Successor)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	879	Current liabilities: Fair value of derivative contracts	$	8,969
	Long-term assets: Fair value of derivative contracts		—	Long-term liabilities: Fair value of derivative contracts		3,085
		$	879		$	12,054

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Gains or losses related to changes in fair value and cash settlements for derivatives not designated or not qualifying as hedging instruments are recorded as derivative income (expense) in the statement of operations. The following table discloses the before tax effect of our derivatives not designated or not qualifying as hedging instruments on the statement of operations for the three months ended March 31, 2018 (Successor), the period from January 1, 2017 through February 28, 2017 (Predecessor) and the period from March 1, 2017 through March 31, 2017 (Successor) (in thousands).

Gain (Loss) Recognized in Derivative Income (Expense)
	Successor					Predecessor
	Three Months Ended March 31, 2018			Period from March 1, 2017 through March 31, 2017		Period from January 1, 2017 through February 28, 2017
Description
Commodity contracts:
Cash settlements	$	(3,429	)	$	161	$	—
Change in fair value		(6,119	)		2,485		(1,778	)
Total gains (losses) on derivatives not designated or not qualifying as hedging instruments	$	(9,548	)	$	2,646	$	(1,778	)

Offsetting of derivative assets and liabilities

Our derivative contracts are subject to netting arrangements. It is our policy to not offset our derivative contracts in presenting the fair value of these contracts as assets and liabilities in our balance sheet. The following tables present the potential impact of the offset rights associated with our recognized assets and liabilities at March 31, 2018 (Successor) and December 31, 2017 (Successor) (in thousands):

	March 31, 2018 (Successor)
	As Presented Without Netting			Effects of Netting			With Effects of Netting
Current assets: Fair value of derivative contracts	$	417		$	(417	)	$	—
Long-term assets: Fair value of derivative contracts		—			—			—
Current liabilities: Fair value of derivative contracts		(13,147	)		417			(12,730	)
Long-term liabilities: Fair value of derivative contracts		(4,564	)		—			(4,564	)

	December 31, 2017 (Successor)
	As Presented Without Netting			Effects of Netting			With Effects of Netting
Current assets: Fair value of derivative contracts	$	879		$	(879	)	$	—
Long-term assets: Fair value of derivative contracts		—			—			—
Current liabilities: Fair value of derivative contracts		(8,969	)		879			(8,090	)
Long-term liabilities: Fair value of derivative contracts		(3,085	)		—			(3,085	)

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NOTE 8 – DEBT

Our debt balances (net of related unamortized discounts and debt issuance costs) as of March 31, 2018 (Successor) and December 31, 2017 (Successor) were as follows (in thousands):

	Successor
	March 31, 2018			December 31, 2017
7 1⁄2% Senior Second Lien Notes due 2022	$	225,000		$	225,000
4.20% Building Loan		10,824			10,927
Total debt		235,824			235,927
Less: current portion of long-term debt		(430	)		(425	)
Long-term debt	$	235,394		$	235,502

Current Portion of Long-Term Debt

As of March 31, 2018 (Successor), the current portion of long-term debt of $0.4 million represented principal payments due within one year on the 4.20% Building Loan (the “Building Loan”).

Revolving Credit Facility

On February 28, 2017, the Company entered into the Fifth Amended and Restated Credit Agreement with the lenders party thereto and Bank of America, N.A. (as amended from time to time, the “Amended Credit Agreement”), as administrative agent and issuing lender. The Amended Credit Agreement provides for a reserve-based revolving credit facility and matures on February 28, 2021.

The Company’s borrowing base under the Amended Credit Agreement was redetermined to $100 million on November 8, 2017. On March 31, 2018, the Company had no outstanding borrowings and $9.8 million of outstanding letters of credit, leaving $90.2 million of availability under the Amended Credit Agreement. Interest on loans under the Amended Credit Agreement is calculated using the London Interbank Offering Rate (“LIBOR”) or the base rate, at the election of the Company, plus, in each case, an applicable margin. The applicable margin is determined based on borrowing base utilization and ranges from 2.00% to 3.00% per annum for base rate loans and 3.00% to 4.00% per annum for LIBOR loans.

