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 continue to control supply and 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; 26 Table of Contents •gathering, transportation and marketing of crude oil, NGL and natural gas in the Williston Basin and other regions in the United States; •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. 27 Table of Contents 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. 28 Table of Contents 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 half of 2026, driven primarily by the escalation of conflict in the Middle East beginning in late February and the resulting disruptions to global oil and natural gas supply following the effective closure of the Strait of Hormuz to most commercial shipping. Continued geopolitical tensions, including the uncertain pace and durability of any diplomatic resolution between the United States and Iran and periodic actual and potential escalations in hostilities, uncertainty around OPEC+ production policy, including the withdrawal of the United Arab Emirates from OPEC+ effective in May 2026 and the withdrawal’s potential to reduce the group’s ability to coordinate global supply, 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 June 30, 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 have 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. During the first half of 2026, higher energy and commodity prices contributed to a renewed rise in U.S. inflation, and the U.S. Federal Reserve held its benchmark interest rate steady. 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 be negatively impacted. 29 Table of Contents Results of Operations Operational and Financial Highlights •Production volumes averaged 286,447 Boepd (58% oil), including average daily crude oil volumes of 165,436 Bopd in the second quarter of 2026. •Capital expenditures (excluding capitalized interest) were $416.7 million in the second quarter of 2026. •Lease operating expenses (“LOE”) were $10.28 per Boe in the second quarter of 2026. •Net cash provided by operating activities was $1,116.2 million and net income was $525.2 million for the second quarter of 2026. Shareholder Return Highlights •Paid $1.30 per share base cash dividend on June 5, 2026. •Repurchased $147.4 million of common stock (excluding accrued excise taxes) in the second quarter of 2026. •Declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on September 4, 2026 to shareholders of record as of August 20, 2026. Net Income (Loss) We had net income of $525.2 million and $633.8 million for the three and six months ended June 30, 2026, respectively, primarily due to increased realized oil prices and production volumes and net impacts from derivative instruments, compared to net losses of $389.9 million and $170.1 million for the three and six months ended June 30, 2025, respectively, primarily due to a non-cash impairment charge on our goodwill recorded during the second quarter of 2025. Additional impacts on net income from increases and decreases in certain 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. Our purchased oil and gas sales are derived from the sale of crude oil 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 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 related purchases and sales with one or more counterparties in contemplation of one another, and these transactions are recorded on a net basis. 30 Table of Contents The following table summarizes our revenues, production and average realized prices for the periods presented: Three Months Ended June 30, 2026 Three Months Ended March 31, 2026 Six Months Ended June 30, 2026 Six Months Ended June 30, 2025 Revenues (in thousands) Crude oil revenues $ 1,414,957 $ 996,296 $ 2,411,253 $ 1,835,064 NGL revenues 44,596 38,222 82,818 89,914 Natural gas revenues 34,731 116,071 150,802 128,712 Purchased oil and gas sales 678,401 515,046 1,193,447 341,916 Total revenues $ 2,172,685 $ 1,665,635 $ 3,838,320 $ 2,395,606 Production data Crude oil (MBbls) 15,055 14,222 29,277 28,098 NGL (MBbls) 4,823 4,413 9,236 9,251 Natural gas (MMcf)(1) 37,129 37,023 74,152 76,063 Oil equivalents (MBoe) 26,067 24,805 50,872 50,026 Average daily production (Boepd) 286,447 275,615 281,061 276,387 Average daily crude oil production (Bopd) 165,436 158,027 161,752 155,235 Average sales prices Crude oil (per Bbl) Average sales price $ 93.99 $ 70.05 $ 82.36 $ 65.31 Effect of derivative settlements(2) (7.05) (0.48) (3.86) 0.47 Average realized price after the effect of derivative settlements(2) $ 86.94 $ 69.57 $ 78.50 $ 65.78 NGL (per Bbl) Average sales price $ 9.25 $ 8.66 $ 8.97 $ 9.72 Effect of derivative settlements(2) — — — — Average realized price after the effect of derivative settlements(2) $ 9.25 $ 8.66 $ 8.97 $ 9.72 Natural gas (per Mcf) Average sales price(1) $ 0.94 $ 3.14 $ 2.03 $ 1.69 Effect of derivative settlements(2) 0.35 (0.32) 0.02 0.01 Average realized price after the effect of derivative settlements(1)(2) $ 1.29 $ 2.82 $ 2.05 $ 1.70 ____________________ (1)For the three months ended June 30, 2026 and March 31, 2026, natural gas production volume from the Marcellus Shale was 10,637 MMcf and 11,745 MMcf, respectively. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $2.10 per Mcf and $6.40 per Mcf for the three months ended June 30, 2026 and March 31, 2026, respectively. For the six months ended June 30, 2026 and June 30, 2025, natural gas production volume from the Marcellus Shale was 22,382 MMcf and 23,384 MMcf, respectively. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $4.36 per Mcf and $3.59 per Mcf for the six months ended June 30, 2026 and June 30, 2025, respectively. (2)The effect of derivative settlements includes the gains or losses on commodity derivatives for contracts ending in the periods presented. Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes. Three months ended June 30, 2026 as compared to three months ended March 31, 2026 Crude oil revenues. Our crude oil revenues increased $418.7 million to $1,415.0 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The increase was primarily due to higher crude oil average realized prices quarter over quarter resulting in a $340.4 million increase, coupled with an increase of $78.3 million due to higher crude oil production volumes sold quarter over quarter. Average crude oil sales prices, without derivative settlements, increased by $23.94 per barrel quarter over quarter to an average of $93.99 per barrel for the three months ended June 30, 2026 primarily due to an increase in the average NYMEX WTI quarter over quarter. 31 Table of Contents NGL revenues. Our NGL revenues increased $6.4 million to $44.6 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The increase was primarily due to higher NGL production volumes sold quarter over quarter resulting in a $3.8 million increase, coupled with an increase of $2.6 million due to higher average realized NGL prices quarter over quarter. Average NGL sales prices, without derivative settlements, increased by $0.59 per barrel quarter over quarter to an average of $9.25 per barrel for the three months ended June 30, 2026 primarily due to increases in the corresponding NGL product index prices for butane, pentane and propane. Natural gas revenues. Our natural gas revenues decreased $81.3 million to $34.7 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The decrease was primarily due to lower natural gas average realized prices quarter over quarter resulting in an $81.4 million decrease quarter over quarter. Average natural gas sales prices, without derivative settlements, decreased by $2.20 per Mcf quarter over quarter to $0.94 per Mcf for the three months ended June 30, 2026 primarily due to the seasonality of warmer weather resulting in lower index prices quarter over quarter. Purchased oil and gas sales. Purchased oil and gas sales increased $163.4 million to $678.4 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. This increase was primarily due to higher crude oil prices quarter over quarter, partially offset by a decrease in the volume of crude oil purchased and subsequently sold quarter over quarter. Six months ended June 30, 2026 as compared to six months ended June 30, 2025 Crude oil revenues. Our crude oil revenues increased $576.2 million to $2,411.3 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The increase was primarily due to higher crude oil average realized prices period over period resulting in a $479.1 million increase, coupled with an increase of $97.1 million due to higher crude oil production volumes sold period over period. Average crude oil sales prices, without derivative settlements, increased by $17.05 per barrel period over period to an average of $82.36 per barrel for the six months ended June 30, 2026 primarily due to an increase in the average NYMEX WTI period over period. NGL revenues. Our NGL revenues decreased $7.1 million to $82.8 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The decrease was primarily due to lower average realized NGL prices period over period resulting in a $7.0 million decrease period over period. Average NGL sales prices, without derivative settlements, decreased by $0.75 per barrel period over period to an average of $8.97 per barrel for the six months ended June 30, 2026 primarily due to decreases in the corresponding NGL product index prices. Natural gas revenues. Our natural gas revenues increased $22.1 million to $150.8 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The increase was primarily due to higher natural gas average realized prices period over period resulting in a $26.0 million increase, partially offset by a decrease of $3.9 million due to lower natural gas production volumes sold period over period. Average natural gas sales prices, without derivative settlements, increased by $0.34 per Mcf period over period to $2.03 per Mcf for the six months ended June 30, 2026 primarily due to increases in the corresponding natural gas index prices period over period. Purchased oil and gas sales. Purchased oil and gas sales increased $851.5 million to $1,193.4 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold period over period, coupled with increased crude oil prices over the same period. 