NORTHERN OIL GAS INC

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 9,765 gross (951.6 net) producing wells as of December 31, 2023. As of December 31, 2023, we had leased approximately 272,251 net acres, of which approximately 89% 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 10,868 gross (1,108 net) producing wells as of December 31, 2024. As of December 31, 2024, we had leased approximately 292,500 net acres, of which approximately 84% were developed and all were located in the United States.

Previous wording

Our average daily production for full year 2023 was 98,822 Boe per day, and in the fourth quarter of 2023 was 114,363 Boe per day (approximately 60% oil). This represented significant growth from 2022, which was driven in large part by our substantial acquisition activity in 2022 and 2023, as described in Note 3 to our financial statements.

Current wording

Our average daily production for full year 2024 was 124,108 Boe per day, and in the fourth quarter of 2024 was 131,777 Boe per day (approximately 60% oil). This represented significant growth from 2023, which was driven in large part by our substantial acquisition activities in 2023 and 2024, as described in Note 3 to our financial statements.

Previous wording

During 2023, we added 76.6 new net wells to production, plus an additional 80.4 net wells added from acquisitions which were already producing when acquired. We ended 2023 with 66.5 net wells in process.

Current wording

During 2024, we added 90.7 new net wells to production, plus an additional 69.4 net wells added from acquisitions which were already producing when acquired. We ended 2024 with 50.4 net wells in process.

Previous wording

•Total production of 98,822 Boe per day, a 31% increase compared to 2022

Current wording

•Total production of 124,108 Boe per day, a 26% increase compared to 2023

Previous wording

•Proved reserves of 339.7 MMBoe at year-end, a 3% increase compared to year-end 2022

Current wording

•Proved reserves of 378.5 MMBoe at year-end, an 11% increase compared to year-end 2023

Previous wording

•Grew and diversified the business through over $1.0 billion in substantial bolt-on acquisitions that closed during 2023

Current wording

•Grew and diversified the business through over $883.5 million in substantial bolt-on acquisitions that closed during 2024

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 proved oil and gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, a non-cash impairment expense is required.

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 years ended December 31, 2024 and 2023. 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 and Appalachian 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 2023 was $2.83 per barrel, as compared to $2.73 per barrel in 2022. Our net realized gas price during 2023 was $2.98 per Mcf, representing 112% realization relative to average Henry Hub pricing, compared to a net realized gas price of $7.43 per Mcf during 2022, which represented 113% 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 2024 was $3.88 per barrel, as compared to $2.83 per barrel in 2023. Our net average realized gas price during 2024 was $2.24 per Mcf, representing a 93% realization relative to the average NYMEX Henry Hub pricing, compared to a net average realized gas price of $2.98 per Mcf during 2023, which represented 112% realization relative to average NYMEX Henry Hub pricing. Fluctuations in our oil and 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 oil prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher. Lower oil 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 2023, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $9.5 million, compared to $8.0 million for the wells we elected to participate in during 2022.

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. 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 2024 and 2023, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $9.4 million and $9.5 million, respectively.

Previous wording

For 2023, the average NYMEX pricing was $77.61 per barrel of oil, or 18% lower than in 2022. Our average realized oil price before reflecting settled oil derivatives was $74.78 per barrel of oil in 2023. Our average realized oil price after reflecting settled oil derivatives was $73.88 per barrel of oil in 2023, or 5% higher than in 2022, due to a significantly smaller loss on settled oil derivatives in 2023 compared to 2022, partially offset by the lower average NYMEX price and a higher oil price differential.

Current wording

For 2024, the average NYMEX WTI pricing was $75.76 per barrel of oil, or 2% lower than the $77.61 average pricing in 2023. Our average realized oil price before reflecting settled oil derivatives was $71.59 per barrel of oil in 2024, as compared to $74.78 in 2023. Our average realized oil price after reflecting settled oil derivatives was $71.48 per barrel of oil in

Previous wording

For 2023, the average NYMEX pricing for natural gas was $2.66 per Mcf, or 59% lower than in 2022. Our average realized natural gas price before reflecting settled natural gas derivatives was $2.98 per Mcf in 2023. Our average realized natural gas price after reflecting settled natural gas derivatives was $3.90 per Mcf in 2023, or 33% lower than in 2022, due to the lower average NYMEX price, partially offset by a gain on settled natural gas derivatives in 2023 compared to a loss in 2022.

