NORTHERN OIL & GAS, INC.
For the period ended Dec 31, 2025. Filed Feb 26, 2026.
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FY2025 · Filed Feb 26, 2026
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NOG$22.84+3.2%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 136 previous paragraphs and 154 current paragraphs.
74 unchanged; 53 reworded; 24 added; 8 removed; 1 previous and 3 current paragraphs rearranged.
Tables are not compared: 6 previous and 6 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (24)
Current report
•Cash flows from operations of $1.5 billion, a 7% increase compared to 2024
Current report
•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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
(1)Excludes the impact of certain non-cash adjustments to revenues
Current report
(2) Excludes the impact of a legal settlement (See Note 2 to our financial statements)
Current report
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).
Current report
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.
Current report
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).
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
Our cash summary for the years ended December 31, 2025 and 2024 is presented below:
Current report
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.
Current report
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%.
Current report
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.
Removed paragraphs (8)
Previous report
•Cash flows from operations of $1.4 billion, a 19% increase compared to 2023
Previous report
•Grew and diversified the business through over $883.5 million in substantial bolt-on acquisitions that closed during 2024
Previous report
In 2023, we recorded a contingent consideration gain of $10.1 million due to the change in the fair value of certain contingent consideration liabilities previously recorded pursuant to certain acquisitions of oil and natural gas properties. As of December 31, 2024, there were no remaining outstanding contingent consideration liabilities.
Previous report
During 2024, we recorded income tax expense of $160.5 million related to federal and state income taxes, as compared to $77.8 million in 2023. The effective tax rate for 2024 was 23.6% compared to an effective tax rate of 7.8% for 2023. The increase in income tax expense in 2024 is primarily due to the release of our valuation allowance during the second quarter of 2023.
Previous report
Our cash flows for the years ended December 31, 2024 and 2023 are presented below:
Previous report
The cash provided by financing activities in 2023 was primarily related to the issuance of the Senior Notes due 2031 of $492.8 million and the issuance of common stock of $514.7 million, which was partially offset by $8.0 million in repurchases of common stock, $18.4 million in repurchases of our Senior Notes due 2028, and $158.0 million of net repayments on our Revolving Credit Facility. Additionally, we paid common stock dividends of $123.9 million and spent $11.9 million in fees in connection with debt financing transactions in 2023.
Previous report
As of December 31, 2024, we had outstanding $705.1 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.
Reworded paragraphs (53)
Previous wording
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 10,868 gross (1,108 net) producing wells as of December 31, 2024. As of December 31, 2024, we had leased approximately 292,500 net acres, of which approximately 84% were developed and all were located in the United States.
Current wording
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.
Previous wording
Our average daily production for full year 2024 was 124,108 Boe per day, and in the fourth quarter of 2024 was 131,777 Boe per day (approximately 60% oil). This represented significant growth from 2023, which was driven in large part by our substantial acquisition activities in 2023 and 2024, as described in Note 3 to our financial statements.
Current wording
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.
Previous wording
During 2024, we added 90.7 new net wells to production, plus an additional 69.4 net wells added from acquisitions which were already producing when acquired. We ended 2024 with 50.4 net wells in process.
Current wording
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.
Previous wording
•Total production of 124,108 Boe per day, a 26% increase compared to 2023
Current wording
•Total production of 135,045 Boe per day, a 9% increase compared to 2024
Previous wording
•Proved reserves of 378.5 MMBoe at year-end, an 11% increase compared to year-end 2023
Current wording
•Proved reserves of 384.1 MMBoe at year-end, a 1% increase compared to year-end 2024
Previous wording
•Grew our total quarterly common stock dividends by 10%, from $1.49 per share total during 2023 to $1.64 per share total during 2024
Current wording
•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
Previous wording
•Provided returns to shareholders totaling approximately $256.5 million, comprised of $162.0 million in common stock dividend payments and $94.5 million in repurchases of common stock.
Current wording
•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
Previous wording
•Commodity price differentials. The price differential between our well head price for oil and the NYMEX WTI benchmark price 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 is primarily driven by gathering and transportation costs.
Current wording
•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.
Previous wording
•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.
Current wording
•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)
Previous wording
•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, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties.
Current wording
•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.
Previous wording
•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, franchise taxes, audit and other professional fees and legal compliance.
Current wording
•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.
Previous wording
•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 and bond premiums (including origination and amendment fees), commitment fees and annual agency fees as interest expense. Further, we record the settled amounts of our interest rate derivative instruments as interest expense.
Current wording
•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.
Previous wording
•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. The Company did not have any ceiling test impairment 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 a non-cash ceiling test impairment of its oil and gas property costs in future periods.
Current wording
•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.
Previous wording
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 2024 was $3.88 per barrel, as compared to $2.83 per barrel in 2023. Our net average realized gas price during 2024 was $2.24 per Mcf, representing a 93% realization relative to the average NYMEX Henry Hub pricing, compared to a net average realized gas price of $2.98 per Mcf during 2023, which represented 112% realization relative to average NYMEX Henry Hub pricing. Fluctuations in our oil and 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.
