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

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

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

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

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

As of ~~August 3, 2018,~~October 26, 2022, the registrant had ~~54,155,768~~82,570,328 shares of common stock, $0.01 par value per share, outstanding.

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

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

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

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

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

~~Deepwater.~~ Deepwater —Water depths of more than 600 ~~feet where there is clearly defined infrastructure, production history and geological well control to reduce operational and investment risk in development and exploitation activities.~~feet.

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

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

~~Gross acres or gross wells.~~ ~~The total acres or wells~~GAAP — Accounting principles generally accepted in ~~which~~ the ~~Company owns a working interest.~~United States of America.

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

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

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

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

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

~~Productive well.~~ ~~A well that is found to be capable~~OPEC — Organization of ~~producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.~~Petroleum Exporting Countries.

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

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

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

SEC ~~pricing.~~ pricing —The unweighted average first-day-of-the-month commodity price for crude oil or natural gas for each month within the 12-month period prior ~~twelve months,~~to the end of the reporting period, adjusted by lease for market differentials (quality, transportation, fees, energy content, and regional price differentials). The ~~Securities and Exchange Commission~~SEC provides a complete definition of prices in “~~Modernization~~“Modernization of Oil and Gas ~~Reporting~~”Reporting” (Final Rule, Release Nos. 33-8995; 34-59192).

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

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

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

The information in this ~~report~~Quarterly Report on Form 10-Q (this “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this ~~report,~~Quarterly Report, regarding ~~the Company’s~~our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this ~~report,~~Quarterly Report, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” ~~“project”~~“project,” “forecast,” “may,” “objective,” “plan” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on ~~the Company’s~~our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements about:

We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility ~~inflation,~~due to the continued impact of the coronavirus disease 2019 (“COVID-19”), including any new strains or variants, and governmental measures related thereto on global demand for oil and natural gas and on the operations of our business; the ability or willingness of OPEC and other state-controlled oil companies (“OPEC Plus”), such as Saudi Arabia and Russia, to set and maintain oil production levels; the impact of any such actions; the lack of a resolution to the war in Ukraine and its impact on certain commodity markets; lack of transportation and storage capacity as a result of oversupply, government and regulations; lack of availability of drilling and production equipment and ~~services,~~services; adverse weather events, including tropical storms, hurricanes and winter storms; cybersecurity threats; sustained inflation and the impact of central bank policy in response thereto; environmental ~~risks,~~risks; failure to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current discoveries and prospects; geologic risk; drilling and other operating ~~risks,~~risks; well control ~~risk,~~risk; regulatory ~~changes,~~changes; the uncertainty inherent in estimating reserves and in projecting future rates of ~~production,~~production; cash flow and access to ~~capital,~~capital; the timing of development ~~expenditures,~~expenditures; potential adverse reactions or ~~changes to business or employee relations resulting from the business combination between Talos Energy LLC and Stone Energy Corporation,~~ competitive responses to ~~such business combination,~~our acquisitions and other transactions; the possibility that the anticipated benefits of ~~such business combination~~our acquisitions are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of ~~the two companies, litigation relating to the business combination,~~acquired assets and operations, and the other risks discussed in Part I, Item 1A. “Risk Factors” of Talos Energy Inc.’s Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 25, 2022 (the “2021 Annual Report”), Part II, Item ~~1A,~~1A. “Risk Factors” ~~herein.~~of Talos Energy Inc.’s Quarterly Report on Form 10-Q for the period ended March 31, 2022, filed with the SEC on May 5, 2022 and Part II, Item 1A. “Risk Factors” of Talos Energy Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2022, filed with the SEC on August 5, 2022.

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

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

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

Note 3 — Leases

The Company has operating leases principally for office space, drilling rigs, compressors and other equipment necessary to ~~purchasers under short-term contracts (less than twelve months) at market prices when delivery~~support the Company’s operations. Additionally, the Company has a finance lease related to the ~~customer has occurred, title has transferred, prices are fixed and determinable and collection~~use of the Helix Producer I (the “HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy. The HP-I 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~~utilized in the Company’s ~~entitled~~oil and natural gas development activities and the right-of-use asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserves using the unit-of-production method, computed quarterly. Costs associated with the Company’s leases are either expensed or capitalized depending on how the underlying asset is utilized.

Table of Contents

The lease costs described below are presented on a gross basis and do not represent the Company’s net proportionate share of ~~production with any difference recorded as an imbalance on the condensed consolidated balance sheet. Upon the adoption~~such amounts. A portion of ~~ASC 606, revenues are recorded based on the actual sales volumes sold~~these costs have been or may be billed to ~~purchasers. An imbalance receivable or payable is recorded only to the extent the imbalance is in excess of its~~other working interest owners. The Company’s share of ~~remaining proved developed reserves~~these costs is included 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 directproperty and equipment, lease operating expense ~~on the condensed consolidated statement~~or general and administrative expense, as applicable. The components 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~~costs were as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Finance lease cost - interest on lease liabilities	$	1,386	$	2,749	$	5,179	$	9,017
Operating lease cost, excluding short-term leases(1)		568		702		1,703		2,138
Short-term lease cost(2)		12,982		14,541		24,838		32,393
Variable lease cost(3)		363		350		1,088		994
Total lease cost	$	15,299	$	18,342	$	32,808	$	44,542

(1)

Operating 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 ascost reflect 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~~

(2)

Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a right-of-use asset and lease liability on the Condensed Consolidated Balance Sheets.

(3)

Variable lease ~~liability separately from amortization of the right-to-use asset. ASU 2016-02 does not apply to leases for oil~~costs primarily represent differences between minimum payment obligations 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.

~~Note 2 — Summary of Significant Accounting Policies~~

~~Below are the Company’s significant accounting policies that have been implemented or changed since December 31, 2017.~~

~~Income Taxes~~

Prior to the Stone Combination, Talos Energy LLC was a partnership for federal income tax purposes and was not subject to federal income tax or state income tax (in most states). As such, Talos Energy LLC was not a taxpaying entity for federal income tax purposes and accordingly, did not recognize any expenses for such states. In connection with completing the Stone Combination, Talos Energy LLC was contributed toactual operating charges incurred by the Company ~~which is subject~~related to ~~federal and state income taxes.~~ its long-term leases.

The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. Changes in tax laws are recorded in the period they are enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the consolidated balance sheets.

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

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

~~Earnings Per Common Share~~

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

~~Share-Based Compensation~~

The Company records share-based compensation associated with restricted stock units in general and administrative expense on the condensed consolidated statement of operations, net of amounts capitalized to oil and gas properties. Share-based compensation expense is based on the grant date fair value of issued restricted stock units recognized over the vesting period of the instrument. For each restricted stock unit grant, the Company determines whether the awards represent equity or liability based awards. The fair value of equity awards are determined based on the close price of the stock on the grant date. The fairpresent 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~~.

~~Note 3 — Acquisitions~~

~~Combination Between Talos Energy LLC and Stone Energy Corporation~~

On May 10, 2018, the Company consummated the Transactions contemplated by the Transaction Agreement and the Exchange Agreement, pursuant to which, among other things, Talos Energy LLC and Stone became wholly-owned subsidiaries of the Company. Substantially concurrent with the consummation of the Transactions, the name of the Company was changed from Sailfish Energy Holdings Corporation to Talos Energy Inc. The combination was executedfixed lease payments recorded as ~~an all-stock transaction whereby the former stakeholders of Talos Energy LLC held approximately 63% of~~ the Company’s ~~outstanding Common Stock~~right-of-use asset and ~~the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Closing Date.~~

The purchase price of $732.0 million is based on the closing price of Stone common stock and common warrants immediately prior to closing. The following table summarizes the purchase price (in thousands, except per share data):

Stone Energy common stock - issued and outstanding as of May 9, 2018

20,038

Stone Energy common stock price

$
35.49

Common stock value

$
711,149

Stone Energy common stock warrants - issued and outstanding as of May 9, 2018

3,528

Stone Energy common stock warrants price

$
5.90

Common stock warrants value

$
20,815

Total consideration and fair value

$
731,964

The Company incurred approximately $76.2 million of transaction related costs, of which, $20.1 million was expensed and reflected in general and administrative expense on the condensed consolidated statement of operations. The remaining $56.1 million was the result of (i) $9.3 million in work fees paid to holders of the 11.00% Senior Secured Notes reflected as a debt discount reducing long-term debt on the condensed consolidated balance sheet and (ii) $46.8 million in fees for seismic use agreements for change in control provisions and reflected in proved properties on the condensed consolidated balance sheet.

The Stone Combination qualified as a business combination and was accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the condensed consolidated balance sheet at their fair values as of the acquisition date, May 10, 2018. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates at the time of the valuation.

While the Company has substantially completed the determination of the fair values of the assets acquired and liabilities assumed, the Company is still finalizing the fair value analysis related to oil and natural gas properties and the related asset retirement obligations. The Company anticipates finalizing the determination of the fair values by December 31, 2018. The following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on May 10, 2018 (in thousands):

Current assets⁽¹⁾

$
377,155

Property and equipment

876,500

Other long-term assets

18,928

Current liabilities

(130,121
)
Long-term debt

(235,416
)
Other long-term liabilities

(175,082
)
Allocated purchase price

$
731,964

~~(1)~~

Includes $293.0 million of cash acquired. The fair values of current assets acquired includes trade receivables and joint interest receivables of $43.3 million and $3.5 million, respectively, which the Company expects all to be realizable.

~~Pro Forma Financial Information (Unaudited)~~

The following supplemental pro forma information (in thousands, except per common share amounts), presents the condensed consolidated results of operations for the three and six months ended June 30, 2018 and 2017 as if the Stone Combination had occurred on January 1, 2017. The unaudited proforma information was derived from historical combined statements of operations of the Company and Stone and adjusted to include (i) depletion and accretion expense applied to the adjusted basis of the oil and natural gas properties acquired (ii) interest expense to reflect the debt transactions contemplated by the Exchange Agreement and (iii) general and administrative expenseliability, adjusted for ~~transaction related~~initial direct costs incurred. This information does not purport to be indicative of results of operations that would have occurred had the Stone Combination occurred on January 1, 2017, nor is such information indicative of any expected future results of operations.

Three Months Ended June 30,

Six Months Ended June 30,

2018

2017

2018

2017

Revenue

$
244,453

$
166,669

$
471,652

$
340,939

Net income (loss)

$
(45,696
)

$
19,032

$
(51,211
)

$
66,518

Basic and diluted net income (loss) per common share

$
(0.84
)

$
0.35

$
(0.95
)

$
1.23

~~Material, non-recurring adjustments included in pro forma net income (loss) above consist of historical Stone results adjusted to exclude a divestiture of oil~~ and ~~natural gas properties during 2017.~~

~~Note 4 — Property, Plant and Equipment~~

~~Proved Properties.~~ The Company’s interests in oil and natural gas properties are located in the United States (“U.S.”) primarily in the Gulf of Mexico deep and shallow waters. The Company follows the full cost method of accounting for its oil and natural gas exploration and development activities.

Pursuant to SEC Regulation S-X, Rule 4-10, under the full cost method of accounting, the Company’s capitalized oil and natural gas costs, net of related deferred taxes, are limited to a ceiling based on the present value of future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized. The Company performs this ceiling test calculation each quarter utilizing SEC pricing. At June 30, 2018, the Company’s ceiling test computation of its U.S. oil and natural gas properties was based on SEC pricing of $60.03 per Bbl of oil, $2.90 per Mcf of natural gas and $28.26 per Bbl of NGLs. During the three and six months ended June 30, 2018 and 2017, the Company’s ceiling test computation did not result in a write-down of its U.S. oil and natural gas properties.

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

~~Capitalized Overhead.~~ General and administrative expense in the Company’s financial statements is reflected net of capitalized overhead. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities. Capitalized overhead for the three months ended June 30, 2018 and 2017 was $4.5 million and $3.1 million, respectively. Capitalized overhead for the six months ended June 30, 2018 and 2017 was $7.5 million and $6.5 million, respectively.

~~Asset Retirement Obligations.~~ The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when it no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount it will incur to plug, abandon, replace, remove and/or remediate the associated assets at the end of their productive lives. See Note 11 – ~~Commitments and Contingencies~~ ~~relating to performance bonds associated with plugging and abandoning wells.~~

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

The discounted asset retirement obligations included on the condensed consolidated balance sheets in current and non-current liabilities and the changes to that liability during the six months ended June 30, 2018incentives were as follows (in thousands):


	September 30, 2022		December 31, 2021
Operating leases:
Operating lease assets	$	5,518	$	5,714

Current portion of operating lease liabilities	$	1,885	$	1,715
Operating lease liabilities		14,895		16,330
Total operating lease liabilities	$	16,780	$	18,045

Finance leases:
Proved property	$	124,299	$	124,299

Other current liabilities	$	20,458	$	27,083
Other long-term liabilities		—		13,138
Total finance lease liabilities	$	20,458	$	40,221

The table below presents the supplemental cash flow information related to leases (in thousands):


	Nine Months Ended September 30,
	2022		2021
Operating cash outflow from finance leases	$	5,179	$	9,017
Operating cash outflow from operating leases	$	2,776	$	2,946

Right-of-use assets obtained in exchange for new operating lease liabilities	$	—	$	1,020

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

As of ~~June~~September 30, ~~2018~~2022 and December 31, ~~2017,~~2021, the carrying amounts of cash and cash equivalents, ~~restricted cash,~~ accounts receivable and accounts payable approximate their fair values because of the short-term nature of these instruments.

The carrying value of the senior notes are presented net of the original issue discount and deferred financing ~~costs (see Note 6 –~~ ~~Debt). The fair~~costs. Fair value ~~of the 11.00% Senior Secured Notes are~~is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.

