# NORTHERN OIL & GAS, INC. (NOG) Informational only - not investment advice. CIK: 0001104485 SIC: 1311 Crude Petroleum & Natural Gas SIC breadcrumb: [Mining](/division/B/) > [SIC Major Group 13](/major-group/13/) > [SIC 1311 Crude Petroleum & Natural Gas](/industry/1311/) Latest 10-K filed: 2026-02-26 SEC page: https://www.sec.gov/edgar/browse/?CIK=1104485 Filing source: https://www.sec.gov/Archives/edgar/data/1104485/000110448526000008/nog-20251231.htm ## Selected Fundamentals | Metric | Value | Unit | FY | Filed | | --- | ---: | --- | ---: | --- | | Revenue | 2475723000 | USD | 2025 | 2026-02-26 | | Net income | 38761000 | USD | 2025 | 2026-02-26 | | Assets | 5409375000 | USD | 2025 | 2026-02-26 | ## Financials Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-26. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001104485.json. Derived margins are computed from the extracted annual SEC facts. | Metric | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Revenue | 144,903,496 | 209,320,000 | 678,924,000 | 472,402,000 | 552,210,000 | 496,899,000 | 1,570,535,000 | 2,166,259,000 | 2,225,728,000 | 2,475,723,000 | | Net income | -293,493,708 | -9,194,000 | 143,689,000 | -76,318,000 | -906,041,000 | 6,361,000 | 773,237,000 | 922,969,000 | 520,308,000 | 38,761,000 | | Operating income | -229,304,855 | 60,495,000 | 432,628,000 | 55,509,000 | -841,243,000 | 77,959,000 | 853,192,000 | 1,121,862,000 | 837,831,000 | 245,847,000 | | Diluted EPS | -4.80 | -0.15 | 6.07 | -2.00 | -21.55 | -0.13 | 8.92 | 10.03 | 5.14 | 0.39 | | Assets | 431,532,961 | 632,253,679 | 1,503,645,000 | 1,905,465,000 | 872,089,000 | 1,522,866,000 | 2,875,178,000 | 4,484,255,000 | 5,603,822,000 | 5,409,375,000 | | Liabilities | 918,954,629 | 1,123,094,229 | 1,073,780,000 | 1,346,822,000 | 1,095,393,000 | 1,307,731,000 | 2,129,917,000 | 2,436,578,000 | 3,283,387,000 | 3,283,034,000 | | Stockholders' equity | -487,421,668 | -490,840,550 | 429,865,000 | 558,643,000 | -223,304,000 | 215,135,000 | 745,260,000 | 2,047,676,000 | 2,320,435,000 | 2,126,341,000 | | Cash and cash equivalents | 6,486,098 | 102,183,191 | 2,358,000 | 16,068,000 | 1,428,000 | 9,519,000 | 2,528,000 | 8,195,000 | 8,933,000 | 14,299,000 | | Net margin | | -4.39% | 21.16% | -16.16% | | 1.28% | 49.23% | 42.61% | 23.38% | 1.57% | | Operating margin | | 28.90% | 63.72% | 11.75% | | 15.69% | 54.32% | 51.79% | 37.64% | 9.93% | ## Quarterly Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-04-29. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001104485.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. | Quarter | End date | Revenue | Net income | Diluted EPS | Method | | --- | --- | ---: | ---: | ---: | --- | | 2022-Q2 | 2022-06-30 | | | 2.74 | reported discrete quarter | | 2022-Q3 | 2022-09-30 | | | 6.77 | reported discrete quarter | | 2023-Q2 | 2023-03-31 | | 340,191,000 | | reported discrete quarter | | 2023-Q1 | 2023-03-31 | | | 3.98 | reported discrete quarter | | 2023-Q2 | 2023-06-30 | 476,554,000 | | 1.88 | reported discrete quarter | | 2023-Q3 | 2023-06-30 | | 167,815,000 | | reported discrete quarter | | 2023-Q3 | 2023-09-30 | 313,973,000 | | 0.28 | reported discrete quarter | | 2023-Q4 | 2023-12-31 | 793,517,000 | 388,853,000 | | derived Q4 = FY annual - nine-month YTD | | 2024-Q1 | 2024-03-31 | 396,348,000 | 11,606,000 | 0.11 | reported discrete quarter | | 2024-Q2 | 2024-03-31 | | 11,606,000 | | reported discrete quarter | | 2024-Q3 | 2024-06-30 | | 138,556,000 | | reported discrete quarter | | 2024-Q2 | 2024-06-30 | 560,766,000 | | 1.36 | reported discrete quarter | | 2024-Q3 | 2024-09-30 | 753,638,000 | | 2.96 | reported discrete quarter | | 2024-Q4 | 2024-12-31 | 514,977,000 | 71,699,000 | | derived Q4 = FY annual - nine-month YTD | | 2025-Q1 | 2025-03-31 | 602,098,000 | 138,982,000 | 1.39 | reported discrete quarter | | 2025-Q2 | 2025-03-31 | | 138,982,000 | | reported discrete quarter | | 2025-Q3 | 2025-06-30 | | 99,585,000 | | reported discrete quarter | | 2025-Q2 | 2025-06-30 | 706,809,000 | | 1.00 | reported discrete quarter | | 2025-Q3 | 2025-09-30 | 556,637,000 | | -1.33 | reported discrete quarter | | 2025-Q4 | 2025-12-31 | 610,178,000 | -70,732,000 | | derived Q4 = FY annual - nine-month YTD | | 2026-Q1 | 2026-03-31 | 5,029,000 | -522,847,000 | -5.31 | reported discrete quarter | ## Macro Cross-References - [CPIAUCSL](/indicator/CPIAUCSL/): Consumer Price Index for All Urban Consumers: All Items in U.S. City Average - [UNRATE](/indicator/UNRATE/): Unemployment Rate - [FEDFUNDS](/indicator/FEDFUNDS/): Federal Funds Effective Rate - [CES0500000003](/indicator/CES0500000003/): Average Hourly Earnings of All Employees, Total Private - [DFEDTARU](/indicator/DFEDTARU/): Federal Funds Target Range - Upper Limit - [DFEDTARL](/indicator/DFEDTARL/): Federal Funds Target Range - Lower Limit - [DGS3MO](/indicator/DGS3MO/): Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity - [DGS2](/indicator/DGS2/): Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity - [DGS10](/indicator/DGS10/): Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity - [DGS30](/indicator/DGS30/): Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity - [T10Y2Y](/indicator/T10Y2Y/): 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity - [CPILFESL](/indicator/CPILFESL/): Consumer Price Index for All Urban Consumers: All Items Less Food and Energy - [CPIUFDSL](/indicator/CPIUFDSL/): Consumer Price Index for All Urban Consumers: Food - [CPIENGSL](/indicator/CPIENGSL/): Consumer Price Index for All Urban Consumers: Energy - [CUSR0000SAH1](/indicator/CUSR0000SAH1/): Consumer Price Index for All Urban Consumers: Shelter - [PCEPI](/indicator/PCEPI/): Personal Consumption Expenditures: Chain-type Price Index - [PCEPILFE](/indicator/PCEPILFE/): Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index - [PPIACO](/indicator/PPIACO/): Producer Price Index by Commodity: All Commodities - [T10YIE](/indicator/T10YIE/): 10-Year Breakeven Inflation Rate - [U6RATE](/indicator/U6RATE/): Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons - [PAYEMS](/indicator/PAYEMS/): All Employees, Total Nonfarm - [CIVPART](/indicator/CIVPART/): Labor Force Participation Rate - [EMRATIO](/indicator/EMRATIO/): Employment-Population Ratio - [UNEMPLOY](/indicator/UNEMPLOY/): Unemployed - [CE16OV](/indicator/CE16OV/): Employment Level - [ICSA](/indicator/ICSA/): Initial Claims - [JTSJOL](/indicator/JTSJOL/): Job Openings: Total Nonfarm - [JTSQUR](/indicator/JTSQUR/): Quits: Total Nonfarm - [GDPC1](/indicator/GDPC1/): Real Gross Domestic Product - [A191RL1Q225SBEA](/indicator/A191RL1Q225SBEA/): Real Gross Domestic Product: Percent Change from Preceding Period - [INDPRO](/indicator/INDPRO/): Industrial Production: Total Index - [TCU](/indicator/TCU/): Capacity Utilization: Total Index - [HOUST](/indicator/HOUST/): New Privately-Owned Housing Units Started: Total Units - [PERMIT](/indicator/PERMIT/): New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units - [RSAFS](/indicator/RSAFS/): Advance Retail Sales: Retail Trade - [PCE](/indicator/PCE/): Personal Consumption Expenditures - [DSPIC96](/indicator/DSPIC96/): Real Disposable Personal Income - [PSAVERT](/indicator/PSAVERT/): Personal Saving Rate - [M2SL](/indicator/M2SL/): M2 - [BOPGSTB](/indicator/BOPGSTB/): U.S. International Trade in Goods and Services: Balance - [MSPUS](/indicator/MSPUS/): Median Sales Price of Houses Sold for the United States - [HSN1F](/indicator/HSN1F/): New One Family Houses Sold: United States - [RHORUSQ156N](/indicator/RHORUSQ156N/): Homeownership Rate in the United States - [TTLCONS](/indicator/TTLCONS/): Total Construction Spending: Total Construction in the United States - [RRVRUSQ156N](/indicator/RRVRUSQ156N/): Rental Vacancy Rate in the United States - [TOTALSL](/indicator/TOTALSL/): Total Consumer Credit Owned and Securitized - [REVOLSL](/indicator/REVOLSL/): Revolving Consumer Credit Owned and Securitized - [DRCCLACBS](/indicator/DRCCLACBS/): Delinquency Rate on Credit Card Loans, All Commercial Banks - [GDP](/indicator/GDP/): Gross Domestic Product - [GPDI](/indicator/GPDI/): Gross Private Domestic Investment - [GCE](/indicator/GCE/): Government Consumption Expenditures and Gross Investment - [PCEC](/indicator/PCEC/): Personal Consumption Expenditures - [NETEXP](/indicator/NETEXP/): Net