Chord Energy Corp
For the period ended Dec 31, 2025. Filed Feb 26, 2026.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Feb 26, 2026
CHRD$136.49+3.1%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-02-27.
0001486159-25-000005
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-02-26.
0001486159-26-000005
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 144 previous paragraphs and 144 current paragraphs.
66 unchanged; 59 reworded; 19 added; 18 removed; 1 previous and 0 current paragraphs rearranged.
Tables are not compared: 7 previous and 7 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (19)
Current report
2025 Williston Basin Acquisition
Current report
On September 15, 2025, we entered into a definitive agreement to acquire certain developed and undeveloped oil and gas assets located in the Williston Basin from XTO Energy Inc. and affiliates (collectively, “XTO”), subsidiaries of Exxon Mobil Corporation, for total cash consideration of $550.0 million, subject to customary purchase price adjustments (the “2025 Williston Basin Acquisition”).
Current report
On October 31, 2025, we completed the 2025 Williston Basin Acquisition for total cash consideration of $542.2 million, including a cash deposit of $55.0 million to XTO upon execution of the purchase and sale agreement and $487.2 million paid to XTO at closing (including customary preliminary purchase price adjustments). We funded the 2025 Williston Basin Acquisition with proceeds from the issuance of the 2030 Senior Notes (defined in “Liquidity and Capital Resources—Long-Term Debt” below) and cash on hand. The effective date of the 2025 Williston Basin Acquisition was September 1, 2025.
Current report
During 2025, the energy markets were marked by heightened volatility that led to frequent and unpredictable changes in crude oil prices. Throughout the year, prices fluctuated considerably, with periods of both decline and recovery. The average NYMEX WTI declined 14% during the year ended December 31, 2025, compared to the prior year, and overall conditions remain unstable. Market conditions during the year were adversely influenced by elevated production levels from OPEC+, ongoing trade and tariff negotiations between the United States and other governments, and retaliatory measures taken by such other governments. Further declines 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, as well as our access to capital. For example, 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 declines in crude oil and natural gas prices over that same period, we assessed goodwill for impairment and recognized a non‑cash impairment charge of $539.3 million. See “Item 8. Financial Statements and Supplementary Data—Note 6—Fair Value Measurements” for additional information.
Current report
•Capital expenditures (excluding capitalized interest) were $1,357.9 million for the year ended December 31, 2025.
Current report
•Paid $5.20 per share base cash dividends for the year ended December 31, 2025.
Current report
Net Income
Current report
We had net income of $44.5 million for the year ended December 31, 2025, which decreased 95% as compared to $848.6 million for the year ended December 31, 2024, primarily due to decreased realized oil prices and a non-cash goodwill impairment charge during the year ended December 31, 2025. The impacts on net income of our expanded operations from the Arrangement and other increases and decreases in revenues and expenses are further explained below.
Current report
Certain operating expenses, including LOE, GPT expenses and DD&A, increased for the year ended December 31, 2025 as compared to the year ended December 31, 2024 due to the Arrangement, which closed on May 31, 2024 and expanded our operations primarily in the Williston Basin.
Current report
Production taxes. Production taxes decreased $41.5 million to $291.9 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. Excluding the $46.0 million increase in production taxes attributable to our expanded operations after the Arrangement, production taxes decreased $66.6 million primarily due to a decrease in crude oil revenues year over year due to lower crude oil realized prices and decreased $20.9 million as a result of a reduction in the production tax rate during the year ended December 31, 2025 primarily due to a non-recurring refund related to certain North Dakota wells receiving an extraction tax exemption. The production tax rate as a percentage of crude oil, NGL and natural gas sales was 7.5% for the year ended December 31, 2025 as compared to 8.7% for the year ended December 31, 2024. This rate decrease year-over-year was primarily due to the non-recurring refund in 2025 coupled with natural gas comprising a larger percentage of total sales relative to the prior period.
Current report
General and administrative expenses. Our general and administrative (“G&A”) expenses decreased $79.3 million to $126.3 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024, primarily due to a $79.5 million decrease in merger and acquisition-related costs year-over-year. Merger and acquisition-related costs for the years ended December 31, 2025 and 2024 were $9.8 million and $89.3 million, respectively, and were primarily comprised of severance, legal, and advisory expenses related to the Arrangement.
