NORTHERN OIL & GAS, INC.

Previous wording

•general economic or industry conditions, nationally and/or in the communities in which our company conducts business;

Current wording

•general economic or industry conditions, whether internationally, nationally and/or in the communities in which our company conducts business, including any future economic downturn, cost inflation, supply chain disruptions, the impact of continued or further inflation, disruption in the financial markets, changes in the interest rate environment and actions taken by OPEC and other oil producing countries as it pertains to the global supply and demand of, and prices for, crude oil, natural gas and NGLs;

Previous wording

•our ability to acquire additional development opportunities, potential or pending acquisition transactions, the projected capital efficiency savings and other operating efficiencies and synergies resulting from our acquisition transactions, integration and benefits of property acquisitions, or the effects of such acquisitions on our company’s cash position and levels of indebtedness;

Current wording

•our ability to identify and consummate additional development opportunities and potential or pending acquisition transactions, the projected capital efficiency savings and other operating efficiencies and synergies resulting from our acquisition transactions, integration and benefits of property acquisitions, or the effects of such acquisitions on our company’s cash position and levels of indebtedness;

Previous wording

•our ability to raise or access capital;

Current wording

•our ability to raise or access capital on acceptable terms;

Previous wording

Our primary strategy is to invest in non-operated minority working and mineral interests in oil and gas properties, with a core area of focus in the premier basins within the United States. Using this strategy, we had participated in 10,445 gross (1,049.8 net) producing wells as of September 30, 2024. As of September 30, 2024, we had leased approximately 275,514 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 11,097 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.

Previous wording

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

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 financial statements for information regarding our recent acquisition activities.

Previous wording

Our average daily production in the third quarter of 2024 was approximately 121,815 Boe per day, of which approximately 58% was oil. This was a 19% increase in production compared to the third quarter of 2023, primarily due to production attributable to recent acquisitions and new wells added to production. During the three months ended September 30, 2024, we added 9.5 net wells to production.

Current 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.

Previous wording

•Commodity price differentials. The price differential between our well head price for oil and the NYMEX WTI benchmark price is primarily driven by the cost to transport oil via train, pipeline or truck to refineries. The price differential between our well head price for natural gas and NGLs and the NYMEX Henry Hub benchmark price is primarily driven by gathering and transportation costs.

Current wording

•Commodity price differentials. The price differential between our well head price for oil and the NYMEX WTI benchmark price is primarily driven by the cost to transport oil via train, pipeline or truck to refineries, as well as certain other immaterial non-cash revenue adjustments. The price differential between our well head price for natural gas and

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.

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 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.

Previous wording

•Impairment expense. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, a non-cash impairment expense is required. The Company did not have any ceiling test impairment for the three and nine months ended September 30, 2024 and 2023. However, if lower average monthly prices continue to decline 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. 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.

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, following the closing of the XCL Acquisition in October 2024 (see Note 3 to our condensed financial statements), Uinta Basins subjects our operating results to factors specific to these 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 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 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.

Previous wording

The price at which our oil production is sold typically reflects a discount to the NYMEX benchmark price. The price at which our natural gas production is sold may reflect either a discount or premium to the NYMEX benchmark price. Thus, our operating results are also affected by changes in the price differentials between the applicable benchmark and the sales prices we receive for our production. Our oil price differential to the NYMEX benchmark price during the third quarter of 2024 was $3.45 per barrel, as compared to $2.84 per barrel in the third quarter of 2023. Our net realized gas price in the third quarter of 2024 was $1.60 per Mcf, representing 72% realization relative to average Henry Hub pricing, compared to a net realized gas price of $2.19 per Mcf in the third quarter of 2023, which represented 82% realization relative to average Henry Hub pricing. Fluctuations in our oil and gas price realizations are due to several factors such as pricing by basin, gathering and transportation costs, transportation method, 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

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.

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 the cost 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. Since 2021, we have observed inflationary pressures on drilling and other operating costs due to various factors, such as higher commodity prices, labor shortages, supply chain disruptions and other factors. During the first nine months of 2024 and 2023, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $9.1 million and $9.4 million, respectively. The decrease is due in part to a decline in Permian lateral lengths relative to the prior year.

