# TALOS ENERGY INC. (TALO) FY 2023 MD&A Verbatim Item 7 Management's Discussion and Analysis from TALOS ENERGY INC.'s 10-K for fiscal year 2023. SEC filing source: https://www.sec.gov/Archives/edgar/data/1724965/000095017024022540/talo-20231231.htm Accession: 0000950170-24-022540 Filing date: 2024-02-29 Report date: 2023-12-31 Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Confidence: high Company profile: /company/TALO/ All MD&A years: /company/TALO/mda/ Previous year: /company/TALO/mda/fy2022/ (FY 2022) Next year: /company/TALO/mda/fy2024/ (FY 2024) 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. 63 Table of Contents 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. 64 Table of Contents 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. 65 Table of Contents 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. 66 Table of Contents 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. 67 Table of Contents Basis of Presentation Sources of Revenues Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs, that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives, which are reported in “Price risk management activities income (expense)” on our Consolidated Statements of Operations. The following table presents a breakout of each revenue component: [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["","2023","","2022","","2021"],["Oil","","93","%","","83","%","","86","%"],["Natural gas","","5","%","","14","%","","10","%"],["NGL","","2","%","","4","%","","4","%"]] [[/GREPCENT_TABLE]] 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. [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["","2023","","2022","","2021"],["Oil:"],["NYMEX WTI high per Bbl","$","89.43","","$","114.84","","$","81.48"],["NYMEX WTI low per Bbl","$","70.25","","$","76.44","","$","52.01"],["Average NYMEX WTI per Bbl","$","77.63","","$","94.79","","$","67.99"],["Average oil sales price per Bbl (including commodity derivatives)","$","73.59","","$","68.40","","$","49.67"],["Average oil sales price per Bbl (excluding commodity derivatives)","$","75.17","","$","93.75","","$","65.86"],["Natural Gas:"],["NYMEX Henry Hub high per MMBtu","$","3.27","","$","8.81","","$","5.51"],["NYMEX Henry Hub low per MMBtu","$","2.14","","$","4.38","","$","2.62"],["Average NYMEX Henry Hub per MMBtu","$","2.54","","$","6.42","","$","3.91"],["Average natural gas sales price per Mcf (including commodity derivatives)","$","3.32","","$","5.30","","$","3.11"],["Average natural gas sales price per Mcf (excluding commodity derivatives)","$","2.60","","$","7.06","","$","3.98"],["NGLs:"],["NGL realized price as a % of average NYMEX WTI","","23","%","","35","%","","39","%"]] [[/GREPCENT_TABLE]] 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. 68 Table of Contents 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. 69 Table of Contents Results of Operations Revenues The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and sales prices (in thousands, except per unit data): [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["","2023","","2022","","Change"],["Revenues:"],["Oil","$","1,357,732","","$","1,365,148","","$","(7,416",")"],["Natural gas","","68,034","","","227,306","","","(159,272",")"],["NGL","","32,120","","","59,526","","","(27,406",")"],["Total revenues","$","1,457,886","","$","1,651,980","","$","(194,094",")"],["Production Volumes:"],["Oil (MBbls)","","18,062","","","14,561","","","3,501"],["Natural gas (MMcf)","","26,194","","","32,215","","","(6,021",")"],["NGL (MBbls)","","1,767","","","1,793","","","(26",")"],["Total production volume (MBoe)","","24,195","","","21,723","","","2,472"],["Daily Production Volumes by Product:"],["Oil (MBblpd)","","49.5","","","39.9","","","9.6"],["Natural gas (MMcfpd)","","71.8","","","88.3","","","(16.5",")"],["NGL (MBblpd)","","4.8","","","4.9","","","(0.1",")"],["Total production volume (MBoepd)","","66.3","","","59.5","","","6.8"],["Average Sale Price per Unit:"],["Oil (per Bbl)","$","75.17","","$","93.75","","$","(18.58",")"],["Natural gas (per Mcf)","$","2.60","","$","7.06","","$","(4.46",")"],["NGL (per Bbl)","$","18.18","","$","33.20","","$","(15.02",")"],["Price per Boe","$","60.26","","$","76.05","","$","(15.79",")"],["Price per Boe (including realized commodity derivatives)","$","59.86","","$","56.46","","$","3.40"]] [[/GREPCENT_TABLE]] 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): [[GREPCENT_TABLE]] [["","Price","","Volume","","Total"],["Revenues:"],["Oil","$","(335,635",")","$","328,219","","$","(7,416",")"],["Natural gas","","(116,764",")","","(42,508",")","","(159,272",")"],["NGL","","(26,543",")","","(863",")","","(27,406",")"],["Total revenues","$","(478,942",")","$","284,848","","$","(194,094",")"]] [[/GREPCENT_TABLE]] 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. 