Current report
Impairment and exploration expenses. Impairment and exploration expenses increased $534.4 million to $551.4 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024, primarily due to the impairment of our goodwill. During the year ended December 31, 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 during that same period.
Current report
Loss on debt extinguishment. On March 13, 2025, we paid an aggregate of $409.1 million to purchase and satisfy and discharge $400.0 million of our 6.375% senior unsecured notes due June 1, 2026 (the “2026 Senior Notes), resulting in a loss on debt extinguishment of $3.5 million for the year ended December 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.
Current report
Other income, net. For the year ended December 31, 2025, we recognized $15.0 million of other income, net, which related primarily to proceeds from the disposition of surplus equipment, partially offset by remeasurement of equipment inventory. For the year ended December 31, 2024, we recognized $5.0 million of other income, net, which related primarily to interest income associated with the average cash balance in our money market account.
Current report
Williston Basin Acquisition. On October 31, 2025, we completed the 2025 Williston Basin Acquisition for total cash consideration of $542.2 million, including the $55.0 million deposit and $487.2 million paid to XTO at closing (including customary preliminary purchase price adjustments).
Current report
2024, we incurred merger and acquisition-related costs of $9.8 million and $89.3 million, respectively, and were primarily comprised of severance, legal, and advisory expenses related to the Arrangement.
Current report
(1)Total E&P capital expenditures include approximately $19.7 million, $25.2 million and $14.5 million of non-operated capital expenditures related to certain non-operated divested assets that were reimbursable for the years ended December 31, 2025, 2024 and 2023, respectively.
Current report
For the year ended December 31, 2025, our total capital expenditures increased $125.8 million to $1,362.3 million primarily due to an increase in non-operated drilling and completion activities of $109.6 million, coupled with our expanded operations as a result of the Arrangement.
Current report
Acquisition and leasehold costs were $576.5 million, $16.0 million and $361.6 million for the years ended December 31, 2025, 2024 and 2023, respectively. Acquisitions include $542.2 million for the 2025 Williston Basin Acquisition and $361.6 million for the acquisition of net acreage in the Williston Basin for the years ended December 31, 2025 and 2023, respectively, and exclude amounts attributable to the Arrangement, including cash consideration of $375.8 million, for the year ended December 31, 2024.
Removed paragraphs (18)
Previous report
Enerplus Arrangement
Previous report
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.
Previous report
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.
Previous report
Divestitures
Previous report
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.
Previous report
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.
Previous report
•E&P and other capital expenditures were $1.2 billion for the year ended December 31, 2024.
Previous report
•Paid $10.15 per share base-plus-variable cash dividend for the year ended December 31, 2024.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
(1)For the year ended December 31, 2024, capital expenditures related to the Marcellus Shale were $8.9 million.
Previous report
(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.
Previous report
(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.
Previous report
(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”).
Previous report
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.
Reworded paragraphs (59)
Previous wording
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.
Current wording
Chord Energy Corporation, a Delaware corporation (together with our 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 with limited non-operated interests in the Marcellus Shale. On May 31, 2024, we acquired Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”) in a stock-and-cash transaction (such transaction, the “Arrangement”). Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a fun and rewarding environment for our employees. We are ideally positioned to generate strong free cash flow and enhance return of capital, while being responsible stewards of the communities and environment where we operate.
Previous wording
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.
Current wording
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, NGL 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, NGL and natural gas. The potential for continued volatility in our markets, economic uncertainty and unfavorable oil and gas market dynamics, including OPEC+ announcements during 2025 regarding increased oil production targets and U.S. tariffs and potential retaliatory tariffs, may have an adverse impact on our future business operations, financial condition and liquidity.
Previous wording
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 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.
Current wording
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 and 2025. 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, NGL and natural gas (see “Item 7A. —Quantitative and Qualitative Disclosures about Market Risk—Inflation risks” for additional information). The uncertainties 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 wider Middle East and the recent developments in relations between the United States and Venezuela, make it difficult to predict future impacts to commodity prices.
Previous wording
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.
Current wording
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 in the near future at current price levels; however, we would 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 price of crude oil, NGL 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” for additional information.
Previous wording
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.”
Current wording
In an effort to improve price realizations from the sale of our crude oil, NGL and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGL 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.”
Previous wording
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.
Current wording
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, 2025, 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, to a lesser extent, rail markets in order to optimize price realizations. Expansions of both pipeline and rail facilities in the Williston Basin has reduced prior constraints on crude oil takeaway capacity and improved our price differentials received at the lease.
