Chord Energy Corp: Form 10-Q for the period ended Mar 31, 2025

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2024 (“2024 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategic tactics, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plans” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and detailed under “Part II, Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Without limiting the generality of the foregoing, certain statements incorporated by reference or included in this Quarterly Report on Form 10-Q constitute forward-looking statements.

Forward-looking statements may include statements about:

• crude oil, NGLs and natural gas realized prices;
• uncertainty regarding the future actions of foreign oil producers and the related impacts such actions have on the balance between the supply of and demand for crude oil, NGLs and natural gas;
• the actions taken by OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;
• changes in trade policies and regulations, including increases or change in duties, current and potentially new tariffs or quotas; and other similar measures, as well as the potential impact of retaliatory tariffs and other actions;
• war between Russia and Ukraine, military conflicts in the Red Sea Region and war between Hamas and Israel, with the potential for escalation of hostilities across the surrounding countries in the Middle East, and their effect on commodity prices;
• changes in general economic and geopolitical conditions, including as a result of change of administration in the federal government of the United States;
• inflation rates and the impact of associated monetary policy responses, including increased interest rates;
• logistical challenges and supply chain disruptions;
• our business strategy;
• the geographic concentration of our operations;
• estimated future net reserves and present value thereof;
• timing and amount of future production of crude oil, NGLs and natural gas;
• drilling and completion of wells;
• estimated inventory of wells remaining to be drilled and completed;
• costs of exploiting and developing our properties and conducting other operations;
• availability of drilling, completion and production equipment and materials;
• availability of qualified personnel;
• infrastructure for produced and flowback water gathering and disposal;
• gathering, transportation and marketing of crude oil, NGLs and natural gas in the Williston Basin and other regions in the United States;
• the possible shutdown of the Dakota Access Pipeline;
• incurring significant transaction and other costs in connection with the Arrangement (as defined in the “Results of Operations” section of Item 2 below) in excess of those anticipated;
• the ultimate timing, outcome and results of integrating the operations of Chord and Enerplus;
• failure to realize the anticipated benefits or synergies from the Arrangement in the timeframe expected or at all;
• property acquisitions, including the Arrangement, and divestitures;
• integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness, including the Arrangement;
• the amount, nature and timing of capital expenditures;
• availability and terms of capital;
• our financial strategic tactics, budget, projections, execution of business plan and operating results;
• cash flows and liquidity;
• our ability to pursue capital management activities such as share repurchases, paying dividends on our common stock or additional means to return capital to shareholders;
• our ability to utilize net operating loss carryforwards or other tax attributes in future periods;
• our ability to comply with the covenants under our Credit Agreement and other indebtedness;
• operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
• interruptions in service and fluctuations in tariff provisions of third-party connecting pipelines;
• potential effects arising from cybersecurity threats, terrorist attacks and any consequential or other hostilities;
• compliance with, and changes in, environmental, safety and other laws and regulations, including the Inflation Reduction Act of 2022;
• execution of our sustainability initiatives;
• effectiveness of risk management activities;
• competition in the oil and gas industry;
• counterparty credit risk;
• incurring environmental liabilities;
• developments in the global economy as well as any public health crisis and resulting demand and supply for crude oil, NGLs and natural gas;
• governmental regulation and the taxation of the oil and gas industry;
• developments in crude oil-producing and natural gas-producing countries;
• technology;
• consumer demand and preferences for, and governmental policies encouraging, fossil fuel alternatives;
• the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements;
• uncertainty regarding future operating results;
• our ability to successfully forecast future operating results and manage activity levels with ongoing macroeconomic uncertainty;
• the impact of disruptions in the financial markets, including bank failures and the elevated interest rate environment;
• plans, objectives, expectations and intentions contained in this Quarterly Report on Form 10-Q that are not historical; and
• certain factors discussed elsewhere in this Quarterly Report on Form 10-Q, in our 2024 Annual Report and in our other filings with the SEC.

All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include changes in crude oil, NGL and natural gas prices, climatic and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, inflation, changing trade policies, the proximity to and capacity of transportation facilities and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Quarterly Report on Form 10-Q, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Overview

Chord Energy Corporation (together with its consolidated subsidiaries, the “Company”, “Chord”, “we”, “us,” or “our”) is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, NGL and natural gas primarily in the Williston Basin. Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a rewarding environment for our employees. We are ideally positioned to enhance return of capital and generate strong free cash flow, while being responsible stewards of the communities and environment where we operate.

Market Conditions and Commodity Prices

Our revenue, profitability and ability to return cash to shareholders depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Prices for crude oil, NGLs and natural gas have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future due to a combination of macro-economic factors that impact the supply and demand for crude oil, NGLs and natural gas. The potential for continued volatility in our markets, economic uncertainty and unfavorable oil and gas market dynamics, including the recent OPEC+ announcement to increase oil production levels, U.S. tariffs and potential retaliatory tariffs, may have an adverse impact on our future business operations, financial condition and liquidity. Recent volatility in the energy markets during the second quarter of 2025 has led to a decrease in the price of crude oil. Further decline in the price of crude oil, or a sustained depression of the price of crude oil for an extended period of time, could have a material adverse effect on our financial position, results of operations, cash flows, the quantities of crude oil, NGL and natural gas reserves that may be economically produced, the assessment of goodwill impairment, and our access to capital.

