TALOS ENERGY INC. (TALO)

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 2024 and 2023 items and year-to-year comparisons between 2024 and 2023. Discussions of 2022 items and year-to-year comparisons between 2023 and 2022 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, 2023 filed with the SEC on February 29, 2024.

Our Business

We are a technically driven, innovative, independent energy company focused on maximizing long-term value through our Upstream business in the U.S. Gulf of America and offshore Mexico. We leverage decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while maintaining a focus on safe and efficient operations, environmental responsibility and community impact.

We have historically focused our operations in the U.S. Gulf of America 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 an 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.

Outlook

We operate within an industry sector directly impacted by the energy transition. The energy transition will require both significant new investments in low-carbon energies and continued use of traditional hydrocarbons to meet the expected energy demand of an expanding global economy.

Our historical focus in the Gulf of America results in an asset profile that differentiates us from the typical shale-driven onshore exploration and production companies. Completion of the QuarterNorth Acquisition added scale to our business both in terms of production and operated infrastructure, while also diversifying our production across a broader asset base. While we are currently a pure play Gulf of America company, diversification outside of our existing operational areas is always a possibility.

The U.S. Energy Information Administration (“EIA”) expects downward oil price pressures over much of the next two years, as they expect that global oil production will grow more than global oil demand. The EIA also expects the Henry Hub gas spot price to generally rise over the next two years up from a historically low average in 2024 due to growth in demand that outpaces production growth.

Some energy policy changes can be expected under the Trump Administration. President Trump’s energy priorities include energy independence and lowering energy costs. His proposals seek to increase domestic production of oil and gas. Some of the proposals can be carried out by executive action or through the regulatory process, while others, such as changes to legislation, would require congressional action. Meanwhile, changes in certain tax policies could also impact the oil and gas industry. Easing monetary policies, like lowering interest rates, typically lead to an increase in oil prices by stimulating economic growth and increasing demand for energy. Geopolitical tensions, particularly in the main producing regions, such as the Middle East, will continue to influence prices. While these tensions pose risks, they are mitigated by the ability of OPEC Plus to manage supply. The group has delayed oil production increases until April 2025 and prolonged the complete reversal of cuts by a year, until the end of 2026.

We remain exposed to potential operational disruptions from weather-related events in the U.S. Gulf of America. The first long-range forecast for the 2025 Atlantic hurricane season was released on December 10, 2024, with Tropical Storm Risk projecting there could be 15 tropical storms, 7 hurricanes, and 3 intense hurricanes for the 2025 Atlantic hurricane season, which would be roughly aligned with the 30-year norm.

We recently announced that the Katmai West #2 well was drilled significantly under budget and ahead of schedule. Completion activities are ongoing and we expect production to commence late in the second quarter of 2025. We anticipate production to commence from our Sunspear well late in the second quarter of 2025.

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Significant Developments

The following encompasses significant developments since the filing of our Annual Report on Form 10-K for year ended December 31, 2023:

Cooperation Agreement — On December 16, 2024, we entered into the Cooperation Agreement with Control Empresarial. Pursuant to the Cooperation Agreement, Control Empresarial agreed that during the term of the Cooperation Agreement that it would not acquire, agree or seek to acquire or make any proposal or offer to acquire, or announce any intention to acquire, directly or indirectly, beneficially or otherwise, any voting securities of the Company (other than in connection with a stock split, stock dividend or similar corporate action initiated by us) if, immediately after such acquisition, Control Empresarial and the other members of its investor group, collectively, would, in the aggregate, beneficially own more than 25.0% of the outstanding shares of any class of voting securities of the Company. The Cooperation Agreement expires December 16, 2025, but is subject to early termination upon the occurrence of certain events described in the Cooperation Agreement. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Related Party Transactions for additional information on Control Empresarial.

Agreement to Sell Additional Stake in Zama Asset — On December 16, 2024, we entered into an agreement to sell an additional 30.1% equity interest in Talos Mexico to Zamajal, a subsidiary of Carso, for $49.7 million in cash consideration with an additional $33.1 million contingent on first oil production from the Zama Field (the “Incremental Mexico Equity Sale”). The Incremental Mexico Equity Sale is expected to close during 2025 upon the satisfaction of customary closing conditions and the receipt of all regulatory approvals. After consummation of the Incremental Mexico Equity Sale, Talos Mexico, which currently holds a 17.4% interest in the Zama field, will be owned 20.0% by the Company and 80.0% by Zamajal. While the Company anticipates the Incremental Mexico Equity Sale will close in 2025, there can be no assurance that all of the conditions to closing, including obtaining necessary regulatory approvals, will be satisfied. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments for additional information on the Incremental Mexico Equity Sale and Note 14 — Related Party Transactions for additional information on Carso.

Limited Duration Stockholder Rights Agreement — On October 1, 2024, our Board adopted a stockholder rights agreement (the “Rights Agreement”) and declared a dividend distribution of one preferred share purchase right (“Right”) on each outstanding share of our common stock, par value $0.01 per share, which became payable on October 11, 2024. In adopting the Rights Agreement, the Board noted, in particular, the continued accumulation of approximately 24.0% of shares of Talos common stock by Control Empresarial. In connection with entering into the Cooperation Agreement, we entered into the First Amendment to the Rights Agreement (the “Amendment”). The Amendment accelerated the expiration of the Rights from the close of business on October 1, 2025 to the close of business on December 17, 2024. Accordingly, the Rights issued under the Rights Agreement expired and are no longer outstanding.

See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 10 — Stockholders’ Equity for more information on both the Rights Agreement and Amendment and Note 14 — Related Party Transactions for additional information on Control Empresarial.

Chief Executive Officer Transition — On August 29, 2024, Timothy S. Duncan departed his role as President and Chief Executive Officer of the Company. The Company also announced that Joseph A. Mills would serve as Interim Chief Executive Officer and President, effective as of August 29, 2024. On January 5, 2025, Mr. Mills informed the Board that he was resigning from his position as Interim Chief Executive Officer and President and as a member of the Board, effective immediately. Effective as of January 6, 2025, the Board created an Office of the Interim Chief Executive Officer (the “Office of the Interim CEO”) and appointed the following three senior executives to serve, in addition to their existing roles, as interim Co-Presidents and as members of the Office of the Interim CEO: (i) Mr. William S. Moss, III, Executive Vice President, General Counsel and Secretary of the Company; (ii) Mr. Sergio L. Maiworm, Jr., Executive Vice President and Chief Financial Officer of the Company; and (iii) Mr. John B. Spath, Executive Vice President and Head of Operations of the Company (such appointees collectively, the “Members”). Each Member is serving individually as Interim Co-President, managing the function of the Office of the Interim CEO, and serving at the discretion of the Board until the earlier of (a) the effective start date of a permanent Chief Executive Officer and (b) with respect to each such Member, such Member’s successor has been duly appointed and qualified or until his death, disability, resignation or removal. The Office of the Interim CEO reports to the Board and performs the duties and responsibilities of the role of the Chief Executive Officer on an interim basis while the search for a permanent Chief Executive Officer was being concluded by the Board, with Mr. Moss designated as interim Chief Executive Officer and the principal executive officer of the Company on January 6, 2025. On February 3, 2025, the Company announced that Mr. Paul R. Goodfellow had been selected to serve as President and Chief Executive Officer, principal executive officer and member of the Board, effective as of March 1, 2025. The Office of the Interim CEO will dissolve at such time that Mr. Goodfellow takes office.

Acquisition of Working Interests in Monument Oil Discovery — We executed two separate definitive agreements to acquire a collective 21.4% non-operated working interest in the Monument oil discovery (“Monument Project”) in the Deepwater U.S. Gulf of America located on certain Walker Ridge lease blocks in late July 2024 and early August 2024. First production is expected from the Monument Project by late 2026. On February 20, 2025, we executed a definitive agreement to acquire an additional 8.3% non-operated working interest in the Monument Project for $6.3 million, excluding customary effective date adjustments. An additional aggregate $6.3 million will be paid after certain milestones are achieved. The Company expects to close in March 2025. See additional information in Part IV, Item 1. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures.

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Talos Low Carbon Solutions Divestiture — On March 18, 2024, we entered into a definitive agreement relating to and subsequently completed the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC, to TotalEnergies E&P USA, Inc. for a purchase price of $125.0 million plus customary reimbursements and adjustments, combined totaling an aggregate of approximately $142.0 million (the “TLCS Divestiture”). The TLCS Divestiture included Talos’s entire CCS business, including its equity investment in three projects along the U.S. Gulf Coast: Bayou Bend CCS LLC (“Bayou Bend”); Harvest Bend CCS LLS; and Coastal Bend CCS LLC. The TLCS Divestiture also entitles Talos to certain contingent payments, of which $4.7 million was received during the year ended December 31, 2024 and $12.5 million is expected to be received during the year ended December 31, 2025. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

QuarterNorth Acquisition Completed — On March 4, 2024, we completed the acquisition of QuarterNorth Energy Inc. (“QuarterNorth”), a privately-held U.S. Gulf of America exploration and production company (the “QuarterNorth Acquisition”) for consideration consisting of (i) $1,247.4 million in cash and (ii) 24.3 million shares of the Company’s common stock valued at $322.6 million. The cash payment was partially funded with a January 2024 underwritten public offering of 34.5 million shares of the Company’s common stock, borrowings under the Bank Credit Facility and the Senior Notes. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures, Note 8 — Debt and Note 10 — Stockholders’ Equity for additional information.

