NORTHERN OIL & GAS, INC.

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 11,097 gross (1,133.9 net) producing wells as of March 31, 2025. As of March 31, 2025, we had leased approximately 291,672 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 11,292 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.

Previous wording

Our average daily production in the first quarter of 2025 was approximately 134,959 Boe per day, of which approximately 58% was oil. This was a 13% increase in production compared to the first quarter of 2024, primarily due to production attributable to recent acquisitions and new wells added to production. During the three months ended March 31, 2025, we added 27.3 net wells to production.

Current 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.

Previous wording

•Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We capitalize a portion of the interest paid on applicable borrowings into our unproved cost pool. We include interest expense that is not capitalized into the unproved cost pool, the amortization of deferred financing costs and bond premiums (including origination and amendment fees), commitment fees and annual agency fees as interest expense. Further, we record the settled amounts of our interest rate derivative instruments as interest expense.

Current wording

•Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We capitalize a portion of the interest paid on applicable borrowings into our unproved cost pool. We include interest expense that is not capitalized into the unproved cost pool, the amortization of deferred financing costs (including origination and amendment fees), the amortization of bond premiums and discounts, commitment fees and annual agency fees as interest expense. Further, we record the settled amounts of our interest rate derivative instruments as interest expense.

Previous wording

•Impairment expense. Under the full cost method of accounting, the Company is required to perform a ceiling test impairment review each quarter. The test determines a limit, or ceiling, on the book value of the Company’s oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The Company did not have any ceiling test impairment for the three months ended March 31, 2025 and 2024. Average commodity prices have declined in recent months. If this downward trend continues, and/or if our proved reserves decrease significantly in future months, the present value of the Company’s future net revenues could decline significantly, which could trigger the need for the Company to record a non-cash ceiling test impairment of its oil and gas property costs in future periods.

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 $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.

Previous wording

The price at which our oil production is sold typically reflects a discount to the NYMEX WTI benchmark price. The price at which our natural gas production is sold may reflect either a discount or premium to the NYMEX Henry Hub benchmark price. Thus, our operating results are also affected by changes in the price differentials between the applicable benchmark prices and the sales prices we receive for our production. Our average oil price differential to the NYMEX WTI benchmark price during the three months ended March 31, 2025 was $5.79 per barrel, as compared to $3.99 per barrel in the three months ended March 31, 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. Our net average realized gas price in the three months ended March 31, 2025 was $3.86 per Mcf, representing 100% 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 March 31, 2024, which represented a 118% 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, 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.

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 three months ended March 31, 2025 and 2024, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $10.5 million and $9.5 million, respectively.

Current wording

Another significant factor affecting our operating results is drilling costs. The cost of drilling wells can vary significantly, driven in part by volatility in commodity prices that can substantially impact the level of drilling activity. Generally, higher commodity prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher. Lower commodity prices have generally had the opposite effect. In addition, individual components of drilling costs can vary depending on numerous factors such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant used. 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.

Previous wording

During the first quarter of 2025 and continuing into April 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 $59.58 on April 8, 2025, the lowest level since the second quarter of 2021.

Current 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.

Previous wording

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

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 and. 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 volume, 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 months ended March 31, 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 six months ended June 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 12% increase in production levels in the first 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 9% increase in production levels in the second 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 $21.8 million in the first quarter of 2025, compared to a loss of $138.5 million in the first 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 $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.

Previous wording

For the first quarter of 2025, we realized a gain on settled commodity derivatives of $12.1 million, compared to a gain of $19.1 million in the first quarter of 2024. For the first quarter of 2025, we realized a gain on our unsettled commodity derivative of $9.7 million, compared to a loss of $157.6 million in the first quarter of 2024.

Current 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.

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 March 31, 2025, all of our unsettled derivative contracts are recorded at their fair values, which was a net liability of $47.6 million, a change of $9.6 million from the $57.2 million net liability recorded as of December 31, 2024. The decrease in net liability at March 31, 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 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.”

Previous wording

Production expenses were $114.0 million in the first quarter of 2025, compared to $105.4 million in the first quarter of 2024. On a per unit basis, production expenses were $9.39 per Boe in the first quarter of 2025 compared to $9.70 per Boe in the first quarter of 2024. The increase in our production expenses in the first quarter of 2025 compared to the first quarter of 2024 was primarily due to a 12% increase in production volumes and a 15% increase in the total number of net producing wells.

Current 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.

Previous wording

We pay production taxes based on realized oil and natural gas sales. Production taxes were $36.1 million in the first quarter of 2025, compared to $51.2 million in the first quarter of 2024. As a percentage of oil and natural gas sales, our production taxes were 6.3% and 9.6% in the first 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 $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.

Previous wording

General and administrative expenses were $14.5 million in the first quarter of 2025, or $1.19 per Boe, compared to $11.4 million in the first quarter 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.

Current 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.

Previous wording

Depletion, depreciation, amortization and accretion (“DD&A”) was $205.7 million in the first quarter of 2025, compared to $174.0 million in the first quarter of 2024. Depletion expense, the largest component of DD&A, increased by $31.6 million in the first quarter of 2025 compared to the first quarter of 2024, primarily due to a 12% increase in production volumes year-over-year. On a per unit basis, depletion expense was $16.84 per Boe in the first quarter of 2025 compared to $15.91 per Boe in the first 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 $1.1 million and $1.0 million in the first quarter of 2025 and 2024, respectively. The following table summarizes DD&A expense per Boe for the first quarter of 2025 and 2024:

Current 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:

Previous wording

Interest expense, net of capitalized interest, was $43.9 million in the first quarter of 2025 compared to $37.9 million in the first 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, 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.

