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Chord Energy Corp (CHRD)

CIK: 0001486159. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2026-02-26.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas

SEC company page: https://www.sec.gov/edgar/browse/?CIK=1486159. Latest filing source: 0001486159-26-000005.

Selected Fundamentals

MetricValueUnitFYFiled
Revenue4,877,126,000USD20252026-02-26
Net income44,459,000USD20252026-02-26
Assets13,074,274,000USD20252026-02-26

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-26. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001486159.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Metric2016201720182019202020212022202320242025
Revenue704,665,0001,293,719,0002,321,947,0001,930,797,000845,457,0001,579,926,0003,646,794,0003,896,641,0005,251,082,0004,877,126,000
Net income-243,016,000123,796,000-35,296,000-128,243,000-3,640,328,000319,602,0001,856,159,0001,023,779,000848,627,00044,459,000
Operating income-130,833,000143,968,000119,012,000-90,175,000-4,971,599,000809,444,0001,583,789,0001,273,182,0001,100,067,000197,425,000
Diluted EPS-1.320.52-0.11-0.41-11.4615.4857.5523.5116.020.74
Assets6,178,632,0006,622,929,0007,626,142,0007,499,253,0002,237,991,0003,026,787,0006,631,081,0006,926,150,00013,032,007,00013,074,274,000
Liabilities3,255,475,0003,109,350,0003,707,262,0003,662,172,0001,179,560,0001,805,214,0001,951,283,0001,849,526,0004,329,745,0004,994,320,000
Stockholders' equity2,923,157,0003,375,691,0003,734,576,0003,636,138,000965,615,0001,032,900,0004,679,798,0005,076,624,0008,702,262,0008,079,954,000
Cash and cash equivalents11,226,00016,720,00022,190,00020,019,0004,241,000172,114,000593,151,000317,998,00036,950,000189,531,000
Net margin-34.49%9.57%-1.52%-6.64%20.23%50.90%26.27%16.16%0.91%
Operating margin-18.57%11.13%5.13%-4.67%51.23%43.43%32.67%20.95%4.05%

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-07. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001486159.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

QuarterEnd DateRevenueNet IncomeDiluted EPSMethod
2022-Q22022-06-306.23reported discrete quarter
2022-Q32022-09-3020.45reported discrete quarter
2023-Q12023-03-316.87reported discrete quarter
2023-Q22023-06-30912,071,000216,071,0004.96reported discrete quarter
2023-Q32023-09-301,123,368,000209,076,0004.77reported discrete quarter
2023-Q42023-12-31964,685,000301,633,000derived Q4 = FY annual - nine-month YTD
2024-Q12024-03-311,085,260,000199,353,0004.65reported discrete quarter
2024-Q22024-06-301,260,680,000213,361,0004.25reported discrete quarter
2024-Q32024-09-301,450,467,000225,316,0003.59reported discrete quarter
2024-Q42024-12-311,454,674,000210,597,000derived Q4 = FY annual - nine-month YTD
2025-Q12025-03-311,215,047,000219,837,0003.66reported discrete quarter
2025-Q22025-06-301,180,560,000-389,905,000-6.77reported discrete quarter
2025-Q32025-09-301,312,081,000130,111,0002.26reported discrete quarter
2025-Q42025-12-311,169,439,00084,416,000derived Q4 = FY annual - nine-month YTD
2026-Q12026-03-311,665,635,000108,608,0001.90reported discrete quarter

Quarterly Charts

Macro Cross-References

Latest quarter (10-Q)

Latest 10-Q source: 0001486159-26-000023.

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high. Filing date: 2026-05-07. Report date: 2026-03-31.

Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “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, 2025 (“2025 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”). All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding, but not limited to, 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.

These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. 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.

We believe these factors and risks relate to forward-looking statements including, but not limited to, the following:

•crude oil, NGL 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, NGL 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 production levels;

•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, Iran, and the wider Middle East and their effect on commodity prices;

•changes or uncertainty in general economic and geopolitical conditions;

•inflation rates and the impact of associated monetary policy responses, including fluctuating interest rates;

•logistical challenges and supply chain disruptions, including as a result of conflicts;

•our business strategy, including the continued implementation of our 4-mile well program;

•the geographic concentration of our operations;

•estimated future net reserves and present value thereof;

•timing and amount of future production of crude oil, NGL 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, NGL and natural gas in the Williston Basin and other regions in the United States;

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•the possible shutdown of the Dakota Access Pipeline;

•our ability to realize the anticipated benefits from acquisitions;

•property acquisitions and divestitures;

•integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness;

•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 goals regarding 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 Facility 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 disruptions arising from cybersecurity threats, terrorist attacks and any consequential or other hostilities;

•compliance with, and changes in, environmental, safety and other laws and regulations;

•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 and resulting demand and supply for crude oil, NGL and natural gas;

•governmental regulation, including, but not limited to, that of the Federal Energy Regulatory Commission (“FERC”), and the taxation of the oil and gas industry;

•developments in crude oil-producing and natural gas-producing countries;

•integration of emerging technologies, including artificial intelligence and machine learning technologies for improving operational efficiency;

•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 volatile 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 2025 Annual Report and in our other filings with the SEC.