Common Stock Repurchase Program — Our Board of Directors authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits. During the year ended December 31, 2023 and six months ended June 30, 2024, we repurchased 3.4 million shares for $47.5 million and 3.8 million shares for $42.9 million, respectively. On July 22, 2024, our Board authorized an additional $150.0 million to our previously approved limit increasing the amount remaining under our authorized plan to $159.6 million. During the three months ended September 30, 2024, we repurchased 0.2 million shares for $2.2 million. There were no shares of common stock repurchased during the three months ended December 31, 2024. We have repurchased an aggregate of 7.4 million shares under our authorized program for a total of $92.6 million resulting in approximately $157.4 million remaining under our authorized program as of December 31, 2024. All repurchased shares are held in treasury.

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.

QuarterNorth Acquisition — On March 4, 2024, we completed the acquisition of QuarterNorth. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

EnVen Acquisition — On February 13, 2023, we acquired EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of America (the “EnVen Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Planned Downtime — We are vulnerable to downtime events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through the Helix Producer I (“HP-I”) that is operated by Helix Energy Solutions Group, Inc (“Helix”). Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the U.S. Coast Guard, during which time we are unable to produce the Phoenix Field.

During the year ended December 31, 2024, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-June, resulting in a total shut-in period of 52 days. The shut-in resulted in an estimated deferred production of approximately 1.2 MBoepd for the year ended December 31, 2024 based on production rates prior to the shut in. The next dry-dock is scheduled for the first half of 2027 with a projected shut-in period of approximately 45 days.

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, 2024 through December 31, 2024, the daily spot prices for NYMEX WTI crude oil ranged from a high of $87.69 per Bbl to a low of $66.73 per Bbl and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $13.20 per MMBtu to a low of $1.21 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, 2024.

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The EIA published its February 2025 Short-Term Energy Outlook on February 11, 2025. The EIA expects the NYMEX WTI spot price will average $70.62 per Bbl in 2025 compared to an average of $76.60 per Bbl in 2024. The current forecast for 2026 is $62.46 per Bbl. Following some initial upward price pressure in early 2025, the EIA expects that crude oil prices will generally decline from mid-2025 through the end of 2026 as growth in global oil production outpaces growth in oil demand. The EIA does not presently anticipate the tariffs put forward in President Trump’s February 1, 2025 executive order would significantly affect global oil supply. However, the possibility of future tariffs and the new sanctions on Russia are sources of uncertainty for oil prices going forward. The EIA also expects natural gas prices to average $3.79 per MMBtu in 2025, and rise to an average of $4.16 per MMBtu in 2026, up from an average of $2.19 per MMBtu in 2024. Natural gas inventories are expected to remain at or below previous five-year averages during the forecast period putting upward pressure on natural gas prices. Over the next two years, the EIA expects that natural gas demand in the U.S. will generally grow by more than natural gas supply. Exports are the leading source of natural gas demand growth in the EIA forecast. Two new LNG export facilities—Plaquemines LNG and Corpus Christi LNG Stage 3—started producing liquefied natural gas in December 2024.

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. Inflation 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. In 2022 and 2023, the Fed raised its benchmark interest rate 11 times. The Fed wants inflation to return to its 2% goal over time, and even though inflation has declined, it is still high in absolute terms. The Fed lowered its benchmark interest rate three times between September and December 2024 by an aggregate 100 basis points to a new range of 4.25%-4.50% from its 23-year high of 5.25% to 5.50%. In January 2025, the Fed left its benchmark interest rate unchanged as the Fed seeks to gauge where inflation is headed and what policies President Trump may pursue. For example, higher tariffs and tax cuts could push inflation higher, while deregulation could possibly reduce it. Future changes to the benchmark interest rate remain uncertain.

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 2024, 2023 and 2022 our ceiling test computations for our U.S. oil and gas properties did not result in a write down. At December 31, 2024, the Company’s ceiling test computation was based on SEC pricing of $75.51 per Bbl of oil, $2.45 per Mcf of natural gas and $21.91 per Bbl of NGLs.

If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2024 and ending December 1, 2024 used in the determination of the SEC pricing was 10% lower, resulting in $67.95 per Bbl of oil, $2.23 per Mcf of natural gas and $19.79 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $420.0 million.

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.

Financial Assurance Requirements — On April 15, 2024, BOEM issued a final rule related to supplemental financial assurance requirements in the OCS entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations.” This rule significantly increases the amount of new supplemental financial assurance required from certain lessees and grant holders conducting operations on the OCS. The final rule provides that BOEM will no longer consider or rely upon the financial strength of predecessors in title in determining whether, or how much, supplemental financial assurance will be required by current lessees and grant holders. The final rule, which became effective on June 29, 2024, adopts a three-year phased compliance period to fully comply with BOEM’s supplemental financial assurance demand. Per BOEM’s June 28, 2024 news release, BOEM indicated it may take up to 24 months from that date to complete the processing of financial assurance demands. The final rule was challenged in the U.S. District Court for the Western District of Louisiana by multiple oil and gas industry groups and the States of Mississippi, Louisiana, and Texas on June 17, 2024. The implementation of the final rule is not currently stayed and the outcome of these challenges remains uncertain. However, the Trump Administration may seek to suspend, revise or rescind the rule pursuant to Interior Secretary Burgum’s Secretarial Order 3418 dated February 3, 2025, although the substance and timing of such action, if any, cannot be predicted at this time.

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If the final rule is not suspended, revised or rescinded, or if it is not overturned pursuant to the ongoing litigation, we may be unable to comply with orders from BOEM to provide additional surety bonds or other financial assurances. Consequently, BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases associated with our noncompliance, which, if upheld, would have a material adverse effect on our business, properties, results of operations, liquidity and financial condition. Moreover, regardless of the final rule, BOEM has the right to issue financial assurance orders in the future, including if it determines there is a substantial risk of nonperformance of the current interest holder’s decommissioning liabilities.

See Part I, Items 1 and 2. Business and Properties — Government Regulation — Outer Continental Shelf (“OCS”) Regulation for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry on the OCS.

Financial Assurance Market Outlook — As a result of adverse developments in restructurings and bankruptcies of companies operating in the OCS, a number of surety companies have left the offshore surety market, which has materially reduced the availability of surety bonds for projects in the OCS and may reduce the ability of companies operating in the OCS to obtain bonding without posting collateral. As a result, there may not be sufficient surety bond capacity available for companies in the OCS to comply with BOEM’s financial assurance requirements or otherwise if the final rule is not suspended, revised or rescinded or if it is not overturned pursuant to the ongoing litigation. In addition to BOEM’s financial assurance requirements, companies with whom we partner or from whom we wish to acquire assets may require that we provide financial assurance, such as surety bonds, to provide assurance that our decommissioning obligations associated with those jointly held or acquired assets can be met in the future. The tightened capacity in the surety market may impact our ability to secure surety bonds at commercially reasonable terms and therefore, our ability to enter into such joint participation or asset acquisition opportunities may be impacted.

Moreover, under our existing and future indemnity agreements, surety companies have the right to demand additional collateral, such as cash or letters of credit, to support existing or future bonds. We cannot provide assurance that we will be able to satisfy collateral demands. If we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be significantly negatively impacted and we may be required to seek alternative financing in order to continue operations, develop new projects and acquire new assets. These regulatory requirements and market trends could, in the future, result in significantly increased costs on our operations, reduced cash flows and liquidity and consequently have a material adverse effect on our business and results of operations.

Deepwater Operations — We have interests in Deepwater fields in the U.S. Gulf of America. 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, Tropical Storms, Winter Storms and Loop Currents — Since our operations are in the U.S. Gulf of America, we are particularly vulnerable to the effects of hurricanes, tropical storms, winter storms and loop currents on production and capital projects. Significant impacts could include reductions and/or deferrals of future oil and natural gas production and revenues and increased lease operating expenses for evacuations and repairs.

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Five-Year Offshore Oil and Gas Leasing Program Update — Under the OCSLA, as amended, 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 America, Lease Sales 259 and 261 included in the 2017-2022 Five-Year Leasing 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 America lease sales. The IRA 2022 reinstated Lease Sale 257 held in November 2021, and required 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 ten (10) blocks and awarded leases on nine (9) blocks. In January 2023, BOEM released its final environmental impact statement for Lease Sales 259 and 261 and, in March 2023, announced the results of Lease Sale 259, in which we were the high bidder on four offshore blocks, and were awarded leases on all four blocks. Lease Sale 261 was scheduled to be held on November 8, 2023, pursuant to a September 21, 2023 court order from the United States District Court for the Western District of Louisiana, as amended by a September 25, 2023 court order from the United States Court of Appeals for the Fifth Circuit. However, on October 26, 2023, the United States Court of Appeals for the Fifth Circuit stayed its and the District Court’s ruling, scheduling oral arguments for November 13, 2023. On November 2, 2023, BOEM announced the postponement of Lease Sale 261 as a result of the United States Court of Appeals for the Fifth Circuit’s October 26, 2023 order. Pursuant to the United States Court of Appeals for the Fifth Circuit’s November 14, 2023 order, BOEM held Lease Sale 261 on December 20, 2023, in which we were the high bidder on thirteen offshore blocks and were awarded leases on all of our high-bid blocks. Additionally, QuarterNorth was the high bidder on four offshore blocks related to Lease Sale 261 and they were also awarded leases on all of their high-bid blocks.

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.

