NORTHERN OIL & GAS, INC.

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 11,292 gross (1,151.7 net) producing wells as of June 30, 2025. As of June 30, 2025, we had leased approximately 295,260 net acres, of which approximately 85% 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 11,469 gross (1,174.2 net) producing wells as of September 30, 2025. As of September 30, 2025, we had leased approximately 296,108 net acres, of which approximately 84% were developed and all were located in the United States.

Previous wording

Our average daily production in the second quarter of 2025 was approximately 134,094 Boe per day, of which approximately 57% was oil. This was a 9% increase in production compared to the second quarter of 2024, primarily due to production attributable to recent acquisitions and new wells added to production. During the three and six months ended June 30, 2025, we added 20.8 and 48.1 net wells to production, respectively.

Current wording

Our average daily production in the third quarter of 2025 was approximately 131,054 Boe per day, of which approximately 55% was oil. This was a 8% increase in production compared to the third quarter of 2024, primarily due to production attributable to recent acquisitions and new wells added to production. During the three and nine months ended September 30, 2025, we added 16.5 and 74.7 net wells to production, respectively.

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, as well as certain other immaterial non-cash revenue adjustments. The price differential between our well head price for natural gas and

Current 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, as well as certain other immaterial non-cash revenue adjustments. 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, as well as certain other immaterial non-cash revenue adjustments.

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

•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 $115.6 million in the three and six months ended June 30, 2025. The Company did not have any ceiling test impairment charge for the three and six months ended June 30, 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 an additional 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 $318.7 million and $434.3 million in the three and nine months ended September 30, 2025. The Company did not have any ceiling test impairment charge for the three and nine months ended September 30, 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 an additional non-cash ceiling test impairment of its oil and gas property costs in future periods.

Previous wording

Our average oil price differential to the NYMEX WTI benchmark price during the three months ended June 30, 2025 was $5.31 per barrel, as compared to $3.55 per barrel for the three months ended June 30, 2024. Our average oil price differential to the NYMEX WTI benchmark price during the six months ended June 30, 2025 was $5.50 per barrel, as compared to $3.81 per barrel in the six months ended June 30, 2024. The increase in our average oil price differential year-over-year was due primarily to the addition of the Uinta Basin to our portfolio of oil and natural gas assets, pursuant to the XCL Acquisition, as described in Note 3 to the Company’s condensed financial statements.

Current wording

Our average oil price differential to the NYMEX WTI benchmark price during the three months ended September 30, 2025 was $3.89 per barrel, as compared to $3.45 per barrel for the three months ended September 30, 2024. Our average oil price differential to the NYMEX WTI benchmark price during the nine months ended September 30, 2025 was $4.93 per barrel, as compared to $3.69 per barrel in the nine months ended September 30, 2024. The increase in our average oil price differential year-over-year was due primarily to the addition of the Uinta Basin to our portfolio of oil and natural gas assets, pursuant to the XCL Acquisition, as described in Note 3 to the Company’s condensed financial statements.

Previous wording

Our net average realized gas price in the three months ended June 30, 2025 was $2.89 per Mcf, representing an 82% realization relative to the average NYMEX Henry Hub pricing. In comparison, our net average realized gas price was $2.47 per Mcf in the three months ended June 30, 2024, which represented a 106% realization relative to the average NYMEX Henry Hub pricing. Our net average realized gas price in the six months ended June 30, 2025 was $3.37 per Mcf, representing a 91% realization relative to the average NYMEX Henry Hub pricing. In comparison, our net average realized gas price was $2.21 per Mcf in the six months ended June 30, 2024, which represented a 111% realization relative to the 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.

Current wording

Our net average realized gas price in the three months ended September 30, 2025 was $2.52 per Mcf, representing an 82% realization relative to the average NYMEX Henry Hub pricing. In comparison, our net average realized gas price was $1.60 per Mcf in the three months ended September 30, 2024, which represented a 72% realization relative to the average NYMEX Henry Hub pricing. Our net average realized gas price in the nine months ended September 30, 2025 was $3.07 per Mcf, representing a 88% realization relative to the average NYMEX Henry Hub pricing. In comparison, our net average realized gas price was 2.18 per Mcf in the nine months ended September 30, 2024, which represented a 98% realization relative to the 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. In recent years, 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 macroeconomic factors. During the six months ended June 30, 2025 and 2024, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $10.0 million and $9.4 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. In recent years, 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 macroeconomic factors. During the nine months ended September 30, 2025 and 2024, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $10.1 million and $9.1 million, respectively.