Previous wording
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.
Current wording
The results of operations presented below relate to the periods ended December 31, 2025 and 2024. The results reported for the year ended December 31, 2025 reflect the consolidated results of Chord, while 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, unless otherwise noted.
Previous wording
•Production volumes averaged 232,737 Boepd (57% oil) for the year ended December 31, 2024.
Current wording
•Production volumes averaged 276,620 Boepd (56% oil) for the year ended December 31, 2025.
Previous wording
•Lease operating expenses (“LOE”) were $9.68 per Boe for the year ended December 31, 2024.
Current wording
•Lease operating expenses (“LOE”) were $9.73 per Boe for the year ended December 31, 2025.
Previous wording
•Net cash provided by operating activities was $2.1 billion and net income was $848.6 million for the year ended December 31, 2024.
Current wording
•Net cash provided by operating activities was $2,040.7 million and net income was $44.5 million for the year ended December 31, 2025.
Previous wording
•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.
Current wording
•Estimated net proved reserves were 917.5 MMBoe as of December 31, 2025, with a Standardized Measure of $7.5 billion and PV-10 of $9.1 billion.
Previous wording
•TIL’d 142 gross (93 net) operated wells for the year ended December 31, 2024.
Current wording
•TIL’d 122 gross (99 net) operated wells for the year ended December 31, 2025.
Previous wording
•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.
Current wording
•Repurchased $364.5 million of common stock (excluding accrued excise taxes) during the year ended December 31, 2025 with $952.2 million remaining under the new $1.0 billion share repurchase program authorized by the Board of Directors in August 2025.
Previous wording
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.
Current wording
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. Additionally, our revenues for the year ended December 31, 2025 were positively impacted 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, NGL 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.
Previous wording
(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.
Current wording
(1)For the years ended December 31, 2025 and 2024, natural gas production volume from the Marcellus Shale was 45,151 MMcf and 24,727 MMcf, respectively. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $3.15 per Mcf and $1.78 per Mcf for the years ended December 31, 2025 and 2024, respectively.
Previous wording
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.
Current wording
Crude oil revenues. Our crude oil revenues decreased $24.4 million to $3,546.9 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. Excluding the increase of $491.4 million due to our expanded operations as a result of the Arrangement, our crude oil revenues decreased $545.6 million due to lower crude oil realized prices year-over-year, partially offset by an increase of $29.8 million due to higher total crude oil production volumes sold. Average crude oil sales prices, without derivative settlements, decreased by $10.89 per barrel year-over-year to an average of $62.78 per barrel for the year ended December 31, 2025 due to decreases in NYMEX WTI and widening in-basin differentials.
Previous wording
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.
Current wording
NGL revenues. Our NGL revenues decreased $23.8 million to $138.3 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. Excluding the increase of $3.8 million due to our expanded operations as a result of the Arrangement, our NGL revenues decreased $34.5 million due to lower NGL realized prices year-over-year, partially offset by an increase of $6.9 million due to higher total NGL production volumes sold. Average NGL sales prices, without derivative settlements, decreased by $2.70 per barrel period over period to an average of $7.22 per barrel for the year ended December 31, 2025 primarily due to wider differentials on incremental production volumes primarily as a result of the Arrangement.
Previous wording
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.
Current wording
Natural gas revenues. Our natural gas revenues increased $109.2 million to $212.0 million for the year ended December 31, 2025 as compared to the year ended December 31, 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 $41.4 million primarily due to higher average natural gas realized prices. Average natural gas sales prices, without derivative settlements, increased by $0.56 per Mcf period over period to $1.40 per Mcf for the year ended December 31, 2025 primarily due to increases in natural gas index prices period over period.
Previous wording
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.
Current wording
Purchased oil and gas sales. Purchased oil and gas sales decreased $435.0 million to $980.0 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. This decrease was primarily due to a decrease in the volume of crude oil purchased and subsequently sold as well as lower crude oil prices year-over-year.
Previous wording
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.
Current wording
Lease operating expenses. LOE increased $158.2 million to $982.6 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. The increase was primarily driven by our expanded operations after the Arrangement, contributing $115.3 million of additional LOE period over period. Additionally, workover costs increased by $30.2 million and fixed and variable costs increased by $12.6 million primarily due to 122 gross (99 net) operated new wells brought online during year ended December 31, 2025. LOE per Boe increased $0.05 per Boe period over period to $9.73 per Boe for the year ended December 31, 2025 primarily due to increased workover costs.
