UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended September 30, 2018

OR

 

For the transition period from              to

 

Commission File Number: 001-38497

 

Talos Energy Inc.

(Exact Name of Registrant as Specified in its Charter)

 

 

Registrant’s telephone number, including area code: (713) 328-3000

 

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐

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

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

As of November 1, 2018, the registrant had 54,155,768 shares of common stock, $0.01 par value per share, outstanding.

 

 

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TABLE OF CONTENTS

 

 

 

 

 

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GLOSSARY

Barrel or Bbl. One stock tank barrel, or 42 United States gallons liquid volume.

Boe. One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.

Boepd. Barrels of oil equivalent per day.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas.

Deepwater. Water depths of more than 600 feet.

Developed acres. The number of acres that are allocated or assignable to producing wells or wells capable of production.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

Gross acres or gross wells. The total acres or wells in which the Company owns a working interest.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

MBblpd. One thousand barrels of crude oil or other liquid hydrocarbons per day.

MBoe. One thousand barrels of oil equivalent.

MBoepd. One thousand barrels of oil equivalent per day.

Mcf. One thousand cubic feet of natural gas.

Mcfpd. One thousand cubic feet of natural gas per day.

MMBoe. One million barrels of oil equivalent.

MMBtu. One million Btus.

MMcf. One million cubic feet of natural gas.

MMcfpd. One million cubic feet of natural gas per day.

MMMBtu. One billion Btus.

Net acres or net wells. The sum of the fractional working interests the Company owns in gross acres or gross wells.

NGL. Natural gas liquid. Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane and natural gasoline.

NYMEX. The New York Mercantile Exchange.

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NYMEX Henry Hub. Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub Index.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed reserves. In general, proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. The Securities and Exchange Commission provides a complete definition of developed oil and gas reserves in Rule 4-10(a)(6) of Regulation S-X.

Proved reserves. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves. In general, proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The Securities and Exchange Commission provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-X.

SEC. The Securities and Exchange Commission.

SEC pricing. The unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the prior twelve months, adjusted by lease for market differentials (quality, transportation, fees, energy content, and regional price differentials). The Securities and Exchange Commission provides a complete definition of prices in “Modernization of Oil and Gas Reporting” (Final Rule, Release Nos. 33-8995; 34-59192).

Shelf. Water depths up to 600 feet.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

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

WTI or West Texas Intermediate. A light crude oil produced in the United States with an API gravity of approximately 38-40 and the sulfur content is approximately 0.3%.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this report 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 report, 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 report, 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:

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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 Part II, Item 1A, “Risk Factors” which are included 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 report 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 report.

 

 

 

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TALOS ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

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TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per common share amounts)

(Unaudited)

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

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TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)

(In thousands)

(Unaudited)

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

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TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

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TALOS ENERGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 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.

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.

On 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 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, funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P. with respect to Series I (“Apollo Funds”), and entities related to 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 that 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 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.

Substantially concurrent therewith, we consummated the Exchange Offer and Consent Solicitation, pursuant to which the holders of the 7.50% Stone Senior Notes, excluding the 7.50% Stone Senior Notes held by the Franklin Noteholders and the MacKay Noteholders, exchanged their 7.50% Stone Senior Notes for 11.00% Senior Secured Notes and a cash payment, and a solicitation of consents to proposed amendments to the 7.50% Stone Senior Notes.

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Approximately $81.5 million in aggregate principal amount of the 7.50% Stone Senior Notes were validly tendered, and approximately $6.1 million in aggregate principal amount of 7.50% Stone Senior Notes remained outstanding as of the Closing Date.

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 in this report 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 consolidated format, it does not include all of the annual disclosures required by GAAP. 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.

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 covers periods prior to the Closing Date, reflects the assets, liabilities and results of operations of Talos Energy LLC and does not reflect the assets, liabilities and results of operations of Stone. These condensed consolidated financial statements should be read in conjunction with the Company’s audited financial statements and the notes thereto for the year ended December 31, 2017, which were filed by the Company on September 20, 2018 with the SEC on a Current Report on Form 8-K. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Statement of Changes in Stockholders’ Equity 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. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos Energy Inc.

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 that of the United States and are reported as one segment. See additional information in Note 4 – Property, Plant and Equipment.

Recently Adopted Accounting Standards

Revenue Recognition

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.

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The Company applied the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

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 stockholders’ 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 nine months ended September 30, 2018 was immaterial.

Recently Issued Accounting Standards

Leases

In February 2016, the FASB issued 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 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 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 condensed consolidated balance sheets.

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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, 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 units (“RSUs”), performance share units (“PSUs”) and outstanding warrants. See Note 9 – Earnings Per Share for additional information.

Share-Based Compensation

Subsequent to May 10, 2018, the Company issued RSUs and PSUs to certain employees and non-employee directors.  The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity, but is remeasured at each reporting period for awards classified as a liability. The Company records share-based compensation, net of actual forfeitures,  for the RSUs and PSUs in general and administrative expense on the condensed consolidated statement of operations, net of amounts capitalized to oil and gas properties. See Note 7 – Employee Benefits Plans and Share-Based Compensation for additional information.

RSUs. Share-based compensation is based on the market price of the Company’s Common Stock on the grant date and recognized over the vesting period using the straight-line method as the requisite service period is fulfilled.

PSUs. Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over the vesting period using the straight-line method. Estimates used in the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of Common Stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on the Company’s total shareholder return (“TSR”) relative to the TSR achieved by a specified industry peer group. Share-based compensation related to PSUs is recognized as the requisite service period is fulfilled, even if the market condition is not achieved.

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Note 3 — Acquisitions

Mexico Exchange

On September 11, 2018, the Company entered into a transaction with Hokchi Energy, S.A. de C.V., ("Hokchi"), a subsidiary of Pan American Energy LLC, to cross assign the Company's Participating Interest ("PI") in Block 2 and Hokchi's PI in Block 31, both in the Sureste Basin offshore Mexico. Under the agreed conditions for the swap, Talos will assign a 25% PI in Block 2 to Hokchi in exchange for a 25% PI in Block 31, which is immediately to the south of Block 2. Once the transaction is completed, Hokchi will be the operator of both blocks and Talos will own a 25% PI on Block 2 and a 25% PI on Block 31. On October 30, 2018, the Mexican oil & gas regulator, the National Hydrocarbons Commission (“CNH”) approved the PI transfer to Hokchi, subject to the approval from the CNH of the transfer of operatorship. The exploration campaign will begin on Block 2 during the second quarter of 2019, where two wells will be drilled, starting with the Acan prospect. Soon thereafter, Talos plans to participate in two wells in Block 31.

Acquisition of Whistler Energy II, LLC

On August 31, 2018, the Company completed the acquisition of all the issued and outstanding membership interests of Whistler Energy II, LLC (“Whistler”) from Whistler Energy II Holdco, LLC, an affiliate of Apollo Funds, for $52.3 million ($14.5 million net of $37.8 million of cash acquired). The $37.8 million of cash acquired consists of $30.8 million of cash collateral posted by Whistler released by third party surety companies at closing and $7.0 million of cash on hand for working capital purposes. Through the acquisition, the Company acquired all of Whistler’s oil and natural gas assets located in Green Canyon Block 18, Green Canyon Block 69 and Ewing Bank Block 988, including a fixed production platform on Green Canyon Block 18. The Company also assumed the associated asset retirement obligations. We refer to the acquisition as the “Whistler Acquisition.” The Whistler Acquisition qualified as an asset acquisition that requires, among other items, that the cost of the assets acquired and liabilities assumed be recognized on the condensed consolidated 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 and estimates at the time of the valuation. Transaction costs incurred on an asset acquisition are capitalized as a component of the assets acquired.

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on August 31, 2018 (in thousands):

 

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 concurrently 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.

