TALOS ENERGY INC. 10-K

10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) ☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2022 OR ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission File Number 001-38497 Talos Energy Inc. (Exact name of Registrant as specified in its Charter) 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) Registrant’s telephone number, including area code: ( 713 ) 328-3000 Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Trading Symbol(s) Name of Each Exchange on Which Registered Common Stock TALO New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ N o ☐ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ N o ☑ 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 ☑ N o ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ N o ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer ☑ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐ 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑ If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Y es ☐ No ☑ The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on the closing price of the shares of common stock on the New York Stock Exchange on June 30, 2022 , was $ 1,076,771,374 . The number of shares of registrant’s Common Stock outstanding as of February 21, 2023 was 126,370,218 . Portions of the registrant’s definitive proxy statement relating to the 2023 Annual Meeting of Stockholders are incorporated by reference into Part III of this report. Table of Contents TABLE OF CONT ENTS Page GLOSSARY 3 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS 5 SUMMARY RISK FACTORS 7 PART I Items 1 and 2. Business and Properties 9 Item 1A. Risk Factors 39 Item 1B. Unresolved Staff Comments 68 Item 3. Legal Proceedings 68 Item 4. Mine Safety Disclosures 69 PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity Securities 70 Item 6. [Reserved] 71 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 72 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 91 Item 8. Financial Statements and Supplementary Data 92 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 92 Item 9A. Controls and Procedures 92 Item 9B. Other Information 93 Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 93 PART III Item 10. Directors, Executive Officers and Corporate Governance 94 Item 11. Executive Compensation 94 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 94 Item 13. Certain Relationships and Related Transactions, and Director Independence 94 Item 14. Principal Accounting Fees and Services 94 PART IV Item 15. Exhibits and Financial Statement Schedules 95 Item 16. Form 10-K Summary 101 2 Table of Contents G LOSSARY 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 — One stock tank barrel, or 42 United States gallons liquid volume. Boe — One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate. BOEM — Bureau of Ocean Energy Management. BSEE — Bureau of Safety and Environmental Enforcement. Boepd — Barrels of oil equivalent per day. Btu — British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit. CO 2 — Carbon dioxide. Completion — The installation of permanent equipment for the production of oil or natural gas. Deepwater — Water depths of more than 600 feet. Developed acres — The number of acres that are allocated or assignable to producing wells or wells capable of production. Field — An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition. GAAP — Accounting principles generally accepted in the United States of America. Gross acres or gross wells — The total acres or wells in which the Company owns a working interest. MBbls — One thousand barrels of crude oil or other liquid hydrocarbons. MBblpd — One thousand barrels of crude oil or other liquid hydrocarbons per day. MBoe — One thousand barrels of oil equivalent. MBoepd — One thousand barrels of oil equivalent per day. Mcf — One thousand cubic feet of natural gas. Mcfpd — One thousand cubic feet of natural gas per day. MMBoe — One million barrels of oil equivalent. MMBtu — One million British thermal units. MMcf — One million cubic feet of natural gas. MMcfpd — One million cubic feet of natural gas per day. Net acres or net wells — The sum of the fractional working interests the Company owns in gross acres or gross wells. NGL — Natural gas liquid. Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane and natural gasoline. NYMEX — The New York Mercantile Exchange. NYMEX Henry Hub — Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub Index. 3 Table of Contents OPEC — Organization of Petroleum Exporting Countries. Productive well — A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Proved developed reserves — In general, proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. The SEC provides a complete definition of developed oil and gas reserves in Rule 4-10(a)(6) of Regulation S-X. Proved reserves — Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved undeveloped reserves — In general, proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The SEC provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-X. PV-10 — The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) non-property related expenses such as general and administrative expenses, derivatives, debt service and future income tax expense or (ii) depreciation depletion and amortization expense. SEC — The Securities and Exchange Commission. SEC pricing — The unweighted average first-day-of-the-month commodity price for crude oil or natural gas for each month within the 12-month period prior to the end of the reporting period, adjusted by lease for market differentials (quality, transportation, fees, energy content, and regional price differentials). The SEC provides a complete definition of prices in “Modernization of Oil and Gas Reporting” (Final Rule, Release Nos. 33-8995; 34-59192). Shelf — Water depths up to 600 feet. Standardized Measure — The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the SEC and the Financial Accounting Standards Board (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Undeveloped acreage — Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves. Working interest — The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production. WTI or West Texas Intermediate — A light crude oil produced in the United States with an American Petroleum Institute gravity of approximately 38-40 and the sulfur content is approximately 0.3%. 4 Table of Contents CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS The information in this Annual Report on Form 10-K (this “Annual 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 Annual Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “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 our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements about: • business strategy; • reserves; • exploration and development drilling prospects, inventories, projects and programs; • our ability to replace the reserves that we produce through drilling and property acquisitions; • financial strategy, liquidity and capital required for our development program and other capital expenditures; • realized oil and natural gas prices; • the transaction with EnVen Energy Corporation (“EnVen”, and such transaction, the “EnVen Acquisition”) and anticipated future performance of the combined company; • timing and amount of future production of oil, natural gas and NGLs; • our hedging strategy and results; • future drilling plans; • availability of pipeline connections on economic terms; • competition, government regulations and political developments; • our ability to obtain permits and governmental approvals; • pending legal, governmental or environmental matters; • our marketing of oil, natural gas and NGLs; • leasehold or business acquisitions on desired terms; • costs of developing properties; • general economic conditions, including the impact of continued inflation and associated changes in monetary policy; • political and economic conditions and events in foreign oil, natural gas and NGL producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, the war in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America and China and acts of terrorism or sabotage; • credit markets; • impact of new accounting pronouncements on earnings in future periods; • estimates of future income taxes; 5 Table of Contents • our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities; • the success of our carbon capture and sequestration opportunities; • our ongoing strategy with respect to our Zama asset; • uncertainty regarding our future operating results and our future revenues and expenses; and • plans, objectives, expectations and intentions contained in this Annual Report that are not historical. We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility 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; 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; 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; well control risk; regulatory changes; the uncertainty inherent in estimating reserves and in projecting future rates of production; cash flow and access to capital; the timing of development expenditures; potential adverse reactions or competitive responses to our acquisitions and other transactions; the possibility that the anticipated benefits of 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 acquired assets and operations, and the other risks discussed in Part I, Item 1A. Risk Factors which are included herein. Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify upward or downward revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered. Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this Annual 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 Annual Report. 6 Table of Contents SUMMARY RISK FACTORS Risks Related to our Business and the Oil and Natural Gas Industry • Oil and natural gas prices are volatile. Stagnation or declines in commodity prices may adversely affect our financial condition and results of operations, cash flows, access to the capital markets and ability to gro w. • 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. • Production periods or relatively short reserve lives for U.S. 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. • Our actual recovery of reserves may substantially differ from our proved reserve estimates. • Our acreage has to be drilled before lease expirations 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. • The marketability of our production depends mostly upon the availability, proximity and capacity of oil and natural gas gathering systems, pipelines and processing facilities. • 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. • Continuing or worsening inflationary issues and associated changes in monetary policy may result in increases to the cost of our goods, services and personnel, which in turn could cause our capital expenditures and operating costs to rise. • We may be unable to pursue our CCS business, either wholly or in significant measure, which could have a material adverse effect on our business, results of operations and financial condition. • Our inability to qualify for, obtain, monetize or otherwise benefit from Section 45Q tax credits could materially reduce our ability to develop CCS projects and, as a result, may adversely impact 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. • Events outside of our control, including an epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business. • The ongoing war between Russia and Ukraine could adversely affect our business, financial condition and results of operations. • 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. • 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. • Hedging transactions may limit our potential gains. • Our operations may incur substantial liabilities to comply with environmental laws and regulations as well as legal requirements applicable to marine mammals and endangered and threatened species. 7 Table of Contents • We may be unable to provide the financial assurances in the amounts and under the time periods required by the BOEM if it submits future demands to cover our decommissioning obligations. If in the future the BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore leases. • Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local governmental regulations that materially affect our operations. • If we are forced to shut-in production, we will likely incur greater costs to bring the associated production back online, and will be unable to predict the production levels of such wells once brought back online. • Our operations may be adversely affected by political and economic circumstances in the countries in which we operate. • We may experience significant shut-ins and losses of production due to the effects of tropical storms and hurricanes in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico. • The Inflation Reduction Act of 2022 could accelerate the transition to a low carbon economy and could impose new costs on our operations. Risks Related to our Capital Structure and Ownership of our Common Stock • 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 12.00% Second-Priority 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. • A financial crisis may impact our business and financial condition and may adversely impact our ability to obtain funding under our Bank Credit Facility or in the capital markets. • We 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 are a holding company that has no material assets other than our ownership of the equity interests of Talos Production Inc. Accordingly, we are dependent upon distributions from Talos Production Inc. to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock. • 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 may not realize all of the anticipated benefits from our future acquisitions, and we may be unable to successfully integrate future acquisitions. • Our future acquisitions could expose us to potentially significant liabilities, including P&A liabilities. • Resolution of litigation could materially affect our financial position and results of operations. Risks Related to our Integration of EnVen into our Business • The combined company may fail to realize the anticipated benefits of the EnVen Acquisition. • The failure to successfully integrate our business and operations with EnVen in the expected time frame may adversely affect our future results. 8 Table of Contents Part I Items 1 and 2. Business and Properties Overview As used in this Annual Report and unless otherwise indicated or the context otherwise requires, references to “we,” “us,” “our,” “Talos Energy Inc.,” “Talos” and the “Company” refer to Talos Energy Inc. and its consolidated subsidiaries. We were incorporated on November 14, 2017 under the laws of the state of Delaware for the purpose of effecting the business combination between Talos Energy LLC and Stone Energy Corporation (“Stone”), pursuant to which each of Talos Energy LLC and Stone became our wholly-owned subsidiary. 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 oil and gas exploration and production (“Upstream”) and the development of carbon capture and sequestration (“CCS”) opportunities. We leverage decades of technical and offshore operational expertise in 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 along the coast of the U.S. Gulf of Mexico (“Gulf Coast”). We combine our technical experience in geology, geophysics and engineering with innovative resource evaluation techniques and seismic imaging expertise to discover new resources. We rely on our operational experience to optimize our assets’ production and recovery safely and responsibly. Finally, we leverage our commercial and corporate management experience to most effectively allocate our capital to balance risk and reward, grow our business and maximize long-term stockholder value. Business Strategy We intend to increase stockholder value by growing our Upstream reserves, production, cash flow and future growth opportunities in a capital efficient manner while exploring potential CCS opportunities with aspirations to become a contributor to U.S. emissions reduction goals. Our deep technical expertise and extensive physical operating experience also allows us to successfully manage our Upstream business and consistently make attractive acquisitions, thereby increasing stockholder value over time. Additionally, we believe these same core competencies can be utilized to develop large-scale decarbonization projects to reduce industrial emissions. Upstream Strategy We maintain a large and diverse in-house technical staff focused on geology, geophysics, engineering and other technical disciplines, providing many decades of exploration and production experience in the key resource trends in which we focus. Our significant library of seismic data resources, which focuses on the U.S. Gulf of Mexico and offshore Mexico, allows our technical team to apply proprietary seismic reprocessing techniques to evaluate or re-evaluate potential resources across our asset portfolio. Finally, we have deep in-house experience across our offshore operations, production operations, safety, facilities and business development teams. Our strategic business development activities allow us to consistently identify and evaluate new opportunities through a wide range of potential avenues, including government lease sales, joint ventures and acquisitions, among others. Our proven track record of success through organic drilling opportunities frequently attracts potential drilling partners in projects that we operate, while in non-operated projects we leverage our core competencies to independently identify the best investment opportunities, review partner-proposed projects and be a value-added contributor. Our asset acquisition strategy is focused on assets with a geological setting that can benefit from our ability to use our seismic database and technical expertise to re-evaluate and improve the acquired properties. Specifically, our acquisition focus areas target a variety of potential situations and sellers that are currently available in offshore basins, including single asset acquisitions, consolidation of private companies and broader asset package transactions. We seek to actively participate in government lease sales to identify and acquire attractive leasehold acreage, which in many cases has not been evaluated with the latest reprocessed seismic data, resulting in an opportunity for us to identify previously unknown drilling prospects. 9 Table of Contents 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 asset acquisition market. Our asset footprint, which includes operational control of several key shallow and Deepwater facilities, allows us to invest in a diverse set of opportunities ranging from in-field development to high impact exploration projects while optimizing our facilities to lower incremental operating costs structures. We also believe our operated infrastructure can be attractive to other operators looking for a host facility for their subsea tie-back projects, which allows us either to be involved in new investment opportunities or to offset the operating cost of these facilities. Utilizing our core competencies in conjunction with a robust and active business development effort allows us to use the following strategies to increase stockholder value: • Continuously Optimizing our Existing Asset Base — We benefit from our proven ability to enhance and extend the life of existing projects within our portfolio. Investments in optimization projects across our asset base aim to stabilize and improve the profile of producing assets by increasing recovery, production and cash flow with typically relatively low investment capital and risk. These projects allow for reinvestment opportunities in exploitation and exploration projects. • Conducting Development and Near-Field Projects In and Around Our Existing Asset Footprint — We undertake asset development and exploitation drilling projects in close proximity to our existing assets as well as facilities that we either own or have access to. These projects leverage ongoing operations and existing technical knowledge of the area, often coupled with recent proprietary seismic reprocessing evaluations to provide attractive incremental investment opportunities to grow reserves, production and cash flow in well-understood areas. • Engaging in Exploration Activities to Grow our Asset Base and Potentially Unlock Significant New Resources — We conduct exploration drilling activities across our acreage set with risk-weighted investments that could establish significant new reserves and production. These projects are intended to optimize risk and reward across our portfolio of prospective drilling opportunities by finding and developing previously undiscovered resources along existing or emerging geological trends with the most efficient deployment of capital. When successful, exploration drilling activities can organically generate material new assets for the Company. • Utilize Acquisitions and Other Business Development Activities to Expand our Asset Base, Opportunity Set and Value Creation Potential — We rely on our commercial and business development activities to expand our asset base through the acquisition or optimization of additional or existing properties, respectively. Commercial and business development provides a key avenue to create additional value from the acquisition of undervalued properties where we can apply our technical and operational competencies to generate upside. Additionally, we utilize business development to acquire new leaseholds, enter new projects and increase or decrease working interests in various existing projects to optimize capital planning and our targeted risk/return profile for varying business conditions. Acquisition opportunities in our basin and, more broadly, in the offshore exploration and production segment in other basins around the world, are numerous and span a wide range of lifecycle stages, sizes and geographic variables. We expect to continue utilizing acquisitions and business development to grow our business in a manner that preserves a strong and healthy credit profile as well as a diverse and high-quality asset base. 10 Table of Contents • Maintain Safety, Sustainability and Corporate Responsibility as Key Principles for Operations Across All Areas of our Business — We are focused on maintaining high standards of safety, environmental responsibility and corporate citizenship across all elements of our business. We closely monitor safety performance and consistently take steps to improve our performance. For the year ended 2022, we maintained a high level of safety performance with a lower recordable incident rate when compared to the average for offshore operators in the U.S. Gulf of Mexico as well as across numerous other industrial sectors of the broader economy. We strive to execute our business plan while simultaneously minimizing our environmental footprint, including emissions, potential spills and other impacts. Due to the nature of subsea wells and ample offshore pipelines, we believe the offshore operating environment is a region where greenhouse gas (“GHG”) emissions can continue to be lowered over time. Finally, we aim to be a good corporate citizen in the regions and communities where we operate. We recently published our third annual Environmental, Social, and Governance (“ESG”) report highlighting our performance and initiatives across all of these categories and other topics, which is not incorporated into, and does not form a part of, this Annual Report. Carbon Capture and Sequestration Strategy Our CCS business is operated through our Talos Low Carbon Solutions (“TLCS”) subsidiary. TLCS intends to leverage its experience and technical expertise along the Gulf Coast, including subsurface engineering expertise, seismic data sets and interpretation capabilities, operational experience offshore and along the Gulf Coast and a solid track record of safety and environmentally responsible operations. The Gulf Coast is a critical industrial region with a large emissions footprint, while the underlying conventional geology in the area is believed to be ideal for carbon sequestration. TLCS intends to provide decarbonization solutions to assist industrial partners with carbon emissions capture, transportation and injection into sequestration sites in the region. Upstream Properties United States Gulf of Mexico Our area of focus in the United States is the Gulf of Mexico Deepwater. Our strategy is concentrated in areas characterized by clearly defined infrastructure, well-known production history and geological well control, which reduces operational and investment risk. We believe the potential for large discoveries and increasing success rates in the sub-salt and mini-basin lower Pliocene and Miocene plays has resulted in increased industry focus on this area over the last decade. We also believe our Deepwater operations in the U.S. Gulf of Mexico provide significant potential growth opportunities through our drilling program. Through our technical approach of starting with known hydrocarbon systems and applying modern seismic reprocessing techniques, we have generated a substantial inventory of Deepwater prospects that we believe are capable of delivering predictable production growth. We primarily focus our exploitation and exploration efforts around our existing infrastructure. This subsea tie-back strategy allows for better project economics and shorter periods between a discovery and production as compared to design, construction and installation of a new facility following a discovery. 11 Table of Contents As of December 31, 2022, our core areas in the United States are illustrated below: The following table sets forth a summary of certain key 2022 information regarding our core areas in the United States: Estimated Proved Reserves MBoe % Oil % Natural Gas % NGLs % Proved Developed Net Production (MBoe) % Operated Green Canyon 30,691 81 % 13 % 6 % 100 % 6,731 97 % Mississippi Canyon 74,380 68 % 21 % 11 % 76 % 9,383 60 % Shelf & Gulf Coast 35,508 44 % 48 % 8 % 82 % 5,609 53 % Total United States 140,579 65 % 26 % 9 % 83 % 21,723 70 % Green Canyon — Green Canyon is a Deepwater region in the Central U.S. Gulf of Mexico and is a key focus area both industry-wide and for our exploration activities. We operate two production facilities in the region, including a floating production unit, the Helix Producer I (“HP-I”), that is leased from Helix Energy Solutions Group, Inc. (“Helix”). Mississippi Canyon — Mississippi Canyon is a Deepwater region in the eastern portion of the Central U.S. Gulf of Mexico with a track record of prolific production and ongoing exploration success that continues to unlock new resources. We operate three production facilities in the region and are active as both an operator and non-operating partner in numerous development projects and producing fields. Shelf and Gulf Coast — The U.S. Gulf of Mexico Shelf (the “Shelf”) and Gulf Coast area spans an enormous geographical area across the basin and provides diverse production from numerous operated production facilities. The Shelf area is a producing region of the basin with attractive redevelopment and recovery enhancement opportunities. 12 Table of Contents Mexico As of December 31, 2022, our area of focus in Mexico is the Block 7, Zama Unit Area segment located within the Sureste Basin, a prolific proven hydrocarbon province, in the shallow waters off the coast of Mexico’s Tabasco state. Such area is illustrated below: Block 7 — On July 15, 2015, a Talos-led consortium was awarded Block 7 (“Block 7 Consortium”) with a term of thirty years, starting in September 2015, and extendable for two additional five-year periods. The Company’s participation interest in Block 7 is 35% and we are the operator. The Block 7 Consortium made a significant discovery in Block 7 after drilling the Zama-1 in 2017, less than two years after signing a production sharing contract (“PSC”) for the block with Mexico's upstream oil and gas regulator, the National Hydrocarbon Commission (“CNH”). Subsequent to the Zama-1 discovery, we drilled three additional wells to further appraise the discovery. Upon conclusion of the three well appraisal program, we determined that the Zama Field likely extended into a nearby offshore block owned by Petróleos Mexicanos (“PEMEX”). On July 7, 2020, we received a notice from Mexico’s Secretaría de Energía (“SENER”) instructing the Block 7 Consortium and PEMEX to unitize the Zama Field. The Block 7 Consortium and PEMEX engaged a third-party reservoir engineering firm to evaluate initial tract participation within the Zama reservoir, which concluded that the Block 7 Consortium holds 49.6% of the gross interest in the Zama Field and PEMEX holds 50.4%. On July 2, 2021, we were notified by SENER that it had designated PEMEX as the operator of the Zama unit. During the third quarter of 2021, we submitted Notices of Dispute (“Notices of Dispute”) to the Government of Mexico over decisions taken by SENER, including the designation of PEMEX as the operator of a yet-to-be unitized asset. On March 23, 2022, we received a final Unitization Resolution (the “UR”) from SENER regarding the development of the Zama Field. The UR defines the rights and responsibilities of PEMEX and the Block 7 Consortium (together, the “Zama Field Participants”) with respect to the development of the Zama Field. On May 26, 2022, the Zama Field Participants ratified the creation of a Unit Operating Committee (“UOC”), with participation of each party, to oversee the development of the Zama Field. Since then, we have actively engaged with PEMEX and the rest of the Block 7 Consortium to advance development. We hold a 17.35% interest in the unitized Zama Field, and we are working with the rest of the Zama Field Participants towards the finalization of the Zama Field Development Plan for submission to the CNH for final approval. The PSC forms the basis for the Company’s exploration, development and production operations on Block 7. The Block 7 PSC includes a cost recovery feature pursuant to which eligible costs in relation to the minimum work program activities are recoverable in-kind at a rate of 125% of costs from future production volumes. Production volumes are allocated in-kind between the Block 7 Consortium and the United Mexican States on a monthly basis based on the contractual value of the hydrocarbons as defined in the PSC. Up to 60% of the monthly contractual value of the hydrocarbons will be allocated to the Block 7 Consortium to recover eligible costs incurred in petroleum activities. Eligible costs exceeding 60% of the current month contractual value of the hydrocarbons will be recoverable in future periods. The amount of royalties will be determined for each type of hydrocarbons (oil, associated natural gas, non-associated natural gas and condensate) using an initial rate, adjusted thereafter for inflation. The remaining value of the hydrocarbons after the allocation for cost recovery and royalties is considered operating profit under the PSC. 13 Table of Contents The allocation of operating profit to the Block 7 Consortium after the allocation for cost recovery and royalties is 31%. The profit for oil and gas is determined on a monthly basis using an adjustment mechanism based on the projects rate of return (“ROR”). If the cumulative project’s ROR in any one month exceeds 25%, the barrels of oil allocated to the Block 7 Consortium after cost recovery are reduced on a sliding scale. Once the cumulative project’s internal ROR meets or exceeds 40%, the reduction locks in at a maximum rate. The Hydrocarbons Revenue Law provides that exploration and extraction activities are zero rated for value-added tax (“VAT”) purposes; all other activities are taxed at 16% VAT. The 0% rates only apply to agreements between the United Mexican States and state-owned enterprises or entities, and do not apply to any other agreement executed with third parties, even in the case of exploration and extraction contracts. The Mexico income tax rate is 30%. Carbon Capture & Sequestration TLCS is leveraging decades of experience with conventional geology and Gulf Coast operations to pursue the development of future CCS projects. Project opportunities are actively being evaluated along the Gulf Coast. Future CCS project opportunities and the associated sequestration sites can generally be categorized into the following: (i) regional hub projects; and (ii) point source projects; which TLCS intends to identify, lease, mature and operate. Areas of development are illustrated below as of December 31, 2022: Regional Hubs — These projects will be large, contiguous sequestration sites located proximally to large industrial emissions centers in which TLCS intends to consolidate carbon emissions from multiple contributing sources and develop large-scale CCS projects. Regional hub projects are characterized by their large size, population of diverse contributing emitters and central proximity to major emitting regions. Current regional hub projects under development are as follows: • Bayou Bend CCS — On March 11, 2022, Bayou Bend CCS LLC (“Bayou Bend”), an equity method investment with Carbonvert, Inc. (“Carbonvert”), executed definitive lease documentation with the Texas General Land Office, formalizing the Jefferson County carbon sequestration site located in state waters offshore Jefferson County, Texas, near the Beaumont and Port Arthur, Texas industrial corridor. 