The borrowing base under the Amended Credit Agreement is redetermined semi-annually, in May and November, by the lenders, in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. In connection with the pending Talos combination, the May 1, 2018 redetermination has been moved to June 1, 2018. Subject to certain exceptions, the Amended Credit Agreement is required to be guaranteed by all of the material domestic direct and indirect subsidiaries of the Company. As of March 31, 2018, the Amended Credit Agreement is guaranteed by Stone Energy Offshore, L.L.C. (“Stone Offshore”). The Amended Credit Agreement is secured by substantially all of the Company’s and its subsidiaries’ assets.

The Amended Credit Agreement provides for customary optional and mandatory prepayments, affirmative and negative covenants and events of default, including limitation on the incurrence of debt, liens, restrictive agreements, mergers, asset sales, dividends, investments, affiliate transactions and restrictions on commodity hedging. During the continuance of certain events of default, the lenders may take a number of actions, including declaring the entire amount then outstanding under the Amended Credit Agreement due and payable (in the event of certain insolvency-related events, the entire amount then outstanding under the Amended Credit Agreement will become automatically due and payable). The Amended Credit Agreement also requires maintenance of certain financial covenants, including (i) a consolidated funded debt to EBITDA ratio of not more than 2.50x for

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the test periods ending March 31, 2018, June 30, 2018, September 30, 2018 and December 31, 2018, respectively, 2.75x for the test period ending March 31, 2019, 3.00x for the test period ending June 30, 2019, 3.50x for the test periods ending September 30, 2019 and December 31, 2019, respectively, 3.00x for the test period ending March 31, 2020, 2.75x for the test periods ending June 30, 2020 and September 30, 2020, respectively, and 2.50x for the test periods ending December 31, 2020 and March 31, 2021, respectively, (ii) a consolidated interest coverage ratio of not less than 2.75 to 1.00, and (iii) a requirement to maintain minimum liquidity of at least 20% of the borrowing base. We were in compliance with all covenants under the Amended Credit Agreement as of March 31, 2018.

NOTE 9 – ASSET RETIREMENT OBLIGATIONS

The change in our asset retirement obligations during the three months ended March 31, 2018 (Successor) is set forth below (in thousands, inclusive of current portion):

Asset retirement obligations as of January 1, 2018 (Successor)	$	213,101
Liabilities settled		(20,734	)
Accretion expense		4,287
Asset retirement obligations as of March 31, 2018 (Successor)	$	196,654

NOTE 10 – INCOME TAXES

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). Generally effective for tax years 2018 and beyond, the Tax Act makes broad and complex changes to the Internal Revenue Code, including, but not limited to, (i) reducing the U.S. federal corporate tax rate from 35% to 21%; (ii) eliminating the corporate alternative minimum tax (“AMT”) and changing how existing AMT credits are realized; (iii) creating a new limitation on deductible interest expense; and (iv) changing rules related to uses and limitation of net operating loss carryforwards created in tax years beginning after December 31, 2017. As of March 31, 2018, we have not completed our accounting for the tax effects of enactment of the Tax Act. However, we have made a reasonable estimate of the effects on our existing deferred tax balances and recognized a provisional amount of $87.3 million to remeasure our deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. This amount is included as a component of income tax expense (benefit) from continuing operations and is fully offset by the related adjustment to our valuation allowance. We are still analyzing certain aspects of the Tax Act and refining our calculations, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts.

As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined during 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. As of March 31, 2018 (Successor), our valuation allowance totaled $127.1 million. Our assessment of the realizability of our deferred tax assets is based on the weight of all available evidence, both positive and negative, including future reversals of deferred tax liabilities.

We had a current income tax receivable of $36.3 million at December 31, 2017 (Successor), which related to expected tax refunds from the carryback of net operating losses to previous tax years. In January 2018, we received $20.1 million of the tax refund and have a current income tax receivable of $16.2 million at March 31, 2018 (Successor).