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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):

The Company incurred approximately $83.7 million of transaction related costs, of which, $27.6 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.

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.

During the third quarter of 2018, certain adjustments were recorded to reflect new information obtained subsequent to recording the preliminary allocation of the purchase price. Income tax receivable was decreased by $5.5 million, trade receivables were increased by $1.0 million and unproved properties were increased by $4.5 million. Had these adjustments been recorded as of the acquisition date, May 10, 2018, there would have been no corresponding impact to net income subsequent to the acquisition. These adjustments are reflected in the preliminary purchase price allocation table below.

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):

 

Revenue attributable to the assets acquired in the Stone Combination during the three and nine months ended September 30, 2018 was $135.0 million and $204.3 million, respectively. Net income attributable to the assets acquired in the Stone Combination during the three and nine months ended September 30, 2018 was $76.0 million and $120.4 million, respectively.

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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 nine months ended September 30, 2018 and 2017 as if the Stone Combination had occurred on January 1, 2017. The unaudited pro forma 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.

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 less related income tax effects. The Company performs this ceiling test calculation each quarter utilizing SEC pricing. At September 30, 2018, the Company’s ceiling test computation of its U.S. oil and natural gas properties was based on SEC pricing of $66.43 per Bbl of oil, $2.89 per Mcf of natural gas and $29.18 per Bbl of NGLs. During the three and nine months ended September 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 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 September 30, 2018 and 2017 was $8.7 million and $3.6 million, respectively. Capitalized overhead for the nine months ended September 30, 2018 and 2017 was $16.2 million and $10.1 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.

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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 nine months ended September 30, 2018 were as follows (in thousands):

 

 

Note 5 — Financial Instruments

The following table presents the carrying amounts and estimated fair values of financial instruments (in thousands):

 

 

As of September 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 September 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.

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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 September 30, 2018 at their carrying value (see Note 6 – Debt). The fair value of the 7.50% Stone Senior 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 September 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, costless collars and put contracts. 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 a sold call option with no net premiums paid to or received from counterparties. Collar contracts typically require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price. 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 the maximum cash exposure to the Company. Under put contracts, monthly payments are made to the Company if the NYMEX prices fall below the agreed upon floor price, while allowing the Company to fully participate in commodity prices above the floor.

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 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):

 

 

The following table reflects the contracted volumes and weighted average prices the Company will receive under its derivative contracts as of September 30, 2018:

 

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Subsequent event. The following table reflects the contracted volumes and weighted average prices the Company will receive under its derivative contracts entered into subsequent to September 30, 2018, which are not reflected in the table above:

 

 

The Company’s commodity derivative instruments are measured at fair value based on third-party industry-standard models using various inputs substantially observable in active markets, including forward oil and natural gas price curves, and are therefore classified as Level 2 in the required fair value hierarchy for the periods presented. The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):

 

 

 

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 September 30, 2018 and December 31, 2017 (in thousands):

 

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 Credit Risk. The Company is subject to the risk of loss on its financial instruments as a result of nonperformance 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 September 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 counterparties 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.

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):

 

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.

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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 $0.1 million and $4.6 million of transaction fees related to the modification which were expensed and reflected in general and administrative expense on the condensed consolidated statements of operations during the three and nine months ended September 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.

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 September 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 has been released. The 7.50% Stone Senior Notes mature May 31, 2022 and have interest payable semi-annually 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. Talos Production LLC, a subsidiary of 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 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 the Company and certain of its 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 during the second quarter and fourth quarter. On October 31, 2018, the Company held the semi-annual redetermination and the results are expected during November of 2018. The next redetermination is scheduled for April 2019.

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As of September 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 September 30, 2018. As of September 30, 2018, the Bank Credit Facility had approximately $329.0 million of undrawn commitments (taking into account $6.0 million letters of credit and $265.0 million drawn from the Bank Credit Facility).

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 September 30, 2018, the outstanding balance under the Building Loan totaled $10.7 million. The Building Loan is collateralized by the Company’s two office buildings in Lafayette, Louisiana. 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 was in compliance with all covenants under the Building Loan as of September 30, 2018.

9.75% Senior Notes – due February 2018. The 2018 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

The Company maintains the Stone Energy Corporation Executive Severance Plan and Stone Energy Corporation Employee Severance Plan, each a legacy plan of Stone Energy Corporation. The plans provide for the payment of severance and change in control benefits to certain individuals who, prior to the transaction, were executive officers or employees of Talos Petroleum LLC (f/k/a Stone Energy Corporation), in each case upon an involuntary termination within twelve months of Closing. For the three and nine months ended September 30, 2018 the Company incurred nil and $7.5 million of severance expense, respectively, reflected in general and administrative expense on the condensed consolidated statement of operations. Approximately $1.7 million of such expense remained unpaid at September 30, 2018.

Talos Energy Inc. Long Term Incentive Plan

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, subject to Board approval, grants of 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 to employees, directors and consultants. The LTIP authorizes the Company to grant awards of up to 5,415,576 shares of the Company’s Common Stock.  

Restricted Stock Units – Non-employee Directors. On May 21, 2018, the Company granted 22,963 RSUs under the LTIP to non-employee directors. These RSUs had a grant date fair value of $0.8 million and vest on May 19, 2019, subject to such non-employee director’s continued service through the vesting date. Upon vesting, these RSUs represent a contingent right to receive one share of Common Stock for each RSU for 60% or 13,778 of these RSUs, and cash for the remaining 40% or 9,185 of these RSUs. The Company recognized $0.2 million and $0.3 million of share-based compensation expense for the three and nine months ended September 30, 2018, respectively. The total unrecognized share-based compensation expense related to these RSUs at September 30, 2018 was approximately $0.5 million, which is expected to be recognized over a weighted average period of 0.6 years. Of the unrecognized share-based compensation expense, $0.2 million relates to liability awards and will be subsequently remeasured at each reporting period.

Restricted Stock Units – Employees. During the three months ended September 30, 2018, the Company granted 116,448 RSUs under the LTIP to employees. These RSUs had a grant date fair value of $3.9 million and vest ratably over an approximate three year period beginning on May 14, 2018, subject to such employee’s continued service through the vesting date. Upon vesting, each RSU represents a contingent right to receive one share of Common Stock. The Company recognized $0.1 million of share-based compensation expense, net of $0.1 million capitalized to oil and natural gas properties, for the three and nine months ended September 30, 2018. The

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total unrecognized share-based compensation expense related to these RSUs at September 30, 2018 was approximately $3.7 million, which is expected to be recognized over a weighted average period of 2.6 years.

The following table summarizes RSU activity for the nine months ended September 30, 2018:

 

 

Performance Share Units – Employees. During the three months ended September 30, 2018, the Company granted 232,891 PSUs to employees with each PSU representing the contingent right to receive one share of Common Stock. However, the number of Common Stock shares issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on the total shareholder return (“TSR”) of the Common Stock relative to the TSR achieved by a specific industry peer group over an approximate three-year performance period, the last day of which is also the vesting date. The Company recognized $0.2 million of share-based compensation expense, net of $0.2 million capitalized to oil and natural gas properties, for the three and nine months ended September 30, 2018. The total unrecognized share-based compensation expense related to these PSUs at September 30, 2018 was approximately $10.0 million, which is expected to be recognized over a weighted average period of 2.6 years.

The following table summarizes PSU activity for the nine months ended September 30, 2018:

 

 

The grant date fair value of the PSUs, calculated using a Monte Carlo simulation, was $10.4 million.  The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted August 29, 2018 and September 28, 2018:

 

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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 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 three months ended September 30, 2018 and 2017, the Company recognized approximately $0.4 million and $0.3 million, respectively, as share-based compensation expense included in general and administrative expense on the condensed consolidated statement of operations and capitalized approximately $0.1 million and $0.3 million, respectively, into its oil and natural gas properties on the condensed consolidated balance sheet. During the nine months ended September 30, 2018 and 2017, the Company recognized approximately $0.6 million and $0.8 million, respectively, as share-based compensation expense included in general and administrative expense on the condensed consolidated statement of operations and capitalized approximately $0.3 million and $0.8 million, respectively, into its oil and natural gas properties on the condensed consolidated balance sheet.