Current wording

For 2024, the average NYMEX Henry Hub pricing for natural gas was $2.41 per MMbtu, or 9% lower than the $2.66 per MMbtu price in 2023. Our average realized natural gas price before reflecting settled natural gas derivatives was $2.24 per Mcf in 2024, as compared to $2.98 per Mcf in 2023. Our average realized natural gas price after reflecting settled natural gas derivatives was $3.00 per Mcf in 2024, as compared to $3.90 per Mcf in 2023, representing a 23% decline year-over-year. The lower average realized natural gas price in 2024 is due to both a lower average NYMEX Henry Hub benchmark price and lower gain on settled natural gas derivatives in 2024 compared to 2023.

Previous wording

Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. In 2023, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, decreased 4% from 2022, driven by a 27% decrease in realized prices, excluding the effect of settled commodity derivatives, partially offset by a 31% increase in production volumes. The lower average realized price in 2023 as compared to 2022 was driven by lower average NYMEX oil and natural gas prices and slightly higher average oil price differential in 2023 as compared to 2022. Oil price differential during 2023 averaged $2.83 per barrel, as compared to $2.73 per barrel in 2022.

Current wording

Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. In 2024, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, increased 13% from 2023, driven by a 26% increase in production volumes, partially offset by a 10% decrease in realized prices on a per Boe basis, excluding the effect of settled commodity derivatives. The lower average realized price in 2024 as compared to 2023 was driven by lower average NYMEX oil and natural gas prices in 2024 as compared to 2023, in addition to higher average oil price differentials and lower gas price realizations to the NYMEX average natural gas price in 2024 as compared to 2023. Oil price differentials during 2024 averaged $3.88 per barrel, as compared to $2.83 per barrel in 2023. Gas price realizations in 2024 averaged 93% of the NYMEX average gas price, as compared to 112% in 2023

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. Our substantial acquisition activities in 2022 and 2023 (see Note 3 to our financial statements) helped drive the 31% increase in production levels in 2023 as compared to 2022. In addition, the number of net wells we added to production (excluding acquisitions) increased by 35% in 2023 as compared to 2022, due to our growing organic acreage footprint and increased development on our properties.

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. Our substantial acquisition activities in 2024 and 2023 (see Note 3 to our financial statements) helped drive the 26% increase in production levels in 2024 as compared to 2023. In addition, the number of net wells we added to production (excluding acquisitions) increased by 18% in 2024 as compared to 2023, due to our growing organic acreage footprint and increased development on our properties.

Previous wording

We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our gain (loss) on commodity derivatives, net was a gain of $259.3 million in 2023, compared to a loss of $415.3 million in 2022. Gain (loss) on commodity derivatives, net 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 $62.0 million in 2024, compared to a gain of $259.3 million in 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.

Previous wording

For 2023, we realized a gain on settled commodity derivatives of $57.9 million, compared to a $455.4 million loss in 2022. The increased gain on settled derivatives was primarily due to a significant decrease in the average NYMEX oil price in 2023 compared to 2022. The average NYMEX oil price for 2023 was $77.61 per barrel, compared to $94.38 per barrel for 2022. During 2023, our derivative settlements included 8.1 million barrels of oil subject to swaps at an average settlement price of $75.19 per barrel, and we had an additional 6.3 million barrels of oil hedged subject to collars. During 2022, our settled commodity derivatives included 10.9 million barrels of oil at an average settlement price of $62.52 per barrel. Our average realized price (including all commodity derivative cash settlements) in 2023 was $54.22 per Boe compared to $55.53 per Boe in 2022. The gain (loss) on settled commodity derivatives increased our average realized price per Boe by $1.61 in 2023 and decreased our average realized price per Boe by $16.52 in 2022. The percentage of oil production hedged under our derivative contracts was 65% and 68% in 2023 and 2022, respectively.