70 Table of Contents Operating Expenses Lease Operating Expense The following table highlights lease operating expense items in total and on a cost per Boe production basis 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): [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["","2023","","2022"],["Lease operating expenses","$","389,621","","$","308,092"],["Lease operating expenses per Boe","$","16.10","","$","14.18"]] [[/GREPCENT_TABLE]] 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 $17.1 million decrease in facility and workover expense related to repairs and maintenance at the Phoenix Field compared to the same period in 2022. Depreciation, Depletion and Amortization The following table highlights depreciation, depletion and amortization items. The information below provides the financial results and an analysis of significant variances in these results (in thousands): [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["","2023","","2022"],["Depreciation, depletion and amortization","$","663,534","","$","414,630"]] [[/GREPCENT_TABLE]] 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 $176.3 million of additional depletion. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures” for further discussion on the EnVen Acquisition. Additionally, the depletion rate increased due to the extension of the HP-I lease during the fourth quarter of 2022. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 5 — Leases for additional information on the HP-I lease extension. General and Administrative Expense The following table highlights general and administrative expense items in total and on a cost per Boe production basis for the Upstream Segment. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data): [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["","2023","","2022"],["Upstream Segment","$","139,026","","$","82,979"],["CCS Segment","","11,922","","","10,240"],["Unallocated corporate","","7,545","","","6,535"],["Total general and administrative expense","$","158,493","","$","99,754"],["Upstream general and administrative expense per Boe","$","5.75","","$","3.82"]] [[/GREPCENT_TABLE]] 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 $3.0 million, primarily due to a forfeiture during the third quarter of 2023. 71 Table of Contents Miscellaneous The following table highlights miscellaneous items in total. The information below provides the financial results and an analysis of significant variances in these results (in thousands): [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["","2023","","2022"],["Accretion expense","$","86,152","","$","55,995"],["Other operating (income) expense","$","(52,155",")","$","33,902"],["Interest expense","$","173,145","","$","125,498"],["Price risk management activities (income) expense","$","(80,928",")","$","272,191"],["Equity method investment (income) expense","$","(3,209",")","$","(14,222",")"],["Other (income) expense","$","(12,371",")","$","(31,800",")"],["Income tax (benefit) expense","$","(60,597",")","$","2,537"]] [[/GREPCENT_TABLE]] 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. 72 Table of Contents 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. 73 Table of Contents The following table presents a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands): [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["","2023","","2022","","2021"],["Net income (loss)","$","187,332","","$","381,915","","$","(182,952",")"],["Interest expense","","173,145","","","125,498","","","133,138"],["Income tax expense (benefit)","","(60,597",")","","2,537","","","(1,635",")"],["Depreciation, depletion and amortization","","663,534","","","414,630","","","395,994"],["Accretion expense","","86,152","","","55,995","","","58,129"],["EBITDA","","1,049,566","","","980,575","","","402,674"],["Write-down of oil and natural gas properties","","\u2014","","","\u2014","","","18,123"],["Transaction and other (income) expense(1)","","(33,295",")","","(34,513",")","","5,886"],["Decommissioning obligations(2)","","11,879","","","31,558","","","21,055"],["Derivative fair value (gain) loss(3)","","(80,928",")","","272,191","","","419,077"],["Net cash received (paid) on settled derivative instruments(3)","","(9,457",")","","(425,559",")","","(290,164",")"],["(Gain) loss on debt extinguishment","","\u2014","","","1,569","","","13,225"],["Non-cash write-down of other well equipment","","\u2014","","","\u2014","","","5,606"],["Non-cash equity-based compensation expense","","12,953","","","15,953","","","10,992"],["Adjusted EBITDA","$","950,718","","$","841,774","","$","606,474"]] [[/GREPCENT_TABLE]] (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 $787.9 million. We fund drilling, completions and development activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities. We are continuing to explore a capital raise to finance the accelerated growth of our CCS segment. 