While we are unable to predict future commodity prices, we do not believe that an impairment of our oil and gas properties is reasonably likely to occur at current price levels as it is more likely than not that the fair value of our oil and gas properties will continue to exceed its carrying value. We will continue to evaluate the recoverability of the carrying value of our oil and gas properties as a result of a future material or extended decline in the current price of crude oil, NGLs or natural gas or a material increase in the costs of labor, materials or services.

A sustained decline in the price of our common stock, coupled with depressed crude oil prices as a result of the significant changes in market volatility could result in a non-cash goodwill impairment charge in future periods that could be material to our results of operations and financial statements as a whole.

In an effort to improve price realizations from the sale of our crude oil, NGLs and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGLs and natural gas to a broader array of potential purchasers. We enter into crude oil, NGL and natural gas sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single customer would have a material adverse effect on our results of operations or cash flows.

Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of March 31, 2025, substantially all of our gross operated crude oil and natural gas production were connected to gathering systems.

Results of Operations

Comparability of Financial Statements

On May 31, 2024, we acquired Enerplus Corporation (“Enerplus”) in a stock-and-cash transaction (“the “Arrangement”). Enerplus was an independent North American oil and gas E&P company domiciled in Canada with substantially all of its producing assets in the Williston Basin of North Dakota, with limited non-operated interests in the Marcellus Shale. The results of operations presented below relate to the three months ended March 31, 2025, December 31, 2024 and March 31, 2024. The results reported for the three months ended March 31, 2025 and December 31, 2024 reflect the consolidated results of Chord, including combined operations with Enerplus, while the results reported for the three months ended March 31, 2024 reflect the consolidated results of Chord, excluding the impact from the business combination with Enerplus, unless otherwise noted.

Operational and Financial Highlights

• Production volumes averaged 270,855 Boepd (57% oil), including crude oil volumes of 153,720 Bopd in the first quarter of 2025.
• E&P and other capital expenditures (excluding capitalized interest) were $355.4 million in the first quarter of 2025.
• Lease operating expenses (“LOE”) were $9.56 per Boe in the first quarter of 2025.
• Net cash provided by operating activities was $656.9 million and net income was $219.8 million in the first quarter of 2025.
• Issued $750.0 million 6.750% senior unsecured notes due March 15, 2033 (the “2033 Senior Notes”) in March 2025.

Shareholder Return Highlights

• Paid $1.30 per share base cash dividend on March 26, 2025.
• Repurchased $216.5 million of common stock in the first quarter of 2025 with $376.1 million remaining under our $750 million share repurchase program.
• Declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on June 9, 2025 to shareholders of record as of May 21, 2025.

Revenues

Our crude oil, NGL and natural gas revenues are derived from the sale of crude oil, NGL and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold and/or changes in commodity prices. Our revenues for the three months ended March 31, 2025 increased compared to the three months ended March 31, 2024 due to the Arrangement, which expanded our operations primarily in the Williston Basin. Our purchased oil and gas sales are derived from the sale of crude oil, NGLs and natural gas purchased through our marketing activities primarily to optimize transportation costs, for blending to meet pipeline specifications or to cover production shortfalls. Revenues and expenses from crude oil, NGL and natural gas sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the counterparty. In certain cases, we enter into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis.

The following table summarizes our revenues, production and average realized prices for the periods presented:

(1) For the three months ended March 31, 2025 and December 31, 2024, natural gas production volume from the Marcellus Shale was 11,563 MMcf and 10,454 MMcf, respectively. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $4.71 per Mcf and $2.29 per Mcf for the three months ended March 31, 2025 and December 31, 2024, respectively.

(2) The effect of derivative settlements includes the gains or losses on commodity derivatives for contracts ending in the periods presented. Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes.

Three months ended March 31, 2025 as compared to three months ended December 31, 2024

Crude oil revenues. Our crude oil revenues decreased $14.3 million to $956.1 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. The decrease was primarily due to a decrease in crude oil production volumes sold quarter over quarter resulting in a $18.8 million decrease, partially offset by an increase of $4.5 million due to higher crude oil realized prices quarter over quarter. Average crude oil sales prices, without derivative settlements, increased by $0.32 per barrel quarter over quarter to an average of $69.11 per barrel for the three months ended March 31, 2025 primarily due to an increase in NYMEX WTI.

NGL revenues. Our NGL revenues increased $13.3 million to $61.3 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. The increase was primarily due to higher realized NGL prices quarter over quarter resulting in a $19.5 million increase, partially offset by a decrease of $6.2 million due to lower NGL production volumes sold quarter over quarter. Average NGL sales prices, without derivative settlements, increased by $4.11 per barrel quarter over quarter to an average of $14.18 per barrel for the three months ended March 31, 2025 primarily due to increases in the corresponding NGL product index prices.

