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 in North America. Using this strategy, we had participated in 12,507 gross (1,369.7 net) producing wells as of June 30, 2026. As of June 30, 2026, we had leased approximately 414,787 net acres, of which approximately 71% were developed and all were located in the United States and Canada.

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 in North America. Using this strategy, we had participated in 12,728 gross (1,391.2 net) producing wells as of September 30, 2026. As of September 30, 2026, we had leased approximately 426,247 net acres, of which approximately 71% were developed and all were located in the United States and Canada.

Previous wording

Our average daily production in the second quarter of 2026 was approximately 145,659 Boe per day, of which approximately 47% was oil. This was a 9% increase in production compared to the second quarter of 2025, primarily due to production attributable to recent acquisitions and new wells added to production. During the three and six months ended June 30, 2026, we added 12.7 and 29.8 net wells to production, respectively.

Current wording

Our average daily production in the third quarter of 2026 was approximately 156,239 Boe per day, of which approximately 48% was oil. This was a 19% increase in production compared to the third quarter of 2025, primarily due to production attributable to recent acquisitions and new wells added to production. During the three and nine months ended September 30, 2026, we added 23.9 and 53.7 net wells to production, respectively.

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 $268.3 million in the six months ended June 30, 2026. The Company did not have any ceiling test impairment charge in the three months ended June 30 2026. The Company recorded a non-cash impairment charge of $115.6 million in the three and six months ended June 30, 2025. Average commodity prices used in our ceiling test calculation have fluctuated significantly in recent quarters. If such prices trend downward, and/or if our proved reserves decrease significantly in future months, the present value of the Company’s future net revenues could decline, 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 $268.3 million in the nine months ended September 30, 2026 for the United States cost pool. The Company did not have a ceiling test impairment charge in the three months ended September 30, 2026. Conversely, 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, respectively, in the United States cost pool. Average commodity prices used in our ceiling test calculation have fluctuated significantly in recent quarters. If such prices trend downward, and/or if our proved reserves decrease significantly in future months, the present value of the Company’s future net revenues could decline, 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, 2026 was $3.03 per barrel, as compared to $5.31 per barrel for the three months ended June 30, 2025. Our average oil price differential to the NYMEX WTI benchmark price during the six months ended June 30, 2026 was $4.88 per barrel, as compared to $5.50 per barrel for the six months ended June 30, 2025.

Current wording

Our average oil price differential to the NYMEX WTI benchmark price during the three months ended September 30, 2026 was $2.84 per barrel, as compared to $3.89 per barrel for the three months ended September 30, 2025. Our average oil price differential to the NYMEX WTI benchmark price during the nine months ended September 30, 2026 was $4.13 per barrel, as compared to $4.93 per barrel for the nine months ended September 30, 2025.

Previous wording

Our net average realized gas price in the three months ended June 30, 2026 was $2.64 per Mcf, representing a 90% realization relative to the average NYMEX Henry Hub pricing. In comparison, our net average realized gas price was $2.89 per Mcf in the three months ended June 30, 2025, which represented a 82% realization relative to the average NYMEX Henry Hub pricing. Our net average realized gas price in the six months ended June 30, 2026 was $2.57 per Mcf, representing an 80% realization relative to the average NYMEX Henry Hub pricing. In comparison, our net average realized gas price was $3.37 per Mcf in the six months ended June 30, 2025, which represented a 91% realization relative to the average NYMEX Henry Hub pricing.

Current wording

Our net average realized gas price in the three months ended September 30, 2026 was $2.84 per Mcf, representing a 98% realization relative to the average NYMEX Henry Hub pricing. In comparison, our net average realized gas price was $2.52 per Mcf in the three months ended September 30, 2025, which represented an 82% realization relative to the average NYMEX Henry Hub pricing. Our net average realized gas price in the nine months ended September 30, 2026 was $2.66 per Mcf, representing an 86% realization relative to the average NYMEX Henry Hub pricing. In comparison, our net average realized gas price was $3.07 per Mcf in the nine months ended September 30, 2025, which represented an 88% realization relative to the average NYMEX Henry Hub pricing.

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. During the six months ended June 30, 2026 and 2025, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $10.4 million and $10.0 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 the nine months ended September 30, 2026 and 2025, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $10.6 million and $10.1 million, respectively.