Exports of Goods and Services - [GFDEBTN](/indicator/GFDEBTN/): Federal Debt: Total Public Debt - [GFDEGDQ188S](/indicator/GFDEGDQ188S/): Federal Debt: Total Public Debt as Percent of Gross Domestic Product - [FYFSD](/indicator/FYFSD/): Federal Surplus or Deficit - [FGRECPT](/indicator/FGRECPT/): Federal Government Current Receipts - [FGEXPND](/indicator/FGEXPND/): Federal Government: Current Expenditures - [MANEMP](/indicator/MANEMP/): All Employees, Manufacturing - [USCONS](/indicator/USCONS/): All Employees, Construction - [USTRADE](/indicator/USTRADE/): All Employees, Retail Trade - [USFIRE](/indicator/USFIRE/): All Employees, Financial Activities - [USGOVT](/indicator/USGOVT/): All Employees, Government - [AWHAETP](/indicator/AWHAETP/): Average Weekly Hours of All Employees, Total Private - [DGORDER](/indicator/DGORDER/): Manufacturers' New Orders: Durable Goods - [NEWORDER](/indicator/NEWORDER/): Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft - [BUSINV](/indicator/BUSINV/): Total Business Inventories - [EXPGS](/indicator/EXPGS/): Exports of Goods and Services - [IMPGS](/indicator/IMPGS/): Imports of Goods and Services - [IR](/indicator/IR/): Import Price Index (End Use): All Commodities - [PPIFIS](/indicator/PPIFIS/): Producer Price Index by Commodity: Final Demand ## Latest quarter (10-Q) Latest 10-Q source: https://www.sec.gov/Archives/edgar/data/1104485/000110448526000020/nog-20260331.htm Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high Filing date: 2026-04-29 Report date: 2026-03-31 Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Cautionary Statement Concerning Forward-Looking Statements We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords. From time to time, our management or persons acting on our behalf may make forward-looking statements to inform existing and potential security holders about our company. All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations, industry conditions, indebtedness covenant compliance, capital expenditures, production, cash flow, borrowing base under our Revolving Credit Facility, our intention or ability to pay or increase dividends on our capital stock, and impairment are forward-looking statements.  When used in this report, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes.  Items contemplating or making assumptions about actual or potential future production, sales, market size, collaborations, cash flows, and trends or operating results also constitute such forward-looking statements. Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following:  •changes in crude oil and natural gas prices, the pace of drilling and completions activity on our current properties and properties pending acquisition; •infrastructure constraints and related factors affecting our properties; •general economic or industry conditions, whether internationally, nationally and/or in the communities in which our company conducts business, including any future economic downturn, cost inflation, supply chain disruptions, the impact of continued or further inflation, disruption in the financial markets, changes in the interest rate environment and actions taken by OPEC and other oil producing countries as it pertains to the global supply and demand of, and prices for, crude oil, natural gas and NGLs; •ongoing legal disputes over, and potential shutdown of, the Dakota Access Pipeline; •our ability to identify and consummate additional development opportunities and potential or pending acquisition transactions, the projected capital efficiency savings and other operating efficiencies and synergies resulting from our acquisition transactions, integration and benefits of property acquisitions, or the effects of such acquisitions on our company’s cash position and levels of indebtedness; •changes in our reserves estimates or the value thereof; •disruption to our company’s business due to acquisitions and other significant transactions; •changes in local, state, and federal laws, regulations or policies that may affect our business or our industry (such as the effects of tax law changes, and changes in environmental, health, and safety regulation and regulations addressing climate change, and trade policy and tariffs); •conditions of the securities markets; •risks associated with our Convertible Notes, including the potential impact that the Convertible Notes may have on our financial position and liquidity, potential dilution, and that provisions of the Convertible Notes could delay or prevent a beneficial takeover of our company; •the potential impact of the capped call transactions undertaken in tandem with the Convertible Notes issuance, including counterparty risk; •increasing attention to environmental, social and governance matters; •our ability to raise or access capital on acceptable terms; •cyber-incidents could have a material adverse effect on our business, financial condition or results of operations; •changes in accounting principles, policies or guidelines; •events beyond our control, including a global or domestic health crisis, acts of terrorism, political or economic instability or armed conflict in oil and gas producing regions and shipping channels, including the joint U.S.-Israel strikes on Iran, continued instability in the Middle East and the effects of any changes to conditions in or impacting Venezuela; and •other economic, competitive, governmental, regulatory and technical factors affecting our operations, products and prices. We have based any forward-looking statements on our current expectations and assumptions about future events.  While our management considers these expectations and assumptions to be reasonable, they are inherently subject to 30 Table of Contents significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control.  Accordingly, results actually achieved may differ materially from expected results described in these statements. Forward-looking statements speak only as of the date they are made. You should consider carefully the statements in the section entitled “Item 1A. Risk Factors” and other sections of our Annual Report on Form 10-K for the fiscal year ended December 31, 2025, as updated by subsequent reports we file with the SEC (including this report), which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our company does not undertake, and specifically disclaims, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements. Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. We assume no obligation to update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this report, other than as may be required by applicable law or regulation. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the SEC which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected. Overview Our primary strategy is to invest in non-operated minority working and mineral interests in oil and natural gas properties, with a core area of focus in the premier basins within the United States.  Using this strategy, we had participated in 12,153 gross (1,303.9 net) producing wells as of March 31, 2026. As of March 31, 2026, we had leased approximately 335,050 net acres, of which approximately 81% were developed and all were located in the United States. We have grown and diversified our business significantly over the last several years through acquisitions of oil and natural gas properties. See Note 3 to our condensed financial statements for information regarding our recent acquisition activities. Our average daily production in the first quarter of 2026 was approximately 148,303 Boe per day, of which approximately 50% was oil. This was a 10% increase in production compared to the first quarter of 2025, primarily due to production attributable to recent acquisitions and new wells added to production. During the three months ended March 31, 2026, we added 17.1 net wells to production. Our weighted average percentage of production volumes by basin for the three months ended March 31, 2026 and 2025 were as follows: Three Months Ended March 31, 2026 Williston Permian Appalachian Uinta Total Oil (Bbl) 38  % 47  % 2  % 13  % 100  % Natural Gas (Mcf) 18  % 32  % 49  % 1  % 100  % Total (Boe) 28  % 39  % 26  % 7  % 100  % Source of Our Revenues We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties.  Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market.  We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil and natural gas production.  We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations.  The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements. Principal Components of Our Cost Structure •Commodity price differentials.  The price differential between our well head price for oil and the NYMEX WTI benchmark price (“Oil Price Differential”) is primarily driven by the cost to transport oil via train, pipeline or truck to 31 Table of Contents refineries. The price differential between our well head price for natural gas and NGLs and the NYMEX Henry Hub benchmark price (“Gas Price Differential”) is primarily driven by gathering and transportation costs. As applicable, the calculations of both our Oil Price Differential and Gas Price Differential include certain immaterial non-cash revenue adjustments intended to reflect current period economic conditions. •Gain (loss) on commodity derivatives, net.  We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas.  Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period end. •Production expenses.  Production expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include field personnel compensation, natural gas processing, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties. •Production taxes.  Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities.  We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions.  In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. •Depreciation, depletion, amortization and accretion.  Depreciation, depletion, amortization and accretion includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method. Accretion expense relates to the passage of time of our asset retirement obligations. •General and administrative expenses.  General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, audit and other prof [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 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion should be read in conjunction with our financial statements and accompanying notes to financial statements appearing elsewhere in this report. See Item 7., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2024 for discussion and analysis of results of operations for the year ended December 31, 2023. Executive Overview Our primary strategy is to invest in non-operated minority working and mineral interests in oil and natural gas properties, with a core area of focus in the premier basins within the United States. Using this strategy, we had participated in 11,702 gross (1,195 net) producing wells as of December 31, 2025. As of December 31, 2025, we had leased approximately 301,797 net acres, of which approximately 83% were developed and all were located in the United States. Our average daily production for full year 2025 was 135,045 Boe per day, and in the fourth quarter of 2025 was 140,064 Boe per day (approximately 53% oil). This represented significant growth from 2024, which was driven in large part by our substantial acquisition activities in 2024 and 2025, as described in Note 3 to our financial statements. During 2025, we added 80.7 new net wells to production, plus an additional 18.6 net wells added from acquisitions which were already producing when acquired. We ended 2025 with 45.6 net wells in process. Our financial and operating performance for the year ended December 31, 2025 included the following: •Total production of 135,045 Boe per day, a 9% increase compared to 2024 •Cash flows from operations of $1.5 billion, a 7% increase compared to 2024 •Proved reserves of 384.1 MMBoe at year-end, a 1% increase compared to year-end 2024 •Grew our total quarterly common stock dividends by 10%, from $1.64 per share total during 2024 to $1.80 per share total during 2025 •Provided returns to shareholders totaling approximately $230.4 million, comprised of $173.4 million in common stock dividend payments and $57.0 million in repurchases of common stock •Extended the weighted average maturity on our outstanding indebtedness to 5.4 years at year-end 2025, compared to 3.9 years at year-end 2024. Source of Our Revenues We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties.  Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market.  We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil and natural gas production.  We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations.  The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.  Principal Components of Our Cost Structure •Commodity price differentials.  The price differential between our well head price for oil and the NYMEX WTI benchmark price (“Oil Price Differential”) is primarily driven by the cost to transport oil via train, pipeline or truck to refineries. The price differential between our well head price for natural gas and NGLs and the NYMEX Henry Hub benchmark price (“Gas Price Differential”) is primarily driven by gathering and transportation costs. As applicable, the calculations of both our Oil Price Differential and Gas Price Differential include certain immaterial non-cash revenue adjustments intended to reflect current period economic conditions. •Gain (loss) on commodity derivatives, net.  We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas. Gain (loss) on commodity derivatives, net is comprised of (i) 50 Table of Contents cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period end. •Production expenses.  Production expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include field personnel compensation, natural gas processing, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties. •Production taxes.  Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. •Depreciation, depletion, amortization and accretion.  Depreciation, depletion, amortization and accretion includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method. Accretion expense relates to the passage of time of our asset retirement obligations. •General and administrative expenses.  General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, audit and other professional fees and legal compliance. •Interest expense.  We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings.  As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.  We capitalize a portion of the interest paid on applicable borrowings into our unproved cost pool.  We include interest expense that is not capitalized into the unproved cost pool, the amortization of deferred financing costs (including origination and amendment fees), the amortization of bond premiums and discounts, commitment fees and annual agency fees as interest expense. Further, we record the settled amounts of our interest rate derivative instruments as interest expense. •Impairment expense. Under the full cost method of accounting, the Company is required to perform a ceiling test impairment review each quarter.  The test determines a limit, or ceiling, on the book value of the Company’s oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. As a result of its ceiling test, the Company recorded a non-cash impairment charge of $702.7 million in the year ending December 31, 2025. The Company did not have any ceiling test impairment charges for the years ended December 31, 2024 and 2023. Average commodity prices have declined in recent months. If this downward trend continues, and/or if our proved reserves decrease significantly in future months, the present value of the Company’s future net revenues could decline significantly, which could trigger the need for the Company to record an additional non-cash ceiling test impairment of its oil and gas property costs in future periods. •Income tax expense.  Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP, 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. Selected Factors That Affect Our Operating Results Our revenues, cash flows from operations and future growth depend substantially upon: •the timing and success of drilling and production activities by our operating partners; •the prices and the supply and demand for oil, natural gas and NGLs; 51 Table of Contents •the quantity of oil and natural gas production from the wells in which we participate; •changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in commodity prices; •our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and •the level of our operating expenses. In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston, Permian, Appalachian, and Uinta Basins subjects our operating results to factors specific to these operating regions.  