Chord Energy Corp (CHRD) FY 2024 MD&A

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. In addition, the following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. See “Cautionary Note Regarding Forward-Looking Statements” at the beginning of this report for an explanation of these types of statements.

For discussion related to changes in financial condition and results of operations for the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 26, 2024.

Overview

Chord Energy Corporation (together with its consolidated subsidiaries, the “Company” or “Chord”) is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, natural gas liquids (“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.

Recent Developments

Enerplus Arrangement

On February 21, 2024, we entered into an arrangement agreement (the “Arrangement Agreement ”) with Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”), and Spark Acquisition ULC, an unlimited liability company organized and existing under the laws of the Province of Alberta, Canada and a wholly-owned subsidiary of the Company, pursuant to which, among other things, we agreed to acquire Enerplus in a stock-and-cash transaction (such 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 Arrangement was completed on May 31, 2024.

Upon completion of the Arrangement on May 31, 2024, we issued 20,680,097 shares of common stock and paid $375.8 million in cash to Enerplus shareholders. Under the terms of the Arrangement Agreement, Enerplus shareholders received 0.10125 shares of Chord common stock, par value $0.01 per share, and $1.84 per share in cash in exchange for each share of Enerplus they owned at closing.

Divestitures

On October 25, 2024, we completed the sale of certain of our non-core properties located in the DJ Basin in Colorado that were classified as assets held for sale as of September 30, 2024, for total net cash proceeds (including preliminary purchase price adjustments) of $36.4 million, resulting in a $0.6 million gain on asset divestment.

In addition, during the year ended December 31, 2024, we completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds (subject to purchase price adjustments) of $25.0 million.

Market Conditions

Our revenue, profitability and ability to return cash to stockholders depend substantially on factors beyond our control, such as economic, geopolitical, 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. Commodity prices remained low throughout 2024 due to a combination of factors, including slowing demand growth as a result of decreased global economic activity levels and higher levels of production from domestic oil and gas producers in the United States and other non-OPEC+ countries.

In an effort to reduce inflationary pressures that emerged in the broader economy, central banks began to aggressively raise interest rates in 2022. After peaking in 2023, interest rates began to trend downward during 2024. Although U.S. inflation rates have shown signs of moderating, higher interest rates generally reduce economic activity levels, which have and could in the future again result in lower commodity prices due to reduced demand for crude oil, NGLs and natural gas (see “Item 7A. —Quantitative and Qualitative Disclosures about Market Risk—Inflation risks” for additional information). The uncertainties

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resulting from the potential economic outcomes of monetary policy decisions of central banks as well as tariff and trade policy decisions of the U.S. or other governments, coupled with the geopolitical risks associated with the continued military conflicts in the Red Sea Region and the wars between Russia and Ukraine and Hamas and Israel, make it difficult to predict future impacts to commodity prices.

While we are unable to predict future commodity prices, we do not believe that an impairment of our oil and gas properties or goodwill is reasonably likely to occur in the near future at current price levels; however, we would evaluate the recoverability of the carrying value of our oil and gas properties and goodwill as a result of a future material or extended decline in the price of crude oil, NGLs or natural gas or a material increase in the costs of labor, materials or services. See “Part I, Item 1A. Risk Factors—If crude oil, NGL and natural gas prices decline, or for an extended period of time remain at depressed levels, we may be required to take write-downs of the carrying values of our oil and gas properties and goodwill” for additional information.

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. Please see “Part I, Item 1. Business—Exploration and Production Operations—Marketing.”

Our average net realized crude oil prices and average price differentials are shown in the tables below for the periods presented:

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(1)Realized crude oil prices do not include the effect of derivative contract settlements.

(2)Price differential reflects the difference between our realized crude oil prices and NYMEX WTI.

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 December 31, 2024, substantially all of our gross operated crude oil production was connected to gathering systems. Our market optionality on these crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order to optimize price realizations. Expansions of both rail and pipeline facilities in the Williston Basin has reduced prior constraints on crude oil takeaway capacity and improved our price differentials received at the lease.

