NORTHERN OIL & GAS, INC.

Previous wording

•changes in local, state, and federal laws, regulations or policies that may affect our business or our industry (such as the effects of tax law changes, and changes in environmental, health, and safety regulation and regulations addressing climate change, and trade policy and tariffs);

Current wording

•changes in local, state, and federal laws, regulations or policies that may affect our business or our industry (such as the effects of tax law changes, and changes in environmental, health, and safety regulation and regulations addressing climate change, and trade policy and tariffs), and similar changes in foreign jurisdictions where we currently or in the future may operate, including Canada;

Previous wording

•the potential impact of the capped call transactions undertaken in tandem with the Convertible Notes issuance, including counterparty risk;

Current wording

•the potential impact of the capped call transactions undertaken in tandem with the Convertible Notes issuances, including counterparty risk;

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 12,153 gross (1,303.9 net) producing wells as of March 31, 2026. As of March 31, 2026, we had leased approximately 335,050 net acres, of which approximately 81% were developed and all were located in the United States.

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 12,507 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.

Previous wording

We have grown and diversified our business significantly over the last several years through acquisitions of oil and natural gas properties. See Note 3 to our condensed financial statements for information regarding our recent acquisition activities.

Current wording

We have grown and diversified our business significantly over the last several years through acquisitions of oil and natural gas properties. See Note 3 to our condensed consolidated financial statements for information regarding our recent acquisition activities.

Previous wording

Our average daily production in the first quarter of 2026 was approximately 148,303 Boe per day, of which approximately 50% was oil. This was a 10% increase in production compared to the first quarter of 2025, primarily due to production attributable to recent acquisitions and new wells added to production. During the three months ended March 31, 2026, we added 17.1 net wells to production.

Current 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.

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 three months ended March 31, 2026. The Company did not have any ceiling test impairment charge for the three months ended March 31, 2025. Average commodity prices used in our ceiling test calculation have declined in recent quarters. 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, 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 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.

Previous wording

•Income tax expense. Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

Current wording

•Income tax expense. Our provision for taxes includes, federal, state and foreign taxes. We record our income taxes in accordance with accounting for income taxes under GAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

Previous wording

•our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and

Current wording

•our ability to continue to identify and acquire high-quality acreage and drilling opportunities;

Previous wording

•the level of our operating expenses.

Current wording

•the level of our operating expenses; and

Previous wording

In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston, Permian, Appalachian and Uinta Basins subjects our operating results to factors specific to these operating regions. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these operating regions.

Current wording

In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston, Permian, Appalachian, Uinta and Duvernay Basins subjects our operating results to factors specific to these operating regions. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these operating regions.

Previous wording

Our average oil price differential to the NYMEX WTI benchmark price during the three months ended March 31, 2026 was $5.85 per barrel, as compared to $5.79 per barrel for the three months ended March 31, 2025. Our net average realized gas price in the three months ended March 31, 2026 was $2.50 per Mcf, representing a 72% realization relative to the average NYMEX Henry Hub pricing. In comparison, our net average realized gas price was $3.86 per Mcf in the three months ended March 31, 2025, which represented a 100% 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 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.

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 three months ended March 31, 2026 and 2025, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $10.3 million and $10.5 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 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.

Previous wording

During 2025, a significant 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. However, during March 2026, a significant increase in oil prices occurred as a result of the threatened and actual closing of oil shipping routes, including the Strait of Hormuz, by Iran and affiliated groups in connection with the joint U.S.-Israel strikes on Iran, with the NYMEX price for oil reaching levels not seen since the second quarter of 2022.

Current wording

During 2025, a significant 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. However, in early 2026, significant increases in oil prices occurred as a result of the threatened and actual closing of oil shipping routes, including the Strait of Hormuz, by Iran and affiliated groups in connection with the joint U.S.-Israel strikes on Iran, with the NYMEX price for oil peaking in April 2026 at levels not seen since the second quarter of 2022. Oil prices have remained highly volatile since then.

Previous wording

Although U.S. inflation rates were relatively stable during the first quarter 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 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.