Natural gas revenues. Our natural gas revenues increased $40.1 million to $85.9 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. The increase was primarily due to higher natural gas realized prices quarter over quarter. Average natural gas sales prices, without derivative settlements, increased by $1.09 per Mcf quarter over quarter to $2.30 per Mcf for the three months ended March 31, 2025 primarily due to the seasonality of colder weather resulting in higher index prices quarter over quarter.

Purchased oil and gas sales. Purchased oil and gas sales decreased $278.8 million to $111.6 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. This decrease was primarily due to a decrease in the volume of crude oil purchased and subsequently sold quarter over quarter.

Three months ended March 31, 2025 as compared to three months ended March 31, 2024

Crude oil revenues. Our crude oil revenues increased $277.3 million to $956.1 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. Our crude oil revenues increased $318.5 million due to our expanded operations as a result of the Arrangement. Excluding the increase from the Arrangement, crude oil revenues decreased $55.2 million due to lower crude oil realized prices, partially offset by an increase of $14.1 million due to higher crude oil production volumes sold. Average crude oil sales prices, without derivative settlements, decreased by $6.13 per barrel period over period to an average of $69.11 per barrel for the three months ended March 31, 2025 due to decreases in NYMEX WTI and widening in-basin differentials period over period.

NGL revenues. Our NGL revenues increased $14.1 million to $61.3 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. Our NGL revenues increased $5.7 million due to our expanded operations as a result of the Arrangement. Excluding the increase from the Arrangement, NGL revenues increased $6.6 million due to higher realized NGL prices period over period, coupled with an increase of $1.4 million due to higher NGL production volumes sold. Average NGL sales prices, without derivative settlements, increased by $2.12 per barrel period over period to an average of $17.21 per barrel for the three months ended March 31, 2025 primarily due to increases in the corresponding NGL product index prices and improved differentials period over period.

Natural gas revenues. Our natural gas revenues increased $63.9 million to $85.9 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. Our natural gas revenues increased $51.0 million due to our expanded operations as a result of the Arrangement. Excluding the increase from the Arrangement, natural gas revenues increased $13.2 million primarily due to higher average natural gas sales prices. Average natural gas sales prices, without derivative settlements, increased by $0.69 per Mcf period over period to $1.85 per Mcf for the three months ended March 31, 2025 primarily due to increases in index prices period over period.

Purchased oil and gas sales. Purchased oil and gas sales decreased $225.5 million to $111.6 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. This decrease was primarily due to a decrease in the volume of crude oil purchased and subsequently sold period over period.

Expenses and other income (expense)

The following table summarizes our operating expenses and other income (expense) for the periods presented:

(In thousands, except per Boe of production data)

Three months ended March 31, 2025 as compared to three months ended December 31, 2024

Lease operating expenses. LOE decreased $8.4 million to $233.1 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. The decrease was primarily due to lower variable and fixed costs quarter over quarter of $12.3 million primarily resulting from continued execution and operational improvements, offset by higher workover costs of $3.9 million quarter over quarter. LOE per Boe decreased $0.04 per Boe quarter over quarter to $9.56 per Boe for the three months ended March 31, 2025.

Purchased oil and gas expenses. Purchased oil and gas expenses decreased $279.3 million to $111.4 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024 primarily due to a decrease in the volume of crude oil purchased and subsequently sold quarter over quarter.

Production taxes. Production taxes decreased $14.3 million to $74.6 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. The decrease was primarily due to a non-recurring refund related to certain North Dakota wells receiving an extraction tax exemption, which reduces the overall production tax rate, coupled with the impact of slightly lower crude oil sales quarter over quarter. The production tax rate as a percentage of crude oil, NGL and natural gas sales of 6.8% for the three months ended March 31, 2025 decreased from 8.4% for the three months ended December 31, 2024 primarily as a result of the extraction tax exemption for certain wells within the current quarter coupled with natural gas comprising a larger percentage of total sales relative to the prior quarter.

Depreciation, depletion and amortization. DD&A expense decreased $0.9 million to $349.8 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. The decrease was primarily driven by lower production volumes of $14.0 million quarter over quarter, offset by $14.3 million related to a higher depletion rate quarter over quarter. The depletion rate increased $0.46 per Boe quarter over quarter to $14.09 per Boe for the three months ended March 31, 2025 primarily due to downward revisions to our proved reserves at December 31, 2024 largely driven by lower crude oil prices.

General and administrative expenses. G&A expenses decreased $7.3 million to $38.4 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. The decrease was primarily attributable to various cost savings related to other G&A expenses of $5.6 million, coupled with a decrease in merger-related costs of $3.8 million. Merger-related costs for the three months ended March 31, 2025 and December 31, 2024 were $5.1 million and $9.0 million, respectively, and were primarily comprised of severance, legal and advisory expenses related to the Arrangement in both periods.

Gain on sale of assets, net. During the three months ended March 31, 2025 and December 31, 2024, we recorded a net gain on sale of assets of $5.5 million and $3.3 million, respectively, primarily related to the divestiture of certain oil and gas properties within each quarter.