Previous wording

Although U.S. inflation rates were relatively stable during the first half of 2026, 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 2026, 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

Further, pursuant to our recent acquisition of oil and gas properties in Canada (See Note 3 to the condensed consolidated financial statements), we are now subject to foreign currency risks. Our wholly owned Canadian subsidiary uses the Canadian dollar (“CAD”) as its functional currency. Fluctuations in the USD/CAD exchange rate will affect the USD equivalent of our wholly owned Canadian subsidiary’s assets, liabilities, revenues, and operating expenses as reported in our condensed consolidated financial statements.

Current wording

Further, pursuant to our recent acquisition of oil and gas properties in Canada (See Note 3 to the condensed consolidated financial statements), we are now subject to foreign currency risks. Our wholly owned Canadian subsidiary uses CAD as its functional currency. Fluctuations in the USD/CAD exchange rate will affect the USD equivalent of our wholly owned Canadian subsidiary’s assets, liabilities, revenues, and operating expenses as reported in our condensed consolidated financial statements.

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, 2026 and 2025.

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, 2026 and 2025.

Previous wording

We have entered into derivatives contracts to hedge commodity price risks on a portion of our future expected oil and natural gas production. For a summary as of June 30, 2026, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in Part I, Item 3 below. See also Note 10 to our condensed consolidated financial statements.

Current wording

We have entered into derivative contracts to hedge commodity price risks on a portion of our future expected oil and natural gas production. For a summary as of September 30, 2026, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in Part I, Item 3 below. See also Note 10 to our condensed consolidated financial statements.

Previous wording

Excluding the impact of the legal settlement, oil and natural gas sales increased by 36%. The increase in revenues was primarily driven by a 24% increase in weighted average realized prices and a 9% increase in production volumes.

Current wording

In the third quarter of 2026, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $697.7 million, compared to $482.2 million in the third quarter of 2025. The increase in revenues was primarily driven by a 20% increase in weighted average realized prices and a 19% 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 9% increase in production volumes in the second quarter of 2026 compared to the same period of 2025.

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 19% increase in production volumes in the third quarter of 2026 compared to the same period of 2025.

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 $70.2 million in the second quarter of 2026, compared to a gain of $128.8 million in the second quarter of 2025. 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 loss of $359.5 million in the third quarter of 2026, compared to a gain of $70.8 million in the third quarter of 2025. 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 2026, we realized a loss on settled commodity derivatives of $86.3 million, compared to a gain of $60.9 million in the second quarter of 2025. We incur realized losses on settled commodity derivatives when the average commodity market price at settlement is higher than our average hedge book price. Conversely, we incur gains when the average commodity market price at settlement is lower than our average hedge book price.

Current wording

For the third quarter of 2026, we realized a loss on settled commodity derivatives of $51.4 million, compared to a gain of $55.4 million in the third quarter of 2025. We incur realized losses on settled commodity derivatives when the average commodity market price at settlement is higher than our average hedge book price. Conversely, we incur gains when the average commodity market price at settlement is lower than our average hedge book price.

Previous wording

For the second quarter of 2026, we realized a gain on our unsettled commodity derivative of $156.5 million, compared to a gain of $67.9 million in the second quarter of 2025.

Current wording

For the third quarter of 2026, we recorded a non-cash loss on our unsettled commodity derivative of $308.0 million, compared to a gain of $15.4 million in the third quarter of 2025.

Previous wording

Our derivatives are not designated for hedge accounting, and thus 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 condensed consolidated 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, 2026, all of our unsettled derivative contracts are recorded at their fair values, which was a net liability of $240.3 million, a change of $361.9 million from the $121.6 million net asset recorded as of December 31, 2025. The change in the net fair value or our unsettled derivative contracts at June 30, 2026 as compared to December 31, 2025 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2025. 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 thus 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 loss in the accompanying condensed consolidated 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, 2026, all of our unsettled derivative contracts are recorded at their fair values, which was a net liability of $547.1 million, a change of $668.7 million from the $121.6 million net asset recorded as of December 31, 2025. The change in the net fair value of our unsettled derivative contracts at September 30, 2026 as compared to December 31, 2025 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2025. Our open commodity derivative contracts are summarized in “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Previous wording

We pay production taxes based on realized oil and natural gas sales. Production taxes were $45.7 million in the second quarter of 2026, compared to $35.6 million in the second quarter of 2025. As a percentage of oil and natural gas sales, our production taxes were 6.8% and 7.2% in the second quarter of 2026 and 2025, respectively.

