Exhibit 99.1

INDEX TO FINANCIAL STATEMENTS

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Talos Energy LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of Talos Energy LLC (the Company) as of December 31, 2017 and 2016, and the related statements of consolidated operations, cash flows and changes in members’ equity for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2017 and 2016, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal controls over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2010.

Houston, Texas

March 14, 2018

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TALOS ENERGY LLC

CONSOLIDATED BALANCE SHEETS

(In thousands)

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TALOS ENERGY LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

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TALOS ENERGY LLC

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’ EQUITY (DEFICIT)

(In thousands)

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TALOS ENERGY LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

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TALOS ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017

Note 1 – Formation and Basis of Presentation

Formation and Nature of Business

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

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

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

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

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

Basis of Presentation and Consolidation

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include each subsidiary from the date of

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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. We have evaluated subsequent events through March 14, 2018, the date the consolidated financial statements were issued.

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

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

Recently Adopted Accounting Standards

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

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

Recently Issued Accounting Standards

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). This ASU supersedes the lease requirements in Topic 840 and requires that a lessee recognize a right-of-use asset and lease liability for leases that do not meet the definition of a short-term lease. The right-of-use asset and lease liability are to be measured on the balance sheet at the present value of the lease payments. For income statement purposes, ASU 2016-02 retains a dual model requiring leases to be classified as either operating or finance within our 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

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for oil and natural gas properties, but does apply to equipment used to explore and develop oil and natural gas reserves. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.

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

Note 2 – Summary of Significant Accounting Policies

Below are the Company’s significant accounting policies.

Cash and Cash Equivalents

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

Accounts Receivable and Allowance for Uncollectible Accounts

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

Other Current Assets

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

Inventory

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

Revenue Recognition and Imbalances

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

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

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

Accounting for Oil and Natural Gas Activities

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

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

Our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized. Any costs in excess of the ceiling are recognized as a non-cash impairment expense on the consolidated statement of operations and an increase to accumulated depreciation, depletion and amortization on our consolidated balance sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. We perform this ceiling test

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calculation each quarter. In accordance with the Securities and Exchange Commission (“SEC”) rules and regulations, we utilize SEC Pricing when performing the ceiling test. We also hold prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period. The ceiling test computation resulted in a write-down of our oil and natural gas properties of nil, nil and $603.4 million during the years ended December 31, 2017, 2016 and 2015, respectively.

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

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

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

Other Property and Equipment

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

Other Well Equipment Inventory

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

Fair Value Measure of Financial Instruments

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

Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly

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transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows:

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

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

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

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

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

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

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

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

Asset Retirement Obligations

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

Price Risk Management Activities

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

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

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

Equity Based Compensation

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

Income Taxes

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

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

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

Concentration of Credit Risk

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

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

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

We market substantially all of our oil and natural gas production from properties we operate and those we do not operate. The majority of our oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. Our customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. We perform ongoing credit evaluations of our customers and provide allowances for probable credit losses when

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necessary. The percent of consolidated revenue of major customers, those whose total represented 10% or more of our oil, natural gas and NGL revenues, was as follows:

** less than 10%

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

Supplementary Cash Flow Information

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

Note 3 – Acquisitions

2017 Merger Announcement

Merger with Stone Energy

On November 21, 2017, the Company executed an agreement to combine with Stone Energy Corporation (“Stone”) to form Talos Energy, Inc. in an all-stock transaction, which is expected to occur during the second quarter of 2018. The transaction has been unanimously approved by both our and Stone’s Board of Directors. Under the terms of the agreement, each outstanding share of Stone common stock will be exchanged for one share of Talos Energy, Inc. common stock and the current Talos Energy stakeholders will be issued an aggregate of approximately 34.2 million common shares. At closing, our stakeholders will own 63% and Stone’s shareholders will own 37% of the combined company. Talos Energy, Inc. is expected to trade on the New York Stock Exchange under the ticker symbol “TALO.”

2016 Acquisitions

The acquisition below qualified as an asset acquisition that requires, among other items, that the cost of the assets acquired and liabilities assumed to be recognized on the balance sheet by allocating the asset cost on a relative fair value basis. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments

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and estimates by the Company’s management at the time of the valuation. Transaction costs incurred on an asset acquisition are capitalized as a component of the assets acquired and any contingent consideration is recognized as the contingency is resolved.

Acquisition of Additional Working Interest in the Phoenix Field

On December 20, 2016, we purchased an additional 15% working interest in the Phoenix Field from Sojitz Energy Venture Inc. (“Sojitz”) for approximately $85.8 million in cash and the assumption of certain asset retirement obligations, subject to customary post-closing adjustments. The purchase price was funded by a $93.8 million ($91.9 million net of $1.9 million of transaction fees) contribution from our Sponsors. Additionally, we entered into a contingent consideration arrangement in the form of an earn-out equal to 5% of the acquired property’s monthly net profit if the Company’s realized oil price is greater than $65.00 per Bbl in a given month. The maximum payout under the earn-out is $10.0 million and has an indefinite life pursuant to the purchase and sale agreement. We refer to the acquisition of assets from Sojitz as the “Sojitz Acquisition.”

