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Summary of Significant Accounting Policies (Policies)

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Formation and Nature of Business

Talos Energy Inc. (“Talos” or the “Company”) is a technically driven independent exploration and production company with operations in the United States Gulf of Mexico and in the shallow waters off the coast of Mexico. The Company’s focus in the Gulf of Mexico is the exploration, acquisition, exploitation and development of deep and shallow water assets near existing infrastructure. The shallow waters off the coast of Mexico provide the Company high impact exploration opportunities in an emerging basin. The Company uses its access to an extensive seismic database and its deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. The Company’s management and technical teams have a long history working together and have made significant discoveries in the deep and shallow waters in the Gulf of Mexico and in the shallow waters off the coast of Mexico.

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

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

Concurrently with the consummation of the Transaction Agreement, the Company consummated the transactions contemplated by the certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”), among the Company, Stone, the Talos Issuers (defined below), the various lenders and noteholders of the Talos Issuers listed therein, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) (such controlled noteholders, the “Franklin Noteholders”), and certain clients of MacKay Shields LLC (“MacKay Shields”) (such noteholders, the “MacKay Noteholders”), pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% senior notes due 2022 (“9.75% Senior Notes”) issued by Talos Production LLC and Talos Production Finance, Inc. (together, the “Talos Issuers”) to the Company in exchange for an aggregate of 2,874,049 shares of Common Stock (the “Sponsor Debt Exchange”); (ii) the holders of second lien bridge loans (“11.00% Bridge Loans”) issued by the Talos Issuers exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 of the Talos Issuers (“11.00% Senior Secured Notes”) and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Senior Secured Notes due 2022 issued by Stone (“7.50% Stone Senior Notes”) for $137.4 million aggregate principal amount of 11.00% Senior Secured Notes.

As a result of the closing of the transactions contemplated by the Transaction Agreement and the Exchange Agreement (the “Transactions”) the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Closing Date.

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

Formation and Nature of Business

Talos Energy LLC was formed in 2011. Upon formation, Talos Energy Operating Company LLC; Talos Energy Offshore LLC; Talos Energy Operating GP, LLC; Talos Energy Holdings LLC; and Talos Production LLC became wholly-owned subsidiaries of Talos Energy LLC. Talos Production Finance Inc. was formed on January 15, 2013 as a wholly-owned subsidiary of Talos Energy LLC. Unless otherwise indicated or the context otherwise requires, references in this report to “us,” “we,” “our” or the “Company” are to Talos Energy LLC and its wholly-owned subsidiaries. On February 6, 2013, we acquired all of the equity of Energy Resource Technology GOM, LLC (“ERT”) and its subsidiary from Helix Energy Solutions Group, Inc. (“Helix”) for approximately $625.2 million (inclusive of purchase price and working capital adjustments of approximately $15.2 million), and payments for ongoing guarantees from Helix to third-parties. Additionally, the Company agreed to assign Helix an overriding royalty interest in certain properties acquired in the transaction at closing. We refer to this purchase as the “ERT Acquisition.” The ERT Acquisition was effective December 1, 2012 and closed on February 6, 2013. Prior to the closing of the ERT Acquisition, Energy Resource Technology GOM, Inc. and its wholly-owned subsidiary, CKB Petroleum, Inc., were each converted into Delaware limited liability companies, and as a result changed their names to Energy Resource Technology GOM, LLC and CKB Petroleum, LLC, respectively.

On February 3, 2012, the Company completed a transaction with funds affiliated with, and controlled by, Apollo Global Management LLC (together with its consolidated subsidiaries, “Apollo”), funds affiliated with, and controlled by, Riverstone Holdings, LLC (together with its affiliates, “Riverstone” and together with Apollo, our “Sponsors”) and members of management pursuant to which the Company received a private equity capital commitment, which may be increased up to $600 million with approval from the Company’s Board of Directors.

Prior to the closing of the ERT Acquisition, our Sponsors and members of management had invested an aggregate of approximately $325 million in the Company to fund a portion of the ERT Acquisition as well as to fund other asset purchases. In connection with the ERT Acquisition, the Company also issued $300 million aggregate principal amount of 9.75% Senior Notes due February 15, 2018 (the “2018 Senior Notes”) at a discount of 0.975%, (see Note 6—Debt).