Derivative instruments. We recorded a $20.3 million net loss on derivative instruments for the three months ended March 31, 2025, which was comprised of a net loss of $21.0 million associated with our commodity derivative contracts, offset by an unrealized gain of $0.7 million associated with a contract that includes contingent consideration. The net loss of $21.0 million on commodity derivative contracts included an unrealized loss of $20.7 million related to the change in fair value of our commodity derivative contracts primarily driven by an upward shift in the futures curve for forecasted commodity prices and a realized loss of $0.3 million on settled commodity derivative contracts. During the three months ended December 31, 2024, we recorded a $17.2 million net loss on derivative instruments, which was comprised of a net loss of $19.7 million associated with our commodity derivative contracts, partially offset by a gain of $2.5 million associated with a contract that includes contingent consideration. The net loss of $19.7 million on commodity derivative contracts included an unrealized loss of $24.8 million related to the change in fair value of our commodity derivative contracts primarily driven by an upward shift in the futures curve for forecasted commodity prices, partially offset by a realized gain of $5.1 million on settled commodity derivative contracts.

Investment in unconsolidated affiliate. We recorded a $4.9 million net loss related to our investment in Energy Transfer LP (“Energy Transfer”) for the three months ended March 31, 2025, which included an unrealized loss of $7.3 million as a result of a decrease in the fair value of the investment during the quarter, partially offset by a gain of $2.4 million for a cash distribution from Energy Transfer during the quarter. During the three months ended December 31, 2024, we recorded a $28.0 million gain related to our investment in Energy Transfer due to an unrealized gain of $25.7 million as a result of an increase in the fair value of the investment during the quarter, coupled with a gain of $2.3 million for a cash distribution from Energy Transfer during the quarter.

Interest expense, net of capitalized interest. Interest expense decreased $1.8 million to $15.8 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. The decrease was primarily due to lower borrowings on the Credit Facility (defined below) during the quarter, and the purchase and satisfaction and discharge of the $400.0 million 6.375% senior unsecured notes outstanding due June 1, 2026 (the “2026 Senior Notes”), partially offset by the issuance of the 2033 Senior Notes in March 2025. For the three months ended March 31, 2025, the weighted average borrowings outstanding under the Credit Facility were $383.4 million, and the weighted average interest rate incurred on the outstanding borrowings was 6.4%. For the three months ended December 31, 2024, the weighted average borrowings outstanding under the Credit Facility were $573.6 million, and the weighted average interest rate incurred on the outstanding borrowings was 6.9%. Interest capitalized during the three months ended March 31, 2025 and December 31, 2024 was $1.1 million and $1.2 million, respectively.

Loss on debt extinguishment. On March 13, 2025, we paid an aggregate of $409.1 million to purchase and satisfy and discharge the 2026 Senior Notes, resulting in a loss on debt extinguishment of $3.5 million for the three months ended March 31, 2025. The loss primarily included the write-off of unamortized debt issuance costs of $2.1 million and a premium paid to redeem a portion of the 2026 Senior Notes of $1.1 million.

Income tax expense. Our effective tax rate was recorded at 25.0% and 18.8% of pre-tax income for the three months ended March 31, 2025 and December 31, 2024, respectively. The effective tax rate for the three months ended March 31, 2025 was higher than the statutory federal rate of 21% primarily as a result of the impact of state income taxes and deferred taxes on unremitted earnings. The effective tax rate for the three months ended December 31, 2024 was lower than the statutory federal rate of 21% primarily as a result of reducing the blended state tax rate at which our deferred tax assets and liabilities were recorded, coupled with recognizing a benefit for transaction costs recorded during the three months ended December 31, 2024.

Three months ended March 31, 2025 as compared to three months ended March 31, 2024

Lease operating expenses. LOE increased $73.9 million to $233.1 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. The increase was primarily driven by our expanded operations after the Arrangement contributing $62.8 million of additional LOE period over period, increased fixed costs of $8.8 million and increased workover costs of $6.4 million. LOE per Boe decreased $0.83 per Boe period over period to $9.56 per Boe for the three months ended March 31, 2025 primarily due to operational synergies achieved through the Arrangement.

Gathering, processing and transportation expenses. GPT expenses increased $19.3 million to $73.3 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. The increase was primarily due to our expanded operations after the Arrangement contributing $29.5 million of additional GPT expenses. This increase was partially offset by lower transportation rates of $5.6 million, primarily due to several contracts expiring during the year ended December 31, 2024, and lower fair value losses of $3.2 million attributable to the completion of a derivative transportation contract in June 2024. This net increase resulted in an increase in GPT expenses of $0.51 per Boe period over period to $3.01 per Boe for the three months ended March 31, 2025.

Purchased oil and gas expenses. Purchased oil and gas expenses decreased $224.4 million to $111.4 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024 primarily due to a decrease in the volume of crude oil purchased and subsequently sold period over period.