These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these operating regions. The price at which our oil production is sold typically reflects a discount to the NYMEX WTI benchmark price.  The price at which our natural gas production is sold may reflect either a discount or premium to the NYMEX Henry Hub benchmark price. Thus, our operating results are also affected by changes in the price differentials between the applicable benchmark prices and the sales prices we receive for our production.   Our average oil price differential to the NYMEX WTI benchmark price during 2025 was $5.53 per barrel, as compared to $3.88 per barrel in 2024.  Our net average realized gas price during 2025 was $2.87 per Mcf, representing a 79% realization relative to the average NYMEX Henry Hub pricing, compared to a net average realized gas price of $2.24 per Mcf during 2024, which represented 93% realization relative to average NYMEX Henry Hub pricing. Fluctuations in our oil and natural gas price realizations are due to several factors, such as realized pricing by basin, gathering and transportation costs, transportation methods, takeaway capacity relative to production levels, regional storage capacity, seasonal refinery maintenance, temporarily depressing demand, and in the case of gas realizations, the price of NGLs. Another significant factor affecting our operating results is drilling costs.  The cost of drilling wells can vary significantly, driven in part by volatility in commodity prices that can substantially impact the level of drilling activity.  Generally, higher commodity prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher.  Lower commodity prices have generally had the opposite effect.  In addition, individual components of drilling costs can vary depending on numerous factors, such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant used. During 2025 and 2024, the weighted average gross authorization for expenditure cost for wells we elected to participate in was $10.2 million and $9.4 million, respectively. Market Conditions The crude oil and natural gas industry is cyclical and commodity prices are inherently volatile. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand.  Because our oil and gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas.  World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can significantly impact oil prices. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production. During 2025, a decline in oil prices occurred as a result of, among other things, (i) uncertainties regarding U.S. trade policies and tariffs driving concerns over increasing inflation, (ii) continued concerns over slowing global economic growth and resulting reductions in estimated global oil consumption, and (iii) the decision by OPEC to increase production starting in May 2025 and on multiple occasions subsequent thereto, creating additional global supply and further downward pressure on oil prices. These factors led to declining oil prices, with the NYMEX price for oil reaching levels not seen since the first quarter of 2021. Although U.S. inflation rates were relatively stable during 2025, they remain slightly higher than historical averages. Inflationary pressures, such as trade tariffs, can lead to economic slowdown and/or lead to a recession, which in turn can cause a decrease in short-term or longer-term demand for commodities, resulting in oversupply and potential for lower commodity prices. The foregoing destabilizing factors have caused dramatic fluctuations in global financial markets and uncertainty about world-wide oil and natural gas supply and demand, which in turn has increased the volatility of oil and natural gas prices. 52 Table of Contents Prolonged lower oil prices and inflationary costs could impact our operating partners’ development schedule for the non-operated wells in which we have a working interest. Additionally, such prolonged depressed prices could result in a significant triggering event indicating the need for further impairment of our oil and natural gas assets. Any of the foregoing events or circumstances could impact our future sales volumes, operating revenues and expenses, liquidity, per unit metrics and capital expenditures. In light of current macroeconomic uncertainty and geopolitical tensions, including developments pertaining to Russia's invasion of Ukraine, conflicts in the Middle East and Venezuela, and potential further imposition of domestic and foreign tariffs, we cannot predict any future volatility in or levels of commodity prices or demand for oil and natural gas. Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows.  The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2025 and 2024. December 31, 2025 2024 Average NYMEX Prices(1) Oil (per Bbl) $ 64.73  $ 75.76  Natural Gas (per MMbtu) 3.62  2.41  ________________________ (1)Based on average NYMEX closing prices. For 2025, the average NYMEX WTI pricing was $64.73 per barrel of oil, or 15% lower than the $75.76 average pricing in 2024. Our average realized oil price before reflecting settled oil derivatives was $59.20 per barrel of oil in 2025, as compared to $71.59 in 2024. Our average realized oil price after reflecting settled oil derivatives was $64.35 per barrel of oil in 2025, as compared to $71.48 in 2024, representing a 10% decline year-over-year. The lower average realized oil price in 2025 was principally due to a 15% lower average NYMEX WTI benchmark price in 2025 compared to 2024, partially offset by higher gains on settled oil derivatives. For 2025, the average NYMEX Henry Hub pricing for natural gas was $3.62 per MMbtu, or 50% higher than the $2.41 per MMbtu price in 2024. Our average realized natural gas price before reflecting settled natural gas derivatives was $2.87 per Mcf in 2025, as compared to $2.24 per Mcf in 2024. Our average realized natural gas price after reflecting settled natural gas derivatives was $3.32 per Mcf in 2025, as compared to $3.00 per Mcf in 2024, representing an 11% increase year-over-year. The higher average realized natural gas price in 2025 is due to a higher average NYMEX Henry Hub benchmark price, partially offset by lower gains on settled natural gas derivatives in 2025 compared to 2024. We have entered into derivatives contracts to hedge commodity price risk on a portion of our future expected oil and natural gas production. For a summary as of December 31, 2025, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in Item 7A below. See also Note 12 to our financial statements. 53 Table of Contents Results of Operations for 2025 and 2024 The following table sets forth selected operating data for the periods indicated.  Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated. Year Ended December 31, 2025 2024 Net Production: Oil (MBbl) 27,611  26,511  Natural Gas (MMcf) 130,084  113,476  Total (MBoe) 49,292  45,423  Net Sales (in thousands): Oil Sales $ 1,627,493  $ 1,897,857  Natural Gas and NGL Sales 453,795  254,222  Gain on Settled Commodity Derivatives 201,321  83,225  Gain (Loss) on Unsettled Commodity Derivatives 179,343  (21,258) Other Revenue 13,771  11,683  Total Revenues 2,475,723  2,225,729  Average Sales Prices: Oil (per Bbl) (1) $ 59.20  $ 71.59  Effect of Loss on Settled Oil Derivatives on Average Price (per Bbl) 5.15  (0.11) Oil, Net of Settled Oil Derivatives (per Bbl) (1) 64.35  71.48  Natural Gas and NGLs (per Mcf) (1) (2) 2.87  2.24  Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.45  0.76  Natural Gas and NGLs, Net of Settled Natural Gas and NGL Derivatives (per Mcf) (1) (2) 3.32  3.00  Realized Price on a Boe Basis Excluding Settled Commodity Derivatives(1) (2) 40.74  47.38  Effect of Gain on Settled Commodity Derivatives on Average Price (per Boe) 4.08  1.83  Realized Price on a Boe Basis Including Settled Commodity Derivatives(1) (2) 44.82  49.21  Operating Expenses (in thousands): Production Expenses $ 473,666  $ 429,792  Production Taxes 131,334  157,091  General and Administrative Expenses 61,332  50,463  Depletion, Depreciation, Amortization and Accretion 814,859  740,901  Other Expense 12,848  9,650  Costs and Expenses (per Boe): Production Expenses $ 9.61  $ 9.46  Production Taxes 2.66  3.46  General and Administrative Expenses 1.24  1.11  Depletion, Depreciation, Amortization and Accretion 16.53  16.31  Net Producing Wells at Period-End 1,195.4  1,108.0  ______________ (1)    Excludes the impact of certain non-cash adjustments to revenues (2)     Excludes the impact of a legal settlement (See Note 2 to our financial statements) 54 Table of Contents Oil and Natural Gas Sales Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes.  