14 Table of Contents On May 24, 2022, Bayou Bend executed definitive documentation with Chevron U.S.A., Inc. (“Chevron”), through its Chevron New Energies division, and closed an expanded venture to jointly develop the Bayou Bend project with Chevron. Under the terms of the transaction, Chevron acquired a 50% membership interest in Bayou Bend for gross consideration of $50.0 million, consisting of $30.0 million of cash at closing and up to $20.0 million of gross contributions to Bayou Bend. This cash is expected to cover TLCS and Carbonvert’s share of capital expenditures through the project’s final investment decision. TLCS, Carbonvert and Chevron hold a 25%, 25% and 50% membership interest in Bayou Bend, respectively, and TLCS remains the project’s operator. The three companies have also established an area of mutual interest over the full acreage in the Jefferson County offshore region contemplated in the State of Texas’s original request for proposal, aligning the parties for future expansion opportunities. For additional information on Bayou Bend, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — Related Party Transactions . • River Bend CCS — In February 2022, an agreement was reached to lease acreage along the Mississippi River industrial corridor for a future CCS project. The lease agreement will allow for three sequestration sites near existing pipeline infrastructure that may be used for the project. TLCS will manage the project and be operator of the injection, storage, and monitoring services. TLCS will be supported by its partner, Storegga Geotechnologies Limited (“Storegga”). Point Sources — These projects will be bespoke, customized sequestration projects for individual industrial partners to capture and eliminate carbon emissions from singular sources, such as liquefied natural gas (“LNG”) facilities, manufacturing plants, or power generation facilities, among others. Point source projects are characterized by their smaller footprint, individual emissions source (i.e ., one (1) plant) and pore space leases located nearby or on-site to that emissions source. Point source projects may carry a wider range of commercial structures than regional hubs due to their customized and directly negotiated nature, and TLCS believes the total number of point source opportunities along the Gulf Coast is significant. Current point source projects under development are as follows: • Coastal Bend CCS — Pursuant to an option agreement with the Port of Corpus Christi Authority (“PCCA”) executed in February 2022, TLCS and Howard Energy Partners (“HEP”) are pursuing commercial CCS opportunities on-site at the Port of Corpus Christi. As of December 31, 2022, definitive documentation with HEP remained subject to negotiation of final terms. • Freeport LNG CCS — In November 2021, a letter of intent with an affiliate of Freeport LNG Development, L.P. (“Freeport LNG”) was executed to develop a CCS point source project immediately adjacent to its existing LNG pre-treatment facilities in Freeport, Texas. The project intends to utilize a Freeport LNG-owned geological sequestration site located less than half a mile from point of capture. This point source project benefits from a dedicated source of CO 2 and a secured injection site in close physical proximity. As of December 31, 2022, definitive documentation with Freeport LNG remained subject to negotiation of final terms. 15 Table of Contents Summary of Reserves The following table summarizes our estimated proved reserves which are all located in the United States: Oil (MBbls) Natural Gas (MMcf) NGL (MBbls) MBoe Standardized Measure (in thousands) PV -10 (in thousands) December 31, 2022 Proved developed producing 63,049 103,245 6,194 86,451 $ 3,935,208 Proved developed non-producing 17,236 58,482 3,121 30,104 661,882 Total proved developed 80,285 161,727 9,315 116,555 4,597,090 Proved undeveloped 10,774 57,824 3,613 24,024 584,009 Total proved 91,059 219,551 12,928 140,579 $ 4,368,448 $ 5,181,099 December 31, 2021 Proved developed producing 70,183 108,238 7,426 95,649 $ 3,073,168 Proved developed non-producing 23,237 78,204 4,366 40,637 599,010 Total proved developed 93,420 186,442 11,792 136,286 3,672,178 Proved undeveloped 14,344 49,911 2,643 25,306 253,819 Total proved 107,764 236,353 14,435 161,592 $ 3,440,611 $ 3,925,997 December 31, 2020 Proved developed producing 64,763 119,824 4,958 89,692 $ 1,556,221 Proved developed non-producing 20,244 84,230 3,146 37,428 197,924 Total proved developed 85,007 204,054 8,104 127,120 1,754,145 Proved undeveloped 24,300 53,154 2,754 35,913 244,340 Total proved 109,307 257,208 10,858 163,033 $ 1,904,934 $ 1,998,485 Reconciliation of Standardized Measure to PV-10 PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves. The following table provides a reconciliation of the standardized measure of discounted future net cash flows to PV-10 of our proved reserves (in thousands): Year Ended December 31, 2022 2021 2020 Standardized measure $ 4,368,448 $ 3,440,611 $ 1,904,934 Present value of future income taxes discounted at 10% 812,651 485,386 93,551 PV-10 (Non-GAAP) $ 5,181,099 $ 3,925,997 $ 1,998,485 16 Table of Contents Changes in Proved Developed Reserves The following table discloses our estimated changes in proved developed reserves: Oil, Natural Gas and NGLs (MBoe) Proved developed reserves at December 31, 2021 136,286 Changes during the year: Production (21,723 ) Revisions of previous estimates 1,994 Additions 881 Divestitures (883 ) Total proved developed reserves changes (19,731 ) Proved developed reserves at December 31, 2022 116,555 Our proved developed reserves at December 31, 2022 decreased by 19.7 MMBoe, or 14% primarily due to: Revisions of Previous Estimates — Upward revisions of 2.0 MMBoe are due to an increase of 7.4 MMBoe related to the Ram Powell Field and Pompano Field located in the Mississippi Canyon core area and the West Cameron Field located in the Shelf and Gulf Coast core area due to performance and price revisions. This increase was offset with a decrease in the Tornado wells in the Phoenix Field located in the Green Canyon core area of 6.2 MMBoe primarily related to performance revisions from increased water volumes. Additions — Additions of 0.9 MMBoe are primarily attributable to the successful drilling results in the Sawfish Field located in the Shelf and Gulf Coast core area and the Green Canyon 18 Field in the Green Canyon core area. Divestitures — Divestitures of 0.9 MMBoe are primarily attributable to Brushy Creek Field located in the Shelf and Gulf Coast core area. Development of Proved Undeveloped Reserves The following table discloses our estimated proved undeveloped (“PUD”) reserve activities: Oil, Natural Gas and NGLs Future Development Costs (MBoe) (in thousands) Proved undeveloped reserves at December 31, 2021 25,305 $ 308,032 Changes during the year: Extensions and discoveries 10,269 307,854 Revisions of previous estimates (11,004 ) (133,135 ) Divestitures (546 ) (4,240 ) Total proved undeveloped reserves changes (1,281 ) 170,479 Proved undeveloped reserves at December 31, 2022 24,024 $ 478,511 Our PUD reserves at December 31, 2022 decreased by 1.3 MMBoe, or 5% primarily due to: Extensions and Discoveries — Extensions and discoveries of 10.3 MMBoe are primarily attributable to the Ram Powell Field and Pompano Field located in the Mississippi Canyon core area. The increase includes 6.3 MMBoe associated with the successful drilling results in our Lime Rock and Venice prospects, which are awaiting completion and hookup to facilities at the Ram Powell Platform. Revisions of Previous Estimates — Downward revisions of 11.0 MMBoe, of which 9.9 MMBoe and associated future development costs were due to the write off of a certain Phoenix Field PUD location. Annually better prospects become available to drill and as such resulted in this field location to move beyond the five year expiration. Divestitures — Divestitures of 0.5 MMBoe are attributable to our Brushy Creek Field located in the Shelf and Gulf Coast core area. 17 Table of Contents We annually review all PUD reserves to ensure an appropriate plan for development exists. Our PUD reserves are required to be converted to proved developed reserves within five years of the date they are first booked as PUD reserves, unless the reserves are associated with an existing producing zone. Future development costs associated with our PUD reserves at December 31, 2022 totaled approximately $478.5 million, of which $388.2 million and $90.3 million is attributable to our Mississippi Canyon and Shelf and Gulf Coast core areas, respectively. When considering capital expenditures associated with other exploration projects and abandonment obligations, we expect to fund the development of PUD reserves using cash flows from operations and, if needed, availability under the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”), in each future annual period prior to the five year expiration. Our 2023 drilling program includes development of PUD reserves, and the conversion rate may not be uniform due to obligatory wells, newly acquired PUD reserves and production performance targets. Internal Controls over Reserve Estimates and Reserve Estimation Procedures At December 31, 2022, 2021 and 2020, proved oil, natural gas and NGL reserves attributable to our net interests in oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists, as described in further detail below. Our policies regarding internal controls over the determination of reserves estimates require reserves quantities, reserves categorization, future producing rates, future net revenue and the present value of such future net revenue prepared using the definitions set forth in Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and guidance. These internal controls, which are intended to ensure reliability of our reserves estimations, include, but are not limited to, the following: • reserve information, as well as models used to estimate such reserves, is stored on secure database applications to which only authorized personnel are given access rights consistent with their assigned job function; • a comparison of historical expenses is made to the lease operating costs in the reserve database; • internal reserves estimates are reviewed by well and by area by our reservoir engineers. A variance analysis by well to the previous year-end reserve report is performed; • reserve estimates are reviewed and approved by certain members of senior management, including our President and Chief Executive Officer; • our management requires that the independent petroleum engineers and geologists and our reserve quantities and calculation of the net present value of the reserves, collectively, vary by no more than 10% in the aggregate, in accordance with Society of Petroleum Evaluation Engineers (“SPEE”) auditing standards; • data is transferred to NSAI through a secure file transfer protocol site; and • material reserve variances are discussed among NSAI, as applicable, our internal reservoir engineers and our Director of Reserves to ensure the best estimate of remaining reserves. Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil, natural gas and NGLs that are ultimately recovered. 18 Table of Contents During the reserves audit, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil, natural gas and NGL production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of NSAI that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. When compared on a well by well basis, some of our estimates are greater and some are less than the estimates of NSAI. Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and external estimates are to be expected. NSAI determined that its estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(24) of Regulation S-X. NSAI issued unqualified audit opinions on our reserves as of December 31, 2022, 2021 and 2020 based upon its evaluations. NSAI concluded that our estimates of reserves were, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPEE. The 2022 NSAI report is filed as Exhibit 99.1 to this Annual Report. Technologies Used in Reserve Estimation The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and/or NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reservoir engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of our reserves is a function of: • the quality and quantity of available data and the engineering and geological interpretation of that data; • estimates regarding the amount and timing of future operating costs, development costs and workovers, all of which may vary considerably from actual results; • future prices of oil, natural gas and NGLs, which may vary considerably from those mandated by the SEC; and • the judgment of the persons preparing the estimates. Qualifications of Primary Internal Engineer Our Director of Reserves is the technical person primarily responsible for overseeing the preparation of our internal reserve estimates and for coordinating reserve audits conducted by NSAI. He has over 48 years of industry experience with positions of increasing responsibility, including 40 years as a reserves evaluator or manager. His further professional qualifications include a State of Texas Professional Engineering License, extensive internal and external reserve training and asset evaluation. In addition, he is an active participant in industry reserve seminars and professional industry groups, and has been a member of the Society of Petroleum Engineers for over 48 years. He reports directly to our Vice President of Corporate Development. 19 Table of Contents Drilling Activity The following table sets forth our drilling activity: Exploratory and Appraisal Wells Development Wells Productive (1) Dry (2) Total Productive (1) Dry (2) Total Total Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net December 31, 2022 United States — — 1.0 1.0 1.0 1.0 6.0 2.8 — — 6.0 2.8 7.0 3.8 Mexico — — — — — — — — — — — — — — Total — — 1.0 1.0 1.0 1.0 6.0 2.8 — — 6.0 2.8 7.0 3.8 December 31, 2021 United States — — 2.0 1.5 2.0 1.5 5.0 2.4 — — 5.0 2.4 7.0 3.9 Mexico — — — — — — — — — — — — — — Total — — 2.0 1.5 2.0 1.5 5.0 2.4 — — 5.0 2.4 7.0 3.9 December 31, 2020 United States (3) 2.0 0.7 — — 2.0 0.7 3.0 1.9 — — 3.0 1.9 5.0 2.6 Mexico — — — — — — — — — — — — — — Total 2.0 0.7 — — 2.0 0.7 3.0 1.9 — — 3.0 1.9 5.0 2.6 (1) A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas producing well. Productive wells are included in the table in the year they were determined to be productive, as opposed to the year the well was drilled. (2) A dry well is an exploratory or development well that is not a productive well. Dry wells are included in the table in the year they were determined not to be productive, as opposed to the year the well was drilled. (3) One gross and net development well had a dual completion in an exploratory zone. As of December 31, 2022, we had wells actively drilling or completing and wells suspended or awaiting completion, as follows: Actively Drilling or Completing Wells Suspended or Waiting on Completion Exploratory Development Exploratory Development Gross Net Gross Net Gross Net Gross Net United States 3.0 0.9 2.0 1.2 2.0 0.9 — — Mexico — — — — 4.0 0.7 — — Total 3.0 0.9 2.0 1.2 6.0 1.6 — — Productive Wells The number of our productive wells is as follows for the year ended December 31, 2022: Gross Net Crude oil 203.0 151.1 Natural gas 67.0 31.9 Total (1) 270.0 183.0 (1) Includes 9.0 gross and 6.8 net wells with dual completions. Acreage Gross and net developed and undeveloped acreage is as follows for the year ended December 31, 2022: Developed Acres Undeveloped Acres Total Acres Gross Net Gross Net Gross Net United States: Deepwater 286,671 140,051 501,244 214,771 787,915 354,822 Shelf 234,250 148,210 103,827 80,838 338,077 229,048 Total United States 520,921 288,261 605,071 295,609 1,125,992 583,870 Mexico — — 4,584 1,604 4,584 1,604 Total 520,921 288,261 609,655 297,213 1,130,576 585,474 20 Table of Contents Undeveloped acreage is considered to be leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether or not such acreage contains proved reserves. Included within undeveloped acreage are leased acres (held by production under the terms of a lease) that are not within the spacing unit containing, or acreage assigned to, the productive well holding such lease. The terms of our leases on undeveloped acreage as of December 31, 2022 are scheduled to expire as shown in the table below (the terms of which may be extended by drilling and production operations): Gross Net 2023 186,342 106,268 2024 101,720 34,830 2025 46,166 25,778 2026 23,041 10,657 2027 86,401 38,326 2028 and beyond 165,985 81,354 Total 609,655 297,213 Crude Oil, Natural Gas and NGL Production, Prices and Production Costs Our production volumes, average sales prices and average production costs are as follows: Year Ended December 31, 2022 2021 2020 Production Volumes: Crude oil (MBbls) 14,561 16,159 13,665 Natural gas (MMcf) 32,215 32,795 28,652 NGLs (MBbls) 1,793 1,875 1,559 Total (MBoe) 21,723 23,500 19,999 Percent of MBoe from crude oil 67 % 69 % 68 % Average Sales Price (including commodity derivatives): Crude oil (per Bbl) $ 68.40 $ 49.67 $ 47.36 Natural gas (per Mcf) $ 5.30 $ 3.11 $ 2.00 NGLs (per Bbl) $ 33.20 $ 26.54 $ 9.90 Average (per Boe) $ 56.46 $ 40.61 $ 35.99 Average Sales Price (excluding commodity derivatives): Crude oil (per Bbl) $ 93.75 $ 65.86 $ 37.09 Natural gas (per Mcf) $ 7.06 $ 3.98 $ 1.87 NGLs (per Bbl) $ 33.20 $ 26.54 $ 9.90 Average (per Boe) $ 76.05 $ 52.96 $ 28.80 Average Lease Operating Expense (per Boe) $ 14.18 $ 12.07 $ 12.33 21 Table of Contents Crude Oil, Natural Gas and NGL Production, Prices and Production Costs—Significant Fields Mississippi Canyon Core Area — Pompano Field The following table sets forth certain information regarding our production volumes, average sales prices and average production costs for the Pompano Field, which consisted of 15% or more of our 2022 total estimated proved reserves on December 31, 2022: Year Ended December 31, 2022 2021 2020 Production Volumes: Crude oil (MBbls) 2,809 2,716 2,852 Natural gas (MMcf) 4,759 2,626 2,179 NGLs (MBbls) 393 254 216 Total (MBoe) 3,995 3,408 3,431 Percent of MBoe from crude oil 70 % 80 % 83 % Average Sales Price (excluding commodity derivatives): Crude oil (per Bbl) $ 95.21 $ 67.33 $ 38.51 Natural gas (per Mcf) $ 8.02 $ 4.68 $ 2.28 NGLs (per Bbl) $ 31.87 $ 25.54 $ 6.51 Average (per Boe) $ 79.63 $ 59.17 $ 33.86 Average Lease Operating Expense (per Boe) $ 2.26 $ 3.57 $ 2.90 Expenditures and Costs Incurred For information on property development, exploration and acquisition costs, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Supplemental Oil and Gas Disclosures (Unaudited) . Title to Properties We believe that we have satisfactory title to our oil and natural gas properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalties, overriding royalties, and carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes and development obligations under oil and natural gas leases. As is customary in the industry in the case of undeveloped properties, often limited investigation of record title is made at the time of acquisition. Title search investigations are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. To the extent title opinions or other investigations reflect defects affecting such undeveloped properties, we are typically responsible for curing any such title defects at our expense. Commodity Price Risks and Price Risk Management Activities Production from our properties is marketed using methods that are consistent with industry practices. Sales prices for oil and natural gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. We enter into derivative contracts on our oil and natural gas production primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales. For additional information regarding our commodity price risk and commodity derivative instruments, see Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk. 22 Table of Contents Significant Customers Oil and natural gas companies spend capital on exploration, drilling and production operations expenditures, the amount of which is generally dependent on the prevailing view of future oil and natural gas prices which are subject to many external factors which may contribute to significant volatility in future prices. We market substantially all of our oil, natural gas and NGL production from the properties we operate and those we do not operate. Our customers consist primarily of major oil and gas companies, well-established oil and pipeline companies and independent oil and natural gas producers and suppliers. We perform ongoing credit evaluations of our customers and provide allowances for probable credit losses when necessary. For the year ended December 31, 2022, 44%, 23% and 11% of our oil, natural gas and NGL revenues were attributable to Shell Trading (US) Company, Valero Energy Corporation and Chevron Products Company, respectively, which are the customers that individually represented 10% or more of our oil, natural gas and NGL revenues. Competitive Conditions The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of oil and natural gas leases, equipment and personnel required to find and produce reserves and in the gathering and marketing of oil, natural gas and NGLs. We compete with large integrated oil and natural gas companies as well as independent exploration and production companies. Certain of our competitors may have significantly more financial or other resources available to them. In addition, certain of the larger integrated companies may be better able to respond to industry changes, including price fluctuation, oil and natural gas demand and governmental regulations. However, we believe our high quality oil-weighted production base, proven expertise in utilizing seismic technology to identify, evaluate and develop exploitation and exploration opportunities, balanced mix of assets in the U.S. Gulf of Mexico deep and shallow waters and significant operating control give us a strong competitive position relative to many of our competitors. Seasonality of Business Weather conditions affect the demand for, and prices of, oil and natural gas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis. Generally, but not always, the demand for gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers may impact general seasonal changes in demand. Insurance Matters Our oil and natural gas operations are subject to risks incident to the operation of oil and gas wells, including, but not limited to, uncontrolled flows of oil, gas, brine or well fluids into the environment, blowouts, cratering, mechanical difficulties, fires, explosions or other physical damage, pollution or other risks, any of which could result in substantial losses to us. In addition, our oil and natural gas properties are located in the U.S. Gulf of Mexico, which makes us more vulnerable to tropical storms and hurricanes. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and the suspension of operations. Damages arising from such occurrences may result in lawsuits asserting large claims. Insurance may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful claim for which we are not fully insured could have a material adverse effect on our financial condition, results of operations and cash flow. Although we obtain insurance against some of these risks, we cannot insure against all possible losses. As a result, any damage or loss not covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flow. We have insurance policies to cover some of our risk of loss associated with our operations, and we maintain the amount of insurance we believe is prudent. However, not all of our business activities can be insured at the levels we desire because of either limited market availability or unfavorable economics (limited coverage for the underlying cost). 23 Table of Contents Our general property damage insurance provides varying ranges of coverage based upon several factors, including well counts and the cost of replacement facilities. Our general liability insurance program provides a limit of $500.0 million for each occurrence and in the aggregate, and includes varying deductibles. Our Offshore Pollution Act insurance is subject to a maximum of up to $150.0 million for each occurrence and in the aggregate, including a $100,000 retention. Coverage is provided for damage to our assets resulting from a named U.S. Gulf of Mexico windstorm; however, such coverage is subject to a maximum of $200.0 million per named windstorm and in the aggregate, and is also subject to a maximum of $15.0 million per occurrence retention dependent on location. We separately maintain an operators extra expense policy with additional coverage for an amount up to $500.0 million for U.S. Gulf of Mexico Deepwater drilling wells, $150.0 million for U.S. Gulf of Mexico Shelf drilling wells, $75.0 million for U.S. Gulf of Mexico producing and shut-in wells, $75.0 million for drilling and workover in inland waters and $25.0 million for drilling and workover in onshore fields that would cover costs involved in making a well safe after a blow-out or getting the well under control; re-drilling a well to the depth reached prior to the well being out of control or blown out; costs for plugging and abandoning the well; and costs for clean-up and containment and for damages caused by contamination and pollution. For our Mexico insurance policies, we maintain $250.0 million in operators extra expense coverage for operations and $500.0 million per occurrence and aggregate limit for general liability. We may increase or decrease insurance coverage around our key strategic assets, including potentially purchasing catastrophic bond instruments. Our highest value assets, which are located in the Phoenix Field, produce through the HP-I floating production system, which has the capability to disconnect and move away in the event of a storm, mitigating the risk of property damage. We customarily have reciprocal agreements with our customers and vendors in which each contracting party is responsible for its respective personnel for liability related to work performed for us. Under these agreements, we generally are indemnified against third party claims related to the injury or death of our customers’ or vendors’ personnel, subject to the application of various states’ laws. Government Regulation Exploration and development and the production and sale of oil, natural gas and NGLs are subject to extensive federal, state, local and foreign laws and regulations. An overview of these legal requirements is set forth below. Historically, our compliance with existing requirements has not had a material adverse effect on our financial position, results of operations or cash flows. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Because such laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production. General Overview — Our oil and natural gas operations are subject to various federal, state, local and foreign laws and regulations. Generally speaking, these regulations relate to matters that include, but are not limited to: • location of wells; • size of drilling and spacing units or proration units; • number of wells that may be drilled in a unit; • unitization or pooling of oil and natural gas properties; • drilling and casing of wells; • issuance of permits in connection with exploration, drilling and production; • well production; • spill prevention plans; • protection of private and public surface and ground water supplies; • emissions permitting or limitations; 24 Table of Contents • protection of endangered species; • use, transportation, storage and disposal of fluids and materials incidental to oil and natural gas operations; • surface usage and the restoration of properties upon which wells have been drilled; • calculation and disbursement of royalty payments and production taxes; • requirements for the posting of supplemental bonds or providing other forms of financial assurance for the plugging and abandonment of wells located in the U.S. Gulf of Mexico and offshore Mexico and, following cessation of operations, the removal or appropriate abandonment of all production facilities, structures and pipelines in those areas (“P&A” or “decommissioning” obligations); • performance of P&A obligations; and • transportation of production. Outer Continental Shelf (“OCS”) Regulation — Our operations on federal oil and natural gas leases in the U.S. Gulf of Mexico are subject to regulation by the BSEE, the BOEM and the Office of Natural Resources Revenue (“ONRR”), which are all agencies of the U.S. Department of the Interior (“DOI”). These leases are awarded by the BOEM based on competitive bidding and contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the federal Outer Continental Shelf Lands Acts (“OCSLA”). For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of their operations. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency (“EPA”), lessees must obtain a permit from BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, P&A of wells on the OCS, calculation of royalty payments and the valuation of production for this purpose, and decommissioning of facilities, structures and pipelines. President Biden issued an executive order in January 2021 suspending federal offshore and onshore oil and gas leasing pending review and reconsideration of federal oil and gas leasing and permitting practices. The suspension of these federal leasing activities prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a federal district judge in Louisiana in June 2021 and a permanent injunction in August 2022, effectively halting implementation of the leasing suspension with respect to those leases canceled or postponed prior to March 24, 2021. The federal government and a coalition of environmental groups are appealing the district court decision but, in the interim, BOEM scheduled a lease sale for certain blocks in the U.S. Gulf of Mexico consistent with the preliminary injunction, which sale occurred in November 2021. However, on January 27, 2022, a D.C. District Court judge vacated the lease sale on the basis that BOEM failed to consider the impact on foreign greenhouse gas emissions if the November 2021 lease sale was not held and the court determined that this failure was a violation of the National Environmental Policy Act. However, in September 2022, BOEM announced that it was reinstating the lease results in line with congressional direction in the Inflation Reduction Act of 2022 (the “IRA 2022”). Separately, the DOI released its report on federal oil and gas leasing and permitting practices in November 2021, following a review of the onshore and offshore federal oil and gas program. The report states an intent to modernize the federal oil and gas leasing program and, in respect of the offshore sector, recommends strengthening financial assurance coverage amounts that are more protective of the Federal Government and taxpayers and establishing a “fitness to operate” criteria that companies would need to meet in respect of safety, environmental and financial responsibilities in order to operate on the OCS. The IRA 2022 responded to one of the report’s recommendations and increased onshore royalty rates to 16.7% and offshore royalty rates to no less than 16.7% but not more than 18.8% for the next ten years, thereby ensuring the full value of the leased tracts are captured. Several of the report’s other recommendations, however, require further action by the Congress and cannot be implemented unilaterally by the Biden Administration and, thus, the extent to which the Biden Administration will act upon the report’s recommendations cannot be predicted at this time. 25 Table of Contents Laws and regulations are subject to change, and the trend in the United States over the past decade has been for these governmental agencies to continue to evaluate and as necessary develop and implement new, more restrictive safety, permitting and performance requirements, although under the Trump Administration there were actions seeking to mitigate certain of those more rigorous standards. For example, in 2016, the BSEE under the Obama Administration published a final rule on well control that, among other things, imposed rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of Deepwater, high temperature, high pressure drilling activities, and enhanced reporting requirements. However, BSEE under the Trump Administration subsequently reconsidered the 2016 final rule and published final revisions to this rule that became effective in 2019 and, among other things, eliminated the requirement for a BSEE-approved verification organization for third parties providing certifications of certain critical well control functions. In another example, BSEE under the Obama Administration published a final rule in 2016 updating certain safety and pollution prevention equipment (e.g., subsea safety equipment, including blowout preventers) requirements for production safety equipment, including an obligation for independent third-party review and certification that safety and pollution prevention equipment is operational and functioning as designed in the most extreme conditions, but in 2018, BSEE amended this rule, rolling back a number of safety requirements including the third-party review and certification obligation. BSEE and/or BOEM under the Biden Administration may reconsider regulatory actions taken by the Trump Administration, with those agencies potentially seeking to adopt additional, more stringent safety, permitting and performance requirements. For example, in the federal government’s most recent list of potential regulatory actions for 2023, the DOI lists proposed rulemaking initiatives in respect to such matters as increased safety, environmental and equipment reliability protections under the pipeline and pipeline rights-of-way requirements for operating on the OCS and establishing a comprehensive program for identifying, prioritizing and managing risks associated with OCS lease and grant obligations. The DOI also lists forthcoming final rules in respect to such matters as revising certain blowout preventor systems and well control requirements for operating on the OCS. Compliance with Biden Administration legislative, executive and regulatory actions or any other legal initiatives that impact oil and natural gas exploration, development and production activities on the OCS could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. Our failure to comply with legal requirements under the OCSLA, our lease or applicable regulations may ultimately result in BOEM canceling one or more of our leases, which such cancellation could adversely affect our financial condition and operations. Furthermore, tropical storms and hurricanes in the U.S. Gulf of Mexico can have a significant impact on oil and natural gas operations. The effects from past hurricanes have included structural damage to fixed production facilities, semi-submersibles and jack-up drilling rigs. The BOEM and BSEE continue to be concerned about the loss of these facilities and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from future storms. In an effort to reduce the potential for future damage, the BOEM and the BSEE have periodically issued guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures. It is possible that similar, if not more stringent, requirements will be issued by the BOEM and the BSEE for future hurricane seasons. New requirements, if any, could increase our operating costs and/or capital expenditures. 26 Table of Contents In addition, in order to cover the various decommissioning obligations of lessees on the OCS, the 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. The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations and provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS. In 2016, the BOEM under the Obama Administration issued Notice to Lessees and Operators (“NTL”) #2016-N01 (“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”). However, the 2016 NTL was not fully implemented as the BOEM under the Trump Administration rescinded the NTL in 2020 and, in October 2020, pursued a proposed rule published jointly with the BSEE that sought to clarify and provide greater transparency to decommissioning and related financial assurance requirements imposed on oil and gas lessees (record title owners), sublessees (operating rights owners) and RUE and ROW grant holders conducting operations on the federal OCS. Although the notice of proposed rulemaking has not been formally withdrawn, consistent with recommendations made in the November 2021 DOI leasing report in response to President Biden’s January 2021 executive order, it is anticipated that the Biden Administration could pursue more stringent financial assurance requirements that could increase our operating costs. Additionally, in August 2021, the BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements currently applicable to all sole liability properties and now to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-life is fewer than five years, or with damaged infrastructure irrespective of the remaining property life of the surrounding producing assets. BOEM has stated it will prioritize non-sole liability properties where it believes that the current owner does not meet applicable requirements related to financial strength and has no co-owners or predecessors that are financially strong, as determined by BOEM. The future cost of compliance with respect to supplemental bonding, including the obligations imposed on us, whether as current or predecessor lessee or grant holder in respect of any new, more stringent, NTLs or final rules on supplemental bonding published by the BOEM under the Biden Administration, could materially and adversely affect 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 interest holder’s decommissioning liabilities. Regulation in Shallow Waters Off the Coast of Mexico — Our oil and gas operations in shallow waters off the coast of Mexico’s Tabasco state are subject to regulation by SENER, the CNH and other Mexican regulatory bodies. The CNH is responsible for, among other things, overseeing the tender procedures for awarding contracts for the exploration and production of oil and natural gas in Mexican waters, managing and supervising contracts that have been awarded, and approving exploration and production plans. The PSC that the Block 7 Consortium entered into for the development of this acreage contains terms that impose on us the duty to comply with various laws and regulations. These laws and regulations govern, among other things, the exploration and exploitation of hydrocarbons (including certain national content requirements), the treatment, conveyance, marketing, transport and storage of petroleum, and requirements for industrial safety, operational security, and facility decommissioning. Failure to comply can result in the imposition of monetary penalties, revocation of permits, rescission of the PSC, suspension of operations, and ordered decommissioning of offshore facilities and systems. The laws and regulations governing activities in the Mexican energy sector were significantly reformed in 2013, and the legal regulatory framework continues to evolve as SENER, the CNH and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore shallow waters. 27 Table of Contents Hydrocarbon Export Regulation in Mexico — Our oil and gas operations in shallow waters off the coast of Mexico’s Tabasco state are subject to regulation by SENER. Such regulations are subject to change, and it is possible that the Mexican National Agency of Industrial Safety and Environmental Protection of the Hydrocarbons Sector (“ASEA”) or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. For example, in December 2020, SENER published regulations affecting the granting of permits for the import and export of hydrocarbons. These regulations imposed additional constraints on permit applicants, and granted SENER more discretion in issuing, modifying, and revoking those permits. Previously, such permits would have had a term of 20 years – the December 2020 regulations limit terms to 5 years, restrict extensions and add new requirements. Subsequently, in May 2021, the Mexican government amended its federal Hydrocarbons Law in a manner that is anticipated to be beneficial to PEMEX, but have an adverse impact on privately-held oil and gas energy companies including by way of example, (i) authorizing SENER and the Mexican Energy Regulatory Commission (the “CRE”) to suspend or revoke hydrocarbon permits if there is imminent danger to national security, energy security or the national economy; (ii) allowing the government to temporarily occupy the facilities of hydrocarbon permit-holders to safeguard the national interest and hand over the operation of such facilities to State-owned entities, such as PEMEX; and (iii) allowing for denial by default of applications for new permits of private companies if the authorities do not respond within 90 days. Also in May 2021, the Mexican government made a second amendment to its Hydrocarbons Law, which such amendment halts the CRE’s power to enforce asymmetric regulation in the hydrocarbon, petroleum products and petrochemical markets, which regulation obligates PEMEX to comply with certain obligations that effectively limits its market position relative to its competitors. Amparo actions are being pursued in local courts in response to these legal changes and, as interim measures, court actions suspended the December 2020 regulations in March 2021, partially suspended portions of the first amendment to the Hydrocarbons Law (such suspension including the authorization to temporarily occupy facilities of permit-holders) in May 2021 and suspended the second amendment to the Hydrocarbons Law in May 2021. The suspension is to be appealed by SENER. Environmental and Occupational Safety and Health Regulations We are subject to various federal, state, local and foreign regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to, among other things: • assessing the environmental impact of seismic acquisition, drilling or construction activities; • the generation, storage, transportation and disposal of waste materials; • the emission of certain gases into the atmosphere; • the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations; • various environmental permitting requirements, such as permits for wastewater discharges; • the development of emergency response and spill contingency plans; • specific operating criteria addressing worker protection; and • protection of private and public surface and ground water supplies. Based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and it is possible such expenses will continue to increase in the future. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters, and the cost of compliance could be significant. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, natural resource damages or the issuance of injunctive relief (including orders to cease operations). Both onshore and offshore drilling in certain areas has been opposed by environmental groups and, in certain areas, has been restricted. Additionally, President Biden has made the combat of climate change arising from GHG emissions a priority under his administration. Some environmental laws and regulations may impose strict liability, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or third parties. To the extent laws are enacted or other governmental action is taken that prohibits or restricts onshore or offshore drilling or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and financial results could be adversely affected. 28 Table of Contents We expect to continue making expenditures on a regular basis relating to environmental compliance. We maintain insurance coverage for spills, pollution and certain other environmental risks, although we are not fully insured against all such risks. Our insurance coverage provides for the reimbursement to us of certain costs incurred for the containment and clean-up of materials that may be suddenly and accidentally released in the course of our operations, but such insurance does not fully insure against pollution and similar environmental risks. We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our consolidated financial position or our results of operations. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent under the Biden Administration including in respect of GHG emissions, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production. Water Discharges — Our discharges into waters of the United States are limited by the federal Clean Water Act, as amended (“CWA”), and analogous state laws. The CWA prohibits any discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States, except in compliance with permits issued by federal and state governmental agencies. These discharge permits also include monitoring and reporting obligations. Failure to comply with the CWA, including discharge limits set by permits issued pursuant to the CWA, may also result in administrative, civil or criminal enforcement actions. Violations of the CWA can result in suspension, debarment or the imposition of statutory disability, each of which prevents companies and individuals from participating in government contracts and receiving some non-procurement government benefits. The CWA also requires the preparation of oil spill response plans and spill prevention, control and countermeasure plans. Oil Pollution Act — The Oil Pollution Act of 1990, as amended (“OPA”), holds owners and operators of offshore oil production or handling facilities, including the lessee or permittee of the area where an offshore facility is located, strictly liable for the costs of removing oil discharged into waters of the United States and for certain damages from such spills. OPA assigns joint and several strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. OPA’s damages liability cap is currently $137.7 million; however, a party cannot take advantage of liability limits if a spill was caused by gross negligence or willful misconduct, resulted from violation of a federal safety, construction or operating regulation, or if the party failed to report a spill or cooperate fully in the clean-up. OPA also requires responsible parties to maintain evidence of financial responsibility in prescribed amounts. OPA currently requires a minimum financial responsibility demonstration of between $35 million to $150 million, based on a worst case oil spill discharge volume, for companies operating on the OCS, although the BOEM may increase this amount in certain situations, but in no event greater than $150 million. From time to time, the United States Congress has proposed, but not adopted, amendments to OPA raising the financial responsibility requirements. If OPA is amended to increase the minimum level of financial responsibility, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position. 29 Table of Contents National Environmental Policy Act — The National Environmental Policy Act, as amended (“NEPA”), requires federal agencies, including the DOI, to consider the impacts their actions have on the human environment, and to prepare detailed statements for major federal actions having the potential to significantly impact the environment. These requirements can lead to additional costs and delays in permitting for operators as the DOI or its bureaus may need to prepare Environmental Assessments (“EA”) and more detailed Environmental Impact Statements (“EIS”) in support of its leasing and other activities that have the potential to significantly affect the quality of the environment. If the EA indicates that no significant impact is likely, then the agency can release a finding of no significant impact and carry on with the proposed action. Otherwise, the agency must then conduct a full-scale EIS. In July 2020, the Council on Environmental Quality (“CEQ”) under former President Trump’s Administration published a final rule modifying the NEPA including, among other things, establishing a time limit of two years for preparation of EIS statements and one year for the preparation of EAs, and also eliminating the responsibility to consider cumulative effects of a project. While the July 2020 rule modifying NEPA remains subject to ongoing litigation in several federal district courts, the CEQ, now under the Biden Administration, announced in October 2021, that it intends to make three significant changes to the 2020 final rule, including authorizing agencies to consider direct, indirect and cumulative effects of major federal actions including upstream and downstream GHG emissions impacts of fossil fuel projects, allowing agencies to determine the purpose and need of a project, which allows consideration of less-harmful alternatives, and affording agencies greater flexibility in crafting their own NEPA procedures, consistent with CEQ regulations, so as to meet the agencies’ and public’s needs. To that end, in April 2022, the CEQ issued a final rule in line with the proposed changes, a move considered as “Phase I” of the Biden Administration’s two-phased approach to modifying the NEPA. “Phase 2” of this process includes the release of a new rule proposing the broader changes to the NEPA regulations. Additionally, in January 2023, the CEQ released guidance to assist federal agencies in assessing the GHG emissions and climate change effects of their proposed actions under NEPA. The CEQ’s interim guidance is effective immediately and encourages agencies to consider, among other things, effects from upstream and downstream GHG emissions of fossil fuel projects and, in many cases, use estimates of the social costs of GHGs when communicating those findings to the public. The NEPA process involves public input through comment. These comments, as well as the agency’s analysis of the proposed project, can result in changes to the nature of a proposed project, such as by limiting the scope of the project or requiring resource-specific mitigation. The adequacy of the agency’s NEPA process can be challenged in federal court by process participants. This process may result in delaying the permitting and development of projects, and result in increased costs. Endangered Species Act — The Endangered Species Act, as amended (“ESA”), restricts activities that may affect federally identified endangered and threatened species or their habitats. Additionally, the Migratory Bird Treaty Act, as amended (“MBTA”), implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. Under the MBTA, the taking, killing or possessing of migratory birds is unlawful without a permit. The U.S. Fish and Wildlife Service (“FWS”) under former President Trump issued a final rule on January 7, 2021, which notably clarifies that criminal liability under the MBTA will apply only to actions “directed at” migratory birds, its nests or its eggs; however, in October 2021, the FWS under the Biden Administration revoked the Trump Administration’s rule on incidental take and published an advanced notice of proposed rulemaking to codify a general prohibition on incidental take while establishing a process to regulate or permit exceptions to such a prohibition. A notice of proposed rulemaking is scheduled for release toward the end of the first quarter of 2023. The Marine Mammal Protection Act, as amended (“MMPA”), similarly prohibits the taking of marine mammals without authorization. Additionally, the FWS may make determinations on the listing of species as threatened or endangered under the ESA and litigation with respect to the listing or non-listing of certain species may result in more fulsome protections for non-protected or lesser-protected species. We conduct operations on oil and natural gas leases in areas where certain species that are protected by the ESA, MBTA and MMPA are known to exist and where other species that could potentially be protected under these statutes are known to exist. The FWS or the National Marine Fisheries Service may designate critical habitat that it believes is necessary for survival of a threatened or endangered species. A critical habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for oil and natural gas development. These statutes may result in operating restrictions or a temporary, seasonal or permanent ban in affected areas. 30 Table of Contents Hazardous Substances and Waste Management — The Resource Conservation and Recovery Act, as amended (“RCRA”), generally regulates the disposal of solid and hazardous wastes and imposes certain environmental cleanup obligations. Although RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy,” the EPA and state agencies may regulate these wastes as solid wastes. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any future loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in increased costs to manage and dispose of generated wastes. Also, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste. Comprehensive Environmental Response, Compensation and Liability Act — The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on persons that are considered to have contributed to the release of a “hazardous substance” into the environment. Such “responsible persons” may be subject to joint and several liability under CERCLA for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Further, it is not uncommon for coastal landowners or other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Air Emissions — The Clean Air Act, as amended (“CAA”), and comparable state statutes restrict the emission of air pollutants and affect both onshore and offshore oil and natural gas operations. New facilities may be required to obtain separate construction and operating permits before construction work can begin or operations may start, and existing facilities may be required to incur capital costs in order to remain in compliance. Also, the EPA has developed, and continues to develop, more stringent regulations governing emissions of toxic air pollutants and is considering the regulation of additional air pollutants and air pollutant parameters. For example, in 2015, the EPA under the Obama Administration issued a final rule under the CAA, making the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone more stringent. Since that time, the EPA has issued area designations with respect to ground-level ozone and, more recently, in December 2020, the EPA, under the Trump Administration, published a final action that, upon conducting a periodic review of the ozone standard in accord with CAA requirements, elected to retain the 2015 ozone NAAQS without revision on a going-forward basis. However, several groups filed litigation over this December 2020 decision, and, in October 2021, the EPA announced it would reconsider the decision with a target date of year end of 2023. A draft assessment released in April 2022 indicates EPA staff have reached a preliminary conclusion that the December 2020 decision will stand, but uncertainty remains until a final decision is released. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant. Worker Health and Safety — The Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties. 31 Table of Contents Climate Change — The threat of climate change continues to attract considerable public, governmental and scientific attention in the United States and in foreign countries. President Biden has made action on climate change a priority of his administration’s agenda and laws such as the IRA 2022 advance numerous climate-related objectives. Additionally, numerous proposals have been made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHG as well as to restrict or eliminate such future emissions. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG emissions reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, the EPA has adopted regulations under the existing CAA that, among other things, impose pre-construction and operating permit requirements on certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources and implement New Source Performance Standards directing the reduction of methane from certain new, modified or reconstructed facilities in the oil and natural gas sector. Compliance with these rules or others could result in increased compliance costs on our operations. In November 2021, the EPA issued a proposed rule that would make methane emissions from the crude oil and natural gas sources category more stringent, by establishing Quad Ob new source and Quad Oc first-time existing source standards of performance for methane and volatile organic compound emissions for new sources and existing sources in the crude oil and natural gas source category. The EPA published a supplemental proposal in November 2022 which, among other items, would impose expanded inspection, monitoring, and emissions controls requirements on oil and gas sites and strengthen emissions requirements related to equipment and routine flaring. The proposal is currently subject to public comment and is expected to be finalized in 2023. It is likely, however, that these regulatory actions will be subject to legal challenges, so we are unable to predict at this time the scope of any final regulatory requirements and the expected cost to comply with such requirements. Any increase in regulatory scope and oversight may increase compliance expenditure or mitigation costs for our operations. Additionally, state implementation of revised air emission standards could result in stricter permitting requirements, delay, limit or prohibit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant. At the international level, there exists the United Nations-sponsored “Paris Agreement,” which is a non-binding agreement among participating nations to limit their GHG emissions through individually-determined emissions reduction goals every five years after 2020. President Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. Moreover, the international community gathered again in Glasgow in November 2021 at the 26th Conference of the Parties (“COP26”), during which multiple announcements (not having the effect of law) were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO 2 GHGs. Relatedly, the United States and European Union jointly announced at COP26 the launch of a Global Methane Pledge, an initiative which over 100 countries joined, committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. In November 2022, the Government of the Arab Republic of Egypt hosted the 27th session of the Conference of the Parties (“COP27”). At COP27 in Sharm El-Sheik, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The United States also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity gas. Although no firm commitment or timeline to phase out or phase down all fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, COP27, or other international conventions cannot be predicted at this time and it is unclear what additional initiatives may be adopted or implemented that may have a negative impact on our financial condition. 