Current wording

During 2023, our derivative settlements included 8.1 million barrels of oil subject to swaps at an average settlement price of $75.19 per barrel, and we had an additional 6.3 million barrels of oil hedged subject to collars. Additionally, during 2023, our derivative settlements included 33.8 million MMBtu of gas subject to swaps at an average settlement price of $3.95 per MMBtu, and we had an additional 20.0 million MMBtu of gas hedged subject to collars. Our average realized price (including all commodity derivative cash settlements) in 2024 was $49.21 per Boe compared to $54.22 per Boe in 2023. The gain on settled commodity derivatives increased our average realized price per Boe by $1.83 and $1.61 in 2024 and 2023, respectively. The percentage of oil production hedged under our derivative contracts was 73% and 65% in 2024 and 2023, respectively.

Previous wording

Unsettled commodity derivative gains and losses was a gain of $201.3 million in 2023 compared to a gain of $40.2 million in 2022. 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 December 31, 2023, all of our derivative contracts are recorded at their fair value, which was a net liability of $36.2 million, a change of $200.3 million from the $236.5 million net liability recorded as of December 31, 2022. The decrease in the net liability at December 31, 2023 as compared to December 31, 2022 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2022. Our open commodity derivative contracts are summarized in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Current wording

The Company had unsettled commodity derivative losses of $21.3 million in 2024, compared to a gain of $201.3 million in 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 December 31, 2024, all of our derivative contracts were recorded at their fair value, which was a net liability of $57.2 million, a change of $21.0 million from the $36.2 million net liability recorded as of December 31, 2023. The increase in the net liability at December 31, 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 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Previous wording

Production expenses were $347.0 million in 2023 compared to $260.7 million in 2022. On a per unit basis, production expenses increased 2%, from $9.46 per Boe in 2022 to $9.62 per Boe in 2023, due to higher service and maintenance costs and higher workover expenses, which was partially offset by lower processing costs associated with a change in our production mix. On an absolute dollar basis, the 33% increase in our production expenses in 2023 compared to 2022 was primarily due to a 31% increase in production volumes and a 2% increase in per unit costs.

Current wording

Production expenses were $429.8 million in 2024, compared to $347.0 million in 2023. On a per unit basis, production expenses decreased 2%, from $9.62 per Boe in 2023 to $9.46 per Boe in 2024, due to higher production volumes in 2024. On an absolute dollar basis, production expenses increased 24% in 2024 compared to 2023, primarily due to a 26% increase in production volumes partially caused by an 18% increase in net wells.

Previous wording

We pay production taxes based on realized oil and natural gas sales. Production taxes were $160.1 million in 2023 compared to $158.2 million in 2022. The increase is due to higher production and a higher oil cut percentage, offset by the significantly lower realized prices and the change in our geographical production mix. As a percentage of oil and natural gas sales, our production taxes were 8.4% and 8.0% in 2023 and 2022, respectively. The fluctuation in our average production tax rate from year to year is primarily due to changes in our oil sales as a percentage of our total oil and gas sales, as well as the mix of our production by basin. Oil sales are taxed at a higher rate than natural gas sales.

Current wording

We pay production taxes based on realized oil and natural gas sales. Production taxes were $157.1 million in 2024, compared to $160.1 million in 2023. As a percentage of oil and natural gas sales, our production taxes were 7.3% and 8.4% in 2024 and 2023, respectively. The fluctuation in our average production tax rate from year to year is primarily due to our oil and gas sales mix by basin and to certain out-of-period adjustments made to production taxes, as discussed under the heading “Out-of-Period Adjustments” in Note 2 to the financial statements.

Previous wording

General and administrative expenses were $46.8 million for 2023 compared to $47.2 million for 2022. The decrease in 2023 compared to 2022 was primarily due to a $5.3 million decrease in acquisition costs, partially offset by a $2.5 million increase in professional fees and a $1.2 million increase in compensation costs.

Current wording

General and administrative expenses were $50.5 million for 2024, compared to $46.8 million for 2023. The increase in 2024 compared to 2023 was driven in part by an increase in professional fees and employee compensation to support the Company’s growth, partially offset by lower acquisition-related costs.