Previous wording
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.
Current wording
Gathering, processing and transportation expenses. GPT expenses increased $23.4 million to $290.9 million for the year ended December 31, 2025 as compared to the year ended December 31, 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 certain derivative transportation contracts in June 2024. GPT expenses decreased $0.26 per Boe period over period to $2.88 per Boe for the year ended December 31, 2025 primarily due to an increase in production volumes, lower transportation rates and fair value losses period over period.
Previous wording
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.
Current wording
Purchased oil and gas expenses. Purchased oil and gas expenses decreased $437.2 million to $975.1 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024 primarily due to a decrease in the volume of crude oil purchased and subsequently sold as well as lower crude oil prices year-over-year.
Previous wording
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.
Current wording
Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense increased $362.4 million to $1,470.2 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. The increase was primarily due to $209.6 million of additional depletion expense due to a higher depletion rate year-over-year, coupled with $128.2 million of additional DD&A expense related to an overall increase in production volumes year-over-year, mainly due to our expanded operations after the Arrangement, as well as an increase in accretion expense of $19.8 million. The depletion rate increased $1.82 per Boe year-over-year to $14.12 per Boe for the year ended December 31, 2025 primarily due to the purchase consideration allocated to the fair value of oil and gas properties acquired in the Arrangement and the 2025 Williston Basin Acquisition.
Previous wording
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.
Current wording
Gain on sale of assets, net. During the years ended December 31, 2025 and 2024, we recorded a net gain on sale of assets of $8.7 million and $17.1 million, respectively, primarily related to the divestiture of certain oil and gas properties within each period.
Previous wording
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.
Current wording
Derivative instruments. During the year ended December 31, 2025, we recorded a $127.6 million net gain on derivative instruments, which was primarily comprised of a net gain of $125.4 million associated with our commodity derivative contracts and a net gain of $2.2 million associated with a contract that included contingent consideration. The net gain of $125.4 million on commodity derivative contracts included a realized gain of $63.8 million on settled commodity derivative contracts, coupled with an unrealized gain of $61.6 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. 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 included 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.
Previous wording
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.
Current wording
Investment in equity securities. We recorded a $13.0 million loss related to our investment in Energy Transfer for the year ended December 31, 2025, which included an unrealized loss of $22.5 million as a result of a decrease in the fair value of the investment during the year, partially offset by a realized gain of $9.5 million for cash distributions received. During the year ended December 31, 2024, we recorded a $51.3 million gain related to our investment in Energy Transfer, primarily related to a realized 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.
Previous wording
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.
Current wording
Interest expense, net of capitalized interest. Interest expense increased $23.6 million to $80.2 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. The increase is primarily due to $32.0 million of higher interest expense on a greater outstanding balance of senior notes resulting from the issuance of the 2033 Senior Notes (as defined below) and the 2030 Senior Notes (as defined below) during 2025, partially offset by the impact of the repayment of the 2026 Senior Notes in March 2025. This increase in interest expense was partially offset by a decrease in interest expense on the Credit Facility (as defined below) of $9.6 million year-over-year. For the year ended December 31, 2025, the weighted average borrowings outstanding under the Credit Facility were $215.0 million, and the weighted average interest rate incurred on the outstanding borrowings was 6.52%. 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 7.27%.
Previous wording
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.
Current wording
Income tax expense. Our effective tax rate was recorded at 81.7% and 23.7% of pre-tax income for the years ended December 31, 2025 and December 31, 2024, respectively. Our effective tax rate for the year ended December 31, 2025 was higher than the statutory federal tax rate of 21% primarily as a result of the impact of the goodwill impairment charge recorded during the second quarter of 2025. The effective tax rate for the year ended December 31, 2024 was higher than the statutory federal tax rate of 21% primarily as a result of the impact of state income taxes.
Previous wording
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.
Current wording
As of December 31, 2025, we had $2,156.7 million of liquidity available, including $1,967.2 million of aggregate unused borrowing base capacity available under our Credit Facility (as defined below) and $189.5 million in cash and cash equivalents. We had no net borrowings outstanding under our Credit Facility and $32.8 million of outstanding letters of credit. Our primary sources of liquidity were from cash flows from operations, available borrowing capacity under the Credit Facility, proceeds from the issuance of the 2030 Senior Notes and the 2033 Senior Notes and cash on hand. Our primary liquidity requirements were debt repayments under our Credit Facility, capital expenditures for the development of oil and gas properties, acquisitions, debt repayments under the 2026 Senior Notes, share repurchases, dividend payments and working capital requirements.