In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. 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. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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Overview

Chord Energy Corporation, a Delaware 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 with limited non-operated interests in the Marcellus Shale. 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.

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. Energy markets experienced significant volatility during the first quarter of 2026, driven primarily by geopolitical tensions and the resulting disruptions to global oil supply. Following the escalation of conflict in the Middle East in late February, the NYMEX WTI spot price increased more than 50% by the end of the first quarter. Continued geopolitical tensions, uncertainty around OPEC+ production policy and the potential economic outcomes of tariff and trade policy decisions of the U.S. or other governments create difficulty in predicting future impacts to commodity prices, which could affect our financial position, results of operations, cash flows, capital and operating costs, and the quantities of crude oil, NGL and natural gas reserves that may be economically produced.

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.

Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of March 31, 2026, substantially all of our gross operated crude oil and natural gas production were 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.

In an effort to reduce inflationary pressures that emerged in the broader economy, central banks have in the past raised interest rates. 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. To the extent we and our relevant markets experience high inflation, we may see cost increases in our operations, including increases in equipment and labor costs, and as a result our revenues, estimates of future reserves, borrowing base calculations and impairment assessments could b

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-26. Report date: 2025-12-31.

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

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

For discussion related to changes in financial condition and results of operations for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 27, 2025.

Overview

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.

Recent Developments

2025 Williston Basin Acquisition

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”).

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.

Market Conditions

Our revenue, profitability and ability to return cash to stockholders depend substantially on factors beyond our control, such as economic, geopolitical, political and regulatory developments as well as competition from other sources of energy. Prices for crude oil, 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.

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

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non‑cash impairment charge of $539.3 million. See “Item 8. Financial Statements and Supplementary Data—Note 6—Fair Value Measurements” for additional information.

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.

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.

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.”

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

2025

Year Ended December 31, 2025

Q1

Q2

Q3

Q4

Average realized crude oil prices ($/Bbl)(1)

$

69.11 

$

61.62 

$

63.59 

$

56.90 

$

62.78 

Average price differential ($/Bbl)(2)

$

(2.30)

$

(2.15)

$

(1.41)

$

(2.24)

$

(2.02)

Average price differential percentage(2)

(3.3)

%

(3.5)

%

(2.2)

%

(3.9)

%

(3.2)

%

2024

Year Ended December 31, 2024

Q1

Q2

Q3

Q4

Average realized crude oil prices ($/Bbl)(1)

$

75.32 

$

78.89 

$

73.51 

$

68.79 

$

73.67 

Average price differential ($/Bbl)(2)

$

(1.71)

$

(1.41)

$

(1.51)

$

(1.49)

$

(1.52)

Average price differential percentage(2)

(2.3)

%

(1.8)

%

(2.1)

%

(2.2)

%

(2.1)

%

__________________ 

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

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

We sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of December 31, 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.

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Results of Operations

Comparability of Financial Statements

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.

For a discussion of the changes related to the financial condition and results of operations for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 27, 2025.

Operational and Financial Highlights

•Production volumes averaged 276,620 Boepd (56% oil) for the year ended December 31, 2025.

•Lease operating expenses (“LOE”) were $9.73 per Boe for the year ended December 31, 2025.

•Capital expenditures (excluding capitalized interest) were $1,357.9 million for the year ended December 31, 2025.

•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.

•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.

•TIL’d 122 gross (99 net) operated wells for the year ended December 31, 2025.

Shareholder Return Highlights

•Paid $5.20 per share base cash dividends for the year ended December 31, 2025.

•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.

•On February 25, 2026, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 27, 2026 to stockholders of record as of March 12, 2026.

Net Income

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.

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. 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.