As of December 31, 2017, the Company recorded $2.5 million in post-closing adjustments related to activity between the effective date and closing date of the acquisition.

The following table below presents the allocation of the purchase price (inclusive of post-closing adjustments) to the assets acquired and liabilities assumed, based on their relative fair values on December 20, 2016 (in thousands):

2015 Acquisitions

The acquisitions below qualified as business combinations and were accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates by the Company’s management at the time of the valuation.

Acquisition of Additional Working Interest in Our Motormouth Discovery from Deep Gulf Energy III, LLC

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

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We completed the final purchase price allocation in 2015 which was calculated as follow (in thousands):

Revenue attributable to the assets acquired in the DGE Acquisition during the year ended December 31, 2015 was $1.9 million. The presentation of net income attributable to the assets acquired from DGE is impracticable due to the integration of the operations upon acquisition.

Acquisition of Gulf Coast Energy Resources, LLC

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

We completed the final purchase price allocation in 2015 which was calculated as follow (in thousands):

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The fair value, as adjusted, of the current assets acquired includes the following receivables (in thousands):

Revenue and net loss attributable to the assets acquired in the GCER Acquisition during the year ended December 31, 2015 was $12.6 million and $9.7 million, respectively. Revenues were reduced by production costs of the assets acquired and for estimated depletion and accretion expense in calculating net loss. Depletion expense was calculated by applying the Company’s depletion rate on proved oil and natural gas properties per Boe to production attributable to the acquired assets. Accretion on the asset retirement obligation was calculated using the Company’s credit-adjusted risk-free interest rate. Total non-cash depletion and accretion expense included in the net loss for the year ended December 31, 2015 was $15.6 million.

Note 4 – Property, Plant and Equipment

Proved Properties. The Company’s interests in oil and natural gas properties are located primarily in the United States Gulf of Mexico deep and shallow waters. We follow the full cost method of accounting for our oil and natural gas exploration and development activities. In August 2016, the Company entered into a capital lease for the use of the HP-I and recorded a $124.3 million capital lease asset. Since the HP-I is utilized in our oil and natural gas development activities, the asset is included within proved property, subject to the ceiling test calculation described below and is depleted as part of the full cost pool.

Pursuant to SEC Regulation S-X, Rule 4-10, under the full cost method of accounting, our capitalized oil and natural gas costs are limited to a ceiling based on the present value of future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized. We perform this ceiling test calculation each quarter utilizing SEC Pricing. During 2017 and 2016, our ceiling test computations did not result in a write-down of our U.S oil and natural gas properties. At September 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and natural gas properties of $279.3 million based on SEC Pricing, of $61.22 per Bbl of oil, $3.29 per Mcf of natural gas and $20.65 per Bbl of NGLs. At December 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and natural gas properties of $324.1 million based on SEC Pricing of $50.72 per Bbl of oil, $2.75 per Mcf of natural gas and $17.60 per Bbl of NGLs.

Unproved Properties. Unproved capitalized costs of oil and natural gas properties excluded from amortization relate to unevaluated properties associated with acquisitions, leases awarded in the Gulf of Mexico federal lease sales, certain geological and geophysical costs, costs associated with certain exploratory wells in progress and capitalized interest. Unproved properties also include costs associated with the two blocks awarded on September 4, 2015 to the Company together with Sierra Oil & Gas S. de R.L de C.V. (“Sierra”) and Premier Oil Plc (“Premier”), the (“Consortium”), located in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states, by the National Hydrocarbons Commission (“CNH”).

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The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2017, by the year in which such costs were incurred (in thousands):

The excluded costs will be included in the amortization base as properties are evaluated and proved reserves are established or impairment is determined. We expect this process to occur over the next five years.

In March 2017, the Company was the apparent high bidder on six blocks in connection with the Gulf of Mexico Federal Lease Sale 247 held by the Bureau of Ocean Energy Management (“BOEM”). The six blocks were awarded to the Company during the second quarter 2017. The Company paid BOEM approximately $2.6 million during the first and second quarter of 2017 for the awarded leases and for first year’s lease rentals.

Capitalized Interest. Interest expense in our financial statements is reflected net of capitalized interest. We capitalize interest on the costs associated with drilling and completing wells until production begins. The interest rate used is the weighted average interest rate of our outstanding borrowings. Capitalized interest for the years ended December 31, 2017, 2016 and 2015 was $0.6 million, $0.4 million and $3.9 million, respectively.