Production taxes. Production taxes increased $10.7 million to $74.6 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. The increase was primarily due to an overall increase in crude oil sales period over period and included a $29.9 million increase in production taxes attributable to our expanded operations after the Arrangement. This increase was partially offset by lower crude oil prices period over period and a reduction in the production tax rate during the three months ended March 31, 2025 primarily due to a non-recurring refund related to certain North Dakota wells receiving an extraction tax exemption. The production tax rate as a percentage of crude oil, NGL and natural gas sales decreased from 8.5% for the three months ended March 31, 2024 to 6.8% for the three months ended March 31, 2025 primarily due to a non-recurring refund related to the extraction tax exemption for certain wells within the current quarter coupled with natural gas comprising a larger percentage of total sales relative to the prior period.

Depreciation, depletion and amortization. DD&A expense increased $180.9 million to $349.8 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. The increase was primarily due to $106.5 million of additional depletion expense due to a higher depletion rate period over period, coupled with $74.1 million of additional DD&A expense related to an overall increase in production volumes, mainly due to our expanded operations after the Arrangement. The depletion rate increased $3.47 per Boe period over period to $14.09 per Boe for the three months ended March 31, 2025 primarily due to the purchase consideration allocated to the fair value of the oil and gas properties acquired in the Arrangement.

General and administrative expenses. G&A expenses increased $12.7 million to $38.4 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024 primarily due to an increase in costs associated with a larger organization after the Arrangement of $15.7 million, partially offset by decreased merger-related costs of $3.0 million. Merger-related costs for the three months ended March 31, 2025 and 2024 were $5.1 million and $8.1 million, respectively, and were primarily comprised of severance, legal and advisory expenses related to the Arrangement in both periods.

Exploration and impairment. Exploration and impairment expenses decreased $4.2 million to $2.0 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024 primarily due to a lower of cost or net realizable value write down of oil-in-tank inventory recorded during the three months ended March 31, 2024.

Gain on sale of assets, net. During the three months ended March 31, 2025 and 2024, we recorded a net gain on sale of assets of $5.5 million and $1.3 million, respectively, primarily related to the divestiture of certain oil and gas properties within each period.

Derivative instruments. During the three months ended March 31, 2025, we recorded a $20.3 million net loss on derivative instruments, which was comprised of a net loss of $21.0 million associated with our commodity derivative contracts and an unrealized gain of $0.7 million associated with a contract that includes contingent consideration. The net loss of $21.0 million on commodity derivative contracts included an unrealized loss of $20.7 million related to the change in fair value of our commodity derivative contracts primarily driven by an upward shift in the futures curve for forecasted commodity prices and a realized loss of $0.3 million on settled commodity derivative contracts. During the three months ended March 31, 2024, we recorded a $27.6 million net loss on derivative instruments, which was comprised of a net loss of $31.0 million associated with our commodity derivative contracts, partially offset by an unrealized gain of $3.4 million associated with a contract that includes contingent consideration. The net loss of $31.0 million on commodity derivative contracts included an unrealized loss of $29.6 million related to the change in fair value of our commodity derivative contracts primarily driven by an upward shift in the futures curve for forecasted commodity prices and a realized loss of $1.4 million on settled commodity derivative contracts.

Investment in unconsolidated affiliate. We recorded a $4.9 million net loss related to our investment in Energy Transfer for the three months ended March 31, 2025, which included an unrealized loss of $7.3 million as a result of a decrease in the fair value of the investment during the period, offset by a gain of $2.4 million for cash distributions from Energy Transfer during the period. During the three months ended March 31, 2024, we recorded a gain of $16.3 million related to our investment in Energy Transfer, which primarily included an unrealized gain of $14.0 million as a result of an increase in the fair value of the investment during the period, coupled with a gain of $2.3 million for cash distributions from Energy Transfer during the period.

Interest expense, net of capitalized interest. Interest expense increased $8.2 million to $15.8 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. The increase is primarily due to higher borrowings outstanding on the Credit Facility (defined below) period over period and the issuance of the 2033 Senior Notes in March 2025, partially offset by the purchase and satisfaction and discharge of the 2026 Senior Notes in March 2025. For the three months ended March 31, 2025, the weighted average borrowings outstanding under the Credit Facility were $383.4 million, and the weighted average interest rate incurred on the outstanding borrowings was 6.4%. During the three months ended March 31, 2024, we incurred no borrowings under the Credit Facility, resulting in a weighted average interest rate of 0.0%. Interest capitalized during the three months ended March 31, 2025 and March 31, 2024 was $1.1 million and $0.7 million, respectively.

Loss on debt extinguishment. On March 13, 2025, we paid an aggregate of $409.1 million to purchase and satisfy and discharge the 2026 Senior Notes, resulting in a loss on debt extinguishment of $3.5 million for the three months ended March 31, 2025. The loss primarily included the write-off of unamortized debt issuance costs of $2.1 million and a premium paid to redeem a portion of the 2026 Senior Notes of $1.1 million.

Income tax expense. Our effective tax rate was recorded at 25.0% and 22.4% of pre-tax income for the three months ended March 31, 2025 and March 31, 2024, respectively. Our effective tax rate for the three months ended March 31, 2025 was higher than the statutory federal rate of 21% primarily as a result of the impact of state income taxes and deferred taxes on unremitted earnings. The effective tax rate for the three months ended March 31, 2024 was higher than the statutory federal rate of 21% primarily as a result of the impact of state income taxes.