Previous wording

Depletion, depreciation, amortization and accretion (“DD&A”) was $486.0 million in 2023 compared to $251.3 million in 2022. The aggregate increase in DD&A expense for 2023 compared to 2022 was driven by a 31% increase in production levels and a 48% increase in the depletion rate per Boe. The increase in depletion rate per Boe for 2023 as compared to 2022 was primarily due to a significant increase to our depletable base, due to the closing of several larger acquisitions in 2022 and 2023 (see Note 3 to our financial statements). The following table summarizes DD&A expense per Boe for 2023 and 2022:

Current wording

Depletion, depreciation, amortization and accretion (“DD&A”) was $740.9 million in 2024, compared to $486.0 million in 2023. The aggregate increase in DD&A expense for 2024 compared to 2023 was driven by a 26% increase in production levels and a 21% increase in the depletion rate per Boe. The increase in depletion rate per Boe for 2024 as compared to 2023 was primarily due to a significant increase to our depletable cost base, due to the closing of several larger acquisitions in 2023 and 2024 (see Note 3 to our financial statements). The following table summarizes DD&A expense per Boe for 2024 and 2023:

Previous wording

Interest expense, net of capitalized interest, was $135.7 million in 2023 compared to $80.3 million in 2022. The increase in interest expense for 2023 as compared to 2022 was primarily due to higher levels of debt and higher weighted-average interest rates on debt outstanding during 2023 compared to 2022.

Current wording

Interest expense, net of capitalized interest, was $157.7 million in 2024, compared to $135.7 million in 2023. The increase in interest expense for 2024 as compared to 2023 was primarily due to higher levels of debt pursuant to borrowings to fund the Company’s acquisition activities in 2024. See Note 3 for further information.

Previous wording

We have incurred contingent consideration liabilities in connection with certain acquisitions of oil and gas properties. During the years ended December 31, 2023 and 2022, we recorded a contingent consideration gain of $10.1 million compared to a gain of $1.9 million, respectively, due to the change in the fair value of these liabilities. As of December 31, 2023, there were no remaining outstanding contingent consideration liabilities.

Current wording

In 2023, we recorded a contingent consideration gain of $10.1 million due to the change in the fair value of certain contingent consideration liabilities previously recorded pursuant to certain acquisitions of oil and natural gas properties. As of December 31, 2024, there were no remaining outstanding contingent consideration liabilities.

Previous wording

During 2023, we recorded income tax expense of $77.8 million related to federal and state income taxes as a result of the release of the majority of our valuation allowance during the period. During 2022, we recorded income tax expense of $3.1 million related to state income taxes as the Company maintained a full valuation allowance for its deferred tax assets. The effective tax rate for 2023 was 7.8% compared to an effective tax rate of 0.4% for 2022. The difference was due primarily to the release of our full valuation allowance and recording of deferred tax liabilities in 2023.

Current wording

During 2024, we recorded income tax expense of $160.5 million related to federal and state income taxes, as compared to $77.8 million in 2023. The effective tax rate for 2024 was 23.6% compared to an effective tax rate of 7.8% for 2023. The increase in income tax expense in 2024 is primarily due to the release of our valuation allowance during the second quarter of 2023.

Previous wording

We completed over $1.0 billion in substantial bolt-on acquisitions that closed during 2023 (see Note 3 to our financial statements). We financed these acquisitions with a combination of debt and equity financings, credit facility borrowings, and internally generated cash flow from operations.

Current wording

We completed over $883.5 million in substantial bolt-on acquisitions that closed during 2024 (see Note 3 to our financial statements). We financed these acquisitions with a combination of credit facility borrowings, equity consideration and internally generated cash flow from operations.

Previous wording

As of December 31, 2023, we had outstanding debt consisting of $161.0 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, and $500.0 million aggregate principal amount of our Senior Notes due 2031. We had total liquidity of $1,097.2 million as of December 31, 2023, consisting of $1,089.0 million of committed borrowing availability under the Revolving Credit Facility and $8.2 million of cash on hand.