32 Table of Contents Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing federal political risk regarding climate change. In the United States, President Biden has issued several executive orders calling for more expansive action to address climate change and limit new oil and gas operations on federal lands and waters. See Part I, Items 1 and 2. Business and Properties – Government Regulation – Outer Continental Shelf (“OCS”) Regulation for more information. Other actions that could be pursued by the Biden Administration include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more stringent emissions standards for oil and gas facilities. Additionally, the IRA 2022 was signed into law in August 2022, and contains hundreds of billions of dollars in incentives for the development of renewable energy, clean fuels, electric vehicles and supporting infrastructure, and carbon capture and sequestration, among other provisions. These incentives could further accelerate the transition of the United States’ economy away from the use of fossil fuels toward lower- or zero-carbon emissions alternatives. The IRA 2022 also imposes the first ever federal fee on the emissions of GHGs through a methane emissions charge. Litigation risks are also increasing, as a number of cities, local governments and other plaintiffs have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts. We are not currently a defendant in any of these lawsuits but 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. Additionally, our access to capital may be impacted by climate change policies. Stockholders and bondholders currently invested in fossil fuel energy companies such as ours, but concerned about the potential effects of climate change, may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices that favor “clean” power sources, such as wind and solar, making those sources more attractive, and some of them may elect not to provide funding for fossil fuel energy companies. Many of the largest U.S. banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. At COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. These and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding to fossil fuel energy companies. In late 2020, the Federal Reserve announced that it had joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector, and, in September 2022, announced that six of the U.S.’ largest banks will participate in a pilot climate scenario analysis exercise to enhance the ability of firms and supervisors to measure and manage climate-related financial risk. The Federal Reserve released its pilot exercise in January 2023 which is designed to analyze the impact of both physical and transition risks related to climate change on specific assets of the banks’ portfolios. While we cannot predict what policies may result from these announcements, a material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could impact our business and operations. Separately, the SEC released a proposed rule in March 2022 that would establish a framework for the reporting of climate risks, targets and metrics. A final rule is anticipated to be released in the second quarter of 2023. Although the final form and substance of this rule and its requirements are not yet known, and the ultimate impact on our business is uncertain, the proposed rule, if finalized, may result in increased compliance costs, increased costs of and restrictions on access to capital. The SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege that an issuer’s existing climate disclosures are misleading or deficient. These agency actions could increase the potential for litigation. 33 Table of Contents Finally, some scientists have concluded that increasing concentrations of GHG emissions 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 extreme climatic events, as well as chronic shifts in temperature and precipitation patterns. Our offshore operations are particularly at risk from severe climatic events, which have the potential to cause physical damage to our assets and thus could have an adverse effect on our exploration and production operations. Additionally, changing meteorological conditions, particularly temperature, may result in changes to the amount, timing, or location of demand for energy or the products we produce. While our consideration of changing weather conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality. Environmental Regulation in Shallow Waters Off the Coast of Mexico — Our oil and gas operations in shallow waters off the coast of Mexico’s Tabasco state are subject to regulation by the ASEA. We must obtain ASEA-issued permits and comply with ASEA regulations governing hydrocarbon activities, including requirements for environmental impact and risk assessments, industrial safety, waste management, water and air emissions, operational security and facility decommissioning. Failure to comply with applicable laws and regulations can result in the imposition of monetary penalties, revocation of permits, suspension of operations and ordered decommissioning of offshore facilities and systems. The laws and regulations governing the protection of health, safety and the environment from activities in the Mexican energy sector are relatively new, having been significantly reformed following the establishment of ASEA in 2014 as a result of federal constitutional amendments approved in 2013, and the legal regulatory framework continues to evolve as ASEA and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that ASEA or other Mexican regulatory bodies may impose new or revised requirements that could increase our environmental compliance-related operating costs and/or capital expenditures for operations in Mexican offshore shallow waters. For example, in May 2020, the ASEA published the Industrial Safety, Operational Safety and Environmental Protection Guidelines for the Closing, Dismantling and Abandonment of Hydrocarbons Sector Facilities (the “Dismantling Guidelines”). The Dismantling Guidelines are mandatory for all hydrocarbon sector facilities that perform dismantling, abandonment and closing of hydrocarbon sector activities. The Dismantling Guidelines set out several obligations in terms of safety, reporting and risk, including establishing a closing, dismantling and/or abandonment activities program for each of the relevant phases. Additionally, during the fourth quarter of 2021, ASEA announced its implementation of a “Popular Denunciation System” that will utilize an internet-based platform to allow persons, organizations and companies to anonymously report complaints against entities and companies operating in Mexico, including in respect of safety and environmental incidents such as, for example, hydrocarbon spills and pollution events. We anticipate that ASEA will conduct investigations to substantiate the incidents identified in the new reporting system. Under the Block 7 PSC, we are jointly and severally liable for the performance of all obligations under the PSC, including exploration, appraisal, extraction and abandonment activities and compliance with all environmental regulations, and failure to perform such obligations could result in contractual rescission of the PSC. Federal Regulation of Sales and Transportation of Natural Gas — Our sales of natural gas are affected directly or indirectly by the availability, terms and cost of natural gas transportation. The prices and terms for access to pipeline transportation of natural gas are subject to extensive federal and state regulation. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”) and by regulations and orders promulgated under the NGA and/or NGPA by the Federal Energy Regulatory Commission (“FERC”). In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the United States Congress and by FERC regulations. However, certain offshore gathering and transportation services we rely upon are subject to limited FERC regulation and are regulated by the states. 34 Table of Contents Pursuant to authority delegated to it by the Energy Policy Act of 2005 (“EPAct 2005”), FERC promulgated anti-manipulation regulations establishing violation enforcement mechanisms that make it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of FERC to (i) use or employ any device, scheme or artifice to defraud, (ii) make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading or (iii) engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any entity. The EPAct 2005 also amended the NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes and regulations, up to $1,388,496 per violation, per day for 2021 (this amount is adjusted annually for inflation). FERC may also order disgorgement of profits and corrective action. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which includes annual reporting requirements for entities that purchase or sell a certain volume of natural gas in a given calendar year. We believe, however, that neither the EPAct 2005 nor the regulations promulgated by FERC as a result of the EPAct 2005 will affect us in a way that materially differs from the way they affect other natural gas producers, gatherers and marketers with which we compete. Our sales of oil and natural gas are also subject to market manipulation and anti-disruptive requirements under the Commodity Exchange Act (“CEA”) as amended by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), and regulations promulgated thereunder by the U.S. Commodity Futures Trading Commission (the “CFTC”). The CFTC prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. The current statutory and regulatory framework governing interstate natural gas transactions is subject to change in the future, and the nature of such changes is impossible to predict. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by the United States Congress, the applicable federal agencies, or the various state legislatures, and what effect, if any, the proposals might have on our operations. The natural gas industry historically has been very heavily regulated. In the past, the federal government regulated the prices at which natural gas could be sold. Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. However, we are subject to reporting requirements imposed by FERC. There is always some risk, however, that the United States Congress may reenact price controls in the future. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines or impose additional reporting or other requirements upon our operations, and we cannot predict what future action FERC will take. Therefore, there is no assurance that the current regulatory approach recently pursued by FERC and the United States Congress will continue. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete. Federal Regulation of Sales and Transportation of Crude Oil — FERC regulates the interstate pipeline of crude oil, petroleum products and other liquids, such as NGLs. Our sales of crude oil and condensate are currently not regulated and are made at negotiated prices. There is always some risk, however, that the United States Congress may reenact crude oil, petroleum products and NGL price controls in the future. We cannot predict whether new legislation to regulate crude oil, or the prices charged for crude oil might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting requirements. 35 Table of Contents Our ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act (“ICA”), and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. Certain regulations implemented by FERC in recent years and certain pending rulemaking and other proceedings could result in an increase in the cost of transportation service on certain petroleum products pipelines. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other crude oil and condensate producers with which we compete. Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to other crude oil and condensate producers with which we compete. We have an undivided interest in a pipeline owned by CKB Petroleum, Inc. that is subject to FERC jurisdiction under the ICA, but FERC has granted us a temporary waiver of the filing and reporting requirements. This pipeline is still subject to FERC’s jurisdiction under the ICA and is still subject to the other requirements of the ICA. If the facts upon which the waiver was granted change materially, we are required to inform FERC, which may result in revocation of the waiver. If conditions change such that the pipeline no longer qualifies for a waiver, we may be subject to regulation by FERC of the rates, terms and conditions of service on the CKB Petroleum, Inc. pipeline; however, these burdens generally would not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar pipelines. FERC also implements the OCSLA pertaining to transportation and pipeline issues, which requires that all pipelines operating on or across the OCS provide nondiscriminatory transportation service. We own and operate pipelines that are located in the OCS and are subject to the non-discrimination requirements in the OCSLA. Human Capital Our employees are our most valuable asset and are a key factor in our success. We strive to provide a work environment that attracts and retains top talent, reflects our core values, and fosters an innovative and collaborative culture. In 2022, we finalized and established our Talos Energy Culture Roadmap with five defined pillars to shape the employee experience with purpose. The five key principles define our culture and represent a shared set of values, goals, attitudes, and practices that make up our organization – Think as an Owner, Embody Integrity & Safety, Maintain Optionality, Empower Each Other, and Embrace Diversity & Inclusion. Our human capital measures and objectives focus on several areas, including, but not limited to human rights, diversity and inclusion, assuring the safety of our employees, employee recruitment and development and offering a fulsome array of employee health and welfare benefits. We are focused on developing a diverse team of qualified employees and creating an inclusive workplace culture. While we may reference certain policies and other documents in these disclosures, these are primarily to identify the existence of such policies. They are not, and should not be deemed to be, incorporated into this Annual Report or any of our other SEC filings. As of December 31, 2022, we employ approximately 436 people located primarily in Texas, Louisiana and Mexico, 216 of whom are employed in offshore operations. In addition, we supplement our workforce with contractors and consultants. While headcount does not significantly fluctuate throughout the year, in order to align our workforce with the pace of our business, headcount might increase or decrease in response to various factors, including acquisition activity, unscheduled shut-ins or a change in our capital program. None of our employees are represented by labor unions or covered by any collective bargaining agreement. 36 Table of Contents Safety — At Talos, safety is defined as freedom from unacceptable risk of harm and an empowered workforce promoting a safety-first culture across our operations. Safety in every aspect of our business is our number one priority and is core to our Health, Safety, Environment, and Sustainability operational culture. We drive this culture by being fully transparent in our reporting of safety and ESG matters to our Board of Directors and stakeholders on a regular basis, including our continual collaboration with the BSEE and the United States Coast Guard. The scope and oversight of the Board’s Safety, Sustainability & Corporate Responsibility Committee includes ESG and corporate responsibility matters. We rigorously train our employees to conduct operations in accordance with our strict safety standards and encourage employees to immediately report any breach of safety protocol to their supervisor or our compliance hotline. Our employees are empowered and obligated by our Chief Executive Officer to exercise the Stop Work Authority (“SWA”). With SWA, our employees can call an immediate stop to any work for any safety concern without fear of retaliation or intimidation. Conducting regular safety training allows us to proactively address the dynamic nature of offshore operational risk and promote a robust culture of offshore safety. Our employees and permanently assigned contractors complete custom designed in-house trainings through our eLearning platform and role appropriate hands-on training upon hiring and as part of a continuous development program. Employees are engaged in biweekly field safety meetings directly with senior management to discuss safety culture and ESG initiatives. Employees and contractors conduct emergency response training drills on each facility at least once per hitch allowing our employees to always be ready in case of an emergency situation. After any serious incident we conduct thorough incident investigations and communicate a lessons learned report and any changes to our safety policies to all offshore employees. Safety performance is an element of each employee’s performance review and 10% of the value of the 2022 short-term incentive award pool was based upon our achievement of safety goals. Additionally, our offshore employees are eligible to receive a quarterly safety bonus, the value of which is contingent upon the number of safety or environmental incidents of non-compliance recorded at the employee’s facility location during the quarter. Finally, many of our offshore employees participate in our ESG sub-committees so they can have a voice in corporate-level decisions about ESG matters. Our ESG efforts strive to continually improve our safety and environmental performance and our employees help determine the responsible path forward. Human Rights — We remain committed to upholding human rights across every segment of our business. Our Code of Business Conduct and Ethics, which applies to all of our directors, officers and other employees of the Company, and our Vendor Code of Conduct work in tandem to establish our commitment to human rights as a fundamental part of our responsibilities as a company. Our policy also addresses areas of potential concern including respecting employees’ rights to all types of associations without fear of discrimination, employees’ right to be paid a living wage, the prohibition of forced labor, prevention of human trafficking and child labor. In 2021, we published our Talos Human Rights Policy to further strengthen our commitment to safeguard human rights. Indigenous Rights — While our operations are predominantly offshore, we nonetheless strive to embody a commitment to respect the rights of indigenous people. We are committed to completing all operations in compliance with applicable national laws and treaties. We recognize the importance of respecting indigenous people and communities. Diversity and Inclusion — We believe that creating a work environment where employees feel welcome, supported and valued results in increased employee engagement and reduced turnover. In order to achieve these goals, we carefully observe all applicable laws and have adopted and actively enforce policies in our Employee Handbook and Code of Business Conduct and Ethics that ensure equal employment opportunities for all and prohibit harassment and discrimination of any kind. Our Code of Business Conduct and Ethics requires adherence to the highest standards of personal integrity and assures the protection of human rights. We have a compliance hotline so that employees can report any violation of these policies anonymously if they wish. We know that a diverse workforce brings expanded creativity, stronger problem-solving skills and leads to better decision-making and enhanced performance. Our Code of Business Conduct and Ethics requires that our directors, officers and employees treat each of our employees with the same high level of respect regardless of such employee’s age, color, disability, ethnicity, family or marital status, gender identity or expression, language, national origin, physical and mental ability, political affiliation, race, religion, sexual orientation, socio-economic status, veteran status or other characteristics that make such employee unique. As reflected in our Code of Business Conduct and Ethics, we are committed to working in partnership with vendors and other business partners directly linked to our operations that share our commitment to these same principles. 37 Table of Contents Recruitment, Development and Training — We foster an entrepreneurial culture where open communication is encouraged, the views of our employees are heard, and the results of their efforts are recognized. This is one of the reasons why every year since our inception, we have earned a ranking as a Top Workplace on the Houston Chronicle Top Workplaces list. We operate an inclusive and dynamic recruiting process that utilizes online recruiting platforms, referrals, internships and professional recruiters. We foster the growth and professional development of our employees through robust performance review process, which includes the creation of performance development goals and plans to achieve those goals in order to help our employees reach their full potential. In 2022, we launched the Leadership Development Program available to all employees to help build more dynamic and engaged leaders. We also offer in-house training, eLearning through our Learning Management System, reimbursement of the costs of outside training, and tuition reimbursement to support our employees’ pursuit of higher education at accredited institutions in further support of developing our employees. We believe this emphasis on development and training has contributed to our low 6.6% voluntary turnover rate for 2022. Health and Welfare Benefits — We work to retain employees by offering competitive wages and generous benefits that are designed to meet the varied and evolving needs of a diverse workforce. We provide employees with the ability to participate in health and welfare plans, including medical, dental, life, accidental death and dismemberment and short-term and long-term disability insurance plans. In addition, we offer extended comprehensive benefits that include 401(k) match, confidential support through the Employee Assistant Program, subsidy for gym memberships, paid time off and leaves of absence, as well as a Work From Home program launched at the end of 2021. Community & Social Engagement — We are committed to supporting and giving back to the communities in which we operate and live. We recognize the link between local communities, the success of our employees, and ultimately the success of our business. To take a more proactive role in community support, our Community Committee, comprised of our employees, engages directly in outreach, fundraising, education and awareness. We regularly host volunteer and fundraising events supporting non-profit organizations in our communities, annually provide a $500 allowance to every employee that can be applied in support of a non-profit of their choice, match funds raised by the Community Committee's fundraising efforts for charitable organizations, and provide employees with a paid volunteer day off to support an organization where they want to donate their time. Available Information We make our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, all amendments to those reports, and all other information filed with or furnished to the SEC available, free of charge, through our website, https://www.talosenergy.com, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. The filings are also available by accessing the SEC’s website at https://www.sec.gov. We voluntarily publish annual sustainability reports which are available free of charge on our corporate website at: https://www.talosenergy.com/sustainability/. Information included in these sustainability reports is not incorporated into this Annual Report or in any other report or document we file with the SEC. 38 Table of Contents Item 1A. Ri sk Factors Certain factors may have a material adverse effect on our business, financial condition, and results of operations. You should consider carefully the risks and uncertainties described below, in addition to other information contained in this Annual Report, including our Consolidated Financial Statements and related notes. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we currently believe are not material, may also become important factors that adversely affect our business. If any of the following risks actually occur, our business, financial condition, results of operations and future prospects could be materially and adversely affected. In that event, the trading price of our common stock could decline, and you could lose part or all of your investment. Risks Related to our Business and the Oil and Natural Gas Industry Oil and natural gas prices are volatile. Stagnation or declines in commodity prices 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. 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 economically produce. A reduction in production and/or the prices we receive for our production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth. The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. For example, during the period January 1, 2020 through December 31, 2022, the daily NYMEX WTI crude oil price per Bbl ranged from a low of $(36.98) to a high of $123.64, and the daily NYMEX Henry Hub natural gas price per MMBtu ranged from a low of $1.33 to a high of $23.86. Subsequent to December 31, 2022, NYMEX WTI crude oil and NYMEX Henry Hub natural gas prices recorded daily lows of $72.82 per Bbl and $2.17 per MMBtu, respectively. The prices we receive for our oil and natural gas depend 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 climatic conditions; • the impact of applicable market differentials, including those relating to quality, transportation, fees, energy content and regional pricing; • domestic and foreign governmental actions, 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; • Russia’s ongoing war in Ukraine and resulting sanctions in response thereto; 39 Table of Contents • the occurrence or threat of epidemic or pandemic diseases, such as the outbreak of COVID-19, or any government response to such occurrence or threat; • actions by OPEC Plus 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; • capacity of processing, gathering, storage and transportation facilities; • 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. Because oil, natural gas and NGLs accounted for approximately 65%, 26%, and 9%, respectively, of our estimated proved reserves as of December 31, 2022, and approximately 67%, 25%, and 8%, respectively, of our 2022 production on an MBoe basis, our financial results are sensitive to movements in oil, natural gas and NGL prices. 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 U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico. Unlike other entities that are geographically diversified, we may not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. Our lack of diversification may subject us to numerous economic, competitive and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate, and result in our dependency upon a single or limited number of hydrocarbon basins. In addition, the geographic concentration of our properties in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico means that some or all of our properties could be affected should the region experience: • severe weather, such as hurricanes, winter storms, tornadoes and other adverse climatic conditions; • delays or decreases in production or 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 P&A costs) and interruption or termination of operations by governmental authorities based on environmental, safety or other considerations; • changes in the regulatory environment such as the guidelines issued by the BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the OCS; and/or 40 Table of Contents • changes imposed as a result of litigation or by a new Presidential Administration or by Congress in the United States that may result in added restrictions and delays or prohibitions in offshore oil and natural gas exploration and production activities, including with respect to leasing, permitting, site development or operation in federal waters or hydraulic fracturing. 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. Production periods or relatively short reserve lives for U.S. 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. Substantially all of our operations are in the U.S. Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and natural 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 further lower 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. See Items 1 and 2. Business and Properties— Summary of Reserves for further discussion on 2022 changes in estimates of our proved reserves. 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, 2022 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 legislation, regulations or taxation; • volume, pricing and duration of our oil and natural gas hedging contracts; 41 Table of Contents • 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 natural gas industry in general. At December 31, 2022, approximately 17% of our estimated proved reserves (by volume) were undeveloped and approximately 21% were non-producing. Any or all of our PUD or proved developed non-producing reserves may not be ultimately developed or produced. Furthermore, any or all of our undeveloped and developed non-producing reserves may not be ultimately produced during the time periods we plan or at the costs we budget, which could result in the write-off of previously recognized reserves. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling or waterflood 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. Our acreage has to be drilled before lease expirations 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. Our drilling plans for areas not held by production are subject to change based upon various factors. As of December 31, 2022, approximately 51% of our net acreage was undeveloped acres. See Items 1 and 2. Business and Properties— Acreage for further discussion. 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 acreages. 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 change dramatically, the financial impact could be substantial. The availability of markets and the volatility of product prices are beyond our control and represent a significant risk. 42 Table of Contents 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 natural gas properties. Under the full cost method of accounting, our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. A write-down of oil and natural 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 natural 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. With respect to our operations in Mexico, our oil and natural gas properties are classified as unproved properties, not subject to amortization. The finalization of the unitization and unit operating agreement, which sets out the terms on which the reservoir will be jointly developed, and the outcome of the dispute with the Government of Mexico over decisions taken by SENER with respect to the Zama discovery, could adversely affect the value of the oil and natural gas assets and result in an impairment of our unevaluated oil and gas properties prior to reaching a final investment decision or of our evaluated properties upon reaching a final investment decision. See Part I, Items 1 and 2. Business and Properties — Upstream Properties — Mexico — Block 7 . Continuing or worsening inflationary issues and associated changes in monetary policy may result in increases to the cost of our goods, services and personnel, which in turn could cause our capital expenditures and operating costs to rise. The U.S. inflation rate has been steadily increasing since 2021 and into 2022. These inflationary pressures have resulted in and may result in additional increases to the costs of our goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve (the “Fed”) and other central banks to increase interest rates multiple times in 2022 and the Fed has indicated its intention to continue to raise benchmark interest rates into 2023 in an effort to curb inflationary pressure on the costs of goods and services across the U.S., which could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt the financial and operating results of our business. To the extent elevated inflation remains, we may experience further cost increases for our operations, including services, labor costs and equipment if our drilling activity increases. Higher crude oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation, and a significant increase in inflation, to the extent we are unable to recover higher costs through higher crude oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations. We may be unable to pursue our CCS business, either wholly or in significant measure, which could have a material adverse effect on our business, results of operations and financial condition. Our CCS business strategy envisions the construction and operation of one or more CCS projects within the next two to three years, utilizing anthropogenic CO 2 generated by industrial emitters along the Texas and Louisiana Gulf Coast. See Part I, Items 1 and 2. Business and Properties – Carbon Capture & Sequestration for the four CCS projects that are actively being evaluated. Our goal is that CCS projects, such as these four, will eventually enable us to offset some or all our annual net CO 2 emissions while delivering an economic return. However, the successful development of such projects is dependent on various economic, regulatory and operational factors, and any failure to satisfy, wholly or in significant measure, any of such factors could have a material adverse impact on our business, results of operations and financial condition. 