Capitalized Overhead. General and administrative expense in our financial statements is reflected net of capitalized overhead. We capitalize overhead costs that are directly related to exploration, acquisition and development activities. Capitalized overhead for the years ended December 31, 2017, 2016 and 2015 was $13.7 million, $12.5 million and $14.1 million, respectively.

Asset Retirement Obligations. We have obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We have obligations to plug wells when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue a liability with respect to these obligations based on our estimate of the timing and amount to replace, remove or retire the associated assets.

In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate in the table below represent changes to the expected amount and timing of payments to settle our asset retirement obligations. Typically, these changes result from obtaining new information about the timing of our obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense in our consolidated statements of operations. If we incur an amount different from the amount accrued for decommissioning obligations, we recognize the difference as an adjustment to proved properties.

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The discounted asset retirement obligations included in the consolidated balance sheets in current and non-current liabilities, and the changes in that liability during the each of the years ended December 31, were as follows (in thousands):

Note 5 – Financial Instruments

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

As of December 31, 2017 and 2016, the carrying amounts of cash and cash equivalents, accounts receivable, restricted cash and accounts payable approximate their fair values because of the short-term nature of these instruments.

Bridge Loans, 2022 Senior Notes and 2018 Senior Notes. The $172.0 million aggregate principal amount of 11% senior secured second-priority bridge loans due April 3, 2022 (“Bridge Loans”), $102.0 million aggregate principal amount of 9.75% senior notes due July 5, 2022 (“2022 Senior Notes”) and $25.0 million aggregate principal amount of 9.75% senior notes due February 15, 2018 (“2018 Senior Notes”) are reported on the consolidated balance sheet at their carrying value net of discount and deferred financing costs (see Note 6 – Debt). The fair value of our Bridge Loans is estimated as face value as no market has developed and the holders of the Bridge Loans were the largest holders of the 2018 Senior Notes prior to the April 3, 2017 conversion. The fair value of the 2022 Senior Notes and 2018 Senior Notes are estimated to equal the face value based on the April 3, 2017 conversion and May 15, 2017 redemption of $1.0 million of the 2018 Senior Notes at par. These fair values represent Level 2 fair value measurements (see Note 6 – Debt).

Bank Credit Facility. The Bank Credit Facility is reported on the consolidated balance sheet at its carrying value net of deferred financing costs (see Note 6 – Debt). The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under our Bank Credit Facility since it is secured by the company’s reserves and the interest rates are variable and reflective of market rates.

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Oil and natural gas derivatives. We attempt to mitigate a portion of our commodity price risk and stabilize cash flows associated with sales of oil and natural gas production through the use of oil and natural gas swaps and costless collars. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from the counterparties. These two-way collars provide risk protection if oil prices fall below certain levels, but may limit incremental income from favorable price movements above certain limits. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on the consolidated balance sheet at fair value with settlements of such contracts and changes in the unrealized fair value recorded as price risk management activities income (expense) in the consolidated statements of operations in each period.

The following table presents the impact that derivatives not qualifying as hedging instruments had on our consolidated statements of operations (in thousands):

The following table reflects the contracted volumes and weighted average prices we will receive under our derivative contracts as of December 31, 2017:

Subsequent event. The following table reflects the contracted volumes and weighted average prices we will receive under our derivative contracts entered into subsequent to December 31, 2017, which are not reflected in the table above:

The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):

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Financial Statement Presentation. Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although we have master netting arrangements with our counterparties, we present our derivative financial instruments on a gross basis in our consolidated balance sheets. On derivative contracts recorded as assets in the table below, we are exposed to the risk the counterparties may not perform. The following table presents the fair value of derivative financial instruments at December 31, 2017 and 2016 (in thousands):

Credit Risk. We are subject to the risk of loss on our financial instruments as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We enter into International Swaps and Derivative Association agreements with counterparties to mitigate this risk, when possible. We also maintain credit policies with regard to our counterparties to minimize our overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of our counterparties’ credit exposures; (iii) the use of contractual language that affords us netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk. Our assets and liabilities from commodity price risk management activities at December 31, 2017 represent derivative instruments from eight counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating and seven of which are parties under our Bank Credit Facility. We enter into derivatives directly with these third parties and, subject to the terms of our Bank Credit Facility, are not required to post collateral or other securities for credit risk in relation to the derivative activities.

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Note 6 – Debt

A summary of the detail comprising the Company’s debt and the related book values for the respective periods presented is as follows (in thousands):

On April 3, 2017 (the “Closing Date”), the Company entered into an Exchange Agreement (the “Exchange Agreement”) pursuant to which Bain Capital Credit LP, GSO Capital Partners LP and certain affiliates of our Sponsors (the “Exchanging Noteholders”) exchanged some of the 2018 Senior Notes for Bridge Loans (as described below). Certain affiliates of the Sponsors also exchanged some of the 2018 Senior Notes for 2022 Senior Notes (as described below).