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Results of Operations

Comparability of Financial Statements

The results of operations presented below relate to the periods ended December 31, 2024 and 2023. The results reported for the year ended December 31, 2024 reflect the consolidated results of Chord, including combined operations with Enerplus beginning on May 31, 2024 and the 2023 acquisition of acreage in the Williston Basin, while the results reported for the year ended December 31, 2023 reflect the consolidated results of Chord, including the 2023 acquisition of acreage in the Williston Basin beginning on June 30, 2023, and excluding the impact from the business combination with Enerplus, unless otherwise noted.

For a discussion of the changes related to the financial condition and results of operations for the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 26, 2024.

Operational and Financial Highlights

•Production volumes averaged 232,737 Boepd (57% oil) for the year ended December 31, 2024.

•Lease operating expenses (“LOE”) were $9.68 per Boe for the year ended December 31, 2024.

•E&P and other capital expenditures were $1.2 billion for the year ended December 31, 2024.

•Net cash provided by operating activities was $2.1 billion and net income was $848.6 million for the year ended December 31, 2024.

•Estimated net proved reserves were 883.0 MMBoe as of December 31, 2024, with a Standardized Measure of $8.4 billion and PV-10 of $10.3 billion.

•TIL’d 142 gross (93 net) operated wells for the year ended December 31, 2024.

Shareholder Return Highlights

•Paid $10.15 per share base-plus-variable cash dividend for the year ended December 31, 2024.

•Repurchased $442.8 million of common stock during the year ended December 31, 2024 with $592.6 million remaining under the new $750 million share repurchase program authorized by the Board of Directors in October 2024.

•On February 25, 2025, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 26, 2025 to stockholders of record as of March 11, 2025.

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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 year ended December 31, 2024 increased 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:

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(1)For the year ended December 31, 2024, natural gas production volume from the Marcellus Shale was 24,727 MMcf. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $1.78 per Mcf.

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

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Crude oil revenues. Our crude oil revenues increased $735.4 million to $3.6 billion for the year ended December 31, 2024 as compared to the year ended December 31, 2023. Our crude oil revenues increased $837.3 million due to higher total crude oil production volumes sold, primarily due to our expanded operations as a result of the Arrangement. Excluding the increase from the Arrangement, crude oil revenues decreased $124.9 million due to lower crude oil realized prices, partially offset by an increase of $23.0 million due to higher crude oil production volumes sold year-over-year. Average crude oil sales prices, without derivative settlements, decreased by $4.18 per barrel year-over-year to an average of $73.67 per barrel for the year ended December 31, 2024 due to decreases in NYMEX WTI and widening in-basin differentials.

NGL revenues. Our NGL revenues decreased $15.7 million to $162.1 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The decrease was primarily due to lower NGL realized prices year-over-year resulting in a $48.3 million decrease, partially offset by an increase of $32.6 million due to higher NGL production volumes primarily as a result of the Arrangement. Average NGL sales prices, without derivative settlements, decreased by $3.70 per barrel period over period to an average of $9.92 per barrel for the year ended December 31, 2024 primarily due to wider differentials on incremental production volumes primarily as a result of the Arrangement.

Natural gas revenues. Our natural gas revenues decreased $16.0 million to $102.8 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The decrease was primarily due to lower natural gas realized prices year-over-year resulting in a $49.0 million decrease, offset by an increase in total natural gas production volumes sold of $33.0 million, primarily due to our expanded operations as a result of the Arrangement. Average natural gas sales prices, without derivative settlements decreased by $0.59 per Mcf period over period to $0.84 per Mcf for the year ended December 31, 2024 primarily due to a decrease in natural gas index prices, coupled with the impact of incurring fixed fees and related fee escalations for the majority of our natural gas marketing contracts beginning in the second quarter of 2023.

Purchased oil and gas sales. Purchased oil and gas sales increased $650.7 million to $1.4 billion for the year ended December 31, 2024 as compared to the year ended December 31, 2023. This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold, partially offset by lower crude oil and gas prices year-over-year.

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Expenses and other income (expense)

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

Lease operating expenses. LOE increased $165.5 million to $824.4 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase was primarily driven by our expanded operations after the Arrangement contributing $181.3 million of additional LOE period over period. Excluding the increase from the Arrangement, LOE decreased $31.7 million due to lower workover costs, offset by an increase of $17.0 million due to higher variable costs period over period. LOE per Boe decreased $0.73 per Boe period over period to $9.68 per Boe for the year ended December 31, 2024 primarily due to higher production volumes and lower workover costs.

