TALOS ENERGY INC

Previous wording

The following significant developments have occurred since the filing of our 2023 Annual Report.

Current wording

The following significant developments have occurred since the filing of our Quarterly Report on Form 10-Q for the period ended March 31, 2024.

Previous wording

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 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. The next dry-dock is scheduled for the second quarter of 2024 with an estimated shut-in lasting approximately 55 days.

Current wording

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 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.

Previous wording

QuarterNorth Acquisition —On March 4, 2024, we acquired QuarterNorth, a private operator in the Deepwater U.S. Gulf of Mexico. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for more information.

Current wording

QuarterNorth Acquisition —On March 4, 2024, we acquired QuarterNorth Energy Inc. (“QuarterNorth”), a private operator in the Deepwater U.S. Gulf of Mexico (the “QuarterNorth Acquisition”). See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for more information.

Previous wording

During the period January 1, 2024 through March 31, 2024, the daily spot prices for NYMEX WTI crude oil ranged from a high of $84.39 per Bbl to a low of $70.62 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 $1.25 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 we realize 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 I, Item 1. “Financial Statements — Note 5 —Financial Instruments” for additional information regarding our commodity derivative positions as of March 31, 2024.

Current wording

During the period January 1, 2024 through June 30, 2024, the daily spot prices for NYMEX WTI crude oil ranged from a high of $87.69 per Bbl to a low of $70.62 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 $1.25 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 we realize 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 I, Item 1. “Financial Statements — Note 5 —Financial Instruments” for additional information regarding our commodity derivative positions as of June 30, 2024.

Previous wording

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. For the three months ended March 31, 2024 and 2023, we did not recognize an impairment based on the ceiling test computations. At March 31, 2024 our ceiling test computation was based on SEC pricing of $78.19 per Bbl of oil, $2.50 per Mcf of natural gas and $17.08 per Bbl of NGLs.

Current wording

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. For the three and six months ended June 30, 2024 and 2023, we did not recognize an impairment based on the ceiling test computations. At June 30, 2024 our ceiling test computation was based on SEC pricing of $80.82 per Bbl of oil, $2.44 per Mcf of natural gas and $19.86 per Bbl of NGLs.

Previous wording

If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning April 1, 2023 and ending March 1, 2024 used in the determination of the SEC pricing was 10% lower, resulting in $70.45 per Bbl of oil, $2.25 per Mcf of natural gas and $15.37 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by $446.5 million.

Current wording

If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning July 1, 2023 and ending June 1, 2024 used in the determination of the SEC pricing was 10% lower, resulting in $72.90 per Bbl of oil, $2.20 per Mcf of natural gas and $17.88 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by $166.3 million.

Previous wording

BOEM Bonding Rule —On April 15, 2024, BOEM issued its final rule, entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations,” which significantly increases the amount of new supplemental financial assurance required from lessees and grant holders conducting operations on the federal outer continental shelf (“OCS”). The final rule replaces the prior five-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead requires lessees to meet one of two criteria based on: (1) the credit rating of the lessee or (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. As a result of the new rule, BOEM will no longer consider or rely upon the financial strength of predecessors in determining whether, or how much, supplemental financial assurance will be required by current lessees and grant holders. The final rule, effective 60 days following publication in the Federal Register, adopts a three-year phased compliance period for full payment of a supplemental financial assurance demand.

Current wording

BOEM Bonding Rule —On April 15, 2024, BOEM issued its final rule, entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations,” which significantly increases the amount of new supplemental financial assurance required from lessees and grant holders conducting operations on the U.S. federal outer continental shelf (“OCS”). The final rule replaces the prior five-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead requires lessees to meet one of two criteria based on: (1) the credit rating of the lessee or (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. As a result of the new rule, BOEM will no longer consider or rely upon the financial strength of predecessors 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 for full payment of a supplemental financial assurance demand. Per BOEM’s June 28, 2024 news release, BOEM anticipates it will take up to 24 months to complete the processing of financial assurance demands for execution.

Previous wording

As discussed in our 2023 Annual Report, including under Part I, Item 1A. “Risk Factors — Risks Related to Our Business and the Oil and Natural Gas Industry, We may be unable to provide the financial assurances in the amounts and under the time periods required by the new rule. If we are unable to comply with these requirements, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including assessing civil penalties, commencing proceedings to suspend our production and other operations or cancelling our affected federal offshore leases. In addition, as a result of continuing adverse developments in restructurings and bankruptcies of companies operating in the OCS, a number of bonding companies have left the offshore surety market over the last nine months, which has materially reduced the availability of surety bonds for projects in the OCS. As a result, there may not be sufficient surety bonds capacity available for companies in the OCS to comply with the new financial assurances rule. Our inability to obtain adequate supplemental financial assurance in order to comply with BOEM’s final rule, including the future cost of compliance with respect to supplemental bonding, could materially and adversely affect our financial condition, cash flows, business, properties, liquidity and results of operations.

Current wording

As discussed in our 2023 Annual Report, including under Part I, Item 1A. “Risk Factors — Risks Related to Our Business and the Oil and Natural Gas Industry,” we may be unable to provide the financial assurances in the amounts and under the time periods required by the new rule. If we are unable to comply with these requirements, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including assessing civil penalties, commencing proceedings to suspend our production and other operations or canceling our affected federal offshore leases. In addition, as a result of continuing adverse developments in restructurings and bankruptcies of companies operating in the OCS, a number of bonding companies have left the offshore surety market over the last twelve months, which has materially reduced the availability of surety bonds for projects in the OCS. As a result, there may not be sufficient surety bonds capacity available for companies in the OCS to comply with the new financial assurances rule. Our inability to obtain adequate supplemental financial assurance in order to comply with BOEM’s final rule, including the future cost of compliance with respect to supplemental bonding, could materially and adversely affect our financial condition, cash flows, business, properties, liquidity and results of operations.

Previous wording

Five-Year Offshore Oil and Gas Leasing Program Update —Under the Outer Continental Shelf Lands Act (“OCSLA”), as amended, BOEM prepares and maintains 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. As required by the Inflation Reduction Act of 2022, BOEM held Lease Sale 261 under the 2017-2022 national program on December 20, 2023, in which we were the high bidder on thirteen offshore blocks and QuarterNorth was the high bidder on four offshore blocks. We and QuarterNorth were awarded leases on all seventeen of these high-bid blocks.

Current wording

Five-Year Offshore Oil and Gas Leasing Program Update —Under the Outer Continental Shelf Lands Act (“OCSLA”), as amended, BOEM prepares and maintains 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 OCS. As previously disclosed in our 2023 Annual Report, we were the high bidder on thirteen offshore Gulf of Mexico blocks related to Lease Sale 261 held by BOEM and awarded four leases. Subsequently, we were awarded leases on our remaining 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.

Previous wording

The 2024-2029 national program starts on July 1, 2024, and continues through June 30, 2029. It is possible, however, that the final program could be delayed by opposing lawsuits that were filed on February 12, 2024, by the American Petroleum Institute and by 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 lease sales 262, 263 and 264 pursuant to the 2024-2029 national program. Lease Sale 262 is tentatively scheduled for 2025.

Current wording

The 2024-2029 national program began on July 1, 2024, and will continue through June 30, 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 Mexico lease sales 262, 263 and 264 pursuant to the 2024-2029 national program. Lease Sale 262 is tentatively scheduled for 2025.

Previous wording

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):

Current wording

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. Revenues are presented in thousands, except per unit data.

Previous wording

Three Months Ended March 31, 2024 and 2023 Volumetric Analysis —Production volumes increased by 16.0 MBoepd to 79.6 MBoepd. The increase was primarily due to 7.4 MBoepd of production from the oil and natural gas assets acquired from the QuarterNorth Acquisition that closed in early March 2024 as well as 6.9 MBoepd from the EnVen Acquisition that closed mid-first quarter of 2023. Additionally, there was 10.2 MBoepd production from the Venice and Lime Rock wells, which tie back to our Ram Powell facility, which commenced initial production late in the fourth quarter of 2023. These increases were partially offset by a decrease of 6.9 MBoepd due to well performance and natural production declines. Additionally, there was approximately 2.0 MBoepd of deferred production resulting from third party infrastructure downtime primarily from our Lobster Field located in our Mississippi Canyon core area.

Current wording

Six Months Ended June 30, 2024 and 2023 Volumetric Analysis —Production volumes increased by 20.6 MBoepd to 87.5 MBoepd. The increase was primarily due to 17.7 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, production volumes increased 10.3 MBoepd production from the Venice and Lime Rock wells, which tie back to our Ram Powell facility, which commenced initial production late in the fourth quarter of 2023. These increases were partially offset by a decrease of 5.9 MBoepd due to well performance and natural production declines. Additionally, we deferred approximately 2.4 MBoepd of production resulting from third party downtime associated with the HP-I dry-dock in our Phoenix Field.

Previous wording

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):

Current wording

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):

Previous wording

Three Months Ended March 31, 2024 and 2023 — Lease operating expense for the three months ended March 31, 2024 increased by approximately $53.8 million, or 66%. This was related to an increase of $34.0 million primarily due to major well workover expenses at the Phoenix Field and the Garden Banks 506 Field. Additionally, there was a $12.8 million increase in lease operating expenses incurred in connection with assets acquired from the QuarterNorth Acquisition as well as a $8.8 million increase in direct lease operating expenses due to the EnVen Acquisition that closed mid-first quarter of 2023.

Current wording

Six Months Ended June 30, 2024 and 2023 — Lease operating expense for the six months ended June 30, 2024 increased by approximately $110.0 million, or 60%. This increase was related to lease operating expenses of $52.8 million incurred in connection with assets acquired in the QuarterNorth Acquisition as well as a $10.4 million increase in lease operating expenses due to the EnVen Acquisition that closed in mid-first quarter 2023. Additionally, there was a $52.8 million increase in facility and workover expense primarily related to the HP-I and major well workover expenses at the Phoenix Field and the Garden Banks 506 Field. These increases were partially offset by a $3.2 million increase in production handling reimbursements from certain third parties related to our historical operations.

Previous wording

Three Months Ended March 31, 2024 and 2023 — Depreciation, depletion and amortization expense for the three months ended March 31, 2024 increased by approximately $68.3 million, or 46% due to increased production volumes, which are described above. Additionally, the depletion rate increased by $4.07 per Boe, or 16%, on our proved oil and natural gas properties.

Current wording

Three Months Ended June 30, 2024 and 2023 — Depreciation, depletion and amortization expense for the three months ended June 30, 2024 increased by approximately $89.3 million, or 53% due to increased production volumes, which are described above. Additionally, the depletion rate increased by $3.30 per Boe, or 13%, on our proved oil and natural gas properties.

Previous wording

Three Months Ended March 31, 2024 and 2023 —General and administrative expense for the three months ended March 31, 2024 increased by approximately $6.7 million, or 11%. This increase was primarily related to first quarter 2024 Upstream Segment transaction costs, severance costs and additional general and administrative expenses related to the QuarterNorth Acquisition of $30.6 million or $4.22 per Boe. Additionally, unallocated corporate had an increase during the first quarter 2024 in transaction costs and severance costs of $9.8 million related to the TLCS Divestiture. These increases were partially offset by a decrease in the Upstream Segment transaction costs for the EnVen Acquisition of $35.4 million or $6.19 per Boe. Additionally, the CCS Segment expenses decreased by $1.4 million due to the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for further discussion.

Current wording

Six Months Ended June 30, 2024 and 2023 —General and administrative expense for the six months ended June 30, 2024 increased by approximately $21.7 million, or 23%. 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 $42.1 million or $2.64 per Boe. Unallocated corporate reflects an increase in transaction costs and severance costs of $9.0 million related to the TLCS Divestiture. Additionally, there was an increase in 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 $38.2 million or $3.15 per Boe. Additionally, the CCS Segment expenses decreased by $3.8 million due to the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for further discussion.

Previous wording

Accretion Expense —During the three months ended March 31, 2024, we recorded $26.9 million of accretion expense compared to $19.4 million during the three months ended March 31, 2023. The change is primarily the result of a $4.2 million increase in accretion associated with the asset retirement obligations assumed as part of the QuarterNorth Acquisition and EnVen Acquisition. See Part I, Item 1. “Financial Statements—Note 2—Acquisitions and Divestitures.”

Current wording

Accretion Expense —During the three months ended June 30, 2024, we recorded $30.7 million of accretion expense compared to $22.8 million during the three months ended June 30, 2023. The change is primarily the result of a $4.5 million increase in accretion associated with the asset retirement obligations assumed as part of the QuarterNorth Acquisition. See Part I, Item 1. “Financial Statements—Note 2—Acquisitions and Divestitures.”

Previous wording

Income Tax (Benefit) Expense — During the three months ended March 31, 2024, we recorded $21.6 million of income tax benefit primarily due to current year activity inclusive of permanent differences compared to $46.5 million of income tax benefit during the three months ended March 31, 2023. The income tax benefit recorded during the three months ended March 31, 2023 is primarily due to a non-cash tax benefit related to the partial release of the valuation allowance on our U.S. federal deferred tax assets. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 10 —Income Taxes.”

Current wording

Income Tax (Benefit) Expense — During the three months ended June 30, 2024, we recorded $1.0 million of income tax benefit compared to $6.9 million of income tax expense during the three months ended June 30, 2023. The income tax benefit recorded during the three months ended June 30, 2024 is primarily due to a non-cash income tax benefit recognized in the Company’s state deferred tax liability. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 10 —Income Taxes.”

Previous wording

Other Operating (Income) Expense —During the three months ended March 31, 2024, we recognized a gain of $86.9 million on the TLCS Divestiture. See Part I, Item 1. “Financial Statements—Note 2 —Acquisitions and Divestitures”for further discussion.

Current wording

Other Operating (Income) Expense —During the six months ended June 30, 2024, we recognized a gain of $86.9 million on the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for further discussion.

Previous wording

Interest Expense —During the three months ended March 31, 2024, we recorded $50.8 million of interest expense compared to $37.6 million during the three months ended March 31, 2023. The change is primarily the result of an increase in incremental debt outstanding offset by a lower rate of interest on these instruments. See Part I, Item 1. “Financial Statements—Note 7—Debt” for more information. Additionally, there was an increase of $4.9 million of fees associated with the unutilized bridge loan. See Part I, Item 1. “Financial Statements—Note 2—Acquisitions and Divestitures” for more information.

Current wording

Interest Expense —During the six months ended June 30, 2024, we recorded $99.8 million of interest expense compared to $83.2 million during the six months ended June 30, 2023. The change is primarily the result of an increase in debt outstanding offset by a lower rate of interest on these instruments. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information. Additionally, there was an increase of $4.9 million of fees associated with the unutilized bridge loan. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for more information.

Previous wording

Price Risk Management Activities — The expense of $87.1 million for the three months ended March 31, 2024 consists of $83.6 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $3.5 million in cash settlement losses. The income of $58.9 million for the three months ended March 31, 2023 consists of $71.3 million in non-cash gains from the increase in the fair value of our open derivative contracts partially offset by $12.3 million in cash settlement losses.

Current wording

Price Risk Management Activities —The expense of $84.8 million for the six months ended June 30, 2024 consists of $63.8 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $21.0 million in cash settlement losses. The income of $85.1 million for the six months ended June 30, 2023 consists of $89.3 million in non-cash gains from the increase in the fair value of our open derivative contracts partially offset by $4.2 million in cash settlement losses.

Previous wording

Equity Method Investment Income — During the three months ended March 31, 2024, we recorded equity losses of $8.1 million. During the three months ended March 31, 2023, we recorded equity losses of $1.1 million offset by an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron.

Current wording

Equity Method Investment (Income) Expense — During the six months ended June 30, 2024, we recorded equity losses of $8.9 million partially offset by $0.4 million equity method income. During the six months ended June 30, 2023, we recorded equity losses of $3.2 million offset by an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron. See Part I, Item 1. “Financial Statements — Note 12 —Related Party Transactions” for additional information.

Previous wording

Other (Income) Expense — During the three months ended March 31, 2024, we recorded a $60.3 million loss on extinguishment of debt because of 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 I, Item 1. “Financial Statements — Note 7 —Debt” for more information.

Current wording

Other (Income) Expense— During the six months ended June 30, 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 I, Item 1. “Financial Statements — Note 7 —Debt” for more information.

Previous wording

For the three months ended March 31, 2024, transaction expenses include $28.1 million in costs related to the QuarterNorth Acquisition, inclusive of $14.2 million in severance expense and $9.8 million in costs related to the TLCS Divestiture, inclusive of $3.7 million in severance expense. For the three months ended March 31, 2023, transaction expenses included $35.2 million in costs related to the EnVen Acquisition, inclusive of $22.6 million in severance expense. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” and “Note 9 —Employee Benefits Plans and Share-Based Compensation.” Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended March 31, 2024, it includes a gain of $86.9 million related to the TLCS Divestiture. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.” For the three months ended March 31, 2023, it includes an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron.

Current wording

For the three and six months ended June 30, 2024, transaction expenses include $9.3 million and $37.4 million, respectively, in costs related to the QuarterNorth Acquisition, inclusive of $8.1 million and $22.3 million, respectively, in severance expense. For the six months ended June 30, 2024, transaction expenses include $9.0 million in costs related to the TLCS Divestiture, inclusive of $3.7 million in severance expense. For the three and six months ended June 30, 2023, transaction expenses included $2.7 million and $37.9 million, respectively, in costs related to the EnVen Acquisition, inclusive of $1.4 million and $24.0 million, respectively, in severance expense. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” and “Note 9 —Employee Benefits Plans and Share-Based Compensation.” Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the six months ended June 30, 2024, it includes a gain of $86.9 million related to the TLCS Divestiture. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.” For the six months ended June 30, 2023, it includes an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron.

Previous wording

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 I, Item 1. “Financial Statements — Note 13 —Commitments and Contingencies.”

Current wording

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 I, Item 1. “Financial Statements — Note 13 —Commitments and Contingencies” for additional information on decommissioning obligations.

Previous wording

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 borrowings under our Bank Credit Facility has increased. By raising its federal funds rate, the Fed made it more expensive to borrow money. As of March 31, 2024, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $650.2 million.

Current wording

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 borrowings under our Bank Credit Facility has increased. By raising its federal funds rate, the Fed made it more expensive to borrow money. As of June 30, 2024, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $738.7 million.

Previous wording

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.

Current wording

We fund our development and exploration 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 equity issuances. We 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.

Previous wording

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

Current wording

Capital Expenditures —The following is a table of our capital expenditures, excluding acquisitions, for the six months ended June 30, 2024 (in thousands):

Previous wording

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund the remaining portion of our 2024 Upstream capital spending program of $570.0 million to $600.0 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 various operating and economic conditions, many 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.

Current wording

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund the remaining portion of our 2024 Upstream capital spending program of $570.0 million to $600.0 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, (ii) obtain future borrowings under the Bank Credit Facility, and (iii) 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 various operating and economic conditions, many 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 take additional future actions on an opportunistic basis. To address further changes in the financial 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.

Previous wording

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. There were no shares of common stock repurchased during the three months ended March 31, 2024. As of March 31, 2024, there is $52.5 million remaining under the authorized program. All repurchased shares are held in treasury. The 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the Inflation Reduction Act of 2022 applies to our share repurchase program.

Current wording

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 three months ended June 30, 2024, we repurchased approximately 3.8 million shares for $42.9 million. As of June 30, 2024, there is $9.7 million remaining under the authorized program. In July 2024, our Board of Directors authorized an increase of $150.0 million to the previously approved limit increasing the amount remaining under the authorized plan to $159.7 million. All repurchased shares are held in treasury. The 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the Inflation Reduction Act of 2022 applies to our share repurchase program. We do not currently anticipate incurring any excise tax in 2024 based on the fair market value of the common stock issued during 2024. See Part II, Item 2. “Unregistered Sales of Equity Securities and Use of Proceeds” for additional information.

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Operating Activities — Net cash provided by operating activities increased $33.6 million in the three months ended March 31, 2024 compared to the corresponding period in 2023 primarily attributable to an increase from revenues offset with an increase in lease operating expense of $53.5 million. Additionally, there was an increase in settlements of asset retirement obligations of $17.8 million.

Current wording

Operating Activities — Net cash provided by operating activities increased $108.7 million in the six months ended June 30, 2024 compared to the corresponding period in 2023 primarily attributable to an increase from revenues offset with an increase in lease operating expense of $179.3 million and an increase in net cash paid on derivatives of $16.9 million.