The exchange of debt instruments was accounted for as a debt modification. Under a debt modification, a new effective interest rate that equates the revised cash flows to the carrying amount of the 2018 Senior Notes is computed and applied prospectively. Costs incurred with third parties directly related to the modification are expensed as incurred. The Company incurred approximately $4.3 million of transaction fees which were expensed and reflected in general and administrative expense during the year ended December 31, 2017, respectively.

Bridge Loans. On the Closing Date, the Company exchanged $172.0 million of the 2018 Senior Notes for $172.0 million of Bridge Loans issued under a second lien bridge loan agreement, dated as of the Closing Date (the “Credit Agreement”), by and among the Company, the lenders party thereto and Wilmington Trust, National Association, as administrative agent and collateral agent. Of the $172.0 million exchanged, the Sponsors held $39.8 million. The Bridge Loans mature on the fifth anniversary of the Closing Date.

The obligations under the Credit Agreement are second-priority secured obligations behind the Bank Credit Facility. The obligations are secured by substantially all of the Company’s assets. The Company will pay interest on amounts outstanding under the Credit Agreement at 11.0% per annum, semiannually on April 15 and October 15 of each year, which commenced October 15, 2017.

The Company may redeem up to 35% of the aggregate principal amount of the Bridge Loans at a price equal to 111% of the aggregate principal amount plus accrued and unpaid interest, if any, at any time prior to April 3, 2018. The Company may redeem the Bridge Loans, in whole or in part, on or after April 3, 2018 at the redemption prices set forth in the Credit Agreement.

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The Credit Agreement contains covenants that limit the Company’s ability (and their restricted subsidiaries’ ability) to, among other things: (i) incur additional indebtedness or issue certain preferred shares; (ii) pay dividends and make certain other restricted payments; (iii) create restrictions on the payment of dividends or other distributions to the Company from its restricted subsidiaries; (iv) create liens on certain assets to secure debt; (v) make certain investments; (vi) engage in transactions with affiliates; (vii) engage in sales of assets and subsidiary stock; and (viii) transfer all or substantially all of its assets or enter into merger or consolidation transactions. The Credit Agreement does not contain a financial maintenance covenant. The Credit Agreement also provides for certain customary events of default, which, if any of such defaults occurs, would permit or require the principal, premium (if any), interest or other monetary obligations on all of the then outstanding Bridge Loans to become due and payable. The Bridge Loans contain customary quarterly and annual reporting, financial and administrative covenants.

2022 Senior Notes. On the Closing Date, the Company exchanged $102.0 million of the 2018 Senior Notes for $102.0 million of 2022 Senior Notes issued under a new indenture, dated as of the Closing Date (the “Indenture”), between the Company, as issuer, the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee. The 2022 Senior Notes mature on July 5, 2022. The Company will pay interest on the 2022 Senior Notes at 9.75% per annum, semiannually on February 15 and August 15 of each year, which commenced August 15, 2017.

The Company may redeem up to 35% of the aggregate principal amount of the 2022 Senior Notes at a price equal to 109.75% of the aggregate principal amount plus accrued and unpaid interest, if any, at any time prior to April 3, 2018. The Company may redeem the 2022 Senior Notes, in whole or in part, on or after April 3, 2018 at the redemption prices set forth in the Indenture. The remainder of the terms of the 2022 Senior Notes are substantially similar to the terms of the 2018 Senior Notes.

2018 Senior Notes. The 2018 Senior Notes were issued pursuant to an indenture dated February 6, 2013 among the Company and one of our wholly-owned subsidiaries, as issuers, the subsidiary guarantors party thereto and the trustee. The 2018 Senior Notes pay interest on February 15 and August 15 of each year. The 2018 Senior Notes are fully and unconditionally guaranteed by certain of our wholly-owned subsidiaries. The indenture governing the 2018 Senior Notes applies certain limitations on our ability and the ability of our subsidiaries to, among other things, (i) incur or guarantee additional indebtedness; (ii) pay dividends or distributions on, or redeem or repurchase capital investment and make other restricted payments; (iii) make investments; (iv) consummate certain asset sales; (v) engage in transactions with affiliates; (vi) grant or assume liens; and (vii) consolidate, merge or transfer all or substantially all of our assets. The 2018 Senior Notes contain customary quarterly and annual reporting, financial and administrative covenants. In addition to the exchange of some of the 2018 Senior Notes for Bridge Loans and 2022 Senior Notes, the Company redeemed $1.0 million of the 2018 Senior Notes on May 15, 2017.

Subsequent event. On February 15, 2018, the Company redeemed the remaining $25.0 million aggregate principal amount of the 2018 Senior Notes at par.