Gathering, processing and transportation expenses. Gathering, processing and transportation (“GPT”) expenses increased $87.3 million to $267.6 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase was primarily due to our expanded operations after the Arrangement contributing $79.5 million of additional GPT period over period and lower fair value gains of $26.4 million attributable to the completion of certain derivative transportation contracts at the end of 2023 and during the first half of 2024. These increases were partially offset by a decrease of $19.5 million due to lower transportation rates, primarily due to several contracts expiring during the year ended December 31, 2024. These net increases resulted in an increase in GPT expenses of $0.29 per Boe period over period to $3.14 per Boe for the year ended December 31, 2024.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $651.0 million to $1.4 billion for the year ended December 31, 2024 as compared to the year ended December 31, 2023 primarily due to an increase in the volume of crude oil purchased and subsequently sold, partially offset by lower crude oil and gas prices year-over-year.

Production taxes. Production taxes increased $73.4 million to $333.4 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase was primarily driven by our expanded operations after the Arrangement contributing $77.4 million of additional production tax, or $3.59 per Boe, for the year ended December 31, 2024.

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The production tax rate as a percentage of crude oil, NGL and natural gas sales was 8.7% for the year ended December 31, 2024 as compared to 8.3% for the year ended December 31, 2023. This rate increase year-over-year was primarily due to an increase in new wells with a higher associated oil production tax rate, coupled with decreased natural gas and NGL revenues as a result of lower realized prices.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense increased $509.2 million to $1.1 billion for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase was primarily due to our expanded operations after the Arrangement contributing $281.1 million of additional DD&A expense period over period, an increase of $225.0 million due to a higher depletion rate period over period and an increase of $4.5 million due to higher production volumes year-over-year. The depletion rate increased $3.50 per Boe year-over-year to $12.70 per Boe for the year ended December 31, 2024 primarily due to the purchase consideration allocated to the fair value of oil and gas properties acquired in the Arrangement.

General and administrative expenses. Our general and administrative (“G&A”) expenses increased $79.3 million to $205.6 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023, primarily due to increased merger-related costs of $79.6 million incurred in connection with the Arrangement and an increase in costs associated with a larger organization after the Arrangement of $26.7 million. These increases were partially offset by a decrease in stock-based compensation costs of $23.1 million due to the vesting of certain equity-based compensation awards year-over-year.

Exploration and impairment expenses. Exploration and impairment expenses decreased $18.3 million to $17.0 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. During the year ended December 31, 2024, we recorded an impairment expense of $9.8 million, which primarily included a $7.4 million lower of cost or net realizable value write-down of oil-in-tank inventory and a $2.5 million impairment expense related to the Denver office lease and related fixed assets acquired in connection with the Arrangement. During the year ended December 31, 2023, exploration and impairment expenses totaled $35.3 million, which was primarily due to impairment expenses of $29.0 million, including $17.5 million associated with the write-down of our Denver office lease acquired in 2022, $5.8 million associated with a lower of cost or net realizable value write-down of oil-in-tank inventory and $5.6 million to adjust the carrying value of certain non-core properties held for sale to their estimated fair value less costs to sell.

Gain (loss) on sale of assets, net. During the year ended December 31, 2024, we recorded a net gain on sale of assets of $17.1 million, primarily related to certain non-operated wellbore divestitures in the Williston Basin. During the year ended December 31, 2023, we recorded a net loss on sale of assets of $2.8 million, primarily related to divestitures of certain of our non-core properties located outside of the Williston Basin.

Derivative instruments. During the year ended December 31, 2024, we recorded a $12.6 million net gain on derivative instruments, which was primarily comprised of a net gain of $7.5 million associated with our commodity derivative contracts and a net gain of $5.1 million associated with a contract that includes contingent consideration. The net gain of $7.5 million on commodity derivative contracts included an unrealized gain of $6.6 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices, coupled with a realized gain of $0.9 million on settled commodity derivative contracts. During the year ended December 31, 2023, we recorded a $63.2 million net gain on derivative instruments, which was primarily comprised of a net gain of $56.4 million associated with our commodity derivative contracts and a net gain of $6.8 million associated with a contract that includes contingent consideration. The net gain of $56.4 million on commodity derivative contracts included an unrealized gain of $313.1 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices, partially offset by a realized loss of $256.7 million on settled commodity derivative contracts.