~~7.50% Senior Secured Notes – due May 2022~~. The ~~$6.1 million aggregate principal~~carrying amount of ~~7.50% Stone Senior Notes are reported on the condensed consolidated balance sheet as of June 30, 2018 at their carrying value (see Note 6 –~~ ~~Debt). The fair value of the 7.50% Senior Secured Notes are estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.~~

~~Bank Credit Facility – due May 2022.~~ ~~On May 10, 2018, in connection with the Stone Combination,~~ the Company’s ~~senior reserve-based revolving credit facility (“Old Bank Credit Facility”) was repaid and terminated, and the Company executed a new~~ bank credit facility, ~~with an initial borrowing base of $600.0 million (“Bank~~as amended and restated (the “Bank Credit Facility”)~~. The Old Bank Credit Facility was repaid with borrowings from the Bank Credit Facility and cash acquired in the Stone Combination. The Company’s Bank Credit Facility~~, is ~~reported on the condensed consolidated balance sheet as of June 30, 2018 at its carrying value~~presented net of deferred financing ~~costs (see Note 6 –~~ ~~Debt~~).costs. The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the ~~Company’s~~ Bank Credit Facility since it is secured by the Company’s reserves and the interest rates are variable and reflective of market rates (representing a Level 2 fair value measurement).

The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas ~~production through the use of~~production. The Company is currently utilizing oil and natural gas swaps ~~put contracts~~ and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from counterparties. Collar contracts typically require payments by the ~~counterparties. The~~ Company ~~has elected not~~if the NYMEX average closing price is above the ceiling price or payments to ~~designate any of its derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on~~ the ~~condensed consolidated balance sheet at fair value with settlements of such contracts and changes in~~Company if the ~~unrealized fair value recorded as~~NYMEX average closing price ~~risk management activities income (expense) on~~is below the ~~condensed consolidated statements of operations in each period.~~floor price.

Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although the Company has master netting arrangements with its counterparties, the Company presents its derivative financial instruments on a gross basis onin its ~~condensed consolidated balance sheets. On derivative contracts recorded as assets in the table below, the Company is exposed to the risk the counterparties may not perform.~~ Condensed Consolidated Balance Sheets. The following table presents the fair value of derivative financial instruments ~~at June 30, 2018~~as well as the potential effect of netting arrangements on the Company's recognized derivative asset and ~~December 31, 2017~~liability amounts (in thousands):

7.50% Senior ~~Secured~~ Notes ~~– due May 2022~~. The 7.50% Stone Senior Notes represent the remaining $6.1 million of long-term debt assumed in the Stone Combination that were not exchanged for 11.00% Senior Secured Notes pursuant to the exchange offer and consent solicitation, and thus remain outstanding. As a result of the exchange offer and consent solicitation, substantially all of the restrictive covenants relating to the 7.50% Stone Senior Notes have been removed and collateral securing the 7.50% Stone Senior Notes have been released. The 7.50% Stone Senior Notes mature

On May 31, 2022 ~~and have interest payable semiannually each May 31 and November 30. Prior to May 31, 2020,~~, the ~~Company may, at its option, redeem all or a portion of the 7.50% Stone~~7.50% Senior Notes matured and were redeemed at ~~100%~~an aggregate principal of ~~the principal amount~~$6.1 million plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 7.50% Stone Senior Notes at redemption prices decreasing annually from 105.625% to 100.0% plus accrued and unpaid interest.

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

The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%. In addition, the Company is obligated to pay a commitment fee of 0.50% on the unfunded portion of the commitments under the Bank Credit Facility. The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a total debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 each quarter beginning on or after September 30, 2018. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter beginning on or after September 30, 2018. According to the Bank Credit Facility, undrawn commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by substantially all of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by certain of the Company’s wholly-owned subsidiaries and each direct parent of the Company.

institutions. The Bank Credit Facility provides for the determination of the borrowing base based on the Company’s proved producing reserves and a portion of ~~its~~the Company's proved undeveloped reserves.The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth ~~quarter. In June 2018,~~quarter of each year. On May 4, 2022, the Company ~~completed~~entered into a (i) Borrowing Base Redetermination Agreement and Eighth Amendment to Credit Agreement (the “Eighth Amendment”) and (ii) Incremental Agreement of Increasing Lenders (“Incremental Agreement”). The Eighth Amendment and the ~~first redetermination and~~Incremental Agreement, among other things, (i) increased the borrowing base ~~was reaffirmed at $600.0~~from $950.0 million to $1.1 billion and (ii) increased the commitments from $791.3 million to $806.3 million. ~~The next redetermination will occur in October 2018 and scheduled redeterminations will occur each April and October thereafter.~~

The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. The Company was in compliance with all debt covenants at June 30, 2018. As of June 30, 2018, the Bank Credit Facility ~~had approximately $354.0 million of undrawn commitments (taking into account $6.0 million letters of credit and $240.0 million drawn from~~no longer bears interest at the ~~Bank Credit Facility). The $294.0 million in cash received from~~applicable London InterBank Offered Rate plus the ~~Company’s initial drawdown~~applicable margin. Interest under the Bank Credit Facility ~~was used to partially repay outstanding borrowings under~~accrues at the ~~Old Bank Credit Facility upon its termination in connection with~~Company’s option either at an alternate base rate (“ABR”) plus the ~~Stone Combination.~~

~~Building Loan – due November 2030. In connection with~~applicable margin (“ABR Loans”), an adjusted term secured overnight financing rate (“SOFR”) plus the ~~Stone Combination,~~applicable margin (“Term Benchmark Loans”) or adjusted daily simple SOFR plus the ~~Company assumed Stone’s 4.20% term loan maturing on November 20, 2030 (the “Building Loan”~~applicable margin (“RFR Loans”). The ~~Building Loan bears~~ABR is based on the greater of (a) the prime rate, (b) a federal funds rate plus 0.5% or (c) the adjusted term SOFR for a one-month interest ~~at a rate of 4.20% per annum~~period plus 1.00%. The adjusted term SOFR is equal to the term SOFR for each applicable tenor (e.g., one-month, three-months, six-months, and is to be repaid in 180 equal monthly installments of approximately $0.1 million. As of June 30, 2018, the outstanding balance under the Building Loan totaled $10.8 million. The Building Loan is collateralizedtwelve-months) calculated and published by the Company’s two Lafayette, Louisiana office buildings. Under the financial covenants of the Building Loan, the Company must maintain a ratio of EBITDA to Net Interest Expense of not less than 2.00 to 1.00. In addition, the Building Loan contains certain customary restrictions or requirements with respect to change of control and reporting responsibilities. The Company is in compliance with all covenants under the Building Loan as of June 30, 2018.

~~9.75% Senior Notes – due February 2018~~CME Group Inc. plus 0.10%. The ~~9.75% Senior Notes were issued pursuant~~adjusted daily simple SOFR is equal to ~~an indenture dated February~~the overnight SOFR calculated and published by the Federal Reserve Bank of New York plus 0.10%. The applicable margin, which is based on the borrowing base utilization percentage, ranges from 2.00% to 3.00% for ABR Loans and 3.00% to 4.00% for Term Benchmark Loans and RFR Loans.

Item 2. Management’s Discussion and Analysis of ~~the transactions contemplated by the Transaction Agreement~~Financial Condition and ~~the Exchange Agreement (the “Transactions”) the former stakeholders~~Results 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.Operations

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

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with our Condensed Consolidated Financial Statements and notes thereto in Part I, Item 1. “Condensed Consolidated Financial Statements” of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 2021 Annual Report and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2021 Annual Report.

We are a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through our operations, currently in the United States (“U.S.”) and offshore Mexico both through upstream oil and gas exploration and production and the development of carbon capture and sequestration (“CCS”) opportunities. We leverage decades of technical and offshore operational expertise towards the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. With a focus on environmental stewardship, we also utilize our expertise to explore opportunities to reduce industrial emissions through our CCS initiatives both in and along the coast of the U.S. Gulf of Mexico.

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

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

Below is a cumulative list of significant developments that have occurred since the filing of our Quarterly Report on Form 10-Q for the period ended June 30, 2022.

EnVen Acquisition— On September 21, 2022, we executed a merger agreement to acquire EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico, for approximately $1.1 billion in stock and cash consideration (the “EnVen Acquisition,” and such agreement, the “EnVen Merger Agreement”). The EnVen Acquisition is expected to double our operated Deepwater facility footprint by adding key infrastructure in our existing operating areas. Upon closing, we expect this to increase our production by approximately 40% or 24.0 MBoep/d and increase our gross acreage by 35%.

Consideration for the EnVen Acquisition consists of 43.8 million shares of our common stock and $212.5 million in cash, subject to certain adjustments. Following the EnVen Acquisition, our shareholders will own approximately 66% of the pro forma company and EnVen’s equity holders will own the remaining 34%. The closing of the EnVen Acquisition is expected to occur by late December 2022 or early January 2023.

On October 21, 2022, Talos Production Inc. commenced a consent solicitation to obtain the requisite holders’ consent to certain amendments to the indenture governing its 12.00% Notes (as defined below under “— Liquidity and Capital Resources — Overview of Debt Instruments”) to permit the incurrence of indebtedness with respect to EnVen’s 11.75% Senior Secured Second Lien Notes due 2026. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 10 — Commitments and Contingencies” for additional information.

2022 Drilling Program — We recently commenced drilling operations with the Seadrill Sevan Louisiana rig on our Lime Rock prospect near our operated Ram Powell facility and the rig will move to drill the adjacent Venice prospect once the Lime Rock drilling operations are complete. We own a 60% working interest in both prospects and expect first oil within 12-18 months from beginning drilling operations at each prospect. Prior to commencing operations at Lime Rock, we encountered issues related to strong looping ocean currents while performing a well recompletion project. The recompletion operation has been suspended and we plan to ~~opportunistically expand~~return to the project at a later date.

Phoenix Field Update — Production from one of our ~~asset base~~Tornado wells generated increased water volumes during the third quarter primarily as a result of the ongoing sub-surface water flood project in the Phoenix Field. This water breakthrough occurred earlier than originally expected, though within the range of projected outcomes in previous reservoir simulations used for the 2021 year-end reserves. We currently expect minor negative revisions to proved reserves as a result of timing impacts of early water breakthrough.

Oxy Transaction— In August 2022, we entered into an eight block cross assignment (the “Joint Area”) with Occidental Petroleum Corporation (“Oxy”), which resulted in Oxy being the operator with a 70% working interest and we have the remaining 30% working interest. We contributed 100% working interest in two blocks within Green Canyon area to the Joint Area. We and Oxy will commence drilling an exploration well in the Joint Area in the first half of 2023.

Inflation Reduction Act of 2022 (the “IRA”)— On August 16, 2022, President Biden signed the IRA into law. The inclusion of several provisions in the IRA is expected to benefit both our upstream and CCS businesses. Specifically, the IRA directs the Department of the Interior (”DOI”) to:

We were one of the most active bidders in Lease Sale 257 and were the high bidder on 10 blocks and awarded leases on 9 blocks. The ~~acquisition strategy~~IRA also links issuance of federal wind and solar development rights to requirements to offer for sale federal oil and gas leases for a 10-year period of time. The IRA requires the federal government to offer for sale a minimum of 60 million acres for offshore oil and gas leases during the one-year period immediately preceding granting an offshore wind lease on the U.S. Outer Continental Shelf.

The IRA incentivizes additional capital investment in CCS projects by developers and sponsors through the following:

The IRA also raises the minimum oil and gas royalty rate for new offshore leases from the current 12.5% to 16.7% and caps the royalty rate at 18.8% for 10 years; however this provision does not affect existing offshore leases. The 18.8% cap is commensurate with existing offshore royalty rate for leases in water depth exceeding 200 meters.

Additionally, the IRA imposes a first-ever federal fee on ~~deep and shallow water assets with~~greenhouse gases through a ~~geological setting which we believe can benefit~~methane emissions charge. The IRA amends the federal Clean Air Act to impose a charge on emissions of methane from ~~our access~~sources required to an extensive seismic database and our reprocessing expertise to reevaluate the acquired assets. We expect to target acquisitions involving assets with physical infrastructure that will allow us to focus on additional drilling opportunities. By applying a disciplined valuation methodology, we seek to reduce the risk of acquired property underperformance while maintaining potential for higher returns on our investment. In addition, we may consider acquisition opportunities in other offshore basins with analogous geologies that are suitable for our operational and technical expertisereport their GHG emissions to the ~~extent we believe it~~U.S. Environmental Protection Agency (“EPA”), including those sources in the offshore and onshore oil and gas production, and onshore processing, transmission and compression, gathering, and boosting station source categories. For such qualifying facilities, the charge starts at $900 per metric ton of methane reported for calendar year 2024, increasing to $1,200 per metric ton of methane for calendar year 2025 and again to $1,500 per metric ton of methane for calendar year 2026 and year thereafter. Calculation of the charge is based on certain thresholds established in the IRA. The charge will be based on the prior year’s emissions, and the charge starts in 2025 based on 2024 data. The methane emissions charge could increase our ~~reserves~~operating costs and ~~enhance returns on~~adversely affect our ~~investment and long-term growth prospects.~~business.

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

~~As previously described, Stone~~The following items affect the comparability of our financial condition and Talos Energy LLC became our wholly-owned subsidiaries on the Closing Date. Prior to the Closing Date, we had not conducted any material activities other than those incident to our formation and certain matters contemplated by the Transaction Agreement. Talos Energy LLC is the acquirer of Stone for financial reporting and accounting purposes. Talos Energy LLC was considered the accounting acquirer in the Transactions under accounting principles generally accepted in the United States of America (“GAAP”). Accordingly, our historical financial and operating data, which cover periods prior to May 10, 2018, reflects the assets, liabilities and operations of Talos Energy LLC prior to the Closing Date and does not reflect the assets, liabilities and operations of Stone prior to the Closing Date. In addition, we incurred material costs associated with the Transactions that are reflected in our historical results of operations for periods ~~prior~~presented herein and could potentially continue to affect our future financial condition and results of operations.