Bank Credit Facility. The Company maintains a Bank Credit Facility with a syndicate of financial institutions, which has been amended periodically. The Bank Credit Facility provides a revolving credit facility with a borrowing capacity up to the lesser of (i) the borrowing base (as defined in the Bank Credit Facility) and (ii) aggregate lender commitments. The Bank Credit Facility matures on February 6, 2019.

The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. In addition, the Company is obligated to pay a commitment fee rate based on the borrowing base usage of 0.375% to 0.50%. The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a consolidated debt to adjusted EBITDA figure of no greater than 3.50 to 1.00. The Bank Credit Facility is secured by substantially all of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by certain of our wholly-owned subsidiaries.

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The Bank Credit Facility provides for determination of the borrowing base based on the Company’s proved producing reserves and a portion of its proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually in the spring and fall, with the last redetermination on May 16, 2017.

On January 10, 2017, we paid down $15.0 million under our Bank Credit Facility, and on April 3, 2017, we borrowed $10.0 million from our Bank Credit Facility.

In May 2017, the lenders under our Bank Credit Facility reaffirmed the borrowing base at $475.0 million during their regular semi-annual redetermination. In conjunction with the reaffirmation of the borrowing base, the Company executed the Eighth Amendment to the Bank Credit Facility effective May 16, 2017. The Eighth Amendment includes (i) an increase to the consolidated total debt to EBITDAX (as defined in the Bank Credit Facility) ratio covenant from 3.50 to 1.0 to 3.75 to 1.0 each quarter from September 30, 2017 to March 31, 2018 and (ii) a requirement to execute control agreements for all deposit accounts, securities accounts and commodities accounts in the name of the borrowers and guarantors. On October 31, 2017, the Company executed the Ninth Amendment to the Bank Credit Facility deferring the borrowing base redetermination to January 2018 to fully assess the reserve impact of our recent Tornado II discovery.

As of December 31, 2017, the Company’s borrowing base was set at $475.0 million, of which no more than $200 million can be used as letters of credit. As of December 31, 2017, the Bank Credit Facility had approximately $67.1 million of undrawn commitments (taking into account $4.9 million letters of credit and $403.0 million drawn under the Bank Credit Facility). We were in compliance with all debt covenants at December 31, 2017.

Subsequent event. On January 24, 2018, at our election we executed the Tenth Amendment to the Bank Credit Facility deferring the next borrowing base redetermination to May 31, 2018 in response to our recently announced combination with Stone.

Note 7 – Employee Incentive Programs

Employee Share Ownership Program

The LLC Agreement established Series A, Series B and Series C Units. Series B Units are generally intended to be used as incentives for Company employees. The Company is initially authorized to issue 1 million Series B Units and may issue more under the LLC Agreement.

With the exception of distributions to cover the assumed tax liability of the Series B Unit holders, Series B Units do not participate in cash distributions prior to vesting and until Series A Units have received cumulative cash distributions equal to (i) the original cash contributed to the Company for such Series A Units and (ii) 8% returns, compounded annually (the “Aggregate Series A Payout”), and Series C Units have received $25 million in cash distributions.

After issuance, 80% of the Series B Units vest on a monthly basis over a four year period, subject to continued employment. The remaining 20% of the Series B Units fully vest (a) upon the occurrence of a Liquidation Event or an Approved Sale, as defined in the LLC Agreement, that results in an Aggregate Series A Payout or (b) in the case of a public offering upon the occurrence of an Aggregate Series A Payout.

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We had 992,850 Series B Units outstanding at December 31, 2017, 980,250 Series B Units outstanding at December 31, 2016 and 906,000 Series B Units outstanding at December 31, 2015. A summary of the Series B Unit activity for the years ended December 31, 2017, 2016 and 2015 is presented below.

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 members’ equity. In the years ended December 31, 2017, 2016 and 2015, we recognized approximately $0.9 million, $1.1 million and $1.7 million, respectively, in compensation expense included in general and administrative expense and capitalized approximately $0.9 million, $1.2 million and $1.9 million, respectively, into our oil and natural gas properties. The Series B Units issued were valued using the option pricing method for valuing securities. In this method, the rights and claims of each security are modeled as a portfolio of Black-Scholes-Merton call options written on the total equity of the Company. The fair value of each grant was estimated at the date of grant using the following weighted-average assumptions:

The total value of the equity is calculated in an iterative process that results in the Series A Units being valued at par. The risk-free rate of interest is based on the U.S. Treasury yield curve on the grant date. The expected time to a liquidity event is based on a weighted average calculation of management’s estimate considering market conditions and expectations. The expected volatility of equity is based on the volatility of the assets of similar publicly traded companies using a Black-Scholes-Merton model. The discount for lack of marketability is based on the restrictions on the Series B Units and the volatility of the Series B Units using a Black-Scholes-Merton model.