32 Table of Contents Expenses and other income (expense) The following table summarizes our operating expenses and other income (expense) for the periods presented: Three Months Ended June 30, 2026 Three Months Ended March 31, 2026 Six Months Ended June 30, 2026 Six Months Ended June 30, 2025 (In thousands, except per Boe of production data) Operating expenses Lease operating expenses $ 267,839 $ 244,909 $ 512,748 $ 490,040 Gathering, processing and transportation expenses 62,765 67,018 129,783 147,415 Purchased oil and gas expenses 671,661 509,832 1,181,493 343,113 Production taxes 125,878 86,711 212,589 143,607 Depreciation, depletion and amortization 409,237 384,215 793,452 726,806 General and administrative expenses 29,894 37,508 67,402 70,917 Impairment and exploration 2,687 2,563 5,250 543,923 Total operating expenses 1,569,961 1,332,756 2,902,717 2,465,821 Gain (loss) on sale of assets, net (4) 343 339 4,993 Operating income (loss) 602,720 333,222 935,942 (65,222) Other income (expense) Net gain (loss) on derivative instruments 107,866 (241,471) (133,605) 61,950 Net gain (loss) from investment in equity securities 1,143 22,829 23,972 (5,862) Interest expense, net of capitalized interest (26,663) (26,596) (53,259) (34,606) Loss on debt extinguishment — — — (3,494) Other income, net 2,186 6,329 8,515 4,546 Total other income (expense), net 84,532 (238,909) (154,377) 22,534 Income (loss) before income taxes 687,252 94,313 781,565 (42,688) Income tax benefit (expense) (162,066) 14,295 (147,771) (127,380) Net income (loss) $ 525,186 $ 108,608 $ 633,794 $ (170,068) Costs and expenses (per Boe of production) Lease operating expenses $ 10.28 $ 9.87 $ 10.08 $ 9.80 Gathering, processing and transportation expenses 2.41 2.70 2.55 2.95 Production taxes 4.83 3.50 4.18 2.87 Three months ended June 30, 2026 as compared to three months ended March 31, 2026 Lease operating expenses. LOE increased $22.9 million to $267.8 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The increase was primarily due to higher variable costs of $10.0 million, higher fixed costs of $9.6 million and higher workover costs of $6.6 million, partially offset by a decrease in operating costs from our non-operated assets of $3.3 million quarter over quarter. The same factors contributed to an increase in LOE per Boe, which increased $0.41 per Boe quarter over quarter to $10.28 per Boe for the three months ended June 30, 2026. Gathering, processing and transportation expenses. GPT expenses decreased $4.3 million to $62.8 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The decrease was primarily due to an $8.8 million change in the non-cash valuation adjustment on our cumulative pipeline imbalance position, partially offset by an increase in crude oil production volumes transported of $3.1 million and a net increase in natural gas and NGL gathering, processing and transportation fees of $1.4 million quarter over quarter. Excluding the non-cash valuation adjustment, GPT expenses increased $0.04 per Boe quarter over quarter to $2.83 per Boe for the three months ended June 30, 2026 primarily due to higher natural gas and NGL gathering, processing and transportation fees. Purchased oil and gas expenses. Purchased oil and gas expenses increased $161.8 million to $671.7 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. This increase was primarily due to higher crude oil prices quarter over quarter, partially offset by a decrease in the volume of crude oil purchased and subsequently sold quarter over quarter. 33 Table of Contents Production taxes. Production taxes increased $39.2 million to $125.9 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026 primarily due to higher crude oil revenues quarter over quarter. The production tax rate as a percentage of crude oil, NGL and natural gas revenues of 8.4% for the three months ended June 30, 2026 increased from 7.5% for the three months ended March 31, 2026 primarily due to higher crude oil revenues quarter over quarter coupled with natural gas comprising a smaller percentage of total sales relative to the prior period. Depreciation, depletion and amortization. DD&A expense increased $25.0 million to $409.2 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The increase was primarily driven by higher production volumes of $21.2 million, coupled with an increase in accretion expense of $3.8 million related to plugging and abandonment charges. General and administrative expenses. G&A expenses decreased $7.6 million to $29.9 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The decrease was primarily attributable to a decrease in equity-based compensation expenses of $3.7 million due to the impact of our stock price on the fair value of our liability-based awards, coupled with a decrease of $2.5 million due to lower current expected credit losses and various cost decreases related to other G&A expenses of $1.4 million quarter over quarter. Derivative instruments. We recorded a $107.9 million net gain on derivative instruments for the three months ended June 30, 2026, which included an unrealized gain of $201.0 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 on settled commodity derivative contracts of $93.1 million. During the three months ended March 31, 2026, we recorded a $241.5 million net loss on derivative instruments, which included an unrealized loss of $223.0 million related to the change in fair value of our commodity derivative contracts primarily driven by an upward shift in the futures curve for forecasted commodity prices, coupled with a realized