Investment in unconsolidated affiliate. We recorded a $51.3 million gain related to our investment in Energy Transfer for the year ended December 31, 2024, which included an unrealized gain of $42.0 million as a result of an increase in the fair value of the investment during the year and a realized gain of $9.3 million for cash distributions received. During the year ended December 31, 2023, we recorded a $21.3 million gain related to our investment in Energy Transfer, primarily related to a realized gain of $10.8 million for cash distributions received and an unrealized gain of $8.4 million as a result of an increase in the fair value of the investment during the year.

Interest expense, net of capitalized interest. Interest expense increased $27.9 million to $56.5 million for the year ended December 31, 2024, compared to the year ended December 31, 2023. The increase is primarily due to higher borrowings outstanding on our Credit Facility (defined below) during the year. For the year ended December 31, 2024, the weighted average borrowings outstanding under the Credit Facility were $362.2 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.3%. For the year ended December 31, 2023, the weighted average borrowings outstanding under the Credit Facility were $4.9 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.1%. Interest capitalized during the year ended December 31, 2024 and December 31, 2023 was $4.9 million and $4.1 million, respectively.

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Other income, net. For the year ended December 31, 2024, we recognized $5.0 million of other income, net as compared to $10.0 million for the year ended December 31, 2023. The $5.0 million decrease was primarily due to a decrease in interest income year-over-year associated with lower balances in our money market accounts.

Income tax expense. Our effective tax rate for the year ended December 31, 2024 was materially unchanged from our effective tax rate for the year ended December 31, 2023. Our income tax expense was recorded at 23.7% and 23.5% of pre-tax income for the year ended December 31, 2024 and December 31, 2023, respectively.

Liquidity and Capital Resources

As of December 31, 2024, we had $1.1 billion of liquidity available, including $37.0 million in cash and cash equivalents and $1.0 billion of aggregate unused borrowing base capacity available under our Credit Facility (defined below). During the first quarter of 2025, we expect to have approximately $1.6 billion of liquidity available after taking into account the increase in the aggregate amount of elected commitments to $2.0 billion. Our primary sources of liquidity were from cash on hand, cash flows from operations and available borrowing base capacity under our Credit Facility. Our primary liquidity requirements were capital expenditures for the development of oil and gas properties, dividend payments, debt repayments under our Credit Facility, share repurchases, cash consideration and transaction costs associated with the Arrangement, and working capital requirements.

Capital availability is 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 increase or remain elevated for an extended period of time creates 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.

We also incurred certain costs for advisory, legal and other third-party fees in connection with the Arrangement, which were recorded to G&A expenses on the Consolidated Statements of Operations. During the year ended December 31, 2024, we incurred merger-related costs of $89.3 million, primarily related to legal and advisory services and severance costs.

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. 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.

Commodity derivative contracts. As of December 31, 2024, our commodity derivative contracts cover 9,301 MBbls of our crude oil production and 8,902 MMBtu of our natural gas production for 2025, as well as 4,000 MBbls of our crude oil production and 10,475 MMBtu of our natural gas production for 2026. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and “Part I, Item 1A. Risk Factors” for additional information.

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Subsequent to December 31, 2024, we entered into new commodity derivative contracts to manage risks related to changes in commodity prices. The following table summarizes these commodity derivative contracts:

Material cash requirements

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 a mix of base and variable 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.

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 $579.2 million as of December 31, 2024. We believe that for the substantial majority of these agreements, our future production will be adequate to meet our delivery commitments or that we can purchase sufficient volumes of crude oil, NGLs and natural gas from third parties to satisfy our minimum volume commitments.

Long-term debt

Our long-term debt consists of a senior secured revolving line of credit that is generally used to support our working capital requirements and $400.0 million of 6.375% senior unsecured notes as of December 31, 2024.