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 months ended March 31, 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 six months ended June 30, 2026 and 2025.

Previous wording

We have entered into derivatives contracts to hedge commodity price risk on a portion of our future expected oil and natural gas production. For a summary as of March 31, 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 financial statements.

Current 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.

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 volumes in the first 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 9% increase in production volumes in the second quarter of 2026 compared to the same period 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 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 March 31, 2026, all of our unsettled derivative contracts are recorded at their fair values, which was a net liability of $398.2 million, a change of $519.9 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 March 31, 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 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.”

Previous wording

Production expenses were $129.7 million in the first quarter of 2026, compared to $114.0 million in the first quarter of 2025. On a per unit basis, production expenses were $9.72 per Boe in the first quarter of 2026 compared to $9.39 per Boe in the first quarter of 2025. The increase in our production expenses in the first quarter of 2026 compared to the first quarter of 2025 was primarily due to higher processing charges incurred to process our natural gas and NGL production volumes.

Current wording

Production expenses were $127.1 million in the second quarter of 2026, compared to $121.4 million in the second quarter of 2025. On a per unit basis, production expenses were $9.59 per Boe in the second quarter of 2026 compared to $9.95 per Boe in the second quarter of 2025. The decrease in our production expenses per unit in the second quarter of 2026 compared to the second quarter of 2025 was primarily due to higher production volumes in the second quarter of 2026 as compared to the same period in 2025.

Previous wording

We pay production taxes based on realized oil and natural gas sales. Production taxes were $38.3 million in the first quarter of 2026, compared to $36.1 million in the first quarter of 2025. As a percentage of oil and natural gas sales, our production taxes were 7.1% and 6.3% in the first quarter of 2026 and 2025, respectively.

Current 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.

Previous wording

General and administrative expenses were $23.2 million in the first quarter of 2026, or $1.74 per Boe, compared to $14.5 million in the first quarter of 2025, or $1.19 per Boe. The increase was primarily driven by higher transaction costs recorded for the acquisition of the Utica Assets, which was accounted for as a business combination (see Note 3 to our condensed financial statements).

Current 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).

Previous wording

Depletion, depreciation, amortization and accretion (“DD&A”) was $197.1 million in the first quarter of 2026, compared to $205.7 million in the first quarter of 2025. Depletion expense, the largest component of DD&A, decreased by $8.7 million in the first quarter of 2026 compared to the first 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 $14.67 per Boe in the first quarter of 2026 compared to $16.84 per Boe in the first quarter of 2025. Depreciation, amortization and accretion was $1.3 million and $1.1 million in the first quarter of 2026 and 2025, respectively. The following table summarizes DD&A expense per Boe for the first quarter of 2026 and 2025:

Current 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:

Previous wording

In the first quarter of 2026, the Company recorded a non-cash impairment charge of $268.3 million as a result of its full cost ceiling test. No impairment charges were recorded in the first quarter of 2025.

Current 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.

Previous wording

Interest expense, Net was $42.6 million in the first quarter of 2026 compared to $43.4 million in the first quarter of 2025. The decrease was primarily due to lower average levels of debt pursuant to the repurchase and redemption of the Company’s Senior Notes due 2028 (See Note 4 to our condensed financial statements).

Current wording

Interest expense, Net was $41.4 million in the second quarter of 2026 compared to $44.4 million in the second quarter of 2025. The decrease was primarily due to lower weighted average borrowing rates, pursuant to the refinancing of the Company’s Senior Notes due 2028 by the Senior Notes due 2033 at a lower borrowing cost (See Note 4 to our condensed consolidated financial statements).

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 $539.1 million in the first quarter of 2026, compared to a gain of $21.8 million in the first 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 $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.

Previous wording

For the first quarter of 2026, we realized a loss on settled commodity derivatives of $17.6 million, compared to a gain of $12.1 million in the first quarter of 2025. For the first quarter of 2026, we realized a loss on our unsettled commodity derivative of $521.4 million, compared to a gain of $9.7 million in the first quarter of 2025.