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

Year Ended December 31,

2025

2024

(In thousands, except price per unit data)

Revenues

Crude oil revenues

$

3,546,890 

$

3,571,336 

NGL revenues

138,277 

162,052 

Natural gas revenues

211,973 

102,750 

Purchased oil and gas sales

979,986 

1,414,944 

Total revenues

$

4,877,126 

$

5,251,082 

Production data

Crude oil (MBbls)

56,500 

48,479 

NGL (MBbls)

19,149 

16,338 

Natural gas (MMcf)(1)

151,903 

122,193 

Oil equivalents (MBoe)

100,966 

85,182 

Average daily production (Boepd)

276,620 

232,737 

Average daily crude oil production (Bopd)

154,795 

132,455 

Average sales prices

Crude oil (per Bbl)

Average sales price

$

62.78 

$

73.67 

Effect of derivative settlements(2)

0.81 

0.02 

Average realized price after the effect of derivative settlements(2)

$

63.59 

$

73.69 

NGL (per Bbl)

Average sales price

$

7.22 

$

9.92 

Effect of derivative settlements(2)

— 

— 

Average realized price after the effect of derivative settlements(2)

$

7.22 

$

9.92 

Natural gas (per Mcf)

Average sales price(1)

$

1.40 

$

0.84 

Effect of derivative settlements(2)

0.11 

— 

Average realized price after the effect of derivative settlements(1)(2)

$

1.51 

$

0.84 

__________________

(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.

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

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.

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

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ended December 31, 2025 primarily due to wider differentials on incremental production volumes primarily as a result of the Arrangement.

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.

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.

Expenses and other income (expense)

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.

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

Year Ended December 31,

2025

2024

(In thousands, except per Boe of production)

Operating expenses

Lease operating expenses

$

982,610 

$

824,408 

Gathering, processing and transportation expenses

290,917 

267,559 

Purchased oil and gas expenses

975,128 

1,412,357 

Production taxes

291,880 

333,397 

Depreciation, depletion and amortization

1,470,171 

1,107,776 

General and administrative expenses

126,294 

205,585 

Impairment and exploration

551,412 

17,021 

Total operating expenses

4,688,412 

4,168,103 

Gain on sale of assets, net

8,711 

17,088 

Operating income

197,425 

1,100,067 

Other income (expense)

Net gain on derivative instruments

127,618 

12,563 

Net gain (loss) from investment in equity securities

(12,957)

51,284 

Interest expense, net of capitalized interest

(80,150)

(56,523)

Loss on extinguishment of debt

(3,494)

— 

Other income, net

15,042 

5,047 

Total other income, net

46,059 

12,371 

Income before income taxes

243,484 

1,112,438 

Income tax expense

(199,025)

(263,811)

Net income

$

44,459 

$

848,627 

Costs and expenses (per Boe of production)

Lease operating expenses

$

9.73 

$

9.68 

Gathering, processing and transportation expenses

2.88 

3.14 

Production taxes

2.89 

3.91 

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

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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.

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.

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.

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.

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.

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.

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.

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.

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.

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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.

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%.

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.

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.

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.

Liquidity and Capital Resources

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.

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.

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).

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

We also incurred certain costs for advisory, legal and other third-party fees in connection with the Arrangement, which were recorded to G&A expenses on the Consolidated Statements of Operations. During the years ended December 31, 2025 and

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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.

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.

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.

Subsequent to December 31, 2025, we entered into new commodity derivative contracts to manage risks related to changes in commodity prices. The following table summarizes these commodity derivative contracts:

Weighted Average Prices

Commodity

Settlement Period

Derivative Instrument

Volumes

Fixed-Price Swaps

Sub-Floor

Floor

Ceiling

Crude oil

2026

Three-way collars

459,000 

Bbls

$

45.00 

$

55.00 

$

67.75 

Crude oil

2026

Two-way collars

2,108,000 

Bbls

$

60.00 

$

66.28 

Crude oil

2027

Three-way collars

1,732,000 

Bbls

$

48.42 

$

58.42 

$

72.01 

Crude oil

2027

Two-way collars

270,000 

Bbls

$

60.00 

$

65.22 

Crude oil

2028

Three-way collars

364,000 

Bbls

$

48.75 

$

58.75 

$

73.79 

Natural gas

2026

Fixed-price swaps

3,220,000 

MMBtu

$

4.10 

Natural gas

2027

Fixed-price swaps

905,000 

MMBtu

$

4.00 

Material cash requirements

Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to our long-term debt, 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.

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.

Long-term debt

Our long-term debt consists of a senior secured revolving line of credit that is generally used to support our working capital requirements, $750.0 million of 6.000% senior unsecured notes and $750.0 million of 6.750% senior unsecured notes.

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.

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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.

We were in compliance with the financial covenants in the Credit Facility at December 31, 2025. See “Item 8. Financial Statements and Supplementary Data—Note 12—Long-Term Debt” for additional information.

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.