Planned Downtime — We are vulnerable to downtime events impacting the ~~Closing Date,~~transportation, gathering and ~~Talos Energy LLC did not incur United States federal income tax expense or the incremental expenses associated with being a public company.~~

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

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

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

~~Revenue.~~ Total revenue for the three months ended June 30, 2018 was $203.9 million compared to $95.4 million for the three months ended June 30, 2017, an increase of approximately $108.5 million, or 114%. Oil revenue increased approximately $101.4 million, or 129%, during the three months ended June 30, 2018. This increase was primarily due to an increase of $21.98 per Bbl in our realized oil sales price and a 10.3 MBblpd increase in oil production volumes. The increase in oil production volumes was attributable to 9.6 MBblpd from the Stone Combination and 3.3 MBblpd from the Tornado II well inproduction. We produce the Phoenix Field ~~which commenced initial production in December 2017. This was partially offset by 1.1 MBblpd deferred production from the Phoenix Field for unplanned third party downtime for~~through the Helix Producer I ~~(“HP-I”~~(the “HP-I”) ~~as determined~~that is operated by Helix Energy Solutions Group, Inc. ~~(Helix”~~(“Helix”). Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the U.S. Coast Guard, during which time we are unable to produce the Phoenix Field.

~~Natural gas revenue increased approximately $3.6 million, or 28%, during~~During the three months ended ~~June~~September 30, ~~2018. This increase was primarily due to~~2022, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-September, resulting in a ~~19.1 MMcfpd increase~~total shut-in period of 41 days. The shut-in resulted in ~~gas volumes, 22.6 MMcfpd~~an estimated deferred production of ~~which was attributable to the Stone Combination. This is partially offset by a $0.29 per Mcf decrease in our realized gas sales price.~~

~~NGL revenue increased~~ approximately ~~$3.9 million, or 112%, during the three months ended June 30, 2018. This increase was due to an increase of $6.03 per Bbl in our realized NGL sales price~~6.2 MBoepd and ~~a 1.2 MBblpd increase in NGL volumes, all of which was attributable to the Stone Combination.~~

~~Lease operating expense.~~ ~~Total lease operating expense for three months ended June 30, 2018 was $38.9 million compared to $31.9 million~~2.1 MBoepd for the three and nine months ended ~~June~~September 30, ~~2017, an increase~~2022, respectively, based on production rates prior to the shut-in.

During the third quarter of 2022, we experienced approximately 17 days of planned third-party downtime due to maintenance of the Shell Odyssey Pipeline, which carries our production primarily from our Ram Powell Field, Main Pass 288 Field and non-operated Delta House facility. Production resumed in October 2022. We estimate the shut-in resulted in deferred production of approximately $6.9 million, or 22%. This increase was primarily related to $9.9 million of lease operating expense in connection with the Stone Combination, partially offset by a $2.9 million decrease due to additional reimbursements related to our production handling agreements in the Phoenix Field.

~~Depreciation, depletion~~1.8 MBoepd and ~~amortization.~~ ~~Depreciation, depletion and amortization expense~~0.6 MBoepd for the three and nine months ended ~~June~~September 30, ~~2018 was $67.7 million compared~~2022, respectively, based on production rates prior to ~~$36.2 million for~~ the ~~three months ended June 30, 2017, an increase~~shut-in.

Eugene Island Pipeline System — During the first quarter of 2022, we experienced approximately ~~$31.6 million, or 87%. This increase is primarily~~40 days of unplanned third-party downtime due to a $3.33 per Boe, or 24%, increase in the depletion rate on our proved oil and natural gas properties during the three months ended June 30, 2018. Depletion on a per Boe basis increased primarily due to an increase in proved properties related to the Stone Combination and higher estimated future development costs related to proved undeveloped reserves in the Phoenix Field.

~~General and administrative expense.~~ General and administrative expense for the three months ended June 30, 2018 was $30.9 million compared to $7.5 million for the three months ended June 30, 2017, an increase of approximately $23.4 million, or 313%. This increase was primarily attributable to $18.3 million in transaction related costs related to the Stone Combination and additional general and administrative expenses as a resultmaintenance of the ~~combined company.~~

~~Other operating expense.~~ Other operating expense for the three months ended June 30, 2018 was $27.2 million compared to $13.5 million for the three months ended June 30, 2017, an increase of approximately $13.7 million, or 101%. This increase was primarily related to an increase of $4.5 million and $4.1 million in workover and maintenance expense and accretion expense, respectively, in connection with the Stone Combination. This increase also relates to a $5.0 million increase in repairs and maintenance during the three months ended June 30, 2018 primarily related to $1.3 million in repairs on SMI 130 and inspection and reconnection support in the Phoenix Field of $1.2 million.

~~Price risk management activities.~~ Price risk management activities for the three months ended June 30, 2018 resulted in a $91.2 million expense compared to income of $39.0 million for the three months ended June 30, 2017. The change of approximately $130.2 million was attributable to a $87.4 million decrease in the fair value ofEugene Island Pipeline System, which carries our open derivative contracts and a $42.8 million decrease in cash settlement gains for the three months ended June 30, 2018. These unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our condensed consolidated statements of operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through 2019, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

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

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

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

~~Revenue.~~ Total revenue for the six months ended June 30, 2018 was $349.8 million compared to $197.3 million for the six months ended June 30, 2017, an increase of approximately $152.5 million, or 77%. Oil revenue increased approximately $145.4 million, or 89%, during the six months ended June 30, 2018. This increase was primarily due to an increase of $18.90 per Bbl in our realized oil sales price and a 6.7 MBblpd increase in oil production volumes. The increase in oil production volumes was attributable to 4.8 MBblpd from the Stone Combination and 3.3 MBblpd from the Tornado II well in the Phoenix Field which commenced initial production in December 2017. This was partially offset by 0.6 MBblpd deferred production from the Phoenix Field and Green Canyon 18 Field. For the nine months ended September 30, 2022, we estimate the shut-in resulted in deferred production of approximately 1.5 MBoepd based on production rates prior to the shut-in.

Hurricanes and Tropical Storms — During the third quarter of 2021, production from the U.S. Gulf of Mexico was impacted due to Hurricane Ida. While our assets did not sustain significant damage, the storm impacted key third-party downstream infrastructure, which prevented us from restoring the majority of our production for ~~unplanned third party downtime for~~several weeks. For the ~~HP-I as determined by Helix.~~

~~Natural gas revenue increased~~three and nine months ended September 30, 2021, we estimate that deferred production related to this storm was approximately ~~$3.1 million,~~12.7 MBoepd and 4.3 MBoepd, respectively, based on production rates prior to the storm. We did not experience any disruptions to our operations from hurricanes or ~~12%,~~tropical storms during the ~~six~~three and nine months ended ~~June~~September 30, 2018. This increase was due to an 8.7 MMcfpd increase in gas volumes, 11.4 MMcfpd of which was attributable to the Stone Combination. This was partially offset by a $0.17 per Mcf decrease in our realized gas sales price.2022.

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

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

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

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

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

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

See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2021 Annual Report for a detailed discussion of known trends and uncertainties. The following carries forward or provides an update to known trends and uncertainties discussed in our 2021 Annual Report.

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

With respect to our operations in Mexico, our oil and natural gas properties are classified as unproved properties, not subject to ~~wide fluctuations~~amortization. The submission of the Unit Development Plan for the Zama Field to the National Hydrocarbon Commission, which will set out the terms on which the reservoir will be jointly developed, is expected by March 2023 and could adversely affect the value of the Mexico oil and natural gas assets and result in ~~response to relatively minor changes in supply~~an impairment of our unevaluated oil and ~~demand.~~gas properties.

BOEM Bonding Requirements. — In order to cover the various decommissioning obligations of lessees on the Outer Continental Shelf (“OSC”), the Bureau of Ocean Energy Management (“BOEM”) generally requires that lessees post some form of acceptable financial assurances that such obligations will be met, such as surety bonds. The cost of such bonds or other financial assurance can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. As many BOEM regulations are being reviewed by the agency, we may be subject to additional financial assurance requirements in the future. For example, in July 2016, the BOEM issued the 2016 Notice to Lessees and Operators ~~(NTL) #2016-N01 (the “2016~~ (“NTL”) to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, rights of way (“ROWs”) and rights of use and easement (“RUEs”)., which bolstered supplemental bonding requirements. The ~~2016~~ NTL ~~became effective in September 2016, but~~was not fully implemented as the BOEM ~~has since extended indefinitely~~under the ~~start date for implementing~~Trump Administration first paused, and then in 2020 rescinded, this NTL so as to provide the BOEM with time to review its complex financial assurance program. This extension currently remains in effect. We remain in active discussions with government regulators and industry peers with regard to any future rulemaking and financial assurance requirements. Notwithstanding the BOEM’s 2016 NTL, the BOEM may also bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. NTL.

The future cost of compliance with respect to supplemental bonding, including the obligations imposed on ~~the Company~~us, whether as current or predecessor lessee or grant holder, as a result of the implementation of a new NTL analogous to the 2016 NTL to the extent ~~implemented,~~finalized, as well as to the provisions of any other ~~future~~new, more stringent NTLs or final rules on supplemental bonding published by the BOEM ~~directives, or any other changes to~~under the ~~BOEM’s rules applicable to the Company or its subsidiaries’ properties,~~Biden Administration, could materially and adversely affect ~~its~~our financial condition, cash flows and results of operations. Moreover, the BOEM has the right to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the current interest holder’s decommissioning liabilities and the Biden Administration may elect to pursue more stringent supplemental bonding requirements.

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

Oil Spill Response ~~Plan.~~Plan — We maintain a Regional Oil Spill Response Plan that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil ~~Spill Response Plans~~spill response plans are generally approved by the ~~Bureau of Safety and Environmental Enforcement (“BSEE”)~~BSEE bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. Additionally, these plans are tested and drills are conducted periodically at all levels.

~~Hurricanes.~~Hurricanes and Tropical Storms — Since our operations are in the U.S. Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes and tropical storms on ~~production. Additionally, affordable insurance coverage for property damage to our facilities for hurricanes has become less effective due to rising retentions~~production and ~~limitations on named windstorm coverage and has been difficult to obtain at times in recent years.~~capital projects. Significant ~~hurricane~~ impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.

~~Commitments~~Five-Year Offshore Oil and ~~Contingencies~~Gas Leasing Program Update — Under the Outer Continental Shelf Lands Act (“OCSLA”), as amended, the BOEM within the DOI must prepare and maintain forward-looking five-year plans—referred to by BOEM as national programs or five-year programs—to schedule proposed oil and gas lease sales on the U.S. Outer Continental Shelf. On May 11, 2022, the DOI cancelled two lease auctions in the Gulf of Mexico, Lease Sales 259 and 261, and one auction in the Cook Inlet, Alaska, Lease Sale 258, under the 2017-2022 national program that was developed under the Obama Administration, which expired on June 30, 2022. The DOI cited “conflicting court rulings” as the primary reason for not holding the two Gulf of Mexico lease sales. As discussed above under “ — Significant Developments,” President Biden signed the IRA into law on August 16, 2022. The IRA reinstates Lease Sale 257 held in November 2021, and requires the DOI to both accept all valid high bids received in Lease Sale 257 and issue leases to the high bidders. We were one of the most active bidders in Lease Sale 257 and we were the the high bidder on 10 blocks and awarded leases on 9 blocks. Furthermore, the DOI must hold Gulf of Mexico lease sales 259 and 261 by March 31, 2023, and September 30, 2023, respectively.

~~For~~BOEM’s development of a new national program typically takes place over several years, during which successive drafts of the program are published for review and comment. At the end of the process, the Secretary of the Interior must submit the Proposed Final Program to the President and to Congress for a period of at least 60 days, after which the program may be approved by the Secretary of the Interior and may take effect with no further regulatory or legislative action.

BOEM took the first formal step in pursuit of a new five-year national program in January 2018 by releasing a Draft Proposed Program. The OCSLA and its implementing regulations call for two subsequent drafts, a Proposed Program (“PP”), which is open for public comment for a period of at least 90 days, and then a Proposed Final Program, which is submitted to Congress and the President for 60 days before implementation. These later program stages also are accompanied by publication of a draft and final Programmatic Environmental Impact Statement (“PEIS”), with a period for public comment on the draft PEIS. The PP and a draft PEIS for the 2023-2028 five-year period were published in the Federal Register on July 8, 2022, with a 90-day comment period. The public comment period has now closed, and BOEM is reviewing the comments received. The PP includes no more than ten potential lease sales in the Gulf of Mexico; however, BOEM’s subsequent Proposed Final Program for 2023-2028 could reduce the number of Gulf of Mexico lease sales in the national program.

When the 2023-2028 national program will be approved and implemented remains uncertain. Congress may influence the Biden Administration’s development and implementation of the five-year 2023-2028 national program by submitting public comments during formal comment periods, by evaluating programs in committee oversight hearings, and, more directly, by enacting legislation with program requirements. It is possible that the program could be delayed if opponents of offshore oil and gas production initiate lawsuits challenging BOEM’s actions.

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

The information below provides a discussion of, and an analysis of significant variance in, our ~~commitments~~oil, natural gas and ~~contingencies, see “Item 1, Condensed Consolidated Financial Statements, Note 11 –~~ ~~Commitments~~NGL revenues, production volumes and ~~Contingencies.~~”sales prices (in thousands):

The information below provides an analysis of the change in our oil, natural gas and NGL revenues due to changes in sales prices and production volumes (in thousands):

Three Months Ended September 30, 2022 and 2021 Volumetric Analysis — Production volumes decreased by 3.5 MBoepd to 53.0 MBoepd. The decrease in production volumes was primarily due to the third party downtime associated with the HP-I dry-dock in our Phoenix Field and the Shell Odyssey Pipeline shut-in primarily impacting our Ram Powell Field, Main Pass 288 Field and non-operated Delta House facility, which resulted in 6.2 MBoepd and 1.8 MBoepd of deferred production, respectively. Additionally, production volumes decreased 4.3 MBoepd and 1.8 MBoepd primarily attributable to well performance and natural production declines in our Phoenix Field and Green Canyon 18 Field, respectively. The decrease was partially offset by an increase of 12.7 MBoepd in deferred production attributable to Hurricane Ida in 2021.

~~For~~Nine Months Ended September 30, 2022 and 2021 Volumetric Analysis — Production volumes decreased by 2.4 MBoepd to 60.5 MBoepd. The decrease in production volumes was primarily due to the third party downtime for the HP-I dry-dock in our Phoenix Field, the Eugene Island Pipeline System shut-in primarily impacting HP-I and Green Canyon 18 Field and the Shell Odyssey Pipeline shut-in primarily impacting our Ram Powell Field, Main Pass 288 Field and non-operated Delta House facility, which resulted in 4.2 MBoepd of deferred production. Additionally, production volumes decreased 1.7 MBoepd at Delta House, a non-operated facility located in Mississippi Canyon, primarily related to temporary shut-ins for repairs and maintenance and natural production declines. The decrease was partially offset by an increase of 4.3 MBoepd in deferred production attributable to Hurricane Ida in 2021.