Current wording

We pay production taxes based on realized oil and natural gas sales. Production taxes were $48.3 million in the third quarter of 2026, compared to $28.7 million in the third quarter of 2025. As a percentage of oil and natural gas sales, our production taxes were 6.9% and 5.9% in the third quarter of 2026 and 2025, respectively.

Previous wording

General and administrative expenses were $24.5 million in the second quarter of 2026, or $1.85 per Boe, compared to $15.6 million in the second quarter of 2025, or $1.28 per Boe. The increase was primarily driven by the $7.6 million transaction costs recorded for the Duvernay Acquisition, which was accounted for as a business combination (see Note 3 to our condensed consolidated financial statements).

Current wording

General and administrative expenses were $18.0 million in the third quarter of 2026, or $1.25 per Boe, compared to $14.1 million in the third quarter of 2025, or $1.17 per Boe. The increase was primarily driven by higher general corporate costs to support the Company’s growth initiatives.

Previous wording

Depletion, depreciation, amortization and accretion (“DD&A”) was $192.9 million in the second quarter of 2026, compared to $205.7 million in the second quarter of 2025. Depletion expense, the largest component of DD&A, decreased by $13.0 million in the second quarter of 2026 compared to the second quarter of 2025, primarily due to a lower depletable property cost basis following certain non-cash ceiling test impairment charges recorded in recent periods. On a per unit basis, depletion expense was $14.45 per Boe in the second quarter of 2026 compared to $16.76 per Boe in the second quarter of 2025. Depreciation, amortization and accretion was $1.3 million and $1.2 million in the second quarter of 2026 and 2025, respectively. The following table summarizes DD&A expense per Boe for the second quarter of 2026 and 2025:

Current wording

Depletion, depreciation, amortization and accretion (“DD&A”) was $207.9 million in the third quarter of 2026, compared to $199.4 million in the third quarter of 2025. Depletion expense, the largest component of DD&A, increased by $8.4 million in the third quarter of 2026 compared to the third quarter of 2025, primarily due to a 19% increase in production volumes, partially offset by a lower depletable property cost basis following certain non-cash ceiling test impairment charges recorded in recent periods. On a per unit basis, depletion expense was $14.37 per Boe in the third quarter of 2026 compared to $16.44 per Boe in the third quarter of 2025. Depreciation, amortization and accretion was $1.3 million and $1.1 million in the third quarter of 2026 and 2025, respectively. The following table summarizes DD&A expense per Boe for the third quarter of 2026 and 2025:

Previous wording

The Company recorded an impairment charge of $115.6 million in the second quarter of 2025, as a result of its full cost ceiling test. No impairment charges were recorded in the second quarter of 2026.

Current wording

We did not have a ceiling test impairment in the third quarter of 2026. We recorded an impairment charge of $318.7 million in the third quarter of 2025, as a result of our full cost ceiling test for our United States cost pool.

Previous wording

Foreign currency transaction losses were $4.7 million in the second quarter of 2026, primarily driven by the remeasurement of certain monetary assets and liabilities denominated in CAD, pursuant to the Company’s recent acquisition of oil and natural gas properties in Canada. The Company did not have any foreign currency transactions in the second quarter of 2025.

Current wording

Foreign currency transaction losses were $0.5 million in the third quarter of 2026, primarily driven by the remeasurement of certain monetary assets and liabilities denominated in CAD, pursuant to our recent acquisition of oil and natural gas properties in Canada. We did not have any foreign currency transactions in the third quarter of 2025.

Previous wording

During the second quarter of 2026, we recorded a contingent consideration gain of $2.7 million due to a change in the fair value of the contingent consideration liability incurred pursuant to the Duvernay Acquisition (see Notes 3 and 9 to our condensed consolidated financial statements). The contingent consideration gain was primarily driven by a favorable change in the forward NYMEX WTI oil price curve from the acquisition date to June 30, 2026.

Current wording

During the third quarter of 2026, we recorded a contingent consideration loss of $5.6 million due to a change in the fair value of the contingent consideration liability incurred pursuant to the Duvernay Acquisition (see Notes 3 and 9 to our condensed consolidated financial statements). The contingent consideration loss was primarily driven by an increase in the forward NYMEX WTI oil price curve from June 30, 2026 to September 30, 2026.

Previous wording

Results of Operations for the Six Months Ended June 30, 2026 and June 30, 2025

Current wording

Results of Operations for the Nine Months Ended September 30, 2026 and September 30, 2025

Previous wording

(1)The six months ended June 30, 2025, excludes the impact of a legal settlement (See Note 2 to our condensed financial statements).