Current 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.

Previous wording

During the first quarter of 2026, we recorded an income tax benefit of $173.1 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 $46.8 million for the first quarter of 2025.

Current 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.

Previous wording

As of March 31, 2026, we had outstanding total debt of $2.6 billion consisting of $653.0 million of borrowings under our Revolving Credit Facility, $700.0 million aggregate principal amount of our Convertible Notes due 2029, $500.0 million aggregate principal amount of our Senior Notes due 2031, and $725.0 million aggregate principal amount of our Senior Notes due 2033.

Current wording

As of June 30, 2026, we had outstanding total debt of $2.8 billion consisting of $825.0 million of borrowings under our Revolving Credit Facility, $700.0 million aggregate principal amount of our Convertible Notes due 2029, $500.0 million aggregate principal amount of our Senior Notes due 2031, and $725.0 million aggregate principal amount of our Senior Notes due 2033.

Previous wording

As of March 31, 2026, we had total liquidity of approximately $1.2 billion, consisting of $1.1 billion of committed borrowing availability under the Revolving Credit Facility and $37.0 million of cash on hand.

Current wording

As of June 30, 2026, we had total liquidity of approximately $1.0 billion, consisting of $975.0 million of committed borrowing availability under the Revolving Credit Facility and $47.6 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 81% and 80% of our total oil and gas sales in the first quarter of 2026 and 2025, 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 three months ended March 31, 2026, we hedged approximately 65% of our crude oil production and approximately 62% of our natural gas production. For a summary as of March 31, 2026, of our open commodity swap contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk” in Part I, Item 3 below.

Current wording

One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 83% and 82% of our total oil and gas sales in the second quarter of 2026 and 2025, 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 six months ended June 30, 2026, we hedged approximately 80% of our crude oil production and approximately 60% of our natural gas production. For a summary as of June 30, 2026, of our open commodity swap contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk” in Part I, Item 3 below.

Previous wording

At March 31, 2026, we had a working capital deficit of $426.5 million, compared to a surplus of $46.7 million at December 31, 2025. Current assets decreased by $113.1 million and current liabilities increased by $360.1 million at March 31, 2026, compared to December 31, 2025.

Current wording

At June 30, 2026, we had a working capital deficit of $128.4 million, compared to a surplus of $46.7 million at December 31, 2025. Current assets decreased by $83.9 million and current liabilities increased by $91.2 million at June 30, 2026, compared to December 31, 2025.

Previous wording

Our cash summary for the three months ended March 31, 2026 and 2025 is presented below:

Current wording

Our cash summary for the three and six months ended June 30, 2026 and 2025 is presented below:

Previous wording

Net cash provided by operating activities for the three months ended March 31, 2026 was $323.6 million, compared to $407.4 million in the same period of the prior year. The lower cash provided by operating activities in the first quarter of 2026 was due, primarily, to lower weighted average realized prices.

Current wording

Net cash provided by operating activities for the three months ended June 30, 2026 was $321.6 million, compared to $362.1 million in the same period of the prior year. The lower cash provided by operating activities in the second quarter of 2026 was primarily due to realized losses from settled commodity derivatives, partially offset by increased revenues from higher prices and production volumes.

Previous wording

Cash flows used in investing activities during the three months ended March 31, 2026 and 2025 were $634.7 million and $264.6 million, respectively. Cash used in investing activities was higher during the three months ended March 31, 2026 primarily because of the Utica Acquisition, as described in Note 3 to the Company’s condensed financial statements.

Current wording

Cash flows used in investing activities during the six months ended June 30, 2026 and 2025 were $1,014.5 million and $591.8 million, respectively. Cash used in investing activities was higher during the six months ended June 30, 2026 primarily due to the Utica Acquisition and the Duvernay Acquisition, as described in Note 3 to the Company’s condensed consolidated financial statements.

Previous wording

Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred. As a result, our actual cash spending is not always reflective of current levels of development activity. For instance, during the three months ended March 31, 2026, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g., drilling and completion costs, acquisitions, and other capital expenditures) amounted to $739.7 million, while the actual cash spend in this regard amounted to $634.6 million.