Previous wording
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.
Current wording
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 has continued to steadily decrease 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.
Previous wording
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.
Current wording
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 years ended December 31, 2025 and
Previous wording
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.
Current wording
Our cash flows depend on many factors, including the price of crude oil, NGL 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.
Previous wording
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.
Current wording
Commodity derivative contracts. As of December 31, 2025, our commodity derivative contracts cover 7,216 MBbls of our crude oil production and 44,185 MMBtu of our natural gas production for 2026, as well as 2,501 MBbls of our crude oil production and 13,620 MMBtu of our natural gas production for 2027. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and “Part I, Item 1A. Risk Factors” for additional information.
Previous wording
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.
Current wording
Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to our long-term debt, payment of income taxes, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, obligations associated with our leases, obligations associated with outstanding commodity derivative contracts that settle in a loss position and obligations to pay dividends on equity awards. In addition, we have announced a return of capital plan pursuant to which we intend to return capital to stockholders through base dividend payouts, supplemented by opportunistic share repurchases and variable dividend payouts. There were no borrowings outstanding under the Credit Facility (as defined below) as of December 31, 2025; however, 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.
Previous wording
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.
Current wording
We also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, NGL, 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 $467.9 million as of December 31, 2025. We believe that for the substantial majority of these agreements, our future production will be adequate to meet our delivery commitments or that we can purchase sufficient volumes of crude oil, NGL and natural gas from third parties to satisfy our minimum volume commitments.
Previous wording
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.
Current wording
Our long-term debt consists of a senior secured revolving line of credit that is generally used to support our working capital requirements, $750.0 million of 6.000% senior unsecured notes and $750.0 million of 6.750% senior unsecured notes.
Previous wording
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.
Current wording
Senior secured revolving line of credit. As of December 31, 2025, we had a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $2.75 billion and an aggregate amount of elected commitments of $2.0 billion that is due November 3, 2029. We had no net borrowings outstanding and $32.8 million of outstanding letters of credit, resulting in an unused borrowing base capacity of $1,967.2 million as of December 31, 2025. Additionally, we are permitted to incur term loans in addition to the revolving loans provided under the Credit Facility. In November 2025, we completed the semi-annual borrowing base redetermination, which affirmed the borrowing base of $2.75 billion and the aggregate amount of elected commitments of $2.0 billion and entered into the Seventh Amendment to the Amended and Restated Credit Agreement.
Previous wording
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.
Current wording
For the year ended December 31, 2025, the weighted average interest rate incurred on borrowings under the Credit Facility was 6.52%, compared to 7.27% for the year ended December 31, 2024.
Previous wording
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.
Current wording
Senior unsecured notes. As of December 31, 2025, we had $750.0 million of 6.750% senior unsecured notes (the “2033 Senior Notes”) that mature on March 15, 2033 and $750.0 million of 6.000% senior unsecured notes (the “2030 Senior Notes”) that mature on October 1, 2030. Interest on the 2033 Senior Notes is payable semi-annually on March 15 and September 15 of each year, and interest on the 2030 Senior Notes is payable semi-annually on April 1 and October 1 of each year. We were in compliance with the terms of the indentures for the 2030 Senior Notes and the 2033 Senior Notes at December 31, 2025. See “Item 8. Financial Statements and Supplementary Data—Note 12—Long-Term Debt” for additional information.
Previous wording
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.
Current wording
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 $2,040.7 million for the year ended December 31, 2025. The decrease in net cash provided by operating activities of $56.6 million from the year ended December 31, 2024 was primarily due to lower revenues from crude oil and NGL sales driven by decreased crude oil and NGL realized prices, higher cash interest expenses and changes in our working capital. These decreases were largely offset by our expanded operations from the Arrangement, lower merger and acquisition-related costs and decreased production taxes primarily driven by decreased crude oil sales. Crude oil, NGL and natural gas revenues were positively impacted by an increase in crude oil, NGL, and natural gas production volumes due to our expanded operations from the Arrangement, partially offset by increases in LOE and GPT expenses. See “Results of Operations” above for additional information.
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Previous report — wording carried elsewhere
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.