The Company commenced commercial operations on February 6, 2013. Prior to February 6, 2013, the Company had incurred certain general and administrative expenses associated with the start-up of its operations.

We are a technically driven independent exploration and production company with operations in the Gulf of Mexico and in the shallow waters off the coast of Mexico. Our focus in the Gulf of Mexico is the exploration, acquisition and development of deep and shallow water assets near existing infrastructure. The shallow waters off the coast of Mexico provide us high impact exploration opportunities in an emerging basin. We use our access to an extensive seismic database and our deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. Our management and technical teams have a long history working together and have made significant discoveries in the deep and shallow waters in the Gulf of Mexico and in the shallow waters off the coast of Mexico. The Company shall continue until it is liquidated or dissolved in accordance with the Limited Liability Company Agreement of Talos Energy LLC, as amended and restated (the “LLC Agreement”).

Basis of Presentation and Consolidation

Basis of Presentation and Consolidation

The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) as applied to interim financial statements and include each subsidiary from the date of inception. Because this is an interim periodic report presented using a condensed format, it does not include all of the annual disclosures required by GAAP. Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP. Accordingly, the historical financial and operating data of Talos Energy Inc., which cover periods prior to the Closing Date, reflects the assets, liabilities and operations of Talos Energy LLC prior to the Closing Date and does not reflect the assets, liabilities and operations of Stone prior to the Closing Date. These condensed consolidated financial statements should be read in conjunction with Talos Energy LLC’s audited financial statements and the notes thereto for the year ended December 31, 2017, which are included elsewhere in this prospectus. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Statement of Changes in Equity and the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the business combination. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos. All intercompany transactions have been eliminated. All adjustments that are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the interim periods are reflected herein. The results for any interim period are not necessarily indicative of the expected results for the entire year. The Company has evaluated subsequent events through the date the condensed consolidated financial statements were issued.

For presentation purposes, as of June 30, 2018, certain balances previously disclosed as “Accounts payable” and “Other current assets” have been reclassified to “Accrued liabilities” and “Prepaid assets”, respectively. The corresponding balances as of December 31, 2017 of $73.5 million and $7.3 million were reclassified to “Accrued liabilities” and “Prepaid assets”, respectively. The balance sheet reclass between “Accounts payable” and “Accrued liabilities” is related to estimates of operating costs incurred but not yet invoiced.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.

During September 2015, the Company expanded its acreage position to include two shallow water exploration blocks off the coast of Mexico and drilled its first well in those blocks in July 2017. The business activities in Mexico, which are currently deemed immaterial, have been combined with the United States and reported as one segment. See additional information in Note 4—Property, Plant and Equipment.

Basis of Presentation and Consolidation

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include each subsidiary from the date of inception. All material intercompany transactions have been eliminated. All adjustments that are of a normal, recurring nature and are necessary to fairly present the Company’s financial position, results of operations and cash flows for the periods are reflected.

During September 2015, the Company expanded its acreage position to include two shallow water exploration blocks off the coast of Mexico and drilled our first well in July 2017. The business activities in Mexico have been combined with the United States and reported as one segment. See additional information in “Note 4—Property, Plant and Equipment.”

Recently Adopted Or Issued Accounting Standards

Recently Adopted Accounting Standards

Impact of the Adoption of ASC 606—Revenue from Contracts with Customers

On January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customers using the modified retrospective approach. ASC 606 supersedes the revenue recognition requirements in Topic 615, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition. The new standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for these goods and services.

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

The Company does not disclose the value of unsatisfied performance obligations for contracts with an original expected length of one year or less or contracts for which variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

Gas Imbalances. Under previous accounting guidance, the Company used the entitlement method to account for sales and production. Under the entitlement method, revenue was recorded based on the Company’s entitled share of production with any difference recorded as an imbalance on the condensed consolidated balance sheet. Upon the adoption of ASC 606, revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an underlying property. The change in accounting method from the entitlements method to the sales method resulted in an immaterial cumulative-effect adjustment to members’ deficit on the date of adoption.

Production Handling Fees. Under previous accounting guidance, the Company presented certain reimbursements for costs from certain third parties as other revenue on the condensed consolidated statement of operations. Upon the adoption of ASC 606, the reimbursements are presented as a reduction of direct lease operating expense on the condensed consolidated statement of operations. The impact of the reclassification for the three and six months ended June 30, 2018 was immaterial.