Previous wording

During the first half of 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, 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 $57.13 on May 5, 2025, the lowest level since the first quarter of 2021. In July 2025, OPEC announced an additional production increase for August 2025, which could further such supply-side pricing pressures on oil prices.

Current wording

During the first three quarters of 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.

Previous wording

Although U.S. inflation rates were relatively stable during the first half of 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 wording

Although U.S. inflation rates were relatively stable during the first three quarters of 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.

Previous wording

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. 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 impairment over our oil and natural gas assets. Any of the foregoing events or circumstances could impact our future sales volume, operating revenues and expenses, liquidity, per unit metrics and capital expenditures.

Current wording

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. 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 impairment over 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.

Previous wording

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 three and six months ended June 30, 2025 and 2024.

Current wording

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 three and nine months ended September 30, 2025 and 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. Acquisitions were a significant driver of our 9% increase in production levels in the second quarter of 2025 compared to the same period of 2024.

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. Acquisitions were a significant driver of our 8% increase in production levels in the third quarter of 2025 compared to the same period of 2024.

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 $128.8 million in the second quarter of 2025, compared to a loss of $3.4 million in the second quarter of 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.

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 $70.8 million in the third quarter of 2025, compared to a gain of $238.2 million in the third quarter of 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 the second quarter of 2025, we realized a gain on settled commodity derivatives of $60.9 million, compared to a gain of $8.9 million in the second quarter of 2024. For the second quarter of 2025, we realized a gain on our unsettled commodity derivative of $67.9 million, compared to a loss of $12.3 million in the second quarter of 2024.

Current wording

For the third quarter of 2025, we realized a gain on settled commodity derivatives of $55.4 million, compared to a gain of $29.7 million in the third quarter of 2024. For the third quarter of 2025, we realized a gain on our unsettled commodity derivative of $15.4 million, compared to a gain of $208.4 million in the third quarter of 2024.

Previous wording

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 June 30, 2025, all of our unsettled derivative contracts are recorded at their fair values, which was a net asset of $20.3 million, a change of $77.4 million from the $57.2 million net liability recorded as of December 31, 2024. The change in the net fair value or our unsettled derivative contracts at June 30, 2025 as compared to December 31, 2024 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 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Current wording

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 September 30, 2025, all of our unsettled derivative contracts are recorded at their fair values, which was a net asset of $35.5 million, a change of $92.7 million from the $57.2 million net liability recorded as of December 31, 2024. The change in the net fair value or our unsettled derivative contracts at September 30, 2025 as compared to December 31, 2024 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 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Previous wording

Production expenses were $121.4 million in the second quarter of 2025, compared to $100.9 million in the second quarter of 2024. On a per unit basis, production expenses were $9.95 per Boe in the second quarter of 2025 compared to $8.99 per Boe in the second quarter of 2024. The increase in our production expenses in the second quarter of 2025 compared to the second quarter of 2024 was primarily due to a 9% increase in production volumes and a 13% increase in the total number of net producing wells.

Current wording

Production expenses were $118.3 million in the third quarter of 2025, compared to $106.9 million in the third quarter of 2024. On a per unit basis, production expenses were $9.81 per Boe in the third quarter of 2025 compared to $9.54 per Boe in the third quarter of 2024. The increase in our production expenses in the third quarter of 2025 compared to the third quarter of 2024 was primarily due to an 8% increase in production volumes and a 12% increase in the total number of net producing wells.

Previous wording

We pay production taxes based on realized oil and natural gas sales. Production taxes were $35.6 million in the second quarter of 2025, compared to $48.6 million in the second quarter of 2024. As a percentage of oil and natural gas sales, our production taxes were 7.2% and 8.7% in the second quarter of 2025 and 2024, respectively. The fluctuation in our production taxes and average production tax rates year-over-year was primarily due to a higher proportion of our 2025 production coming from the Permian basin, which has a relatively lower average production tax rate.

Current wording

We pay production taxes based on realized oil and natural gas sales. Production taxes were $28.7 million in the third quarter of 2025, compared to $14.7 million in the third quarter of 2024. As a percentage of oil and natural gas sales, our production taxes were 5.9% and 2.9% in the third quarter of 2025 and 2024, respectively. The fluctuation in our production taxes and average production tax rates year-over-year was primarily due to certain out-of-period adjustments made to production taxes in 2024, as discussed under the heading “Out-of-Period Adjustments” in Note 2 to the condensed financial statements.