43 Table of Contents Another emerging financial incentive for CCS projects may be the approximately $1.2 trillion infrastructure bill signed by President Biden in November 2021, which includes a provision for approximately $2.5 billion to expand the U.S. Department of Energy’s Carbon Storage Validation and Testing program to include large-scale commercialization of new or expanded carbon sequestration projects and CO 2 transport infrastructure. However, the applicability of the financial incentives in the infrastructure bill to our projects is uncertain at this time and there is no assurance that we would qualify for such incentives in the pursuit of our CCS projects or that such incentives would be adequate for our CCS project needs. Additionally, successful development of CCS projects in the United States requires that we comply with what we anticipate will be a stringent regulatory scheme requiring that we obtain certain permits applicable to subsurface injection of CO 2 for geologic sequestration. Moreover, as operator of our CCS projects, we must demonstrate and maintain levels of financial assurance sufficient to cover the cost of corrective action, injection well plugging, post injection site care and site closure, and emergency and remedial response. As CCS and carbon management represent an emerging sector, regulations may evolve rapidly, which could impact the feasibility of one or more of our anticipated projects. There is no assurance that we will be successful in obtaining permits or adequate levels of financial assurance for one or more of our CCS projects or that permits can be obtained on a timely basis, whether due to difficulty with the technical demonstrations required to obtain such permits, public opposition or otherwise. Separately, permitting CCS projects also requires obtaining a number of other permits and approvals unrelated to subsurface injection from various U.S. federal and state agencies, such as for air emissions or impacts to environmental, natural, historic or cultural resources resulting from the construction and operation of a CCS facility. To the extent regulatory requirements are imposed, are amended or more stringently enforced, we may incur additional costs in the pursuit of one or more of our CCS projects, which costs may be material or may render any one or more of our CCS projects uneconomical. Development of successful CCS projects will also require satisfying certain operational factors, such as locating a suitable source of anthropogenic CO 2 and reaching suitable agreements to capture that CO 2 . Such agreements are complex and may involve allocation of not only fees but also various credits, incentives and environmental attributes associated with the sequestration of CO 2 . Not all emission sources produce sufficiently large quantities of pure or relatively pure streams of CO 2 , or have installed equipment to capture such CO 2 , so as to be usable in one or more of our CCS projects. As a result, we cannot assure whether we will be able to obtain sufficient quantities of CO 2 from emitters on terms that are acceptable to us, and the failure to do so may have a material impact on our ability to execute our CCS strategy. Additionally, development of successful CCS projects will require infrastructure to transport CO 2 between the source and our CCS sites. In project areas with existing CO 2 transportation pipelines, this may require reaching an agreement on CO 2 transportation with operators of CO 2 pipelines within the regions in which we operate. Inability to reach a suitable agreement may render a project uneconomical or impracticable. Separately, if no CO 2 pipelines exist in proposed project areas, or if existing pipelines do not extend to one or more of our project sites, we may be required to convert existing pipelines, or build new CO 2 pipelines or lateral connections, which may be subject to various environmental and other permitting requirements as well as third party easements, which may render one or more projects uneconomical. We will also need to build the required equipment on a timely basis and at a cost that is economically viable. Additionally, complex recordkeeping and GHG emissions/sequestration accounting may be required in connection with one or more of our projects, which may increase the costs of such operations. Different methodologies may be required for various regulatory and non-regulatory accounts regarding GHG emissions/sequestration at one or more of our projects, including but not limited to, compliance with the EPA’s mandatory Greenhouse Gas Reporting Program. Furthermore, as CCS may be viewed as a pathway to the continued use of fossil fuels, notwithstanding that CO 2 emissions are intended to be captured, there may be organized opposition to CCS, including as it relates to our projects. In consideration of the above matters, we anticipate, but can provide no assurance, that we will be able to execute upon our CCS business strategy in the future. Any failure by us to achieve such expectations in whole or any significant measure could have a material adverse effect on our business, results of operations and financial condition. 44 Table of Contents Our inability to qualify for, obtain, monetize or otherwise benefit from Section 45Q tax credits could materially reduce our ability to develop CCS projects and, as a result, may adversely impact our business, results of operations and financial condition. The successful development of our CCS projects is dependent upon our ability to benefit from certain financial and tax incentives available with respect to CCS projects. The development of CCS projects is incentivized by tax credits provided under Section 45Q of the Internal Revenue Code of 1986, as amended (such credits, “Section 45Q tax credits”), which provides a tax credit for qualified CO 2 that is captured using carbon capture equipment and disposed of in secure geological storage. The amount of Section 45Q tax credits from which we may benefit is dependent upon our ability to satisfy certain wage and apprenticeship requirements, which we cannot assure you that we will satisfy. With respect to the first five tax years a qualifying CCS project is in service, but not beyond December 31, 2032, we may elect a “direct pay” option with respect to available Section 45Q tax credits to efficiently monetize their value (i.e., we may receive a payment for the tax credits through a tax refund as if there had been an overpayment of taxes). Following the period in which the direct pay election is available and for the remaining period in which the applicable Section 45Q tax credits are otherwise available, we may elect to transfer the Section 45Q tax credits to unrelated taxpayers. We cannot assure you that we will be able to efficiently monetize Section 45Q tax credits that are transferred to unrelated taxpayers. We will benefit from Section 45Q tax credits only if we satisfy the applicable statutory and regulatory requirements for obtaining the Section 45Q tax credits, including that we own carbon capture equipment that captures qualified CO 2 that we physically or contractually capture and securely store, or if another party that owns carbon capture equipment elects to pass through Section 45Q tax credits to us, that we dispose of the qualified CO 2 in secure storage. If we are unable to satisfy such statutory and regulatory requirements or otherwise qualify for or obtain the Section 45Q tax credits, our CCS projects may no longer be economically viable and may not be completed. We cannot assure you that we will be successful in satisfying such requirements or otherwise qualifying for or obtaining the Section 45Q tax credits currently available or that we will be able to effectively benefit from such tax credits. Section 45Q tax credits are also subject to recapture with respect to any CO 2 that ceases to be disposed of in secure storage, which recapture is treated as an increase in tax liability for the year in which the recapture occurs. The recapture period for Section 45Q tax credits is limited to a 3-year lookback period preceding the date that sequestered CO 2 escapes from its secure storage. Additionally, the availability of Section 45Q tax credits may be reduced, modified or eliminated as a matter of legislative or regulatory policy. There can be no assurance that Section 45Q tax credits will not be reduced, modified or eliminated in the future. Any such reduction, modification or elimination of Section 45Q tax credits, or our inability to otherwise benefit from Section 45Q tax credits, could materially reduce our ability to develop CCS projects and, as a result, may adversely impact our business, results of operations and financial condition. Even if we are able to benefit from Section 45Q tax credits, we may determine that additional financial incentives are required for our CCS projects to be economically viable. If such additional incentives do not emerge, we may not be able to achieve an economic return from our CCS business or, alternatively, the construction or operation of our CCS projects may be substantially delayed, unprofitable or otherwise infeasible. 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. 45 Table of Contents 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. Events outside of our control, including an epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business. We face risks related to epidemics, outbreaks or other public health events that are outside of our control, and could significantly disrupt our operations and adversely affect our financial condition. The global or national outbreak of an illness or other communicable disease, or any other public health crisis, such as COVID-19, may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors or subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by government and health authorities, including quarantines, to address an outbreak and (v) restrictions that we and our contractors, subcontractors and our customers impose, including facility shutdowns, to ensure the safety of employees. In addition, the effects of COVID-19 and concerns regarding its global spread could negatively impact the domestic and international demand for crude oil and natural gas, which could contribute to price volatility, impact the price we receive for oil and natural gas and materially and adversely affect the demand for and marketability of our production. The potential impact from COVID-19, both now and in the future, is difficult to predict, and the extent to which it may negatively affect our operating results or the duration of any potential business disruption is uncertain. Any potential impact will depend on future developments and new information that may emerge regarding the COVID-19 infection rate or the efficacy and distribution of COVID-19 vaccines, and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control. These potential impacts, while uncertain, could adversely affect our operating results. The ongoing war between Russia and Ukraine could adversely affect our business, financial condition and results of operations. On February 24, 2022, Russian military forces invaded Ukraine, and sustained war and disruption in the region is likely. Although the length, impact and outcome of the ongoing military war in Ukraine is highly unpredictable, this war could lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability, changes in consumer or purchaser preferences as well as increases in cyberattacks and espionage. Russia’s recognition of two separatist republics in the Donetsk and Luhansk regions of Ukraine and subsequent military action against Ukraine have led to an unprecedented expansion of sanction programs imposed by the U.S., the European Union, the United Kingdom, Canada, Switzerland, Japan and other countries against Russia, Belarus, the Crimea Region of Ukraine, the so-called Donetsk People’s Republic and the so-called Luhansk People’s Republic, including, among others: • blocking sanctions against some of the largest state-owned and private Russian financial institutions (and their subsequent removal from the Society for Worldwide Interbank Financial Telecommunication payment system) and certain Russian businesses, some of which have significant financial and trade ties to the European Union; • blocking sanctions against Russian and Belarusian individuals, including the Russian President, other politicians and those with government connections or involved in Russian military activities; and • blocking of Russia’s foreign currency reserves as well as expansion of sectoral sanctions and export and trade restrictions, limitations on investments and access to capital markets and bans on various Russian imports. 46 Table of Contents In retaliation against new international sanctions and as part of measures to stabilize and support the volatile Russian financial and currency markets, the Russian authorities also imposed significant currency control measures aimed at restricting the outflow of foreign currency and capital from Russia, imposed various restrictions on transacting with non-Russian parties, banned exports of various products and other economic and financial restrictions. The situation is rapidly evolving as a result of the war in Ukraine, and the U.S., the European Union, the United Kingdom and other countries may implement additional sanctions, export controls or other measures against Russia, Belarus and other countries, regions, officials, individuals or industries in the respective territories. Such sanctions and other measures, as well as the existing and potential further responses from Russia or other countries to such sanctions, tensions and military actions, could adversely affect the global economy and financial markets and could adversely affect our business, financial condition and results of operations. We are actively monitoring the situation in Ukraine and assessing its impact on our business, including our business partners and customers. To date we have not experienced any material interruptions in our infrastructure, supplies, technology systems or networks needed to support our operations. We have no way to predict the progress or outcome of the war in Ukraine or its impacts in Ukraine, Russia or Belarus as the war, and any resulting government reactions, are rapidly developing and beyond our control. Continued hostilities, or any significant increases in the extent and duration of the military action, sanctions and resulting market disruptions — or any meaningful escalation in the objectives thereof or the methods used by the combatants to achieve such objectives —could be significant and could potentially have substantial impact on the global economy and our business for an unknown period of time. Alternatively, a cessation of hostilities as a result of a negotiated withdrawal or otherwise—particularly if coupled with an easing of international sanctions — could cause commodity prices to decline in a manner that would reduce the revenues we receive for our oil and gas production. During the first quarter of 2022, we experienced an increase in commodity prices as sanctions imposed on Russia severely limited the access of Russian oil and gas producers to international markets. In the months that followed, commodity prices subsequently decreased and remained stagnant during the second half of 2022. If the military action concludes and the related sanctions are dropped, commodity prices could significantly decrease. Any of the abovementioned factors could affect our business, financial condition and results of operations. 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. For example, in March 2022, the final UR from SENER regarding the development of the Zama Field in offshore Mexico, affirmed the appointment of PEMEX as operator of the unit, despite our discovery of the Zama Field in 2017 and subsequent operatorship. 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; 47 Table of Contents • 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 failure 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. 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 NGLs, we periodically enter into oil, natural gas and NGLs price hedging arrangements with respect to a portion of our expected production. 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. 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. 48 Table of Contents O ur operations may incur substantial liabilities to comply with environmental laws and regulations as well as legal requirements applicable to marine mammals and endangered and threatened species. Our oil and natural gas operations in the United States and Mexico are subject to stringent federal, state and/or local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations require the acquisition of a permit or other approval before drilling or other regulated activity commences; restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities; limit or prohibit exploration or drilling activities on certain lands lying within protected areas or that may affect certain wildlife, including marine species and endangered and threatened species and impose substantial liabilities for pollution resulting from our operations. Additionally, the threat of climate change continues to attract considerable attention in the United States and in foreign countries and the combat of climate change has been made a focal point of the Biden Administration's agenda. See Part I, Items 1 and 2. Business and Properties — Government Regulation — Environmental and Occupational Safety and Health Regulations for more discussion on environmental and worker safety matters. One or more of these developments that impact our oil and natural gas exploration and production activities on the OCS could have a material adverse effect on our business, results of operations and financial condition. Additional drilling laws, regulations, executive orders and other regulatory initiatives that restrict, delay or prohibit oil and natural gas exploration, development and production activities or access to locations where such activities may occur could have a material adverse effect on our business, financial condition or results of operations. The Biden Administration has taken a number of actions that may result in stricter environmental, health and safety standards applicable to our operations and those of the oil and gas industry more generally. The Biden Administration issued the “Executive Order on Tackling the Climate Crisis at Home and Abroad” on January 27, 2021 (the “Climate Change Executive Order”). This executive order directed the Secretary of the Interior to halt indefinitely new oil and natural gas leases on federal lands and offshore waters pending completion of a review by the Secretary of the Interior of federal oil and gas permitting and leasing practices in light of the Biden Administration’s concerns regarding the impact of these activities on the environment and climate. The Secretary of the Interior completed its review of permitting and leasing practices in November 2021 and issued a report recommending, among other things, an increase in royalty rates and financial assurance requirements. However, litigation concerning the Climate Change Executive Order’s pause on new oil and gas leases is ongoing. In June 2021, the U.S. District Court for the Western District of Louisiana issued a nationwide preliminary injunction barring the Biden Administration from implementing the pause in new federal oil and gas leases, an injunction which was made permanent in August 2022. This effectively halts implementation of the leasing suspension with respect to those lease sales canceled or postponed prior to March 24, 2021. In November 2021, the Biden Administration conducted an offshore lease sale and various industry participants submitted bids for leases in the Gulf of Mexico; however, on January 27, 2022, in litigation brought by Friends of the Earth and other plaintiffs, the U.S. District Court for the District of Columbia vacated the November 2021 lease sale and the related agency decision making process, finding that the BOEM failed to consider the impact on foreign greenhouse gas emissions if the November 2021 lease sale was not held and the court determined that this failure was a violation of the NEPA. In September 2022, BOEM announced that it was reinstating the lease results in line with congressional direction in the IRA 2022. In addition, there is increasing uncertainty regarding the near-term future of Gulf of Mexico lease sales. These lease sales are conducted pursuant to Five-Year Leasing Programs under the Outer Continental Shelf Lands Act. The most recent Five-Year Leasing Program expired on June 30, 2022 and on July 1, 2022, BOEM released a proposed program for 2023 through 2028. The proposed program, which was subject to public comment through October 6, 2022, proposes no more than ten potential lease sales in the Gulf of Mexico. However, until a final program decision is made and approved—which can take two to three years to complete—no new Gulf of Mexico lease sales can be held. Consequently, it is uncertain whether a new Five-Year Leasing Program will be finalized and subsequent lease sales will be conducted during the current Biden Administration. Additionally, the new Five-Year Leasing Program will likely be subject to heightened environmental review. It is also possible that the program could be delayed if opponents of offshore oil and gas production initiate lawsuits challenging BOEM’s actions. Future actions taken by the Biden Administration to limit the availability of new oil and gas leases on the OCS would adversely impact the offshore oil and gas industry and impact demand for our products. 49 Table of Contents Over the past decade, BSEE and BOEM, primarily under the Obama Administration, have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. While actions by BSEE or BOEM under the Trump Administration sought to mitigate or delay certain of those more rigorous standards, the Biden Administration could reconsider rules and regulatory initiatives implemented under the previous administration and replace them with more stringent requirements and also provide more rigorous enforcement of existing regulatory requirements. Compliance with any added or more stringent regulatory requirements or enforcement initiatives and 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 could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. Moreover, governmental agencies under the Biden Administration may continue evaluating aspects of safety and operational performance in the U. S. Gulf of Mexico that may result in new, more restrictive requirements. These regulatory actions, or any new laws, executive orders, regulations or other legal or enforcement initiatives, that impose increased costs or more stringent operational standards could delay or disrupt our operations, result in increased supplemental bonding and associated costs, and limit activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities or result in suspension or cancellation of leases. 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 and production operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations. See Part I, Items 1 and 2. Business and Properties — Government Regulation — OCS Regulation for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry on the OCS. We may be unable to provide the financial assurances in the amounts and under the time periods required by the BOEM if it submits future demands to cover our decommissioning obligations. If in the future the BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore leases. 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 2016, the BOEM under the Obama Administration had sought to implement more stringent and costly standards under the existing federal financial assurance requirements through issuance and implementation of the 2016 NTL, but former President Trump’s Administration first suspended, and then in 2020 rescinded, the implementation of this NTL. Consistent with recommendations made in a November 2021 DOI report on the federal oil and gas leasing program, the Biden Administration could pursue more stringent financial assurance requirements that could increase our operating costs. Following the effectiveness of the 2016 NTL, we received orders from the BOEM in late 2016 directing us to provide additional financial assurance in material amounts relating to our OCS properties. We entered into discussions with the BOEM regarding the requested additional financial security and submitted a proposed tailored plan (applicable to our sole and non-sole liability properties) for the posting of additional financial security to the agency for review. However, as the Trump Administration rescinded the 2016 NTL, the BOEM withdrew the previously issued orders under the 2016 NTL. In August 2021, the BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements currently applicable to all sole liability properties and now to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-life is fewer than five years, or with damaged infrastructure irrespective of the remaining property life of the surrounding producing assets. BOEM has stated it will prioritize non-sole liability properties where it believes that the current owner does not meet applicable requirements related to financial strength and has no co-owners or predecessors that are financially strong, as determined by BOEM. In connection with this Note to Stakeholders, BOEM initially assessed the required financial assurance for our sole liability properties as approximately $70 million. However, following the opportunity to review BOEM’s sole liability assessment, we were able to reduce the financial assurance required to approximately $37.7 million. The bonds covering this amount were posted in 2021. 50 Table of Contents Notwithstanding the above, the BOEM, now under the Biden Administration, could, in the future, continue to make new demands for additional financial assurances in material amounts relating to the decommissioning of our OCS properties. The BOEM may reject our proposals to satisfy any such additional financial assurance coverage and make demands that exceed our capabilities. If we fail to comply with the current or future orders of 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 the event that the BOEM issues a new NTL or proposes and finalizes new regulations similar to or more stringent than the 2016 NTL, the likely result could include the loss of supplemental bonding waivers for a large number of operators on the OCS, which could in turn force these operators to seek additional surety bonds and could, consequently, challenge the surety bond market’s capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety companies may have about the priority of their lien on the operator’s collateral. Moreover, a depressed oil price environment could result in sureties seeking additional collateral to support existing bonds, such as cash or letters of credit, and we cannot provide assurance that we will be able to satisfy collateral demands for future bonds to comply with supplemental bonding requirements of the 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 the 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. Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local governmental regulations that materially affect our operations. Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions. Regulated matters include: permits for exploration, development and production operations; limitations on our drilling activities in environmentally sensitive areas, such as marine habitats, and restrictions on the way we can discharge materials and/or GHG emissions into the environment; bonds or other financial responsibility requirements to cover drilling contingencies, well P&A and other decommissioning costs; reports concerning operations, the spacing of wells and unitization and pooling of properties; regulations regarding the rate, terms and conditions of transportation service or the price, terms, and conditions related to the purchase and sale of oil and natural gas; and taxation. Failure to comply with these laws and regulations can result in the assessment of administrative, civil or criminal penalties, the issuance of remedial obligations and the imposition of injunctions limiting or prohibiting certain of our operations. In addition, because we hold federal leases, the federal government requires that we comply with numerous additional regulations applicable to government contractors. The SENER 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, specifically relating to Block 7 offshore Mexico. In July 2021, SENER designated PEMEX as operator of the Zama unit, just three days after SENER received a letter directly from PEMEX arguing for operatorship. Under Mexico’s own unitization guidelines, SENER was required to “consider the principles of economy, competitiveness, efficiency, legality, transparency, best practices of industry and the best use of hydrocarbons.” In September 2021, we submitted Notices of Dispute to the Government of Mexico relating to the decision taken by SENER. Our aim is to resolve the dispute amicably through consultations and negotiations to achieve a fair and mutually beneficial agreement; however, the outcome of these Notices of Dispute could be adverse to us and affect the value that we are able to recognize from the reservoir discovery. 51 Table of Contents If we are forced to shut-in production, we will likely incur greater costs to bring the associated production back online, and will be unable to predict the production levels of such wells once brought back online. If we are forced to shut-in production, we will likely incur greater costs to bring the associated production back online. Cost increases necessary to bring the associated wells back online may be significant enough that such wells would become uneconomic at low commodity price levels, which may lead to decreases in our proved reserve estimates and potential impairments and associated charges to our earnings. If we are able to bring wells back online, there is no assurance that such wells will be as productive following recommencement as they were prior to being shut-in. Any shut-in or curtailment of the oil, natural gas and NGLs produced from our fields could adversely affect our financial condition and results of operations. 