Current wording

As of December 31, 2024, we had outstanding total debt consisting of $690.0 million of borrowings under our Revolving Credit Facility, $705.1 million aggregate principal amount of our Senior Notes due 2028 (as defined herein), $500.0 million aggregate principal amount of our Senior Notes due 2031 (as defined herein), and $500.0 million aggregate principal amount of our Convertible Notes due 2029 (as defined herein).

Previous wording

One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 87% and 74% of our total oil and gas sales in 2023 and 2022, 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 years ended 2023 and 2022, we hedged approximately 65% and 68% of our crude oil production, respectively. For a summary as of December 31, 2023, of our open commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.

Current wording

One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 88% and 87% of our total oil and gas sales in 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 years ended 2024 and 2023, we hedged approximately 73% and 65% of our crude oil production, respectively, and approximately 63% and 64% of our natural gas production, respectively. For a summary as of December 31, 2024, of our open commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.

Previous wording

Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, collection of receivables, expenditures related to our development and production operations and the impact of our outstanding derivative instruments. At December 31, 2023, we had a working capital surplus of $123.6 million, compared to a deficit of $24.5 million at December 31, 2022. Current assets increased by $188.9 million and current liabilities increased by $40.8 million at December 31, 2023 as compared to December 31, 2022.

Current wording

Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, collection of receivables, expenditures related to our development and production operations and the impact of our outstanding derivative instruments. At December 31, 2024, we had a working capital deficit of $43.5 million, compared to a surplus of $123.6 million at December 31, 2023. Current assets decreased by $8.7 million and current liabilities increased by $158.5 million at December 31, 2024, as compared to December 31, 2023.

Previous wording

The $188.9 million increase in current assets in 2023 as compared to 2022 was driven by a $99.2 million increase in accounts receivable, primarily due to higher production levels, and a $40.4 million increase in derivative instruments due to the change in fair value as a result of commodity price changes.

Current wording

The $8.7 million decrease in current assets in 2024 as compared to 2023 was primarily driven by a $29.2 million decrease in derivative instruments and a $36.9 million decrease in advances to operators, partially offset by a $19.1 million increase in accounts receivable and a $34.8 million increase in income tax receivable.

Previous wording

The $40.8 million increase in current liabilities in 2023 as compared to 2022 was driven by a $90.3 million increase in accounts payable and accrued liabilities, primarily as a result of increased development activity, and a $1.9 million increase in accrued interest. These increases were partially offset by a $41.6 million decrease in our derivative instruments as a result of commodity price changes and a $10.1 million decrease in contingent consideration liabilities related to our acquisition activities (see Note 3 to our financial statements).

Current wording

The $158.5 million increase in current liabilities in 2024 as compared to 2023 was primarily due to a $155.6 million increase in accounts payable and accrued liabilities, primarily as a result of increased development activity, and a $3.1 million increase in derivative instruments.

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 24 months. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”

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 “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”

Previous wording

Net cash provided by operating activities in 2023 was $1,183.3 million, compared to $928.4 million in 2022. This increase was driven by a 31% year-over-year increase in production levels and a 5% increase in our realized oil price after the effect of settled derivatives, which was partially offset by an increase in production expenses. Net cash provided by operating activities is also 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 year ended December 31, 2023 was a deficit of $106.1 million compared to a deficit of $62.4 million in 2022.

Current wording

Net cash provided by operating activities in 2024 was $1.4 billion, compared to $1.2 billion in 2023. This increase was driven by an increase in production volumes, partially offset by lower average realized commodity prices and higher operating and interest 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 year ended December 31, 2024 was a deficit of $53.9 million compared to a deficit of $106.1 million in 2023.

Previous wording

We had cash flows used in investing activities of $1,862.3 million and $1,402.8 million during the years ended December 31, 2023 and 2022, respectively, primarily as a result of our capital expenditures for drilling, development and acquisition costs. The year-over-year increase in cash used in investing activities in 2023 was mainly attributable to our 2023 acquisitions. In addition, cash flows used in investing activities included a $17.1 million acquisition deposit for an acquisition that was pending at year-end 2023. During 2023 and 2022, we added 76.6 and 56.8 net wells to production, respectively, excluding already producing wells from acquisitions.

