Chord Energy Corp: Form 10-Q for the period ended Jun 30, 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, war between Hamas and Israel and conflict between Iran 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;
• 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 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 and provisions under the newly enacted One Big Beautiful Bill Act;
• 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, including sustained decreases during 2025, and may continue to fluctuate widely or continue to decrease 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 and our access to capital.

At June 30, 2025, we assessed goodwill for impairment and recognized a non-cash impairment charge of $539.3 million. See “Item 1. Financial Statements (Unaudited)—Note 5—Fair Value Measurements” for additional information.

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.

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 June 30, 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 periods ended June 30, 2025, March 31, 2025 and June 30, 2024. The results reported for the three and six months ended June 30, 2025 and the three months ended March 31, 2025 reflect the consolidated results of Chord, including combined operations with Enerplus, while the results reported for the six months ended June 30, 2024 reflect the consolidated results of Chord, including the impact from the business combination with Enerplus beginning on May 31, 2024, unless otherwise noted.

Operational and Financial Highlights

• Production volumes averaged 281,858 Boepd (56% oil), including crude oil volumes of 156,734 Bopd in the second quarter of 2025.
• E&P and other capital expenditures (excluding capitalized interest) were $355.6 million in the second quarter of 2025.
• Lease operating expenses (“LOE”) were $10.02 per Boe in the second quarter of 2025.
• Net cash provided by operating activities was $419.8 million and net loss was $389.9 million in the second quarter of 2025.

Shareholder Return Highlights

• Paid $1.30 per share base cash dividend on June 9, 2025.
• Repurchased $55.0 million of common stock in the second quarter of 2025.
• In August 2025, the Board of Directors authorized a new $1.0 billion share repurchase program.
• Declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on September 8, 2025 to shareholders of record as of August 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 crude oil, NGL and natural gas revenues for the six months ended June 30, 2025 increased compared to the six months ended June 30, 2024 due to the Arrangement, which closed on May 31, 2024 and 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 June 30, 2025 and March 31, 2025, natural gas production volume from the Marcellus Shale was 11,821 MMcf and 11,563 MMcf, respectively. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $2.49 per Mcf and $4.71 per Mcf for the three months ended June 30, 2025 and March 31, 2025, respectively. For the six months ended June 30, 2025 and 2024, natural gas production volume from the Marcellus Shale was 23,384 MMcf and 3,764 MMcf, respectively. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $3.59 per Mcf and $1.66 per Mcf for the six months ended June 30, 2025 and 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 June 30, 2025 as compared to three months ended March 31, 2025

Crude oil revenues. Our crude oil revenues decreased $77.2 million to $878.9 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The decrease was primarily due to a decrease of $103.6 million due to lower crude oil realized prices quarter over quarter, partially offset by an increase of $26.4 million due to higher crude oil production volumes sold quarter over quarter. Average crude oil sales prices, without derivative settlements, decreased by $7.49 per barrel quarter over quarter to an average of $61.62 per barrel for the three months ended June 30, 2025 primarily due to a decrease in NYMEX WTI.

NGL revenues. Our NGL revenues decreased $32.8 million to $28.6 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The decrease was primarily due to lower realized NGL prices quarter over quarter resulting in a $36.3 million decrease, partially offset by an increase of $3.5 million due to higher NGL production volumes sold quarter over quarter. Average NGL sales prices, without derivative settlements, decreased by $8.38 per barrel quarter over quarter to an average of $5.80 per barrel for the three months ended June 30, 2025 primarily due to decreases in the corresponding NGL product index prices.

Natural gas revenues. Our natural gas revenues decreased $43.2 million to $42.8 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The decrease was primarily due to lower natural gas realized prices quarter over quarter resulting in a $44.8 million decrease, partially offset by an increase of $1.6 million due to higher natural gas production volumes sold quarter over quarter. Average natural gas sales prices, without derivative settlements, decreased by $1.20 per Mcf quarter over quarter to $1.10 per Mcf for the three months ended June 30, 2025 primarily due to the seasonality of warmer weather resulting in lower index prices quarter over quarter.