Liquidity and Capital Resources

As of March 31, 2025, we had $1,944.9 million of liquidity available, including $35.8 million in cash and cash equivalents and $1,909.2 million of aggregate unused borrowing capacity available under the Credit Facility (defined below). Our primary sources of liquidity were from cash on hand, cash flows from operations, available borrowing capacity under the Credit Facility and proceeds from the issuance of the 2033 Senior Notes. Our primary liquidity requirements were capital expenditures for the development of oil and gas properties, dividend payments, debt repayments, share repurchases and working capital requirements.

Our cash flows depend on many factors, including the price of crude oil, NGLs and natural gas and the success of our development and exploration activities as well as future acquisitions. Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to our long-term debt, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, payment of income taxes, obligations associated with outstanding commodity derivative contracts that settle in a loss position, obligations to pay dividends on vested equity awards that include dividend equivalent rights and obligations associated with our leases. In addition, we have announced a return of capital plan pursuant to which we intend to return capital to stockholders through dividend payouts, supplemented by opportunistic share repurchases. On a quarterly basis, we pay a commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.

Capital availability will be affected by prevailing conditions in our industry, the global economy, the global banking and financial markets, stakeholder scrutiny of sustainability matters and other factors, many of which are beyond our control. The U.S. Federal Reserve recently decreased interest rates, however the potential for such rates to decrease further or to remain elevated for an extended period of time has created additional economic uncertainty. Although we are unable to predict future interest rates, this disruption to the broader economy and financial markets may reduce our ability to access capital or result in such capital being available on less favorable terms, which could in the future negatively affect our liquidity. We believe, however, we have adequate liquidity to fund our capital expenditures and meet our contractual obligations during the next 12 months and the foreseeable future.

Enerplus Arrangement. In connection with the consummation of the Arrangement on May 31, 2024, we paid $375.8 million, or $1.84 per Enerplus common share, to Enerplus shareholders. In addition, we paid $395.0 million to settle Enerplus’ revolving bank credit facility balance and $102.4 million to settle all outstanding Enerplus equity-based compensation awards, as well as $5.9 million in retention bonuses paid to Enerplus employees.

Also in connection with the Arrangement, we incurred certain costs for advisory, legal and other third-party fees which were recorded to G&A expenses on the Condensed Consolidated Statements of Operations. During the three months ended March 31, 2025, we incurred merger-related costs of $5.1 million, primarily related to severance costs and legal and advisory services.

Commodity derivative contracts. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the impact of changes in crude oil, NGL and natural gas prices on our production, which mitigates our exposure to crude oil, NGL and natural gas price declines; however, these transactions may also limit our cash flow in periods of rising crude oil, NGL and natural gas prices.

As of March 31, 2025, our commodity derivative contracts cover 8,979 MBbls of our crude oil production and 26,077,600 MMBtu of our natural gas production for 2025, 5,181 MBbls of our crude oil production and 25,935,000 MMBtu of our natural gas production for 2026 and 180 MBbls of our crude oil production for 2027. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk” for additional information.

Commitments. We also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, NGLs, natural gas and water within specified time frames, the majority of which are five years or less. Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract. The estimable future commitments under these agreements were $526.6 million as of March 31, 2025. We believe that for the substantial majority of these agreements our future production will be adequate to meet our delivery commitments or that we will be able to purchase sufficient volumes of crude oil, NGLs and natural gas from third parties to satisfy our minimum volume commitments. See “Item 8. Financial Statements and Supplementary Data—Note 21—Commitments and Contingencies” in our 2024 Annual Report for additional information on our volume delivery commitments.

Long-term debt

Revolving credit facility. As of March 31, 2025, we had a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $2.75 billion and elected commitments of $2.0 billion that is due July 1, 2027. As of March 31, 2025, we had $60.0 million borrowings outstanding and $30.8 million of outstanding letters of credit, resulting in an unused borrowing capacity of $1.9 billion. Additionally, we are permitted to incur term loans in addition to the revolving loans provided under the Credit Facility. We were in compliance with the financial covenants under the Credit Facility as of March 31, 2025. See “Item 1. Financial Statements (Unaudited)—Note 10—Long-Term Debt” for additional information.

2033 Senior Notes. On March 13, 2025, we issued in a private placement $750.0 million of 6.750% senior unsecured notes due March 15, 2033 (the “2033 Senior Notes”). Interest on the 2033 Senior Notes is payable semi-annually on March 15 and September 15 of each year. The 2033 Senior Notes were issued at par and resulted in proceeds of $738.8 million, after deducting underwriters’ discounts, commissions and other expenses. The proceeds were used to repurchase the 2026 Senior Notes (defined below) tendered in a concurrent tender offer, to satisfy and discharge the remaining 2026 Senior Notes not tendered in the concurrent tender offer (which will be redeemed on or about June 1, 2025) and to repay a portion of the borrowings outstanding under the Credit Facility. In connection with the issuance of the 2033 Senior Notes, we recorded deferred financing costs of $11.2 million.