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

Three Months Ended September 30, 2022 and 2021 —Lease operating expense for the three ~~and six~~ months ended ~~June~~September 30, ~~2018,~~2022 increased by approximately $11.7 million, or 17%.The increase is primarily due to a $4.9 million increase in facility and workover expense related to repairs and maintenance at the Phoenix Field and the Pompano Field. Additionally, there was a $1.7 million increase in company and contract labor compared to the same period in 2021 and $1.4 million reduction in production handling fees related to reimbursements for costs from certain third parties.

Nine Months Ended September 30, 2022 and 2021 — Lease operating expense for the nine months ended September 30, 2022 increased by approximately $20.5 million, or 10%. The increase is primarily due to a $19.8 million increase in facility and workover expense related to repairs and maintenance at the Phoenix Field and the Gunflint Field. Additionally, there was a $4.8 million increase in company and contract labor compared to the same period in 2021. This increase was partially offset by $7.0 million in additional production handling fees related to reimbursements for costs from certain third parties.

The following table highlights depreciation, depletion and amortization items in total and on a cost per Boe production basis. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):

Three Months Ended September 30, 2022 and 2021 —Depreciation, depletion and amortization expense for the three months ended September 30, 2022 increased by approximately $3.7 million, or 4%. This was primarily due to an increase of $1.85 per Boe, or 11%, in the depletion rate on our ~~effective tax~~proved oil and natural gas properties partially offset by decreased production of 3.5 MBoepd.

Nine Months Ended September 30, 2022 and 2021 — Depreciation, depletion and amortization expense for the nine months ended September 30, 2022 increased by approximately $5.1 million, or 2%. This was primarily due to an increase of $1.00 per Boe, or 6% in the depletion rate on our proved oil and natural gas properties partially offset by decreased production of 2.4 MBoepd.

The following table highlights general and administrative expense items in total and on a cost per Boe production basis. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):

Three Months Ended September 30, 2022 and 2021 — General and administrative expense for the three months ended September 30, 2022 increased by approximately $4.9 million, or 24%. This increase was 0%primarily related to non-cash equity-based compensation of $4.3 million, or $0.88 per Boe, during the three months ended September 30, 2022, which is an increase of $1.7 million. Additionally, there was an increase in transaction costs of $2.8 million primarily related to the EnVen Acquisition. On a per unit basis, general and administrative expense increased $1.26 Boe primarily due to decreased production of 3.5 MBoepd.

Nine Months Ended September 30, 2022 and 2021 — General and administrative expense for the nine months ended September 30, 2022 increased by approximately $11.7 million, or 20%. ~~Our effective tax rate~~This increase was primarily related to $5.6 million of expenses incurred by our emerging CCS operating segment during the nine months ended September 30, 2022, an increase of $4.1 million. There was an increase in ~~2018 differed from~~transaction costs of $2.0 million primarily related to the ~~statutory rate~~EnVen Acquisition. Additionally, general and administrative expense includes non-cash equity-based compensation of ~~21%,~~$11.7 million, or $0.71 per Boe, during the nine months ended September 30, 2022, an increase of $3.4 million. On a per unit basis, general and administrative expense increased $0.85 per Boe primarily due to decreased production of 2.4 MBoepd.

The following table highlights miscellaneous items in total. The information below provides the financial results and an analysis of significant variances in these results (in thousands):

Other Operating (Income) Expense — During the three months ended September 30, 2022, we recorded $0.1 million of estimated decommissioning obligations primarily as a result of ~~recognition~~working interest partners or counterparties of divesture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. During the three months ended September 30, 2021, we recorded $4.1 million of estimated decommissioning obligations. See further discussion in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 10 — Commitments and Contingencies.”

Interest Expense — During the three months ended September 30, 2022, we recorded $29.3 million of interest expense compared to $32.4 million during the three months ended September 30, 2021. The change is primarily the result of the decrease in interest associated with the Bank Credit Facility (as defined below under “ — Liquidity and Capital Resources — Overview of Debt Instruments”) with outstanding borrowings of $60.0 million as of September 30, 2022 when compared to $400.0 million as of September 30, 2021.

Price Risk Management Activities — The income of $114.2 million for the three months ended September 30, 2022 consists of $195.3 million in non-cash gains from the increase in the fair value of our open derivative contracts partially offset by $81.1 million in cash settlement losses. The expense of $81.5 million for the three months ended September 30, 2021 consists of $71.6 million in cash settlement losses and $9.8 million in non-cash losses from the decrease in the fair value of our open derivative contracts.

These unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a ~~full~~gain or loss on our Condensed Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through December 2024, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 4 — Financial Instruments.”

Equity Method Investment Income — During the three months ended September 30, 2022, we recorded equity losses of $0.4 million offset by a $1.4 million gain on partial sale of our equity method investment in Bayou Bend. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 9 — Related Party Transactions” for additional information.

Other (Income) Expense — During the three months ended September 30, 2021, we recorded a $4.4 million gain as a result of the settlement related to the Whistler Acquisition that is further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 9 — Related Party Transactions.”

Income Tax (Benefit) Expense — During the three months ended September 30, 2022, we recorded $0.1 million of income tax expense compared to $0.4 million of income tax benefit during the three months ended September 30, 2021. The income tax expense for each period is primarily a result of recording a valuation allowance on our deferred tax assets. ~~For~~The realization of our deferred tax asset depends on recognition of sufficient future taxable income in specific tax jurisdictions in which temporary differences or net operating losses relate. In assessing the ~~three~~need for a valuation allowance, we consider whether it is more likely than not that some portion of all of the deferred tax assets will not be realized. See additional information on the valuation allowance as described in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 7 — Income Taxes.”

Other Operating (Income) Expense — During the nine months ended ~~June~~September 30, ~~2018,~~2022, we recorded ~~a full valuation allowance against our net deferred tax assets.~~

~~“Adjusted EBITDA” is not a measure~~$10.6 million of ~~net income (loss) as determined by GAAP. We use this measure~~estimated decommissioning obligations primarily as a ~~supplemental measure because~~result of working interest partners or counterparties of divesture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. During the nine months ended September 30, 2021, we ~~believe it provides meaningful information to our investors. We define Adjusted EBITDA as net income (loss) plus~~recorded $6.9 million of estimated decommissioning obligations. See further discussion in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 10 — Commitments and Contingencies.”

Interest Expense — During the nine months ended September 30, 2022, we recorded $91.5 million of interest expense ~~depreciation, depletion and amortization, accretion~~compared to $100.0 million during the nine months ended September 30, 2021. The change is primarily a result of the interest associated with the Bank Credit Facility with outstanding borrowings of $60.0 million as of September 30, 2022 when compared to $400.0 million as of September 30, 2021.

Price Risk Management Activities — The expense ~~loss on debt extinguishment, transaction related costs,~~of $231.1 million for the ~~net change~~nine months ended September 30, 2022 consists of $368.5 million in cash settlement losses partially offset by $137.4 million in non-cash gains from the increase in the fair value of ~~derivatives (mark~~our open derivative contracts. The expense of $405.6 million for the nine months ended September 30, 2021 consists of $216.4 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $189.3 million in cash settlement losses.

These unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Condensed Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through December 2024, we expect these activities to continue to impact net income (loss) based on fluctuations in market ~~effect, net of cash settlements and premiums related to these derivatives), non-cash write-down of~~prices for oil and natural ~~gas properties, non-cash write-down~~gas. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 4 — Financial Instruments.”

Equity Method Investment Income — During the nine months ended September 30, 2022, we recorded equity losses of $0.7 million offset by a $15.3 million gain on partial sale of our equity method investment in Bayou Bend. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 9 — Related Party Transactions” for additional information.

Other (Income) Expense — During the nine months ended September 30, 2022, we recorded a $27.5 million gain as a result of the settlement agreement to resolve a previously pending litigation that was filed in October 2017 that is further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 10 — Commitments and ~~non-cash equity based compensation expense. We believe~~Contingencies.” During the ~~presentation~~nine months ended September 30, 2021, we recorded a $13.2 million loss on extinguishment of debt as a result of the redemption of the 11.00% Second-Priority Senior Secured Notes (the “11.00% Notes”). This was partially offset by a $4.4 million gain as a result of the settlement related to the Whistler Acquisition that is further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 9 — Related Party Transactions.”

Income Tax (Benefit) Expense — During the nine months ended September 30, 2022, we recorded $2.3 million of income tax expense compared to $0.7 million of income tax expense during the nine months ended September 30, 2021. The change is primarily a result of a discrete tax expense and recording a valuation allowance on our deferred tax assets. The realization of our deferred tax asset depends on recognition of sufficient future taxable income in specific tax jurisdictions in which temporary differences or net operating losses relate. In assessing the need for a valuation allowance, we consider whether it is more likely than not that some portion of all of the deferred tax assets will not be realized. See additional information on the valuation allowance as described in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 7 — Income Taxes.”

“EBITDA” and “Adjusted EBITDA” are non-GAAP financial measures used to provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDA and Adjusted EBITDA ~~has~~have limitations as an analytical ~~tool~~tools and should not be considered in isolation or as ~~a substitute~~substitutes for analysis of our results as reported under GAAP or as ~~an alternative~~alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in ~~thousands, except~~thousands):

Our primary sources of liquidity are cash generated by our operations and borrowings under our ~~newly established~~ Bank Credit Facility. Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. Our working capital deficit has decreased since December 31, 2021 primarily due to a decrease of $87.3 million in liabilities from price risk management activities and an increase of $26.4 million in assets from price risk management activities. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 4 — Financial Instruments.” As of ~~June~~September 30, ~~2018,~~2022, our available liquidity (cash plus available capacity under the Bank Credit Facility) was ~~$432.9~~$806.8 million.

AsWe fund exploration and development activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant property acquisitions with the issuance of ~~June 30, 2018, total debt, net of discount and deferred financing costs, was approximately $628.4 million, comprised of our $380.0 million aggregate principal amount of~~senior notes, borrowings under the ~~11.00% Senior Secured Notes and $6.1 million aggregate principal amount of our 7.50% Stone Senior Notes, $231.5 million outstanding under our~~ Bank Credit Facility and ~~$10.8~~through additional equity issuances. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities.

Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the nine months ended September 30, 2022 (in thousands):

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund the remainder of our board approved ~~2018~~2022 capital spending ~~project~~program of ~~$430.0~~$450.0 million to ~~$450.0 million.~~$480.0 million, of which approximately $30.0 million is allocated to CCS. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on operating and economic conditions, some of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g. by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/or commodity markets, future actions may include, without limitation, ~~raising~~issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding ~~debt.~~indebtedness.

AsOverview of ~~June 30, 2018, we had secured performance bonds primarily related to plugging and abandonment~~Cash Flow Activities —The following table summarizes cash flows provided by (used in) by type of ~~wells and removal of facilities~~activity, for the following periods (in thousands):

During the ~~BOEM’s estimate~~nine months ended September 30, 2021, the issuance of the ~~lessees’ decommissioning obligations.~~12.00% Notes in January 2021 generated $579.4 million after original discount and deferred financing costs. The ~~2016 NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07. The 2016 NTL allows qualifying operators to self-insure for an amount up to 10% of their tangible~~ net worth. In addition, the 2016 NTL implements a phase-in period for establishing compliance with additional security obligations for certain categories of properties covered under the NTL, whereby a lessee may seek compliance with its additional financial security requirements under a “tailored plan” that is approved by the BOEM and would require securing phased-in compliance in three approximately equal installments during a one-year periodproceeds from the ~~date of~~12.00% Notes funded the BOEM’s approval of the tailored plan. However, in June 2017, the BOEM announced that it will extend the implementation timeline for NTL #2016-N01 beyond June 30, 2017, except in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities, to allow the BOEM time to reconsider a number of regulatory initiatives. This extension currently remains in effect. We received notice from the BOEM on December 29, 2016 ordering us to secure financial assurances in the form of additional security in the amount of $0.5 million. Subsequent to the December 29, 2016 order, the BOEM has rescinded that order and all others dated December 29, 2016 until further notice. However, the BOEM reserved the right to re-issue sole liability orders in the future, including in the event that it determines there is a substantial risk of nonperformance of the interest holders’ decommissioning sole liabilities. We remain in active discussion with our government regulators and industry peers with regard to any future rule making and financial assurance requirements. Notwithstanding the BOEM’s July 2016 NTL, the BOEM may also increase its financial assurance requirements mandated by rule for all companies operating in federal waters. The future cost of compliance with our existing supplemental bonding requirements, the NTL #2016-N01, as well as any other future directives or any other changes to the BOEM’s rules applicable to us or our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows and results of operations.

~~In connection with the Stone Combination, we consummated the transactions contemplated by the Exchange Agreement, pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0~~$356.8 million in aggregate principal amount of 9.75% senior notes (9.75% Senior Notes) to us in exchange for Common Stock; (ii) the holders of 11.00% Bridge Loans exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Senior Secured Notes and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Stone Senior Notes for $137.4 million aggregate principal amount of 11.00% Senior Secured Notes. An additional $81.5 million of 7.50% Stone Senior Notes held by non-affiliates were also exchanged for 11.00% Senior Secured Notes pursuant to an exchange offer and consent solicitation in connection with the Stone Combination.

The exchange of 7.50% Stone Senior Notes for 11.00% Senior Secured Notes was accounted for as a debt modification. Under a debt modification, a new effective interest rate that equates the revised cash flows to the carrying amountredemption of the 11.00% ~~Senior Secured~~ Notes ~~is computed~~ and ~~applied prospectively. Costs incurred with third parties directly related to~~reduced the modification are expensed as incurred. We incurred approximately $3.9 million and $4.5 million of transaction fees related to the exchange of 11.00% Bridge Loans and 7.50% Stone Senior Notes into 11.00% Senior Secured Notes, which were expensed and reflected in general and administrative expense during the three months and six months ended June 30, 2018, respectively. We also paid $9.3 million in work fees to debt holders, which are reflected as debt discount reducing long-term debt on the condensed consolidated balance sheet at June 30, 2018.