The 2024-2029 Five-Year Leasing Program began on July 1, 2024, and will continue through June 30, 2029, and includes a maximum of three potential oil and gas lease sales in the Gulf of America scheduled to be held in years 2025, 2027 and 2029. It is possible, however, that this program could be delayed by opposing lawsuits that were filed on February 12, 2024 by the American Petroleum Institute and Earthjustice representing multiple environmental groups, both of which are challenging BOEM’s actions. Despite these challenges, on April 1, 2024, BOEM announced the availability of the Area Identification for proposed Gulf of America lease sales 262, 263 and 264 pursuant to the 2024-2029 Five-Year Leasing Program. On December 13, 2024, BOEM published its Draft Programmatic Environmental Impact Statement for proposed U.S. Gulf of America lease sales 262, 263 and 264. Lease Sale 262 is tentatively scheduled for 2025. The Trump Administration may seek to take additional action to revise the Five-Year Leasing Program, although the substance and timing of such action cannot be predicted.

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.

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:

Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

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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 America 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.

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.

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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 plug, 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.

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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, except per unit data):

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

Volumetric Analysis — Production volumes increased by 26.3 MBoepd to 92.6 MBoepd for the year ended December 31, 2024. The increase was primarily due to 21.9 MBoepd in production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024 as well as 2.2 MBoepd from the EnVen Acquisition that closed mid-first quarter of 2023. Additionally, we recognized incremental 10.0 MBoepd of production from the Venice and Lime Rock wells, which tie back to our Ram Powell facility and commenced initial production late in the fourth quarter of 2023. These increases were partially offset by a decrease of 4.7 MBoepd due to well performance and natural production declines primarily in our Phoenix Field, Green Canyon 18 Field and Pompano Field. Additionally, there was a decrease of 1.2 MBoepd of production due to disruptions from weather events in the U.S. Gulf of America as well as approximately 1.2 MBoepd of deferred production resulting from third party downtime associated with the HP-I dry-dock in our Phoenix Field.

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Operating Expenses

Lease Operating Expense

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

Total lease operating expenses for the year ended December 31, 2024 increased by approximately $176.4 million, or 45%. The increase is primarily related to lease operating expenses of $147.0 million incurred in connection with assets acquired from the QuarterNorth Acquisition. Additionally, there was a $58.6 million increase in facility and workover expenses primarily attributable to the HP-I and major well workover expenses at the Phoenix Field and Garden Banks 506 Field associated with our historical operations.

Depreciation, Depletion and Amortization

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

Depreciation, depletion and amortization expense for the year ended December 31, 2024 increased by approximately $360.0 million, or 54%. This increase was primarily driven by the increased production volumes of 26.3 MBoepd discussed above and to a lesser extent an increase of $2.87 per Boe, or 11% in the depletion rate on our proved oil and natural gas properties due to our amortization base increasing disproportionately to the increase in our reserve base. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures.

General and Administrative Expense

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

General and administrative expense for the year ended December 31, 2024, increased by approximately $43.0 million, or 27%. This increase was primarily related to the Upstream Segment transaction costs, severance costs and additional general and administrative expenses related to the QuarterNorth Acquisition of $43.6 million or $1.29 per Boe. The CCS Segment reflects an increase in transaction costs and severance costs of $7.9 million related to the TLCS Divestiture. There was an increase to the Upstream Segment of $5.0 million in severance expense related to the departure of the Company’s former President and Chief Executive Officer as discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — Employee Benefits Plans and Share-Based Compensation. Additionally, there was an increase in contractor and payroll expenses due to an increase in employee headcount primarily related to the QuarterNorth Acquisition. These increases were partially offset by a decrease in the Upstream Segment transaction costs for the EnVen Acquisition of $40.6 million or $1.68 per Boe. Additionally, the CCS Segment expenses decreased by $10.0 million due to the TLCS Divestiture. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion.

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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):

Accretion Expense — During the year ended December 31, 2024, we recorded $117.6 million of accretion expense compared to $86.2 million during the year ended December 31, 2023. The change is primarily the result of the increase in accretion associated with the higher asset retirement obligations subject to accretion expense including $15.4 million of incremental accretion expense related to the asset retirement obligations assumed as part of the QuarterNorth Acquisition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion.

Other Operating (Income) Expense — During the year ended December 31, 2024, we recognized a gain of $100.4 million on the TLCS Divestiture. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion. This gain was partially offset by $8.6 million of estimated decommissioning obligations primarily as a result of unrelated parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. During the year ended December 31, 2023, we recognized a gain of $66.2 million on the 2023 Mexico Divestiture. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion. This gain was partially offset by $11.9 million of estimated decommissioning obligations primarily as a result of unrelated parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency.

Interest Expense — During the year ended December 31, 2024, we recorded $187.6 million of interest expense compared to $173.1 million during the year ended December 31, 2023. The change is primarily a result of an increase in debt outstanding offset by a lower rate of interest on these instruments. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt. Additionally, there was an increase of $4.9 million of fees associated with the unutilized bridge loan during the year ended December 31, 2024. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion.

Price Risk Management Activities — Price risk management activities for year ended December 31, 2024 resulted in a decrease of approximately $82.4 million, or 102%. The expense of $1.5 million for the year ended December 31, 2024 consisted of $6.2 million in non-cash losses from the decrease in the fair value of our open derivative contracts offset by $4.7 million in cash settlement gains. The income of $80.9 million for the year ended December 31, 2023 consisted of $90.4 million in non-cash gains from the increase in the fair value of our open derivative contracts offset by $9.5 million in cash settlement losses.

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 2026, 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) Expense — During the year ended December 31, 2024, we recorded equity losses of $10.3 million. During the year ended December 31, 2023, we recorded $12.1 million of equity losses offset by an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron U.S.A. Inc. (“Chevron”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments for additional information.

Other (Income) Expense — During the year ended December 31, 2024, we recorded a $60.3 million loss on extinguishment of debt in conjunction with the redemption of the 12.00% Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) and 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information.

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Income Tax Benefit (Expense) — During the year ended December 31, 2024, we recorded $5.0 million of income tax expense compared to $60.6 million of income tax benefit during the year ended December 31, 2023. The expense of $5.0 million for the year ended December 31, 2024 is primarily due to a non-cash tax expense of $38.2 million related to the effect of a change in state tax rate, offset with a non-cash tax benefit of $20.3 million related to the partial release of the valuation allowance for certain of our state deferred tax assets and an income tax benefit of $10.7 million related to current year activity inclusive of permanent differences. For the year ended December 31, 2023, we recorded $106.8 million of income tax benefit related to the release of the valuation allowance for our federal deferred tax assets partially offset with an income tax expense of $31.1 million related to current year activity inclusive of permanent differences. The realization of our deferred tax assets 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 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 12 — 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 15 — 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 and non-cash equity-based compensation expense.

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

(1)
For the year ended December 31, 2024, transaction expenses include $39.1 million in costs related to the QuarterNorth Acquisition, inclusive of $22.2 million in severance expense, $8.5 million in costs related to the TLCS Divestiture, inclusive of a net $3.0 million in severance expense, and $5.0 million in severance expense related to the departure of the Company’s President and Chief Executive Officer as discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — Employee Benefits Plans and Share-Based Compensation. Transaction expenses include $40.4 million and $9.0 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expense for the years ended December 31, 2023 and 2022, respectively. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisition and Divestitures and Note 11 — Employee Benefits Plans and Share-Based Compensation. Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. For the year ended December 31, 2024, the amount includes a gain of $100.4 million related to the TLCS Divestiture and a $9.5 million gain related to an increase in fair value of a service credit acquired via the QuarterNorth Acquisition. For the year ended December 31, 2023, the amount includes a $66.2 million gain on the 2023 Mexico Divestiture. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures. The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million and $1.4 million for the years ended December 31, 2023 and 2022, respectively. Additionally, it includes a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron for the year ended December 31, 2022. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments. 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 15 — Commitments and Contingencies.

(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 15 — 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, share repurchases and for general corporate purposes. The cost of borrowing under our Bank Credit Facility is influenced by changes in the federal funds rate. As interest rates increase, it becomes more expensive to borrow money while interest rate cuts make it less expensive to borrow money. Our working capital deficit has decreased since December 31, 2023 primarily due to increased cash and cash equivalents of $74.5 million and redemption $30.0 million in the current portion of principal amount of the 11.75% Notes using the proceeds from the issuance of the Senior Notes. For additional details on the 11.75% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Our Bank Credit Facility currently has a borrowing base of $925.0 million but is subject to an $800.0 million availability cap. As of December 31, 2024, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $865.8 million or $990.8 million inclusive of the $125.0 million availability cap requiring certain lender approval. If we are unable to replace proved reserves either through acquisitions or new drilling activity, our borrowing base will likely be reduced at our next redetermination which is expected second quarter of 2025 and our available liquidity may be negatively impacted unless offset by cash generated from our operating activities. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information.

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We fund drilling, completions 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 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.

Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the year ended December 31, 2024 (in thousands):

(1)
Asset management consists of capital expenditures for development related activities primarily associated with recompletions and improvements to our facilities and infrastructure.

(2)
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 15 — Commitments and Contingencies for additional information on decommissioning obligations.

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund our 2025 Upstream capital spending program of $500.0 million to $540.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $120.0 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.

Common Stock Repurchase Program — Our Board of Directors authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits. During the year ended December 31, 2023 and six months ended June 30, 2024, we repurchased 3.4 million shares for $47.5 million and 3.8 million shares for $42.9 million, respectively. On July 22, 2024, our Board authorized an additional $150.0 million to our previously approved limit increasing the amount remaining under our authorized plan to $159.6 million. During the three months ended September 30, 2024, we repurchased 0.2 million shares for $2.2 million. There were no shares of common stock repurchased during the three months ended December 31, 2024. We have repurchased an aggregate of 7.4 million shares under our authorized program for a total of $92.6 million resulting in approximately $157.4 million remaining under our authorized program as of December 31, 2024. All repurchased shares are held in treasury.