Previous wording

General and administrative expenses were $15.6 million in the second quarter of 2025, or $1.28 per Boe, compared to $13.5 million in the second quarter of 2024, or $1.21 per Boe. The increase was primarily driven by a higher personnel headcount as well as the timing of share-based compensation and professional fees, partially offset by lower acquisition related expenses.

Current wording

General and administrative expenses were $14.1 million in the third quarter of 2025, or $1.17 per Boe, compared to $10.0 million in the third quarter of 2024, or $0.89 per Boe. The increase was primarily driven by a higher personnel headcount as well as the timing of share-based compensation and professional fees.

Previous wording

Depletion, depreciation, amortization and accretion (“DD&A”) was $205.7 million in the second quarter of 2025, compared to $176.6 million in the second quarter of 2024. Depletion expense, the largest component of DD&A, increased by $29.0 million in the second quarter of 2025 compared to the second quarter of 2024, primarily due to a 9% increase in production volumes year-over-year. On a per unit basis, depletion expense was $16.76 per Boe in the second quarter of 2025 compared to $15.64 per Boe in the second quarter of 2024. The higher depletion rate per Boe was primarily driven by a higher depletable cost base as the result of the closing of several larger acquisitions in 2024. Depreciation, amortization and accretion was $1.2 million and $1.1 million in the second quarter of 2025 and 2024, respectively. The following table summarizes DD&A expense per Boe for the second quarter of 2025 and 2024:

Current wording

Depletion, depreciation, amortization and accretion (“DD&A”) was $199.4 million in the third quarter of 2025, compared to $185.7 million in the third quarter of 2024. Depletion expense, the largest component of DD&A, increased by $13.6 million in the third quarter of 2025 compared to the third quarter of 2024, primarily due to a 8% increase in production volumes year-over-year. On a per unit basis, depletion expense was $16.44 per Boe in the third quarter of 2025 compared to $16.47 per Boe in the third quarter of 2024. Depreciation, amortization and accretion was $1.1 million and $1.1 million in the third quarter of 2025 and 2024, respectively. The following table summarizes DD&A expense per Boe for the third quarter of 2025 and 2024:

Previous wording

In the second quarter of 2025, the Company recorded a non-cash impairment charge of $115.6 million as a result of its full cost ceiling test. The Company did not have any ceiling test impairment for the three months ended June 30, 2024.

Current wording

In the third quarter of 2025, the Company recorded a non-cash impairment charge of $318.7 million as a result of its full cost ceiling test. The Company did not have any ceiling test impairment for the three months ended September 30, 2024.

Previous wording

Interest expense, net of capitalized interest, was $44.4 million in the second quarter of 2025 compared to $37.7 million in the second quarter of 2024. The increase was primarily due to higher levels of debt pursuant to borrowings to fund the Company’s recent acquisition activities.

Current wording

Interest expense was $43.0 million in the third quarter of 2025 compared to $36.8 million in the third quarter of 2024. The increase was primarily due to higher levels of debt pursuant to borrowings to fund the Company’s recent acquisition activities.

Previous wording

Results of Operations for the Six Months Ended June 30, 2025 and June 30, 2024

Current wording

Results of Operations for the Nine Months Ended September 30, 2025 and September 30, 2024

Previous wording

In the first six months of 2025, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $1,151.3 million, compared to $1,093.1 million in the first six months of 2024. In the first six months of 2025, we recorded a legal settlement of approximately $81.7 million expected from an operator in North Dakota to resolve our claims related to certain post-production costs previously deducted from revenues (see Note 2 to our condensed financial statements).

Current wording

In the first nine months of 2025, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $1,633.6 million, compared to $1,606.6 million in the first nine months of 2024. In the first nine months of 2025, we recorded a legal settlement of approximately $81.7 million received from an operator in North Dakota to resolve our claims related to certain post-production costs previously deducted from revenues (see Note 2 to our condensed financial statements).

Previous wording

Excluding the impact of the legal settlement, oil and natural gas sales would have declined by 12%, principally due to an 18% weighted average decrease in realized prices, partially offset by a 9% increase in production volumes.

Current wording

Excluding the impact of the legal settlement, oil and natural gas sales would have declined by 3.4%, principally due to an 11% decrease in weighted average realized prices, partially offset by a 9% increase in production volumes.