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

~~7.50% Senior Secured Notes – due May 2022~~. The 7.50% Stone Senior Notes represent the remaining $6.1 million of long-term debt assumed in the Stone Combination that were not exchanged for 11.00% Senior Secured Notes pursuant to the exchange offer and consent solicitation, and thus remain outstanding. As a result of the exchange offer and consent solicitation, substantially all of the restrictive covenants relating to the 7.50% Stone Senior Notes have been removed and collateral securing the 7.50% Stone Senior Notes have been released. The 7.50% Stone Senior Notes mature May 31, 2022 and have interest payable semiannually each May 31 and November 30. Prior to May 31, 2020, we may, at our option, redeem all or a portion of the 7.50% Stone Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, we may redeem all or a portion of the 7.50% Stone Senior Notes at redemption prices decreasing annually from 105.625% to 100.0% plus accrued and unpaid interest.

~~We executed~~indebtedness under the Bank Credit Facility by $175.0 million in ~~conjunction with~~ the ~~Stone Combination~~first quarter of 2021. Indebtedness under the Bank Credit Facility was reduced further by $65.0 million.

Bank Credit Facility — matures November 2024 — We maintain a Bank Credit Facility with a syndicate of financial institutions ~~with an initial borrowing base of $600.0 million. The Bank~~(the “Bank Credit ~~Facility matures on May 10, 2022.~~

Facility”). The Bank Credit Facility provides for determination of the borrowing base based on our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth ~~quarter. In June 2018, we completed the redetermination and the~~quarter each year. On May 4, 2022, our borrowing base ~~was reaffirmed at $600.0~~increased from $950.0 million to $1.1 billion and commitments increased from $791.3 million to $806.3 million. The next scheduled redetermination is expected to occur in ~~October 2018.~~the fourth quarter of 2022. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — Debt”for more information.

12.00% Second-Priority Senior Secured Notes — due January 2026 — The amount that we are able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. We were in compliance with all debt covenants at June 30, 2018. As of June 30, 2018, the Bank Credit Facility had approximately $354.0 million of undrawn commitments (taking into account $6.0 million letters of credit and $240.0 million drawn from the Bank Credit Facility). The $294.0 million in cash received from our initial drawdown under the Bank Credit Facility was used to partially repay outstanding borrowings under the Old Bank Credit Facility upon its termination in connection with the Stone Combination.

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

~~9.75% Senior~~Secured Notes ~~– due February 2018. The 9.75% Senior Notes~~(the “12.00% Notes”) were issued pursuant to an indenture dated ~~February 6, 2013 among the Talos Issuers, the subsidiary guarantors party thereto~~January 4, 2021 and the ~~trustee. On February~~first supplemental indenture dated January 14, 2021 between Talos Energy Inc. (the “Parent Guarantor”); Talos Production Inc. (the “Issuer”); the Subsidiary Guarantors (defined below); and Wilmington Trust, National Association, as trustee and collateral agent. The 12.00% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indentures. The 12.00% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 12.00% Notes mature on January 15, ~~2018,~~2026 and have interest payable semi-annually each January 15 and July 15. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — Debt”for more information.

7.50% Senior Notes — redeemed May 2022 — The 7.50% Senior Notes matured and were redeemed on May 31, 2022. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — Debt”for more information.

Guarantor Financial Information —We own no operating assets and have no operations independent of our subsidiaries. The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the ~~Talos Issuers redeemed the remaining $25.0 million principal amount~~Parent Guarantor and on a second-priority senior secured basis by each of the ~~9.75% Senior Notes at par.~~Issuer’s present and future direct or indirect wholly owned material restricted domestic subsidiaries (collectively, the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”) that guarantees the Issuer’s senior reserve-based revolving credit facility. Our non-domestic subsidiaries and our unrestricted CCS domestic subsidiaries (the “Non-Guarantors”) are 100% owned by us but do not guarantee the 12.00% Notes.

~~Overview~~In lieu of ~~Cash Flow Activities~~providing separate financial statements for the Issuer and the Guarantors, we have presented the accompanying supplemental summarized combined balance sheet and statement of operations information for the Issuer and the Guarantors on a combined basis after elimination of intercompany transactions and amounts related to investment in any subsidiary that is a Non-Guarantor.

The following table ~~summarizes cash flows provided by (used in) by type of activity,~~presents the balance sheet information for the ~~following~~respective periods (in thousands):

The following table presents the statement of operations information (in thousands):

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

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

~~Financing Activities.~~ Net cash used in financing activities increased $200.6 million in the six months ended June 30, 2018 from 2017 primarily attributable to the repayment of $403.0 million related to the Old Bank Credit Facility, $54.0 million related to the repayment of the Bank Credit Facility, $25.0 million related to the redemptionnormal course of our ~~2018 Senior Notes and $17.5 million~~operations. There have been no material changes to our material cash requirements from known contractual obligations since those reported in ~~deferred financing cost, partially offset by proceeds received from the Bank Credit Facility~~our 2021 Annual Report except:

•

Purchase obligations increased from $3.2 million ~~which we plan~~ to ~~fund~~$57.8 million through ~~cash flows from operations and borrowings under our Bank Credit Facility.~~

~~Off-Balance Sheet Arrangements~~

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

2023 primarily due to increased committed purchase orders to execute planned Deepwater drilling activities.

~~Contractual~~Performance Obligations ~~and Other Contingencies~~

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

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

2018

2019

2020

2021

Thereafter

Total

Long-term financing obligations:

Debt principal

$
217

$
217

$
—

$
—

$
647,272

$
647,706

Debt interest

33,759

67,517

67,517

67,517

23,560

259,870

Vessel commitments ⁽¹⁾

22,030

11,765

—

—

—

33,795

Derivative liabilities

92,293

94,195

—

—

—

186,488

Committed purchase orders⁽²⁾

1,460

13,704

—

—

—

15,164

Capital lease ⁽³⁾

22,500

45,000

45,000

45,000

63,750

221,250

Minimum lease payments

2,242

3,944

3,791

3,811

30,492

44,280

Mexico minimum work program

—

34,942

—

—

—

34,942

Total contractual obligations⁽⁴⁾

$
174,501

$
271,284

$
116,308

$
116,328

$
765,074

$
1,443,495

~~(1)~~

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

~~(2)~~

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

~~(3)~~

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

~~(4)~~

This table does not include the Company’s estimated discounted liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $414.4 million as of June 30, 2018. For additional information regarding these liabilities, please see Note 4 – Property, Plant and Equipment.

~~Performance Bonds.~~ — As of ~~June~~September 30, ~~2018 and December 31, 2017,~~2022, we had secured performance bonds totaling $689.5 million primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of Mexico and ~~executing~~certain obligations under the ~~minimum work program in~~production sharing contracts with Mexico ~~totaling approximately $569.3 million and $287.8 million, respectively. As of June 30, 2018 and December 31, 2017,~~from third party sureties. Additionally, we had ~~$6.0 million and $4.9 million, respectively, in~~secured letters of credit issued under our Bank Credit Facility totaling $3.9 million. Letters of credit that are outstanding reduce the available revolving credit commitments.

See the subsection entitled “— Known Trends and Uncertainties — BOEM Bonding Requirements” for additional information on the ~~Old~~future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — Debt” for further information on the Bank Credit Facility.

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

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenue and expense, and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those estimates that require complex or subjective judgment in the application of the accounting policy and that could significantly impact our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. Our management has identified the following critical accounting estimates. Our significant accounting policies ~~that have been implemented or changed since December 31, 2017 are described in “Part I, Item 1, Condensed Consolidated Financial Statements, Note 2 –~~ ~~Summary of Significant Accounting Policies~~” of our condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q. Our other significant accounting policies that are not referenced in Note 2 can be found within Talos Energy LLC’s audited financial statements and the notes thereto for the year ended December 31, 2017, which we filed on May 18, 2018 with the SEC on a Current Report on Form 8-K.

~~Oil and Natural Gas Properties~~

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

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

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

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

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

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

~~Proved Reserve Estimates~~

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

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

~~Fair Value Measure of Financial Instruments~~

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

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

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

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

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

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

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

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

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

~~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, revenue recognition, imbalances and production handling fees and income taxes as critical accounting policies. The policies include significant estimates made by management using information available at ~~fair value~~the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. There have been no changes to our critical accounting policies, which are summarized in the ~~period such obligations are incurred with the associated asset retirement costs being capitalized as part~~Part II, Item 7. “Management’s Discussion and Analysis of ~~the carrying cost~~Financial Condition and Results of ~~the asset. Our asset retirement obligations consist of estimated costs for dismantlement, removal, site reclamation and similar activities associated with~~Operations” section in our oil and natural gas properties. The estimate of the asset retirement cost is determined, inflated to an estimated future value using a three year average of the Consumer Price Index and discounted to present value using our credit-adjusted risk-free rate. Accretion of the liability is recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values.2021 Annual Report.

~~Revenue Recognition and Imbalances~~

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

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

We record the gross amount of reimbursements for costs from third parties as other revenues whenever 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.

~~Income Taxes~~

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

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

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

Recently Adopted Accounting Standards

~~See “Part I, Item 1, Condensed Consolidated Financial Statements, Note 1~~ – ~~Formation and Basis of Presentation” for Recently Adopted Accounting Standards by the Company.~~ None.

Recently Issued Accounting Standards

~~See “Part I, Item 1, Condensed Consolidated Financial Statements, Note 1~~ – ~~Formation and Basis~~There was no recently issued accounting standards material to us.

Table of ~~Presentation” for Recently Issued Accounting Standards applicable to the Company.~~Contents

Item 3. Quantitative and Qualitative Disclosures About Market Risk

~~We are currently exposed~~For information regarding our exposures to certain market ~~risk~~risks, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in ~~two areas: commodity prices~~our 2021 Annual Report and ~~to a lesser extent, interest rate risk. Our risk management activities involve~~Part II, Item 3. “Quantitative and Qualitative Disclosures about Market Risk” in our Quarterly Report on Form 10-Q for the use of derivative financial instruments to mitigate the impact of market price risk exposures primarily related to our oil and natural gas production. All derivatives are recorded on the condensed consolidated balance sheet at fair value with settlements of such contracts and, changes in the unrealized fair value recorded as price risk management activities income (expense) on the condensed consolidated statements of operations in each period.

~~Commodity Price Risks~~

~~Oil and natural gas prices can fluctuate significantly and have a direct impact on our revenues, earnings and cash flow. During the six months~~quarter ended June 30, ~~2018,~~2022. Except as disclosed in this Quarterly Report, there have been no material changes from the disclosures presented in our ~~average oil price realizations after~~2021 Annual Report and our Quarterly Report on Form 10-Q for the effect of derivatives increased 6% to $54.12 per Bbl from $51.28 per Bbl in the comparable 2017 period. Our average natural gas prices realizations after the effect of derivatives increased 2% during the six monthsquarter ended June 30, ~~2018 to $2.94 per Mcf from $2.87 per Mcf in the comparable 2017 period.~~

~~Price Risk Management Activities~~

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

We had commodity derivative instruments in place to reduce the price risk associated with future production of 14,444 MBbls of crude oil and 9,177 MMBtu of natural gas at June 30, 2018, with a net derivative liability position of $185.8 million. For additional information2022 regarding our ~~commodity derivative instruments, see “Item 1,~~ ~~Condensed Consolidated~~ ~~Financial Statements, Note 5 –~~ ~~Financial Instruments.” The table below presents the hypothetical sensitivity of~~exposures to certain market risks except for our ~~commodity price risk management activities to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at June 30, 2018 (in thousands):~~

Oil and Natural Gas Derivatives

10 Percent Increase

10 Percent Decrease

Fair Value

Fair Value

Change

Fair Value

Change

Price impact⁽¹⁾

$
(185,755
)

$
(281,258
)

$
(95,503
)

$
(90,224
)

$
95,531

~~(1)~~

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

~~Variable Interest Rate Risks~~

We had total debt outstanding of $628.4 million at June 30, 2018, net of unamortized original issue discount and deferred financing costs. Of this, $396.9 million was from our 11.00% Senior Secured Notes, 7.50% Stone Senior Notes and Building Loan, which bear interest at fixed rates. The remaining $231.5 million is from borrowingsminimum hedging requirement under our Bank Credit Facility with variable interest rates. Therefore, we are subject to the risk of changes in interest rates under our Bank Credit Facility. In addition, the terms of our Bank Credit Facility require us to pay higher interest rates as we utilizefor each calendar month on a larger percentage of our available borrowing base. We manage our interest rate exposure by maintaining a combination of fixed and variable rate debt and monitoring the effect of market changes in interest rates. We believe our interest rate risk exposure is partially mitigated as a result of fixed interest rates on 63% of our debt. The interest rate on our variable rate debt at June 30, 2018 was 5.05%. A 10% change in the interest rate on this variable rate debt balance at June 30, 2018 would change interest expense for the six months ended June 30, 2018 by approximately $0.3 million.six-full fiscal quarter rolling basis.

Item 4. Controls and Procedures

~~Evaluation of~~ Disclosure Controls and Procedures

Under the supervision and with the participation of our management, our principal executive officer and principal financial officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this Quarterly ~~Report on Form 10-Q.~~Report. Our disclosure controls and procedures are designed to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of ~~June~~September 30, ~~2018.~~2022.

~~Changes in~~ Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended ~~June~~September 30, ~~2018~~2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

PART II – ~~OTH~~EROTHER INFORMATION

Item 1. Legal Proceedings

~~We are named as~~On March 23, 2022, the Company entered into a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.