Cash flows

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

Year Ended December 31,

2025

2024

(In thousands)

Net cash provided by operating activities

$

2,040,657 

$

2,097,227 

Net cash used in investing activities

(1,805,981)

(1,753,817)

Net cash used in financing activities

(82,095)

(624,458)

Increase (decrease) in cash and cash equivalents

$

152,581 

$

(281,048)

For a discussion on cash flows for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2024 Annual Report on Form 10-K filed with the SEC on February 27, 2025 under the subheading “Cash flows.”

Cash flows provided by operating activities

Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes and operating costs. Net cash provided by operating activities was $2,040.7 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.

Working capital. Our working capital is primarily impacted due to the factors discussed above, coupled with the timing of cash receipts and disbursements. During the years ended December 31, 2025 and 2024, changes in working capital (as reflected in the Consolidated Statements of Cash Flows) decreased net cash flows from operating activities by $7.2 million and $34.1 million, respectively. Changes in working capital associated with our capital expenditure activities and settlement of outstanding commodity derivative instruments impact our cash flows from investing activities.

The Credit Facility includes a requirement that we maintain a Current Ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter. For purposes of the Current Ratio, the Credit Facility’s definition of total current assets includes unused commitments under the Credit Facility, which were $1,967.2 million as of December 31, 2025, and excludes current hedge assets, which were $77.3 million as of December 31, 2025. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which there were none as of December 31, 2025.

Cash flows used in investing activities

For the year ended December 31, 2025, net cash used in investing activities of $1,806.0 million was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $1,347.9 million and net cash paid for acquisitions of $575.7 million paid primarily for the 2025 Williston Basin Acquisition, partially offset by the settlement of derivative contracts of $56.3 million, the receipt of a 2024 contingent consideration earn-out payment of $25.0 million, proceeds from divestitures of certain non-core oil and gas properties of $24.8 million and distributions from our investment in equity securities of $11.6

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million. For the year ended December 31, 2024, net cash used in investing activities of $1,753.8 million was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $1,179.1 million, and net cash paid for acquisitions of $655.0 million. The net cash paid for acquisitions during 2024 primarily related to the Arrangement and included $395.0 million paid to settle Enerplus’ revolving bank credit facility balance, $375.8 million paid to Enerplus shareholders and $102.4 million paid to settle Enerplus’ outstanding equity awards, partially offset by cash acquired in the Arrangement of $239.9 million. Net cash used in investing activities for the year ended December 31, 2024 also included proceeds from divestitures of $60.7 million, the receipt of a 2023 contingent consideration earn-out payment of $25.0 million and distributions from our investment in equity securities of $7.2 million.

Cash flows used in financing activities

For the year ended December 31, 2025, net cash used in financing activities of $82.1 million was primarily attributable to repayments under the Credit Facility of $4,271.0 million, which were offset by borrowings of $3,826.0 million, resulting in net repayments under the Credit Facility of $445.0 million, repayments of the 2026 Senior Notes totaling $401.4 million, payments to repurchase common stock of $364.9 million, dividends paid to shareholders of $317.8 million, payment of debt issuance costs of $29.4 million made in connection with the 2030 Senior Notes, 2033 Senior Notes and the Seventh Amendment to the Amended and Restated Credit Agreement and payments for income tax withholdings on vested equity-based compensation awards of $22.1 million. These uses of cash were partially offset by the issuance of the 2030 Senior Notes and the 2033 Senior Notes of $1,500.0 million. For the year ended December 31, 2024, net cash used in financing activities of $624.5 million was primarily attributable to dividends paid to shareholders of $529.9 million, payments to repurchase common stock of $444.2 million, payments for income tax withholdings on vested equity-based compensation awards of $63.4 million and repayment of the $63.0 million of 3.79% senior unsecured notes assumed from Enerplus. These uses of cash were partially offset by borrowings under the Credit Facility of $3,535.0 million, offset by repayments of $3,090.0 million, resulting in net borrowings under the Credit Facility of $445.0 million, made primarily in connection with the Arrangement and proceeds from the exercise of outstanding warrants of $35.8 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:

Year Ended December 31,

2025

2024

2023

(In thousands)

E&P(1)

$

1,337,565 

$

1,222,507 

$

918,851 

Midstream

18,320 

6,756 

1,990 

Other(2)

1,999 

2,286 

1,493 

Capitalized interest

4,419 

4,905 

4,133 

Total capital expenditures(3)

$

1,362,303 

$

1,236,454 

$

926,467 

__________________ 

(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.

(2)Other capital expenditures include items such as corporate and administrative capital.

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

For the year ended December 31, 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.

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.

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Refer to “Item 8. Financial Statements and Supplementary Data—Note 9—Acquisitions” for additional information.