Our unrecognized compensation expense at December 31, 2017 is approximately $3.4 million. Of this amount, approximately $1.1 million of the unrecognized compensation expense will continue to be recognized on a straight-line basis over the remainder of the four year requisite service period. The remaining $2.2 million related to 135,712 Series B Units will be recognized (a) upon the occurrence of a Liquidation Event or an Approved Sale, as defined in the LLC Agreement, that results in an Aggregate Series A Payout or (b) in the case

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of a public offering upon the occurrence of an Aggregate Series A Payout. The weighted-average period over which the unrecognized compensation expense will be recognized is 24 months. At December 31, 2017, the Company has 7,150 Series B units authorized but not yet issued.

Note 8 – Income Taxes

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

We operate in the shallow waters off the coast of Mexico under a different legal form. As a result, we are subject to foreign tax authorities. Although the Company is subject to foreign income taxes, the Company incurred only foreign expenses in Mexico during the years ended December 31, 2017, 2016 and 2015. The Company is subject to foreign income taxes and under the foreign tax law and treaties among these governments taxes are estimated to be immaterial.

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

Foreign tax loss carryforwards at December 31, 2017 was $13.4 million. The foreign tax loss carryforwards will start to expire in 2025.

On December 22, 2017, the President signed into Public Law No. 115-97 (“Tax Act”), “an Act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018.” Tax Act makes broad and complex changes to the U.S. tax code. Since Talos is a limited liability company and treated as a pass-through entity for federal tax purposes and in most states, the Company did not recognize any income tax impact from the new Tax Act.

Note 9 – Related Party Transactions

Transaction Fee Agreement. As part of the agreements with Apollo and Riverstone, the Company pays a transaction fee equal to 2% of capital contributions made by each of our Sponsors. For the years ended December 31, 2017, 2016 and 2015 we incurred fees totaling nil, $1.9 million and $1.5 million, respectively, related to the capital contributions received from our Sponsors.

Service Fee Agreement. The Company entered into service fee agreements with each of our Sponsors for the provision of certain management consulting and advisory services. Under each agreement, the Company pays a fee equal to the higher of (i) a certain percentage of earnings before interest, income taxes, depletion, depreciation and amortization and (ii) a fixed fee payable quarterly, provided, however, such fees shall not exceed in each case $0.5 million, in aggregate, for any calendar year. For the years ended December 31, 2017, 2016 and 2015, we incurred approximately $0.5 million, $0.5 million and $0.5 million, respectively, for these services. These fees are recognized in general and administrative expense on the consolidated statement of operations.

Contributions and Distributions. During the year ended December 31, 2017, the Company did not receive any capital contributions from our Sponsors or make any distributions to our Sponsors. During the year ended

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December 31, 2016, the Company received a $93.8 million ($91.9 million net of $1.9 million of transaction fees) capital contribution from our Sponsors primarily to fund the Sojitz Acquisition (see Note 3 – Acquisitions). During the year ended December 31, 2015, the Company received a $75.0 million ($73.5 million net of $1.5 million of transaction fees) capital contribution from our Sponsors primarily to fund the DGE Acquisition and to partially fund the $55.0 million extinguishment of the GCER Bank Credit Facility assumed in the GCER Acquisition (see Note 3 – Acquisitions).

Note 10 – Commitments and Contingencies

Capital Lease

On August 2, 2016, ERT executed a seven-year lease agreement (the “Agreement”), effective June 1, 2016, with Helix for use of the HP-I to process hydrocarbons produced from the Phoenix Field. Under the terms of the Agreement, the Company will pay Helix an annual fixed demand charge of $49.0 million during the first two years and $45.0 million thereafter. If certain uptime rates are achieved, the Company will pay Helix a quarterly incentive payment of $0.5 million during the first two years of the agreement and $0.8 million thereafter.

The Agreement replaces the previous lease agreement for the HP-I, which provided that ERT would pay Helix (i) a fixed annual demand fee of $33.0 million and (ii) a 10% throughput charge on the net consideration payable to ERT under a sales contract for the sale of hydrocarbons processed through the HP-I.

The Agreement with Helix is accounted for as a capital lease. The Company initially recorded both a capital lease asset and obligation of $124.3 million on our consolidated balance sheet. As of December 31, 2017, the balance of the capital lease obligation on the consolidated balance sheet is $106.6 million, of which $12.9 million is included in other current liabilities and $93.7 million is included in other long-term liabilities. As a result of the Agreement being accounted for as a capital lease, the lease payments are reflected as (i) a reduction of the capital lease obligation, (ii) interest expense and (iii) direct lease operating expense.