On January 4, 2018 and February 2, 2018, two putative class action complaints challenging the Transactions were filed on behalf of purported Stone stockholders in the U.S. District Court for the District of Delaware. The complaints are captioned John Heinrich v. Stone Energy Corporation, et al., Case 1:18-cv-00054-GMS and Allen Miskowiec v. Stone Energy Corporation, et al., Case 1:18-cv-00202-RGA. On February 8, 2018, a third putative class action complaint challenging the Transactionssettlement agreement to receive $27.5 million to resolve previously pending litigation, which was filed on behalf of purported Stone stockholders in the U.S. District Court for the Western District of Louisiana and is captioned Anthony Franchi v. Stone Energy Corporation, et al., Case 6:18-cv-00167. The complaints assert, among other things, claims under Sections 14(a) and 20(a) of the Exchange ActOctober 23, 2017, against Stone and certain members of its board of directors and challenges the adequacy of the disclosures made in the version of this consent solicitation statement/prospectus filed with the SEC on December 29, 2017. The Miskowiec and Franchi lawsuits also name Talos Energy LLC as an additional defendant and the Franchi lawsuit names Talos Production LLC as additional defendant. The defendants believe that the claims asserted against them in the lawsuits are without merit and intenda third-party supplier related to defend vigorously against all claims asserted. The Heinrich lawsuit was dismissed on June 6, 2018. The Miskowiec lawsuit was dismissed on May 15, 2018. The Franchi lawsuit was dismissed on July 25, 2018.

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

~~On November 17, 2014,~~settlement agreement, the ~~Pennsylvania Department~~Company released all of Environmental Protection (“PADEP”) issued a Notice of Violation (“NOV”) to Stone alleging releases of production fluid and an improper closure of a drill cuttings pit at Stone’s Loomis No. 1 well site in Susquehanna County, Pennsylvania. Prior to this, in September 2014, Stone had transferred ownership of the Loomis No. 1 well site to Southwestern Energy Company (“Southwestern”). PADEP approved the transfer on November 24, 2014, after issuing the NOV to Stone. Stone investigated the allegations foundits claims in the ~~NOV and responded to PADEP on January 5, 2015. Reclamation of the site by Southwestern,~~litigation.

There have been no additional material developments with ~~the participation of the PADEP and Stone, was completed. The PADEP may impose a penalty in this matter, but the amount of such penalty cannot be reasonably estimated at this time.~~

On November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damagesrespect to the ~~Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration~~information previously reported under Part I, Item 3. “Legal Proceedings” of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the lawsuit. In connection with Stone’s filing of bankruptcy in December 2016, Plaquemines Parish dismissed its claims against Stone without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. The Plaquemines Parish lawsuit has been stayed pending the conclusion of trials in five other cases, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone. The Plaquemines Parish lawsuit has been removed to federal district court in the Eastern District of Louisiana.

On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, “the CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the three lawsuits. In connection with Stone’s filing of bankruptcy in December 2016, Jefferson Parish dismissed its claims against Stone in two of the three Jefferson Parish Coastal Zone Management lawsuits without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. The Jefferson Parish lawsuits have been removed to federal district court in the Eastern District of Louisiana.our 2021 Annual Report.

Legal proceedings are subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the resolution of some of these matters and may be unable to estimate a range of possible losses or any minimum loss from such matters. See “Item 1, Condensed Consolidated Financial Statements, Note 11 – ~~Commitments and Contingencies.”~~

Item 1A. Risk Factors

~~Certain~~In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors ~~may have a material adverse effect on~~and other cautionary statements described under Part I, Item 1A. “Risk Factors” included in our 2021 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our business, financial condition and results of operations. You should consider carefully the risks and uncertainties described below, in addition to other information contained in this Quarterly Report on Form 10-Q, including our condensed consolidated financial statements and related notes. The risks and uncertainties described below are not the only ones we face.or future results. Additional risks and uncertainties ~~that we are unaware of,~~not currently known to us or that we currently believe are not material, may also become important factors that adversely affect our business. If any of the following risks actually occurs, our business, financial condition, results of operations, and future prospects coulddeem to be ~~materially and adversely affected. In that event, the trading price of our common stock could decline, and you could lose part or all of your investment.~~

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

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

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

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

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

Immediately following the closing of the Stone Combination, the stakeholders of Talos Energy LLC beneficially owned and possessed voting power over 63% of our common stock. Under the Stockholders’ Agreement, the Apollo Funds and the Riverstone Funds may acquire additional shares of our common stock without the approval of the Company Independent Directors.

Through their ownership of a majority of our voting power and the provisions set forth in our charter, bylaws and the Stockholders’ Agreement, the Apollo Funds and the Riverstone Funds have the ability to designate and elect a majority of our directors. As a result of the Apollo Funds’ and the Riverstone Funds’ ownership of a majority of the voting power of our common stock, we are a “controlled company” as defined in NYSE listing rules and, therefore, we are not be subject to NYSE requirements that would otherwise require us to have (i) a majority of independent directors, (ii) a nominating committee composed solely of independent directors, (iii) director nominees selected, or recommended for the board’s selection, either by a majority of the independent directors or a nominating committee composed solely of independent directors, and (iv) the compensation of our executive officers determined by a majority of the independent directors or a compensation committee composed solely of independent directors. Under the Stockholders’ Agreement, our board of directors has four directors not designated by the Apollo Funds and the Riverstone Funds and six directors designated by the Apollo Funds and the Riverstone Funds.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

~~market uncertainty;~~

~~level of consumer product demands;~~

~~hurricanes and other adverse weather conditions;~~

~~domestic and foreign governmental regulations and taxes;~~

~~price and availability of alternative fuels;~~

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

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

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

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

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

~~the level of global oil and natural gas inventories;~~

~~localized supply and demand fundamentals and transportation availability;~~

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

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

~~technological advances affecting energy consumption; and~~

~~overall domestic and foreign economic conditions.~~

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

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

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

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

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

~~incurring additional debt;~~

~~paying dividends on stock, redeeming stock, or redeeming subordinated debt;~~

~~making investments;~~

~~creating liens on our assets;~~

~~selling assets;~~

~~guaranteeing other indebtedness;~~

~~entering into agreements that restrict dividends from our subsidiaries to us;~~

~~merging, consolidating, or transferring all or substantially all of our assets;~~

~~hedging future production; and~~

~~entering into transactions with affiliates.~~

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

requiring that we dedicate a substantial portion of our cash flow from operating activities to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures, and other general business activities;

•

~~limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, and other general business activities;~~

~~limiting our flexibility in planning for, or reacting to,~~no material changes in our ~~business and the industry in which we operate;~~

~~detracting~~risk factors from ~~our ability to successfully withstand a downturn~~those described in our ~~business~~2021 Annual Report or ~~the economy generally;~~

~~placing us at a competitive disadvantage against~~our other ~~less leveraged competitors; and~~

~~making us vulnerable to increases in interest rates because debt under our Bank Credit Facility is at variable rates.~~

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

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

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

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

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

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

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

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

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

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

~~As of the filing date of this~~ Quarterly Report on Form 10-Q we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders for financial assurance obligations. Following completion of its review, the BOEM may elect to retain the 2016 NTL in its current form or may make revisions thereto and, thus, until the review is completed and BOEM determines what additional financial assurance may be required by us, we cannot provide any assurance that such financial assurance coverage can be obtained. Moreover, the BOEM could in the future make other demands for additional financial assurances covering our obligations under sole liability properties and/or our non-sole liability properties. The BOEM may reject our proposals and make demands that exceed our capabilities.

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

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

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

In February 2014, we received a grand jury subpoena from the DOJ addressing activities that occurred on the Ship Shoal 225A production platform operated by one of our subsidiaries, Energy Resource Technology GOM, LLC (“ERT”). On November 30, 2015, ERT was charged with two violations of the Outer Continental Shelf Lands Act in connection with hot work and blowout preventer testing activities, and with two violations of the Clean Water Act for self-reported activities surrounding overboard discharge sampling and unpermitted discharges. On January 6, 2016, ERT pled guilty to these charges. On April 6, 2016, the United States District Court for the ~~Eastern District of Louisiana (the “Court”) accepted ERT’s plea~~quarter ended March 31, 2022 and ~~sentenced ERT, consistent with the plea agreement, to pay a penalty of $4.2 million, which ERT has paid. The Court placed ERT~~our Quarterly Report on probation for three years. The conditions of probation include compliance with an agreed SECP, pursuant to which ERT and another subsidiary of ours must implement enhanced safety and environmental compliance inspections, reviews and audits, implement a comprehensive training program, implement enhanced operational controls to better manage, detect and prevent safety and environmental violations, and preparation and implementation of schedule for decommissioning. we believe that we are in substantial compliance with the SECP, a failure to comply with the SECP could result in a violation of the plea agreement and provide a basis for revocation or modification of probation, which could adversely our financial condition and operations.

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

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

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

~~We spend a substantial amount of capital~~Form 10-Q for the acquisition, exploration, exploitation, development, and production of oil and natural gas reserves. We fund our capital expenditures primarily through operating cash flows, cash on hand and borrowings under our Bank Credit Facility, if necessary. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil and natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A further reduction in commodity prices may result in a further decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

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

~~our proved reserves;~~

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

~~the prices at which our production is sold;~~

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

~~our ability to borrow under our Bank Credit Facility.~~

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

Our production, revenue, and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.

Our production, revenue, and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, the Gulf of Mexico. Unlike other entities that are geographically diversified, we may not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. Our lack of diversification may subject us to numerous economic, competitive, and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate, and result in our dependency upon a single or limited number of hydrocarbon basins. In addition, the geographic concentration of our properties in the Gulf of Mexico and the Gulf Coast means that some or all of the properties could be affected should the region experience:

~~severe weather, such as hurricanes and other adverse weather conditions;~~

~~delays or decreases in production, the availability of equipment, facilities, or services;~~

~~delays or decreases in the availability or capacity to transport, gather, or process production;~~

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

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

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

Because all or a number of our properties could experience many of the same conditions at the same time, these conditions may have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.

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

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

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

~~For the six months~~quarter ended June 30, 2018, approximately 51% of our production and 63% of our oil, natural gas, and NGL revenue was attributable to our Phoenix Field, which is located offshore Louisiana. This concentration in the Phoenix Field means that any impact on our production from the Phoenix Field, whether because of mechanical problems, adverse weather, well containment activities, changes in the regulatory environment, or otherwise, could have a material effect on our business. We produce the Phoenix Field through the Helix Producer I (“HP-1”) a dynamically positioned floating production facility that is operated by Helix Energy Solutions Group, Inc. (“Helix”). The HP-I interconnects the Phoenix Field through a production buoy that can be disconnected if the HP-I cannot maintain its position on station, such as in the event of a mechanical problem with the dynamic positioning system or the approach of a hurricane. Because the HP-I may have to be disconnected from the Phoenix Field if circumstances require, our production from the Phoenix Field may be subject to more frequent interruptions than if the Phoenix Field was produced by a more conventional platform. We are also required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the United States Coast Guard, during which time we are unable to produce the Phoenix Field. On September 10, 2016, the HP-I was disconnected from the production buoy and released for dry dock for 28 days. Upon completion of the dry dock, the HP-I remained disconnected from the buoy connecting it to the Phoenix Field due to Federal Emergency Management Agency testing of test upgrades to the power management system, preventing us from reconnecting the HP-I to the Phoenix Field for a further five days. Once the buoy was connected, Phoenix Field production remained shut-in for an additional five days to conduct buoy remediation of the swivel piping. In addition, for 25 days in March 2015, we were required to disconnect the HP-I from the production buoy due to upgrades to the power management system of the vessel, which is an integral part of the dynamic positioning system. The upgrade work was followed by sea trials that tested the dynamic positioning system and were required by various regulatory groups, including the United States Coast Guard.2022.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Production periods or reserve lives for Gulf of Mexico properties may subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.

The vast majority of our operations are in the Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices.

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

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

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

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

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

~~the amount and timing of capital expenditures and decommissioning costs;~~

~~the rate and timing of production;~~

~~changes in governmental regulations or taxation;~~

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

~~supply of and demand for oil and natural gas;~~

~~actual prices we receive for oil and natural gas; and~~

~~our actual operating costs in producing oil and natural gas.~~

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

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

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

We rely on 3D seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or, if present, produce in economic quantities, and seismic indications of hydrocarbon saturation are generally not reliable indicators of productive reservoir rock. These limitations of 3D seismic data may impact our drilling and operational results, and consequently our financial condition.

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

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

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

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

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

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

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

~~Our actual production could differ materially from our forecasts.~~

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

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

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

~~unexpected drilling conditions;~~

~~pressure or irregularities in formations;~~

~~equipment failures or accidents;~~

~~hurricanes and other adverse weather conditions;~~

~~shortages in experienced labor; and~~

~~shortages or delays in the delivery of equipment.~~

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

~~Our industry experiences numerous operating risks.~~

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

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

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

We have an interest in six deepwater fields: the Phoenix Field, the Bushwood Field, the Gunnison Field, the Pompano Field, the Amberjack Field and the Ram Powell Field, and may attempt to pursue additional operational activity in the future and acquire additional fields and leases in the deepwaters of the Gulf of Mexico. Exploration for oil or natural gas in the deepwater of the Gulf of Mexico generally involves greater operational and financial risks than exploration on the Gulf of Mexico Conventional Shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. For example, the drilling of deepwater wells requires specific types of drilling rigs with significantly higher day rates and limited availability as compared to the rigs used in shallower water. Deepwater wells often use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in cost overruns. Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present on the Gulf of Mexico Conventional Shelf. As a result, a considerable amount of time may elapse between a deepwater discovery and the marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the deepwater may never be produced economically.

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

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

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

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

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

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

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

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

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

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

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

Our growth strategy will, in part, rely on acquisitions. We have to plan and manage acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. We expect to grow in the future by expanding the exploitation and development of our existing assets, in addition to growing through targeted acquisitions in the Gulf of Mexico or in other basins. We may not realize all of the anticipated benefits from our future acquisitions, such as increased earnings, cost savings, and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher than expected acquisition and operating costs or other difficulties, inexperience with operating in new geographic regions, unknown liabilities, inaccurate reserve estimates, and fluctuations in market prices.

In addition, integrating acquired businesses and properties involves a number of special risks and unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. These difficulties include, among other things:

~~operating a larger organization;~~

~~coordinating geographically disparate organizations, systems and facilities;~~

~~integrating corporate, technological and administrative functions;~~

~~diverting management’s attention from regular business concerns;~~

~~diverting financial resources away from existing operations;~~

~~increasing our indebtedness; and~~

~~incurring potential environmental or regulatory liabilities and title problems.~~

Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results. The process of integrating our operations could cause an interruption of or loss of momentum in the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which decreases the time they have to manage our business. If our management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, our business could suffer.