Repurchases may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.

The IRA 2022 provides for, among other things, the imposition of a 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations such as us after December 31, 2022. Accordingly, the excise tax applies to our share repurchase program. The excise tax payment is non-deductible for income tax purposes. Subject to certain exceptions and adjustments, the excise tax equals 1% of the fair market value of the stock repurchased by a corporation during the applicable tax year. The repurchase amount subject to the excise tax is generally reduced by the fair market value of any stock issued by a corporation during a taxable year, including the fair market value of any stock issued or provided to employees of a corporation or employees of certain of its subsidiaries. In the past, there have been proposals to increase the amount of the excise tax from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any change can take effect. We do not anticipate paying any excise tax in 2024 based on the fair market value of the stock issued during 2024.

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Overview of Cash Flow Activities — The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands):

Operating Activities — Net cash provided by operating activities increased $443.5 million in 2024 compared to 2023 primarily attributable to an increase in revenues that was slightly offset by an increase in lease operating expense of $339.3 million. Additionally, there were $4.7 million of net cash settlement receipts on derivative instruments during the year ended December 31, 2024 compared to $9.5 million in net cash settlement payments on derivative instruments during the corresponding period in 2023.

Investing Activities — Net cash used in investing activities increased $807.7 million in 2024 compared to 2023 primarily due to cash paid for acquisitions of $936.2 million, net of cash acquired, of which $916.0 million related to the QuarterNorth Acquisition. Cash proceeds of $146.7 million were received from the TLCS Divestiture during the year ended December 31, 2024 compared to $74.9 million of net proceeds from the 2023 Mexico Divestiture during the corresponding period in 2023. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information. Additionally, cash capital expenditures decreased $52.5 million.

Financing Activities — Net cash provided by financing activities increased $350.7 million in 2024 compared to 2023. During the year ended December 31, 2024, the issuance of the Senior Notes in February 2024 generated $1,217.1 million after deferred financing costs. The net proceeds from the Senior Notes funded the $897.1 million redemption of the 12.00% Notes and the 11.75% Notes and partially funded the cash portion of the QuarterNorth Acquisition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information. Additionally, on January 17, 2024, we entered into an underwritten public offering of 34.5 million shares of our common stock, which generated net proceeds of $387.7 million after deducting underwriting discounts of $15.1 million and offering expenses of $0.8 million. The net proceeds from this equity offering partially funded the cash portion of the QuarterNorth Acquisition. Furthermore, Bank Credit Facility net repayments of $200.0 million were made during the year ended December 31, 2024 due to a management goal to maintain or reduce our leverage ratio coupled with a commodity price environment that supported debt repayments to achieve such goal. We had net borrowings from the Bank Credit Facility of $200.0 million during the corresponding period in 2023 due to the funding of the EnVen Acquisition, working capital needs and capital expenditures.

Overview of Debt Instruments

Financing Arrangements — As of December 31, 2024, total debt, net of discount and deferred financing costs, was approximately $1,221.4 million, comprised of our $1,250.0 million aggregate principal amount of the 9.000% Notes and 9.375% Notes (as defined herein) and no outstanding borrowings under our Bank Credit Facility. We were in compliance with all debt covenants at December 31, 2024. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Bank Credit Facility – matures March 2027 — We maintain a Bank Credit Facility with a syndicate of financial institutions. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year based on a proved reserves report that we deliver to the administrative agent of our Bank Credit Facility. For additional details on our Bank Credit Facility, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Redemption of the 12.00% Second-Priority Senior Secured Notes—due January 2026 — On February 7, 2024, we redeemed $638.5 million aggregate principal amount of the 12.00% Notes using the proceeds from the issuance of the Senior Notes. For additional details on the 12.00% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Redemption of the 11.75% Senior Secured Second Lien Notes—due April 2026 — On February 7, 2024, we redeemed $227.5 million aggregate principal amount of the 11.75% Notes using the proceeds from the issuance of the Senior Notes. For additional details on the 11.75% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

9.000% Second-Priority Senior Secured Notes—due February 2029 — The 9.000% Notes were issued pursuant to the 9.000% Notes indenture. The 9.000% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indenture. The 9.000% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.000% Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1.

9.375% Second-Priority Senior Secured Notes—due February 2031 — The 9.375% Notes were issued pursuant to the 9.375% Notes indenture. The 9.375% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indenture. The 9.375% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1.

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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, 2024 (in thousands):

(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)
This table does not include our estimated discounted liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $1,149.7 million as of December 31, 2024. For additional information regarding these liabilities, please see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 9 — Asset Retirement Obligations. Additionally, this table does not include liabilities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitment and Contingencies.

Performance Obligations — As of December 31, 2024, we had secured performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of America. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $42.4 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See the subsection entitled “— Known Trends and Uncertainties — Financial Assurance Requirements and — Financial Assurance Market Outlook” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition.

For additional information about certain of our obligations and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — 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.

Proved Reserve Estimates — We account for our oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural gas properties and whether the carrying value of our proved oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test.

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.

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Our estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. Our reserves at December 31, 2024 were fully engineered by NSAI, while prior year reserve estimates, including as of December 31, 2023 and 2022, were audited by NSAI. See Part I, Items 1 and 2. Business and Properties—Summary of Reserves for further discussion. 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.

The depletion of our proved oil and natural gas properties is calculated using the unit-of-production method based on proved oil and gas reserves. If the proved reserves used had been a 10 percent lower, depreciation, depletion and amortization in the year ended December 31, 2024 would have increased by an estimated $108.1 million. Furthermore, 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. We estimate the net downward revisions of previous reserve volume estimates accounted for approximately $162.0 million of the standardized measure of our total reserves from December 31, 2023 to December 31, 2024. The Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties during the years ended December 31, 2024, 2023 and 2022.

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to P&A and decommission the associated assets.

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

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

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

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

Determination of Fair Value in Business Combinations — We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. The amount of goodwill or bargain purchase gain recognized, if any, is determined based on the consideration transferred compared to the acquisition date amounts of the identifiable net assets acquired.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties.

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The fair value of proved and oil natural gas properties as of the acquisition date are based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments are applied to proved developed non-producing, proved undeveloped, probable and possible reserves to reflect the relative uncertainty of each reserve class.

The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value. Historically there has been significant volatility in oil, natural gas and NGL prices and estimates of such future prices are inherently imprecise. Additionally, the actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. A higher discount rate decreases the net present value of cash flows.

Recently Adopted Accounting Standards

Information on Recently Adopted Accounting Standards that impacted our consolidated financial statements and related disclosures is incorporated by reference to Part IV, Item 15. Exhibit and Financial Statement Schedules — Note 1 — Organization, Nature of Business and Basis of Presentation.

Recently Issued Accounting Standards

Information on Recently Issued Accounting Standards that could potentially impact our consolidated financial statements and related disclosures is incorporated by reference to Part IV, Item 15. Exhibit and Financial Statement Schedules — Note 1 — Organization, Nature of Business and Basis of Presentation.

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 2023 and 2022 items and year-to-year comparisons between 2023 and 2022. Discussions of 2021 items and year-to-year comparisons between 2022 and 2021 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, 2022 filed with the SEC.

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 low carbon solutions 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. We are also utilizing our expertise to develop CCS projects to help reduce industrial emissions along the coast of the U.S. Gulf of Mexico.

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

Outlook

We operate within an industry sector directly impacted by the energy transition. The energy transition will require both significant new investments in low-carbon energies and continued use of traditional hydrocarbons to meet the expected energy demand of an expanding global economy.

Our historical focus in the Gulf of Mexico results in an asset profile that differentiates us from the typical shale-driven onshore exploration and production companies. We are continuing to build operational scale. We expect that the QuarterNorth Acquisition, discussed below, will add scale to our business both in terms of production and operated infrastructure, while also diversifying our production across a broader asset base. While we are currently a pure play Gulf of Mexico company, diversification outside of our existing operational areas is always a possibility.

Oil and gas prices are expected to remain relatively stable in 2024. However, geopolitical tensions may contribute to hydrocarbon price volatility. For now, it looks like inflation will return to normal without a recession. Future changes to the benchmark interest rate remain uncertain. However, a modest reduction to the benchmark interest rate is the most likely scenario for 2024. We expect to scale back planned capital expenditures in 2024 compared to 2023. We remain exposed to increasing regulatory scrutiny and potential operational disruptions from weather-related events in the Gulf of Mexico. The limited scope of BOEM's 2024-2029 offshore oil and gas leasing program is disappointing to offshore producers. However, we have the ability to increase our acreage inventory through exchanges and mergers and acquisitions.

Significant Developments

The following encompasses significant developments since the filing of our Annual Report on Form 10-K for the year ended December 31, 2022:

QuarterNorth Acquisition — On January 13, 2024, we executed the QuarterNorth Merger Agreement to acquire QuarterNorth, a privately-held U.S Gulf of Mexico exploration and production company. The QuarterNorth Acquisition is expected to close during the first quarter of 2024. Consideration for the QuarterNorth Acquisition consists of (i) approximately $964.9 million in cash, (ii) the amount of net unrestricted cash of QuarterNorth as of December 31, 2023 and (iii) 24.8 million shares of the Company’s common stock.

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Equity Offering — On January 22, 2024, we closed an upsized firm commitment underwritten public offering (the “January Equity Offering”) of 34,500,000 shares of our common stock, resulting in net proceeds to us of approximately $388.5 million, after deducting underwriting discounts and commissions and before estimated offering expenses. We intend to use the net proceeds from the January Equity Offering to fund a portion of the cash consideration for the QuarterNorth Acquisition. However, the QuarterNorth Acquisition remains subject to certain conditions to closing. Pending the use of the proceeds of the January Equity Offering as described above, we may temporarily use all or a portion of such proceeds to reduce the borrowings outstanding under our Bank Credit Facility. In the event that the QuarterNorth Acquisition is not completed, the proceeds from the January Equity Offering will be used for general corporate purposes.