As of December 31, 2017, minimum lease commitments for our capital lease for the years ended December 31 are as follows (in thousands):

Legal Proceedings and Other Contingencies

In August 2015, we became aware of a potential unauthorized discharge on our Vermilion 195 platform in connection with an operation to bleed off production casing pressure. We immediately initiated an internal investigation of the alleged matter and concluded that an unauthorized discharge had occurred. We terminated the individuals that were determined to be responsible for the discharge. We also self-reported the matter to the U.S. Environmental Protection Agency (“EPA”) on September 17, 2015.

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On November 30, 2015, ERT was charged with two violations of Outer Continental Shelf Lands Act (“OCSLA”) in connection with hot work and blowout preventer testing activities, and with two violations of the Clean Water Act (“CWA”) for the self-reported activities surrounding overboard discharge sampling and unpermitted discharges, as described above.

On January 6, 2016, ERT plead guilty to two violations of the Clean Water for self-reported activities surrounding overboard discharge sampling and unpermitted discharges and two violations of OSCLA. On April 6, 2016, the United States District Court for the Eastern District of Louisiana accepted ERT’s plea and sentenced ERT, consistent with the plea agreement, to pay a penalty of $4.2 million which ERT has paid. The Court placed ERT on probation for three years. The conditions of probation include compliance with an agreed Safety and Environmental Compliance Program. As a result of ERT’s conviction for violations of the CWA, ERT was debarred and cannot enter into contracts with or receive benefits from the federal government, until the EPA reinstates ERT by certifying that ERT has corrected the conditions giving rise to the Clean Water convictions. EPA also imposed discretionary suspension and proposed debarment on Talos Production LLC, Talos Energy Offshore LLC and Talos Energy LLC as affiliates of ERT. On November 23, 2016, EPA terminated and administratively closed the suspension as to each of the three entities previously suspended. On August 29, 2017, EPA certified that the conditions giving rise to ERT’s conviction were corrected, and its debarment was lifted.

Performance Obligations

Regulations with respect to offshore operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities and to guarantee the execution of the minimum work program under the Mexico production sharing contracts. As of December 31, 2017 and 2016, we had secured performance bonds totaling approximately $287.8 million and $338.2 million, respectively. As of December 31, 2017 and 2016, we had $4.9 million and $4.0 million, respectively, in letters of credit issued under our Bank Credit Facility.

In July 2016, the BOEM announced updated financial assurance and risk management requirements for offshore leases. The Notice to Lessees (“NTL”) details procedures to determine a lessee’s ability to carry out its lease obligations – primarily the decommissioning of Outer Continental Shelf (“OCS”) facilities – and whether to require lessees to furnish additional financial assurance to meet BOEM’s estimate of the lessees decommissioning obligations. The NTL supersedes the agency’s prior practice of allowing operators of a certain net worth to waive the need for supplemental bonds and provides updated criteria for determining a lessee’s ability to self-insure its OCS liabilities based upon the lessee’s financial capacity and financial strength. The NTL also allows lessees to meet their additional financial security requirements through the submission of a tailored plan, whereby an operator and BOEM agree to set a timeframe for the posting of additional financial assurances. In the first quarter of 2017, BOEM announced that it will extend the implementation timeline for the new NTL by an additional six months. Sole-liability leaseholders will have 60 days from the date of receipt of an order requiring additional financial security to comply. For all other holdings, leaseholders will have 120 days from the date they receive an order to provide additional security, if required. Alternatively, lessees can provide a tailored financial plan to BOEM, which will permit the use of forms of financial security other than surety bonds and pledges of treasury securities and allow companies to phase in funding of the additional security. We received notice from BOEM on December 29, 2016 ordering the Company to secure financial assurances in the form of additional security in the amount of $0.5 million. Subsequent to the December 29, 2016 order, BOEM has rescinded that order and all others dated December 29, 2016 until further notice. We remain in active discussion with our government regulators and industry peers with regard to any future rule making and financial assurance requirements. Notwithstanding BOEM’s July 2016 NTL, BOEM may also bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The future cost of compliance with our existing supplemental bonding requirements, the July 2016 NTL, as well as any other future BOEM directives or any other changes to BOEM’s rules applicable to us or our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows, and results of operations.

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Subsequent event. On January 23, 2018, the Company canceled $22.3 million in performance bonds in response to receiving confirmation from the CNH that the Consortium had fulfilled its obligation under the minimum work program in Block 7.

Other Commitments

On February 19, 2013, we signed a three-year agreement to use Helix’s Q4000 vessel (the “Q4000”) or equivalent substitute, a dynamic positioning semi-submersible vessel specifically designed for well intervention and construction. The contract was effective beginning on January 1, 2015 and was amended January 9, 2017. The Q4000 is expected to be utilized for certain deep water well intervention and decommissioning activities for properties operated by the Company. Under the amended terms of the agreement, the Company will pay Helix a base vessel day work rate based on the number of days contracted at a minimum of 20 days per contract year through 2019. As of December 31, 2017 the total estimated minimum payments in 2018 and 2019 are approximately $6.5 million and $6.7 million, respectively.