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. President Andrés Manuel López Obrador was elected to a six-year term, took office on December 1, 2018, and his political party, Movimiento Regeneración Nacional has 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. We may experience significant shut-ins and losses of production due to the effects of tropical storms and hurricanes in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico. Our production is primarily associated with our properties in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue. We are particularly vulnerable to significant risk from hurricanes and tropical storms in the U.S. 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. We are not insured against all of the operating risks to which our business is exposed. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational loss-related events. We have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, named U.S. Gulf of Mexico windstorm, oil pollution, construction all risk, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that have to be met prior to recovery, as well as sub-limits or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences, damages or losses. See Part I, Items 1 and 2. Business and Properties – Insurance Matters for more information on our insurance coverage. 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. 52 Table of Contents We reevaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations in the U.S. 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. SEC rules could limit our ability to book additional PUD reserves in the future. SEC rules require that, subject to limited exceptions, PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement may limit our ability to book additional PUD reserves as we pursue our drilling program. Moreover, we may be required to write down our PUD reserves if we do not drill those wells within the required five-year timeframe. Our 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, adverse resolutions to disputes relating to operatorships (such as that observed with the Zama Field dispute) 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 U.S. Gulf of Mexico Deepwater and/or in the Gulf Coast deep shelf, our drilling activities increase 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 holes and wells that are productive but do not produce sufficient cash flows to recoup drilling costs. Our industry experiences numerous operating risks. The exploration, development and production of oil and gas properties involves a variety of operating risks, including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. We are also involved in completion operations that utilize hydraulic fracturing, which may potentially present additional operational and environmental risks. Additionally, our offshore operations are subject to the additional hazards of marine operations, such as capsizing, collisions and adverse weather and sea conditions, including the effects of hurricanes. 53 Table of Contents 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 Deepwater fields and may attempt to pursue additional operational activity in the future and acquire additional fields and leases in the Deepwaters of the U.S. Gulf of Mexico. Exploration for oil or natural gas in the Deepwaters of the U.S. Gulf of Mexico generally involves greater operational and financial risks than exploration in the shallower waters of the U.S. 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 in the shallower waters of the U.S. 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. 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 U.S. 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 the 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 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. 54 Table of Contents 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, Valero Energy Corporation and Chevron Products 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. 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 U.S. 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. We have operations in multiple jurisdictions, including jurisdictions in which the tax laws, their interpretation or their administration may change. As a result, our tax obligations and related filings are complex and subject to change, and our after-tax profitability could be lower than anticipated. Additionally, future tax legislative or regulatory changes in the United States, Mexico or any other jurisdiction in which we operate or have subsidiaries could result in changes to the taxation of our income and operations, which could also adversely impact our after-tax profitability. We are subject to income, withholding and other taxes in the United States on a worldwide basis and in numerous state, local and foreign jurisdictions with respect to our income, operations and subsidiaries in those jurisdictions. Our after-tax profitability could be affected by numerous factors, including the availability of tax credits, exemptions, refunds (including refunds of value added taxes) and other benefits to reduce our tax liabilities, changes in the relative amount of our earnings subject to tax in the various jurisdictions in which we operate or have subsidiaries, the potential expansion of our business into or otherwise becoming subject to tax in additional jurisdictions, changes to our existing business structure and operations, the extent of our intercompany transactions and the extent to which taxing authorities in the relevant jurisdictions respect those intercompany transactions. 55 Table of Contents Our after-tax profitability may also be affected by changes in the relevant tax laws and tax rates, regulations, administrative practices and principles, judicial decisions, and interpretations, in each case, possibly with retroactive effect. From time to time, federal and state level legislation in the United States has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently available to oil and natural gas exploration and development companies. Such proposed legislative changes have included, but have not been limited to, (i) the elimination of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies, and (v) an increase in the U.S. federal income tax rate applicable to corporations (such as us). U.S. states in which we operate or own assets may also impose new or increased taxes or fees on oil and natural gas extraction. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, the Multilateral Convention to Implement Tax Treaty Related Measures to Prevent Base Erosion and Profit Shifting (the “Multilateral Instrument”) has entered into force among the jurisdictions that have ratified it, although the United States has not yet become a signatory to the Multilateral Instrument. Such proposed legislative changes and ratification of the Multilateral Instrument in the jurisdictions in which we operate could result in further changes to our global taxation. Additionally, Mexico has enacted tax reform legislation, and a majority of the provisions became effective on January 1, 2020. These tax reforms provided for new and complex provisions that significantly change how Mexico tax entities and operations and are subject to further legislative change and administrative guidance and interpretation, which may differ from our interpretation. Future tax legislative or regulatory changes in the United States, Mexico or in any other jurisdictions in which we operate now or in the future could also adversely impact our after-tax profitability. A significant portion of our production, revenue and cash flow is concentrated in our Phoenix Field and our Pompano Field. Because of this concentration, any production problems, impacts of adverse weather or inaccuracies in reserve estimates could have a material adverse impact on our business. For the year ended December 31, 2022, approximately 21% and 18% of our production and 23% and 19% of our total revenue was attributable to our Phoenix Field and our Pompano Field, respectively, both of which are located in the federal waters offshore in the U.S. Gulf of Mexico. This concentration in these fields means that any impact on our production from these fields, whether because of mechanical problems, adverse weather, well containment activities, changes in the regulatory environment or otherwise, could have a material effect on our business. We produce the Phoenix Field through the HP-I, a dynamically positioned floating production facility that is operated by 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. During the year ended December 31, 2022, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-September 2022, resulting in a total shut-in period of 41 days. The shut-in resulted in deferred production of 1.6 MBoepd during the year ended December 31, 2022 based on production rates prior to the shut-in. 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. 56 Table of Contents In addition, all of our production from the Phoenix Field flows through the Green Canyon 19 connection facility operated by Shell GOM Pipeline Company LLC. To the extent Shell GOM Pipeline Company LLC temporarily shuts in its Green Canyon 19 connection facility, whether for maintenance or otherwise, we would not be 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. In addition, all of our production from the Pompano Field flows through the Pompano Pipeline System operated by Crimson Gulf LLC. To the extent Crimson Gulf LLC temporarily shuts in the Pompano Pipeline System, whether for maintenance or otherwise, we would not be able to produce the Pompano Field during this period of time, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. If the actual reserves associated with the Pompano Field are less than our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial condition, results of operations and cash flows. Our Mexican operations are subject to certain offshore regulatory and environmental laws and regulations promulgated by Mexico. Our oil and gas operations in shallow waters off the coast of Mexico’s Tabasco state are subject to regulation by the SENER, the CNH and other Mexican regulatory bodies. The laws and regulations governing activities in the Mexican energy sector have undergone significant reformation over the past decade, and the legal regulatory framework continues to evolve as SENER, the CNH and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. See Part I, Items 1 and 2. Business and Properties – Government Regulation – Regulation in Shallow Waters Off the Coast of Mexico and Part I, Items 1 and 2. Business and Properties – Government Regulation – Hydrocarbon Export Regulation in Mexico for additional disclosure relating to the legal requirements imposed by SENER, CNH or other Mexican regulatory bodies to which we may be subject in the pursuit of our operations. In addition, our oil and gas operations in shallow waters off the coast of Mexico’s Tabasco state are subject to regulation by the ASEA. The laws and regulations governing the protection of health, safety and the environment from activities in the Mexican energy sector are also relatively new, having been significantly reformed in 2013 and 2014, and the legal regulatory framework continues to evolve as ASEA and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that ASEA or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. See Part I, Items 1 and 2. Business and Properties – Environmental and Occupational Safety and Health Regulations – Environmental Regulation in Shallow Waters Off the Coast of Mexico for additional disclosure relating to the legal requirements imposed by ASEA or other Mexican regulatory bodies to which we may be subject in the pursuit of our operations. The permit holders must comply with requirements relating to insurance, facility construction and design, law compliance, and risk analysis scenarios. Under the Block 7 PSC, we are also jointly and severally liable for the performance of all obligations under the PSC, including exploration, appraisal, extraction and abandonment activities and compliance with all environmental regulations, and failure to perform such obligations could result in contractual rescission of the PSC. Three-dimensional seismic interpretation does not guarantee that hydrocarbons are present or if present, produce 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. 57 Table of Contents 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 Block 7 PSC with the CNH, we work as a consortium with our partners. 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 PSC if these violations occur. 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. Our operations are subject to various risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur and reduce demand for the crude oil and natural gas that we produce. Climate change continues to attract considerable public, political and scientific attention. In the United States, no comprehensive climate change legislation has been adopted at the federal level, but President Biden has indicated that action to address climate change is an important part of his administration’s agenda. For example, in August 2022, the IRA 2022 passed which advances numerous climate-related objectives. Numerous other executive actions and legislative and regulatory initiatives have been made or are likely to be considered by his administration and analogous legal actions are likely to be made or considered at the state, regional or international levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. These regulatory efforts have included consideration of cap-and-trade programs, carbon taxes, GHG emissions reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. Additionally, the threat of climate change has resulted in increasing political, litigation and financial risks associated with the production of fossil fuels and emissions of GHGs. Moreover, climate change activism calling for reduced access to capital, fuel conservation measures, governmental initiatives for renewable energy resources, increasing consumer demand for alternative forms of energy, technological advances in fuel economy and energy generation devices may create new competitive conditions that result in reduced demand for the oil and natural gas we produce. Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events. See Part I, Items 1 and 2. Business and Properties – Environmental and Occupational Safety and Health Regulations – Climate Change for additional disclosure relating to risks arising out of the threat of climate change. 58 Table of Contents The adoption of legislation or regulatory programs to reduce or eliminate future emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce or eliminate future emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Also, political, financial and litigation risks may result in our restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes or impairing the ability to continue to operate in an economic manner. Further, if any such effects of climate changes were to occur, they could have an adverse effect on our financial condition and results of operations. Increasing attention to ESG matters may impact our business. Increasing attention to climate change, societal expectations on companies to address climate change, and potential consumer use of substitutes to oil and gas commodities may result in increased costs, reduced demand for our products and our services and the products and services of our customers, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change, for example, may result in demand shifts for the hydrocarbon products we produce as well as additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. The Board of Directors’ Safety, Sustainability and Corporate Responsibility Committee is the primary committee of our Board of Directors responsible for overseeing and managing our ESG initiatives. Committee members are expected to meet quarterly to review the implementation and effectiveness of our ESG programs and policies. In 2022, we hired a Director of ESG who is responsible for driving our sustainability initiatives, engaging with stakeholders, benchmarking our ESG data, and evaluating potential and emerging ESG drivers. Additionally, we have set the following aspirational goals to help strengthen our ESG performance: (i) a 30% reduction in GHG emissions intensity by 2025 with a stretch goal of 40%, as compared to our 2018 GHG emissions intensity baseline; and (ii) increased to 20% the ESG metrics component of our management’s annual incentive plan, which includes key initiatives aimed at GHG emissions reduction and health and safety performance. We note, however, that our ESG governance structure may not be able to adequately identify or manage ESG-related risks and opportunities, which may include failing to achieve our GHG emissions intensity reduction or other ESG-related aspirational goals, including but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such goals. Moreover, given the evolving nature of GHG emissions accounting methodologies and climate science, it is possible that factors outside of our control could give rise to the need to restate or revise our emissions intensity reduction goals, cause us to miss them altogether, or limit the impact of success of achieving our goals. Additionally, to the extent we meet such targets, they may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. However, we cannot guarantee that there will be sufficient offsets available for purchase given the increased demand from numerous businesses implementing net zero goals, or that the offsets we do purchase will successfully achieve the emissions reductions they represent. 59 Table of Contents In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. We and other companies in our industry publish sustainability reports that are made available to investors. Such ratings and reports are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and to the diversion of investment to other industries which could have a negative impact on our stock price and/or our access to and costs of capital. Additionally, certain institutional lenders may decide not to provide funding to us based on ESG concerns, which could adversely affect our financial condition and access to capital for potential growth projects. To the extent ESG matters negatively impact our reputation, we may also be unable to compete as effectively to recruit or retain employees, which may adversely affect our operations. Furthermore, public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. Certain non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG statements, goals or standards were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risk from private parties and governmental authorities related to our ESG efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Additionally, we could face increasing costs as we attempt to comply with and navigate further regulatory ESG-related focus and scrutiny. 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 Act, enacted on July 21, 2010, expanded federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC and the SEC have finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this is accomplished. 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 continue 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 continue to qualify for, and to utilize, the end-user exception from such margin requirements for swaps to be entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the regulations are fully implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we may encounter or reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations implementing the Dodd-Frank Act, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations. 60 Table of Contents 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. Negative publicity may adversely impact us. Media coverage and public statements that insinuate improper actions by us, regardless of their factual accuracy or truthfulness, may result in negative publicity, litigation or governmental investigations by regulators. For example, in September 2021, we experienced negative publicity relating to an oil release in the U.S. Gulf of Mexico, off the coast of Port Fourchon, Louisiana. Although we were a prior lessee of the block in question, had ceased production in the area in 2017 and had removed all pipeline infrastructure by 2019, the resulting publicity may have had a negative impact on us. Similar or further such negative publicity in the future relating to U.S. Gulf of Mexico operations generally, or our operations specifically, may expose us to adverse consequences. Addressing negative publicity and any resulting litigation or investigations may distract management, increase costs and divert resources. Negative publicity may have an adverse impact on our reputation and the morale of our employees, which could materially adversely affect our business, financial position, results of operations, cash flows, growth prospects and stock price. A change in the jurisdictional characterization of our FERC-jurisdictional pipelines, tribal or local regulatory agencies or a change in policy by those agencies may result in increased regulation of such asset, which may cause our revenues to decline and operating expenses to increase or delay or increase the cost of expansion projects. With respect to CKB Petroleum, Inc., which has been granted a waiver of certain portions of the ICA and related regulations by the FERC, should the pipeline’s circumstances change, the FERC could, either at the request of other entities or on its own initiative, assert that such pipeline no longer qualifies for a waiver. In the event that the FERC were to determine that CKB Petroleum, Inc. no longer qualified for a waiver, we would likely be required to file a tariff with the FERC, provide a cost justification for the transportation charge and provide service to all potential shippers without undue discrimination. Such a change in the jurisdictional status of transportation on the CKB Petroleum, Inc. pipeline could adversely affect our results of operations. The Inflation Reduction Act of 2022 could accelerate the transition to a low carbon economy and could impose new costs on our operations. In August 2022, President Biden signed the IRA 2022 into law. The IRA 2022 contains hundreds of billions in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. In addition, the IRA 2022 imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge. The IRA 2022 amends the federal CAA to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production categories. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022. In addition, the multiple incentives offered for various clean energy industries referenced above could further accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives. This could decrease demand for crude oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business. Risks Related to our Capital Structure and Ownership of our Common Stock 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 12.00% Second-Priority 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; 61 Table of Contents • 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 12.00% Second-Priority Senior Secured Notes due January 2026 (the “12.00% Notes”) of Talos Production Inc. (the “Issuer”), 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, changes in our business and the industry in which we operate; • detracting from our ability to successfully withstand a downturn in our business or the economy generally; • placing us at a competitive disadvantage against 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. 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 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. 62 Table of Contents We may not have sufficient funds to make such repayments. If we do not repay our debt out of cash on hand, we could attempt to restructure or refinance such debt, reduce or delay investments and capital expenditures, sell assets, or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flows from operating activities to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets are available to pay or refinance such debt. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our debt, including our Bank Credit Facility and the indenture for our 12.00% Notes, may also prohibit us from taking such actions. Factors that affect our ability to raise cash through offerings of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offerings, refinancing or sale of assets. We cannot assure you that any such offerings, restructuring, refinancing or sale of assets would be successfully completed. A financial crisis may impact our business and financial condition and may adversely impact our ability to obtain funding under our Bank Credit Facility or in the capital markets. We use our cash flows from operating activities and borrowings under our Bank Credit Facility to fund our capital expenditures, and we rely on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. As such, we may not be able to access adequate funding under our Bank Credit Facility as a result of (i) a decrease in our borrowing base due to the outcome of a borrowing base redetermination or a breach or default under our Bank Credit Facility, including a breach of a financial covenant or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. We may also face limitations on our ability to access the debt and equity capital markets and complete asset sales, increased counterparty credit risk on our derivatives contracts and requirements by our contractual counterparties to post collateral guaranteeing performance. In addition, from time to time, we could be required to, or we or our affiliates may seek to, retire or purchase our outstanding debt through cash purchases and/or exchanges for equity or debt, open-market purchases, privately negotiated transactions or other transactions. Such debt repurchase or exchange transactions, if any, will be upon such terms and at such prices as we may determine and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. Such transactions may give rise to taxable cancellation of indebtedness income (to the extent the fair market value of the property exchanged, or the amount of cash paid to acquire the outstanding debt, is less than the adjusted issue price of the outstanding debt) and adversely impact our ability to deduct interest expenses in respect of our debt against our taxable income in the future. This could result in a current or future tax liability, which could adversely affect our financial condition and cash flows. We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures. We spend a substantial amount of capital for the acquisition, exploration, exploitation, development, and production of oil and natural gas reserves. We fund our capital expenditures primarily through operating cash flows, cash on hand and borrowings under our Bank Credit Facility, if necessary. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil and natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment and regulatory, technological and competitive developments. A further reduction in commodity prices may result in a further decrease in our actual capital expenditures, which would negatively impact our ability to grow production. Our cash flow from operations and access to capital is subject to a number of variables, including: • our proved reserves; • the level of hydrocarbons we are able to produce from our wells; • the prices at which our production is sold; • our ability to acquire, locate and produce new reserves; and • our ability to borrow under our Bank Credit Facility. 63 Table of Contents 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, and continues to be, significantly limited. We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production Inc. Accordingly, we are dependent upon distributions from Talos Production Inc. to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock. We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production Inc. We have no independent means of generating revenue. To the extent Talos Production Inc. has available cash, we will cause Talos Production Inc. to make distributions of cash to us, directly and indirectly through our wholly owned subsidiaries, to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock. As we have never declared or paid any cash dividends on our common stock, we anticipate that any available cash, other than the cash distributed to us to pay taxes and cover our corporate and other overhead expenses, will be retained by Talos Production Inc. to satisfy its operational and other cash needs. Accordingly, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. Although we do not expect to pay dividends on our common stock, if our board of directors decides to do so in the future, our ability to do so may be limited to the extent Talos Production Inc. is limited in its ability to make distributions to us, including the significant restrictions the agreements governing Talos Production Inc.’s debt impose on the ability of Talos Production Inc. to make distributions and other payments to us. To the extent that we need funds and Talos Production Inc. is restricted from making such distributions under applicable law or regulation or under the terms of our financing agreements, or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt — Restrictions Which Limit the Payment of Dividends for additional information. 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 U.S. 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 U.S. 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. 64 Table of Contents We have divested, as assignor, various leases, wells and facilities located in the U.S. Gulf of Mexico where the purchasers, as assignees, typically assume all abandonment obligations acquired. Certain of these counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations. Under certain circumstances, regulations or federal laws such as the OCSLA could impose joint and several strict liability and require predecessor assignors, such as us, to assume such obligations. As of December 31, 2022, we have accrued $42.1 million and $12.2 million in obligations reflected as “Other current liabilities” and “Other long-term liabilities”, respectively, on the Consolidated Balance Sheets. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies and Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies for more information. 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 U.S. 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 particular, this risk arises in the context of the EnVen Acquisition, which closed on February 13, 2023. See “—Risks Related to our Integration of EnVen into our Business—The failure to successfully integrate our business and operations with EnVen in the expected time frame may adversely affect our future results.” 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 P&A liabilities. We expect that future acquisitions will contribute to our growth. In connection with potential future acquisitions, we may only be able to perform limited due diligence. 