Current wording

(1)The nine months ended September 30, 2025, excludes the impact of a legal settlement (See Note 2 to our condensed financial statements).

Previous wording

In the first six months of 2026, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $1,210.7 million, compared to $1,151.3 million in the first six months of 2025. In the first six months of 2025, we recorded a legal settlement of approximately $81.7 million 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 consolidated financial statements).

Current wording

In the first nine months of 2026, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $1,908.3 million, compared to $1,633.6 million in the first nine months of 2025. In the first nine months of 2025, we recorded a legal settlement of approximately $81.7 million 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 consolidated financial statements).

Previous wording

Excluding the impact of the legal settlement, oil and natural gas sales increased 13%. The increase in revenues was primarily driven by a 3% increase in weighted average realized prices and a 9% increase in production volumes.

Current wording

Excluding the impact of the legal settlement, oil and natural gas sales increased 23%. The increase in revenues was primarily driven by a 8% increase in weighted average realized prices and a 13% 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 9% increase in production volumes in the first six months of 2026 compared to the same period of 2025.

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 13% increase in production volumes in the first nine months of 2026 compared to the same period of 2025.

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 loss of $468.9 million in the first six months of 2026, compared to a gain of $150.6 million in the first six months of 2025. 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 loss of $828.3 million in the first nine months of 2026, compared to a gain of $221.4 million in the first nine months of 2025. 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 2026, we realized a loss on settled commodity derivatives of $104.0 million, compared to a gain of $73.0 million in the first six months of 2025. For the first six months of 2026, we realized a loss on our unsettled commodity derivative of $364.9 million, compared to a gain of $77.6 million in the first six months of 2025.

Current wording

For the first nine months of 2026, we realized a loss on settled commodity derivatives of $155.4 million, compared to a gain of $128.4 million in the first nine months of 2025. For the first nine months of 2026, we recorded a non-cash loss on our unsettled commodity derivative of $673.0 million, compared to a gain of $93.0 million in the first nine months of 2025.

Previous wording

Our derivatives are not designated for hedge accounting, and thus 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 condensed consolidated 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, 2026, all of our unsettled derivative contracts are recorded at their fair values, which was a net liability of $240.3 million, a change of $361.9 million from the $121.6 million net asset recorded as of December 31, 2025. The change in the net fair value or our unsettled derivative contracts at June 30, 2026 as compared to December 31, 2025 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2025. 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 thus 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 loss in the accompanying condensed consolidated 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, 2026, all of our unsettled derivative contracts are recorded at their fair values, which was a net liability of $547.1 million, a change of $668.7 million from the $121.6 million net asset recorded as of December 31, 2025. The change in the net fair value of our unsettled derivative contracts at September 30, 2026 as compared to December 31, 2025 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2025. 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 $256.8 million in the first six months of 2026, compared to $235.5 million in the first six months of 2025. On a per unit basis, production expenses were $9.65 per Boe in the first six months of 2026 compared to $9.67 per Boe in the first six months of 2025.

Current wording

Production expenses were $400.3 million in the first nine months of 2026, compared to $353.8 million in the first nine months of 2025. On a per unit basis, production expenses were $9.77 per Boe in the first nine months of 2026 compared to $9.72 per Boe in the first nine months of 2025.

Previous wording

We pay production taxes based on realized oil and natural gas sales. Production taxes were $84.0 million in the first six months of 2026, compared to $71.7 million in the first six months of 2025. As a percentage of oil and natural gas sales, our production taxes were 6.9% and 6.7% in the first six months of 2026 and 2025, respectively.

Current wording

We pay production taxes based on realized oil and natural gas sales. Production taxes were $132.4 million in the first nine months of 2026, compared to $100.4 million in the first nine months of 2025. As a percentage of oil and natural gas sales, our production taxes were 6.9% and 6.5% in the first nine months of 2026 and 2025, respectively.

Previous wording

General and administrative expenses were $47.7 million in the first six months of 2026, or $1.79 per Boe, compared to $30.1 million in the first six months of 2025, or $1.24 per Boe. The increase was primarily driven by $14.3 million in transaction costs recorded for both the Utica Acquisition and the Duvernay Acquisition, which were both accounted for as business combinations (see Note 3 to our condensed consolidated financial statements).

Current wording

General and administrative expenses were $65.7 million in the first nine months of 2026, or $1.60 per Boe, compared to $44.2 million in the first nine months of 2025, or $1.21 per Boe. The increase was primarily driven by $14.3 million in transaction costs recorded for both the Utica Acquisition and the Duvernay Acquisition, which were both accounted for as business combinations (see Note 3 to our condensed consolidated financial statements), as well as higher general corporate costs to support the Company’s growth initiatives.

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 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 consolidated 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 consolidated financial statements).

Previous wording

Depletion, depreciation, amortization and accretion (“DD&A”) was $390.0 million in the first six months of 2026, compared to $411.4 million in the first six months of 2025. Depletion expense, the largest component of DD&A, decreased by $21.7 million in the first six months of 2026 compared to the first six months of 2025, primarily due to a lower depletable property cost basis following certain non-cash ceiling test impairment charges recorded in recent periods. On a per unit basis, depletion expense was $14.56 per Boe in the first six months of 2026 compared to $16.80 per Boe in the first six months of 2025. Depreciation, amortization and accretion was $2.6 million and $2.4 million in the first six months of 2026 and 2025, respectively. The following table summarizes DD&A expense per Boe for the first six months of 2026 and 2025:

Current wording

Depletion, depreciation, amortization and accretion (“DD&A”) was $597.9 million in the first nine months of 2026, compared to $610.8 million in the first nine months of 2025. Depletion expense, the largest component of DD&A, decreased by $13.3 million in the first nine months of 2026 compared to the first nine months of 2025, primarily due to a lower depletable property cost basis following certain non-cash ceiling test impairment charges recorded in recent periods. On a per unit basis, depletion expense was $14.50 per Boe in the first nine months of 2026 compared to $16.68 per Boe in the first nine months of 2025. Depreciation, amortization and accretion was $3.9 million and $3.5 million in the first nine months of 2026 and 2025, respectively. The following table summarizes DD&A expense per Boe for the first nine months of 2026 and 2025:

Previous wording

In the first six months of 2026, the Company recorded a non-cash impairment charge of $268.3 million compared to $115.6 million in the first six months of 2025, as a result of its full cost ceiling tests.

Current wording

In the first nine months of 2026, we recorded a non-cash impairment charge of $268.3 million compared to $434.3 million in the first nine months of 2025, as a result of our full cost ceiling tests for our United States cost pool.

Previous wording

Foreign currency transaction losses were $4.7 million in the first six months of 2026, primarily driven by the remeasurement of certain monetary assets and liabilities denominated in CAD, pursuant to the Company’s recent acquisition of oil and natural gas properties in Canada. The Company did not have any foreign currency transactions in the first six months of 2025.

Current wording

Foreign currency transaction losses were $5.1 million in the first nine months of 2026, primarily driven by the remeasurement of certain monetary assets and liabilities denominated in CAD, pursuant to our recent acquisition of oil and natural gas properties in Canada. We did not have any foreign currency transactions in the first nine months of 2025.

Previous wording

During the first six months of 2026, we recorded a contingent consideration gain of $2.7 million due to a change in the fair value of the contingent consideration liability incurred pursuant to the Duvernay Acquisition (see Notes 3 and 9 to our condensed consolidated financial statements). The contingent consideration gain was primarily driven by a favorable change in the forward NYMEX WTI oil price curve from the acquisition date to June 30, 2026.

Current wording

During the first nine months of 2026, we recorded a contingent consideration loss of $3.0 million due to a change in the fair value of the contingent consideration liability incurred pursuant to the Duvernay Acquisition (see Notes 3 and 9 to our condensed consolidated financial statements). The contingent consideration loss was primarily driven by an increase in the forward NYMEX WTI oil price curve from the acquisition date to September 30, 2026.

Previous wording

During the first six months of 2026, we recorded an income tax benefit of $99.1 million due to our pretax losses caused, primarily, by our losses on commodity derivatives and our non-cash ceiling test impairment charge. Conversely, we recorded an income tax expense of $79.0 million for the first six months of 2025.

Current wording

During the first nine months of 2026, we recorded an income tax benefit of $112.8 million due to our pretax losses caused, primarily, by our losses on commodity derivatives and our non-cash ceiling test impairment charge. Conversely, we recorded an income tax expense of $39.3 million for the first nine months of 2025.

Previous wording

In June 2026, we repurchased and retired 2,948,447 shares of our common stock for total consideration of $60.1 million, or an average price of $20.37 per share.

Current wording

During the nine months ended September 30, 2026, we repurchased and retired 3,616,436 shares of our common stock for total consideration of $76.1 million, or an average price of $21.03 per share.