In 2025, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, decreased by 3% from 2024, driven by a 14% decrease in realized prices on a per Boe basis, excluding the effect of settled commodity derivatives, partially offset by a 9% increase in production volumes. The lower average realized price in 2025 as compared to 2024 was driven primarily by lower average NYMEX oil prices in 2025 as compared to 2024, in addition to higher average oil price differentials, partially offset by higher realized gas and NGL prices in 2025 as compared to 2024.  Oil price differentials during 2025 averaged $5.53 per barrel, as compared to $3.88 per barrel in 2024. We add production through drilling success as we place new wells into production and through additions from acquisitions, which is offset by the natural decline of our oil and natural gas production from existing wells. Our acquisition activities in 2025 and 2024 (see Note 3 to our financial statements) helped drive the 9% increase in production levels in 2025 as compared to 2024. In addition, the number of net wells we added to production (excluding acquisitions) increased by 11% in 2025 as compared to 2024, due to our growing organic acreage footprint and increased development on our properties. Our production for the last two years is set forth in the following table: Year Ended December 31, 2025 2024 Production: Oil (MBbl) 27,611  26,511  Natural Gas and NGL (MMcf) 130,084  113,476  Total (MBoe)(1) 49,292  45,423  Average Daily Production: Oil (MBbl) 76  72  Natural Gas (MMcf) 356  310  Total (MBoe)(1) 135  124  __________________________________ (1)Natural gas and NGLs are converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices. Commodity Derivative Instruments We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production.  Our net result from commodity derivatives trade was a gain of $380.7 million in 2025, compared to a gain of $62.0 million in 2024.  Net gain or loss on commodity derivatives is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end. For 2025, we realized a gain on settled commodity derivatives of $201.3 million, compared to a $83.2 million gain in 2024.  The increased gain on settled derivatives was primarily due to a decrease in the average NYMEX oil price in 2025 compared to 2024. The average NYMEX oil price for 2025 was $64.73 per barrel, compared to $75.76 per barrel for 2024. During 2025, our derivative settlements included 11.9 million barrels of oil subject to swaps at an average settlement price of $73.27 per barrel, and we had an additional 9.4 million barrels of oil hedged subject to collars. Additionally, during 2025, our derivative settlements included 40.0 million MMBtu of natural gas subject to swaps at an average settlement price of $3.88 per MMBtu, and we had an additional 40.9 million MMBtu of natural gas hedged subject to collars. During 2024, our derivative settlements included 10.5 million barrels of oil subject to swaps at an average settlement price of $74.93 per barrel, and we had an additional 8.9 million barrels of oil hedged subject to collars. Additionally, during 2024, our derivative settlements included 41.7 million MMBtu of natural gas subject to swaps at an average settlement price of $3.50 per MMBtu, and we had an additional 29.6 million MMBtu of gas hedged subject to collars. Our average realized price 55 Table of Contents (including all commodity derivative cash settlements) in 2025 was $44.82 per Boe compared to $49.21 per Boe in 2024. The gain on settled commodity derivatives increased our average realized price per Boe by $4.08 and $1.83 in 2025 and 2024, respectively. The percentage of oil production hedged under our derivative contracts was 77% and 73% in 2025 and 2024, respectively. The Company had unsettled commodity derivative gains of $179.3 million in 2025, compared to a loss of $21.3 million in 2024.  Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings.  Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets.  As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our commodity derivatives.  Any gains on our unsettled commodity derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date.  At December 31, 2025, all of our derivative contracts were recorded at their fair value, which was a net asset of $121.6 million, a change of $178.8 million from the $57.2 million net liability recorded as of December 31, 2024.  The change in the fair value of our derivative contracts year-over-year was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2024.  Our open commodity derivative contracts are summarized in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.” Production Expenses Production expenses were $473.7 million in 2025, compared to $429.8 million in 2024.  On a per unit basis, production expenses increased 2%, from $9.46 per Boe in 2024 to $9.61 per Boe in 2025, primarily due to higher workover costs in 2025. On an absolute dollar basis, production expenses increased 10% in 2025 compared to 2024, primarily due to a 9% increase in production volumes. Production Taxes We pay production taxes based on realized oil and natural gas sales. Production taxes were $131.3 million in 2025, compared to $157.1 million in 2024.  As a percentage of oil and natural gas sales, our production taxes were 6.5% and 7.3% in 2025 and 2024, respectively. The fluctuation in our average production tax rate from year to year is primarily due to our oil and gas sales mix by basin and to certain out-of-period adjustments made to production taxes, as discussed under the heading “Out-of-Period Adjustments” in Note 2 to the financial statements. General and Administrative Expenses General and administrative expenses were $61.3 million for 2025, compared to $50.5 million for 2024. The increase in 2025 compared to 2024 was driven by an increase in employee compensation costs to support the Company’s growth and higher acquisition-related costs, partially offset by lower professional fees. Legal Settlement Expense In 2025, we incurred legal expenses of approximately $33.1 million in conjunction with our $81.7 million received from an operator in North Dakota, pursuant to a legal settlement resolving our claims related to certain post-production costs previously deducted from revenues (see Note 2 to the financial statements). Depletion, Depreciation, Amortization and Accretion Depletion, depreciation, amortization and accretion (“DD&A”) was $814.9 million in 2025, compared to $740.9 million in 2024.  The aggregate increase in DD&A expense for 2025 compared to 2024 was driven by a 9% increase in production levels and a 1% increase in the depletion rate per Boe. The following table summarizes DD&A expense per Boe for 2025 and 2024: 56 Table of Contents Year Ended December 31, 2025 2024 Change % Change Depletion $ 16.43  $ 16.22  $ 0.21  1  % Depreciation, Amortization, and Accretion 0.10  0.09  0.01  11  % Total DD&A expense $ 16.53  $ 16.31  $ 0.22  1  % Impairment Expense In 2025, the Company recorded a non-cash impairment charge of $702.7 million as a result of its full cost ceiling test. The Company did not have any ceiling test impairment charges in 2024. Interest Expense Interest expense, net of capitalized interest, was $172.4 million in 2025, compared to $157.7 million in 2024.  