65 Table of Contents Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental, regulatory and other liabilities, including P&A liabilities. Such assessments are inexact and may not disclose all material issues or liabilities. In connection with our assessments, we perform a review of the acquired properties. However, such a review may not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We may be successful in obtaining contractual indemnification for preclosing liabilities, including environmental liabilities, but we expect that we will generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. In addition, even if we are able to obtain such indemnification from the sellers, these indemnification obligations usually expire over time and could potentially expose us to unindemnified liabilities, which could materially adversely affect our production, revenues and results of operations. 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. The corporate opportunity provisions in our Second Amended and Restated Certificate of Incorporation could enable others to benefit from corporate opportunities that might not otherwise be available to us. Subject to the limitations of applicable law, our Second Amended and Restated Certificate of Incorporation, 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 our officers or directors who are also officers, directors, employees, managing directors, or other affiliate of a Principal Stockholder (as defined in the Second Amended and Restated Certificate of Incorporation) 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 any of our officers or directors who is also an officer, director, employee, managing director or other affiliate of the Principal Stockholders 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. Any of our directors may vote upon any contract or any other transaction between us and any affiliated corporation without regard to the fact that such person is also a director or officer of such affiliated corporation. These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of others. 66 Table of Contents Our Second Amended and Restated Certificate of Incorporation designates the Court of Chancery of the State of Delaware and, to the extent enforceable, the federal district courts of the United States of America 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 Second Amended and Restated Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (i) any derivative action or proceeding brought on our or our stockholders’ behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our current or former directors, officers, employees, agents and stockholders to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL, our Second Amended and Restated Certificate of Incorporation or our Second Amended and Restated Bylaws, (iv) any action as to which the DGCL confers jurisdiction to the Court of Chancery of the State of Delaware, or (v) any other action asserting a claim that is governed by the internal affairs doctrine shall be the Court of Chancery of the State of Delaware. Our Second Amended and Restated Certificate of Incorporation also provides that, to the fullest extent permitted by applicable law, the federal district courts of the U.S. are the exclusive forum for resolving any complaint asserting a cause of action arising under the Securities Act, subject to and contingent upon a final adjudication in the State of Delaware of the enforceability of such exclusive forum provision. Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts with respect to suits brought to enforce a duty or liability created by the Securities Act or the rules and regulations thereunder. Accordingly, both state and federal courts have jurisdiction to entertain claims under the Securities Act. Notwithstanding the foregoing, the exclusive forum provision does not apply to suits brought to enforce any liability or duty created by the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Any person or entity purchasing or otherwise acquiring an interest in any shares of our capital stock shall be deemed to have notice of and to have consented to the forum provisions in our Second Amended and Restated Certificate of Incorporation. These choice-of-forum provisions may limit a stockholder’s ability to bring a claim in a judicial forum that he, she or it believes to be favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits. Alternatively, if a court were to find these provisions of our Second Amended and Restated Certificate of Incorporation inapplicable or unenforceable with respect to one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could materially adversely affect our business, financial condition and results of operations and result in a diversion of the time and resources of our management and board of directors. While the Delaware courts have determined that choice of forum provisions of this type are facially valid, uncertainty exists as to whether a court would enforce such provision, and as such, a stockholder may nevertheless seek to bring a claim in a venue other than those designated in our exclusive forum provision. In such instance, to the extent applicable, we would expect to vigorously assert the validity and enforceability of our exclusive forum provision. This may require additional costs associated with resolving such action in other jurisdictions and there can be no assurance that the provisions will be enforced by a court in those other jurisdictions. Future sales, or the perception of future sales, by us or our existing stockholders in the public market following the EnVen Acquisition could cause the market price for our common stock to decline. The sale of substantial amounts of shares of our common stock in the public market, or the perception that such sales could occur, could harm the prevailing market price of shares of our common stock. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. Certain holders of our common stock, including certain significant stockholders of EnVen, are entitled to rights with respect to registration of approximately 34.3 million shares of our common stock (representing approximately 27.1% of the outstanding shares of our common stock) under the Securities Act pursuant to certain registration rights agreements. If these holders of our common stock, by exercising their registration rights, sell a large number of shares, they could adversely affect the market price for our common stock. 67 Table of Contents Risks Related to our Integration of EnVen Into our Business The combined company may fail to realize the anticipated benefits of the EnVen Acquisition. The ultimate success of the EnVen Acquisition will depend on, among other things, our ability to combine each of Talos’s and EnVen’s businesses in a manner that realizes anticipated synergies and benefits and meets or exceeds the forecasted stand-alone cost savings anticipated by the combined company. We anticipate that we will benefit from significant synergies, based on, among other things, increased scale. If we are not able to successfully achieve these synergies, or the cost to achieve these synergies is greater than expected, then the anticipated benefits of the EnVen Acquisition may not be realized fully or at all or may take longer to realize than expected. The failure to successfully integrate our business and operations with EnVen in the expected time frame may adversely affect our future results. It is possible that the integration process of our business with EnVen’s could result in the loss of key employees, customers, providers, vendors or business partners, the disruption of either company’s or both companies’ ongoing businesses, inconsistencies in standards, controls, procedures and policies, potential unknown liabilities and unforeseen expenses, delays, or regulatory conditions or higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated. Specifically, the following issues, among others, must be addressed in integrating the operations in order to realize the anticipated benefits of the EnVen Acquisition: • combining the companies’ operations and corporate functions and the resulting difficulties associated with managing a larger, more complex, integrated business; • combining our business with EnVen in a manner that permits the combined company to achieve any cost savings or operating synergies anticipated to result from the EnVen Acquisition; • reducing additional and unforeseen expenses such that integration costs are not more than anticipated; • minimizing the loss of key employees; • identifying and eliminating redundant functions and assets; • maintaining existing agreements with customers, providers and vendors or business partners and avoiding delays in entering into new agreements with prospective customers, providers and vendors or business partners; and • consolidating the companies’ operating, administrative and information technology infrastructure. In addition, at times the attention of certain members of our management and resources may be focused on the integration of the businesses of the two companies and diverted from day-to-day business operations or other opportunities that may have been beneficial to us, which may disrupt our ongoing business. Item 1B. Un resolved Staff Comments None. Item 3. Legal Proc eedings We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition. On March 23, 2022, the Company entered into a settlement agreement to receive $27.5 million to resolve previously pending litigation, which was filed on October 23, 2017, against a third-party supplier related to quality issues. As part of the settlement agreement, the Company released all of its claims in the litigation. On May 29, 2020, a lawsuit was filed in the Court of Chancery asserting derivative and class action claims against us relating to the ILX and Castex Acquisition. Specifically, the lawsuit relates to the fairness of the consideration paid for such acquisitions in light of the fact that certain of the sellers are our affiliates. The lawsuit was dismissed during the third quarter of 2021, and the plaintiffs have appealed the dismissal to the Delaware Supreme Court. 68 Table of Contents 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 were removed to the United States District Court for the Eastern District of Louisiana. The plaintiffs moved to remand the lawsuit to the state courts. Plaintiffs’ motions to remand were submitted to the state court for decision in two of the lawsuits on February 15, 2023 and in the third lawsuit on February 16, 2023. 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 damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the lawsuit. In connection with Stone’s filing of bankruptcy in December 2016, Plaquemines Parish dismissed its claims against Stone without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. In state court, the Plaquemines Parish lawsuit was 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. However, subsequently, the Plaquemines Parish lawsuit was removed to the United States District Court for the Eastern District of Louisiana. The plaintiffs have moved to remand the lawsuit to the state courts, but the case was administratively closed in federal court pending the appeal of another case, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone. That appeal was resolved by the United States Court of Appeals for the Fifth Circuit on December 15, 2022, and on December, 22, 2022, plaintiffs filed a motion in federal court to re-open the lawsuit. The United States Court of Appeals for the Fifth Circuit has not yet ruled on plaintiffs’ motion to re-open. 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 Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies for more information. Item 4. Mine Saf ety Disclosures Not applicable. 69 Table of Contents PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuers Purchases of Equity Securities Market for Common Stock Our common stock is listed on the NYSE under the symbol “TALO”. Holders of Record Pursuant to the records of our transfer agent, as of February 21, 2023, there were approximately 282 holders of record of our common stock. Dividends We have never declared or paid any cash dividends on our common stock, and we anticipate that any available cash, other than the cash distributed to us to pay taxes and cover our corporate and other overhead expenses, will be retained by Talos Production Inc. to satisfy its operational and other cash needs. Accordingly, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. Although we do not expect to pay dividends on our common stock, if our board of directors decides to do so in the future, our ability to do so may be limited to the extent Talos Production Inc. is limited in its ability to make distributions to us, including the significant restrictions that the agreements governing Talos Production Inc.’s debt impose on the ability of Talos Production Inc. to make distributions and other payments to us. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt — Limitation on Restricted Payments Including Dividends for additional information. Securities Authorized for Issuance Under Equity Compensation Plans See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information regarding securities authorized for issuance under equity compensation plans. 70 Table of Contents Stockholder Return Performance Presentation The following graph is included in accordance with the SEC’s executive compensation disclosure rules. This historic stock price performance is not necessarily indicative of future stock performance. The graph compares the change in the cumulative total return of our common stock, the Dow Jones U.S. Exploration and Production Index, and the S&P 500 Index for May 10, 2018 through December 31, 2022. The graph assumes that $100 was invested in our common stock and each index on May 10, 2018 and that dividends were reinvested. May 10, 2018 2018 2019 2020 2021 2022 Talos Energy Inc. $ 100 $ 45 $ 83 $ 23 $ 27 $ 52 S&P 500 Index $ 100 $ 93 $ 123 $ 145 $ 187 $ 153 Dow Jones U.S. Exploration & Production Index $ 100 $ 71 $ 78 $ 53 $ 93 $ 147 The performance graph and the information contained in this section is not “soliciting material,” is being “furnished” not “filed” with the SEC and is not to be incorporated by reference into any of our filings under the Securities Act or the Exchange Act whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing. Item 6. [Reserved] 71 Table of Contents Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with our Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15. Exhibits and Financial Statement Schedules; Part I, Items 1 and 2. Business and Properties; Part I, Item 1A. Risk Factors; and Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk. This discussion and analysis contains forward-looking statements that involve risk and uncertainties. Actual results may differ materially from those anticipated in these forward-looking statements. This section of this Annual Report generally discusses 2022 and 2021 items and year-to-year comparisons between 2022 and 2021. Discussions of 2020 items and year-to-year comparisons between 2021 and 2020 that are not included in this Annual Report can be found in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2021 filed on February 25, 2022. Our Business 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 U.S. and offshore Mexico both through Upstream and the development of 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 along the Gulf Coast. 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, an acquisition or joint venture opportunities. We add to and reevaluate our inventory in order to deploy capital as efficiently as possible. Outlook We know that our investors and other stakeholders’ expectations of a successful energy company are evolving. We strive to provide safe, reliable, and responsible energy production that powers our world and delivers energy prosperity to modern life, while simultaneously applying our core skill sets to develop large-scale decarbonization projects to reduce industrial emissions. There are catalysts driving future value creation for both our legacy Upstream business and our emerging CCS business. For example, we plan to fortify, expand and advance our CCS business in 2023 by enhancing our existing portfolio and increasing storage capacity in existing project areas; expand partnerships in existing project areas; progress permitting and front-end engineering design workstreams; advancing and executing commercial contracts; and developing additional point source projects. Ongoing geopolitical uncertainty will continue to dictate commodity prices, including the ongoing Russia-Ukraine war, production decisions by OPEC Plus and China’s evolving policies toward COVID-19. The European Union’s ban on seaborne imports of petroleum products from Russia began on February 5, 2023 and could be more disruptive than the ban on crude oil imports implemented on December 5, 2022. 72 Table of Contents U.S. inflation rates rose to their highest levels since the 1980s last year, due to a string of geopolitical tensions and pandemic-related economic decisions. The Consumer Price Inflation index peaked in June 2022 at 9.0%, then fell for six straight months to 6.5% by the end of the year. The Fed raised interest rates from historic lows with four successive three-quarter point interest rate increases in 2022 and a quarter-point interest rate increase in February 2023. Future interest rate hikes are anticipated in 2023 in order to bring inflation down to the Fed’s target of 2.0%. The impact of the interest rate hikes could mean a slower economy, fewer jobs and less spending. The threat for a U.S. recession in 2023 is a reasonable expectation. However, many economists believe a recession, if it were to occur, would be relatively mild. Janet Yellen, U.S. Treasury Secretary, recently expressed confidence that the U.S. can avoid a recession after adding more than 500,000 jobs in January of 2023 that brought unemployment to a 54-year low. In January 2023, the national unemployment rate fell to 3.4%, which is the lowest reading on record since 1969. Tropical Storm Risk (“TSR”), one of the industry’s watched hurricane forecasting teams, issued its extended range forecast for North Atlantic hurricane activity in 2023 anticipating a season with activity below the 1991-2020 30-year norm level. The forecast spans the period from June 1, 2023 to November 30, 2023 and employs data through to the end of November 2022. The TSR is forecasting three intense hurricanes, six hurricanes and 13 tropical storms. TSR’s forecast for below-norm activity is due to the warm-neutral or weak El Nino conditions expected through July, August and September of 2023. Despite the expectation for a below-norm hurricane season in 2023, large uncertainties remain. Significant Developments The following encompasses significant developments since our Annual Report on Form 10-K for the year ended December 31, 2021: EnVen Acquisition — On September 21, 2022, we executed a merger agreement to acquire EnVen, a private operator in the Deepwater U.S. Gulf of Mexico (such agreement, the “EnVen Merger Agreement”). The closing of the EnVen Acquisition occurred on February 13, 2023. Consideration for the EnVen Acquisition consisted of (i) $207.3 million in cash and (ii) 43.8 million shares of the Company’s common stock valued at $832.2 million. We borrowed $130.0 million from our Bank Credit Facility, of which $119.0 million was used to partially fund the cash portion of the purchase price. 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 to permit the incurrence of indebtedness with respect to EnVen’s 11.75% Senior Secured Second Lien Notes due 2026. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt for additional information. Carbon Capture Initiatives — In February 2023, we elected to participate alongside Chevron in an onshore CO 2 sequestration leasehold in southeast Texas. Combined with the offshore Bayou Bend CCS pore space, this participation further expands our CO 2 storage capacity to serve multiple industrial markets within the region. See Part I, Items 1 and 2. Business and Properties — Carbon Capture & Sequestration for additional information regarding previously announced projects. Zama Update — See Part I, Items 1 and 2. Business and Properties — Upstream Properties — Mexico — Block 7 . Inflation Reduction Act of 2022 — On August 16, 2022, President Biden signed the IRA 2022 into law. The inclusion of several provisions in the IRA 2022 is expected to benefit both our upstream and CCS businesses. Specifically, the IRA 2022 directs the DOI to: • accept the highest bids received for Lease Sale 257, which was vacated by the U.S. District Court for the District of Columbia in January 2022; and • move forward with Lease Sales 259 and 261 in the Gulf of Mexico by March 31, 2023 and September 30, 2023, respectively, notwithstanding the June 30, 2022 expiration of the 2017-2022 Outer Continental Shelf Oil and Gas Leasing Program. 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 IRA 2022 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 2022 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. 73 Table of Contents The IRA 2022 incentivizes additional capital investment in CCS projects by developers and sponsors through the following: • increases the Section 45Q tax credit value from $50 per metric ton to $85 per metric ton of qualified carbon oxide captured from an industrial source and stored in secure geologic formations if certain prevailing wage and apprenticeship requirements are met; • expands eligibility for carbon capture and sequestration tax credits under Section 45Q by extending the beginning of the construction deadline from before January 1, 2026 to before January 1, 2033; and • allows taxpayers to now claim the value of a Section 45Q tax credit with respect to carbon capture equipment originally placed in service after December 31, 2022 as a direct pay option (i.e., through a tax refund as if there had been an overpayment of taxes). Both taxable and tax-exempt entities may elect the direct pay option, but any taxable entity may elect such option for only the first 5 years of the tax credit period that is otherwise available. The IRA 2022 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 the existing offshore royalty rate for leases in water depth exceeding 200 meters. Additionally, the IRA 2022 imposes a first-ever federal fee on greenhouse gases through a methane emissions charge. The IRA amends the federal Clean Air Act to impose a charge on emissions of methane from sources required to report their GHG emissions to the 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 thereafter. Calculation of the charge is based on certain thresholds established in the IRA 2022. 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 operating costs and adversely affect our business. Factors Affecting the Comparability of our Financial Condition and Results of Operations The following items affect the comparability of our financial condition and results of operations for periods 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 transportation, gathering and processing of production. We produce the Phoenix Field through the HP-I that is operated by 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. During the year ended December 31, 2022, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-September, resulting in a total shut-in period of 41 days. The shut-in resulted in an estimated deferred production of approximately 1.6 MBoepd for the year ended December 31, 2022, based on production rates prior to the shut-in. During the year ended December 31, 2022, we experienced approximately 26 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 0.7 MBoepd for the year ended December 31, 2022, based on production rates prior to the shut-in. Eugene Island Pipeline System — During the first quarter of 2022, we experienced approximately 40 days of unplanned third-party downtime due to maintenance of the Eugene Island Pipeline System, which carries our production from the Phoenix Field and Green Canyon 18 Field. For the year ended December 31, 2022, we estimate the shut-in has resulted in deferred production of approximately 1.2 MBoepd based on production rates prior to the shut-in. 74 Table of Contents Hurricanes and Tropical Storms — During 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 several weeks. For the year ended December 31, 2021, we estimate deferred production related to this storm was approximately 4.2 MBoepd, based on production rates prior to the storm. We did not experience any significant disruptions to our operations from hurricanes or tropical storms during the year ended December 31, 2022. Known Trends and Uncertainties 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. During January 1, 2022 through December 31, 2022, the daily spot prices for NYMEX WTI crude oil ranged from a high of $123.64 per Bbl to a low of $71.05 per Bbl and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $9.85 per MMBtu to a low of $3.46 per MMBtu. Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of production. We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for more additional information regarding our commodity derivative positions as of December 31, 2022. The U.S. Energy Information Administration (“EIA”) published its latest Short-Term Energy Outlook on February 7, 2023. The EIA expects the Henry Hub spot price will average $3.40 per MMBtu in 2023. Significantly warmer-than-normal weather in January 2023 led to less-than-normal consumption of natural gas for space heating and pushed inventories above the five-year average. Colder than expected temperatures in February and March 2023 could put upward pressure on prices. The Freeport LNG export facility, which went offline in June 2022 due to a fire, is expected to come back online in the first quarter of 2023 and will likely add over 2 billion cubic feet of natural gas per day of natural gas demand to the U.S. market once fully operational. The EIA also expects the NYEMX WTI spot price will average $77.84 per Bbl in 2023 and $71.57 per Bbl in 2024. In January 2023, the EIA highlighted oil demand in China and oil production in Russia as two of the main uncertainties in the oil market for 2023. China’s relaxing COVID-19 restrictions is expected to create oil demand growth. In February 2023, the EIA raised its forecast for Russia’s oil production through the end of 2024 but at the same time lowered its forecast for oil production in OPEC because of rising global oil inventories. These production forecast revisions largely offset each other. Inflation of Cost of Goods, Services and Personnel — Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. In addition, the U.S. inflation rate began increasing in 2021, peaked in the middle of 2022 and began to gradually decline in the second half of 2022. These inflationary pressures may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation could likely cause the Fed and other central banks to further increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business. The Fed raised rates again on February 1, 2023, by a quarter of a percentage point to 4.50%-4.75%. The Fed wants inflation to return to their 2% goal over time, and even though inflation is declining, it’s still high in absolute terms. Impairment of Oil and Natural Gas Properties — Under the full cost method of accounting, the “ceiling test” under SEC rules and regulations specifies that evaluated and unevaluated properties’ capitalized costs, less accumulated amortization and related deferred income taxes (the “Full Cost Pool”), should be compared to a formulaic limitation (the “Ceiling”) each quarter on a country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. During 2022, 2021 and 2020 our ceiling test computations for our U.S. oil and gas properties resulted in a write down of nil, nil and $267.9 million, respectively. At December 31, 2022, the Company’s ceiling test computation was based on SEC pricing of $96.03 per Bbl of oil, $6.80 per Mcf of natural gas and $33.89 per Bbl of NGLs. 75 Table of Contents There is a significant degree of uncertainty with the assumptions used to estimate the present value of future net cash flows from estimated production of proved oil and gas reserves due to, but not limited to the risk factors referred to in Part I, Item 1A. Risk Factors. The discounted present value of our proved reserves is a major component of the Ceiling calculation. Any decrease in pricing, negative change in price differentials, or increase in capital or operating costs could negatively impact the estimated future discounted net cash flows related to our proved oil and natural gas properties. With respect to our operations in Mexico, our oil and natural gas properties are classified as unproved properties, not subject to 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 an impairment of our unevaluated oil and gas properties. We recorded an impairment of $18.1 million for our unproved property investment in Block 31 during the year ended December 31, 2021. BOEM Bonding Requirements — In 2016, the BOEM issued the 2016 NTL, which bolstered supplemental bonding requirements. The 2016 NTL was not fully implemented as the BOEM under the Trump Administration first paused, and then in 2020 rescinded, this NTL. The future cost of compliance with respect to supplemental bonding, including the obligations imposed on 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 finalized, as well as to the provisions of any other new, more stringent NTLs or final rules on supplemental bonding published by the BOEM under the Biden Administration, could materially and adversely affect 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. Additionally, in August 2021, the BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements currently applicable to all sole liability properties and now to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-life is fewer than five years, or with damaged infrastructure irrespective of the remaining property life of the surrounding producing assets. BOEM has stated it will prioritize non-sole liability properties where it believes that the current owner does not meet applicable financial strength and has no co-owners or predecessors that are financially strong, as determined by BOEM. Deepwater Operations — We have interests in Deepwater fields in the U.S. Gulf of Mexico. Operations in Deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statements of operations as well as going concern issues. Oil Spill Response Plan — We maintain a Regional Oil Spill Response Plan that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil spill response plans are generally approved by the 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 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 and capital projects. Significant 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. 76 Table of Contents Five-Year Offshore Oil and Gas Leasing Program Update — Under the 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 included in 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 2022 into law on August 16, 2022. The IRA 2022 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 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. To that end, in January 2023, BOEM released its final environmental impact statement for Lease Sales 259 and 261 and indicated the issuance of a final record of decision by mid-February 2023. BOEM’s development of a new five-year 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. How We Evaluate Our Operations We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: • production volumes; • realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts; • lease operating expenses; • capital expenditures; and • Adjusted EBITDA, which is discussed under “—Supplemental Non-GAAP Measure” below. 