Recently Issued Accounting Standards

In February 2016, the Financial Accounting Standards Boards (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842). This ASU supersedes the lease requirements in Topic 840, Leases, and requires that a lessee recognize a right-of-use asset and lease liability for leases that do not meet the definition of a short-term lease. The right-of-use asset and lease liability are to be measured on the balance sheet at the present value of the lease payments. For income statement purposes, ASU 2016-02 retains a dual model requiring leases to be classified as either operating or finance within the Company’s condensed consolidated statements of operations. Lease costs for operating leases are recognized as a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. For finance leases, interest expense is recognized on the lease liability separately from amortization of the right-to-use asset. ASU 2016-02 does not apply to leases for oil and natural gas properties, but does apply to equipment used to explore and develop oil and natural gas reserves. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company is currently assessing the impact of ASU 2016-02 which includes an analysis of existing contracts and current accounting policies and disclosures that will change as a result of the adoption. Appropriate systems, controls and processes to support the recognition and disclosure requirements of the ASU 2016-02 are also being evaluated. The Company is currently evaluating the impact of this ASU on its condensed consolidated financial statements. The Company plans to adopt ASU 2016-02 effective January 1, 2019.

Recently Adopted Accounting Standards

In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805)—Clarifying the Definition of a Business. This ASU clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU provide a screen that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, they are not a business, which reduces the number of transactions that need to be evaluated further. The update is effective for public entities for annual and interim periods beginning after December 31, 2017, but allows for early adoption provided the transaction date occurs before the issuance of the ASU, only when the transaction has not been reported in previously issued financials. The Company early adopted the amendments for the transaction completed on December 20, 2016. See additional information in “Note 3—Acquisitions.”

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. The amendments in this ASU require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. The Company early adopted ASU 2016-18 as of January 1, 2017 and the adoption was applied retrospective to 2016 and 2015. As a result of the adoption, the Company reclassified $10.2 million and $7.2 million change in restricted cash during the years ended December 31, 2016 and 2015, respectively, from the investing section of the consolidated statements of cash flows to the net change in cash, cash equivalents and restricted cash balance.

Recently Issued Accounting Standards

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). This ASU supersedes the lease requirements in Topic 840 and requires that a lessee recognize a right-of-use asset and lease liability for leases that do not meet the definition of a short-term lease. The right-of-use asset and lease liability are to be measured on the balance sheet at the present value of the lease payments. For income statement purposes, ASU 2016-02 retains a dual model requiring leases to be classified as either operating or finance within our statements ofoperations. Lease costs for operating leases are recognized as a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. For finance leases, interest expense is recognized on the lease liability separately from amortization of the right-to-use asset. ASU 2016-02 does not apply to leases for oil and natural gas properties, but does apply to equipment used to explore and develop oil and natural gas reserves. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Topic 615, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition, and requires an entity to recognize revenue when it transfers promised goods and services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods and services. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2017. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect initially applying ASU 2014-09 recognized at the date of initial application. We are in the process of finalizing our implementation of ASU 2014-09 and does not anticipate the adoption will have a material effect.

Cash and Cash Equivalents

Cash and Cash Equivalents

We reflect our cash as cash and cash equivalents on our consolidated balance sheets. We consider all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost plus accrued interest, which approximates fair value.

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts receivable are stated at the historical carrying amount net of an allowance for uncollectible accounts of $5.9 million at December 31, 2017 and $4.9 million at December 31, 2016, which approximates fair value. We establish provisions for losses on accounts receivable and for natural gas imbalances with other parties if we believe that we will not collect all or part of the outstanding balance. On a quarterly basis we review collectability and establish or adjust our allowance as necessary using the specific identification method.

Other Current Assets

Other Current Assets

Other current assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”). The deposits are estimates related to royalties which we are required to pay the ONRR within thirty days of the production rate. On a monthly basis we adjust the deposit based on actual royalty payments remitted to the ONRR.

Inventory

Inventory

Inventory primarily represents oil in lease tanks and line fill in pipelines. Our inventory is stated at the net realizable value. Sales of oil are accounted for by a weighted average cost method whereby oil sold from inventory is relieved at the weighted average cost of oil remaining in inventory.