The Company’s unrecognized compensation expense at September 30, 2018 is approximately $2.7 million. Of this amount, approximately $0.5 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 1.7 years.

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 Exchange, 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 on the condensed consolidated balance sheet. During the three months ended September 30, 2018 and 2017, the Company recognized $0.1 million and nil, respectively, as share-based compensation expense included in general and administrative expense on the condensed consolidated statement of operations and capitalized approximately $0.1 million and nil, respectively, into its oil and natural gas properties on the condensed consolidated balance sheet. During the nine months ended September 30, 2018 and 2017, the Company recognized approximately $1.3 million and nil, respectively, as share-based compensation expense included in general and administrative expense on the condensed consolidated statement of operations and capitalized approximately $2.4 million and nil, respectively, into its oil and natural gas properties on the condensed consolidated balance sheet.

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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 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 September 30, 2018 is approximately $2.3 million. Of this amount, approximately $0.2 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.

Share-based Compensation Expense, net

For the three and nine months ended September 30, 2018, the Company recognized total share-based compensation expense of $1.0 million and $2.5 million, net of amounts capitalized to oil and gas properties of $0.5 million and $3.0 million, respectively.  For the three and nine months ended September 30, 2017, the Company recognized total share-based compensation of $0.3 and $0.8 million, net of amounts capitalized to oil and gas properties of $0.3 and $0.8 million, respectively.  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 used in / provided by operating activities in our condensed consolidated statement of cash flows.

For the three and nine months ended September 30, 2018, share-based compensation expense did not have any associated income tax benefit.  Prior to the Stone Combination, the Company was not subject to income taxes.

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 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 obligations 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 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 was zero. The Company accounted for the book and tax basis difference from the Stone Combination in acquisition method accounting. Due to the valuation allowance, the net income tax impact was zero.  

As part of the Stone Combination, entities related to the Apollo Funds and Riverstone Funds contributed entities to the Company that were under common control. At September 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 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.

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As a result of the Stone Combination, the Company acquired a current income tax receivable of $10.7 million primarily related to the carryback of specified liability losses.  

Tax Cuts and Jobs Act. On December 22, 2017, the U.S. government enacted the Tax Act, which made broad and complex changes to the U.S. tax code. Due to the complexities involved in the accounting for the enactment of the new law, the SEC issued SAB 118, which provides guidance on the accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date to complete the accounting under ASC 740, "Income Taxes." In accordance with SAB 118, the Company was able to make reasonable estimates on certain effects of the Tax Act in the financial statements.  In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.  Although our net deferred tax assets and the related valuation allowance reflect the provisions of the Tax Cuts and Jobs Act (“TCJA”), due to the timing and the complexity of the provisions of the TCJA, further adjustments may be required during 2018 in determination of the final effect in our financial statements.  

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 RSUs, PSUs and outstanding warrants.

For the nine months ended September 30, 2018, the Company incurred a net loss and accordingly excluded all potentially dilutive securities from the determination of diluted earnings per share for such period as their impact on loss per common share would be antidilutive. As of September 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 ending February 28, 2021. As of September 30, 2018, the Company had 130,226 and 232,891 outstanding RSUs and PSUs, respectively, which settle in shares of Common Stock. 

For the three months ended September 30, 2018, dilutive weighted average shares for RSUs and PSUs totaled 8,241 shares resulting in an increase to basic weighted average common shares of 54,155,768 to arrive at diluted weighted average common shares outstanding of 54,164,009. For the three months ended September 30, 2018, 10,190 of weighted-average antidilutive RSUs were excluded from the computation of diluted net income per common share. Additionally, for the three months ended September 30, 2018, all outstanding warrants were considered antidilutive due to the exercise price of the warrants exceeding the average market price of Common Stock.

For the periods prior to May 10, 2018, the Company retrospectively adjusted the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination. There is no impact in fiscal year 2017 on diluted net income (loss) per common share from the RSUs and PSUs as these instruments didn’t exist throughout such period.

Note 10 — Related Party Transactions

Whistler Acquisition. On August 31, 2018, the Company acquired Whistler from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds, for $52.3 million ($14.5 million net of $37.8 million of cash acquired). Included in current assets acquired on August 31, 2018 is $2.1 million in receivables from an affiliate of the Apollo Funds to reimburse the Company for certain payments made or to be made post closing. See additional details in Note 3 – Acquisitions.

Equity Registration Rights Agreement. On the Closing Date, the Company entered into an Equity Registration Rights Agreement with each of the Apollo Funds, Riverstone Funds, Franklin and MacKay Shields relating to the registered resale of our Common Stock owned by such parties as of Closing. The Company will bear all of the expenses incurred in connection with the offer and sale, while the Apollo Funds, Riverstone Funds, Franklin and MacKay Shields will be responsible for paying underwriting fees, discounts and commissions or similar charges.  Fees incurred by the Company in conjunction with the Equity Registration Rights Agreement were $0.1 million for the three and nine months ended September 30, 2018.

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

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our executive officers, is a partner at Vinson & Elkins L.L.P. For the three and nine months ended September 30, 2018, we paid fees of approximately $5.0 million and $5.3 million, respectively, and for the three and nine months ended September 30, 2017, we paid fees of approximately $0.1 million and $0.1 million, respectively, for legal services performed by Vinson & Elkins L.L.P.

Contributions and Distributions. During the nine months ended September 30, 2018 and 2017, the Company did not receive any cash contributions or make any distributions to Apollo Funds and Riverstone Funds.

Transaction Fee Agreement. As part of the agreements with Apollo Funds and Riverstone Funds, the Company paid a transaction fee equal to 2% of capital contributions made by Apollo Funds and Riverstone Funds. For the nine months ended September 30, 2018 and 2017, there were no capital contributions and thus the Company did not incur or pay transaction fees related to capital contributions. In connection with the Stone Combination, the Transaction Fee Agreement was terminated on May 10, 2018.

Service Fee Agreement. The Company entered into service fee agreements with Apollo Funds and Riverstone Funds for the provision of certain management consulting and advisory services. Under each agreement, the Company 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 did not exceed in each case $0.5 million, in aggregate, for any calendar year. For the nine months ended September 30, 2018 and 2017, the Company incurred approximately $0.5 million and $0.4 million, respectively, for these services. For the three months ended September 30, 2017 the Company incurred $0.1 million, 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 as a result of the Stone Combination. The Apollo Funds and Riverstone Funds received $4.1 million and the Franklin Noteholders and McKay Noteholders received $3.3 million, respectively, as a result of the work fees paid.

Note 11 — Commitments and Contingencies

Capital Lease

As of September 30, 2018, the balance of the capital lease obligation on the condensed consolidated balance sheet was $96.8 million, of which $13.4 million is included in other current liabilities and $83.4 million is included in other long-term liabilities.

Performance Obligations

As of September 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 $647.0 million. The Mexico PSCs govern the exploration and extraction of the hydrocarbons in Mexico with the CNH. As of September 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 shelf drilling program. On July 30, 2018, the Company extended this contract nine months for a total of 278 days. 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 91 days during 2018, for approximately $6.8 million, and 187 days during 2019, for approximately $14.6 million. Total commitments for the Ensco 75 are $21.4 million.

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On June 18, 2018, the Company entered into an agreement for the Ensco 8503, a semi-submersible drilling rig. 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 $6.0 million and $6.5 million, respectively. The Ensco 8503 will be used to execute the appraisal of the Zama discovery in Mexico.