Current wording
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.
Previous wording
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. Since 2021, we have observed inflationary pressures on drilling and other operating costs due to various factors, such as higher commodity prices, labor shortages, supply chain disruptions and other factors. During 2024 and 2023, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $9.4 million and $9.5 million, respectively.
Current wording
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.
Previous wording
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. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.
Current wording
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.
Previous wording
For 2024, the average NYMEX WTI pricing was $75.76 per barrel of oil, or 2% lower than the $77.61 average pricing in 2023. Our average realized oil price before reflecting settled oil derivatives was $71.59 per barrel of oil in 2024, as compared to $74.78 in 2023. Our average realized oil price after reflecting settled oil derivatives was $71.48 per barrel of oil in
Current wording
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.
Previous wording
For 2024, the average NYMEX Henry Hub pricing for natural gas was $2.41 per MMbtu, or 9% lower than the $2.66 per MMbtu price in 2023. Our average realized natural gas price before reflecting settled natural gas derivatives was $2.24 per Mcf in 2024, as compared to $2.98 per Mcf in 2023. Our average realized natural gas price after reflecting settled natural gas derivatives was $3.00 per Mcf in 2024, as compared to $3.90 per Mcf in 2023, representing a 23% decline year-over-year. The lower average realized natural gas price in 2024 is due to both a lower average NYMEX Henry Hub benchmark price and lower gain on settled natural gas derivatives in 2024 compared to 2023.
Current wording
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.
Previous wording
Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. In 2024, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, increased 13% from 2023, driven by a 26% increase in production volumes, partially offset by a 10% decrease in realized prices on a per Boe basis, excluding the effect of settled commodity derivatives. The lower average realized price in 2024 as compared to 2023 was driven by lower average NYMEX oil and natural gas prices in 2024 as compared to 2023, in addition to higher average oil price differentials and lower gas price realizations to the NYMEX average natural gas price in 2024 as compared to 2023. Oil price differentials during 2024 averaged $3.88 per barrel, as compared to $2.83 per barrel in 2023. Gas price realizations in 2024 averaged 93% of the NYMEX average gas price, as compared to 112% in 2023
Current wording
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.
Previous wording
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 substantial acquisition activities in 2024 and 2023 (see Note 3 to our financial statements) helped drive the 26% increase in production levels in 2024 as compared to 2023. In addition, the number of net wells we added to production (excluding acquisitions) increased by 18% in 2024 as compared to 2023, due to our growing organic acreage footprint and increased development on our properties.
Current wording
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.
Previous wording
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 $62.0 million in 2024, compared to a gain of $259.3 million in 2023. 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.
Current wording
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.
Previous wording
For 2024, we realized a gain on settled commodity derivatives of $83.2 million, compared to a $57.9 million gain in 2023. The increased gain on settled derivatives was primarily due to a decrease in the average NYMEX oil and continued depressed NYMEX gas price in 2024 compared to 2023. The average NYMEX oil price for 2024 was $75.76 per barrel, compared to $77.61 per barrel for 2023. Further, the average NYMEX Henry Hub gas price for 2024 was 2.41 per Mcf, compared to 2.66 per Mcf for 2023.
Current wording
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.
Previous wording
During 2023, our derivative settlements included 8.1 million barrels of oil subject to swaps at an average settlement price of $75.19 per barrel, and we had an additional 6.3 million barrels of oil hedged subject to collars. Additionally, during 2023, our derivative settlements included 33.8 million MMBtu of gas subject to swaps at an average settlement price of $3.95 per MMBtu, and we had an additional 20.0 million MMBtu of gas hedged subject to collars. Our average realized price (including all commodity derivative cash settlements) in 2024 was $49.21 per Boe compared to $54.22 per Boe in 2023. The gain on settled commodity derivatives increased our average realized price per Boe by $1.83 and $1.61 in 2024 and 2023, respectively. The percentage of oil production hedged under our derivative contracts was 73% and 65% in 2024 and 2023, respectively.
Current wording
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.
Previous wording
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 natural gas hedged subject to collars.
Current wording
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
Previous wording
The Company had unsettled commodity derivative losses of $21.3 million in 2024, compared to a gain of $201.3 million in 2023. 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, 2024, all of our derivative contracts were recorded at their fair value, which was a net liability of $57.2 million, a change of $21.0 million from the $36.2 million net liability recorded as of December 31, 2023. The increase in the net liability at December 31, 2024 as compared to December 31, 2023 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2023. Our open commodity derivative contracts are summarized in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”
Current wording
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.”
Previous wording
Production expenses were $429.8 million in 2024, compared to $347.0 million in 2023. On a per unit basis, production expenses decreased 2%, from $9.62 per Boe in 2023 to $9.46 per Boe in 2024, due to higher production volumes in 2024. On an absolute dollar basis, production expenses increased 24% in 2024 compared to 2023, primarily due to a 26% increase in production volumes partially caused by an 18% increase in net wells.