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 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.

Previous wording

The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Because our oil and gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can significantly impact oil prices. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.

Current wording

The crude oil and natural gas industry is cyclical and commodity prices are inherently volatile. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Because our oil and gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can significantly impact oil prices. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.

Previous wording

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, 2024 and 2023.

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 months ended March 31, 2025 and 2024.

Previous wording

In the third quarter of 2024, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $513.5 million, compared to $511.7 million in the third quarter of 2023. The slight increase was driven by a 19% increase in production volumes, partially offset by a 16% decrease in realized prices.

Current wording

In the first quarter of 2025, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $577.0 million, compared to $532.0 million in the first quarter of 2024. The increase was driven by a 12% increase in production volumes, partially offset by a 3% decrease in realized prices.

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 19% increase in production levels in the third quarter of 2024 compared to the same period of 2023.

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 12% increase in production levels in the first 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 $238.2 million in the third quarter of 2024, compared to a loss of $199.5 million in the third quarter of 2023. Net gain or loss on commodity derivatives is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.

Current wording

We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our net result from commodity derivatives trade was a gain of $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.

Previous wording

For the third quarter of 2024, we realized a gain on our unsettled commodity derivative of $208.4 million, compared to a loss of $204.7 million in the third quarter of 2023. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our commodity derivatives. Any gains on our unsettled commodity derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date. At September 30, 2024, all of our derivative contracts are recorded at their fair value, which was a net asset of $2.3 million, a change of $38.5 million from the $36.2 million net liability recorded as of December 31, 2023. The increase in asset at September 30, 2024 as compared to December 31, 2023 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2023. Our open commodity derivative contracts are summarized in “Item 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 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.”

Previous wording

Production expenses were $106.9 million in the third quarter of 2024, compared to $82.5 million in the third quarter of 2023. On a per unit basis, production expenses were $9.54 per Boe in the third quarter of 2024 compared to $8.76 per Boe in the third quarter of 2023. The higher production expenses per Boe were driven by higher salt water disposal costs in the third quarter of 2024 compared to the third quarter of 2023. On an absolute dollar basis, the increase in our production expenses in the third quarter of 2024 compared to the third quarter of 2023 was primarily due to a 19% increase in production volumes and a 14% increase in the total number of net producing wells.

Current 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.

Previous wording

We pay production taxes based on realized oil and natural gas sales. Production taxes were $14.7 million in the third quarter of 2024, compared to $42.2 million in the third quarter of 2023. As a percentage of oil and natural gas sales, our production taxes were 2.9% and 8.2% in the third quarter of 2024 and 2023, respectively. The fluctuation in our production taxes and average production tax rates from year to year was primarily due to certain out-of-period adjustments made to production taxes, as discussed under the heading “Out-of-Period Adjustments” in Note 2 to the condensed financial statements.

Current 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.

Previous wording

Depletion, depreciation, amortization and accretion (“DD&A”) was $185.7 million in the third quarter of 2024, compared to $133.8 million in the third quarter of 2023. Depletion expense, the largest component of DD&A, increased by $51.7 million in the third quarter of 2024 compared to the third quarter of 2023. The aggregate increase in depletion expense was driven by a 19% increase in production levels and a 17% increase in the depletion rate per Boe. On a per unit basis, depletion expense was $16.47 per Boe in the third quarter of 2024 compared to $14.11 per Boe in the third quarter of 2023. The higher depletion rate per Boe was primarily driven by a significant increase to our depletable base, due to the closing of several larger acquisitions in 2023 and 2024 (see Note 3 to our condensed financial statements). Depreciation, amortization and accretion was $1.1 million and $1.0 million in the third quarter of 2024 and 2023, respectively. The following table summarizes DD&A expense per Boe for the third quarter of 2024 and 2023:

Current 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:

Previous wording

Interest expense, net of capitalized interest, was $36.8 million in the third quarter of 2024 compared to $37.0 million in the third quarter of 2023. The slight decrease was primarily due to lower levels of average outstanding borrowings on our revolving credit facility in the third quarter of 2024 compared to the third quarter of 2023.

Current 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.