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NOTE 11 – FAIR VALUE MEASUREMENTS

U.S. Generally Accepted Accounting Principles establish a fair value hierarchy that has three levels based on the reliability of the inputs used to determine the fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

As of March 31, 2018 (Successor) and December 31, 2017 (Successor), we held certain financial assets that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. The income approach is used in this determination utilizing the third party’s proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy, and our collar and put contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars and puts were the volatility impacts in the pricing model as it relates to the call portion of the collar and the floor of the put. For a more detailed description of our derivative instruments, seeNote 7 – Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.

The following tables present our assets and liabilities that are measured at fair value on a recurring basis at March 31, 2018 (Successor) (in thousands).

	Fair Value Measurements Successor as of March 31, 2018
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	4,964	$	4,964	$	—	$	—
Derivative contracts		417		—		—		417
Total	$	5,381	$	4,964	$	—	$	417

	Fair Value Measurements Successor as of March 31, 2018
Liabilities	Total		Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative contracts	$	17,711	$	—	$	15,330	$	2,381
Total	$	17,711	$	—	$	15,330	$	2,381

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The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2017 (Successor) (in thousands).

	Fair Value Measurements Successor as of December 31, 2017
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	5,081	$	5,081	$	—	$	—
Derivative contracts		879		—		—		879
Total	$	5,960	$	5,081	$	—	$	879

	Fair Value Measurements Successor as of December 31, 2017
Liabilities	Total		Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative contracts	$	12,054	$	—	$	10,110	$	1,944
Total	$	12,054	$	—	$	10,110	$	1,944

The table below presents a reconciliation for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended March 31, 2018 (Successor) (in thousands).

	Hedging Contracts, net
Balance as of January 1, 2018 (Successor)	$	(1,065	)
Total gains/(losses) (realized or unrealized):
Included in earnings		(1,579	)
Included in other comprehensive income		—
Purchases, sales, issuances and settlements		680
Transfers in and out of Level 3		—
Balance as of March 31, 2018 (Successor)	$	(1,964	)
The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at March 31, 2018	$	(4,702	)

The fair value of cash and cash equivalents approximated book value at March 31, 2018 and December 31, 2017. As of March 31, 2018 and December 31, 2017, the fair value of the 2022 Second Lien Notes was approximately $229.5 million and $227.3 million, respectively. The fair value of the 2022 Second Lien Notes was determined based on quotes obtained from brokers, which represent Level 1 inputs.

On February 28, 2017, the Company emerged from bankruptcy and adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh start reporting

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date, February 28, 2017. SeeNote 3 – Fresh Start Accounting for a detailed discussion of the fair value approaches used by the Company. The inputs utilized in the valuation of our most significant asset, our oil and gas properties, included mostly unobservable inputs, which fall within Level 3 of the fair value hierarchy.

NOTE 12 – COMBINATION TRANSACTION COSTS

In connection with the pending combination with Talos, we incurred approximately $3.4 million in transaction costs during the three months ended March 31, 2018 (Successor). These costs consist primarily of legal and financial advisor costs and are included in salaries, general and administrative (“SG&A”) expense on our statement of operations for the three months ended March 31, 2018 (Successor). Additionally, we have incurred approximately $0.2 million of direct costs for purposes of registering equity securities to effect the Talos combination. These direct costs were recorded as a reduction of additional paid-in-capital during 2017. SeeNote 1 – Financial Statement Presentation (Pending Combination with Talos) for more information on the pending combination.