The increase in interest expense in 2025 as compared to 2024 was primarily due to higher outstanding borrowings under the Revolving Credit Facility, through the first half of 2025, to fund the Company’s acquisitions activities that occurred in the latter part of 2024. See Note 3 for further information. Loss on Debt Extinguishment     In 2025, we recorded a loss on debt extinguishment of $10.8 million, primarily due to the $10.3 million tender premium paid in conjunction with the cash tender offer to holders of our 8.125% senior notes due 2028 (the “Senior Notes due 2028”) (see Note 4 to the financial statements). Income Tax Expense During 2025, we recorded income tax expense of $23.9 million related to federal and state income taxes, as compared to $160.5 million in 2024. The decrease in income tax expense in 2025 is primarily due to lower book income in 2025 as compared to 2024. In addition, the enactment of the One Big Beautiful Bill Act in July 2025, which reinstated the 100% additional first-year “bonus” depreciation deduction, provided favorable updates to the calculation of disallowed interest, and to the determination of whether the Company is subject to the Corporate Alternative Minimum Tax. The effective tax rate for 2025 was 38.2% compared to an effective tax rate of 23.6% for 2024. The higher effective tax rate in 2025 was primarily due to the impact, on our deferred taxes, of the increase in our average state income tax rates, as well as adjustments for the impact of certain nondeductible items. Liquidity and Capital Resources Overview Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations, proceeds from equity and debt financings, credit facility borrowings and cash settlements of commodity derivative instruments.  Our primary uses of capital have been for the acquisition, development and operation of our oil and natural gas properties, cash settlements of commodity derivative instruments and for stockholder returns. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position. During 2025, we repurchased and retired 1,948,996 shares of our common stock for total consideration of $57.0 million, or an average price of $29.25 per share excluding excise taxes. We completed over $333.5 million in bolt-on acquisitions that closed during 2025 (see Note 3 to our financial statements). We financed these acquisitions with a combination of debt issuances, credit facility borrowings, and internally generated cash flow from operations. In June 2025, we issued $200.0 million in aggregate principal amount of our Convertible Notes (the “Additional Convertible Notes”) at an issue price of 105.597% of the principal amount thereof, the proceeds of which were used to reduce borrowings under our Revolving Credit Facility and for other general corporate purposes. 57 Table of Contents In October 2025, upon successfully completing the issuance of $725.0 million in aggregate principal amount of our 7.875% senior notes due 2033 (the “Senior Notes due 2033”), we repurchased approximately 97.14% of our outstanding Senior Notes due 2028, representing approximately $684.9 million in aggregate principal amount, for a total amount of $699.9 million, inclusive of tender premium and accrued interest due. Approximately $20.2 million in aggregate principal of the Senior Notes due 2028 remained outstanding at December 31, 2025. As of December 31, 2025, we had outstanding total debt of $2,423.2 million consisting of $478.0 million of borrowings under our Revolving Credit Facility, $20.2 million aggregate principal amount of our Senior Notes due 2028 (as defined herein), $700.0 million aggregate principal amount of our Convertible Notes (as defined herein), $500.0 million aggregate principal amount of our 8.750% senior notes due 2031 (the “Senior Notes due 2031”) (as defined herein), and $725.0 million aggregate principal amount of our Senior Notes due 2033 (as defined herein). As of December 31, 2025, we had total liquidity of $1,136.3 million, consisting of $1,122.0 million of committed borrowing availability under the Revolving Credit Facility and $14.3 million of cash on hand. One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 81% and 88% of our total oil and gas sales in 2025 and 2024, respectively.  As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices.  We seek to maintain a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the years ended 2025 and 2024, we hedged approximately 77% and 73% of our crude oil production, respectively, and approximately 62% and 63% of our natural gas production, respectively. For a summary as of December 31, 2025, of our open commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below. With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months and, based on current expectations, for the foreseeable future. However, we may seek additional access to capital and liquidity.  We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all. Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility.  Our capital expenditures could be curtailed if our cash flows decline from expected levels.  Because production from existing oil and natural gas wells declines over time, reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future. Working Capital Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, collection of receivables, expenditures related to our development and production operations and the impact of our outstanding derivative instruments.  At December 31, 2025, we had a working capital surplus of $46.7 million, compared to a deficit of $43.5 million at December 31, 2024.  Current assets increased by $85.3 million and current liabilities decreased by $5.0 million at December 31, 2025, as compared to December 31, 2024.  The $85.3 million increase in current assets in 2025 as compared to 2024 was primarily driven by a $120.2 million increase in derivative instruments, a $17.7 million increase in advances to operators, and a $7.2 million increase in cash and other current assets, partially offset by a $39.7 million decrease in accounts receivable and a $20.0 million decrease in income tax receivable. The $5.0 million decrease in current liabilities in 2025 as compared to 2024 was primarily due to a $19.9 million decrease in derivative instruments and $3.0 million decrease in accrued interest, partially offset by a $17.9 million increase in accounts payable, accruals and other current liabilities. Cash Flows Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital.  Any interim cash needs are funded by cash on hand, 58 Table of Contents cash flows from operations or borrowings under our Revolving Credit Facility.  We typically enter into commodity derivative transactions covering a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 36 months. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.” Our cash summary for the years ended December 31, 2025 and 2024 is presented below: Year Ended December 31, (In thousands) 2025 2024 Net Cash Provided by Operating Activities $ 1,505,288  $ 1,408,663  Net Cash Used for Investing Activities (1,252,462) (1,674,754) Net Cash Provided by (Used for) Financing Activities (247,460) 266,829  Net Increase in Cash $ 5,366  $ 738  Cash Flows from Operating Activities Net cash provided by operating activities in 2025 was $1.5 billion, compared to $1.4 billion in 2024. Net cash provided by operating activities is affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital and other items (as reflected in our statements of cash flows) in the year ended December 31, 2025 was a surplus of $70.1 million compared to a deficit of $53.9 million in 2024. Cash Flows from Investing Activities We had cash flows used in investing activities of $1.3 billion and $1.7 billion during the years ended December 31, 2025 and 2024, respectively, primarily as a result of our capital expenditures for drilling, development and acquisition costs.  During 2025 and 2024, we added 80.7 and 90.7 net wells to production, respectively, excluding already producing wells from acquisitions. Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred.  As a result, our actual cash spending is not always reflective of current levels of development activity.  For instance, during the year ended December 31, 2025, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g., drilling and completion costs, acquisitions, and other capital expenditures) amounted to $1.2 billion, while the actual cash spend in this regard amounted to $1.3 billion. Development and acquisition activities are discretionary.  