Revenue Recognition and Imbalances

Revenue Recognition and Imbalances

We record revenues from the sale of oil, natural gas and natural gas liquids (“NGLs”) based on quantities of production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred.

We have interests with other producers in certain properties. In these cases, we use the entitlement method to account for sales of production. Under the entitlement method, revenue is recorded when title passes based on our net interest. We may receive more or less than our entitled share of production, and we record our entitled share of revenues based on entitled volumes and contracted sales prices. If we receive more than our entitled share of production, the imbalance is recorded as a liability in accrued liabilities on the consolidated balance sheets. If we receive less than our entitled share, the imbalance is recorded as an asset in other current assets on the consolidated balance sheets. Our imbalances are recorded gross on our consolidated balance sheets. At December 31, 2017, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.7 million. At December 31, 2016, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.8 million. At December 31, 2015, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.6 million.

We record the gross amount of reimbursements for costs from third parties as other revenues whenever the Company is the primary obligor with respect to the source of such costs, has discretion in the selection of how the related costs are incurred and when it has assumed the credit risk associated with the reimbursement for such costs. The costs associated with these third-party reimbursements are also recorded within the applicable cost and expenses line item in the consolidated statements of operations. Our other revenues have been generated primarily through fees for processing third-party production through some of our production facilities.

Accounting for Oil and Natural Gas Activities

Accounting for Oil and Natural Gas Activities

The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below. In August 2016, the Company entered into a capital lease for the use of the Helix Producer I (“HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy, and recorded a $124.3 million capital lease asset. Since the HP-I is utilized in our oil and natural gas development activities, the asset is included within proved property and subject to the ceiling test calculation described below. Due to the inclusion within proved properties, the HP-I is depleted as part of the full cost pool. See Note 10—Commitments and Contingencies for additional information.

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

Our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized. Any costs in excess of the ceiling are recognized as a non-cash impairment expense on the consolidated statement of operations and an increase to accumulated depreciation, depletion and amortization on our consolidated balance sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. We perform this ceiling test calculation each quarter. In accordance with the Securities and Exchange Commission (“SEC”) rules and regulations, we utilize SEC Pricing when performing the ceiling test. We also hold prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period. The ceiling test computation resulted in a write-down of our oil and natural gas properties of nil, nil and $603.4 million during the years ended December 31, 2017, 2016 and 2015, respectively.

Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs.

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

We recognize transportation costs as a component of direct lease operating expense when we are the shipper of the product. Such costs were $10.3 million, $9.1 million and $10.5 million in the years ended December 31, 2017, 2016 and 2015, respectively.

Other Property and Equipment

Other Property and Equipment

Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures, computer hardware and software. Acquisitions, renewals and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to five years.

Other Well Equipment Inventory

Other Well Equipment Inventory

Other well equipment inventory primarily represents the cost of equipment to be used in our oil and natural gas drilling and development activities such as drilling pipe, tubular and certain wellhead equipment. When this inventory is supplied to wells, the cost of this inventory is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants. Our inventory is stated at net realizable value. We recorded $0.3 million, $0.2 million, $2.1 million of impairment to adjust inventory to net realizable value, which was expensed and reflected in workover/maintenance expense, during the years ended December 31, 2017, 2016 and 2015, respectively.

Fair Value Measure of Financial Instruments

Fair Value Measure of Financial Instruments

Financial instruments generally consist of cash and cash equivalents, restricted cash, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments.

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

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

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

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

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

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

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

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

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

Asset Retirement Obligations

Asset Retirement Obligations

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

Price Risk Management Activities

Price Risk Management Activities

The Company uses commodity derivatives to manage market risks resulting from fluctuations in prices of oil and natural gas. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.

Commodity derivatives are recorded on the consolidated balance sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in price risk management activities income (expense) in the consolidated statements of operations. We classify cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of our oil and natural gas operations, they are classified as cash flows from operating activities. We do not enter into derivative agreements for trading or other speculative purposes.

The fair value of commodity derivatives reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation, market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be favorable or unfavorable.