NOTE 13 – REVENUE RECOGNITION

Our major sources of revenue are oil, natural gas and NGL production from our oil and gas properties. We sell crude oil to purchasers typically through monthly contracts, with the sale taking place at the wellhead. Natural gas is sold to purchasers through monthly contracts, with the sale taking place at the wellhead or the tailgate of an onshore gas processing plant (after the removal of NGLs). We actively market our crude oil and natural gas to purchasers and the volumes are metered and therefore readily determinable. Sales prices for purchased oil and natural gas volumes are negotiated with purchasers and are based on certain published indices. Since the oil and natural gas contracts are month-to-month, there is no dedication of production to any one purchaser. We sell the NGLs entrained in the natural gas that we produce. The arrangements to sell these products first requires natural gas to be processed at an onshore gas processing plant. Once the liquids are removed and fractionated (broken into the individual hydrocarbon chains for sale), the products are sold by the processing plant. The residue gas left over is sold to natural gas purchasers as natural gas sales (referenced above). The contracts for NGL sales are with the processing plant. The prices received for the NGLs are not negotiated by the Company, but rather, are based on what the processing plant can receive from a third party purchaser. The gas processing and subsequent sales of NGLs are subject to contracts with longer terms and dedications of lease production from the Company’s leases offshore.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. SeeNote 1 – Financial Statement Presentation(Recently Adopted Accounting Standards). We adopted ASU 2014-09 on January 1, 2018 using the modified retrospective approach, with the cumulative effect of initially applying the new standard as an adjustment to accumulated deficit on the date of initial application. We applied the standard to contracts in place during 2017 and to new contracts entered into after January 1, 2018. The adoption of the standard did not have a material effect on our financial position, results of operations or cash flows.

We have historically recognized oil, natural gas and NGL production revenue under the entitlements method of accounting. Under this method, revenue was deferred for deliveries in excess of our net revenue interest, while revenue was accrued for undelivered or underdelivered volumes (production imbalances). Production imbalances were generally recorded at the estimated sales price in effect at the time of production. ASU 2014-09 effectively eliminated the entitlements method of accounting, requiring us instead to recognize production revenue for the quantities and values of oil, natural gas and NGLs delivered or received. Our aggregate imbalance positions at December 31, 2017 were immaterial and required only a $0.7 million cumulative effect adjustment (all of which related to oil production) to the January 1, 2018 opening balance of our accumulated deficit upon adoption of ASU 2014-09.

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Sales of oil, natural gas and NGLs are recognized when the product is delivered and title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred. To the extent actual quantities and values of oil, natural gas and NGL production for properties are not available for a given reporting period because of timing or information not received from the purchasers, the expected sales volumes and price are estimated and the result is recorded as purchaser accounts receivable (included in Accounts Receivable) in our balance sheet and as Oil, Natural Gas and NGL production revenue in our statement of operations. At March 31, 2018 (Successor), we recorded a purchaser accounts receivable of $31.2 million, consisting of $25.5 million of oil production revenue, $3.5 million of natural gas production revenue and $2.2 million of NGL production revenue. At December 31, 2017 (Successor), we recorded a purchaser accounts receivable of $32.8 million, consisting of $26.7 million of oil production revenue, $3.9 million of natural gas production revenue and $2.2 million of NGL production revenue. Revenue proceeds relating to third-party royalty owners not remitted by the end of a reporting period are recorded as Undistributed Oil and Gas Proceeds in our balance sheet.

NOTE 14 – PRODUCTION TAXES

Production taxes for the three months ended March 31, 2018 (Successor), the period of March 1, 2017 through March 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor) totaled ($2.2) million, $0.1 million and $0.7 million, respectively. During the three months ended March 31, 2018, we received a $2.4 million refund related to previously paid severance taxes in West Virginia.

NOTE 15 – COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.

Other Commitments and Contingencies

On March 21, 2016, we received notice letters from the Bureau of Ocean Energy Management (“BOEM”) stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at such time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM towards finalizing and implementing our long-term tailored plan. As of March 31, 2018, we have posted an aggregate of approximately $115 million in surety bonds in favor of BOEM, third-party bonds and letters of credit, all relating to our offshore abandonment obligations.