Purchased oil and gas sales. Purchased oil and gas sales increased $118.7 million to $230.3 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold quarter over quarter, partially offset by decreased crude oil prices over the same period.

Six months ended June 30, 2025 as compared to six months ended June 30, 2024

Crude oil revenues. Our crude oil revenues increased $308.1 million to $1.8 billion for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. Our crude oil revenues increased $491.4 million due to our expanded operations as a result of the Arrangement. Excluding the increase from the Arrangement, crude oil revenues decreased $235.0 million due to lower crude oil realized prices, partially offset by an increase of $51.7 million due to higher crude oil production volumes sold. Average crude oil sales prices, without derivative settlements, decreased by $11.95 per barrel period over period to an average of $65.31 per barrel for the six months ended June 30, 2025 due to decreases in NYMEX WTI and widening in-basin differentials period over period.

NGL revenues. Our NGL revenues increased $5.9 million to $89.9 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. Our NGL revenues increased $3.8 million due to our expanded operations as a result of the Arrangement. Excluding the increase from the Arrangement, NGL revenues increased $6.1 million due to higher NGL production volumes sold, partially offset by a decrease of $4.0 million due to lower realized NGL prices period over period. Average NGL sales prices, without derivative settlements, decreased by $2.61 per barrel period over period to an average of $9.72 per barrel for the six months ended June 30, 2025 primarily due to decreases in the corresponding NGL product index prices and widening differentials period over period.

Natural gas revenues. Our natural gas revenues increased $88.9 million to $128.7 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. Our natural gas revenues increased $69.0 million due to our expanded operations as a result of the Arrangement. Excluding the increase from the Arrangement, natural gas revenues increased $20.2 million primarily due to higher average natural gas realized prices. Average natural gas sales prices, without derivative settlements, increased by $0.82 per Mcf period over period to $1.69 per Mcf for the six months ended June 30, 2025 primarily due to increases in index prices period over period.

Purchased oil and gas sales. Purchased oil and gas sales decreased $353.2 million to $341.9 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. This decrease was primarily due to a decrease in the volume of crude oil purchased and subsequently sold period over period, coupled with decreased crude oil prices over the same period.

Expenses and other income (expense)

Certain operating expenses, including LOE, GPT expenses and DD&A, increased for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024 due to the Arrangement, which closed on May 31, 2024 and expanded our operations primarily in the Williston Basin.

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 June 30, 2025 as compared to three months ended March 31, 2025

Lease operating expenses. LOE increased $23.9 million to $257.0 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The increase was primarily due to increased workover activity of $16.2 million and higher variable costs of $7.0 million quarter over quarter. LOE per Boe increased $0.46 per Boe quarter over quarter to $10.02 per Boe for the three months ended June 30, 2025 primarily due to the increase in workover activity.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $120.4 million to $231.7 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025 primarily due to an increase in the volume of crude oil purchased and subsequently sold quarter over quarter, partially offset by decreased crude oil prices over the same period.

Production taxes. Production taxes decreased $5.7 million to $69.0 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The decrease was primarily due to the impact of lower crude oil revenues quarter over quarter. The production tax rate as a percentage of crude oil, NGL and natural gas revenues of 7.3% for the three months ended June 30, 2025 increased from 6.8% for the three months ended March 31, 2025 primarily as a result of higher extraction tax exemptions for certain wells within the three months ended March 31, 2025 coupled with natural gas comprising a smaller percentage of total sales relative to the prior quarter.

Depreciation, depletion and amortization. DD&A expense increased $27.2 million to $377.0 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The increase was primarily driven by higher production volumes of $19.9 million quarter over quarter coupled with increased accretion expense of $7.3 million related to plugging and abandonment charges.