Senior secured revolving line of credit. As of December 31, 2024, we had a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $3.0 billion and an aggregate amount of elected commitments of $1.5 billion that is due July 1, 2027. We had $445.0 million in net borrowings outstanding, primarily made in connection with the Arrangement, and $30.8 million of outstanding letters of credit, resulting in an unused borrowing base capacity of $1.0 billion as of December 31, 2024. Additionally, we are permitted to incur term loans in addition to the revolving loans provided under the Credit Facility. On November 4, 2024, we completed the semi-annual borrowing base redetermination, which affirmed the borrowing base of $3.0 billion and the aggregate amount of elected commitments of $1.5 billion and entered into the Sixth Amendment to the Amended and Restated Credit Agreement. In February 2025, we completed our semi-annual borrowing base redetermination, setting the borrowing base at $2.75 billion and increasing the aggregate amount of elected commitments to $2.0 billion.

For the year ended December 31, 2024, the weighted average interest rate incurred on borrowings under the Credit Facility was 7.27%, compared to 7.13% for the year ended December 31, 2023.

We were in compliance with the financial covenants in the Credit Facility at December 31, 2024. See “Item 8. Financial Statements and Supplementary Data—Note 13—Long-Term Debt” for additional information.

Senior unsecured notes. As of December 31, 2024, we had $400.0 million of 6.375% senior unsecured notes (the “Senior Notes”) that mature on June 1, 2026. Interest on the Senior Notes is payable semi-annually on June 1 and December 1 of each year. See “Item 8. Financial Statements and Supplementary Data—Note 13—Long-Term Debt” for additional information.

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Cash flows

The following table summarizes our changes in cash flows for the years presented:

For a discussion on cash flows for the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2023 Annual Report on Form 10-K filed with the SEC on February 26, 2024 under the subheading “Cash flows.”

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 $2.1 billion for the year ended December 31, 2024. The increase in net cash provided by operating activities of $277.4 million from the year ended December 31, 2023 was primarily due to an increase in oil revenues, offset by increases in LOE, merger-related costs, GPT costs and production taxes, as well as lower NGL and natural gas revenues and changes in our working capital. See “Results of Operations” above for additional information.

Working capital. Our working capital is primarily impacted due to the factors discussed above, coupled with the timing of cash receipts and disbursements. During the years ended December 31, 2024 and 2023, changes in working capital (as reflected in the Consolidated Statements of Cash Flows) decreased net cash flows from operating activities by $34.1 million and $91.9 million, respectively. 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 $1.0 billion as of December 31, 2024, and excludes current hedge assets, which were $35.9 million as of December 31, 2024. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which were $1.2 million as of December 31, 2024.

Cash flows used in investing activities

For the year ended December 31, 2024, net cash used in investing activities of $1.8 billion was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $1.2 billion and net cash paid for acquisitions of $655.0 million. The net cash paid for acquisitions primarily related to the Arrangement and included $395.0 million paid to settle Enerplus’ revolving bank credit facility balance, $375.8 million paid to Enerplus shareholders and $102.4 million paid to settle Enerplus’ outstanding equity awards, partially offset by cash acquired in the Arrangement of $239.9 million. Net cash used in investing activities during the year ended December 31, 2024 also included proceeds from divestitures of $60.7 million and the receipt of a 2023 contingent consideration earn-out payment of $25.0 million in connection with a 2021 divestiture of certain oil and gas properties. Net cash used in investing activities for the year ended December 31, 2023 of $1.4 billion was primarily attributable to $905.7 million of capital expenditures, $361.6 million paid for the 2023 acquisition of acreage in the Williston Basin and $268.9 million associated with the settlement of derivative contracts, partially offset by $54.4 million of proceeds from divestitures and $40.6 million of proceeds from the sale of Energy Transfer units.