In July 2016, BOEM issued a Notice to Lessees (the “NTL”), with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurances by offshore lessees. The NTL details procedures to determine a lessee’s ability to carry out its lease obligations (primarily the decommissioning of facilities on the Outer Continental Shelf (“OCS”)) and whether to require lessees to furnish additional financial assurances to meet BOEM’s estimate of the lessees decommissioning obligations. The NTL supersedes the agency’s prior practice of allowing operators of a certain net worth to waive the need for supplemental bonds and provides updated criteria for determining a lessee’s ability to self-insure only a small portion of its OCS liabilities based upon the lessee’s financial capacity and financial strength. The NTL also allows lessees to meet their additional financial security requirements pursuant to an individually approved tailored plan, whereby an operator and BOEM agree to set a timeframe for the posting of additional financial assurances.

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We received a self-insurance letter from BOEM dated September 30, 2016 stating that we were not eligible to self-insure any of our additional security obligations. We received a proposal letter from BOEM dated October 20, 2016 indicating that additional security may be required. The September 30, 2016 self-insurance determination letter was rescinded by BOEM on March 24, 2017.

In the first quarter of 2017, BOEM announced that it would extend the implementation timeline for the July 2016 NTL by an additional six months. Furthermore, on April 28, 2017, President Trump issued an executive order directing the Secretary of the Interior to review the NTL to determine whether modifications are necessary to ensure operator compliance with lease terms while minimizing unnecessary regulatory burdens. On June 22, 2017, BOEM announced that, pending its review of the NTL, the implementation timeline would be indefinitely extended, subject to certain exceptions. At this time, it is uncertain when the July 2016 NTL will be implemented as a revised NTL. A revised tailored plan may require incremental financial assurance or bonding for non-sole liability properties, dependent on adjustments following ongoing discussions with BOEM and the Bureau of Safety and Environmental Enforcement (“BSEE”), and any modifications to the proposed NTL. There is no assurance that our current tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan.

NOTE 16 – SUBSEQUENT EVENTS

On May 1, 2018, Stone completed the acquisition of a 100% working interest in the Ram Powell Unit, including six lease blocks in the Viosca Knoll Area, the Ram Powell tension leg platform (“TLP”), and related assets, from Shell Offshore Inc., Exxon Mobil Corporation, and Anadarko US Offshore LLC, for a purchase price of $34 million, with an effective date of October 1, 2017, and the posting of decommissioning surety bonds of $200 million. After considering the effects of customary purchase price adjustments from the effective date of the acquisition through closing, Stone received net cash of $29.4 million at closing.

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Talos Production LLC

Talos Production Finance Inc.

Prospectus

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

(CUSIP Nos. 87484JAD2, 87484JAE0 and U83041AC4)

for

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

(CUSIP No. 87484JAF7)

that have been registered under the Securities Act

PROSPECTUS

Each broker-dealer that receives Exchange Notes for its own account pursuant to this Exchange Offer must acknowledge that it will deliver a prospectus (or, to the extent permitted by law, make available a prospectus to purchasers) in connection with any resale of such Exchange Notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus (or, to the extent permitted by law, make available a prospectus to purchasers), a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. 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 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.” In addition, until December 26, 2018, all dealers that effect transactions in the Exchange Notes, whether or not participating in this Exchange Offer, may be required to deliver a prospectus (or, to the extent permitted by law, make available a prospectus to purchasers). This is in addition to the dealers’ obligation to deliver a prospectus (or, to the extent permitted by law, make available a prospectus to purchasers) when acting as underwriters and with respect to their unsold allotments or subscriptions.

No person has been authorized to give any information or to make any representation other than those expressly contained in this prospectus, and, if given or made, any information or representations must not be relied upon as having been authorized. This prospectus does not constitute an offer to sell or the solicitation of an offer to buy any securities other than the securities to which it relates or an offer to sell or the solicitation of an offer to buy these securities in any circumstances in which this offer or solicitation is unlawful. Neither the delivery of this prospectus nor any sale made under this prospectus shall, under any circumstances, create any implication that there has been no change in our affairs since the date of this prospectus.

September 27, 2018