Current wording

Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred. As a result, our actual cash spending is not always reflective of current levels of development activity. For instance, during the three months ended June 30, 2026, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g., drilling and completion costs, acquisitions, and other capital expenditures) amounted to $463.4 million, while the actual cash spend in this regard amounted to $379.8 million. Further, during the six months ended June 30, 2026, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g., drilling and completion costs, acquisitions, and other capital expenditures) amounted to $1,203.1 million, while the actual cash spend in this regard amounted to $1,014.4 million.

Previous wording

Development and acquisition activities are discretionary. We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the three months ended March 31, 2026 and 2025 are summarized in the following table:

Current wording

Development and acquisition activities are discretionary. We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the six months ended June 30, 2026 and 2025 are summarized in the following table:

Previous wording

Net cash provided by financing activities was $333.8 million during the three months ended March 31, 2026, compared to net cash used for financing activities of $118.2 million during the three months ended March 31, 2025.

Current wording

Net cash provided by financing activities was $74.2 million during the three months ended June 30, 2026, compared to net cash used for financing activities of $42.6 million during the three months ended June 30, 2025.

Previous wording

For the three months ended March 31, 2025, cash used for financing activities was primarily due to $60.0 million net repayment of borrowings under our Revolving Credit Facility, $41.7 million of common stock dividend payments and $15.0 million in repurchases of common stock.

Current wording

For the three months ended June 30, 2025, cash used for financing activities was primarily due to $150.0 million net repayment of borrowings under our Revolving Credit Facility, $44.3 million of common stock dividend payments, $35.0 million in repurchases of common stock, and $16.9 million from the entry into Additional Capped Call Transactions, partially offset by the issuance of $200.0 million in aggregate principal amount of Additional Convertible Notes at an issue price of 105.597% of the principal amount thereof.

Previous wording

For the three months ended March 31, 2026, cash provided by financing activities was primarily due to $227.9 million proceeds from issuance of common stock, and $175.0 million net borrowings under our Revolving Credit Facility, partially offset by $44.5 million of common stock dividend payments, $20.2 million spent to redeem all of the outstanding Senior Notes due 2028, and $2.8 million to settle the tax obligations related to employee share based compensations.

Current wording

For the six months ended June 30, 2026, cash provided by financing activities was primarily due to $227.9 million proceeds from issuance of common stock, and $347.0 million net borrowings under our Revolving Credit Facility, partially offset by $91.8 million of common stock dividend payments, $50.0 million in repurchases of common stock, $20.2 million spent to redeem all of the outstanding Senior Notes due 2028, and $2.8 million to settle the tax obligations related to employee share based compensations.

Previous wording

We have entered into the Revolving Credit Facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto. The Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to our oil and natural gas properties. In February 2026, the Company completed a wildcard redetermination, pursuant to which the borrowing base was increased from $1.8 billion to $1.975 billion, and the aggregate elected commitment amount was increased from $1.6 billion to $1.8 billion. As of March 31, 2026, the Revolving Credit Facility had a borrowing base of $1.975 billion and an elected commitment amount of $1.8 billion, and we had $653.0 million in borrowings outstanding under the facility, leaving approximately $1.1 billion in available committed borrowing capacity. See Note 4 to our condensed financial statements for further details regarding the Revolving Credit Facility.

Current wording

We have entered into the Revolving Credit Facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto. The Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to our oil and natural gas properties. In February 2026, the Company completed a wildcard redetermination, pursuant to which the borrowing base was increased from $1.8 billion to $1.975 billion, and the aggregate elected commitment amount was increased from $1.6 billion to $1.8 billion. As of June 30, 2026, the Revolving Credit Facility had a borrowing base of $1.975 billion and an elected commitment amount of $1.8 billion, and we had $825.0 million in borrowings outstanding under the facility, leaving approximately $1.0 billion in available committed borrowing capacity. See Note 4 to our condensed consolidated financial statements for further details regarding the Revolving Credit Facility.