Our planned 2026 capital expenditures are expected to be approximately $1.35 billion to $1.45 billion. We expect to run four to five operated rigs during the majority of 2026 and plan to TIL approximately 135 to 165 gross operated wells with an average working interest of approximately 75%.

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

Dividends

During the year ended December 31, 2025, we declared base cash dividends of $5.20 per share of common stock, or $302.5 million in aggregate. On February 25, 2026, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 27, 2026 to shareholders of record as of March 12, 2026.

During the year ended December 31, 2024, we declared base-plus-variable cash dividends of $10.15 per share of common stock, or $507.6 million in aggregate.

Future dividend payments will depend on our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that the Board of Directors deems relevant.

Share Repurchase Program

In August 2025, our Board of Directors authorized a new share repurchase program covering up to $1.0 billion of our common stock. At times we have repurchased, and may repurchase in the future, shares pursuant to a Rule 10b5-1 trading plan under the Securities Exchange Act of 1934, as amended, which permits us to repurchase shares at times that may otherwise be prohibited under its insider trading policy. The share repurchase program does not require us to make purchases within a particular time frame.

During the year ended December 31, 2025, we repurchased 3,491,618 shares of common stock at a weighted average price of $104.39 per common share for a total cost of $364.5 million (excluding accrued excise taxes) under our existing and previous share repurchase programs. As of December 31, 2025, there was $952.2 million of capacity remaining under the existing $1.0 billion program.

During the year ended December 31, 2024, we repurchased 3,114,007 shares of common stock at a weighted average price of $142.20 per common share for a total cost of $442.8 million under our previous share repurchase programs.

Critical accounting policies and estimates

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

Method of accounting for oil and gas properties

GAAP provides two alternative methods to account for oil and gas properties known as the successful efforts method and the full cost method. These two accounting methods differ in a number of ways, including the treatment of the costs of exploratory dry holes and geological and geophysical costs which are charged against earnings during the period incurred under the successful efforts method and capitalized within a pool of assets under the full cost method. We account for oil and gas

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properties under the successful efforts method of accounting. See “Item 8. Financial Statements and Supplementary Data—Note 2—Summary of Significant Accounting Policies—Property, Plant and Equipment” for additional information.

Estimated quantities of reserves

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

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

Our estimated net proved reserves and PV-10 were determined using the SEC Price. The SEC Price was $65.34 per Bbl for crude oil and $3.39 per MMBtu for natural gas for the year ended December 31, 2025. We cannot reasonably predict future commodity prices; however, assuming all other factors are held constant, a 10% decrease in the SEC Price for crude oil and natural gas would decrease our estimated net proved reserves by 30.4 MMBoe and decrease the PV-10 by $1.8 billion, and a 10% increase in the SEC Price for crude oil and natural gas would increase our estimated net proved reserves by 24.4 MMBoe and increase the PV-10 by $1.8 billion.

Business combinations

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

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

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

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

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

Impairment of proved oil and gas properties

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

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

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

Impairment of unproved oil and gas properties

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

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

•the remaining amount of unexpired term under our leases;

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

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

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

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

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

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

Impairment of goodwill

Goodwill represents the excess of consideration paid over the fair value of identified tangible and intangible assets. Goodwill and intangible assets with indefinite lives are not amortized, but are evaluated for impairment annually as of October 1 or whenever events or changes in circumstances indicate that the fair value of the reporting unit may have been reduced below its carrying value.

For the purpose of the goodwill impairment test, we first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers

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of fair value of the reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. This evaluation includes, but is not limited to, assessment of macroeconomic trends, capital accessibility, operating income trends and industry conditions, as well as our share performance. If an initial qualitative assessment identifies that it is more likely than not that the carrying value of a reporting unit exceeds its estimated fair value, a quantitative evaluation is performed. The quantitative goodwill impairment assessment involves determining the fair value of the reporting unit and comparing it to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, including goodwill, then an impairment charge would be recorded to write down goodwill to its implied fair value. A reporting unit, for the purpose of the impairment test, is at or below the operating segment level, and constitutes a business for which discrete financial information is available and regularly reviewed by segment management. Our single reportable business segment, which is the exploration and production of crude oil, NGL and natural gas, was the reporting unit that carried our goodwill balance as of December 31, 2024. The fair value of the reporting unit was determined using an income approach analysis based on the Company’s net discounted future cash flows. Significant inputs used are subject to management’s judgment and expertise and include, but are not limited to, future oil and gas production from our reserve report, commodity prices based on future pricing assumptions (adjusted for basis differentials), operating and development costs and a discount rate based on our weighted average cost of capital.

Income taxes

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

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

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