Previous wording

Investing Activities — Net cash used in investing activities increased $830.7 million in the three months ended March 31, 2024 compared to the corresponding period in 2023 primarily due to cash paid for the QuarterNorth Acquisition of $916.0 million, net of cash acquired. This was offset by cash proceeds of $142.0 million from the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information. Additionally, there was an increase in capital expenditures of $42.1 million.

Current wording

Investing Activities — Net cash used in investing activities increased $750.3 million in the six months ended June 30, 2024 compared to the corresponding period in 2023 primarily due to cash paid for the QuarterNorth Acquisition of $916.0 million, net of cash acquired. This was offset by cash proceeds of $142.0 million from the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information. Additionally, capital expenditures decreased $29.5 million.

Previous wording

Financing Activities —Cash flow from financing activities changed $712.5 million in the three months ended March 31, 2024 compared to the corresponding period in 2023. During the three months ended March 31, 2024, the issuance of the New Senior Notes in February 2024 generated $1,224.5 million after deferred financing costs. The net proceeds from the New 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 I, Item 1. “Financial Statements — Note 7 —Debt” for additional information. Additionally, on January 17, 2024, we entered into upsized underwritten public offering of 34.5 million shares of our common stock, which generated net proceeds of $387.7 million. The net proceeds from this equity offering partially funded the cash portion of the QuarterNorth Acquisition.

Current wording

Financing Activities —Cash flow from financing activities changed $573.4 million in the six months ended June 30, 2024 compared to the corresponding period in 2023. During the six months ended June 30, 2024, the issuance of the New Senior Notes in February 2024 generated $1,222.6 million after deferred financing costs. The net proceeds from the New 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 I, Item 1. “Financial Statements — Note 7 —Debt” for additional information. Additionally, on January 17, 2024, we entered into anunderwritten 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.

Previous wording

Bank Credit Facility — matures March 2027 — We maintain a Bank Credit Facility with a syndicate of financial institutions (the “Bank Credit Facility”). The Bank Credit Facility provides for determination of the borrowing base based on our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter each year. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information.

Current wording

Bank Credit Facility — matures March 2027 — We maintain a Bank Credit Facility with a syndicate of financial institutions (the “Bank Credit Facility”). 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 the Company delivers to the administrative agent of our Bank Credit Facility. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information.

Previous wording

Redemption of the 11.75% Senior Secured Second Lien Notes — due April 2026 —We redeemed $227.5 million aggregate principal amount of the 11.75% Notes using the proceeds from the issuance of the New Senior Notes. On February 7, 2024, the Company irrevocably deposited funds with the trustee sufficient to satisfy and discharge the 11.75% Notes until redeemed on April 15, 2024 with the funds deposited with the trustee. Concurrently, the Company elected to satisfy and discharge the 11.75% Notes in accordance with its terms and the trustee acknowledged such discharge and satisfaction. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information.

Current wording

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 New Senior Notes. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information.

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

Current wording

Lease agreement for the HP-I floating production facility we utilize to produce the Phoenix Field.

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Includes committed purchase orders to execute planned future drilling activities.

Current wording

Includes committed purchase orders to execute planned future oil and natural gas operational activities.

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This table does not include our estimated discounted liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $1,109.3 million as of March 31, 2024. For additional information regarding these liabilities, please see Part I, Item 1. “Financial Statements — Note 8 —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 I, Item 1. “Financial Statements — Note 13 —Commitments and Contingencies.”

Current wording

This table does not include our estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties with a carrying value of $1,158.8 million as of June 30, 2024. For additional information regarding these liabilities, please see Part I, Item 1. “Financial Statements — Note 8 —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 I, Item 1. “Financial Statements — Note 13 —Commitments and Contingencies.”

Previous wording

Performance Obligations —As of March 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 Mexico. 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. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for further information on the Bank Credit Facility.

Current wording

Performance Obligations —As of June 30, 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 Mexico. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $39.1 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. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for further information on the Bank Credit Facility.

Previous wording

We consider accounting policies related to oil and natural gas properties, proved reserve estimates, fair value measure of financial instruments, asset retirement obligations, revenue recognition, imbalances and production handling fees and income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. There have been no changes to our critical accounting estimates from those disclosed in our 2023 Annual Report under Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates.”

Current wording

There have been no changes to our critical accounting estimates from those disclosed in our 2023 Annual Report under Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates.”