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

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

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

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

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

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

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

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

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

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

~~disrupt our operations;~~

~~restrict the movement of funds or limit repatriation of profits;~~

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

~~limit access to markets for periods of time.~~

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

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

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

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

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

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

~~the timing and amount of capital expenditures;~~

~~the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;~~

~~the operator’s expertise and financial resources;~~

~~approval of other participants in drilling wells;~~

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

~~selection of technology;~~

~~the rate of production of the reserves; and~~

~~the timing and cost of P&A operations.~~

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

~~refuse to initiate exploration or development projects;~~

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

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

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

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

~~Competition within our industry may adversely affect our operations.~~

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Substantial limitations on greenhouse gas emissions could also adversely affect demand for the oil and natural gas we produce and lowers the value of our reserves. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Additionally, with concerns over GHG emissions, certain non-governmental activists have recently directed their efforts at advocating the shifting of funding away from companies with energy-related assets, which could result in limitations or restrictions on certain sources of funding for the energy sector.

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

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

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

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

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

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

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

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

~~Hedging transactions may limit our potential gains.~~

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

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

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

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

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

•

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

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

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

We have not made any unregistered sales of securities during the period covered by this Quarterly Report on Form 10-Q that have not been previously reported in a Current Report on Form 8-K. We have not made any purchases of our own securities during the time period covered by this Quarterly Report on Form 10-QNone.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

~~None.~~Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits


Exhibit Number	Description

~~2.1~~ 2.1#		~~Transaction~~Merger Agreement, dated as of ~~November~~September 21, ~~2017,~~2022, by and among ~~Stone~~Talos Energy Inc., Talos Production Inc., Tide Merger Sub I Inc., Tide Merger Sub II LLC, Tide Merger Sub III LLC, BCC Enven Investments, L.P. and EnVen Energy Corporation ~~Sailfish Energy Holdings Corporation, Sailfish Merger Sub Corporation,~~(incorporated by reference to Exhibit 2.1 to Talos Energy ~~LLC and Talos Production LLC (Included in the Company’s Current Report on~~Inc.’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~September 22, 2022).

3.1		Amended and Restated Certificate of Incorporation of Talos Energy Inc. ~~(Included in the Company’s Current Report on~~(incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, ~~2018, and incorporated herein by reference)~~2018).

3.2		Amended &and Restated Bylaws of Talos Energy Inc. ~~(Included in the Company’s Current Report on~~(incorporated by reference to Exhibit 3.2 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, ~~2018, and incorporated herein~~2018).

3.3	Certificate of Designation, dated as of February 27, 2020 (incorporated by ~~reference)~~reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 2, 2020).

4.1		Amended and Restated Stockholders’ Agreement, dated as of ~~May 10, 2018,~~March 29, 2022, by and among Talos Energy Inc. and each of the other parties set forth on the signature pages thereto ~~(Included in the Company’s Current Report on~~(incorporated by reference to Exhibit 4.1 to Talos Energy Inc.'s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~March 30, 2022).

4.2		Registration Rights Agreement, dated as of May 10, 2018, by and among Talos Energy Inc. and each of the other parties set forth on the signature pages thereto (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).

~~4.3~~		Warrant Agreement, dated as of February 28, 2017, by and among Stone Energy Corporation, Computershare Inc. and Computershare Trust Company, N.A. (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).

~~4.4~~		Amendment No. 1 to Warrant Agreement, dated as of May 10, 2018, by and among Talos Energy Inc., Stone Energy Corporation, Computershare Inc. and Computershare Trust Company, N.A. (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).

~~4.5~~		Indenture, dated as of ~~May 10, 2018,~~January 4, 2021, by and among Talos Production ~~LLC, Talos Production Finance,~~ Inc., the ~~subsidiary guarantors party thereto~~Guarantors named therein and Wilmington Trust, National Association, as trustee and as collateral agent ~~(Included in the Company’s Current Report on~~(incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~January 8, 2021).

~~4.6~~ 4.3		First Supplemental Indenture, dated as of January 14, 2021, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 14, 2021).

4.4	Form of 12.00% Second-Priority Senior Secured Note due 2026 (included as Exhibit A to Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).

4.5	Registration Rights Agreement, dated as of ~~May 10, 2018,~~January 4, 2021, by and among Talos Production ~~LLC, Talos Production Finance,~~ Inc., the ~~subsidiary guarantors~~Guarantors named therein and ~~each~~J.P. Morgan Securities LLC, as representative of the ~~holders set forth on~~initial purchasers of the ~~signature pages thereto (Included in the Company’s Current Report on~~2026 Notes (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~January 8, 2021).

~~10.1~~ 4.6		~~Exchange~~Registration Rights Agreement, dated as of ~~November 21, 2017,~~January 14, 2021, by and among Talos Production ~~LLC, Talos Production Finance~~ Inc., ~~Stone~~the Guarantors named therein and J.P. Morgan Securities LLC, as representative of the initial purchasers of the 2026 Notes (incorporated by reference to Exhibit 4.4 to Talos Energy ~~Corporation, Sailfish Energy Holdings Corporation and the lenders and noteholders listed on the schedules thereto (Included in the Company’s Current Report on~~Inc.’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~January 14, 2021).

~~10.2~~ 4.7		~~Credit~~Registration Rights Agreement, dated ~~as of May 10, 2018,~~September 21, 2022, by and among Talos ~~Production LLC, as borrower,~~Energy Inc. and the Persons listed on Schedule A thereto (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.~~, as holdings, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders named therein (Included in the Company’s Current Report on~~’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~July 18, 2018, and incorporated herein by reference)~~September 22, 2022).

4.8

~~10.3~~			~~Intercreditor Agreement,~~Second Supplemental Indenture, dated as of ~~May 10, 2018, between JPMorgan Chase Bank, N.A.~~October 27, 2022, among Talos Production Inc., ~~as First Lien Agent,~~the Guarantors named therein and Wilmington Trust National Association, as ~~Second Lien Agent (Included in the Company’s Current Report on~~trustee and as collateral agent (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~October 28, 2022).

~~10.4~~ 10.1			Form of Support Agreement, by and among Talos Energy Inc. ~~Long Term Incentive Plan (Included in~~, EnVen Energy Corporation and the ~~Company’s Current Report on~~EnVen Supporting Stockholders (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~September 22, 2022).

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~~10.5~~ 10.2			~~Indemnification~~Form of Support Agreement, ~~(Timothy S. Duncan) (Included in~~by and among Talos Energy Inc., EnVen Energy Corporation and the ~~Company’s Current Report on~~Talos Supporting Stockholders (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~September 22, 2022).

~~10.6~~ 22.1			~~Indemnification Agreement (Stephen E. Heitzman) (Included in the Company’s Current Report on~~List of Subsidiary Guarantors and Issuers of Guaranteed Securities (incorporated by reference to Exhibit 22.1 to Talos Energy Inc.'s Form ~~8-K12B~~10-Q (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~August 4, 2021).

~~10.7~~ 31.1*			~~Indemnification Agreement (John A. Parker) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.8~~			~~Indemnification Agreement (Michael L. Harding II) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.9~~			~~Indemnification Agreement (William S. Moss III) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.10~~			~~Indemnification Agreement (Gregory A. Beard) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.11~~			~~Indemnification Agreement (Christine Hommes) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.12~~			~~Indemnification Agreement (Robert M. Tichio) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.13~~			~~Indemnification Agreement (Olivia C. Wassenaar) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.14~~			~~Indemnification Agreement (Neal P. Goldman) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.15~~			~~Indemnification Agreement (John “Brad” Juneau) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.16~~			~~Indemnification Agreement (James M. Trimble) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.17~~			~~Indemnification Agreement (Charles M. Sledge) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.18~~			~~Indemnification Agreement (Donald R. Kendall, Jr.) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.19~~			~~Indemnification Agreement (Rajen Mahagaokar) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

10.20*			~~Form of Restricted Stock Unit Grant Notice and Restricted Stock Agreement (Directors).~~

31.1*			Certification of Chief Executive Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*

31.2*			Certification of Chief Financial Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**			Certification of Chief Executive Officer and Chief Financial Officer of Talos Energy Inc. pursuant to 18 U.S.C. § 1350, as adopted pursuant to the Sarbanes-Oxley Act of 2002.

101.INS101.INS			Inline XBRL ~~Instance Document~~Instance.

101.SCH101.SCH			Inline XBRL Taxonomy Extension ~~Schema Document~~Schema.

101.CAL101.CAL			Inline XBRL Taxonomy Extension ~~Calculation Linkbase Document~~Calculation.

101.DEF101.DEF			Inline XBRL Taxonomy Extension ~~Definition Linkbase Document~~Definition.

101.LAB101.LAB			Inline XBRL Taxonomy Extension ~~Label Linkbase Document~~Label.

101.PRE101.PRE			Inline XBRL Taxonomy Extension ~~Presentation Linkbase Document~~

Presentation.

104		~~Filed or furnished herewith.~~Cover Page Interactive Date File (Embedded within the Inline XBRL document and included in Exhibit 101).


*		Filed herewith.
**		Furnished herewith
#		The exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the SEC upon request.

Table of Contents ~~SIGNATURES~~

SIGNATURES

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


		Talos Energy Inc.

Date:	November 2, 2022	~~TALOS ENERGY INC.~~By:	/s/ Shannon E. Young III
			Shannon E. Young III
~~Date:~~	~~August 9, 2018~~	~~By:~~	~~/s/ MICHAEL L. HARDING II~~
			~~Michael L. Harding II~~
			Executive Vice President and Chief Financial Officer
			~~(Principal Financial Officer and Authorized Signatory)~~

7643


Delaware	82-3532642
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
333 Clay Street, Suite 3300 Houston, TX	77002
(Address of principal executive offices)	(Zip Code)


Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock	TALO	New York Stock Exchange


Large accelerated filer	☒	☐	Accelerated filer		☒☐
Non-accelerated filer	☐		Smaller reporting company	☐
~~Non-accelerated filer~~		~~☐ (Do not check if a smaller reporting company)~~	~~Smaller reporting company~~		☐

Emerging growth company	☐	☐


	September 30, 2022			December 31, 2021
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	64,490		$	69,852
Accounts receivable:
Trade, net		150,099			173,241
Joint interest, net		42,259			28,165
Other, net		9,450			18,062
Assets from price risk management activities		27,389			967
Prepaid assets		76,397			48,042
Other current assets		1,894			1,674
Total current assets		371,978			340,003
Property and equipment:
Proved properties		5,522,951			5,232,479
Unproved properties, not subject to amortization		213,802			219,055
Other property and equipment		30,601			29,091
Total property and equipment		5,767,354			5,480,625
Accumulated depreciation, depletion and amortization		(3,387,124	)		(3,092,043	)
Total property and equipment, net		2,380,230			2,388,582
Other long-term assets:
Assets from price risk management activities		19,540			2,770
Equity method investments		2,121			—
Other well equipment inventory		27,043			17,449
Operating lease assets		5,518			5,714
Other assets		6,936			12,297
Total assets	$	2,813,366		$	2,766,815
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	109,964		$	85,815
Accrued liabilities		189,743			130,459
Accrued royalties		45,476			59,037
Current portion of long-term debt		—			6,060
Current portion of asset retirement obligations		65,613			60,311
Liabilities from price risk management activities		99,180			186,526
Accrued interest payable		17,537			37,542
Current portion of operating lease liabilities		1,885			1,715
Other current liabilities		26,930			33,061
Total current liabilities		556,328			600,526
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs		652,108			956,667
Asset retirement obligations		387,651			373,695
Liabilities from price risk management activities		7,126			13,938
Operating lease liabilities		14,895			16,330
Other long-term liabilities		39,915			45,006
Total liabilities		1,658,023			2,006,162
Commitments and contingencies (Note 10)
Stockholdersʼ equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of September 30, 2022 and December 31, 2021		—			—
Common stock $0.01 par value; 270,000,000 shares authorized; 82,570,328 and 81,881,477 shares issued and outstanding as of September 30, 2022 and December 31, 2021, respectively		826			819
Additional paid-in capital		1,692,316			1,676,798
Accumulated deficit		(537,799	)		(916,964	)
Total stockholdersʼ equity		1,155,343			760,653
Total liabilities and stockholdersʼ equity	$	2,813,366		$	2,766,815

	June 30, 2018			December 31, 2017
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	78,860		$	32,191
Restricted cash		1,244			1,242
Accounts receivable
Trade, net		100,824			62,871
Joint interest, net		8,394			13,613
Other		7,091			12,486
Assets from price risk management activities		499			1,563
Prepaid assets		51,698			17,931
Inventory		—			840
Income tax receivable		16,212			—
Other current assets		3,910			2,148
Total current assets		268,732			144,885
Property and equipment:
Proved properties		3,412,875			2,440,811
Unproved properties, not subject to amortization		103,836			72,002
Other property and equipment		28,884			8,857
Total property and equipment		3,545,595			2,521,670
Accumulated depreciation, depletion and amortization		(1,547,656	)		(1,430,890	)
Total property and equipment, net		1,997,939			1,090,780
Other long-term assets:
Assets from price risk management activities		234			345
Other well equipment		9,021			2,577
Other assets		8,143			706
Total assets	$	2,284,069		$	1,239,293
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	38,731		$	72,681
Accrued liabilities		155,902			87,973
Accrued royalties		28,508			24,208
Current portion of long-term debt		434			24,977
Current portion of asset retirement obligations		94,334			39,741
Liabilities from price risk management activities		154,722			49,957
Accrued interest payable		7,454			8,742
Other current liabilities		15,541			15,188
Total current liabilities		495,626			323,467
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs		627,968			672,581
Asset retirement obligations		320,044			174,992
Liabilities from price risk management activities		31,766			18,781
Other long-term liabilities		122,820			103,559
Total liabilities		1,598,224			1,293,380
Commitments and contingencies (Note 11)
Equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized; no shares issued or outstanding as of June 30, 2018 and December 31, 2017		—			—
Common stock $0.01 par value; 270,000,000 shares authorized; 54,155,768 and 31,244,085 shares issued and outstanding as of June 30, 2018 and December 31, 2017, respectively		542			312
Additional paid-in capital		1,323,604			489,870
Accumulated deficit		(638,301	)		(544,269	)
Total stockholders' equity (deficit)		685,845			(54,087	)
Total liabilities and equity	$	2,284,069		$	1,239,293


☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


		Page

GLOSSARY			1
			3
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			35
	PART I — FINANCIAL INFORMATION
~~PART I – FINANCIAL INFORMATION~~

Item 1.	Condensed Consolidated Financial Statements		57
	Condensed Consolidated Balance Sheets		7
~~Item 2.~~	Condensed Consolidated Statements of Operations	8
	Condensed Consolidated Statements of Changes in Stockholders’ Equity	9
	Condensed Consolidated Statements of Cash Flows	10
	Notes to Condensed Consolidated Financial Statements	11
	Note 1 — Organization, Nature of Business and Basis of Presentation	11
	Note 2 — Property, Plant and Equipment	12
	Note 3 — Leases	12
	Note 4 — Financial Instruments	13
	Note 5 — Debt	16
	Note 6 — Employee Benefits Plans and Share-Based Compensation	17
	Note 7 — Income Taxes	18
	Note 8 — Income (Loss) Per Share	19
	Note 9 — Related Party Transactions	19
	Note 10 — Commitments and Contingencies	21
	Note 11 — Subsequent Event	23
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		4339
Item 4.	Controls and Procedures		39
~~Item 4.~~	~~Controls and Procedures~~PART II — OTHER INFORMATION		44
Item 1.	Legal Proceedings		40
~~PART II – OTHER INFORMATION~~Item 1A.	Risk Factors	40

Item 1.2.	~~Legal Proceedings~~		45

~~Item 1A.~~	~~Risk Factors~~		46

~~Item 2.~~	Unregistered Sales of Equity Securities and Use of Proceeds		7240
Item 3.	Defaults Upon Senior Securities		40
Item 3.4.	~~Defaults upon Senior Securities~~Mine Safety Disclosures		7240
Item 5.	Other Information		40
Item 4.6.	~~Mine Safety Disclosures~~Exhibits		7241

~~Item 5.~~	~~Other Information~~Signatures		72

~~Item 6.~~	~~Exhibits~~		73

	~~Signatures~~		7643

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Revenues:
Oil revenue	$	180,161		$	78,719		$	307,854		$	162,487
Natural gas revenue		16,448			12,888			29,171			26,062
NGL revenue		7,297			3,436			12,731			7,069
Other		—			383			—			1,632
Total revenue		203,906			95,426			349,756			197,250
Operating expenses:
Direct lease operating expense		34,060			28,871			58,975			56,735
Insurance		4,259			2,688			6,934			5,409
Production taxes		564			380			955			645
Total lease operating expense		38,883			31,939			66,864			62,789
Workover and maintenance expense		17,714			8,225			24,619			17,047
Depreciation, depletion and amortization		67,726			36,157			116,766			76,088
Accretion expense		9,492			5,321			14,252			10,509
General and administrative expense		30,880			7,470			39,460			17,216
Total operating expenses		164,695			89,112			261,961			183,649
Operating income		39,211			6,314			87,795			13,601
Interest expense		(21,678	)		(20,805	)		(41,420	)		(39,577	)
Price risk management activities income (expense)		(91,176	)		38,995			(143,152	)		84,888
Other income (expense)		(1,269	)		103			(1,078	)		157
Total other income (expense)		(114,123	)		18,293			(185,650	)		45,468
Income (loss) before income taxes		(74,912	)		24,607			(97,855	)		59,069
Income tax expense (benefit)		—			—			—			—
Net income (loss)	$	(74,912	)	$	24,607		$	(97,855	)	$	59,069

Net income (loss) per common share:
Basic	$	(1.69	)	$	0.79		$	(2.59	)	$	1.89
Diluted	$	(1.69	)	$	0.79		$	(2.59	)	$	1.89
Weighted average common shares outstanding:
Basic		44,336			31,244			37,826			31,244
Diluted		44,336			31,244			37,826			31,244


											Total
	Common Stock Shares		Common Stock Par Value		Additional Paid-In Capital			Accumulated Deficit			Stockholdersʼ Equity
Balance at June 30, 2021		81,872,498	$	819	$	1,666,887		$	(981,285	)	$	686,421
Equity-based compensation		��		—		4,936			—			4,936
Equity-based compensation tax withholdings		—		—		(42	)		—			(42	)
Equity-based compensation stock issuances		8,979		—		—			—			—
Net loss		—		—		—			(16,691	)		(16,691	)
Balance at September 30, 2021		81,881,477	$	819	$	1,671,781		$	(997,976	)	$	674,624

Balance at June 30, 2022		82,541,345	$	825	$	1,684,949		$	(788,264	)		897,510
Equity-based compensation		—		—		7,495			—			7,495
Equity-based compensation tax withholdings		—		—		(127	)		—			(127	)
Equity-based compensation stock issuances		28,983		1		(1	)		—			—
Net income		—		—		—			250,465			250,465
Balance at September 30, 2022		82,570,328	$	826	$	1,692,316		$	(537,799	)	$	1,155,343

	Common Stock		Additional Paid-In Capital		Retained Earnings (Accumulated Deficit)			Total Stockholders' Equity (Deficit)
Balance at January 1, 2018	$	312	$	489,870	$	(544,269	)	$	(54,087	)
Cumulative effect adjustment (Note 1)		—		—		(325	)		(325	)
Sponsor Debt Exchange		29		101,971		—			102,000
Stone Combination		201		731,763		—			731,964
Equity based compensation		—		—		4,148			4,148
Net loss		—		—		(97,855	)		(97,855	)
Balance at June 30, 2018	$	542	$	1,323,604	$	(638,301	)	$	685,845


	September 30, 2022
Current assets	$	17,500
Non-current assets		2,587
Total assets	$	20,087


	Three Months Ended September 30, 2022			Nine Months Ended September 30, 2022
Revenues	$	—		$	—
Operating expenses		(325	)		(8,130	)
Equity method investment income(1)		916			14,594
Other income		29			29
Net income	$	620		$	6,493


Asset retirement obligations at December 31, 2021	$	434,006
Obligations incurred		78
Obligations settled		(60,304	)
Obligations divested		(1,572	)
Accretion expense		42,400
Changes in estimate		38,656
Asset retirement obligations at September 30, 2022	$	453,264
Less: Current portion at September 30, 2022		65,613
Long-term portion at September 30, 2022	$	387,651

Stone Energy common stock - issued and outstanding as of May 9, 2018		20,038
Stone Energy common stock price	$	35.49
Common stock value	$	711,149
Stone Energy common stock warrants - issued and outstanding as of May 9, 2018		3,528
Stone Energy common stock warrants price	$	5.90
Common stock warrants value	$	20,815
Total consideration and fair value	$	731,964

Current assets⁽¹⁾	$	377,155
Property and equipment		876,500
Other long-term assets		18,928
Current liabilities		(130,121	)
Long-term debt		(235,416	)
Other long-term liabilities		(175,082	)
Allocated purchase price	$	731,964


Asset retirement obligations at January 1, 2018	$	214,733
Fair value of asset retirement obligations assumed		220,637
Obligations settled		(43,896	)
Accretion expense		14,252
Obligations incurred		120
Changes in estimate		8,532
Asset retirement obligations at June 30, 2018	$	414,378
Less: Current portion		94,334
Long-term portion	$	320,044

	June 30, 2018						December 31, 2017
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
11.00% Second-Priority Senior Secured Notes – due April 2022⁽¹⁾	$	380,042		$	410,411		$	—		$	—
7.50% Senior Secured Notes – due May 2022	$	6,060		$	5,999		$	—		$	—
Bank Credit Facility – due May 2022⁽¹⁾	$	231,522		$	240,000		$	—		$	—
11.00% Bridge Loans – due April 2022⁽¹⁾	$	—		$	—		$	169,838		$	172,023
9.75% Senior Notes – due July 2022⁽¹⁾	$	—		$	—		$	100,681		$	102,000
9.75% Senior Notes – due February 2018	$	—		$	—		$	24,977		$	24,977
Old Bank Credit Facility - due February 2019⁽¹⁾	$	—		$	—		$	402,062		$	403,000
Oil and Natural Gas Derivatives	$	(185,755	)	$	(185,755	)	$	(66,830	)	$	(66,830	)


Swap Contracts
Production Period	Settlement Index	Average Daily Volumes		Weighted Average Swap Price
Crude oil:		(Bbls)		(per Bbl)
October 2022 – December 2022	NYMEX WTI CMA		19,326	$	55.05
January 2023 – December 2023	NYMEX WTI CMA		14,863	$	72.18
January 2024 – September 2024	NYMEX WTI CMA		3,989	$	76.59
Natural gas:		(MMBtu)		(per MMBtu)
October 2022 – December 2022	NYMEX Henry Hub		44,000	$	4.21
January 2023 – December 2023	NYMEX Henry Hub		26,395	$	3.76
January 2024 – June 2024	NYMEX Henry Hub		10,000	$	3.25

Production Period	Instrument Type	Average Daily Volumes		Weighted Average Swap Price		Weighted Average Put Price		Weighted Average Call Price
Crude Oil – WTI:		(Bbls)		(per Bbl)		(per Bbl)		(per Bbl)
July 2018 - December 2018	Swap		29,615	$	54.06	$	—	$	—
July 2018 - December 2018	Collar		1,000	$	—	$	45.00	$	55.35
July 2018 - December 2018	Put		2,000	$	—	$	49.50	$	—
January 2019 - December 2019	Swap		23,130	$	54.14	$	—	$	—
Natural Gas – Henry Hub NYMEX:		(MMBtu)		(per MMBtu)		(per MMBtu)		(per MMBtu)
July 2018 - December 2018	Swap		23,747	$	3.01	$	—	$	—
July 2018 - December 2018	Collar		6,000	$	—	$	2.75	$	3.24
January 2019 - December 2019	Swap		10,146	$	2.99	$	—	$	—


Collar Contracts
Production Period	Settlement Index	Average Daily Volumes		Weighted Average Put Price		Weighted Average Call Price
Crude oil:		(Bbls)		(per Bbl)		(per Bbl)
July 2023 – September 2023	NYMEX WTI CMA		2,000	$	75.00	$	90.43
January 2024 – March 2024	NYMEX WTI CMA		2,000	$	70.00	$	88.00
Natural gas:		(MMBtu)		(per MMBtu)		(per MMBtu)
January 2023 – December 2023	NYMEX Henry Hub		10,000	$	5.25	$	8.46
January 2024 – December 2024	NYMEX Henry Hub		10,000	$	4.00	$	6.90


	September 30, 2022
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	46,929		$	—	$	46,929
Liabilities:
Oil and natural gas derivatives		—		(106,306	)		—		(106,306	)
Total net liability	$	—	$	(59,377	)	$	—	$	(59,377	)


	RSUs			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2021		1,983,199		$	13.02
Granted		2,297,465		$	13.23
Vested		(967,269	)	$	14.14
Forfeited		(63,599	)	$	14.05
Unvested RSUs at September 30, 2022(1)		3,249,796		$	12.82


	PSUs			Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2021		1,015,459		$	16.41
Granted(1)		629,666		$	23.73
Forfeited		(16,486	)	$	17.48
Cancelled		(975,564	)	$	16.42
Unvested PSUs at September 30, 2022		653,075		$	23.42


	2022
	Grant			Grant
	September 20			March 5
Expected term (in years)		2.3			2.8
Expected volatility		74.3	%		82.2	%
Risk-free interest rate		3.9	%		1.6	%
Dividend yield		—	%		—	%
Fair value (in thousands)	$	621		$	8,668

Deferred tax asset	$	213,029
Deferred tax liability		(82,805	)
Net deferred tax asset		130,224
Valuation allowance		(130,224	)
Net deferred tax asset	$	—


	Three Months Ended September 30, 2022 vs 2021							Nine Months Ended September 30, 2022 vs 2021
	Price		Volume			Total		Price		Volume			Total
Revenues:
Oil	$	73,322	$	(23,945	)	$	49,377	$	385,793	$	(50,752	)	$	335,041
Natural gas		35,195		1,442			36,637		93,185		2,474			95,659
NGL		992		(787	)		205		16,833		661			17,494
Total revenues	$	109,509	$	(23,290	)	$	86,219	$	495,811	$	(47,617	)	$	448,194


U.S. drilling & completions	$	120,510
Mexico appraisal & exploration		301
Asset management		80,704
Seismic and G&G, land, capitalized G&A and other		35,667
CCS(1)		2,027
Total capital expenditures		239,209
Plugging & abandonment		60,304
Total capital expenditures and plugging & abandonment	$	299,513


	Nine Months Ended September 30, 2022
Revenues	$	1,309,779
Costs and expenses		(936,118	)
Net income	$	373,661

Exploration	$	13,462
Development		60,333
Geological and geophysical/seismic		2,928
Land and lease		2,388
Other		9,163
Total	$	88,274

	2018		2019		2020		2021		Thereafter		Total
Long-term financing obligations:
Debt principal	$	217	$	217	$	—	$	—	$	647,272	$	647,706
Debt interest		33,759		67,517		67,517		67,517		23,560		259,870
Vessel commitments ⁽¹⁾		22,030		11,765		—		—		—		33,795
Derivative liabilities		92,293		94,195		—		—		—		186,488
Committed purchase orders⁽²⁾		1,460		13,704		—		—		—		15,164
Capital lease ⁽³⁾		22,500		45,000		45,000		45,000		63,750		221,250
Minimum lease payments		2,242		3,944		3,791		3,811		30,492		44,280
Mexico minimum work program		—		34,942		—		—		—		34,942
Total contractual obligations⁽⁴⁾	$	174,501	$	271,284	$	116,308	$	116,328	$	765,074	$	1,443,495

				Oil and Natural Gas Derivatives
				10 Percent Increase						10 Percent Decrease
	Fair Value			Fair Value			Change			Fair Value			Change
Price impact⁽¹⁾	$	(185,755	)	$	(281,258	)	$	(95,503	)	$	(90,224	)	$	95,531