We had no drilling rig commitments with a term that exceed one year as of December 31, 2017. Future minimum payments for drilling rig commitments as of December 31, 2017 were $3.9 million.

Subsequent event. On February 8, 2018, the Company amended a previous agreement to use the Ensco 75, a jackup drilling rig, to execute a portion of the Company’s 2018 drilling program. Under the terms of the amendment, the Company will pay Ensco a base vessel day work rate based on the number of days contracted for 60 additional days during 2018. The estimated payments in 2018 are approximately $7.8 million, which includes the $3.9 million related to the agreement prior to the amendment.

Office Lease Obligations

On December 13, 2017, we entered into an eleven year operating lease beginning August 2018 for office space at Three Allen Center in Houston, Texas. In addition to the office lease executed in 2017, we have office leases in Houston, Texas; Dallas, Texas; Dulac, Louisiana and Mexico. Total future minimum lease payments in 2018, 2019, 2020, 2021 and thereafter are $4.1 million, $4.3 million, $3.8 million, $3.8 million and $30.5 million, respectively.

Note 11 —Selected Quarterly Financial Data (Unaudited)

Unaudited quarterly financial data are as follows (in thousands):

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Note 12 – Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs

Aggregate amounts of capitalized costs relating to our oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion, depreciation and amortization as of the dates indicated are presented below (in thousands):

Included in the depletable basis of our proved oil and gas properties is the estimate of our proportionate share of asset retirement costs relating to these properties which are also reflected as asset retirement obligations in the accompanying consolidated balance sheets. At December 31, 2017 and 2016 our oil and gas asset retirement obligations totaled $214.7 million and $220.0 million, respectively.

Costs Incurred for Property Acquisition, Exploration and Development Activities

The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year.

Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves

We have employed full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Our engineering reserve estimates were prepared based upon interpretation of production performance data and sub-surface information obtained from the drilling of existing wells. Our Director of Reserves, internal reservoir engineers and geologists analyzed and prepared reserve estimates on all of our oil and natural gas fields. All of the Company’s proved oil, natural gas and NGL reserves are located offshore in the Gulf of Mexico and lower Gulf Coast regulated by the United States, the State of Louisiana, or the State of Texas.

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At December 31, 2017 and 2016, 100% of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil and natural gas properties were estimated and complied for reporting purposes by our reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists. At December 31, 2015, 100% of proved oil, natural gas and NGL reserves attributable to our net interests in legacy oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers and audited by Ryder Scott, independent petroleum engineers and geologists and 100% of proved oil, natural gas and NGL reserves attributable to the assets acquired in the GCER Acquisition were estimated and compiled for reporting purposes by our reservoir engineers and audited by NSAI.

The following table presents our estimated proved reserves at our net ownership interest:

During 2017, the Company added 12.5 MMBoe of estimated proved reserves from extensions and discoveries primarily from drilling our Tornado II exploration prospect. These were offset by a decrease of 10.5 MMBoe of production and 5.1 MMBoe of negative performance revisions.

During 2016, the Company added 13.9 MMBoe of estimated proved reserves through the purchase of reserves from the asset transaction of the Sojitz Acquisition. The Company also added 26.6 MMBoe of estimated proved reserves from extensions and discoveries from successful drilling of the Tornado exploration well in the Phoenix Field.

During 2015, the Company added 9.5 MMBoe of estimated proved reserves through purchases of reserves consisting of 5.1 MMBoe and 4.4 MMBoe in estimated proved reserves acquired in the GCER Acquisition and DGE Acquisition, respectively. Downward revisions of previous estimates of 7.0 MMBoe were primarily due to the significant decline in commodity prices resulting in uneconomic reserves.

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The following table reflects the standardized measure of discounted future net cash flows relating to our interest in proved oil, natural gas and NGL reserves (in thousands):

Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of our derivative instruments. See the following table for base prices used in determining the standardized measure:

Future net cash flows are discounted at the prescribed rate of 10%. We caution that actual future net cash flows may vary considerably from these estimates. Although our estimates of total proved reserves, development costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves.

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Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to our proved oil, natural gas and NGL reserves are as follows (in thousands):

Note 13 —Subsequent Events

Derivative Contracts

For additional information, see Note 5 - Financial Instruments.

Bank Credit Facility

For additional information, see Note 6 – Debt.

2018 Senior Notes

For additional information, see Note 6 – Debt.

Performance Obligations

For additional information, see Note 10 – Commitments and Contingencies.

Other Commitments

For additional information, see Note 10 – Commitments and Contingencies.

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