Debt Offering — On February 7, 2024, Talos Production, Inc. issued in an upsized offering (the “Debt Offering”) $1,250.0 million in aggregate principal amount of second-priority senior secured notes, consisting of $625.0 million aggregate principal amount of 9.000% second-priority senior secured notes due 2029 (the “9.000% Notes”) and $625.0 million aggregate principal amount of 9.375% second-priority senior secured notes due 2031 (the “9.375% Notes” and, together with the 9.000% Notes, the “New Senior Notes”), in a private offering to eligible purchasers that is exempt from registration under the Securities Act. The New Senior Notes were issued pursuant to an indenture governing the 9.000% Notes (the “9.000% Notes Indenture”) and an indenture governing the 9.375% Notes (the “9.375% Notes Indenture” and, together with the 9.000% Notes Indenture, the “Indentures”), each dated as of February 7, 2024 and by and among the Company, Talos Production Inc., the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The New Senior Notes rank equally in right of payment with all existing and future senior obligations of the issuer and the guarantors thereto. The issuance of the New Senior Notes on February 7, 2024, resulted in $1,250.0 million gross proceeds. The net proceeds from the Debt Offering (i) are expected to fund a portion of the cash consideration for the pending QuarterNorth Acquisition as discussed above, (ii) funded the redemption (the “Redemptions”) of all of the outstanding 11.75% Notes (defined below) and 12.00% Notes (defined below) (the “Senior Notes”), and (iii) paid premiums, fees and expenses related to the Redemptions and the issuance of the New Senior Notes. We intend to use any remaining net proceeds for general corporate purposes, which may include the repayment of a portion of the outstanding borrowings under the Bank Credit Facility.

An aggregate of $340 million principal amount of the New Senior Notes will be subject to a “special mandatory redemption” in the event that the transactions contemplated by the QuarterNorth Merger Agreement are not consummated on or before May 31, 2024 (or up to September 30, 2024 solely in the event the parties require additional time to satisfy certain requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, pursuant to the terms of the QuarterNorth Merger Agreement), or if we notify the trustee of the New Senior Notes that we will not pursue the consummation of the QuarterNorth Acquisition.

Mexico Divestiture — On September 27, 2023, we sold a 49.9% interest in Talos Energy Mexico 7, S. de R.L. de C.V., a wholly owned subsidiary of the Company, to Zamajal, S.A. de C.V., a wholly owned subsidiary of Grupo Carso (the “Mexico Divestiture”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Common Stock Repurchase Program — On March 20, 2023, we announced that our Board of Directors approved a $100.0 million common stock repurchase program. As of December 31, 2023, we have repurchased 3.4 million shares for a total of $47.5 million resulting in $52.5 million remaining under the authorized program. All repurchased shares are held in treasury.

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.

EnVen Acquisition — On February 13, 2023, we acquired EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

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. The next dry-dock is scheduled for the first half of 2024 with a projected shut-in period of approximately 55 days.

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.

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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.

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, 2023 through December 31, 2023, the daily spot prices for NYMEX WTI crude oil ranged from a high of $93.67 per Bbl to a low of $66.61 per Bbl and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $3.78 per MMBtu to a low of $1.74 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, 2023.

The U.S. Energy Information Administration (“EIA”) published its February 2024 Short-Term Energy Outlook on February 6, 2024. The EIA expects natural gas prices to average $2.65 per MMBtu in 2024, and rise to an average of $2.94 per MMBtu in 2025, up from an average of $2.54 per MMBtu in 2023. Prices are expected to increase because of slowing growth in natural gas production and increasing U.S. liquefied natural gas exports, particularly in 2025 following the addition of new export capacity in late 2024. However, the EIA expects upward price pressures to be limited by relatively flat consumption of natural gas in the electric power sector and persistently high inventories. The EIA also expects the NYMEX WTI spot price will average $77.68 per Bbl in 2024 and then fall to $74.98 per Bbl in 2025 when it expects production growth will slightly outpace demand growth, allowing inventories to build modestly and place some downward pressure on crude oil prices. Recent developments in the Middle East increase the risk for supply disruptions over the EIA forecast, which could result in higher and more volatile prices than the EIA currently forecast. Heightened tensions around the critical Red Sea shipping channel and other developments in the Middle East have added upward price pressure since early December 2023 and have the potential to disrupt global oil trade flows and drive up global oil prices further should they escalate or persist.

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. In 2022 and 2023, the Fed raised its benchmark interest rate 11 times. The latest interest rate hike in July 2023 increased the federal funds rate to a range of 5.25%-5.50%, its highest level since 2001. The Fed wants inflation to return to its 2% goal over time, and even though inflation is declining, it is still high in absolute terms. Future changes to the benchmark interest rate remain uncertain.

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 2023, 2022 and 2021 our ceiling test computations for our U.S. oil and gas properties did not result in a write down. At December 31, 2023, the Company’s ceiling test computation was based on SEC pricing of $78.56 per Bbl of oil, $2.75 per Mcf of natural gas and $18.77 per Bbl of NGLs.

If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2023 and ending December 1, 2023 used in the determination of the SEC pricing was 10% lower, resulting in $70.73 per Bbl of oil, $2.48 per Mcf of natural gas and $16.89 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by $321.9 million.

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.

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BOEM Bonding Requirements — In 2016, BOEM issued the 2016 NTL, which bolstered supplemental bonding requirements for offshore oil and gas lessees. The 2016 NTL was first paused under the Trump Administration, and then in 2020, rescinded by BOEM. In October 2020, BOEM 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. The DOI under the Biden Administration elected to separate BOEM and BSEE portions of the supplemental bonding requirements.

In April 2023, BSEE published its Final Rule entitled, “Risk Management, Financial Assurance, and Loss Prevention – Decommissioning Activities and Obligations,” wherein BSEE clarified decommissioning responsibilities for RUE grant holders and formalized BSEE’s policies regarding performance by predecessors ordered to decommission OCS facilities. The final rule withdraws the proposal in the October 2020 proposed rule to amend BSEE’s regulations requiring the agency to proceed in reverse chronological order against predecessor lessees, owners of operating rights and grant holders when requiring such entities to perform their accrued decommissioning obligations upon failure to perform by current lessees, owners, or holders. Under the final rule, BSEE may issue an order to predecessors to perform accrued decommissioning obligations, including beginning maintenance and monitoring within thirty days, designating an operator for decommissioning within ninety days, and submitting a decommissioning plan within one hundred fifty days.

On June 29, 2023, BOEM published a proposed rule that, if adopted as initially proposed, would substantially revise the supplemental financial assurance requirements applicable to offshore oil and gas operations. The proposed rule would change the current criteria used to determine whether OCS lease and grant holders are required to secure supplemental financial assurance. The proposed rule would no longer use the current 5-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead proposes a simplified test: (1) the credit rating of the lessee and, where applicable, (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. Under the proposed rule, BOEM would no longer consider or rely upon the financial strength of predecessors in determining whether, or how much, supplemental financial assurance should be provided by current lessees and grant holders. BOEM would not require supplemental financial assurance above the base bond requirements in three cases: (1) where a lessee has an investment grade credit rating (i.e., a credit rating from a Nationally Recognized Statistical Ratings Organizations, or NRSRO, that is greater than or equal to either BBB- from S&P or Baa3 from Moody’s, or its equivalent, or a proxy credit rating greater than or equal to either BBB- or Baa3, as determined by the Regional Director and based upon a company’s audited financial information with an accompanying auditor’s certificate); (2) where there are multiple co-lessees on a lease and any one of those lessees meets the credit rating threshold; and (3) for any lease on which all lessees are rated below investment grade, where the value of the lease’s proved oil and gas reserves is at least three times that of the estimated decommissioning cost estimate. BOEM proposes to phase in compliance with the new requirements over a three-year period. The extended public comment period closed on September 7, 2023, and BOEM is reviewing the comments received. At this time, we cannot predict whether BOEM will adopt the final rule in its current form or at all, the timing for any final decision, or whether any changes will result from the public notice and comment process, but will continue to monitor this rulemaking.

Moreover, 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 obligations. In August 2021, BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements 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. We may be unable to provide the financial assurances in the amounts and under the time periods required by BOEM if it submits future demands to cover our decommissioning obligations. If in the future BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our production and other operations or cancel our applicable federal offshore leases. Our ability to obtain adequate supplemental financial assurance (pursuant to a final BOEM rule that is substantially consistent with the June 2023 proposed rule or otherwise), including the future cost of compliance with respect to supplemental bonding, could materially and adversely affect our liquidity, financial condition, cash flows, business, properties and results of operations.

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.

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Hurricanes, Tropical Storms and Loop Currents — Since our operations are in the U.S. Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes, tropical storms and loop currents on production and capital projects. Significant impacts could include reductions and/or deferrals of future oil and natural gas production and revenues and increased lease operating expenses for evacuations and repairs.