In connection with the Stone Combination, the Company entered into seismic use agreements totaling $46.8 million. As of September 30, 2018, the outstanding payments due are approximately $33.4 million consisting of $3.7 million, $9.9 million, $11.9 million and $7.9 million for the remainder of 2018, 2019, 2020 and 2021, respectively.

Subsequent Events

On October 8, 2018, the Company entered into a contract for Ensco 87, a jackup drilling rig, for the plugging and abandonment of two wells for a total of 40 days for a total commitment of $2.6 million during 2018.

On October 4, 2018, the Company entered into a contract for Noble Don Taylor, a drill ship, to execute a portion of its 2018 deepwater drilling program. Under the terms of the contract, the Company will pay a day rate of $130,000 for a minimum of 70 days. Total commitments for 2018 and 2019 are $7.9 million and $1.2 million, respectively. The total contract commitment for Noble Don Taylor is $9.1 million. The Company plans to drill and complete two deepwater wells in the Phoenix Field with an initial spud date planned for November 2018.

Note 12 — Condensed Consolidating Financial Information

The Company 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 the Company and certain of its 100% owned subsidiaries (“Guarantors”) on a senior unsecured 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 and Basis of Presentation, the Company retrospectively adjusted its consolidated equity to reflect the legal capital of the Company 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.

 

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TALOS ENERGY INC.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF SEPTEMBER 30, 2018

(In thousands)

(Unaudited)

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TALOS ENERGY INC.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2017

(In thousands)

 

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TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2018

(In thousands)

(Unaudited)

 

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TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2018

(In thousands)

(Unaudited)

 

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TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2017

(In thousands)

(Unaudited)

 

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TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2017

(In thousands)

(Unaudited)

 

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TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2018

(In thousands)

(Unaudited)

 

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TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2017

(In thousands)

(Unaudited)

 

 

Note 13 – Subsequent Events

Derivative Contracts

For additional information, see Note 5 – Financial Instruments.

Other Commitments

For additional information, see Note 11 – Commitments and Contingencies.

 

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

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 May 10, 2018 (the “Closing Date”), we (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”), Sailfish Merger Sub Corporation (“Merger Sub”), Talos Energy LLC and Talos Production LLC, pursuant to which each of Stone and Talos Energy LLC became our wholly-owned subsidiaries (the “Stone Combination”).  Substantially concurrent with the consummation of the transactions, we changed our name from Sailfish Energy Holdings Corporation to Talos Energy Inc.

Prior to the Stone Combination, Stone was an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. Stone operated in the Gulf of Mexico Basin from its incorporation in 1993 until the closing of the Stone Combination. The Stone properties acquired in the Stone Combination are located primarily in the deep water of the Gulf of Mexico, with limited exposure to Gulf of Mexico conventional shelf and deep gas properties. As of the closing of the Stone Combination, Stone’s property portfolio consisted primarily of nine active properties and 34 primary term leases in the Gulf of Mexico Basin.

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, funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”) and entities related to 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 us 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 that certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”), among us, 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 us in exchange for an aggregate of 2,874,049 shares of 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 (“11.00% Senior Secured Notes”) and (iii) Franklin Noteholders and 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.

Substantially concurrent therewith, we consummated the Exchange Offer and Consent Solicitation, pursuant to which the holders of the 7.50% Stone Senior Notes, excluding the 7.50% Stone Senior Notes held by the Franklin Noteholders and the MacKay Noteholders, exchanged their 7.50% Stone Senior Notes for 11.00% Senior Secured Notes and a cash payment, and a solicitation of consents to proposed amendments to the 7.50% Stone Senior Notes.

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Approximately $81.5 million in aggregate principal amount of the 7.50% Stone Senior Notes were validly tendered, and approximately $6.1 million in aggregate principal amount of 7.50% Stone Senior Notes remained outstanding as of the Closing Date.

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 our then outstanding common stock and the former stockholders of Stone held approximately 37% of our then outstanding common stock as of the Closing Date.

Unless otherwise indicated or the context otherwise requires, references in this report to “us,” “we,” “our” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries.

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 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.

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 its formation and certain matters contemplated by the Transaction Agreement. Talos Energy LLC is the acquirer of Stone for financial reporting and accounting purposes and considered the accounting acquirer in the Transactions under accounting principles generally accepted in the United States of America (“GAAP”). Accordingly, our historical financial and operating data, which covers periods prior to the Closing Date, reflects the assets, liabilities and results of operations of Talos Energy LLC prior to the Closing Date and does not reflect the assets, liabilities and results of operations of Stone prior to the Closing Date.

Whistler Acquisition

On August 31, 2018, we completed the acquisition of all the issued and outstanding membership interests of Whistler Energy II, LLC (“Whistler”) from Whistler Energy II Holdco, LLC, an affiliate of Apollo Funds, for $52.3 million ($14.5 million net of $37.8 million of cash acquired). See “Item 1, Condensed Consolidated Financial Statements, Note 3 — Acquisitions” for more information.

Transaction Expenses

We 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 Energy LLC that are not reflected in our comparative historical results of operations.

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 the Stone Combination, Talos Energy LLC was contributed to us and we are subject to U.S. federal and state income taxes.

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Third Party Planned Downtime

Since our operations are offshore, we are vulnerable to third party downtime events impacting the transportation, gathering or processing of production. We produce the Phoenix Field through the Helix Producer I (“HP-I”) which is leased from and operated by Helix Energy Solutions Group, Inc. (“Helix”). Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the United States Coast Guard, during which time we are unable to produce the Phoenix Field. The next dry-dock is scheduled for the first quarter of 2019 with an estimated shut-in lasting approximately 45 to 60 days. For the nine months ended September 30, 2018, the Phoenix Field produced 18.4 MBoepd.

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Results of Operations

Comparison of the Three Months Ended September 30, 2018 and 2017

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

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

 

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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 three months ended September 30, 2018 and 2017 (in thousands, except per Boe data):

 

Revenue. Total revenue for the three months ended September 30, 2018 was $282.9 million compared to $100.0 million for the three months ended September 30, 2017, an increase of approximately $182.9 million, or 183%.

Oil revenue increased approximately $164.1 million, or 195%, during the three months ended September 30, 2018 compared to the corresponding period in 2017. This increase was primarily due to an increase of $24.72 per Bbl in our realized oil sales price and a 18.3 MBblpd increase in oil production volumes. The increase in oil production volumes was attributable to 19.0 MBblpd from the Stone Combination and the Whistler Acquisition and 3.1 MBblpd from the Tornado II well in the Phoenix Field which commenced initial production in December 2017. The increase was partially offset by 2.4 MBblpd deferred production from the Phoenix Field for unplanned third party downtime for the HP-I and 0.7 MBblpd related to shut-in production for three days due to Tropical Storm Gordon.

Natural gas revenue increased approximately $9.0 million, or 81%, during the three months ended September 30, 2018 compared to the corresponding period in 2017. This increase was primarily due to a 32.8 MMcfpd increase in gas volumes, 28.2 MMcfpd of which was attributable to the Stone Combination and the Whistler Acquisition.

NGL revenue increased approximately $10.3 million, or 240%, during the three months ended September 30, 2018 compared to the corresponding period in 2017. This increase was due to an increase of $12.02 per Bbl in our realized NGL sales price and a 2.5 MBblpd increase in NGL volumes, the majority of which was attributable to the Stone Combination and the Whistler Acquisition.