Current wording
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.
Previous wording
We pay production taxes based on realized oil and natural gas sales. Production taxes were $157.1 million in 2024, compared to $160.1 million in 2023. As a percentage of oil and natural gas sales, our production taxes were 7.3% and 8.4% in 2024 and 2023, 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.
Current wording
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.
Previous wording
General and administrative expenses were $50.5 million for 2024, compared to $46.8 million for 2023. The increase in 2024 compared to 2023 was driven in part by an increase in professional fees and employee compensation to support the Company’s growth, partially offset by lower acquisition-related costs.
Current wording
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.
Previous wording
Depletion, depreciation, amortization and accretion (“DD&A”) was $740.9 million in 2024, compared to $486.0 million in 2023. The aggregate increase in DD&A expense for 2024 compared to 2023 was driven by a 26% increase in production levels and a 21% increase in the depletion rate per Boe. The increase in depletion rate per Boe for 2024 as compared to 2023 was primarily due to a significant increase to our depletable cost base, due to the closing of several larger acquisitions in 2023 and 2024 (see Note 3 to our financial statements). The following table summarizes DD&A expense per Boe for 2024 and 2023:
Current wording
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:
Previous wording
Interest expense, net of capitalized interest, was $157.7 million in 2024, compared to $135.7 million in 2023. The increase in interest expense for 2024 as compared to 2023 was primarily due to higher levels of debt pursuant to borrowings to fund the Company’s acquisition activities in 2024. See Note 3 for further information.
Current wording
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.
Previous wording
During 2024, we repurchased and retired 2,535,391 shares of our common stock for total consideration of $95.4 million, or an average price of $37.27 per share excluding excise taxes.
Current wording
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.
Previous wording
We completed over $883.5 million in substantial bolt-on acquisitions that closed during 2024 (see Note 3 to our financial statements). We financed these acquisitions with a combination of credit facility borrowings, equity consideration and internally generated cash flow from operations.
Current wording
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.
Previous wording
As of December 31, 2024, we had outstanding total debt consisting of $690.0 million of borrowings under our Revolving Credit Facility, $705.1 million aggregate principal amount of our Senior Notes due 2028 (as defined herein), $500.0 million aggregate principal amount of our Senior Notes due 2031 (as defined herein), and $500.0 million aggregate principal amount of our Convertible Notes due 2029 (as defined herein).
Current wording
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).
Previous wording
As of December 31, 2024, we had total liquidity of $818.9 million, consisting of $810.0 million of committed borrowing availability under the Revolving Credit Facility and $8.9 million of cash on hand.
Current wording
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.
Previous wording
One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 88% and 87% of our total oil and gas sales in 2024 and 2023, 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 2024 and 2023, we hedged approximately 73% and 65% of our crude oil production, respectively, and approximately 63% and 64% of our natural gas production, respectively. For a summary as of December 31, 2024, of our open commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.
Current wording
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.
Previous wording
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, 2024, we had a working capital deficit of $43.5 million, compared to a surplus of $123.6 million at December 31, 2023. Current assets decreased by $8.7 million and current liabilities increased by $158.5 million at December 31, 2024, as compared to December 31, 2023.
Current wording
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.
Previous wording
The $8.7 million decrease in current assets in 2024 as compared to 2023 was primarily driven by a $29.2 million decrease in derivative instruments and a $36.9 million decrease in advances to operators, partially offset by a $19.1 million increase in accounts receivable and a $34.8 million increase in income tax receivable.
Current wording
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.
Previous wording
The $158.5 million increase in current liabilities in 2024 as compared to 2023 was primarily due to a $155.6 million increase in accounts payable and accrued liabilities, primarily as a result of increased development activity, and a $3.1 million increase in derivative instruments.
Current wording
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.
Previous wording
Net cash provided by operating activities in 2024 was $1.4 billion, compared to $1.2 billion in 2023. This increase was driven by an increase in production volumes, partially offset by lower average realized commodity prices and higher operating and interest costs. 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, 2024 was a deficit of $53.9 million compared to a deficit of $106.1 million in 2023.
Current wording
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.
Previous wording
We had cash flows used in investing activities of $1.7 billion and $1.9 billion during the years ended December 31, 2024 and 2023, respectively, primarily as a result of our capital expenditures for drilling, development and acquisition costs. During 2024 and 2023, we added 90.7 and 76.6 net wells to production, respectively, excluding already producing wells from acquisitions.
Current wording
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.
Showing the first 40 of 53 pairs. Open the source sections for the rest.
Rearranged current paragraphs (3)
Current report — wording carried from elsewhere
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.
Current report — wording carried from elsewhere
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.
Current report — wording carried from elsewhere
(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.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
2024, as compared to $73.88 in 2023, representing a 3% decline year-over-year. The lower average realized oil price in 2024 is due to a lower average NYMEX WTI benchmark price in 2024 compared to 2023, partially offset by a lower average loss on settled oil derivatives.