General and administrative expenses. G&A expenses decreased $5.8 million to $32.5 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The decrease was primarily attributable to lower employee compensation expenses of $6.1 million and a decrease in merger-related costs of $2.2 million, partially offset by various cost increases related to other G&A expenses of $4.2 million. Merger-related costs for the three months ended June 30, 2025 and March 31, 2025 were $2.9 million and $5.1 million, respectively, and were primarily comprised of severance and advisory expenses related to the Arrangement in both periods.

Impairment and exploration. As a result of a decrease in the price of our common stock during the three months ended June 30, 2025, which was impacted by a decline in crude oil and natural gas prices over that same period, we recorded an impairment charge on our goodwill of $539.3 million for the three months ended June 30, 2025. There were no impairment charges during the three months ended March 31, 2025.

Gain (loss) on sale of assets, net. During the three months ended June 30, 2025 and March 31, 2025, we recorded a net loss of $0.5 million and a net gain of $5.5 million, respectively, on sales of assets primarily related to the divestiture of certain non-core oil and gas properties within each quarter.

Derivative instruments. We recorded a $82.2 million net gain on derivative instruments for the three months ended June 30, 2025, which was comprised of a net gain of $82.0 million associated with our commodity derivative contracts and an unrealized gain of $0.2 million associated with a contract that includes contingent consideration. The net gain of $82.0 million on commodity derivative contracts included an unrealized gain of $67.9 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 and a realized gain of $14.1 million on settled commodity derivative contracts. 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, partially offset by an unrealized gain of $0.7 million associated with a contract that included 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 coupled with a realized loss of $0.3 million on settled commodity derivative contracts.

Investment in unconsolidated affiliate. We recorded a $1.0 million net loss related to our investment in Energy Transfer LP (“Energy Transfer”) for the three months ended June 30, 2025, which included an unrealized loss of $3.3 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 March 31, 2025, we recorded a $4.9 million net loss related to our investment in Energy Transfer due to 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.

Interest expense, net of capitalized interest. Interest expense increased $3.0 million to $18.8 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The increase was primarily due to the issuance of $750.0 million of 6.750% senior unsecured notes due March 15, 2033 (the “2033 Senior Notes”) in March 2025, partially offset with lower borrowings on the Credit Facility (defined below) during the quarter coupled with 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”) in March 2025. For the three months ended June 30, 2025, the weighted average borrowings outstanding under the Credit Facility were $238.0 million, and the weighted average interest rate incurred on the outstanding borrowings was 6.56%. 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%. Interest capitalized during the three months ended June 30, 2025 and March 31, 2025 was $1.1 million for each period.

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 (16.2)% and 25.0% of pre-tax income (loss) for the three months ended June 30, 2025 and March 31, 2025, respectively. The effective tax rate for the three months ended June 30, 2025 was lower than the statutory federal rate of 21% primarily as a result of the impact of the goodwill impairment charge recorded during the same period. 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.

Six months ended June 30, 2025 as compared to six months ended June 30, 2024

Lease operating expenses. LOE increased $154.2 million to $490.0 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. The increase was primarily driven by our expanded operations after the Arrangement contributing $115.3 million of additional LOE period over period, as well as increased workover costs of $24.5 million and increased fixed costs of $19.4 million primarily due to new wells brought online during the six months ended June 30, 2025. LOE per Boe decreased $0.03 per Boe period over period to $9.80 per Boe for the six months ended June 30, 2025 primarily due to operational synergies achieved through the Arrangement.

Gathering, processing and transportation expenses. GPT expenses increased $30.3 million to $147.4 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. The increase was primarily due to our expanded operations after the Arrangement contributing $48.2 million of additional GPT expenses. This increase was partially offset by lower transportation rates of $12.8 million, primarily due to several contracts expiring during the year ended December 31, 2024, and lower fair value losses of $5.9 million attributable to the completion of a derivative transportation contract in June 2024. GPT expenses decreased $0.48 per Boe period over period to $2.95 per Boe for the six months ended June 30, 2025 primarily due to lower transportation rates and fair value losses period over period.