74 Table of Contents Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the year ended December 31, 2023 (in thousands): [[GREPCENT_TABLE]] [["U.S. drilling & completions","$","447,254"],["Mexico appraisal & exploration","","291"],["Asset management(1)","","83,970"],["Seismic and G&G, land, capitalized G&A and other","","64,955"],["Total Upstream capital expenditures","","596,470"],["Plugging & abandonment","","86,615"],["Decommissioning obligations settled(2)","","50,584"],["Total Upstream","","733,669"],["Investment in CCS","","40,961"],["Total","$","774,630"]] [[/GREPCENT_TABLE]] (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): [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["","2023","","2022"],["Operating activities","$","519,069","","$","709,739"],["Investing activities","$","(512,626",")","$","(311,977",")"],["Financing activities","$","85,411","","$","(423,469",")"]] [[/GREPCENT_TABLE]] 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. 75 Table of Contents 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. 76 Table of Contents 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): [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["","2023","","2022"],["Current assets","$","409,112","","$","344,525"],["Non-current assets","","4,352,102","","","2,571,254"],["Total assets","$","4,761,214","","$","2,915,779"],["Current liabilities","$","577,587","","$","599,669"],["Non-current liabilities","","2,082,543","","","1,285,992"],["Talos Energy Inc. stockholders\u02bc equity","","2,101,084","","","1,030,118"],["Total liabilities and stockholders\u02bc equity","$","4,761,214","","$","2,915,779"]] [[/GREPCENT_TABLE]] The following table presents the income statement information (in thousands): [[GREPCENT_TABLE]] [["","Year Ended December 31, 2023"],["Revenues","$","1,457,886"],["Costs and expenses","","(1,258,327",")"],["Net income (loss)","$","199,559"]] [[/GREPCENT_TABLE]] Material Cash Requirements — We are party to various contractual obligations. Some of these obligations may be reflected in our accompanying Consolidated Financial Statements, while other obligations, such as certain operating leases and capital commitments, are not reflected on our accompanying Consolidated Financial Statements. 77 Table of Contents The following table and discussion summarizes our material cash requirements from known contractual obligations as of December 31, 2023 (in thousands): [[GREPCENT_TABLE]] [["","2024","","2025","","2026","","2027","","2028","","Thereafter","","Total(5)"],["Long-term financing obligations:"],["Debt principal","$","30,000","","$","30,000","","$","806,041","","$","200,000","","$","\u2014","","$","\u2014","","$","1,066,041"],["Debt interest","","123,084","","","119,559","","","68,975","","","5,152","","","\u2014","","","\u2014","","","316,770"],["Vessel commitments(1)","","13,216","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","13,216"],["Derivative liabilities","","7,305","","","795","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","8,100"],["Operating lease obligations","","4,748","","","4,716","","","4,803","","","4,708","","","4,610","","","4,584","","","28,169"],["Finance lease(2)","","19,336","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","19,336"],["Purchase obligations(3)","","3,083","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","3,083"],["Other commitments(4)","","3,991","","","327","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","4,318"],["Total contractual obligations(5)","$","204,763","","$","155,397","","$","879,819","","$","209,860","","$","4,610","","$","4,584","","$","1,459,033"]] [[/GREPCENT_TABLE]] (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. 78 Table of Contents 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. 79 Table of Contents 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.