# Talos Energy Inc.: Form 10-Q for the period ended Jun 30, 2024

- Company: [Talos Energy Inc.](/companies/talo.md) (CIK 1724965)
- Form: 10-Q
- Filed: 2024-08-08
- Accepted by EDGAR: Aug 7, 2024, 18:00 ET
- Period: 2024-06-30
- Accession: 0000950170-24-093063
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1724965/000095017024093063/talo-20240630.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1724965/000095017024093063/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2024-06-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2024-04-01 to 2024-06-30 | $549.2m | us-gaap:Revenues |
| Revenue | 6 months, 2024-01-01 to 2024-06-30 | $979.1m | us-gaap:Revenues |
| Operating income | 3 months, 2024-04-01 to 2024-06-30 | $54.4m | us-gaap:OperatingIncomeLoss |
| Operating income | 6 months, 2024-01-01 to 2024-06-30 | $122.2m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2024-04-01 to 2024-06-30 | $49.0m | us-gaap:InterestExpense |
| Interest expense | 6 months, 2024-01-01 to 2024-06-30 | $99.8m | us-gaap:InterestExpense |
| Income tax | 3 months, 2024-04-01 to 2024-06-30 | −$983.0k | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 6 months, 2024-01-01 to 2024-06-30 | −$22.6m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2024-04-01 to 2024-06-30 | $12.4m | us-gaap:NetIncomeLoss |
| Net income | 6 months, 2024-01-01 to 2024-06-30 | −$100.1m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2024-04-01 to 2024-06-30 | $0.07 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 6 months, 2024-01-01 to 2024-06-30 | −$0.59 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2024-04-01 to 2024-06-30 | $0.07 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 6 months, 2024-01-01 to 2024-06-30 | −$0.59 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2024-04-01 to 2024-06-30 | 183,692,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 6 months, 2024-01-01 to 2024-06-30 | 171,027,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 6 months, 2024-01-01 to 2024-06-30 | $385.8m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Share repurchases | 6 months, 2024-01-01 to 2024-06-30 | $39.3m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2024-06-30 | $37.8m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2024-06-30 | $565.8m | us-gaap:AssetsCurrent |
| Total assets | at 2024-06-30 | $6.36bn | us-gaap:Assets |
| Current liabilities | at 2024-06-30 | $711.6m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2024-06-30 | $3.64bn | us-gaap:Liabilities |
| Long-term debt | at 2024-06-30 | $1.44bn | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2024-06-30 | $0 | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2024-06-30 | $2.73bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 57,891 characters.

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

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with, our Condensed Consolidated Financial Statements and notes thereto in Part I, Item 1. “Financial Statements” of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 2023 Annual Report and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2023 Annual Report.

### 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 United States (“U.S.”) and offshore Mexico. We leverage decades of technical and offshore operational expertise towards the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world.

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

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

From January 1, 2024 through March 18, 2024, we had two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”), of which the Company’s only reportable segment was the Upstream Segment. Subsequent to the TLCS Divestiture (as defined herein) and our sale of the entire CCS business, we had one operating segment. See additional information in Part I, Item 1. “Financial Statements — Note 14 — *Segment Information.”*

### Significant Developments

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

***Common Stock Repurchase Program —*** During the three months ended June 30, 2024, we repurchased 3.8 million shares for $42.9 million under our stock repurchase program, which was previously authorized by our Board of Directors, resulting in $9.7 million available under the stock repurchase program. In July 2024, our Board of Directors authorized a $150.0 million increase to the previously approved limit of the stock repurchase program, increasing the amount remaining under the authorized plan to $159.7 million. See “Liquidity and Capital Resources—Common Stock Repurchase Program” for additional information.

***Acquisition of Working Interests in Monument Oil Discovery —*** We executed two separate definitive agreements to acquire a collective 21.4% non-operated working interest in the Monument oil discovery (“Monument Project”) in the deepwater U.S. Gulf of Mexico located on certain Walker Ridge lease blocks in late July 2024 and early August 2024. First production is expected from the Monument Project by late 2026. See additional information in Part I, Item 1. “Financial Statements — Note 15 — *Subsequent Events.”*

### 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.

***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.

During the three months ended June 30, 2024, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-June, resulting in a total shut-in period of 52 days. The shut-in resulted in an estimated deferred production of approximately 4.8 MBoepd and 2.4 MBoepd for the three and six months ended June 30, 2024, respectively, based on production rates prior to the shut-in.

***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.

***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 I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for more information.