Purchased oil and gas expenses. Purchased oil and gas expenses decreased $349.0 million to $343.1 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024 primarily due to a decrease in the volume of crude oil purchased and subsequently sold period over period coupled with decreased crude oil prices over the same period.

Production taxes. Production taxes increased $0.2 million to $143.6 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. The increase was primarily due to a $46.0 million increase in production taxes attributable to our expanded operations after the Arrangement. This increase was largely offset by decreases in crude oil revenues period over period due to lower crude oil prices and a reduction in the production tax rate during the six months ended June 30, 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 revenues decreased from 8.7% for the six months ended June 30, 2024 to 7.0% for the six months ended June 30, 2025 primarily due to the non-recurring refund coupled with natural gas comprising a larger percentage of total sales relative to the prior period.

Depreciation, depletion and amortization. DD&A expense increased $330.0 million to $726.8 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. The increase was primarily due to $186.4 million of additional depletion expense due to a higher depletion rate period over period, coupled with $134.7 million of additional DD&A expense related to an overall increase in production volumes, mainly due to our expanded operations after the Arrangement as well as an increase in accretion of $8.7 million. Accretion expense increased primarily due to higher plugging and abandonment expenses and incremental accretion related to properties acquired in the Arrangement. The depletion rate increased $2.84 per Boe period over period to $14.13 per Boe for the six months ended June 30, 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 decreased $36.9 million to $70.9 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024 primarily due to lower merger-related costs of $54.7 million. Merger-related costs for the six months ended June 30, 2025 and 2024 were $8.1 million and $62.8 million, respectively, and were primarily comprised of severance, legal and advisory expenses related to the Arrangement. This decrease in merger-related costs was partially offset by an increase in costs associated with a larger organization after the Arrangement of $17.8 million.

Impairment and exploration. Impairment and exploration expenses increased $536.3 million to $543.9 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024 primarily due to the impairment of our goodwill. During the six months ended June 30, 2025, we recorded an impairment charge on our goodwill of $539.3 million as a result of the decrease in the price of our common stock during the three months ended June 30, 2025, which was impacted by a decline in crude oil and natural gas prices over that same period. During the six months ended June 30, 2024, we recorded a lower of cost or net realizable value write down of oil-in-tank inventory of $3.9 million.

Gain (loss) on sale of assets, net. During the six months ended June 30, 2025 and 2024, we recorded a net gain on sale of assets of $5.0 million and $16.8 million, respectively, primarily related to the divestiture of certain non-core oil and gas properties within each period.

Derivative instruments. During the six months ended June 30, 2025, we recorded a $62.0 million net gain on derivative instruments, which was comprised of a net gain of $61.0 million associated with our commodity derivative contracts and an unrealized gain of $0.9 million associated with a contract that includes contingent consideration. The net gain of $61.0 million on commodity derivative contracts included an unrealized gain of $47.2 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 and a realized gain of $13.8 million on settled commodity derivative contracts. During the six months ended June 30, 2024, we recorded a $23.0 million net loss on derivative instruments, which was comprised of a net loss of $27.0 million associated with our commodity derivative contracts, partially offset by an unrealized gain of $4.0 million associated with a contract that included contingent consideration. The net loss of $27.0 million on commodity derivative contracts included an unrealized loss of $21.7 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 $5.3 million on settled commodity derivative contracts.

Investment in unconsolidated affiliate. We recorded a $5.9 million net loss related to our investment in Energy Transfer for the six months ended June 30, 2025, which included an unrealized loss of $10.6 million as a result of a decrease in the fair value of the investment during the period, partially offset by a gain of $4.7 million for cash distributions from Energy Transfer during the period. During the six months ended June 30, 2024, we recorded a net gain of $22.2 million related to our investment in Energy Transfer, which included an unrealized gain of $17.6 million as a result of an increase in the fair value of the investment during the period, coupled with a gain of $4.6 million for cash distributions from Energy Transfer during the period.