Previous wording

During the first quarter of 2025, we recorded income tax expense of $46.8 million, as compared to $2.8 million recorded for the first quarter of 2024. The higher income tax expense in the first quarter of 2025 was driven by a higher taxable income as compared to the same period in 2024.

Current wording

During the first six months of 2025, we recorded income tax expense of $79.0 million, as compared to $45.6 million recorded for the first six months of 2024. The higher income tax expense in the first six months of 2025 was driven by a higher taxable income as compared to the same period in 2024.

Previous wording

During the three months ended March 31, 2025, we repurchased and retired 499,100 shares of our common stock for total consideration of $15.0 million (excluding brokerage commissions and excise taxes), or an average price of $30.07 per share.

Current 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.

Previous wording

As of March 31, 2025, we had outstanding total debt of $2,335.1 million consisting of $630.0 million of borrowings under our Revolving Credit Facility, $705.1 million aggregate principal amount of our Senior Notes due 2028, $500.0 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 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.

Previous wording

As of March 31, 2025, we had total liquidity of $0.9 billion, consisting of $0.9 billion of committed borrowing availability under the Revolving Credit Facility and $33.6 million of cash on hand.

Current 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.

Previous wording

One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 80% and 88% of our total oil and gas sales in the first quarter of 2025 and 2024, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices. We seek to maintain a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the three months ended March 31, 2025, we hedged approximately 68% of our crude oil production and approximately 62% of our natural gas production. For a summary as of March 31, 2025, 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. Excluding the impact of the legal settlement from the operator in North Dakota discussed in Note 2 to our condensed financial statements, oil accounted for 82% and 87% of our total oil and gas sales in the second quarter of 2025 and 2024, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices. We seek to maintain a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the six months ended June 30, 2025, we hedged approximately 68% of our crude oil production and approximately 60% of our natural gas production. For a summary as of June 30, 2025, 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, 2025, we had a working capital deficit of $42.7 million, compared to a deficit of $43.5 million at December 31, 2024. Current assets increased by $20.9 million and current liabilities increased by $20.0 million at March 31, 2025, compared to December 31, 2024.

Current wording

At June 30, 2025, we had a working capital surplus of $100.2 million, compared to a deficit of $43.5 million at December 31, 2024. Current assets increased by $87.6 million and current liabilities decreased by $56.1 million at June 30, 2025, compared to December 31, 2024.

Previous wording

Our cash summary flows for the three months ended March 31, 2025 and 2024 are presented below:

Current wording

Our cash summary flows for the six months ended June 30, 2025 and 2024 are presented below:

Previous wording

Cash flows used in investing activities during the three months ended March 31, 2025 and 2024 were $264.6 million and $407.1 million, respectively. Cash used in investing activities was higher during the three months ended March 31, 2024 because of the Delaware 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, 2025 and 2024 were $591.8 million and $630.3 million, respectively. Cash used in investing activities was higher during the six months ended June 30, 2024 because of the Delaware Acquisition, as described in Note 3 to the Company’s condensed 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, 2025, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g., drilling and completion costs, acquisitions, and other capital expenditures) amounted to $259.7 million, while the actual cash spend in this regard amounted to $264.0 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 six months ended June 30, 2025, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g., drilling and completion costs, acquisitions, and other capital expenditures) amounted to $535.9 million, while the actual cash spend in this regard amounted to $591.3 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, 2025 and 2024 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, 2025 and 2024 are summarized in the following table:

Previous wording

Net cash used for financing activities was $118.2 million during the three months ended March 31, 2025, compared to net cash provided by financing activities of $39.2 million during the three months ended March 31, 2024.

Current wording

Net cash used for financing activities was $160.8 million during the six months ended June 30, 2025, compared to net cash used for financing activities of $102.8 million during the six months ended June 30, 2024.

Previous wording

For the three months ended March 31, 2025, cash used for financing activities was primarily due to $115.0 million 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, partially offset by $55.0 million of net advances under our Revolving Credit Facility.

Current wording

For the six months ended June 30, 2024, cash used for financing activities was primarily due to $80.3 million payment for common stock dividends and $54.9 million in repurchases of common stock, partially offset by net borrowings of $37.0 million under our Revolving Credit Facility.

Previous wording

We have entered into a Revolving Credit Facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto. The Revolving Credit Facility 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. As of March 31, 2025, the Revolving Credit Facility had a borrowing base of $1.8 billion and an elected commitment amount of $1.5 billion, and we had $630.0 million in borrowings outstanding under the facility, leaving $0.9 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 a 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. As of June 30, 2025, the Revolving Credit Facility had a borrowing base of $1.8 billion and an elected commitment amount of $1.6 billion, and we had $480.0 million in borrowings outstanding under the facility, leaving $1.1 billion in available committed borrowing capacity. See Note 4 to our condensed financial statements for further details regarding the Revolving Credit Facility.

Previous wording

As of March 31, 2025, we had outstanding $500.0 million aggregate principal amount of our Convertible Notes. See Note 4 to our condensed financial statements for further details regarding the Convertible Notes.

Current wording

As of June 30, 2025, we had outstanding $700.0 million aggregate principal amount of our Convertible Notes. See Note 4 to our condensed financial statements for further details regarding the Convertible Notes.