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Cash flows used in financing activities

For the year ended December 31, 2024, net cash used in financing activities of $624.5 million was primarily attributable to dividends paid to stockholders of $529.9 million, payments made to repurchase common stock of $444.2 million, payments for income tax withholdings on vested equity-based compensation awards of $63.4 million and repayments on the Enerplus Senior Notes of $63.0 million. These uses of cash were partially offset by borrowings under the Credit Facility of $3.5 billion, offset by repayments of $3.1 billion, resulting in net borrowings under the Credit Facility of $445.0 million, primarily made in connection with the Arrangement, and proceeds from the exercise of outstanding warrants of $35.8 million. Net cash used in financing activities for the year ended December 31, 2023 of $664.7 million was primarily attributable to dividends paid to shareholders of $500.3 million, payments to repurchase our common stock of $239.3 million and payments for income tax withholdings on vested equity-based compensation awards of $14.6 million, partially offset by proceeds from the exercise of outstanding warrants of $91.3 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:

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(1)For the year ended December 31, 2024, capital expenditures related to the Marcellus Shale were $8.9 million.

(2)Other capital expenditures include items such as infrastructure capital, administrative capital and capitalized interest. Capitalized interest totaled $4.9 million, $4.1 million and $4.6 million for the years ended December 31, 2024, 2023 and 2022, respectively.

(3)Total capital expenditures for the year ended December 31, 2024 include approximately $25.2 million related to certain non-operated divested assets that are expected to be reimbursed.

(4)Excludes amounts attributable to the Arrangement, including cash consideration of $375.8 million, for the year ended December 31, 2024, and to the merger with Whiting Petroleum Corporation on July 1, 2022 (the “Merger”), including cash consideration of $245.4 million, for the year ended December 31, 2022.

(5)Represents capital expenditures attributable to our midstream assets that were classified as discontinued operations related to the merger of Oasis Midstream Partners LP (“OMP”) and OMP GP, OMP’s general partner, with and into a subsidiary of Crestwood Equity Partners LP (the “OMP Merger”).

(6)Total capital expenditures (including acquisitions) reflected in the table above differ from the amounts for capital expenditures and acquisitions shown in the statements of cash flows in our consolidated financial statements because amounts reflected in the table above include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis.

For the year ended December 31, 2024, our total E&P and other capital expenditures increased $310.0 million to $1.2 billion primarily due to our expanded operations as a result of the Arrangement. We completed 93 net operated wells in 2024, compared to 69 net operated wells in 2023. Non-operated drilling and completion activities accounted for $135.9 million of our total E&P and other capital expenditures for the year ended December 31, 2024.

Additionally, on June 30, 2023, we completed the Williston Basin Acquisition for total cash consideration of $361.6 million. Refer to “Item 8. Financial Statements and Supplementary Data—Note 9—Acquisitions” for additional information.

Our planned 2025 E&P capital expenditures are expected to be approximately $1.3 billion to $1.5 billion. We expect to run four to five operated rigs during the majority of 2025 and plan to TIL approximately 130 to 150 gross operated wells with an average working interest of approximately 78%.

The ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. Our capital plan may further be adjusted as business conditions warrant.

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The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If crude oil prices decline substantially or for an extended period of time, we could defer a significant portion of our planned capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control. Furthermore, we actively review acquisition opportunities on an ongoing basis. If we acquire additional acreage, our capital expenditures may be higher than planned. However, our ability to make significant acquisitions for cash may require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

Dividends

During the year ended December 31, 2024, we declared base-plus-variable cash dividends of $10.15 per share of common stock, or $507.6 million in aggregate. On February 25, 2025, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 26, 2025 to shareholders of record as of March 11, 2025. At December 31, 2024, we had dividends payable of $16.7 million related to dividend equivalent rights accrued on equity-based compensation awards, including $16.1 million that was recorded under accrued liabilities and $0.6 million that was recorded under other liabilities on the Consolidated Balance Sheet.

During the year ended December 31, 2023, we declared base-plus-variable cash dividends of $11.88 per share of common stock, or $508.6 million in aggregate.

Future dividend payments will depend on our 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

In October 2024, our Board of Directors authorized a new share repurchase program covering up to $750 million of our common stock, which replaced the existing $750 million share repurchase program that was authorized in October 2023. We repurchased, and may repurchase in the future, shares pursuant to a Rule 10b5-1 trading plan under the Securities Exchange Act of 1934, as amended, which permits us to repurchase shares at times that may otherwise be prohibited under its insider trading policy. The share repurchase program does not require us to make purchases within a particular time frame.