loss on settled commodity derivative contracts of $18.5 million. Investment in equity securities. We recorded a $1.1 million net gain related to our investment in Energy Transfer LP (“Energy Transfer”) for the three months ended June 30, 2026, which included a gain of $2.4 million for a cash distribution from Energy Transfer during the quarter, partially offset by an unrealized loss of $1.3 million as a result of a decrease in the fair value of the investment during the quarter. During the three months ended March 31, 2026, we recorded a $22.8 million net gain related to our investment in Energy Transfer, which included an unrealized gain of $20.4 million as a result of an increase in the fair value of the investment during the quarter, coupled with a gain of $2.4 million for a cash distribution from Energy Transfer during the quarter. Income tax benefit (expense). Our effective tax rate was recorded at 23.6% and (15.2)% of pre-tax income for the three months ended June 30, 2026 and March 31, 2026, respectively. The effective tax rate for the three months ended June 30, 2026 was higher than the statutory federal rate of 21% primarily as a result of state income taxes. The effective tax rate for the three months ended March 31, 2026 was lower than the statutory federal rate of 21% primarily as a result of the identification of an error in the tax provision for the three and six months ended June 30, 2025 pertaining to the impact of goodwill impairment on our deferred taxes on unremitted earnings, which resulted in an additional income tax benefit of $41.8 million in the first quarter of 2026, with a corresponding decrease to deferred tax liabilities. Six months ended June 30, 2026 as compared to six months ended June 30, 2025 Lease operating expenses. LOE increased $22.7 million to $512.7 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The increase was primarily due to increased activity and operating costs from our non-operated assets of $25.7 million, coupled with higher variable costs of $4.7 million, partially offset by lower fixed costs of $7.5 million. The same factors contributed to an increase in LOE per Boe, which increased $0.28 per Boe period over period to $10.08 per Boe for the six months ended June 30, 2026. Gathering, processing and transportation expenses. GPT expenses decreased $17.6 million to $129.8 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The decrease was primarily due to a $15.1 million change in the non-cash valuation adjustment on our cumulative pipeline imbalance position, coupled with lower natural gas and NGL gathering, processing and transportation fees of $7.4 million period over period, partially offset by an increase in crude oil production volumes transported of $4.3 million period over period. Excluding the non-cash valuation adjustment, GPT expenses decreased $0.10 per Boe period over period to $2.81 per Boe for the six months ended June 30, 2026 primarily due to lower natural gas and NGL gathering, processing and transportation fees. Purchased oil and gas expenses. Purchased oil and gas expenses increased $838.4 million to $1,181.5 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold period over period, coupled with increased crude oil prices over the same period. 34 Table of Contents Production taxes. Production taxes increased $69.0 million to $212.6 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The increase was primarily due to higher crude oil revenues period over period, coupled with a $19.4 million decrease in refunds period over period related to certain North Dakota wells receiving an extraction tax exemption. The production tax rate as a percentage of crude oil, NGL and natural gas revenues increased from 7.0% for the six months ended June 30, 2025 to 8.0% for the six months ended June 30, 2026 primarily due to increased crude oil revenues and fewer wells qualifying for the extraction tax exemption relative to the prior period. Depreciation, depletion and amortization. DD&A expense increased $66.6 million to $793.5 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The increase was primarily driven by $51.3 million of additional depletion expense due to a higher depletion rate period over period, coupled with increased production volumes of $17.7 million period over period, partially offset by a decrease in accretion expense of $1.9 million. The depletion rate increased $1.11 per Boe period over period to $15.24 per Boe for the six months ended June 30, 2026 primarily due to a decrease in proved developed reserves period over period. General and administrative expenses. G&A expenses decreased $3.5 million to $67.4 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The decrease was primarily attributable to merger-related costs of $8.1 million incurred during 2025 related to the arrangement agreement we entered into to acquire Enerplus Corporation during 2024, coupled with a decrease of $3.9 million primarily attributable to various cost savings related to other G&A expenses, partially offset by an increase of $5.8 million in equity-based compensation costs and higher current expected credit losses of $2.7 million period over period. Impairment and exploration. There were no significant impairment charges during the six months ended June 30, 2026. As a result of a decrease in the price of our common stock during the six months ended June 30, 2025, which was impacted by a decline in crude oil and natural gas prices over that same period, we recorded an impairment charge on our goodwill of $539.3 million for the six months ended June 30, 2025. Gain (loss) on sale of assets, net. During the six months ended June 30, 2025, we recorded a net gain on sale of assets of $5.0 million, primarily related to the divestiture of certain non-core oil and gas properties. Derivative instruments. During the six months ended June 30, 2026, we recorded a $133.6 million net loss on derivative instruments, which included a realized loss of $111.6 million on settled commodity derivative contracts, coupled with an unrealized loss of $22.0 million related to the change in fair value of our commodity derivative contracts primarily driven by an upward shift in the futures curve for forecasted oil commodity prices. During the six months ended June 30, 2025, we recorded a $62.0 million net gain on derivative instruments, which was comprised of a net gain of $61.0 million associated with our commodity derivative contracts and an unrealized gain of $0.9 million associated with a contract that includes contingent consideration. The net gain of $61.0 million on commodity derivative contracts included an unrealized gain of $47.2 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices and a realized gain of $13.8 million on settled commodity derivative contracts. Investment in equity securities. We recorded a $24.0 million gain related to our investment in Energy Transfer for the six months ended June 30, 2026, which included an unrealized gain of $19.1 million as a result of an increase in the fair value of the investment during the period, coupled with a gain of $4.9 million for a cash distribution from Energy Transfer during the period. For the six months ended June 30, 2025, we recorded a net loss of $5.9 million related to our investment in Energy Transfer, which included an unrealized loss of $10.6 million as a result of a decrease in the fair value of the investment during the period, partially offset by a gain of $4.7 million for a cash distribution from Energy Transfer during the period. Interest expense, net of capitalized interest. Interest expense increased $18.7 million to $53.3 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The increase is primarily due to additional interest expense period over period on our senior unsecured notes of $35.0 million as a result of the issuance of the 2033 Senior Notes (defined below) and the 2030 Senior Notes (defined below) during 2025. This increase was partially offset by an $8.6 million decrease in interest expense on the Credit Facility (defined below) period over period and a $7.7 million decrease resulting from the repayment of the 2026 Senior Notes (defined below) during March 2025. For the six months ended June 30, 2026, the weighted average borrowings outstanding under the Credit Facility were $2.2 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.50%. During the six months ended June 30, 2025, the weighted average borrowings outstanding under the Credit Facility were $310.3 million, and the weighted average interest rate incurred on the outstanding borrowings was 6.47%. 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 6.375% senior unsecured notes outstanding due June 1, 2026 (the “2026 Senior Notes”), resulting in a loss on debt extinguishment of $3.5 million for the six months ended June 30, 2025. The loss primarily included the write-off of unamortized debt issuance costs of $2.1 million and a premium paid to redeem a portion of the 2026 Senior Notes of $1.1 million. 35 Table of Contents Income tax benefit (expense). Our effective tax rate was recorded at 18.9% of pre-tax income and (298.4)% of pre-tax loss for the six months ended June 30, 2026 and 2025, respectively. Our effective tax rate for the six months ended June 30, 2026 was lower than the statutory federal rate of 21% primarily as a result of the identification of an error in the tax provision for the three and six months ended June 30, 2025 pertaining to the impact of goodwill impairment on our deferred taxes on unremitted earnings. As a result, we recognized an additional income tax benefit of $41.8 million during the six months ended June 30, 2026, with a corresponding decrease to deferred tax liabilities. The effective tax rate for the six months ended June 30, 2025 was lower than the statutory federal rate of 21% primarily as a result of the impact of the goodwill impairment charge recorded during the same period. Liquidity and Capital Resources As of June 30, 2026, we had $2,581.2 million of liquidity available, including $1,969.6 million of aggregate unused borrowing capacity available under the Credit Facility (defined below) and $611.6 million in cash and cash equivalents. During the six months ended June 30, 2026, our primary sources of liquidity were from cash flows from operations, available borrowing capacity under the Credit Facility, and cash on hand. During the same period, our primary liquidity requirements were capital expenditures for the development of oil and gas properties, dividend payments, share repurchases, and working capital requirements. 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. Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to our long-term debt, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, payment of income taxes, obligations associated with outstanding commodity derivative contracts that settle in a loss position and obligations associated with our leases. In addition, we have announced a return of capital plan pursuant to which we intend to return capital to stockholders through dividend payouts, supplemented by opportunistic share repurchases. On a quarterly basis, we pay a commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter. Capital availability 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 uncertain path of future interest rates creates additional economic uncertainty. During the first half of 2026, higher energy and commodity prices contributed to a renewed rise in U.S. inflation, and the U.S. Federal Reserve held its benchmark interest rate steady. Although we are unable to predict future interest rates, any resulting 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. Commodity derivative contracts. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the impact of changes in crude oil, NGL and natural gas prices on our production, which mitigates our exposure to crude oil, NGL and natural gas price declines; however, these transactions may also limit our cash flow in periods of rising crude oil, NGL and natural gas prices. See Note 6—Derivative Instruments and “Item 3. Quantitative and Qualitative Disclosures about Market Risk” for additional information. 36 Table of Contents Commitments. 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 $553.3 million as of June 30, 2026. We believe that for the substantial majority of these agreements our future production will be adequate to meet our delivery commitments or that we will be able to purchase sufficient volumes of crude oil, NGL and natural gas from third parties to satisfy our minimum volume commitments. See “Item 1. Financial Statements (Unaudited)—Note 16—Commitments and Contingencies” and “Item 8. Financial Statements and Supplementary Data—Note 20—Commitments and Contingencies” in our 2025 Annual Report for additional information on our volume delivery 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 June 30, 2026, 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 $30.4 million of outstanding letters of credit, resulting in an unused borrowing base capacity of $1,969.6 million as of June 30, 2026. Additionally, we are permitted to incur term loans in addition to the revolving loans provided under the Credit Facility. The semi-annual redetermination of our borrowing base was completed in May 2026, which reaffirmed the borrowing base and the aggregate elected commitment at $2.75 billion and $2.0 billion, respectively. The next redetermination is scheduled for October 2026. For the six months ended June 30, 2026, the weighted average interest rate incurred on borrowings under the Credit Facility was 7.50% compared to 6.47% for the six months ended June 30, 2025. We were in compliance with the financial covenants in the Credit Facility at June 30, 2026. See “Item 1. Financial Statements (Unaudited)—Note 10—Long-Term Debt” for additional information. Senior unsecured notes. As of June 30, 2026, we had $750.0 million of 6.000% senior unsecured notes (the “2030 Senior Notes”) that mature on October 1, 2030 and $750.0 million of 6.750% senior unsecured notes (the “2033 Senior Notes”) that mature on March 15, 2033. Interest on the 2030 Senior Notes is payable semi-annually on April 1 and October 1 of each year, and interest on the 2033 Senior Notes is payable semi-annually on March 15 and September 15 of each year. See “Item 1. Financial Statements (Unaudited)—Note 10—Long-Term Debt” for additional information. Cash Flows Our cash flows for the six months ended June 30, 2026 and 2025 are presented below: Six Months Ended June 30, 2026 2025 (In thousands) Net cash provided by operating activities $ 1,623,621 $ 1,076,703 Net cash used in investing activities (830,575) (677,782) Net cash used in financing activities (371,009) (395,384) Increase in cash and cash equivalents $ 422,037 $ 3,537 Cash flows provided by operating activities Our net cash flows provided by operating activities are primarily impacted by commodity prices, production volumes and operating costs. Net cash provided by operating activities was $1,623.6 million for the six months ended June 30, 2026. The increase in net cash provided by operating activities of $546.9 million as compared to the six months ended June 30, 2025 was primarily due to an increase in crude oil and natural gas revenues primarily due to higher crude oil and natural gas average realized prices and working capital changes, partially offset by increases in our production taxes and LOE. See “Results of Operations” above for additional information. Working Capital. Our working capital is primarily impacted by the factors discussed above, coupled with the timing of cash receipts and disbursements. Changes in working capital (as reflected in the Condensed Consolidated Statements of Cash Flows) increased net cash flows from operating activities by $59.1 million during the six months ended June 30, 2026 and decreased net cash flows from operating activities by $12.5 million during the six months ended June 30, 2025. Changes in working capital associated with our capital expenditure activities and settlements of outstanding commodity derivative instruments impact our cash flows from investing activities. 37 Table of Contents 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 $1,969.6 million at June 30, 2026, and excludes current hedge assets, which were $49.6 million at June 30, 2026. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, of which there were $16.1 million at June 30, 2026. Cash flows used in investing activities For the six months ended June 30, 2026, net cash used in investing activities of $830.6 million was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $755.5 million, settlement of derivative contracts of $88.8 million and acquisitions and leasehold costs of $8.7 million, partially offset by the receipt of the 2025 contingent consideration earn-out payment of $25.0 million. For the six months ended June 30, 2025, net cash used in investing activities of $677.8 million was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $704.4 million and $26.2 million paid primarily for acreage in the Williston Basin, partially offset by the receipt of the 2024 contingent consideration earn-out payment of $25.0 million and the settlement of derivative contracts of $14.1 million. Cash flows used in financing activities For the six months ended June 30, 2026, the net cash used in financing activities of $371.0 million was primarily attributable to payments to repurchase our common stock of $217.7 million, dividends paid to shareholders of $147.7 million, repayments under the Credit Facility of $85.0 million, offset by borrowings under the Credit Facility of $85.0 million. For the six months ended June 30, 2025, net cash used in financing activities of $395.4 million was primarily attributable to the repayments of the 2026 Senior Notes totaling $401.4 million, payments to repurchase our common stock of $274.0 million, dividends paid to shareholders of $168.8 million, payments for income tax withholdings on vested equity-based compensation awards of $21.8 million, payment of debt issuance costs of $13.4 million made primarily in connection with the issuance of the 2033 Senior Notes and repayments under the Credit Facility of $2,700.0 million, partially offset by borrowings under the Credit Facility of $2,435.0 million, resulting in net repayments under the Credit Facility of $265.0 million. These uses of cash were partially offset by proceeds from the issuance of the 2033 Senior Notes of $750.0 million. Capital Expenditures Our capital expenditures are summarized in the following table for the periods presented: Three Months Ended Six Months Ended March 31, 2026 June 30, 2026 June 30, 2026 (In thousands) E&P(1) $ 330,571 $ 402,316 $ 732,887 Midstream 14,203 14,241 28,444 Other(2) 113 191 304 Capitalized interest 933 899 1,832 Total capital expenditures(3) $ 345,820 $ 417,647 $ 763,467 __________________ (1)E&P capital expenditures include approximately $0.7 million and $3.7 million of non-operated capital expenditures related to certain non-operated divested assets that were reimbursable for the three and six months ended June 30, 2026, 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 condensed 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. Acquisitions Acquisitions and leasehold costs were $3.7 million and $8.7 million for the three and six months ended June 30, 2026, respectively. 38 Table of Contents Dividends On August 5, 2026, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on September 4, 2026 to shareholders of record as of August 20, 2026. See “Item 1. Financial Statements (Unaudited)—Note 14—Stockholders’ Equity” for additional information. See “Part I. Item 1.—Business—Business Strategy” in our 2025 Annual Report for additional information regarding our strategy on future dividend payments. Future dividend payments will depend on the Company’s earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that the Board of Directors deems relevant. Share Repurchase Program During the six months ended June 30, 2026, we repurchased 1,663,410 shares of common stock at a weighted average price of $131.14 per common share for a total cost of $218.1 million under our $1.0 billion share repurchase program authorized by our Board of Directors in August 2025. As of June 30, 2026, there was $734.0 million of capacity remaining under this share repurchase program. During the six months ended June 30, 2025, we repurchased 2,600,117 shares of common stock under a previous share repurchase program at a weighted average price of $104.41 per common share for a total cost of $271.5 million. Fair Value of Financial Instruments See “Item 1. Financial Statements (Unaudited)—Note 5—Fair Value Measurements” for additional information on our derivative instruments and their related fair value measurements. See also “Item 3. Quantitative and Qualitative Disclosures about Market Risk” below. Critical Accounting Policies and Estimates There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2025 Annual Report.