Interest expense, net of capitalized interest. Interest expense increased $14.8 million to $34.6 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 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 six months ended June 30, 2025, the weighted average borrowings outstanding under the Credit Facility were $310.3 million, and the weighted average interest rate incurred on the outstanding borrowings was 6.5%. During the six months ended June 30, 2024, the weighted average borrowings outstanding under the Credit Facility were $229.9 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.5%. Interest capitalized during the six months ended June 30, 2025 and June 30, 2024 was $2.2 million and $1.9 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 six months ended June 30, 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 (298.4)% and 24.7% of pre-tax income (loss) for the six months ended June 30, 2025 and 2024, respectively. Our effective tax rate for the six months ended June 30, 2025 was lower than the statutory federal rate of 21% primarily as a result of the impact of the goodwill impairment charge recorded during the same period. The effective tax rate for the six months ended June 30, 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 June 30, 2025, we had $1,830.6 million of liquidity available, including $40.5 million in cash and cash equivalents and $1,790.1 million of aggregate unused borrowing capacity available under the Credit Facility (defined below). During the six months ended June 30, 2025, our primary sources of liquidity were from cash flows from operations, available borrowing capacity under the Credit Facility, proceeds from the issuance of the 2033 Senior Notes and cash on hand. During the same period, 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 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 decreased interest rates during the fourth quarter of 2024, 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, $102.4 million to settle all outstanding Enerplus equity-based compensation awards and $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 and six months ended June 30, 2025, we incurred merger-related costs of $2.9 million and $8.1 million, respectively, 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 June 30, 2025, our commodity derivative contracts cover 5,980 MBbls of our crude oil production and 24,840,000 MMBtu of our natural gas production for 2025, 6,414 MBbls of our crude oil production and 28,680,000 MMBtu of our natural gas production for 2026 and 678 MBbls of our crude oil production and 3,620,000 MMBtu of our natural gas production for 2027. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk” for additional information.

Subsequent to June 30, 2025, we entered into the following commodity derivative contracts:

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 $485.1 million as of June 30, 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 June 30, 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 June 30, 2025, we had $180.0 million borrowings outstanding and $29.9 million of outstanding letters of credit, resulting in an unused borrowing capacity of $1,790.1 million. Additionally, we are permitted to incur term loans in addition to the revolving loans provided under the Credit Facility. As of June 30, 2025, we were in compliance with the financial covenants under the Credit Facility. See “Item 1. Financial Statements (Unaudited)—Note 10—Long-Term Debt” for additional information.

2033 Senior Notes. On March 13, 2025, we issued the 2033 Senior Notes in a private placement. 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 tendered in a concurrent tender offer, to satisfy and discharge the remaining 2026 Senior Notes not tendered in the concurrent tender offer (which were redeemed on 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 $11.6 million.

2026 Senior Notes. As of December 31, 2024, we had $400.0 million of the 2026 Senior Notes outstanding. 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 were redeemed on June 1, 2025. See “Item 1. Financial Statements (Unaudited)—Note 10—Long-Term Debt” for additional information.

Cash Flows

Our cash flows for the six months ended June 30, 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 $1,076.7 million for the six months ended June 30, 2025. The increase in net cash provided by operating activities of $209.1 million as compared to the six months ended June 30, 2024 was primarily due to our expanded operations from the Arrangement, including an increase in oil, NGL and natural gas revenues, partially offset by increases in LOE and GPT expenses. This increase was also driven by lower merger-related costs, offset by 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) decreased net cash flows from operating activities by $12.5 million and $18.1 million during the six months ended June 30, 2025 and 2024, 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 $1.8 billion at June 30, 2025, and excludes current hedge assets, which were $82.1 million at June 30, 2025. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which were $0.3 million at June 30, 2025.