77 Table of Contents Basis of Presentation Sources of Revenues Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs, that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives, which are reported in “Price risk management activities income (expense)” on our Consolidated Statements of Operations. The following table presents a breakout of each revenue component: Year Ended December 31, 2022 2021 2020 Oil 83 % 86 % 88 % Natural gas 14 % 10 % 9 % NGL 4 % 4 % 3 % Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Realized Prices on the Sale of Oil, Natural Gas and NGLs — The NYMEX WTI prompt month oil settlement price is a widely used benchmark in the pricing of domestic oil in the United States. The actual prices we realize from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For example, the prices we realize on the oil we produce are affected by the Gulf of Mexico Basin’s proximity to U.S. Gulf Coast refineries and the quality of the oil production sold in Eugene Island Crude, Louisiana Light Sweet Crude and Heavy Louisiana Sweet Crude markets. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. Currently, the sales points of our gas production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus average Henry Hub prices. In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue, as indicated in the table below, which provides the high, low and average prices for NYMEX WTI and NYMEX Henry Hub monthly contract prices as well as our average realized oil, natural gas, and NGL sales prices for the periods indicated. Year Ended December 31, 2022 2021 2020 Oil: NYMEX WTI high per Bbl $ 114.84 $ 81.48 $ 57.52 NYMEX WTI low per Bbl $ 76.44 $ 52.01 $ 16.55 Average NYMEX WTI per Bbl $ 94.79 $ 67.99 $ 39.16 Average oil sales price per Bbl (including commodity derivatives) $ 68.40 $ 49.67 $ 47.36 Average oil sales price per Bbl (excluding commodity derivatives) $ 93.75 $ 65.86 $ 37.09 Natural Gas: NYMEX Henry Hub high per MMBtu $ 8.81 $ 5.51 $ 2.61 NYMEX Henry Hub low per MMBtu $ 4.38 $ 2.62 $ 1.63 Average NYMEX Henry Hub per MMBtu $ 6.42 $ 3.91 $ 2.03 Average natural gas sales price per Mcf (including commodity derivatives) $ 5.30 $ 3.11 $ 2.00 Average natural gas sales price per Mcf (excluding commodity derivatives) $ 7.06 $ 3.98 $ 1.87 NGLs: NGL realized price as a % of average NYMEX WTI 35 % 39 % 25 % 78 Table of Contents To achieve more predictable cash flow, and to reduce exposure to adverse fluctuations in commodity prices, we enter into commodity derivative arrangements for a portion of our anticipated production. By removing a significant portion of price volatility associated with our anticipated production, we believe it will mitigate, but not eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods. However, our price risk management activity may also reduce our ability to benefit from increases in prices. We will sustain losses to the extent our commodity derivatives contract prices are lower than market prices and, conversely, we will sustain gains to the extent our commodity derivatives contract prices are higher than market prices. We will continue to use commodity derivative instruments to manage commodity price risk in the future. Our hedging strategy and future hedging transactions will be determined in accordance with both our Bank Credit Facility and Hedging Policy and may be different from what we have done on a historical basis. Expenses Lease Operating Expense — Lease operating expense consists of the daily costs incurred to bring oil, natural gas and NGLs out of the underground formation and to the market, together with the daily costs incurred to maintain our producing properties. Expenses for direct labor, insurance, a portion of the HP-I lease, materials and supplies, rental and third party costs comprise the most significant portion of our lease operating expense. It further consists of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production. Because the amount of workover and maintenance expense is closely correlated to the levels of workover activity, which is not regularly scheduled, workover and maintenance expense is not necessarily comparable from period-to-period. There is a reduction in our lease operating expenses for production handling fees related to certain reimbursements for costs from certain third parties. Production Taxes — Production taxes consist of severance taxes levied by the Louisiana Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of the state of Louisiana. Depreciation, Depletion and Amortization expense — Depreciation, depletion and amortization expense is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies for further discussion. Accretion Expense — We have obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We have obligations to plug wells when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue a liability with respect to these obligations based on our estimate of the timing and amount to replace, remove or retire the associated assets. Accretion of the liability is recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values. General and Administrative Expense — General and administrative expense generally consists of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity-based compensation expense, audit and other fees for professional services and legal compliance. Interest Expense — We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Bank Credit Facility and term-based debt. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest includes interest incurred under our debt agreements, the amortization of deferred financing costs (including origination and amendment fees), commitment fees, imputed interest on our capital lease, performance bond premiums and annual agency fees. Interest expense is net of capitalized interest on expenditures made in connection with exploratory projects that are not subject to current amortization. Price Risk Management Activities — We utilize commodity derivative instruments to reduce our exposure to fluctuations in the price of oil and natural gas. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss in our results of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. 79 Table of Contents Results of Operations Revenues The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and sales prices (in thousands): Year Ended December 31, 2022 2021 Change Revenues: Oil $ 1,365,148 $ 1,064,161 $ 300,987 Natural gas 227,306 130,616 96,690 NGL 59,526 49,763 9,763 Total revenues $ 1,651,980 $ 1,244,540 $ 407,440 Total Production Volumes: Oil (MBbls) 14,561 16,159 (1,598 ) Natural gas (MMcf) 32,215 32,795 (580 ) NGL (MBbls) 1,793 1,875 (82 ) Total production volume (MBoe) 21,723 23,500 (1,777 ) Daily Production Volumes by Product: Oil (MBblpd) 39.9 44.3 (4.4 ) Natural gas (MMcfpd) 88.3 89.8 (1.5 ) NGL (MBblpd) 4.9 5.1 (0.2 ) Total production volume (MBoepd) 59.5 64.4 (4.9 ) Average Sale Price per Unit: Oil (per Bbl) $ 93.75 $ 65.86 $ 27.89 Natural gas (per Mcf) $ 7.06 $ 3.98 $ 3.08 NGL (per Bbl) $ 33.20 $ 26.54 $ 6.66 Price per Boe $ 76.05 $ 52.96 $ 23.09 Price per Boe (including realized commodity derivatives) $ 56.46 $ 40.61 $ 15.85 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): Price Volume Total Revenues: Oil $ 406,231 $ (105,244 ) $ 300,987 Natural gas 98,998 (2,308 ) 96,690 NGL 11,939 (2,176 ) 9,763 Total revenues $ 517,168 $ (109,728 ) $ 407,440 Volumetric Analysis — Production volumes decreased by 4.9 MBoepd to 59.5 MBoepd for the year ended December 31, 2022. 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 3.5 MBoepd of deferred production. Additionally, production volumes decreased 2.0 MBoepd and 1.2 MBoepd primarily attributable to well performance and natural production declines in our Phoenix Field and Green Canyon 18 Field, respectively. Production volumes decreased 1.4 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 4.2 MBoepd in deferred production attributable to Hurricane Ida in 2021. 80 Table of Contents Operating Expenses Lease Operating Expense 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): Year Ended December 31, 2022 2021 Lease operating expenses $ 308,092 $ 283,601 Lease operating expenses per Boe $ 14.18 $ 12.07 Total lease operating expenses for the year ended December 31, 2022 increased by approximately $24.5 million, or 9%. The increase is primarily due to a $19.7 million increase in facility and workover expense related to repairs and maintenance at the Phoenix Field and the Gunflint Field. Additionally, there was a $4.3 million increase in company and contract labor compared to the same period in 2021. On a per unit basis, lease operating expense increased $2.11 per Boe to $14.18 per Boe primarily due to decreased production of 4.9 MBoepd. Depreciation, Depletion and Amortization 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): Year Ended December 31, 2022 2021 Depreciation, depletion and amortization $ 414,630 $ 395,994 Depreciation, depletion and amortization per Boe $ 19.09 $ 16.85 Depreciation, depletion and amortization expense for the year ended December 31, 2022 increased by approximately $18.6 million, or 5%. This increase was primarily due to an increase of $2.25 per Boe, or 13% in the depletion rate on our proved oil and natural gas properties due to an increase in proved properties primarily related to the extension of the HP-I lease and a decline in proved reserve volumes when compared to the same period in 2021. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 5 — Leases for additional information on the HP-I lease extension. General and Administrative Expense The following table highlights general and administrative expense items in total. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data): Year Ended December 31, 2022 2021 General and administrative expense $ 99,754 $ 78,677 General and administrative expense for the year ended December 31, 2022, increased by approximately $21.1 million, or 27%. This increase was due to transaction costs of $11.1 million primarily related to the EnVen Acquisition and $8.6 million in expenses incurred by our emerging CCS operating segment during the year ended December 31, 2022. Additionally, there was an increase of $5.1 million in employee and contract labor costs when compared to the same period in 2021. General and administrative expense includes non-cash equity-based compensation of $16.0 million during the year ended December 31, 2022, which is an increase of $5.2 million. On a per unit basis, general and administrative expense related to our Upstream operating segment increased $0.97 per Boe primarily due to decreased production of 4.9 MBoepd. 81 Table of Contents Miscellaneous 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): Year Ended December 31, 2022 2021 Write-down of oil and natural gas properties $ — $ 18,123 Accretion expense $ 55,995 $ 58,129 Other operating expense $ 33,902 $ 32,037 Interest expense $ 125,498 $ 133,138 Price risk management activities expense $ 272,191 $ 419,077 Equity method investment income $ 14,222 $ — Other (income) expense $ (31,800 ) $ 6,988 Income tax (benefit) expense $ 2,537 $ (1,635 ) Write-Down of Oil and Natural Gas Properties — Due to our non-consent to the Block 31 appraisal program, we recorded an impairment of $18.1 million for our unproved property investment in Block 31 during the year ended December 31, 2021 as the costs were not recoverable. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 4 — Property, Plant and Equipment . Other Operating Expense — During the year ended December 31, 2022, we recorded $31.6 million of estimated decommissioning obligations primarily as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. During the year ended December 31, 2021, we recorded $21.1 million of estimated decommissioning obligations. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies . Additionally, we recorded an impairment of $5.6 million related to the adjustment of other well equipment inventory to net realizable value, which was expensed and reflected in “Other operating (income) expense” on the Consolidated Statements of Operations during the year ended December 31, 2021. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies . Interest Expense — During the year ended December 31, 2022, we recorded $125.5 million of interest expense compared to $133.1 million during the year ended December 31, 2021. The change is primarily a result of the interest associated with the Bank Credit Facility with no outstanding borrowings as of December 31, 2022 when compared to $375.0 million as of December 31, 2021. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt . Price Risk Management Activities — Price risk management activities for year ended December 31, 2022 resulted in a decrease of approximately $146.9 million, or 35%. The expense of $272.2 million for the year ended December 31, 2022 consisted of $425.6 million in cash settlement losses offset by $153.4 million in non-cash gains from the increase in the fair value of our open derivative contracts. The expense of $419.1 million for the year ended December 31, 2021 consisted of $290.2 million in cash settlement losses and $128.9 million in non-cash losses from the decrease in the fair value of our open derivative contracts. These unrealized gains and 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 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 IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for additional information. Equity Method Investment Income — During the year ended December 31, 2022, we recorded a $15.3 million gain on partial sale of our equity method investment in Bayou Bend offset by equity losses of $1.1 million. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — Related Party Transactions for additional information. 82 Table of Contents Other (Income) Expense — During the year ended December 31, 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 IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies . This was partially offset by a $1.6 million loss on extinguishment of debt as a result of the redemption of the 12.00% Notes further discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt . During the year ended December 31, 2021, we recorded a $13.2 million loss on extinguishment of debt as a result of the redemption of the 11.00% Notes further discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt . 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 IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — Related Party Transactions . Income Tax Benefit (Expense) — During the year ended December 31, 2022, we recorded $2.5 million of income tax expense compared to $1.6 million of income tax benefit during the year ended December 31, 2021, primarily a result of non-deductible losses in the U.S. and recognition of a valuation allowance for our excess federal and state deferred tax assets in the year ended December 31, 2022. 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 IV, Item 15. Exhibits and Financial Statement Schedules — Note 9 — Income Taxes . Commitments and Contingencies For a further discussion of our commitments and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies . Additionally, we are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuit with certainty, but our management believes it is remote that any such pending or threatened lawsuit will have a material adverse impact on our financial condition. See Part I, Item 3. Legal Proceedings for additional information. Due to the nature of our business, we are, from time-to-time, involved in other routine litigation or subject to disputes or claims related to business activities, including workers’ compensation claims, employment related disputes and civil penalties by regulators. In the opinion of our management, none of these other pending litigations, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Part I, Item 3. Legal Proceedings for additional information. Supplemental Non-GAAP Measure EBITDA and Adjusted EBITDA “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 have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP. We define these as the following: • EBITDA — Net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, and accretion expense. • Adjusted EBITDA — EBITDA plus non-cash write-down of oil and natural gas properties, transaction and other (income) expenses, decommissioning obligations, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash write-down of other well equipment inventory and non-cash equity-based compensation expense. 83 Table of Contents 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): Year Ended December 31, 2022 2021 2020 Net income (loss) $ 381,915 $ (182,952 ) $ (465,605 ) Interest expense 125,498 133,138 99,415 Income tax expense (benefit) 2,537 (1,635 ) 35,583 Depreciation, depletion and amortization 414,630 395,994 364,346 Accretion expense 55,995 58,129 49,741 EBITDA 980,575 402,674 83,480 Write-down of oil and natural gas properties — 18,123 267,916 Transaction and other (income) expense (1) (34,513 ) 5,886 14,917 Decommissioning obligations (2) 31,558 21,055 — Derivative fair value (gain) loss (3) 272,191 419,077 (87,685 ) Net cash received (paid) on settled derivative instruments (3) (425,559 ) (290,164 ) 143,905 (Gain) loss on debt extinguishment 1,569 13,225 (1,662 ) Non-cash write-down of other well equipment inventory — 5,606 699 Non-cash equity-based compensation expense 15,953 10,992 8,669 Adjusted EBITDA $ 841,774 $ 606,474 $ 430,239 (1) Other income (expense) includes restructuring expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the year ended December 31, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies. Additionally, it includes a $15.3 million gain for the year ended December 31, 2022 on partial sale of our investment in Bayou Bend that is further discussed Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — Related Party Transactions . For the year ended December 31, 2020, the amount includes $1.4 million of legal entity restructuring costs and $1.3 million of severance related cost saving initiatives due to the COVID-19 pandemic. (2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies for additional information on decommissioning obligations. (3) The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled. Liquidity and Capital Resources Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility. Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. Our working capital deficit has decreased since December 31, 2021 primarily due to a decrease of $118.2 million in liabilities from price risk management activities and an increase of $24.1 million in assets from price risk management activities. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for additional information. As of December 31, 2022, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $846.5 million. We fund exploration and development activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant property acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities. 84 Table of Contents Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the year ended December 31, 2022 (in thousands): U.S. drilling & completions $ 234,173 Mexico appraisal & exploration 372 Asset management (1) 102,027 Seismic and G&G, land, capitalized G&A and other 44,881 CCS (2) 2,778 Total capital expenditures 384,231 Plugging & abandonment 69,596 Decommissioning obligations settled (3) 1,625 Total $ 455,452 (1) Asset management consists of capital expenditures for development-related activities primarily associated with recompletions and improvements to our facilities and infrastructure. (2) Excludes $2.7 million of expenditures reflected as “Other operating (income) expense” on the Consolidated Statements of Operations. (3) Settlement of decommissioning obligations as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies for additional information on decommissioning obligations. Based on our current level of legacy operations, the recently acquired EnVen operations, and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund our board approved 2023 Upstream capital spending program of $650.0 million to $675.0 million as well as expected investments in our CCS operating segment of $70.0 million to $90.0 million. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on operating and economic conditions, some of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g. by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness. Overview of Cash Flow Activities — The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands): Year Ended December 31, 2022 2021 Operating activities $ 709,739 $ 411,388 Investing activities $ (311,977 ) $ (293,747 ) Financing activities $ (423,469 ) $ (82,022 ) Operating Activities — Net cash provided by operating activities increased $298.4 million in 2022 compared to 2021 primarily attributable to an increase in revenues net of lease operating expense of $382.9 million. This was offset by an increase in cash payments on derivatives of $135.4 million. Investing Activities — Net Cash used in investing activities increased $18.2 million in 2022 compared to 2021 primarily due to an increase in capital expenditures of $29.8 million offset by proceeds of $15.0 million from a partial sale of our investment in Bayou Bend. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — Related Party Transactions for additional information. Financing Activities — Net cash used in financing activities increased $341.4 million in 2022 compared to 2021. During the year ended December 31, 2022, net repayments of $375.0 million reduced the Bank Credit Facility. Additionally, we redeemed $12.1 million and $6.1 million of our 12.00% Notes and 7.50% Senior Notes (as defined herein), respectively. 85 Table of Contents During the year ended December 31, 2021, the issuance of the 12.00% Notes in January 2021 generated $579.0 million after original discount and deferred financing costs. The net proceeds from the 12.00% Notes funded the $356.8 million redemption of the 11.00% Notes and reduced the indebtedness under the Bank Credit Facility by $175.0 million in the first quarter of 2021. Indebtedness under the Bank Credit Facility was then further reduced by $90.0 million during the remainder of 2021. Overview of Debt Instruments Financing Arrangements — As of December 31, 2022, total debt, net of discount and deferred financing costs, was approximately $585.3 million, comprised of our $638.5 million aggregate principal amount of the 12.00% Notes and no outstanding borrowings under our Bank Credit Facility. We were in compliance with all debt covenants at December 31, 2022. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt . Bank Credit Facility – matures March 2027 — We maintain a Bank Credit Facility with a syndicate of financial institutions. 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 each year. For additional details on our Bank Credit Facility, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt . 12.00% Second-Priority Senior Secured Notes—due January 2026 — The 12.00% Notes were issued pursuant to an indenture dated January 4, 2021 and the 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, 2026 and have interest payable semi-annually each January 15 and July 15. We made an interest payment of $38.7 million on January 17, 2023. For additional details on the 12.00% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt . Redemption of the 11.00% Second-Priority Senior Secured Notes—due April 2022 — On January 13, 2021, we redeemed the 11.00% Notes using the proceeds from the issuance of the 12.00% Notes. For additional details on this redemption, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt . 7.50% Senior Notes – redeemed May 2022 — The 7.50% Senior Notes due 2022 (“7.50% Senior Notes”) matured and were redeemed on May 31, 2022. For additional details on the 7.50% Senior Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt . EnVen’s 11.75% Senior Secured Second Lien Notes—due April 2026 — On February 13, 2023, in conjunction with the closing of the EnVen Acquisition, the Company assumed EnVen’s 11.75% Senior Secured Second Lien Notes due 2026 (the “EnVen Second Lien Notes”) with a principal amount of $257.5 million. The EnVen Second Lien Notes will mature on April 15, 2026 and interest accrues and is to be paid semi-annually in cash in arrears on April 15 th and October 15 th of each year. The indenture governing the EnVen Second Lien Notes requires the redemption of $15.0 million of the principal amount outstanding at par value on April 15 th and October 15 th of each year. For additional details on the EnVen Second Lien Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt . 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 Parent Guarantor and on a second-priority senior secured basis by each of the Issuer’s present and future direct or indirect wholly owned material restricted subsidiaries that guarantees the Issuer’s senior reserve-based revolving credit facility (collectively, the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”). Our non-domestic subsidiaries (other than Talos International Holdings SCS) and our unrestricted CCS domestic subsidiaries (the “Non-Guarantors”) are 100% owned by us but do not guarantee the 12.00% Notes. In lieu of 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 . 86 Table of Contents The following table presents the balance sheet information for the respective periods (in thousands): Year Ended December 31, 2022 2021 Current assets $ 344,525 $ 330,415 Non-current assets 2,571,254 2,305,855 Total assets $ 2,915,779 $ 2,636,270 Current liabilities $ 599,669 $ 598,062 Non-current liabilities 1,285,992 1,405,382 Talos Energy Inc. stockholdersʼ equity 1,030,118 632,826 Total liabilities and stockholdersʼ equity $ 2,915,779 $ 2,636,270 The following table presents the income statement information (in thousands): Year Ended December 31, 2022 Revenues $ 1,651,980 Costs and expenses (1,271,834 ) Net income $ 380,146 Material Cash Requirements — 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 certain operating leases and capital commitments, are not reflected on our accompanying Consolidated Financial Statements. The following table and discussion summarizes our material cash requirements from known contractual obligations as of December 31, 2022 (in thousands): 2023 2024 2025 2026 2027 Thereafter Total (4) Long-term financing obligations: Debt principal $ — $ — $ — $ 638,541 $ — $ — $ 638,541 Debt interest 80,769 80,274 76,625 3,193 — — 240,861 Vessel commitments (1) 41,938 — — — — — 41,938 Derivative liabilities 68,370 7,872 — — — — 76,242 Operating lease obligations 3,774 3,579 3,645 3,712 3,596 5,727 24,033 Finance lease (2) 46,407 19,336 — — — — 65,743 Purchase obligations (3) 41,148 — — — — — 41,148 EnVen Acquisition (4) 259,858 — — — — — 259,858 Other commitments (5) 9,627 327 327 — — — 10,281 Total contractual obligations (6) $ 551,891 $ 111,388 $ 80,597 $ 645,446 $ 3,596 $ 5,727 $ 1,398,645 (1) Includes vessel commitments we will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will be billed for their working interest share of such costs. (2) Lease agreement for the HP-I floating production facility in the Phoenix Field. (3) Includes committed purchase orders to execute planned future drilling activities. (4) Includes cash consideration and contingent fees related to the EnVen Acquisition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Subsequent Events for further information on the EnVen Acquisition. (5) Includes commitment to acquire additional lease acreage associated with our CCS Segment. (6) This table does not include our estimated discounted liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $541.7 million as of December 31, 2022. For additional information regarding these liabilities, please see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 4 — Property, Plant and Equipment . Additionally, this table does not include liabilities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see please see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitment and Contingencies . 87 Table of Contents On February 13, 2023, in conjunction with the closing of the EnVen Acquisition, the Company assumed contractual obligations that have material cash requirements. Examples of those contractual obligations include, but are not limited to: • The EnVen Second Lien Notes as discussed above; • Derivative liabilities; • Seismic data licensing change of control payments; and • EnVen’s leased office space located in Downtown Houston. Performance Obligations — As of December 31, 2022, we had secured performance bonds totaling $740.6 million primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of Mexico and certain obligations under the PSCs with Mexico from third party sureties. Additionally, we had 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. For additional information about certain of our obligations and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — 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 are described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies . Oil and Natural Gas Properties — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the Full Cost Pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below. 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, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates 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 the Company owns a direct interest. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities. 88 Table of Contents The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling for U.S. oil and gas properties are recognized as a non-cash “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on the Company’s Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when performing the ceiling test. The Company also holds 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. 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 the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does 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. Proved Reserve Estimates — We estimate our proved oil, natural gas and NGL reserves in accordance with the guidelines established by the SEC. Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs and under existing economic conditions, operating methods and governmental regulations. Prices are determined using SEC pricing. Our estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. The estimates of proved reserves are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in price, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. A material adverse change in the estimated volumes of proved reserves could have a negative impact on depreciation, depletion and amortization or could result in property impairments. Fair Value Measure of Financial Instruments — Our financial instruments generally consisted of cash and cash equivalents, accounts receivable, commodity derivatives, accounts payable and debt as of December 31, 2022. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments. Fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standard