2026 Senior Notes. As of December 31, 2024, we had $400.0 million of 6.375% 2026 Senior Notes outstanding that mature on June 1, 2026 (the “2026 Senior Notes”). Interest on the 2026 Senior Notes was payable semi-annually on June 1 and December 1 of each year. Concurrent with the issuance of the 2033 Senior Notes on March 13, 2025, we paid an aggregate of $409.1 million, including $7.7 million of accrued interest, to purchase $366.3 million of outstanding 2026 Senior Notes tendered in a concurrent tender offer and to satisfy and discharge the remaining $33.7 million of outstanding 2026 Senior Notes, which will be redeemed on or about June 1, 2025. See “Item 1. Financial Statements (Unaudited)—Note 10—Long-Term Debt” for additional information.

Cash Flows

Our cash flows for the three months ended March 31, 2025 and 2024 are presented below:

(In thousands)

Cash flows provided by operating activities

Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes and operating costs. Net cash provided by operating activities was $656.9 million for the three months ended March 31, 2025. The increase in net cash provided by operating activities of $250.2 million as compared to the three months ended March 31, 2024 was primarily due to our expanded operations due to the Arrangement, including an increase in oil revenues, offset by increases in LOE, GPT expenses, G&A expenses and production taxes, as well as changes in our working capital. See “Results of Operations” above for additional information.

Working Capital. Our working capital is primarily impacted by the factors discussed above, coupled with the timing of cash receipts and disbursements. Changes in working capital (as reflected in the Condensed Consolidated Statements of Cash Flows) increased net cash flows from operating activities by $37.2 million during the three months ended March 31, 2025 and decreased net cash flows from operating activities by $9.8 million during the three months ended December 31, 2024. Changes in working capital associated with our capital expenditure activities and settlement of outstanding commodity derivative instruments impact our cash flows from investing activities.

The Credit Facility includes a requirement that we maintain a Current Ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter. For purposes of the Current Ratio, the Credit Facility’s definition of total current assets includes unused commitments under the Credit Facility, which were $1.9 billion at March 31, 2025, and excludes current hedge assets, which were $32.8 million at March 31, 2025. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which were $16.3 million at March 31, 2025.

Cash flows used in investing activities

For the three months ended March 31, 2025, net cash used in investing activities of $292.3 million was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $308.9 million and $17.9 million paid primarily for acreage in the Williston Basin, partially offset by the receipt of the 2024 contingent consideration earn-out payment of $25.0 million. Net cash used in investing activities for the three months ended March 31, 2024 of $204.9 million was primarily attributable to capital expenditures of $222.1 million and the settlement of derivative contracts of $12.1 million, partially offset by the receipt of the 2023 contingent consideration earn-out payment of $25.0 million.

Cash flows used in financing activities

For the three months ended March 31, 2025, net cash used in financing activities of $365.8 million was primarily attributable to repayments of 2026 Senior Notes totaling $401.4 million, payments to repurchase our common stock of $215.2 million, dividends paid to shareholders of $86.5 million, payments for income tax withholdings on vested equity-based compensation awards of $14.4 million, payment of debt issuance costs of $13.0 million primarily in connection with the issuance of the 2033 Senior Notes and repayments under the Credit Facility of $1.4 billion, partially offset by borrowings $1.1 billion, resulting in net repayments under the Credit Facility of $385.0 million. These uses of cash were partially offset by proceeds from the issuance of the 2033 Senior Notes of $750.0 million. Net cash used in financing activities for the three months ended March 31, 2024 of $223.5 million was primarily attributable to dividends paid to shareholders of $152.4 million, income tax withholdings on vested equity-based compensation awards of $46.1 million and payments to repurchase our common stock of $32.0 million, partially offset by proceeds from the exercise of outstanding warrants of $7.4 million.

Capital Expenditures

Expenditures for the acquisition and development of oil and gas properties are the primary use of our capital resources. Our capital expenditures are summarized in the following table for the period presented:

(In thousands)

(1) Total capital expenditures reflected in the table above differs from the amounts shown in the statements of cash flows in our unaudited condensed consolidated financial statements because amounts reflected in the table include changes in accruals, while the amounts presented in the statements of cash flows are presented on a cash basis.

Dividends

On May 6, 2025, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on June 9, 2025 to shareholders of record as of May 21, 2025. See “Item 1. Financial Statements (Unaudited)—Note 14—Stockholders’ Equity” for additional information.

See “Part I. Item 1.—Business—Business Strategy” in our 2024 Annual Report for additional information regarding our strategy on future dividend payments. Future dividend payments will depend on the Company’s earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that the Board of Directors deems relevant.

Share Repurchase Program

During the three months ended March 31, 2025, we repurchased 1,994,496 shares of common stock at a weighted average price of $108.54 per common share for a total cost of $216.5 million under our $750.0 million share repurchase program authorized by our Board of Directors in October 2024. As of March 31, 2025, there was $376.1 million of capacity remaining under our $750.0 million share repurchase program.

During the three months ended March 31, 2024, we repurchased 193,269 shares of common stock under our previous share repurchase program, which was replaced by our current $750.0 million share repurchase program in October 2024.

Fair Value of Financial Instruments

See “Item 1. Financial Statements (Unaudited)—Note 5—Fair Value Measurements” for additional information on our derivative instruments and their related fair value measurements. See also “Item 3. Quantitative and Qualitative Disclosures about Market Risk” below.

Critical Accounting Policies and Estimates

There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2024 Annual Report.

We are exposed to a variety of market risks, including commodity price risk, interest rate risk, counterparty and customer risk and inflation risk. We address these risks through a program of risk management, including the use of derivative instruments.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in crude oil, NGL and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk derivative instruments were entered into for hedging purposes, rather than for speculative trading. The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2024 Annual Report, as well as with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

Commodity price exposure risk. We are exposed to market risk as the prices of crude oil, NGLs and natural gas fluctuate as a result of a variety of factors, including changes in supply and demand and the macroeconomic environment, all of which are typically beyond our control. The markets for crude oil, NGLs and natural gas have been volatile, especially over the last several years, and these prices will likely continue to be volatile in the future. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a portion of our future production. In addition, entering into derivative instruments could limit the benefit we would receive from increases in the prices for crude oil, NGLs and natural gas. We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on our unaudited condensed consolidated balance sheets. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement. See “Item 1. Financial Statements (Unaudited)—Note 5—Fair Value Measurements” and “Note 6—Derivative Instruments” for additional information regarding our derivative instruments.

The fair value of our unrealized crude oil derivative positions at March 31, 2025 was a net asset position of $21.6 million. A 10% increase in crude oil prices would reduce the fair value of this unrealized derivative asset position by approximately $63.5 million, while a 10% decrease in crude oil prices would increase the fair value of this unrealized derivative asset position by approximately $62.3 million. The fair value of our unrealized natural gas derivative positions at March 31, 2025 was a net liability position of $27.8 million. A 10% increase in natural gas prices would decrease the fair value of this unrealized derivative liability position by approximately $21.5 million, while a 10% decrease in natural gas prices would increase the fair value of this unrealized derivative liability position by approximately $21.6 million. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Market Conditions and Commodity Prices,” for further discussion on the commodity price environment. See “Item 1. Financial Statements (Unaudited)—Note 6—Derivative Instruments” for additional information regarding our derivative instruments.

In addition, in connection with the 2021 divestiture of certain oil and gas properties, we are entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $60 per barrel for such year. As of March 31, 2025, the fair value of this contingent consideration was $23.5 million. In each of January 2024 and 2025, we received $25.0 million related to the 2023 and 2024 earn-out payments, respectively. See “Item 1. Financial Statements (Unaudited)—Note 6—Derivative Instruments” for additional information.

Interest rate risk. At March 31, 2025, we had $750.0 million of senior unsecured notes at a fixed interest rate of 6.750% per annum. At March 31, 2025, we had $60.0 million borrowings and $30.8 million of outstanding letters of credit issued under the Credit Facility. Borrowings under the Credit Facility are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a Term SOFR Loan or an ABR Loan (each as defined in the Credit Facility). As of March 31, 2025, if interest rates were to increase by 100 basis points on the Credit Facility, the impact on the Company’s annual interest expense would not be material. See “Item 1. Financial Statements (Unaudited)—Note 10—Long-Term Debt” for additional information on the interest incurred on the Credit Facility.

We do not currently, but may in the future, utilize interest rate derivatives to mitigate interest rate exposure in an attempt to reduce interest rate expense related to debt issued under the Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the three months ended March 31, 2025, our credit losses on joint interest receivables were immaterial. We are also subject to credit risk due to the concentration of our crude oil, NGL and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial position and related financial results.

We monitor our exposure to counterparties on crude oil, NGL and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil, NGL and natural gas sales receivables owed to us. Historically, our credit losses on crude oil, NGL and natural gas sales receivables have been immaterial.

In addition, our crude oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions. All of the counterparties on our derivative instruments currently in place are lenders under the Credit Facility with investment grade ratings. We are likely to enter into any future derivative instruments with these or other lenders under the Credit Facility, which also carry investment grade ratings. This risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under individual contracts. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these netting provisions, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts.

Evaluation of disclosure controls and procedures

As required by Rule 13a-15(b) of the Exchange Act, management, under the supervision and with the participation of our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2025. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of March 31, 2025.

Changes in internal control over financial reporting

On May 31, 2024, we completed the Arrangement. As part of the ongoing integration, we are in the process of incorporating the controls and related procedures of Enerplus. Other than incorporating Enerplus’ controls, there were no changes in internal control over financial reporting that occurred during the quarter ended March 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report on Form 10-Q and in our other SEC filings could have a material impact on our business, financial position, results of operations or cash flows. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

For a discussion of our potential risks and uncertainties, see the information in “Part I. Item 1A. Risk Factors” in our 2024 Annual Report. There have been no material changes in our risk factors from those described in our 2024 Annual Report.