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. Acquisitions were a significant driver of our 10% increase in production levels in the first six months of 2025 compared to the same period of 2024.

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. Acquisitions were a significant driver of our 9% increase in production levels in the first nine months of 2025 compared to the same period of 2024.

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 $150.6 million in the first six months of 2025, compared to a loss of $142.0 million in the first six months of 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.

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 $221.4 million in the first nine months of 2025, compared to a gain of $96.2 million in the first nine months of 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 the first six months of 2025, we realized a gain on settled commodity derivatives of $73.0 million, compared to a gain of $28.0 million in the first six months of 2024. For the first six months of 2025, we realized a gain on our unsettled commodity derivative of $77.6 million, compared to a loss of $170.0 million in the first six months of 2024.

Current wording

For the first nine months of 2025, we realized a gain on settled commodity derivatives of $128.4 million, compared to a gain of $57.7 million in the first nine months of 2024. For the first nine months of 2025, we realized a gain on our unsettled commodity derivative of $93.0 million, compared to a gain of $38.5 million in the first nine months of 2024.

Previous wording

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 June 30, 2025, all of our unsettled derivative contracts are recorded at their fair values, which was a net asset of $20.3 million, a change of $77.4 million from the $57.2 million net liability recorded as of December 31, 2024. The change in the net fair value or our unsettled derivative contracts at June 30, 2025 as compared to December 31, 2024 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 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Current wording

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 September 30, 2025, all of our unsettled derivative contracts are recorded at their fair values, which was a net asset of $35.5 million, a change of $92.7 million from the $57.2 million net liability recorded as of December 31, 2024. The change in the net fair value or our unsettled derivative contracts at September 30, 2025 as compared to December 31, 2024 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 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Previous wording

Production expenses were $235.5 million in the first six months of 2025, compared to $206.3 million in the first six months of 2024. On a per unit basis, production expenses were $9.67 per Boe in the first six months of 2025 compared to $9.34 per Boe in the first six months of 2024. The increase in our production expenses in the first six months of 2025 compared to the first six months of 2024 was primarily due to a 10% increase in production volumes and a 13% increase in the total number of net producing wells.

Current wording

Production expenses were $353.8 million in the first nine months of 2025, compared to $313.2 million in the first nine months of 2024. On a per unit basis, production expenses were $9.72 per Boe in the first nine months of 2025 compared to $9.41 per Boe in the first nine months of 2024. The increase in our production expenses in the first nine months of 2025 compared to the first nine months of 2024 was primarily due to a 9% increase in production volumes and a 12% increase in the total number of net producing wells.

Previous wording

We pay production taxes based on realized oil and natural gas sales. Production taxes were $71.7 million in the first six months of 2025, compared to $99.8 million in the first six months of 2024. As a percentage of oil and natural gas sales, our production taxes were 6.7% and 9.1% in the first six months of 2025 and 2024, respectively. The fluctuation in our production taxes and average production tax rates year-over-year was primarily due to a higher proportion of our 2025 production coming from the Permian basin, which has a relatively lower average production tax rate.

Current wording

We pay production taxes based on realized oil and natural gas sales. Production taxes were $100.4 million in the first nine months of 2025, compared to $114.5 million in the first nine months of 2024. As a percentage of oil and natural gas sales, our production taxes were 6.5% and 7.1% in the first nine months of 2025 and 2024, respectively. The fluctuation in our production taxes and average production tax rates year-over-year was primarily due to a higher proportion of our 2025 production coming from the Permian basin, which has a relatively lower average production tax rate. Further, production tax variances were impacted by certain out-of-period adjustments made to production taxes in 2024, as discussed under the heading “Out-of-Period Adjustments” in Note 2 to the condensed financial statements.

Previous wording

General and administrative expenses were $30.1 million in the first six months of 2025, or $1.24 per Boe, compared to $24.9 million in the first six months of 2024, or $1.13 per Boe. The increase was primarily driven by a higher personnel headcount as well as the timing of share-based compensation and professional fees, partially offset by lower acquisition related expenses.

Current wording

General and administrative expenses were $44.2 million in the first nine months of 2025, or $1.21 per Boe, compared to $34.9 million in the first nine months of 2024, or $1.05 per Boe. The increase was primarily driven by a higher personnel headcount as well as the timing of share-based compensation and professional fees.