During the year ended December 31, 2024, we repurchased 3,114,007 shares of common stock at a weighted average price of $142.20 per common share for a total cost of $442.8 million under both the October 2024 and October 2023 share repurchase programs. As of December 31, 2024, there was $592.6 million of capacity remaining under the existing $750 million program.

During the year ended December 31, 2023, the Company repurchased 1,533,791 shares of common stock at a weighted average price of $157.08 per common share for a total cost of $240.9 million, excluding accrued excise taxes of $0.4 million under both the October 2023 and August 2022 share repurchase programs.

Critical accounting policies and estimates

Our consolidated financial statements have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. See “Item 8. Financial Statements and Supplementary Data—Note 2—Summary of Significant Accounting Policies” for the significant accounting policies and estimates made by management as well as the expected impact of recent accounting pronouncements on our consolidated financial statements. The following are the accounting policies, estimates and judgments used in preparation of our consolidated financial statements which we consider most critical:

Method of accounting for oil and gas properties

GAAP provides two alternative methods to account for oil and gas properties known as the successful efforts method and the full cost method. These two accounting methods differ in a number of ways, including the treatment of the costs of exploratory dry holes and geological and geophysical costs which are charged against earnings during the period incurred under the successful efforts method and capitalized within a pool of assets under the full cost method. We account for oil and gas properties under the successful efforts method of accounting. See “Item 8. Financial Statements and Supplementary Data—Note 2—Summary of Significant Accounting Policies—Property, Plant and Equipment” for additional information.

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Estimated quantities of reserves

Our independent reserve engineers prepare our estimates of crude oil, NGL and natural gas reserves. While the SEC rules allow us to disclose proved, probable and possible reserves, we have elected to disclose only proved reserves in this Annual Report on Form 10-K. Estimates of reserve quantities and the related estimates of future net cash flows are used as inputs into the calculation of the fair value of oil and gas properties in a business combination, the assessment of whether sufficient future taxable income will be generated to realize deferred tax assets, the calculation of depletion expense, the evaluation of proved oil and gas properties for impairment and the Standardized Measure.

Estimates of reserves are prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the Estimating and Auditing Standards. Crude oil, NGL and natural gas reserves engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, changes to our anticipated five-year development plan, changes to commodity prices, cost changes, technological advances, new geological or geophysical data or other economic factors. Accordingly, reserve estimates are generally different from the quantities of crude oil, NGL and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions, and if such revisions are significant, they could significantly affect future depletion expense, the carrying amount of our proved oil and gas properties and the Standardized Measure. See “Item 1. Business—Exploration and Production Operations—Estimated net proved reserves” for additional information on the revisions to our estimated net proved reserves.

Our estimated net proved reserves and PV-10 were determined using the SEC Price. The SEC Price was $75.48 per Bbl for crude oil and $2.13 per MMBtu for natural gas for the year ended December 31, 2024. We cannot reasonably predict future commodity prices; however, assuming all other factors are held constant, a 10% decrease in the SEC Price for crude oil and natural gas would decrease our estimated net proved reserves by 26.7 MMBoe and decrease the PV-10 by $2.0 billion, and a 10% increase in the SEC Price for crude oil and natural gas would increase our estimated net proved reserves by 21.4 MMBoe and increase the PV-10 by $2.0 billion.

Business combinations

We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair value of the oil and gas properties was calculated by a third party valuation expert using an income approach based on the net discounted future cash flows that utilized inputs requiring significant judgment and assumptions, including future production volumes based upon estimates of reserves prepared by our reserve engineers, future commodity prices (adjusted for basis differentials), future operating and development costs and a market-based weighted average cost of capital discount rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of crude oil, NGL and natural gas properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Different techniques may be used to determine fair values, including market prices (where available), comparisons to transactions for similar assets and liabilities and present values of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.

Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill and is subject to ongoing impairment evaluation. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

The purchase price allocation recorded in a business combination may change during the measurement period, which is a period not to exceed one year from the date of acquisition, as additional information about conditions existing at the acquisition date becomes available.