We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the years ended December 31, 2025 and 2024 are summarized in the following table: Year Ended December 31, (In millions) 2025 2024 Drilling and Development Capital Expenditures $ 919.2  $ 771.3  Acquisition of Oil and Natural Gas Properties 328.0  900.2  Other Capital Expenditures 4.5  3.2  Total $ 1,251.7  $ 1,674.6  Cash Flows from Financing Activities Net cash used for financing activities was $247.5 million in the year ended December 31, 2025. The net cash used in financing activities in 2025 was primarily due to $695.2 million spent as part of the tender offer to repurchase certain of our Senior Notes due 2028 (inclusive of tender premiums), $600.0 million in repayments of borrowings under our Revolving Credit Facility, $173.4 million in dividend payments, $57.0 million in repurchases of common stock, $26.1 million spent in debt issuance costs, and $16.9 million from the entry into additional capped call transactions, partially offset by $725.0 million received from the issuance of our Senior notes due 2033, $388.0 million received from borrowing under our credit facility, and $211.2 million received from the issuance of the Additional Convertible Notes. 59 Table of Contents In the year ended December 31, 2024, our financing activities resulted in net cash provided of $266.8 million. The cash provided by financing activities in 2024 was primarily related to $984.0 million in increased borrowings under our Revolving Credit Facility, partially offset by $455.0 million in repayments of borrowing under our Revolving Credit Facility, $94.5 million in repurchases of common stock, and $162.0 million in dividend payments to holders of our common stock. Revolving Credit Facility We have entered into a revolving credit facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto (the “Revolving Credit Facility”). The Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to our oil and natural gas properties. Subsequent to December 31, 2025, in February 2026, the Company completed a wildcard redetermination, pursuant to which the borrowing base was increased from $1.8 billion to $1.975 billion and the elected commitment amount was increased from $1.6 billion to $1.8 billion. As of December 31, 2025, we had $478.0 million in borrowings outstanding under the facility, leaving approximately $1.3 billion in available committed borrowing capacity. See Note 4 to our financial statements for further details regarding the Revolving Credit Facility. Senior Notes due 2028 As of December 31, 2025, we had outstanding $20.2 million aggregate principal amount of our Senior Notes due 2028. See Note 4 to our financial statements for further details regarding the Senior Notes due 2028. Subsequent to December 31, 2025, in February 2026, we gave notice to the holders of the Senior Notes due 2028 (the “Notice of Full Redemption”) that we elected to redeem all of the outstanding Senior Notes due 2028, in accordance with the terms of the 2028 Notes Indenture. Pursuant to the Notice of Full Redemption, the Redemption Date is March 4, 2026, and the Redemption Price is 100%. Convertible Notes due 2029 As of December 31, 2025, we had outstanding $700.0 million aggregate principal amount of our Convertible Notes due 2029. See Note 4 to our financial statements for further details regarding the Convertible Notes. Senior Notes due 2031 As of December 31, 2025, we had outstanding $500.0 million aggregate principal amount of our Senior Notes due 2031. See Note 4 to our financial statements for further details regarding the Senior Notes due 2031. Senior Notes due 2033 As of December 31, 2025, we had outstanding $725.0 million aggregate principal amount of our Senior Notes due 2033. See Note 4 to our financial statements for further details regarding the Senior Notes due 2033. Known Contractual and Other Obligations; Planned Capital Expenditures Contractual and Other Obligations. We have contractual commitments under our debt agreements, including interest payments and principal repayments. See Note 4 to our financial statements. We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 12 to our financial statements. We have future obligations related to the abandonment of our oil and natural gas properties. See Note 9 to our financial statements. With respect to all of these items, except for our commitments under our debt agreements, we cannot determine with accuracy the amount and/or timing of such payments. Planned Capital Expenditures. For 2026, we are budgeting approximately $0.9 billion to $1.1 billion in total planned capital expenditures, including development expenditures and our smaller day-to-day acquisition activity, which we refer to as our “ground game” acquisition activity. As of December 31, 2025, we had incurred $328.9 million in capital expenditures that were included in accounts payable and accrued liabilities, and we estimate that we were committed to an additional approximately $430.6 million in development capital expenditures not yet incurred for wells we had elected to participate in. We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Revolving Credit Facility. The foregoing excludes larger acquisitions, which are typically not included in our annual capital expenditure budget. See also “Capital Requirements” below. 60 Table of Contents Capital Stock and Debt Security Repurchases. In May 2022, the Company’s board of directors approved a stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock. In July 2024, the Company’s board of directors terminated the prior stock repurchase program, and approved a new stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock. On March 10, 2025, the Company’s board of directors approved and promptly announced an additional $100.0 million authorization under this stock repurchase program. The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions. During the year ended December 31, 2025 the Company repurchased 1,948,996 shares of its common stock under the stock repurchase programs at a total cost of $57.3 million (including commissions and $0.3 million in excise tax). The Company may in the future engage in similar transactions. The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors.  If oil, natural gas and NGL prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow.  We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive.  We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, fluctuations in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.  For additional information on the impact of changing prices and market conditions on our financial position, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” Capital Requirements Development and acquisition activities are discretionary, and, for the near term, we expect such activities to be maintained at levels we can fund through cash on hand, internal cash flow and borrowings under our Revolving Credit Facility.  To the extent capital requirements exceed internal cash flow and borrowing capacity under our Revolving Credit Facility, additional financings from the capital markets may be pursued to fund these requirements.  We monitor our capital expenditures on a regular basis, adjusting the amount up or down and also between our projects, depending on commodity prices, cash flow and projected returns.  Also, our obligations may change due to acquisitions, divestitures and continued growth.  Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital.  If internally generated cash flow and borrowing capacity under our Revolving Credit Facility are not available or sufficient, we may issue additional equity or debt to fund capital expenditures, make acquisitions, extend maturities or to repay debt. Satisfaction of Our Cash Obligations for the Next Twelve Months With our Revolving Credit Facility and our cash flows from operations, we believe we will have sufficient capital to meet our drilling commitments, expected general and administrative expenses and other cash needs for the next twelve months and, based on current expectations, for the foreseeable future. Nonetheless, any strategic acquisition of assets or increase in drilling activity may lead us to seek additional capital.  