Previous wording

In the first six months of 2025, we incurred legal expenses of approximately $33.1 million in conjunction with our $81.7 million receivable 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 our condensed financial statements).

Current wording

In the first nine months of 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 our condensed financial statements).

Previous wording

DD&A was $411.4 million in the first six months of 2025, compared to $350.6 million in the first six months of 2024. Depletion expense, the largest component of DD&A, increased by $60.6 million in the first six months of 2025 compared to the first six months of 2024, primarily due to a 10% increase in production volumes year-over-year. On a per unit basis, depletion expense was $16.80 per Boe in the first six months of 2025 compared to $15.77 per Boe in the first six months of 2024. The higher depletion rate per Boe was primarily driven by a higher depletable cost base as the result of the closing of several larger acquisitions in 2024. Depreciation, amortization and accretion was $2.4 million and $2.1 million in the first six months of 2025 and 2024, respectively. The following table summarizes DD&A expense per Boe for the first six months of quarter of 2025 and 2024:

Current wording

DD&A was $610.8 million in the first nine months of 2025, compared to $536.2 million in the first nine months of 2024. Depletion expense, the largest component of DD&A, increased by $74.2 million in the first nine months of 2025 compared to the first nine months of 2024, primarily due to a 9% increase in production volumes year-over-year. On a per unit basis, depletion expense was $16.68 per Boe in the first nine months of 2025 compared to $16.01 per Boe in the first nine months of 2024. The higher depletion rate per Boe was primarily driven by a higher depletable cost base as the result of the closing of several larger acquisitions in 2024. Depreciation, amortization and accretion was $3.5 million and $3.2 million in the first nine months of 2025 and 2024, respectively. The following table summarizes DD&A expense per Boe for the first nine months of quarter of 2025 and 2024:

Previous wording

In the first six months of 2025, the Company recorded a non-cash impairment charge of $115.6 million as a result of its full cost ceiling test. The Company did not have any ceiling test impairment for the first six months of 2024.

Current wording

In the first nine months of 2025, the Company recorded a non-cash impairment charge of $434.3 million as a result of its full cost ceiling test. The Company did not have any ceiling test impairment for the first nine months of 2024.

Previous wording

Interest expense, net of capitalized interest, was $88.3 million in the first six months of 2025 compared to $75.6 million in the first six months of 2024. The increase was primarily due to higher levels of debt pursuant to borrowings to fund the Company’s recent acquisition activities.

Current wording

Interest expense was $131.3 million in the first nine months of 2025 compared to $112.5 million in the first nine months of 2024. The increase was primarily due to higher levels of debt pursuant to borrowings to fund the Company’s recent acquisition activities.

Previous wording

During the six months ended June 30, 2025, we repurchased and retired 1,622,695 shares of our common stock for total consideration of $50.0 million (excluding brokerage commissions and excise taxes), or an average price of $30.82 per share.

Current wording

During the nine months ended September 30, 2025, we repurchased and retired 1,622,695 shares of our common stock for total consideration of $50.0 million (excluding brokerage commissions and excise taxes), or an average price of $30.82 per share.

Previous wording

On June 17, 2025, we issued $200.0 million in aggregate principal amount of 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 wording

In June 2025, we issued $200.0 million in aggregate principal amount of 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.

Previous wording

As of June 30, 2025, we had outstanding total debt of $2.4 billion consisting of $480.0 million of borrowings under our Revolving Credit Facility, $705.1 million aggregate principal amount of our Senior Notes due 2028, $700.0 million aggregate principal amount of our Convertible Notes due 2029, and $500.0 million aggregate principal amount of our Senior Notes due 2031.

Current wording

As of September 30, 2025, we had outstanding total debt of $2.4 billion consisting of $459.0 million of borrowings under our Revolving Credit Facility, $705.1 million aggregate principal amount of our Senior Notes due 2028, $700.0 million aggregate principal amount of our Convertible Notes due 2029, and $500.0 million aggregate principal amount of our Senior Notes due 2031.

Previous wording

As of June 30, 2025, we had total liquidity of $1.1 billion, consisting of $1.1 billion of committed borrowing availability under the Revolving Credit Facility and $25.9 million of cash on hand.

Current wording

As of September 30, 2025, we had total liquidity of $1.2 billion, consisting of $1.1 billion of committed borrowing availability under the Revolving Credit Facility and $31.6 million of cash on hand.