Equity Based Compensation

Share-Based Compensation

The Company records share-based compensation associated with restricted stock units in general and administrative expense on the condensed consolidated statement of operations, net of amounts capitalized to oil and gas properties. Share-based compensation expense is based on the grant date fair value of issued restricted stock units recognized over the vesting period of the instrument. For each restricted stock unit grant, the Company determines whether the awards represent equity or liability based awards. The fair value of equity awards are determined based on the close price of the stock on the grant date. The fair value of the liability awards are remeasured at each reporting date based on the close price of the stock at such date, until the date of settlement. See Note 7—Employee Benefits Plans and Share Based Compensation for additional information.

Equity Based Compensation

Certain of our employees participate in the equity based compensation plan of the Company. We measure all employee equity based compensation awards at fair value as calculated using an option pricing method for valuing such securities on the date awards are granted to our employees and recognize compensation cost on a straight-line basis in our financial statements over the vesting period of each grant according to Accounting Standards Codification 718, Compensation—Stock Compensation.

Income Taxes

Income Taxes

Prior to the Stone Combination, Talos Energy LLC was a partnership for federal income tax purposes and was not subject to federal income tax or state income tax (in most states). As such, Talos Energy LLC was not a taxpaying entity for federal income tax purposes and accordingly, did not recognize any expenses for such states. In connection with completing the Stone Combination, Talos Energy LLC was contributed to the Company, which is subject to federal and state income taxes. The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. Changes in tax laws are recorded in the period they are enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the consolidated balance sheets.

The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating our valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, and the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations.

The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expenses, respectively.

Income Taxes

The Company is a limited liability company and not subject to federal or state income tax (in most states). As such, the Company is not a taxpaying entity for federal income tax purposes and accordingly, does not recognize any expense for such taxes. The federal income tax liability resulting from the Company’s activities is the responsibility of the Company’s Sponsors and other Unit holders. The Company is subject to state income taxes in certain jurisdictions and under applicable state laws taxes are estimated to be immaterial.

We operate in the shallow waters off the coast of Mexico under a different legal form. As a result, income taxes are provided for based upon the tax laws and rates in effect in the foreign tax authorities.

Deferred income tax assets and liabilities are recorded for the expected future tax consequences of events that are recognized in our financial statements or tax returns. A valuation allowance is established to reduce deferred tax assets when it is more likely than not that the overall deferred tax asset will not be realized. At December 31, 2017 and December 31, 2016, the Company has a valuation allowances of $4.0 million and $2.3 million, which is the amount of deferred tax assets.

Concentration of Credit Risk

Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents, restricted cash, accounts receivable and commodity derivatives.

Cash and cash equivalents and restricted cash balances are maintained in financial institutions, which, at times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has experienced no losses on these accounts.

Commodity derivatives are entered into with registered swap dealers, majority of which participate in our senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has experienced no losses due to counterparty default on these instruments.

We market substantially all of our oil and natural gas production from properties we operate and those we do not operate. The majority of our oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. Our customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. We perform ongoing credit evaluations of our customers and provide allowances for probable credit losses when necessary. The percent of consolidated revenue of major customers, those whose total represented 10% or more of our oil, natural gas and NGL revenues, was as follows:


	Year Ended December 31,
	2017			2016			2015
Shell Trading (US) Company		80	%		68	%		68	%
Chevron U.S.A Inc.		*	*		14	%		16	%

**	less than 10%

While the loss of Shell Trading (US) Company and Chevron U.S.A. Inc. as buyers might have a material effect on the Company in the short term, we believe that the Company would be able to obtain other customers for its oil, natural gas and NGL production.

Supplementary Cash Flow Information

Supplementary Cash Flow Information

Supplementary cash flow information for each period presented was as follows (in thousands):


	Year Ended December 31,
	2017		2016		2015
Supplemental Non-Cash Transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	40,626	$	13,832	$	30,125
Fair value of assets acquired	$	—	$	—	$	75,519
Fair value of liabilities assumed	$	—	$	—	$	75,519
Capital lease transaction	$	—	$	124,300	$	—
Supplemental Cash Flow Information:
Interest paid, net of amounts capitalized	$	47,994	$	55,254	$	37,247

Earnings Per Common Share

Earnings Per Common Share

Basic earnings per common share (“EPS”) is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of restricted stock unit grants and outstanding warrants. See Note 9—Earnings Per Share for additional information.