Current wording

We had cash flows used in investing activities of $1.7 billion and $1.9 billion during the years ended December 31, 2024 and 2023, respectively, primarily as a result of our capital expenditures for drilling, development and acquisition costs. During 2024 and 2023, we added 90.7 and 76.6 net wells to production, respectively, excluding already producing wells from acquisitions.

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 year ended December 31, 2023, 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 $1,925.9 million, while the actual cash spend in this regard amounted to $1,861.1 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 year ended December 31, 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 $1.9 billion, while the actual cash spend in this regard amounted to $1.7 billion.

Previous wording

Net cash provided by financing activities was $684.7 million and $467.4 million for the years ended December 31, 2023 and 2022, respectively. The cash provided by financing activities in 2023 was primarily related to the issuance of the Senior Notes due 2031 of $492.8 million and the issuance of common stock of $514.7 million, which was partially offset by $8.0 million in repurchases of common stock, $18.4 million in repurchases of our Senior Notes due 2028, and $158.0 million of net repayments on our Revolving Credit Facility. Additionally, we paid common stock dividends of $123.9 million and spent $11.9 million in fees in connection with debt financing transactions in 2023.

Current wording

The cash provided by financing activities in 2023 was primarily related to the issuance of the Senior Notes due 2031 of $492.8 million and the issuance of common stock of $514.7 million, which was partially offset by $8.0 million in repurchases of common stock, $18.4 million in repurchases of our Senior Notes due 2028, and $158.0 million of net repayments on our Revolving Credit Facility. Additionally, we paid common stock dividends of $123.9 million and spent $11.9 million in fees in connection with debt financing transactions in 2023.

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”). 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 December 31, 2023, the Revolving Credit Facility had a borrowing base of $1.8 billion and an elected commitment amount of $1.25 billion, and we had $161.0 million in borrowings outstanding under the facility, leaving $1,089.0 million in available committed borrowing capacity. See Note 4 to our 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”). 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 December 31, 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 $690.0 million in borrowings outstanding under the facility, leaving $810.0 million in available committed borrowing capacity. See Note 4 to our financial statements for further details regarding the Revolving Credit Facility.

Previous wording

As of December 31, 2023, we had outstanding $705.1 million aggregate principal amount of our 8.125% senior notes due 2028. See Note 4 to our financial statements for further details regarding the Senior Notes due 2028.

Current wording

As of December 31, 2024, we had outstanding $705.1 million aggregate principal amount of our Senior Notes due 2028. See Note 4 to our financial statements for further details regarding the Senior Notes due 2028.

Previous wording

As of December 31, 2023, we had outstanding $500.0 million aggregate principal amount of our 8.750% senior notes due 2031. See Note 4 to our financial statements for further details regarding the Senior Notes due 2031.

Current wording

As of December 31, 2024, we had outstanding $500.0 million aggregate principal amount of our Senior Notes due 2031. See Note 4 to our financial statements for further details regarding the Senior Notes due 2031.

Previous wording

Contractual and Other Obligations. We have contractual commitments under our debt agreements, including interest payments and principal repayments. See Note 4 to our financial statements. We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 12 to our financial statements. We have firm commitments on certain assets that we assumed in our April 2021 acquisition of natural gas properties in the Appalachian Basin. See “Item 2—Properties—Delivery Commitments” above. We have future obligations related to the abandonment of our oil and natural gas properties. See Note 9 to our financial statements. With respect to all of these items, except for our commitments under our debt agreements, we cannot determine with accuracy the amount and/or timing of such payments.

Current wording

Contractual and Other Obligations. We have contractual commitments under our debt agreements, including interest payments and principal repayments. See Note 4 to our financial statements. We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 12 to our financial statements. We have firm commitments on certain assets that we assumed in our April 2021 acquisition of natural gas properties in the Appalachian Basin. See “Item 2—Properties—Delivery Commitments” above. We have future obligations related to the abandonment of our oil and natural gas properties. See Note 9 to our financial statements. With respect to all of these items, except for our commitments under our debt agreements, we cannot determine with accuracy the amount and/or timing of such payments. Further, we have contractual commitments under a Joint Development Agreement with an unaffiliated operator to develop certain oil and natural properties in Appalachia. See Note 8 to our financial statements.