Five-Year Offshore Oil and Gas Leasing Program Update — Under the OCSLA, as amended, 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. The IRA, which President Biden signed into law on August 16, 2022, reinstated Lease Sale 257 held in November 2021, and required 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 ten (10) blocks and awarded leases on nine (9) blocks. In January 2023, BOEM released its final environmental impact statement for Lease Sales 259 and 261 and, in March 2023, announced the results of Lease Sale 259, in which we were the high bidder on four offshore blocks, and were awarded leases on all four blocks. Lease Sale 261 was scheduled to be held on November 8, 2023, pursuant to a September 21, 2023 court order from the United States District Court for the Western District of Louisiana, as amended by a September 25, 2023 court order from the United States Court of Appeals for the Fifth Circuit. However, on October 26, 2023, the United States Court of Appeals for the Fifth Circuit stayed its and the District Court’s ruling, scheduling oral arguments for November 13, 2023. On November 2, 2023, BOEM announced the postponement of Lease Sale 261 as a result of the United States Court of Appeals for the Fifth Circuit’s October 26, 2023 order. Pursuant to the United States Court of Appeals for the Fifth Circuit’s November 14, 2023 order, BOEM held Lease Sale 261 on December 20, 2023, in which we were the high bidder on thirteen offshore blocks and were awarded four leases as of February 16, 2024. As BOEM is still in its bid evaluation, we are awaiting BOEM’s award decisions on our remaining high bids.

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 (“PFP”) 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 PFP, 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 PP included no more than ten potential lease sales in the Gulf of Mexico. On September 29, 2023, the PFP for 2024-2029 was published and includes a maximum of three potential oil and gas lease sales in the Gulf of Mexico scheduled to be held in years 2025, 2027 and 2029. On December 14, 2023, the Secretary of the Interior approved the final program in a combined decision memo and Record of Decision and the final program is set to become effective on July 1, 2024.

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.

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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:

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.

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.

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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.

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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, except per unit data):

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

Volumetric Analysis — Production volumes increased by 6.8 MBoepd to 66.3 MBoepd for the year ended December 31, 2023. The increase was primarily due to 17.6 MBoepd in production from the oil and natural gas assets acquired in the EnVen Acquisition. Additionally, production volumes increased 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 during 2022. These increases were partially offset by a decrease of 13.4 MBoepd due to well performance and natural production declines primarily in our Phoenix Field, Green Canyon 18 Field and Pompano Field.

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Operating Expenses

Lease Operating Expense

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

Total lease operating expenses for the year ended December 31, 2023 increased by approximately $81.5 million, or 26%. The increase is primarily related to lease operating expenses of $86.8 million incurred in connection with assets acquired from the EnVen Acquisition. Additionally, there was a $11.3 million decrease in production handling fees related to reimbursements for costs from certain third parties related to our historical operations. This increase was partially offset by a $17.1 million decrease in facility and workover expense related to repairs and maintenance at the Phoenix Field compared to the same period in 2022.

Depreciation, Depletion and Amortization

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

Depreciation, depletion and amortization expense for the year ended December 31, 2023 increased by approximately $248.9 million, or 60%. This increase was primarily due to an increase of $8.28 per Boe, or 44% in the depletion rate on our proved oil and natural gas properties due to an increase in our proved properties and related production primarily related to the assets acquired as part of the EnVen Acquisition, which resulted in $176.3 million of additional depletion. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures” for further discussion on the EnVen Acquisition. Additionally, the depletion rate increased due to the extension of the HP-I lease during the fourth quarter of 2022. 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 and on a cost per Boe production basis for the Upstream Segment. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):

General and administrative expense for the year ended December 31, 2023, increased by approximately $58.7 million, or 59%. This increase was primarily related to higher Upstream Segment transaction costs for the closing and continued integration of the EnVen Acquisition of $31.4 million or $1.26 per Boe. The Upstream Segment also had an increase in legal fees of $5.1 million or $0.21 per Boe due to the Dunwoody litigation assumed as part of the EnVen Acquisition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies for further discussion. Additionally, there was an increase in payroll expense due to additional employee headcount primarily related to the EnVen Acquisition. These increases were partially offset by a decrease in non-cash equity-based compensation of $3.0 million, primarily due to a forfeiture during the third quarter of 2023.

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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):

Accretion Expense — During the year ended December 31, 2023, we recorded $86.2 million of accretion expense compared to $56.0 million during the year ended December 31, 2022. The change is primarily the result of the increase in accretion associated with the asset retirement obligations assumed as part of the EnVen Acquisition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion.

Other Operating (Income) Expense — During the year ended December 31, 2023, we recognized a gain of $66.2 million on the Mexico Divestiture. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion. This gain was partially offset by $11.9 million of estimated decommissioning obligations primarily as a result of unrelated parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. During the year ended December 31, 2022, we recorded $31.6 million of estimated decommissioning obligations. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies.

Interest Expense — During the year ended December 31, 2023, we recorded $173.1 million of interest expense compared to $125.5 million during the year ended December 31, 2022. The change is primarily a result of the increase in interest associated with the 11.75% Notes assumed as part of the EnVen Acquisition. Additionally, there was an increase in interest associated with the Bank Credit Facility due to increased interest rates and average borrowings when compared to the same period in 2022. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Price Risk Management Activities — Price risk management activities for year ended December 31, 2023 resulted in a decrease of approximately $353.1 million, or 130%. The income of $80.9 million for the year ended December 31, 2023 consisted of $90.4 million in non-cash gains from the increase in the fair value of our open derivative contracts offset by $9.5 million in cash settlement losses. The expense of $272.2 million for the year ended December 31, 2022 consisted of $425.6 million in cash settlement losses and $153.4 million in non-cash gains from the increase 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 2025, 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, 2023, we recorded $12.1 million of equity losses offset by an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron. During the year ended December 31, 2022, we recorded a $13.9 million gain on the partial sale and $1.4 million gain on the funding of the capital carry 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 7 — Equity Method Investments for additional information.

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 14 — 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 8 — Debt.

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Income Tax Benefit (Expense) — During the year ended December 31, 2023, we recorded $60.6 million of income tax benefit compared to $2.5 million of income tax expense during the year ended December 31, 2022, primarily due to a non-cash tax benefit of $106.8 million related to the release of the valuation allowance for our deferred tax assets partially offset with an income tax expense of $31.1 million related to current year activity inclusive of permanent differences for the year ended December 31, 2023. 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 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 11 — 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 14 — 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 and non-cash equity-based compensation expense.

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

(1)
Transaction expenses include $40.4 million and $9.0 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expenses for the years ended December 31, 2023 and 2022, respectively. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures and Note 10 — Employee Benefit Plans and Share-Based Compensation. 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, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures. The amount includes a gain on the funding of the capital carry of our investment in Bayou Bend by Chevron of $8.6 million and $1.4 million for the year ended December 31, 2023 and 2022, respectively. Additionally, it includes a $13.9 million gain on the partial sale of our investment in Bayou Bend to Chevron for the year ended December 31, 2022. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments. 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 14 — Commitments and Contingencies.

(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 14 — 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, share repurchases and for general corporate purposes. The cost of borrowing under our Bank Credit Facility has increased. By raising its federal funds rate, the Fed is making it more expensive to borrow money. Our working capital deficit has decreased since December 31, 2022 primarily due to a decrease of $61.1 million in liabilities from price risk management activities and an increase of $11.1 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, 2023, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $787.9 million.

We fund drilling, completions 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 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. We are continuing to explore a capital raise to finance the accelerated growth of our CCS segment.

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Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the year ended December 31, 2023 (in thousands):

(1)
Asset management consists of capital expenditures for development-related

activities primarily associated with recompletions and improvements to our facilities and infrastructure.

(2)
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 14 — Commitments and Contingencies for additional information on decommissioning obligations.

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund our board approved 2024 Upstream capital spending program of $565.0 million to $595.0 million and plugging & abandonment and decommissioning obligations of $90.0 million to $100.0 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.

Common Stock Repurchase Program — Our Board of Directors authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits. In March and June of 2023, we repurchased 1.9 million shares for $26.6 million and 1.5 million shares for $20.9 million, respectively. As of December 31, 2023, there is $52.5 million remaining under the authorized program. All repurchased shares are held in treasury.

Repurchases may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.

The IRA 2022 provides for, among other things, the imposition of a new 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations such as us after December 31, 2022. Accordingly, the excise tax applies to our share repurchase program. The excise tax payment is non-deductible for income tax purposes. Subject to certain exceptions and adjustments, the excise tax equals 1% of the fair market value of the stock repurchased by a corporation during the applicable tax year. The repurchase amount subject to the excise tax is generally reduced by the fair market value of any stock issued by a corporation during a taxable year, including the fair market value of any stock issued or provided to employees of a corporation or employees of certain of its subsidiaries. The current federal administration has proposed increasing the excise tax amount from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any change can take effect. We do not anticipate paying any excise tax in 2023 based on the fair market value of the stock issuance in connection to the EnVen Acquisition.

Overview of Cash Flow Activities — The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands):

Operating Activities — Net cash provided by operating activities decreased $190.7 million in 2023 compared to 2022 primarily attributable to a decrease in revenues combined with an increase in lease operating expense of $275.6 million.