Lease operating expense. Total lease operating expense for three months ended September 30, 2018 was $46.8 million compared to $28.6 million for the three months ended September 30, 2017, an increase of approximately $18.2 million, or 64%. This increase was primarily related to $15.0 million of lease operating expense incurred in connection with the Stone Combination and $0.7 million related to the Whistler Acquisition.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense for the three months ended September 30, 2018 was $87.8 million compared to $37.7 million for the three months ended September 30, 2017, an increase of approximately $50.1 million, or 133%. This increase was primarily due to a $3.08 per Boe, or 22%, increase in the depletion rate on our proved oil and natural gas properties during the three months ended September 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 three months ended September 30, 2018 was $21.7 million compared to $9.7 million for the three months ended September 30, 2017, an increase of approximately $12.0 million, or 124%. This increase was primarily attributable to $7.4 million in transaction and integration costs related to the Stone Combination and $2.5 million in additional payroll cost and additional general and administrative expenses as a result of the combined company.

Other operating expense. Other operating expense for the three months ended September 30, 2018 was $35.2 million compared to $10.7 million for the three months ended September 30, 2017, an increase of approximately $24.5 million, or 231%. This increase was primarily related to an increase of $7.8 million and $6.8 million in workover and maintenance expense and accretion expense, respectively, incurred in connection with the Stone Combination. This increase also relates to $3.8 million in repairs on the South Marsh Island 130 Field and $3.6 million in preparation for the HP-I dry dock operation repairs in the first quarter of 2019.

Price risk management activities. Price risk management activities for the three months ended September 30, 2018 resulted in a $53.3 million expense compared to an expense of $28.1 million for the three months ended September 30, 2017. The expense of $53.3 million for the three months ended September 30, 2018 consists of $40.7 million in cash settlement losses and $12.6 million in non-cash losses from the decrease in the fair value of our open derivative contracts. The expense of $28.1 million for the three months ended September 30, 2017 consists of cash settlement gains of $8.6 million offset by a $36.7 million in non-cash losses from the decrease in the fair value of our open derivative contracts. These unrealized gains or losses 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.

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Comparison of the Nine Months Ended September 30, 2018 and 2017

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

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

 

 

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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 nine months ended September 30, 2018 and 2017 (in thousands, except per Boe data):

 

Revenue. Total revenue for the nine months ended September 30, 2018 was $632.6 million compared to $297.2 million for the nine months ended September 30, 2017, an increase of approximately $335.4 million, or 113%.

Oil revenue increased approximately $309.4 million, or 126%, during the nine months ended September 30, 2018 compared to the corresponding period in 2017. This increase was primarily due to an increase of $21.33 per Bbl in our realized oil sales price and a 10.6 MBblpd increase in oil production volumes. The increase in oil production volumes was attributable to 9.6 MBblpd from the Stone Combination and the Whistler Acquisition and 3.3 MBblpd from the Tornado II well in the Phoenix Field which commenced initial production in December 2017. The increase in production was partially offset by unplanned third party downtime.

Natural gas revenue increased approximately $12.1 million, or 33%, during the nine months ended September 30, 2018 compared to the corresponding period in 2017. This increase was due to a 15.7 MMcfpd increase in gas production volumes, which was attributable to 15.9 MMcfpd from the Stone Combination and Whistler Acquisition. The increase in production was partially offset by a $0.06 per Mcf decrease in our realized gas sales price.

NGL revenue increased approximately $15.9 million, or 140%, during the nine months ended September 30, 2018 compared to the corresponding period in 2017. This increase was due to an increase of $9.06 per Bbl in our realized NGL sales price and a 1.3 MBblpd increase in NGL volumes, 1.2 MBblpd of which was attributable to the Stone Combination and Whistler Acquisition.

Lease operating expense. Total lease operating expense for the nine months ended September 30, 2018 was $113.7 million compared to $91.4 million for the nine months ended September 30, 2017, an increase of approximately $22.3 million, or 24%. This increase was primarily related to $25.0 million of lease operating expense in connection with the Stone Combination and $0.7 million of lease operating expense in connection with the Whistler Acquisition.

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Depreciation, depletion and amortization. Depreciation, depletion and amortization expense for the nine months ended September 30, 2018 was $204.6 million compared to $113.8 million for the nine months ended September 30, 2017, an increase of approximately $90.8 million, or 80%. This increase was primarily due to a $2.83 per Boe, or 20%, increase in the depletion rate on our proved oil and natural gas properties during the nine months ended September 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.

General and administrative expense. General and administrative expense for the nine months ended September 30, 2018 was $61.1 million compared to $26.9 million for the nine months ended September 30, 2017, an increase of approximately $34.2 million, or 127%. This increase was primarily attributable to $27.6 million in transaction related costs related to the Stone Combination and $5.4 million in additional payroll cost and additional general and administrative expenses as a result of the combined company.

Other operating expense. Other operating expense for the nine months ended September 30, 2018 was $74.1 million compared to $38.2 million for the nine months ended September 30, 2017, an increase of approximately $35.9 million, or 94%. This increase was primarily related to an increase of $12.3 million and $10.9 million in workover and maintenance expense and accretion expense, respectively, in connection with the Stone Combination. This increase also relates to a $14.0 million increase in repairs and maintenance during the nine months ended September 30, 2018 primarily related to $8.8 million in repairs on the South Marsh Island 130 Field.

Price risk management activities. Price risk management activities for the nine months ended September 30, 2018 resulted in a $196.5 million expense compared to income of $56.8 million for the nine months ended September 30, 2017. The expense of $196.5 million for the nine months ended September 30, 2018 consists of $94.8 million in cash settlement losses and $101.7 million in non-cash losses from the decrease in the fair value of our open derivative contracts. The income of $56.8 million for the nine months ended September 30, 2017 consists of cash settlement gains of $22.3 million and a $34.5 million in non-cash gains from the increase in the fair value of our open derivative contracts. 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.

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 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 beyond June 30, 2017 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.

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Deepwater Operations. We have interests in six deepwater fields in the Gulf of Mexico, 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.

Commitments and Contingencies

For a further discussion of our commitments and contingencies, see “Item 1, Condensed Consolidated Financial Statements, Note 11 – Commitments and Contingencies.”

Income Tax Effect

For the three and nine months ended September 30, 2018, our effective tax rate was 0%. Our effective tax rate in 2018 differed from the statutory rate of 21%, as a result of recognition of a full valuation allowance on our deferred tax assets. For the three and nine months ended September 30, 2018, we recorded a full valuation allowance against our net deferred tax assets.

Supplemental Non-GAAP Measure

Adjusted EBITDA

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

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The following table presents 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):

 

 

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility. Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. As of September 30, 2018, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $419.0 million.

As of September 30, 2018, total debt, net of discount and deferred financing costs, was approximately $654.8 million, comprised of our $380.6 million aggregate principal amount of the 11.00%  Senior Secured Notes and $6.1 million aggregate principal amount of our 7.50% Stone Senior Notes, $257.4 million outstanding under our Bank Credit Facility, and $10.7 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 September 30, 2018. For additional details on our debt, see “Item 1, Condensed Consolidated Financial Statements, Note 6 –Debt.”

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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 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 September 30, 2018, we had secured 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 $647.0 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 allows qualifying operators to self-insure for an amount up to 10% of their tangible net worth. The 2016 NTL also provides for operators to propose a tailored plan subject to BOEM approval that allows the posting of additional financial assurance over time. However, BOEM has indefinitely delayed beyond June 30, 2017 implementation of the 2016 NTL, except in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities, to allow BOEM time to reconsider a number of regulatory initiatives. We received notice from the BOEM in late 2016 ordering us to provide additional financial assurances in the form of additional security in material amounts. We entered into discussions with BOEM regarding the requested security and submitted a proposed tailored plan for the posting of additional financial security to the agency for review. However, as noted, BOEM has indefinitely delayed implementation beyond June 30, 2017 of the 2016 NTL, has rescinded the late December 2016 orders while BOEM reviews its financial assurance program and, to date, has taken no action with respect to our previously submitted proposed tailored plan. 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 2016 NTL, BOEM may also increase its financial assurance requirements mandated by rule for all companies operating in federal waters. BOEM could also make new demands for additional financial security in material amounts in the event the agency chooses to implement the 2016 NTL, and such amounts may be material and exceed our capability to provide additional financial assurance. The future cost of compliance with our existing supplemental bonding requirements, including with respect to any tailored plan, the 2016 NTL, 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.