Previous wording

During the nine months ended September 30, 2024, we repurchased and retired 1,841,733 shares of our common stock for total consideration of $69.3 million, or an average price of $37.64 per share.

Current 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.

Previous wording

As of September 30, 2024, we had outstanding total debt of $1,980.1 million consisting of $275.0 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 Senior Notes due 2031, and $500.0 million aggregate principal amount of our Convertible Notes.

Current 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.

Previous wording

As of September 30, 2024, we had total liquidity of $1.3 billion, consisting of $1.2 billion of committed borrowing availability under the Revolving Credit Facility and $34.4 million of cash on hand.

Current 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.

Previous wording

One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 91% and 91% of our total oil and gas sales in the third quarter of 2024 and 2023, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices. We seek to maintain a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the nine months ended September 30, 2024, we hedged approximately 74% of our crude oil production and approximately 62% of our natural gas production. For a summary as of September 30, 2024, of our open commodity price derivative 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 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.

Previous wording

At September 30, 2024, we had a working capital surplus of $98.6 million, compared to a surplus of $123.6 million at December 31, 2023. Current assets increased by $9.5 million and current liabilities increased by $34.5 million at September 30, 2024, compared to December 31, 2023.

Current 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.

Previous wording

Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. We typically enter into commodity derivative transactions covering a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 36 months. Our cash flows for the nine months ended September 30, 2024 and 2023 are presented below:

Current wording

Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. We typically enter into commodity derivative transactions covering a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 36 months. See “Quantitative and Qualitative Disclosures about Market Risk” in Part I, Item 3 below.

Previous wording

Net cash provided by operating activities for the nine months ended September 30, 2024 was $1,118.4 million, compared to $841.0 million in the same period of the prior year. This increase was due to significantly higher production volumes, offset by lower realized natural gas prices (including the effect of settled derivatives) and higher operating costs. Net cash provided by operating activities is affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital and other items (as reflected in our statements of cash flows) in the nine months ended September 30, 2024 was a surplus of $14.7 million compared to a deficit of $82.6 million in the same period of the prior year.

Current wording

Net cash provided by operating activities for the three months ended March 31, 2025 was $407.4 million, compared to $392.1 million in the same period of the prior year. This increase was primarily due to higher oil and gas sales driven by higher production volumes. Net cash provided by operating activities is affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital and other items (as reflected in our statements of cash flows) in the three months ended March 31, 2025 was a surplus of $20.0 million compared to a surplus of $39.7 million in the same period of the prior year.

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 nine months ended September 30, 2024, 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 $1,082.5 million, while the actual cash spend in this regard amounted to $1,012.0 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 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.

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 nine months ended September 30, 2024 and 2023 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 three months ended March 31, 2025 and 2024 are summarized in the following table:

Previous wording

Net cash used for financing activities was $80.1 million during the nine months ended September 30, 2024, compared to net cash provided by financing activities of $653.7 million during the nine months ended September 30, 2023. For the nine months ended September 30, 2024, cash used for financing activities was primarily related to $120.2 million of common stock dividend payments and $69.3 million in repurchases of common stock, which was partially offset by $114.0 million of net advances under our Revolving Credit Facility. For the nine months ended September 30, 2023, cash provided by financing activities was primarily related to the issuance of the Senior Notes due 2031 of $492.8 million, the issuance of common stock of $224.7 million, and $65.0 million of net advances under our Revolving Credit Facility, partially offset by $88.7 million of common stock dividend payments, $18.4 million in repurchases of our Senior Notes due 2028, and $8.0 million in repurchases of common stock.

Current 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.

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 gas properties. As of September 30, 2024, the Revolving Credit Facility had a borrowing base of $1.8 billion and an elected commitment amount of $1.5 billion, and we had $275.0 million in borrowings outstanding under the facility, leaving $1.2 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 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.

Previous wording

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. Based on current conditions and expectations, we are not budgeting for any significant change in per well drilling and completion and other associated costs in 2024 compared to 2023.

Current wording

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. Based on current conditions and expectations, we are not presently budgeting for any material change in per well drilling and completion and other associated costs in 2025 compared to 2024.