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Investing Activities — Net Cash used in investing activities increased $200.6 million in 2023 compared to 2022 primarily due to an increase in capital expenditures of $238.3 million. The capital expenditure budget for 2023 included projects related to the EnVen Acquisition. Additionally, we had an increase in contributions to equity method investees of $27.2 million and investment in intangibles of $12.4 million. This was offset by cash proceeds of $74.9 million from the Mexico Divestiture. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Financing Activities — Net cash used in financing activities increased $508.9 million in 2023 compared to 2022. We had net borrowings from the Bank Credit Facility of $200.0 million for the year ended December 31, 2023 due to the funding of the EnVen Acquisition, working capital needs and capital expenditures. We had net repayments of $375.0 million during the same period in 2022 due to a management goal to reduce our leverage ratio coupled with a commodity price environment that supported debt repayments to achieve such goal. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information on the EnVen Acquisition. We repurchased $47.5 million of our common stock through our share repurchase program during the year ended December 31, 2023. See the subsection entitled “— Common Stock Repurchase Program” for additional information. Additionally, there was an increase in redemption of senior notes of $11.8 million and deferred financing costs of $11.6 million in each case when compared to the same period in 2022. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Overview of Debt Instruments

Financing Arrangements — As of December 31, 2023, total debt, net of discount and deferred financing costs, was approximately $1,025.7 million, comprised of our $866.0 million aggregate principal amount of the 12.00% Notes and 11.75% Notes (as defined herein) and $200.0 million outstanding under our Bank Credit Facility. We were in compliance with all debt covenants at December 31, 2023. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — 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 8 — 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 were secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 12.00% Notes were scheduled to mature on January 15, 2026 and had interest payable semi-annually each January 15 and July 15. We made an interest payment of $38.3 million on January 16, 2024. For additional details on the 12.00% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

On January 23, 2024, we issued a conditional notice to redeem in full the 12.00% Notes at a redemption price of 103.000% of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 12.00% Notes indenture. The 12.00% Notes were redeemed on February 7, 2024 for $662.4 million utilizing the net proceeds from the Debt Offering.

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 “11.75% Notes”) with a principal amount of $257.5 million. The 11.75% Notes were scheduled to mature on April 15, 2026 and interest accrued and was paid semi-annually in cash in arrears on April 15th and October 15th of each year. The 11.75% Notes were secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The indenture governing the 11.75% Notes required the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year. For additional details on the 11.75% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

On January 26, 2024, we issued a conditional notice to redeem in full the 11.75% Notes at a redemption price of 102.938% of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 11.75% Notes indenture. We irrevocably deposited funds with the trustee sufficient to satisfy and discharge the 11.75% Notes indenture and the 11.75% Notes until redeemed on April 15, 2024 with the funds deposited with the trustee and elected to satisfy and discharge the 11.75% Notes indenture in accordance with its terms and the 11.75% Notes trustee acknowledged such discharge and satisfaction. We deposited $247.5 million with the trustee on February 7, 2024 utilizing the net proceeds from the Debt Offering.

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9.000% Second-Priority Senior Secured Notes—due February 2029 — The 9.000% Notes were issued pursuant to the 9.000% Notes indenture. The 9.000% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indenture. The 9.000% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.000% Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1.

9.375% Second-Priority Senior Secured Notes—due February 2031 — The 9.375% Notes were issued pursuant to the 9.375% Notes indenture. The 9.375% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indenture. The 9.375% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1.

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 Bank 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.

The following table presents the balance sheet information for the respective periods (in thousands):

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

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.

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The following table and discussion summarizes our material cash requirements from known contractual obligations as of December 31, 2023 (in thousands):

(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 commitments associated with our CCS Segment relating to an equity funding obligation and payments required under a sequestration agreement.

(5)
This table does not include our estimated discounted liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $897.2 million as of December 31, 2023. For additional information regarding these liabilities, please see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 9 — Asset Retirement Obligations. Additionally, this table does not include liabilities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitment and Contingencies.

Debt principal of $638.5 million associated with the 12.00% Notes reflected in the table above was redeemed on February 7, 2024 from proceeds from the Debt Offering. There was $191.8 million of interest reflected in the table above associated with the 12.00% Notes. Debt principal of $227.5 million associated with the 11.75% Notes reflected in the table above will be redeemed on April 15, 2024 from proceeds from the Debt Offering. There was $58.0 million of interest reflected in the table above associated with the 11.75% Notes. The New Senior Notes have an aggregate principal amount of $1,250.0 million with interest of $688.9 million over the life of the New Senior Notes.

Performance Obligations — As of December 31, 2023, we had secured performance bonds totaling $1.4 billion 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 $10.8 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See the subsection entitled “— Known Trends and Uncertainties — BOEM Bonding Requirements” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition.

For additional information about certain of our obligations and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — 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.

Proved Reserve Estimates — We account for our oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural gas properties and whether the value of our evaluated oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test.

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.

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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.

The depletion of our proved oil and natural gas properties is calculated using the unit-of-production method based on proved oil and gas reserves. If the proved reserves used had been a 10 percent lower, depreciation, depletion and amortization in the three months ended December 31, 2023 would have increased by an estimated $19.4 million. Furthermore, 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. Downward revisions of previous reserve quantity estimates accounted for approximately $484.4 million of the standardized measure of our total reserves from December 31, 2022 to December 31, 2023. The Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties during the years ended December 31, 2023, 2022 and 2021.

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets.

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

Income Taxes — Our provision for income taxes includes U.S. state and federal and foreign taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of December 31, 2023, we believe it is more likely than not that some or all of the benefits from our state deferred tax assets will not be realized and reduced the state deferred tax assets by a valuation allowance.

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

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

Determination of Fair Value in Business Combinations — We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. The amount of goodwill or bargain purchase gain recognized, if any, is determined based on the consideration transferred compared to the acquisition date amounts of the identifiable net assets acquired.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties.

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The fair value of proved and oil natural gas properties as of the acquisition date are based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments are applied to proved developed non-producing, proved undeveloped, probable and possible reserves to reflect the relative uncertainty of each reserve class.

The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value. Historically there has been significant volatility in oil, natural gas and NGL prices and estimates of such future prices are inherently imprecise. Additionally, the actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. A higher discount rate decreases the net present value of cash flows.

Recently Adopted Accounting Standards

None.

Recently Issued Accounting Standards

Information on Recently Issued Accounting Standards that could potentially impact our consolidated financial statements and related disclosures is incorporated by reference to Part IV, Item 15. Exhibit and Financial Statement Schedules — Note 1 — Organization, Nature of Business and Basis of Presentation.

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.

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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 CO2 sequestration leasehold in southeast Texas. Combined with the offshore Bayou Bend CCS pore space, this participation further expands our CO2 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.

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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.

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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.

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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.

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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.

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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:

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.

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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.

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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):

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):

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.

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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):

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):

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):

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.

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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):

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.

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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.

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

(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.

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Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the year ended December 31, 2022 (in thousands):

(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):

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.

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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 15th and October 15th 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 15th and October 15th 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.

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The following table presents the balance sheet information for the respective periods (in thousands):

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

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):

(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.

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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.

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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 standards also clarify fair value as an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. We follow a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows:

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

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

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

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

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

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

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

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

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets.

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

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

Revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an underlying property. Our imbalances are presented gross on our Consolidated Balance Sheets. At December 31, 2022 and 2021, our imbalance receivable was approximately $1.7 million and $1.7 million, respectively, and imbalance payable was approximately $2.5 million and $2.5 million, respectively.

Income Taxes — Our provision for income taxes includes U.S. state and federal and foreign taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of December 31, 2022, we believe it is more likely than not that some or all of the benefits from our federal and state deferred tax assets will not be realized and reduced the net federal and state deferred tax assets by a valuation allowance. We maintain a valuation allowance on most of our Mexico deferred tax assets.

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

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

Recently Adopted Accounting Standards

None.

Recently Issued Accounting Standards

There were no recently issued accounting standards material to us.

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 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 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, 2020 filed on March 11, 2021.

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. Gulf of Mexico and offshore Mexico both upstream through oil and gas exploration and production and downstream through the development of future carbon capture and storage 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 carbon capture and storage collaborative arrangements along the coast of the U.S. Gulf of Mexico.

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

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

Outlook

During 2021, commodity prices experienced significant improvement, particularly crude oil prices, due to a confluence of factors that have provided positive developments to the overall pricing environment when compared to 2020. With some exceptions, pandemic-related travel restrictions have gradually eased as governments continue to have increasing access to vaccines that help reduce the spread of COVID-19. As restrictions continue to abate, there is renewed emphasis on improving economic activity to pre-pandemic levels while managing the risk of a resurgence in COVID-19. Meanwhile, commodity prices demonstrated resiliency during the year. Producers continued to show restraint in increasing their capital expenditures even as prices increased, thereby causing a muted response in supply as demand for commodities increased. Additionally, OPEC Plus remained committed to modest increases in production during the year as the global economy recovered.

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While the current outlook for commodity prices is favorable and our operations are no longer significantly impacted by confinement restrictions, the risk of disruption to our operations continues as the emergence of a new variant of COVID-19 could adversely impact our operations, or commodity prices could significantly decline from current levels. The ongoing COVID-19 outbreak continues to evolve and, during the fourth quarter of 2021, a new variant emerged, the Omicron variant. It is difficult to assess if it will cause meaningful disruptions in economic activity across the world and if there will be any significant impacts in demand for energy. Additionally, while OPEC Plus remained committed to steady and predictable production increases throughout 2021, it is difficult to determine whether it will change its production output policy or whether its members will remain committed to the production quotas set by the organization.

In January 2022, the Energy Information Administration published its short-term energy outlook. WTI spot prices are expected to average $71.32 per Bbl for 2022. Global oil production is forecasted to outpace global oil consumption during 2022 resulting in rising global oil inventories. Oil market balances are subject to significant uncertainties which could keep oil prices volatile. Henry Hub spot prices are expected to average $3.82 per MMBtu in the first quarter of 2022 and average $3.79 per MMBtu for all of 2022.

Looking at external events impacting the oil and gas industry, the focus on the transition and evolution to cleaner forms of energy continues to accelerate as governments across the world discuss how to reduce GHG emissions. Governments will continue to emphasize the importance of utilizing cleaner sources of energy and industry-wide investments in renewables and carbon capture and storage in order to meet the emission reduction targets that will limit the impact of GHG emissions. We believe that the pressure on our industry to manage its carbon footprint will continue to grow as governments find ways to meet their carbon reduction targets. We see the transition to providing cleaner forms of energy as an opportunity to position ourselves to support our industry's efforts to reduce our carbon footprint through the use of commercially available technologies that allow us to capture and store significant volumes of CO2.