We may also choose to seek additional capital rather than utilize our Revolving Credit Facility or other debt instruments to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions.  We will evaluate any potential opportunities for acquisitions as they arise.  However, there can be no assurance that any additional capital will be available to us on favorable terms or at all. Effects of Inflation and Pricing The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry.  Typically, as prices for oil and natural gas increase, so do all associated costs.  Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion.  Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions.  Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel.  Based on current conditions and expectations, we are not presently budgeting for any material change in per well drilling and completion and other associated costs in 2026 compared to 2025.  61 Table of Contents Critical Accounting Estimates The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our financial statements in accordance with generally accepted accounting principles in the United States (GAAP), as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions. Use of Estimates The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect our reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Our estimates of our proved oil and natural gas reserves, future development costs, estimates relating to certain oil and natural gas revenues and expenses, and fair value of derivative instruments are the most critical to our financial statements. Oil and Natural Gas Reserves The determination of depreciation, depletion and amortization expense as well as impairments that are recognized on our oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties.  Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions.  The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment.  For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change.  Approximately 26% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves as of December 31, 2025. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserve, future cash flows from our reserves, and future development of our proved undeveloped reserves. The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties.  Such information includes revisions of certain reserve estimates attributable to our properties included in the prior year’s estimates.  These revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in oil and natural gas prices. Our third-party independent reserve engineers, Cawley, audited 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2025. Our estimates of proved reserves quantities were prepared in accordance with the rules promulgated by the SEC. In connection with our external petroleum engineers performing their independent reserve audits, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests. Oil and Natural Gas Properties The method of accounting we use to account for our oil and natural gas investments determines what costs are capitalized and how these costs are ultimately matched with revenues and expensed. We utilize the full cost method of accounting to account for our oil and natural gas investments instead of the successful efforts method because we believe it more accurately reflects the underlying economics of our programs to explore and develop oil and natural gas reserves. The full cost method embraces the concept that dry holes and other expenditures that fail to add reserves are intrinsic to the oil and natural gas exploration business. Thus, under the full cost method, all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs, geological and geophysical costs that are directly attributable to the properties and capitalized interest. Although some of these costs will ultimately result in no additional reserves, they are part of a program from which we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. The full cost 62 Table of Contents method differs from the successful efforts method of accounting for oil and natural gas investments. The primary difference between these two methods is the treatment of exploratory dry hole costs. These costs are generally expensed under the successful efforts method when it is determined that measurable reserves do not exist. Geological and geophysical costs are also expensed under the successful efforts method. Under the full cost method, both dry hole costs and geological and geophysical costs are initially capitalized and classified as unproved properties pending determination of proved reserves. If no proved reserves are discovered, these costs are then amortized with all the costs in the full cost pool. Capitalized amounts except unproved costs are depleted using the units of production method.  The depletion expense per unit of production is the ratio of the sum of our unamortized historical costs and estimated future development costs to our proved reserve volumes.  Estimation of hydrocarbon reserves relies on professional judgment and use of factors that cannot be precisely determined.  Subsequent reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting periods.  For the year ended December 31, 2025, our average depletion expense per unit of production was $16.43 per Boe. To the extent the capitalized costs in our full cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the sum of the present value (using a 10% discount rate and based on 12-month/SEC oil and natural gas prices) of the estimated future net cash flows from our proved oil and natural gas reserves and the capitalized cost associated with our unproved properties, we would have a non-cash ceiling impairment. Such impairment costs would be charged to operations as a reduction of the carrying value of oil and natural gas properties.  The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are depressed, even if the low prices are temporary.  In addition, ceiling impairment charges may occur if we experience poor drilling results or if estimations of our proved reserves are substantially reduced.  A ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and stockholders’ equity.  Once recognized, a ceiling impairment charge to oil and natural gas properties cannot be reversed at a later date.  At December 31, 2025, we performed an impairment review using prices that reflect an average of 2025’s monthly prices as prescribed pursuant to the SEC’s guidelines.  As a result, we recorded a non-cash impairment charge of $702.7 million in the year ended December 31, 2025. We did not record any full cost impairment charge for the year ended December 31, 2024. Average commodity prices have declined in recent months. If this downward trend continues, and/or if our proved reserves decrease significantly in future months, the present value of the Company’s future net revenues could decline significantly, which could trigger the need for the Company to record a non-cash ceiling test impairment of its oil and gas property costs in future periods. Derivative Instrument Activities We use derivative instruments from time to time to manage market risks resulting primarily from fluctuations in the prices of oil and natural gas.  We may periodically enter into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.  The notional amounts of these financial instruments are based on expected production from existing wells.  We may also use exchange traded futures contracts and option contracts to hedge the delivery price of oil at a future date. All derivative positions are carried at their fair value in the balance sheet and are marked-to-market at the end of each period.  Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses on unsettled derivatives, are aggregated and recorded to gain (loss) on derivative instruments, net on the statements of operations rather than as a component of accumulated other comprehensive income or other income (expense).  The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 12 to our financial statements for a description of the derivative contracts. Recently Issued or Adopted Accounting Pronouncements See Note 2 to the financial statements for a discussion of recently issued or adopted accounting pronouncements. Off-Balance Sheet Arrangements We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. 63 Table of Contents