### Known Trends and Uncertainties

See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2023 Annual Report for a detailed discussion of known trends and uncertainties. The following carries forward or provides an update to known trends and uncertainties discussed in our 2023 Annual Report.

***Volatility in Oil, Natural Gas and NGL Prices —*** Historically, the markets for oil, natural gas and NGLs 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 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.

The U.S. Energy Information Administration (“EIA”) published its July 2024 Short-Term Energy Outlook on July 9, 2024. Oil prices fell on June 4, 2024, following the OPEC Plus meeting on June 2, 2024, when the group announced its voluntary cuts would gradually be unwound beginning in the fourth quarter of 2024. Prices fell following this announcement as market participants assessed that unwinding production cuts could cause a significant increase in global oil inventories. Oil prices have since rebounded based on current global inventory levels and the indication by OPEC Plus that production cuts remain subject to market conditions. The EIA expects NYMEX WTI spot prices will increase from an average of $79.66 per barrel in the first half of 2024 to $84.31 per barrel in the second half of 2024 and $86.16 in the first quarter of 2025. Higher prices in the second half of the year result from the EIA’s forecast of persistent withdrawals from global oil inventories. Uncertainty remains around heightened tensions in the Middle East, and an escalation in Houthi attacks on shipping vessels around the Red Sea. The EIA expects the Henry Hub natural gas spot price will average almost $2.90 per MMBtu in the second half of 2024, up from $2.10 per MMBtu in the first half of 2024. Natural gas prices fell in early 2024 because of mild winter weather that reduced demand for natural gas for space heating. However, low prices reduced natural gas-directed drilling and led producers to curtail some production. As U.S. storage inventories draw down close to the five-year average by the end of injection season (i.e., October) and with new demand from liquefied natural gas export projects coming on line in late 2024 and mid-2025, the EIA expects natural gas prices to rise to an average of $3.30 per MMBtu in 2025.

***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 increases, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices. 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 U.S. Federal Reserve (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 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. 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.

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.

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” included in our 2023 Annual Report. The discounted present value of our proved reserves is a major component of the Ceiling calculation. Any decrease in SEC pricing 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.

***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.

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.

***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 biennially, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. Additionally, these plans are tested and drills are conducted periodically at all levels.

***Hurricanes, Tropical Storms 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 production and revenues and increased lease operating expenses for evacuations and repairs.

***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.

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.

### 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.

### Results of Operations

### Revenue

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.

| Revenues: | Three Months Ended June 30, 2024 | 2023 | Change | Six Months Ended June 30, 2024 | 2023 | Change |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Oil | $507,408 | $342,983 | $164,425 | $900,629 | $635,677 | $264,952 |
| Natural gas | 26,060 | 16,329 | 9,731 | 49,758 | 36,512 | 13,246 |
| NGL | 15,697 | 7,898 | 7,799 | 28,710 | 17,603 | 11,107 |
| Total revenues | $549,165 | $367,210 | $181,955 | $979,097 | $689,792 | $289,305 |
| **Production Volumes:** |  |  |  |  |  |  |
| Oil (MBbls) | 6,303 | 4,801 | 1,502 | 11,476 | 8,907 | 2,569 |
| Natural gas (MMcf) | 10,081 | 6,637 | 3,444 | 18,740 | 13,764 | 4,976 |
| NGL (MBbls) | 703 | 486 | 217 | 1,335 | 915 | 420 |
| Total production volume (MBoe) | 8,686 | 6,393 | 2,293 | 15,934 | 12,116 | 3,818 |
| **Daily Production Volumes by Product:** |  |  |  |  |  |  |
| Oil (MBblpd) | 69.3 | 52.8 | 16.5 | 63.1 | 49.2 | 13.9 |
| Natural gas (MMcfpd) | 110.8 | 72.9 | 37.9 | 103.0 | 76.0 | 27.0 |
| NGL (MBblpd) | 7.7 | 5.3 | 2.4 | 7.3 | 5.1 | 2.2 |
| Total production volume (MBoepd) | 95.5 | 70.2 | 25.3 | 87.5 | 66.9 | 20.6 |
| **Average Sale Price Per Unit:** |  |  |  |  |  |  |
| Oil (per Bbl) | $80.50 | $71.44 | $9.06 | $78.48 | $71.37 | $7.11 |
| Natural gas (per Mcf) | $2.59 | $2.46 | $0.13 | $2.66 | $2.65 | $0.01 |
| NGL (per Bbl) | $22.33 | $16.25 | $6.08 | $21.51 | $19.24 | $2.27 |
| Price per Boe | $63.22 | $57.44 | $5.78 | $61.45 | $56.93 | $4.52 |
| Price per Boe (including realized commodity derivatives) | $61.21 | $58.72 | $2.49 | $60.13 | $56.59 | $3.54 |

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):

| Revenues: | Three Months Ended June 30, 2024 vs 2023 Price | Volume | Total | Six Months Ended June 30, 2024 vs 2023 Price | Volume | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Oil | $57,122 | $107,303 | $164,425 | $81,602 | $183,350 | $264,952 |
| Natural gas | 1,259 | 8,472 | 9,731 | 60 | 13,186 | 13,246 |
| NGL | 4,273 | 3,526 | 7,799 | 3,026 | 8,081 | 11,107 |
| Total revenues | $62,654 | $119,301 | $181,955 | $84,688 | $204,617 | $289,305 |

31

***Three Months Ended June 30, 2024 and 2023 Volumetric Analysis —*** Production volumes increased by 25.3 MBoepd to 95.5 MBoepd. The increase was primarily due to 28.1 MBoepd of production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024. Additionally, there was 10.5 MBoepd production from our operated 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 7.7 MBoepd due to well performance and natural production declines. Additionally, we deferred approximately 4.8 MBoepd of production resulting from third party downtime associated with the HP-I dry-dock in our Phoenix Field.

***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.

### Operating Expenses

### Lease Operating Expense

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

|  | Three Months Ended June 30, 2024 | 2023 | Six Months Ended June 30, 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Lease operating expenses | $157,310 | $101,165 | $292,488 | $182,527 |
| Lease operating expenses per Boe | $18.11 | $15.83 | $18.36 | $15.06 |

***Three Months Ended June 30, 2024 and 2023 —*** Lease operating expense for the three months ended June 30, 2024 increased by approximately $56.1 million, or 55%. This increase was primarily related to lease operating expenses of $40.0 million incurred in connection with assets acquired in the QuarterNorth Acquisition. Additionally, there was a $16.9 million increase in facility and workover expense primarily related to the HP-I compared to the same period in 2023.

***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.

### 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):

|  | Three Months Ended June 30, 2024 | 2023 | Six Months Ended June 30, 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Depreciation, depletion and amortization | $259,091 | $169,794 | $474,755 | $317,117 |

***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.

***Six Months Ended June 30, 2024 and 2023 —*** Depreciation, depletion and amortization expense for the six months ended June 30, 2024 increased by approximately $157.6 million, or 50%. This was due to an increase of $3.71 per Boe, or 14%, in the depletion rate on our proved oil and natural gas properties due to an increase in our proved properties primarily related to the assets acquired as part of the QuarterNorth Acquisition, which is further discussed in Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures.”*

### General and Administrative Expense

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

|  | Three Months Ended June 30, 2024 | 2023 | Six Months Ended June 30, 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Upstream Segment | $46,173 | $28,901 | $102,255 | $87,256 |
| CCS Segment | — | 2,445 | 1,965 | 5,774 |
| Unallocated corporate | 2,074 | 1,836 | 13,868 | 3,339 |
| Total general and administrative expense | $48,247 | $33,182 | $118,088 | $96,369 |
| Upstream general and administrative expense per Boe | $5.32 | $4.52 | $6.42 | $7.20 |

***Three Months Ended June 30, 2024 and 2023 —*** General and administrative expense for the three months ended June 30, 2024 increased by approximately $15.1 million, or 45%. This increase was primarily related to Upstream Segment transaction costs, severance costs and additional general and administrative expenses related to the QuarterNorth Acquisition of $11.5 million or $1.33 per Boe. 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 $2.7 million or $0.43 per Boe. Additionally, the CCS Segment expenses decreased by $2.4 million due to the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for further discussion.

***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.

### 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):

|  | Three Months Ended June 30, 2024 | 2023 | Six Months Ended June 30, 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Accretion expense | $30,732 | $22,760 | $57,635 | $42,174 |
| Other operating (income) expense | $(1,061) | $(723) | $(87,104) | $2,115 |
| Interest expense | $48,982 | $45,632 | $99,827 | $83,213 |
| Price risk management activities (income) expense | $(2,302) | $(26,197) | $84,760 | $(85,134) |
| Equity method investment (income) expense | $456 | $2,012 | $8,510 | $(5,431) |
| Other (income) expense | $(4,164) | $(1,591) | $51,732 | $(8,257) |
| Income tax (benefit) expense | $(983) | $6,892 | $(22,556) | $(39,651) |

### Three Months Ended June 30, 2024 and 2023 —

***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.”*

***Price Risk Management Activities —*** The income of $2.3 million for the three months ended June 30, 2024 consists of $19.8 million in non-cash gains from the increase in the fair value of our open derivative contracts offset by $17.5 million in cash settlement losses. The income of $26.2 million for the three months ended June 30, 2023 consists of $18.0 million in non-cash gains from the increase in the fair value of our open derivative contracts and $8.2 million in cash settlement gains.

These unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Condensed Consolidated Statements of Operations at the end of each reporting period. 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 I, Item 1. “Financial Statements — Note 5 — *Financial Instruments.”*

***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.”*

### Six Months Ended June 30, 2024 and 2023 —

***Accretion Expense —*** During the six months ended June 30, 2024, we recorded $57.6 million of accretion expense compared to $42.2 million during the six months ended June 30, 2023. The change is primarily the result of the increase in accretion associated with the asset retirement obligations assumed as part of both the EnVen Acquisition and QuarterNorth Acquisition and upward revisions of our asset retirement obligations. See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures.”*

***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.

***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.

***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.

These unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Condensed Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through December 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 I, Item 1. “Financial Statements — Note 5 — *Financial Instruments.”*

***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.

***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.

***Income Tax (Benefit) Expense —*** During the six months ended June 30, 2024, we recorded $22.6 million of income tax benefit compared to $39.7 million of income tax benefit during the six months ended June 30, 2023. The income tax benefit is primarily due to current year activity offset by the impact from permanent differences. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 10 — *Income Taxes.”*

### 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.

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):

|  | Three Months Ended June 30, 2024 | 2023 | Six Months Ended June 30, 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Net income (loss) | $12,381 | $13,677 | $(100,058) | $103,537 |
| Interest expense | 48,982 | 45,632 | 99,827 | 83,213 |
| Income tax (benefit) expense | (983) | 6,892 | (22,556) | (39,651) |
| Depreciation, depletion and amortization | 259,091 | 169,794 | 474,755 | 317,117 |
| Accretion expense | 30,732 | 22,760 | 57,635 | 42,174 |
| EBITDA | 350,203 | 258,755 | 509,603 | 506,390 |
| Transaction and other (income) expenses(1) | 6,629 | 3,513 | (42,528) | 25,522 |
| Decommissioning obligations(2) | 4,182 | 741 | 5,037 | 1,482 |
| Derivative fair value (gain) loss(3) | (2,302) | (26,197) | 84,760 | (85,134) |
| Net cash received (paid) on settled derivative instruments(3) | (17,518) | 8,162 | (21,012) | (4,161) |
| (Gain) loss on debt extinguishment | — | — | 60,256 | — |
| Non-cash equity-based compensation expense | 2,790 | 4,749 | 5,544 | 8,687 |
| Adjusted EBITDA | $343,984 | $249,723 | $601,660 | $452,786 |

(1) 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.

(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 I, Item 1. “Financial Statements — Note 13 — *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 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.

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.

Our liquidity could be impacted in the future by financial assurance requirements. See “Known Trends and Uncertainties — BOEM Bonding Rule.”

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

|  |  |
| --- | ---: |
| U.S. drilling & completions | $115,346 |
| Asset management(1) | 61,708 |
| Seismic and G&G, land, capitalized G&A and other | 58,194 |
| Total Upstream capital expenditures | 235,248 |
| Plugging & abandonment | 50,128 |
| Decommissioning obligations settled(2) | 3,328 |
| Investment in Mexico | 2,108 |
| Total Upstream | 290,812 |
| Investment in CCS | 17,519 |
| Total | $308,331 |

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

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.

***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.

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.

***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):

|  | Six Months Ended June 30, 2024 | 2023 |
| --- | ---: | ---: |
| Operating activities | $385,790 | $277,083 |
| Investing activities | $(1,062,845) | $(312,585) |
| Financing activities | $683,221 | $109,855 |

***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.

***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.

***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 an underwritten public offering of 34.5 million shares of our common stock, which generated net proceeds of $387.7 million after deducting underwriting discounts of $15.1 million and offering expenses of $0.8 million. The net proceeds from this equity offering partially funded the cash portion of the QuarterNorth Acquisition.

### Overview of Debt Instruments

***9.000% Second-Priority Senior Secured Notes — due February 2029 —*** The 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, Talos Production Inc. (the “Issuer”), the subsidiary guarantors party thereto (together with the Company, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. 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 rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.000% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.000% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.375% Notes (as defined below) and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.000% Notes including indebtedness under the Bank Credit Facility. The 9.000% Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 — *Debt”* for more information.

***9.375% Second-Priority Senior Secured Notes — due February 2031 —*** The 9.375% Second-Priority Senior Secured Notes due 2031 (the “9.375% Notes” and, together with the 9.000% Notes, the “New Senior Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, the Issuer, the Guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. 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 rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.375% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.375% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.000% Notes and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.375% Notes including indebtedness under the Bank Credit Facility. The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 — *Debt”* for more information.

***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.

***Redemption of the 12.00% Second-Priority Senior Secured Notes — due January 2026 —*** On February 7, 2024, we redeemed $638.5 million aggregate principal amount of the 12.00% Notes using the proceeds from the issuance of the New Senior Notes. See Part I, Item 1. “Financial Statements — Note 7 — *Debt”* for more information.

***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.

### Material Cash Requirements

We have various contractual obligations in the normal course of our operations. Some of these obligations may be reflected in our accompanying Condensed Consolidated Financial Statements, while other obligations, such as certain operating leases and capital commitments, are not reflected on our accompanying Condensed Consolidated Financial Statements.

The following table and discussion summarize our material cash requirements from known contractual obligations as of June 30, 2024 (in thousands):

| Long-term financing obligations: | 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | Total(4) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Debt principal | $— | $— | $— | $225,000 | $— | $1,250,000 | $1,475,000 |
| Debt interest | 66,914 | 137,656 | 137,656 | 120,547 | 114,844 | 174,609 | 752,226 |
| Vessel commitments(1) | 51,447 | 64,680 | — | — | — | — | 116,127 |
| Derivative liabilities | 35,843 | 17,205 | — | — | — | — | 53,048 |
| Operating lease obligations | 2,995 | 5,656 | 4,983 | 4,753 | 4,610 | 4,584 | 27,581 |
| Finance lease(2) | 23,424 | 19,520 | — | — | — | — | 42,944 |
| Purchase obligations(3) | 83,884 | 1,152 | — | — | — | — | 85,036 |
| Other commitments | — | — | — | — | — | — | — |
| Total contractual obligations(4) | $264,507 | $245,869 | $142,639 | $350,300 | $119,454 | $1,429,193 | $2,551,962 |

(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 we utilize to produce the Phoenix Field.

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

(4) 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.”*

***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.

### Critical Accounting Estimates

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.”

### Recently Adopted Accounting Standards

None.

### Recently Issued Accounting Standards

No accounting standards were issued during the quarterly period ended June 30, 2024 that were material to us.

## Market risk

As filed, 1,503 characters.

For information regarding our exposures to certain market risks, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2023 Annual Report. Except as discussed below, there have been no material changes from the disclosures presented in our 2023 Annual Report regarding our exposures to certain market risks.

### Price Risk Management Activities

We had commodity derivative instruments in place to reduce the price risk associated with future production of 16,584 MBbls of crude oil and 25,835 MMBtu of natural gas at June 30, 2024, with a net derivative liability position of $33.9 million. For additional information regarding our commodity derivative instruments, see Part I, Item 1. “Financial Statements — Note 5 — *Financial Instruments,”* included elsewhere in this Quarterly Report. The table below presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at June 30, 2024 (in thousands):

|  | Fair Value | Oil and Natural Gas Derivatives Ten Percent Increase Fair Value | Change | Ten Percent Decrease Fair Value | Change |
| --- | ---: | ---: | ---: | ---: | ---: |
| Price impact(1) | $(33,852) | $(157,211) | $(123,359) | $90,219 | $124,071 |

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

## Controls and procedures

As filed, 1,752 characters.

### Disclosure Controls and Procedures

Under the supervision and with the participation of our management, our principal executive officer and principal financial officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2024.

### Internal Control over Financial Reporting

On March 4, 2024, we completed the QuarterNorth Acquisition. Other than integrating the acquired operations of QuarterNorth into our overall internal control over financial reporting and related processes, there were no other changes in our internal control over financial reporting identified in management's evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended June 30, 2024 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 729 characters.

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under Part I, Item 1A. “Risk Factors” included in our 2023 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our 2023 Annual Report or our other SEC filings.

Filed Aug 8, 2024.
Source: SEC EDGAR, the filing index for accession 0000950170-24-093063. Last ingested by Listed: Nov 3, 2026, 21:34 ET. No prices; not investment advice.