11.00% Senior Secured 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 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 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.

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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. We incurred approximately $0.1 million and $4.6 million of transaction fees related to the exchange of 11.00% Bridge Loans and 7.50% Stone Senior Notes into 11.00% Senior Secured Notes, which were expensed and reflected in general and administrative expense during the three and nine months ended September 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 September 30, 2018.

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, we may, at our 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, we 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.

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 has been released. The 7.50% Stone Senior Notes mature May 31, 2022 and have interest payable semi-annually 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

Talos Production LLC, our subsidiary, 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. On October 31, 2018, the Company held the semi-annual redetermination and the results are expected during November of 2018. The next redetermination is scheduled for April 2019.

As of September 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 September 30, 2018. As of September 30, 2018, the Bank Credit Facility had approximately $329.0 million of undrawn commitments (taking into account $6.0 million letters of credit and $265.0 million drawn from the Bank Credit Facility).

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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 September 30, 2018, the outstanding balance under the Building Loan totaled $10.7 million. We were in compliance with all covenants under the Building Loan as of September 30, 2018.

2018 Senior Notes

9.75% Senior Notes – due February 2018. The 2018 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):

  

Operating Activities. Net cash provided by operating activities increased $19.3 million in the nine months ended September 30, 2018 compared to the corresponding period in 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 $198.3 million in the nine months ended September 30, 2018 compared to the corresponding period in 2017 primarily attributable to $280.7 million of cash received for the Stone Combination and Whistler Acquisition, partially offset by an increase of $82.4 million in capital expenditures.

Financing Activities. Net cash used in financing activities increased $175.0 million in the nine months ended September 30, 2018 compared to the corresponding period in 2017 primarily attributable to the repayment of $403.0 million related to the Old Bank 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 $17.0 million in deferred financing cost, partially offset by proceeds received from the Bank Credit Facility of $319.0 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.

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The following is a table of our capital expenditures for the nine months ended September 30, 2018 (in thousands):

 

  

 

Capital expenditures and plugging and abandonment for the remainder of 2018 are estimated to be approximately $120.0 million to $140.0 million, which we plan to fund through cash flows from operations and borrowings under our Bank Credit Facility.

Off-Balance Sheet Arrangements

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

Contractual Obligations and Other Contingencies

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 September 30, 2018 (in thousands):

 

Performance Bonds. As of September 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 under the PSCs totaling approximately $647.0 million and $287.8 million, respectively. As of September 30, 2018 and December 31, 2017, we had $6.0 million and $4.0 million, respectively, in letters of credit issued under our Bank Credit Facility and the Old Bank Credit Facility primarily for the plugging and abandonment of wells and the removal of facilities.

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For additional information about certain of our obligations and contingencies, see Item 1, Notes to Condensed Consolidated Financial Statements, Note 11 – Commitments and Contingencies.

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 “Part I, Item 1, Condensed Consolidated Financial Statements, Note 2 – Summary of Significant Accounting Policies” of our condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q. Our other significant accounting policies that are not referenced in Note 2 can be found within Talos Energy LLC’s audited financial statements and the notes thereto for the year ended December 31, 2017, which we filed on September 20, 2018 with the SEC on a Current Report on Form 8-K.  

Oil and Natural Gas Properties

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

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

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

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

We recognize transportation costs as a component of direct lease operating expense when we are the shipper of the product. Such costs during the three and nine months ended September 30, 2018 were $3.7 million and $9.5 million, respectively, and $7.5 million and $2.5 million during the three and nine months ended September 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 September 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.

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).

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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, Imbalances and Production Handling Fees

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.

Under previous accounting guidance, we used the entitlement method to account for sales and production. Under the entitlement method, revenue was recorded based on our 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. Our imbalances are recorded gross on our consolidated balance sheets. At September 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.

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 nine months ended September 30, 2018 was immaterial.

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 September 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.

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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 “Part I, Item 1, Condensed Consolidated Financial Statements, Note 1 – Formation and Basis of Presentation” for Recently Adopted Accounting Standards by the Company.  

Recently Issued Accounting Standards

See “Part I, Item 1, Condensed Consolidated Financial Statements, Note 1 – Formation and Basis of Presentation” for Recently Issued Accounting Standards applicable to the Company.

 

Item 3. 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 nine months ended September 30, 2018, our average oil price realizations after the effect of derivatives increased 10% to $56.25 per Bbl from $51.07 per Bbl in the comparable 2017 period. Our average natural gas prices realizations after the effect of derivatives increased 4% during the nine months ended September 30, 2018 to $3.02 per Mcf from $2.91 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, costless collars and put contracts. These derivative 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.

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We had commodity derivative instruments in place to reduce the price risk associated with future production of 12,123 MBbls of crude oil and 6,939 MMBtu of natural gas at September 30, 2018, with a net derivative liability position of $198.3 million. For additional information regarding our commodity derivative instruments, see “Item 1, Condensed Consolidated Financial Statements, Note 5 – Financial Instruments.” 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 September 30, 2018 (in thousands):

 

Variable Interest Rate Risks

We had total debt outstanding of $654.8 million at September 30, 2018, net of unamortized original issue discount and deferred financing costs. Of this, $397.3 million was from our 11.00% Senior Secured Notes, 7.50% Stone Senior Notes and Building Loan, which bear interest at fixed rates. The remaining $257.4 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 61% of our debt. The interest rate on our variable rate debt at September 30, 2018 was 5.07%. A 10% change in the interest rate on this variable rate debt balance at September 30, 2018 would change interest expense for the nine months ended September 30, 2018 by approximately $0.4 million.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, our principal executive officer and principal financial officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this Quarterly Report on Form 10-Q.  Our disclosure controls and procedures are designed to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2018.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

There have been no material developments with respect to the information previously reported under Part II, Item 1 of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2018.

Item 1A. Risk Factors

Certain factors may have a material adverse effect on our business, financial condition, and results of operations. You should consider carefully the risks and uncertainties described below, in addition to other information contained in this Quarterly Report on Form 10-Q, including our condensed consolidated financial statements and related notes. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we currently believe are not material, may also become important factors that adversely affect our business. If any of the following risks actually occur, our business, financial condition, results of operations, and future prospects could be materially and adversely affected. In that event, the trading price of our common stock could decline, and you could lose part or all of your investment.

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, 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 Amended and Restated Certificate of Incorporation, Amended and Restated 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 NYSE listing rules and, therefore, we are not subject to NYSE requirements that would otherwise require us to have a majority of independent directors and nominating and compensation committees composed solely of independent directors. We have not elected 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.

The Apollo Funds and the 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. The Apollo Funds and the Riverstone Funds may have different interests than other holders of our common stock and may make decisions adverse to your interests.

Among other things, the 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 LLC. These expenses could, particularly in the near term, reduce the expected pre-tax synergies related to the integration of the businesses following the completion of the Stone Combination, and accordingly, any net synergies may not be achieved in the near term or at all. These integration expenses may result in us taking significant charges against earnings following the completion of the Stone Combination.

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The corporate opportunity provisions in our Amended and Restated Certificate of Incorporation could enable others to benefit from corporate opportunities that might otherwise be available to us.

Subject to the limitations of applicable law, our Amended and Restated Certificate of Incorporation, among other things:

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

Our Amended and Restated Certificate of Incorporation 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 Amended and Restated Certificate of Incorporation 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 Amended and Restated Certificate of Incorporation or Amended and Restated 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 Amended and Restated Certificate of Incorporation. 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 Amended and Restated Certificate of Incorporation 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 all or a portion of their 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.

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For 12 months following the completion of the Stone Combination, the Apollo Funds and the Riverstone Funds are prohibited from transferring all or a portion of their shares of our common stock other than to their respective affiliates, unless such transfer is approved by a majority of the Company Independent Directors. The lockup will cease to apply to 50% of our common stock that was issued to the Apollo Funds and the Riverstone Funds, respectively, at the closing of the Stone Combination on the six-month anniversary of the Closing Date and will cease to apply to an additional 25% of our common stock that was issued to the Apollo Funds and the Riverstone Funds, respectively, at the closing of the Stone Combination on the nine-month anniversary of the Closing Date. Following such lockup periods, 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 access funds under our Bank Credit Facility and through the capital markets. The amount available for borrowing under our Bank Credit Facility is subject to a borrowing base, which is determined by the lenders taking into account our estimated proved reserves, and is subject to periodic redeterminations based on pricing models to be determined by the lenders at such time. Oil and natural gas prices significantly declined in the second half of 2014, with sustained lower prices continuing throughout 2015, 2016 and 2017. Despite a modest recovery in late 2017, commodity prices could remain suppressed or decline further in the future, which will likely have material adverse effects on our proved reserves and borrowing base. Further, because we use the full cost method of accounting for our oil and gas operations, we perform a ceiling test each quarter, which is impacted by declining prices. Significant price declines could cause us to take ceiling test write-downs, which would be reflected as non-cash charges against current earnings. See the Risk Factor entitled “Lower oil and natural gas prices and other factors in the future may result in ceiling test write-downs and other impairments of our asset carrying values” for further discussion.

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

The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. For example, during the period January 1, 2015 through September 30, 2018, The New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) crude oil price per Bbl ranged from a low of $30.62 to a high of $70.58, 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 depend upon many factors beyond our control, including, among others:

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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. Because oil, natural gas and NGLs accounted for approximately 72%, 21% and 7%, respectively, of our estimated proved reserves as of December 31, 2017, and approximately 67%, 26% and 7%, respectively, of our 2017 production on an MBoe basis, our financial results will be sensitive to movements in oil, natural gas and NGL prices.

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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. The 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 we or 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.

On September 11, 2018, we entered into a transaction with Hokchi Energy, S.A. de C.V. (“Hokchi”), a subsidiary of Pan American Energy LLC, to cross assign our participation interest in Block 2 and Hokchi’s participation in Block 31, both in the Sureste Basin offshore Mexico. Upon the completion of the transaction, which is conditioned on and subject to approval by the CNH, Hockchi will be the operator of both blocks, we will own a participation interest in Block 31 of 25% and our participation interest in Block 2, as well as our financial guarantee with respect to Block 2, will decrease from 45% to 25%.

Our debt level and the covenants in our current or future agreements governing our debt, including our Bank Credit Facility and the indenture for our 11.00% Senior Secured Notes, could negatively impact our financial condition, results of operations, and business prospects. Our failure to comply with these covenants could result in the acceleration of our outstanding indebtedness.

The terms of the agreements governing our debt impose significant restrictions on our ability to take a number of actions that we may otherwise desire to take, including:

Our level of indebtedness, and the covenants contained in the agreements governing our debt, including the Bank Credit Facility and the indenture for our 11.00% Senior Secured Notes, have important consequences on our operations, including:

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We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of repayment of outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions. Sustained low oil and natural gas prices have a material and adverse effect on our liquidity position. Our cash flow is highly dependent on the prices we receive for oil and natural gas, which have declined significantly since mid-2014.

We depend on our Bank Credit Facility for a portion of our future capital needs. We are required to comply with certain debt covenants and, beginning with the fiscal quarter ending September 30, 2018, certain financial ratios under the Bank Credit Facility. Our borrowing base under the Bank Credit Facility, which is redetermined semi-annually, is based on an amount established by the lenders after their evaluation of our proved oil and natural gas reserve values. If, due to a redetermination of our borrowing base, our outstanding borrowings plus outstanding letters of credit exceed our redetermined borrowing base (referred to as a borrowing base deficiency), we could be required to repay such borrowing base deficiency. Our Bank Credit Facility allows us to cure a borrowing base deficiency through any combination of the following actions: (i) repay amounts outstanding sufficient to cure the borrowing base deficiency within 30 days after the existence of such deficiency; (ii) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in such oil and gas properties within 30 days after the existence of such deficiency; (iii) pay the deficiency in four equal monthly installments with the first installment due within 30 days after the existence of such deficiency; or (iv) any combination of the above. We are required to elect one of the foregoing options within 10 days after the existence of such deficiency.

We may not have sufficient funds to make such repayments. If we do not repay our debt out of cash on hand, we could attempt to restructure or refinance such debt, reduce or delay investments and capital expenditures, sell assets, or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flows from operating activities to pay the interest on our debt or that future borrowings, equity financings, or proceeds from the sale of assets are available to pay or refinance such debt. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our debt, including our Bank Credit Facility and the indenture for our 11.00% Senior Secured Notes, may also prohibit us from taking such actions. Factors that affect our ability to raise cash through offerings of our capital stock, a refinancing of our debt, or a sale of assets include financial market conditions and our market value and operating performance at the time of such offerings, refinancing, or sale of assets. We cannot assure you that any such offerings, restructuring, refinancing, or sale of assets would be successfully completed.

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

BSEE and BOEM have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these added and more stringent regulatory requirements and with existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill response, and decommissioning plans and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico and, as a result, are continuing to develop and implement new, more restrictive requirements. For example, in April 2016, BSEE published a final rule on well control that, among other things, imposes rigorous standards relating to the design, operation, and maintenance of blow-out preventers, real-time monitoring of deepwater and high temperature, high pressure drilling activities, and enhanced reporting requirements. Pursuant to President Trump’s Executive Orders dated March 28, 2017, and April 28, 2017 (the “Executive Orders”), respectively, BSEE initiated a review of the well control regulations to determine whether the rules are consistent with the stated policy of encouraging energy exploration and production, while ensuring that any such activity is safe and environmentally responsible. One consequence of this review is that on September 28, 2018, BSEE published final revisions to its regulations regarding offshore drilling safety equipment, which 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.

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 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 (the “DOI”) 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 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 BOEM and BSEE could result in increased financial assurance requirements and incurrence of associated added costs, limit operational activities in certain areas, or cause us to incur penalties or shut-in production at one or more of our facilities. Also, if material spill incidents were to occur in the future, the United States or other countries where such an event may occur could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations.

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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.

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, BOEM issued 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, ROWs or RUEs.  The 2016 NTL became effective in September 2016, but BOEM has since extended indefinitely beyond June 30, 2017 the start date for implementing this NTL, expect in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities, so as to provide BOEM with time to review its complex financial assurance program.

In late 2016, we received orders from BOEM to provide additional financial assurance in material amounts relating to our OCS properties (the “BOEM 2016 Orders”). We entered into discussions with BOEM regarding the requested additional financial security and submitted a proposed tailored plan for the posting of additional financial security to the agency for review. However, as noted, BOEM has indefinitely delayed beyond June 30, 2017 implementation of the 2016 NTL, has rescinded the BOEM 2016 Orders while BOEM reviews its financial assurance program and, to date, has taken no action with respect to our previously submitted proposed tailored plan.

As of the filing date of this Quarterly Report on Form 10-Q, we have no outstanding BOEM orders for financial assurance obligations although we are in discussions with the agency regarding providing financial assurance in what we view as the normal course of business for one well, Mount Providence, that was completed July 2018.  Following completion of its review of its financial assurance program, BOEM may elect to retain the 2016 NTL in its current form or may make revisions thereto. Thus, until the review is completed and BOEM determines what additional financial assurance may be required by us, we cannot provide any assurance of the amount of any additional financial assurance, which may be material, that may be ordered by BOEM and required in any proposed tailored plan that we may submit to BOEM in the future for approval, or that such additional financial assurance amounts can be obtained.  Moreover, BOEM could in the future make new demands for additional financial assurances in material amounts relating to the decommissioning of our OCS properties. BOEM may reject our proposals to satisfy any such additional financial assurance coverage and make demands that exceed our capabilities.

If we fail to comply with the current or future orders of BOEM to provide additional surety bonds or other financial assurances, 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 2016 NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the OCS, which could 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 will be 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.

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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”). 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. Any failure to comply with the SECP could result in a 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 our 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:

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

We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production. Accordingly, we are dependent upon distributions from Talos Production to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock.

We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production. We have no independent means of generating revenue. To the extent Talos Production has available cash, we will cause Talos Production to make distributions of cash to us, directly and indirectly through our wholly owned subsidiaries, to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock. As we have never declared or paid any cash dividends on our common stock, we anticipate that any available cash, other than the cash distributed to us to pay taxes and cover our corporate and other overhead expenses, will be retained by Talos Production to satisfy its operational and other cash needs. Accordingly, we do  not anticipate paying any cash dividends on our common stock in the foreseeable future. Although we do not expect to pay dividends on our common stock, if our board of directors decides to do so in the future, our ability to do so may be limited to the extent Talos Production is limited in its ability to make distributions to us, including due to the significant restrictions the agreements governing Talos Production’s debt impose on the ability of Talos Production to make distributions and other payments to us. To the extent that we need funds and Talos Production is restricted from making such distributions under applicable law or regulation or under the terms of our financing agreements,  or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial  condition.

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 and in the shallow waters off the coast of Mexico. Unlike other entities that are geographically 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 in the shallow waters off the coast of Mexico means that some or all of the properties could be affected should the region experience:

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.

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

Our production is primarily associated with our properties in the Gulf of Mexico and in the shallow waters off the coast of Mexico. 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 and our Pompano 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 three months ended September 30, 2018, approximately 51% of our production and 56% of our oil, natural gas, and NGL revenue was attributable to our Phoenix Field and our Pompano Field, both of which are located in the federal waters offshore in the Gulf of Mexico. This concentration in these fields means that any impact on our production from these fields, whether because of mechanical problems, adverse weather, well containment activities, changes in the regulatory environment, or otherwise, could have a material effect on our business. We produce the Phoenix Field through the Helix Producer I (“HP-I”) a dynamically positioned floating production facility that is operated by Helix Energy Solutions Group, Inc. (“Helix”). The HP-I interconnects the Phoenix Field through a production buoy that can be disconnected if the HP-I cannot maintain its position on station, such as in the event of a mechanical problem with the dynamic positioning system or the approach of a hurricane. Because the HP-I may have to be disconnected from the Phoenix Field if circumstances require, our production from the Phoenix Field may be subject to more frequent interruptions than if the Phoenix Field was produced by a more conventional platform. We are also required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the United States Coast Guard, during which time we are unable to produce the Phoenix Field. The next inspection of the HP-I is scheduled during the first quarter of 2019. On September 10, 2016, the HP-I was disconnected from the production buoy and released for dry dock for 28 days. Upon completion of the dry dock, the HP-I remained disconnected from the buoy connecting it to the Phoenix Field due to Federal Emergency Management Agency testing of test upgrades to the power management system, preventing us from reconnecting the HP-I to the Phoenix Field for a further five days. Once the buoy was connected, Phoenix Field production remained shut-in for an additional five days to conduct buoy remediation of the swivel piping. In addition, for 25 days in March 2015, we were required to disconnect the HP-I from the production buoy due to upgrades to the power management system of the vessel, which is an integral part of the dynamic positioning system. The upgrade work was followed by sea trials that tested the dynamic positioning system and were required by various regulatory groups, including the United States Coast Guard.

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

In addition, all of our production from the Phoenix Field flows through the Green Canyon 19 connection facility operated by Shell GOM Pipeline Company LLC. To the extent Shell GOM Pipeline Company LLC temporarily shuts in its Green Canyon 19 connection 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.

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In addition, all of our production from the Pompano Field flows through the Pompano Pipeline System operated by Crimson Gulf LLC. To the extent Crimson Gulf LLC temporarily shuts in the Pompano Pipeline System,   whether for maintenance or otherwise, we would not able to produce the Pompano 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 Pompano Field are less than our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

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

We 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, generally we are 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.

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

We reevaluate the purchase of insurance, policy limits, and terms annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are 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.

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

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

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

Our oil and gas operations are subject to various international, foreign 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 P&A 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.

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

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

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

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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.

Our Mexican operations are subject to certain offshore regulatory and environmental laws and regulations promulgated by 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.

In addition, 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 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.

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.

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

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

Estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. Additionally, our interpretations of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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

The 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.

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At September 30, 2018, approximately 31% of our estimated proved reserves (by volume) were undeveloped and approximately 20% were non-producing. Any or all of our proved undeveloped (“PUD”) or proved developed non-producing reserves may not be ultimately developed or produced. Furthermore, any or all of our undeveloped and developed non-producing reserves may not be ultimately produced during the time periods we plan or at the costs we budget, which could result in the write-off of previously recognized reserves. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumptions that we incur capital expenditures to develop these undeveloped reserves and the actual costs and results associated with these properties may not be as estimated. Any material inaccuracies in these reserve estimates or underlying assumptions materially affects the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

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

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

SEC rules require that, subject to limited exceptions, PUD 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 PUD reserves as we pursue our drilling program. Moreover, we may be required to write down our PUD 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 September 30, 2018, we did not have any leases covering the undeveloped acres that could potentially expire during the remainder of the 2018 fiscal year.

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

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

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

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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.

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:

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, collisions 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.

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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 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.

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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 considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased or decreased costs. As a result, we may significantly increase or decrease our estimated asset retirement obligations in future periods. For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes and other adverse weather conditions. The estimated costs to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimates of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane or other natural disaster. Also, a sustained lower commodity price environment may cause our non-operator partners to be unable to pay their share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs.

Moreover, the timing for pursuing restoration and removal activities has accelerated for operators in the U.S 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 P&A obligations on us or other predecessors-in-interest, which could be significant and adversely affect our business, results of operations, financial condition and cash flows.

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

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

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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 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 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:

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.

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Our future acquisitions could expose us to potentially significant liabilities, including P&A 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 P&A liabilities. Such assessments are inexact and may not disclose all material issues or liabilities. In connection with our 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.

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:

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

Our operations are adversely affected by laws and policies of the jurisdictions, including Mexico, the United States, the Netherlands and other jurisdictions, in which we do business that affect foreign trade and taxation. Changes in any of these laws or policies or the implementation thereof could have a material adverse effect on our results of operations and financial position.

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

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

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

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

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:

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

Competition within our industry may adversely affect our operations.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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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 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. Instead, in February 2018, the EPA finalized amendments to certain requirements of the rule, and in September 2018 the EPA proposed additional amendments, including rescission of certain requirements and revisions to other requirements, such as fugitive emission monitoring frequency. 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 greenhouse gas emissions, certain non-governmental activists have recently directed their efforts at advocating the shifting of funding away from companies with energy-related assets, which could result in limitations or restrictions on certain sources of funding for the energy sector.  

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

Finally, some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. Our offshore operations are particularly at risk from severe climatic events. If any such climate changes were to occur, they could have an adverse effect on our financial condition and results of operations.

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

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), enacted on July 21, 2010, expanded federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act requires the U.S. Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank 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 Dodd-Frank Act, the CFTC issued on December 5, 2016, re-proposed rules imposing position limits for certain futures and option contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

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

The full impact of the Dodd-Frank 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 Dodd-Frank 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 Dodd-Frank Act and regulations implementing the Dodd-Frank 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 Dodd-Frank 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 Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

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

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Hedging transactions may limit our potential gains.

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

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.

 

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

 

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Item 6. Exhibits

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

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