Cash flows used in investing activities

For the six months ended June 30, 2025, net cash used in investing activities of $677.8 million was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $704.4 million and $26.2 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 and the settlement of derivative contracts of $14.1 million. Net cash used in investing activities for the six months ended June 30, 2024 of $1,150.6 million was primarily attributable to the Arrangement, including $395.0 million paid to settle Enerplus’ revolving bank credit facility balance, $375.8 million paid to Enerplus shareholders, $102.4 million paid to settle Enerplus’ equity awards and $5.9 million in retention bonuses paid to Enerplus employees, partially offset by cash acquired in the Arrangement of $239.9 million. Net cash used in investing activities during the six months ended June 30, 2024 also included capital expenditures of $538.7 million and the settlement of derivative contracts of $16.3 million, partially offset by the receipt of the 2023 contingent consideration earn-out payment of $25.0 million and proceeds from divestitures of certain non-core oil and gas properties of $20.9 million.

Cash flows provided by (used in) financing activities

For the six months ended June 30, 2025, net cash used in financing activities of $395.4 million was primarily attributable to repayments of the 2026 Senior Notes totaling $401.4 million, payments to repurchase our common stock of $274.0 million, dividends paid to shareholders of $168.8 million, payments for income tax withholdings on vested equity-based compensation awards of $21.8 million, payment of debt issuance costs of $13.4 million primarily in connection with the issuance of the 2033 Senior Notes and repayments under the Credit Facility of $2.7 billion, partially offset by borrowings of $2.4 billion, resulting in net repayments under the Credit Facility of $265.0 million. These uses of cash were partially offset by proceeds from the issuance of the 2033 Senior Notes of $750.0 million. Net cash provided by financing activities for the six months ended June 30, 2024 of $162.4 million was primarily attributable to borrowings under the credit facility of $575.0 million, net of repayments of $250.0 million, in connection with the Arrangement and proceeds from the exercise of outstanding warrants of $21.0 million, partially offset by dividends paid to shareholders of $281.7 million, payments to repurchase our common stock of $93.7 million, and income tax withholdings on vested equity-based compensation awards of $57.4 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 August 6, 2025, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on September 8, 2025 to shareholders of record as of August 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 six months ended June 30, 2025, we repurchased 2,600,117 shares of common stock at a weighted average price of $104.41 per common share for a total cost of $271.5 million under our $750.0 million share repurchase program. In August 2025, our Board of Directors authorized a new share repurchase program of up to $1.0 billion of the common stock, which replaces the existing $750 million share repurchase program. As of June 30, 2025, there was $321.2 million of capacity remaining under our $750.0 million share repurchase program.

During the six months ended June 30, 2024, we repurchased 558,579 shares of common stock under a previous share repurchase program at a weighted average price of $164.23 per common share for a total cost of $91.7 million.

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 June 30, 2025 was a net asset position of $61.9 million. A 10% increase in crude oil prices would reduce the fair value of this unrealized derivative asset position by approximately $54.5 million, while a 10% decrease in crude oil prices would increase the fair value of this unrealized derivative asset position by approximately $56.4 million. The fair value of our unrealized natural gas derivative positions at June 30, 2025 was a net liability position of $0.1 million. A 10% increase in natural gas prices would decrease the fair value of this unrealized derivative liability position by approximately $22.8 million, while a 10% decrease in natural gas prices would increase the fair value of this unrealized derivative liability position by approximately $16.5 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 June 30, 2025, the fair value of this contingent consideration was $23.7 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 June 30, 2025, we had $750.0 million of senior unsecured notes at a fixed interest rate of 6.750% per annum. At June 30, 2025, we had $180.0 million borrowings and $29.9 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, an ABR Loan or a Swingline Loan (each as defined in the Credit Facility). As of June 30, 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 and six months ended June 30, 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 June 30, 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 June 30, 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 June 30, 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.