Significant Developments

The following encompasses significant developments since our Annual Report on Form 10-K for the year ended December 31, 2020:

Carbon Capture Initiatives — On February 15, 2022, we announced our entry into (i) a lease agreement for a major carbon capture and sequestration project along the Mississippi River industrial corridor and (ii) a memorandum of understanding with EnLink Midstream, LLC to jointly develop a carbon capture, transportation and sequestration joint service offering focused on the Mississippi River industrial corridor. See Part I, Items 1 and 2. Business and Properties — Carbon Capture & Sequestration for additional information regarding this project and previously announced projects.

Eugene Island Pipeline System — We have experienced approximately 30 days of unplanned third-party downtime to date in the first quarter of 2022 resulting from maintenance of the Eugene Island Pipeline System, which carries our production from the HP-I and Green Canyon 18 facilities. As of the filing of this Annual Report, the shut-in has resulted in a production impact of approximately 3.5 to 4.0 MBoepd for the first quarter of 2022 or 0.8 to 1.0 MBoepd for the full year 2022.

Zama Update — See Part I, Items 1 and 2. Business and Properties — Hydrocarbon Properties — Mexico — Block 7.

Federal Lease Sale — In November 2021, we announced that we were named as the high bidder on ten Deepwater blocks comprising 57,600 acres, or 36,720 net acres, for a net total consideration of approximately $4.8 million. As of December 31, 2021, the BOEM has not announced whether we have been awarded these leases. In January 2022, a federal judge invalidated the lease sale, finding 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.

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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.

LLOG Asset Acquisition — On November 16, 2020, we completed the acquisition of select interests in oil and natural gas assets from LLOG Exploration & Production Company, LLC (the “LLOG Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions for more information.

Castex Energy 2005 Asset Acquisition — On August 5, 2020, we completed the acquisition of select interest in oil and natural gas assets from affiliates of Castex Energy 2005 Holdco, LLC (the “Castex 2005 Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions for more information.

ILX and Castex Acquisition — On February 28, 2020 we acquired the outstanding limited liability interests in certain wholly owned subsidiaries of ILX Holdings, LLC, ILX Holdings II, LLC, ILX Holdings III LLC and Castex Energy 2014, LLC, each a related party and an affiliate with the entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (the “Riverstone Sellers”), and Castex Energy 2016, LP (together with the Riverstone Sellers, the “Sellers” and collectively, the “ILX and Castex Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions for more information.

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.

During 2020, production from the U.S. Gulf of Mexico was impacted due to precautionary shut-ins of facilities and evacuations associated with Hurricanes Hanna, Laura, Marco, Sally, Delta and Zeta and Tropical Storms Cristobal and Beta. Although there was no major storm-related damage to our facilities, we incurred production downtime associated with the shut-ins for the storms. For the year ended December 31, 2020, we estimate deferred production related to these storms was approximately 4.1 MBoepd.

Ram Powell Shut-In — Production at our Ram Powell facility was shut-in in late June 2020 while waiting for the repair of the platform’s oil export riser. We received final regulatory approvals and completed the repair of the export riser. Production commenced on November 21, 2020. For the year ended December 31, 2020, the Ram Powell facility shut-in resulted in deferred production of 2.1 MBoepd.

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.

Oil prices have benefited from the continuation of coordinated production policies by OPEC Plus and capital discipline by oil and gas producers. Despite the recent upswing in oil prices, we believe that commodity prices will remain cyclical and volatile. During January 1, 2021 through December 31, 2021, the daily spot prices for NYMEX WTI crude oil ranged from a high of $85.64 per Bbl to a low of $47.47 per Bbl and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $23.86 per MMBtu to a low of $2.43 per MMBtu. The spread between the high and low natural gas prices was caused by a severe winter storm that precipitated both an immediate constraint in the supply of and a significant increase in the demand for natural gas. 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, 2021.

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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 2021, 2020 and 2019 our ceiling test computations for our U.S. oil and gas properties resulted in a write down of nil, $267.9 million and nil, respectively. At December 31, 2021, the Company’s ceiling test computation was based on SEC pricing of $67.14 per Bbl of oil, $3.71 per Mcf of natural gas and $26.62 per Bbl of NGLs.

There is a significant degree of uncertainty with the assumptions used to estimate future undiscounted cash flows 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 undiscounted 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 finalization of the unitization and unit operating agreement, which sets out the terms on which the Block 7 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. We recorded an impairment of $18.1 million for our unproved property investment in Block 31 during the year ended December 31, 2021. See Part I, Items 1 and 2. Business and Properties — Hydrocarbon Properties — Mexico — Block 31 for additional information.

Third Party Planned Downtime — Since our operations are offshore, we are vulnerable to third party 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 United States Coast Guard, during which time we are unable to produce the Phoenix Field. The next dry-dock is scheduled for mid-2022 with an estimated shut-in lasting approximately 45 to 60 days.

BOEM Bonding Requirements — In 2016, the BOEM issued the 2016 NTL, which bolstered supplemental bonding requirements. The 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 interest holder’s decommissioning liabilities and the Biden Administration may elect to pursue more stringent supplemental bonding requirements.

Deepwater Operations — We have interests in Deepwater fields in the U.S. Gulf of Mexico. Operations in the Deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statements of operations as well as going concern issues.

Oil Spill Response Plan — We maintain a Regional Oil Spill Response Plan that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil spill response plans are generally approved by the 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.

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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:

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production volumes;

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realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;

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lease operating expenses;

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capital expenditures; and

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Adjusted EBITDA, which is discussed under “—Supplemental Non-GAAP Measure” below.

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:

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.

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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.

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.

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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.

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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):

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):

Volumetric Analysis — Production volumes increased by 9.7 MBoepd to 64.4 MBoepd for the year ended December 31, 2021. The increase in production volumes was due to an increase of 7.6 MBoepd from the Green Canyon 18 Field, primarily due to the Kaleidoscope and Tokum wells drilled as part of the Green Canyon 18 Field platform rig program. Additionally, production volumes increased 2.1 MBoepd from temporary shut-ins for repairs and maintenance on the Ram Powell Field export riser that were completed in the fourth quarter of 2020.

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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):

Total lease operating expenses for the year ended December 31, 2021 increased by approximately $37.0 million, or 15%. We had an overall increase in direct operating expenses and labor costs of $6.2 million due to the temporary shuttering of the non-operated Garden Banks Field, Vermilion Field and High Island Field related to cost cutting measures taken during the second half of 2020 because of the economic environment caused by the COVID-19 pandemic. There was an additional $19.4 million increase attributable to facility and workover expense across our portfolio. Due to the Castex 2005 Acquisition and LLOG Acquisition in the second half of 2020, we had an increase of $12.9 million in total lease operating expenses during the year ended December 31, 2021. On a per unit basis, lease operating expense decreased $0.26 per Boe to $12.07 per Boe primarily due to higher production volumes.

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):

Depreciation, depletion and amortization expense for the year ended December 31, 2021 increased by approximately $31.6 million, or 9%. This increase was primarily due to increased production of 9.7 MBoepd offset by a decrease of $1.32 per Boe, or 7% in the depletion rate on our proved oil and natural gas properties as a result of the impairment on oil and gas properties in the fourth quarter of 2020.

General and Administrative Expense

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

General and administrative expense for the year ended December 31, 2021, decreased by approximately $0.5 million, or 1%. Transaction and non-recurring costs were $5.4 million or $0.23 per Boe for 2021, which is a decrease of $9.6 million primarily due to the ILX and Castex Acquisition and Castex 2005 Acquisition in 2020. The decrease was offset with general and administrative expenses of $4.3 million incurred by our emerging carbon capture and sequestration operating segment during the year ended December 31, 2021. Additionally, general and administrative expense includes non-cash equity-based compensation of $11.0 million, or $0.47 per Boe, during the year ended December 31, 2021, which is an increase of $2.1 million. On a per unit basis, general and administrative expense decreased $0.61 per Boe.

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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):

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. During the year ended December 31, 2020, we recorded a $267.9 million write-down of our oil and natural gas properties as a result of our ceiling test evaluation for our oil and gas properties in the United States as described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 4 — Property, Plant and Equipment.

Other Operating (Income) Expense — During the year ended December 31, 2021, we recorded $21.1 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. 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. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies.

During the year ended December 31, 2020, we recorded $8.9 million in income related to our multi-year federal royalty refund claim from the ONRR. 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, 2021, we recorded $133.1 million of interest expense compared to $99.4 million during the year ended December 31, 2020. The change is primarily a result of the interest associated with the 12.00% Notes issued in January 2021 with an aggregate principal amount of $650.0 million when compared to the interest on the 11.00% Second-Priority Senior Secured Notes (the “11.00% Notes”) that were redeemed in January 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, 2021 resulted in a decrease of approximately $506.8 million, or 578%. 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. The income of $87.7 million for the year ended December 31, 2020 consisted of $143.9 million in cash settlement gains that was offset by $56.2 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 2023, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

Other (Income) Expense — 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.

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Income Tax Benefit (Expense) — During the year ended December 31, 2021, we recorded $1.6 million of income tax benefit compared to $35.6 million of income tax expense during the year ended December 31, 2020. The change is primarily a result of the recognition of a valuation allowance for its excess federal and state deferred tax assets in the year ended December 31, 2020. 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 non-recurring expenses, 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.

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The following tables present a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands):