# Talos Energy Inc.: Form 10-Q for the period ended Mar 31, 2024

- Company: [Talos Energy Inc.](/companies/talo.md) (CIK 1724965)
- Form: 10-Q
- Filed: 2024-05-07
- Accepted by EDGAR: May 6, 2024, 18:00 ET
- Period: 2024-03-31
- Accession: 0000950170-24-053731
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1724965/000095017024053731/talo-20240331.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1724965/000095017024053731/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2024-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2024-01-01 to 2024-03-31 | $429.9m | us-gaap:Revenues |
| Operating income | 3 months, 2024-01-01 to 2024-03-31 | $67.8m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2024-01-01 to 2024-03-31 | $50.8m | us-gaap:InterestExpense |
| Income tax | 3 months, 2024-01-01 to 2024-03-31 | −$21.6m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2024-01-01 to 2024-03-31 | −$112.4m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2024-01-01 to 2024-03-31 | −$0.71 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2024-01-01 to 2024-03-31 | −$0.71 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2024-01-01 to 2024-03-31 | 158,490,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2024-01-01 to 2024-03-31 | $96.4m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Share repurchases | 3 months, 2024-01-01 to 2024-03-31 | $0 | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2024-03-31 | $21.0m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2024-03-31 | $540.9m | us-gaap:AssetsCurrent |
| Total assets | at 2024-03-31 | $6.43bn | us-gaap:Assets |
| Current liabilities | at 2024-03-31 | $696.9m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2024-03-31 | $3.68bn | us-gaap:Liabilities |
| Long-term debt | at 2024-03-31 | $1.53bn | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2024-03-31 | $0 | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2024-03-31 | $2.75bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 51,420 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 2023 Annual Report.

***Talos Low Carbon Solutions Divestiture—*** On March 18, 2024, we entered into a definitive agreement relating to and subsequently completed the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC, to TotalEnergies E&P USA, Inc. for a purchase price of $125.0 million plus customary reimbursements and adjustments, combined totaling approximately $142.0 million (the “TLCS Divestiture”). The TLCS Divestiture includes Talos’s entire CCS business, including its equity investments in three projects along the U.S. Gulf Coast: Bayou Bend CCS LLC; Harvest Bend CCS LLC; and Coastal Bend CCS LLC. See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for more information.

***QuarterNorth Acquisition —*** We executed an agreement and plan of merger, dated as of January 13, 2024, by and among Talos, QuarterNorth Energy Inc. (“QuarterNorth”), Compass Star Merger Sub Inc. and the Equityholder Representatives named therein (the “QuarterNorth Merger Agreement”) to acquire QuarterNorth, a privately-held U.S. Gulf of Mexico exploration and production company (such acquisition, the “QuarterNorth Acquisition”). On March 4, 2024, the Company completed the QuarterNorth Acquisition for consideration consisting of (i) $1,247.4 million in cash and (ii) 24.3 million shares of the Company’s common stock valued at $322.6 million. The cash payment was partially funded with an upsized underwritten public offering of 34.5 million shares of the Company’s common stock, borrowings under the Bank Credit Facility and the New Senior Notes (each as defined below). See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for more information.

### Factors Affecting the Comparability of our Financial Condition and Results of Operations

The following items affect the comparability of our financial condition and results of operations for periods presented herein and could potentially continue to affect our future financial condition and results of operations.

***QuarterNorth Acquisition —*** On March 4, 2024, we 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.

***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 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.

The U.S. Energy Information Administration (“EIA”) published its April 2024 Short-Term Energy Outlook on April 9, 2024. The EIA expectations for global oil prices have increased since its last short-term energy outlook report reflecting its expectation of strong global oil inventory draws during the second quarter of 2024 and ongoing geopolitical risks. Oil prices continued to increase in March because of heightened geopolitical risk related to the attacks targeting commercial ships transiting the Red Sea shipping channel and general elevated tensions around the region, including the Israel-Hamas war. In addition, the recent extension of OPEC Plus voluntary production cuts, which expire at the end of June 2024, add to upward price pressure at a time of the year when oil demand typically increases because of the spring and summer driving seasons in the Northern Hemisphere. The EIA expects the NYMEX WTI spot price will average $85.30 per Bbl in the second quarter of 2024 and $83.78 per Bbl for all of 2024. The U.S. winter natural gas withdrawal season ended with more natural gas in storage compared with the five-year average. The large storage surplus contributed to low natural gas prices throughout the first quarter of 2024. From April through October this year, the EIA forecasts less natural gas will be injected into storage than is typical, largely because they expect the United States will produce less natural gas on average in the second and third quarter of 2024 compared with the first quarter of 2024. Despite lower production, the EIA still expects the United States will have the most natural gas in storage on record when the winter withdrawal season begins in November 2024. As a result of high inventories, the EIA expects spot natural gas prices to average less than $2.00 per MMBtu in the second quarter of 2024 and $2.15 per MMBtu for all of 2024.

***Inflation of Cost of Goods, Services and Personnel —*** Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also 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 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.

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.

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.

***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.

***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.

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.

***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 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.

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.

### 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 (in thousands, except per unit data):

| Revenues: | Three Months Ended March 31, 2024 | 2023 | Change |
| --- | ---: | ---: | ---: |
| Oil | $393,221 | $292,694 | $100,527 |
| Natural gas | 23,698 | 20,183 | 3,515 |
| NGL | 13,013 | 9,705 | 3,308 |
| Total revenues | $429,932 | $322,582 | $107,350 |
| **Production Volumes:** |  |  |  |
| Oil (MBbls) | 5,173 | 4,106 | 1,067 |
| Natural gas (MMcf) | 8,659 | 7,127 | 1,532 |
| NGL (MBbls) | 632 | 429 | 203 |
| Total production volume (MBoe) | 7,248 | 5,723 | 1,525 |
| **Daily Production Volumes by Product:** |  |  |  |
| Oil (MBblpd) | 56.8 | 45.6 | 11.2 |
| Natural gas (MMcfpd) | 95.2 | 79.2 | 16.0 |
| NGL (MBblpd) | 6.9 | 4.8 | 2.1 |
| Total production volume (MBoepd) | 79.6 | 63.6 | 16.0 |
| **Average Sale Price Per Unit:** |  |  |  |
| Oil (per Bbl) | $76.02 | $71.28 | $4.74 |
| Natural gas (per Mcf) | $2.74 | $2.83 | $(0.09) |
| NGL (per Bbl) | $20.59 | $22.62 | $(2.03) |
| Price per Boe | $59.32 | $56.37 | $2.95 |
| Price per Boe (including realized commodity derivatives) | $58.84 | $54.21 | $4.63 |

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 March 31, 2024 vs 2023 Price | Volume | Total |
| --- | ---: | ---: | ---: |
| Oil | $24,471 | $76,056 | $100,527 |
| Natural gas | (821) | 4,336 | 3,515 |
| NGL | (1,284) | 4,592 | 3,308 |
| Total revenues | $22,366 | $84,984 | $107,350 |

30

***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.

### Operating Expenses

### Lease Operating Expense

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

|  | Three Months Ended March 31, 2024 | 2023 |
| --- | ---: | ---: |
| Lease operating expenses | $135,178 | $81,362 |
| Lease operating expenses per Boe | $18.65 | $14.22 |

***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.

### 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 March 31, 2024 | 2023 |
| --- | ---: | ---: |
| Depreciation, depletion and amortization | $215,664 | $147,323 |

***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.

### 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 March 31, 2024 | 2023 |
| --- | ---: | ---: |
| Upstream Segment | $56,082 | $58,355 |
| CCS Segment | 1,965 | 3,329 |
| Unallocated corporate | 11,794 | 1,503 |
| Total general and administrative expense | $69,841 | $63,187 |
| Upstream general and administrative expense per Boe | $7.74 | $10.20 |

***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.

### 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 March 31, 2024 | 2023 |
| --- | ---: | ---: |
| Accretion expense | $26,903 | $19,414 |
| Other operating (income) expense | $(86,043) | $2,838 |
| Interest expense | $50,845 | $37,581 |
| Price risk management activities (income) expense | $87,062 | $(58,937) |
| Equity method investment (income) expense | $8,054 | $(7,443) |
| Other (income) expense | $55,896 | $(6,666) |
| Income tax (benefit) expense | $(21,573) | $(46,543) |

### Three Months Ended March 31, 2024 and 2023 —

***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.”*

***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.

***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.

***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.

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 —*** 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.

***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.

***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.”*

### 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 March 31, 2024 | 2023 |
| --- | ---: | ---: |
| Net income (loss) | $(112,439) | $89,860 |
| Interest expense | 50,845 | 37,581 |
| Income tax (benefit) expense | (21,573) | (46,543) |
| Depreciation, depletion and amortization | 215,664 | 147,323 |
| Accretion expense | 26,903 | 19,414 |
| EBITDA | 159,400 | 247,635 |
| Transaction and other (income) expenses(1) | (49,157) | 22,009 |
| Decommissioning obligations(2) | 855 | 741 |
| Derivative fair value (gain) loss(3) | 87,062 | (58,937) |
| Net cash received (paid) on settled derivative instruments(3) | (3,494) | (12,323) |
| (Gain) loss on debt extinguishment | 60,256 | — |
| Non-cash equity-based compensation expense | 2,754 | 3,938 |
| Adjusted EBITDA | $257,676 | $203,063 |

(1) 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.

(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.”*

(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 March 31, 2024, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $650.2 million.

We fund drilling, completions and development activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities.

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 three months ended March 31, 2024 (in thousands):

|  |  |
| --- | ---: |
| U.S. drilling & completions | $44,081 |
| Asset management(1) | 24,982 |
| Seismic and G&G, land, capitalized G&A and other | 43,372 |
| Total Upstream capital expenditures | 112,435 |
| Plugging & abandonment | 27,907 |
| Decommissioning obligations settled(2) | 3,506 |
| Total Upstream | 143,848 |
| Investment in CCS | 17,519 |
| Total | $161,367 |

(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 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.

***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.

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):

|  | Three Months Ended March 31, 2024 | 2023 |
| --- | ---: | ---: |
| Operating activities | $96,426 | $62,857 |
| Investing activities | $(937,644) | $(106,976) |
| Financing activities | $829,580 | $117,116 |

***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.

***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.

***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.

### 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 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.

***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 —*** 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.

### 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 March 31, 2024 (in thousands):

| Long-term financing obligations: | 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | Total(4) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Debt principal | $— | $— | $— | $325,000 | $— | $1,250,000 | $1,575,000 |
| Debt interest | 85,569 | 144,904 | 144,904 | 122,359 | 114,844 | 174,609 | 787,189 |
| Vessel commitments(1) | 35,748 | 14,210 | — | — | — | — | 49,958 |
| Derivative liabilities | 63,991 | 13,789 | — | — | — | — | 77,780 |
| Operating lease obligations | 4,220 | 5,531 | 4,983 | 4,753 | 4,610 | 4,583 | 28,680 |
| Finance lease(2) | 35,136 | 19,520 | — | — | — | — | 54,656 |
| Purchase obligations(3) | 118,251 | 550 | — | — | — | — | 118,801 |
| Other commitments | 2,108 | — | — | — | — | — | 2,108 |
| Total contractual obligations(4) | $345,023 | $198,504 | $149,887 | $452,112 | $119,454 | $1,429,192 | $2,694,172 |

(1) Includes vessel commitments we will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will be billed for their working interest share of such costs.

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

(3) Includes committed purchase orders to execute planned future drilling activities.

(4) This table does not include our estimated discounted liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $1,109.3 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.”*

***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.

### Critical Accounting Estimates

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.”

### Recently Adopted Accounting Standards

None.

### Recently Issued Accounting Standards

No recently issued accounting standards were material to us.

## Market risk

As filed, 1,505 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 16,569 MBbls of crude oil and 29,677 MMBtu of natural gas at March 31, 2024, with a net derivative liability position of $53.7 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 March 31, 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) | $(53,672) | $(175,027) | $(121,355) | $68,688 | $122,360 |

(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, 1,754 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 March 31, 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 March 31, 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 May 7, 2024.
Source: SEC EDGAR, the filing index for accession 0000950170-24-053731. Last ingested by Listed: Nov 3, 2026, 21:34 ET. No prices; not investment advice.