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See Note 9—Acquisitions of the Notes to Consolidated Financial Statements in this Annual Report for additional details regarding our business combinations, including further discussion of the estimated fair value of assets acquired and liabilities assumed in the Merger and the Arrangement as well as any significant changes in these estimates from the date of acquisition.

Impairment of proved oil and gas properties

We review proved oil and gas properties for impairment whenever events and circumstances indicate that their carrying value may not be recoverable. We estimate the expected undiscounted future cash flows by field and compare such undiscounted amounts to the carrying amount to determine if the asset is recoverable. If the carrying amount is not recoverable, we will recognize an impairment by adjusting the carrying amount of the oil and gas properties to fair value. We estimate the fair value of proved oil and gas properties using an income approach that converts future cash flows to a single discounted amount.

The factors used to determine the undiscounted future cash flows and fair value require significant judgment and assumptions, including future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials) and estimates of future operating and development costs. These factors are generally consistent with those used in the planning and budgeting processes. Future production is based upon a combination of inputs and assumptions, including the timing and pace of our development plans, as well as estimates of reserve quantities. When discounting future cash flows to estimate fair value, cash flows realized later in the projection period are less valuable compared to those realized earlier in the projection period due to the time value of money. Future commodity prices are estimated by using a combination of quoted forward market prices adjusted for geographical location and quality differentials based upon assumptions that are developed by reviewing historical realized prices, market supply and demand factors and other relevant factors. Future operating and development costs are generally estimated using inputs including authorizations for expenditures, review of historical data and forecasts developed during the budgeting and planning processes. In addition, estimates of future operating and development costs may be impacted by market supply and demand factors, including inflation expectations and the availability of materials, labor and services. To calculate fair value, future cash flows are discounted using a discount rate that is based on rates utilized by market participants and is commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

A substantial or extended decline in commodity prices could result in future impairment charges which would negatively impact our future operating results. However, because of the uncertainty inherent in the factors described above, we cannot predict when or if future impairment charges for proved oil and gas properties will be recorded.

Impairment of unproved oil and gas properties

The assessment of unproved properties to determine any possible impairment requires significant judgment. We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage.

We recognize impairment expense for unproved properties at the time when the lease term has expired or sooner based on management’s periodic assessments. We consider the following factors in our assessment of the impairment of unproved properties:

•the remaining amount of unexpired term under our leases;

•our ability to actively manage and prioritize our capital expenditures to drill leases;

•our ability to make rental or extension payments to extend existing leases that may be closer to expiration;

•our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;

•our ability to convey partial leasehold ownership in certain leases to other companies in exchange for their drilling of those leases;

•our ability to sell lease positions to other companies; and

•our evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations by us or by other operators in areas adjacent to or near our unproved properties.

Impairment of goodwill

Goodwill represents the excess of consideration paid over the fair value of identified tangible and intangible assets. Goodwill and intangible assets with indefinite lives are not amortized, but are evaluated for impairment annually as of October 1 or more frequently if events or changes in circumstances indicate that the carrying amount might be impaired.

For the purpose of the goodwill impairment test, we first assesses qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers of fair value of the reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant

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events and circumstances since the last fair value assessment. This evaluation includes, but is not limited to, assessment of macroeconomic trends, capital accessibility, operating income trends and industry conditions, as well as our share performance. If an initial qualitative assessment identifies that it is more likely than not that the carrying value of a reporting unit exceeds its estimated fair value, a quantitative evaluation is performed. The quantitative goodwill impairment assessment involves determining the fair value of the reporting unit and comparing it to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, including goodwill, then an impairment charge would be recorded to write down goodwill to its implied fair value. A reporting unit, for the purpose of the impairment test, is at or below the operating segment level, and constitutes a business for which discrete financial information is available and regularly reviewed by segment management. Our single reportable business segment which is the exploration and production of crude oil, NGLs and natural gas, is the reporting unit that carries our goodwill balance as of December 31, 2024. The fair value of the reporting unit is estimated using an income approach. Significant inputs used are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of reserves prepared by our reserve engineers, future operating and development costs, future commodity prices (adjusted for basis differentials) and a market-based weighted average cost of capital rate.

Income taxes

Our provision for taxes includes both federal and state income taxes. We record our income taxes in accordance with ASC 740, Income Taxes, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.

We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.

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