What changed in this filing

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Item 7. Management’s Discussion and Analysis

2025-02-20 compared with 2024-02-23 · 120 added, 133 removed, 304 unchanged (45% of the section changed)

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Executive Overview

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.

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.

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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 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.

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.

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.

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• Cash flows from operations of $1.4 billion, a 19% increase compared to 2023

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

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

• Grew our quarterly common stock dividend by 33%, from $0.30 per share for the fourth quarter of 2022 to $0.40 per share for the fourth quarter of 2023

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

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

• Grew our total quarterly common stock dividends by 10%, from $1.49 per share total during 2023 to $1.64 per share total during 2024

• Provided returns to shareholders totaling approximately $256.5 million, comprised of $162.0 million in common stock dividend payments and $94.5 million in repurchases of common stock.

Source of Our Revenues

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Production expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties.

Such costs also include

field personnel compensation, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties.

Such costs also include field personnel compensation, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties.

• Production taxes.

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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.

• 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.

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.

• Income tax expense.

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• the level of our operating expenses.

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.

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.

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.

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.

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.

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 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.

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.

Market Conditions

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Oil (per Bbl) $ 75.76 $ 77.61

Natural Gas (per Mcf) 2.66 6.56

Natural Gas (per MMbtu) 2.41 2.66

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(1) Based on average NYMEX closing prices.

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.

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.

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

2024, as compared to $73.88 in 2023, representing a 3% decline year-over-year.

The lower average realized oil price in 2024 is due to a lower average NYMEX WTI benchmark price in 2024 compared to 2023, partially offset by a lower average loss on settled oil derivatives.

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.

We have entered into derivatives contracts to hedge commodity price risk on a portion of our future expected oil and natural gas production.

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Net Production:

Oil (Bbl) 22,012,986 16,090,072

Natural Gas and NGLs (Mcf) 84,341,858 68,829,142

Total (Boe) 36,069,962 27,561,596

Oil (MBbl) 26,511 22,013

Natural Gas (MMcf) 113,476 84,342

Total (MBoe) 45,423 36,070

Net Sales (in thousands):

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Natural Gas and NGL Sales 254,222 251,683

Gain (Loss) on Settled Commodity Derivatives 57,919 (455,450)

Gain on Unsettled Commodity Derivatives 201,331 40,187

Gain on Settled Commodity Derivatives 83,225 57,919

Gain (Loss) on Unsettled Commodity Derivatives (21,258) 201,331

Other Revenue 11,683 9,230

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Natural Gas and NGLs (per Mcf) 2.24 2.98

Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.92 (1.60)

Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) 3.90 5.83

Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.76 0.92

Natural Gas and NGLs, Net of Settled Natural Gas and NGL Derivatives (per Mcf) 3.00 3.90

Realized Price on a Boe Basis Excluding Settled Commodity Derivatives 47.38 52.61

Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) 1.61 (16.52)

Effect of Gain on Settled Commodity Derivatives on Average Price (per Boe) 1.83 1.61

Realized Price on a Boe Basis Including Settled Commodity Derivatives 49.21 54.22

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Depletion, Depreciation, Amortization and Accretion 740,901 486,024

Other Expenses 4,448 —

Other Expense 9,650 4,448

Costs and Expenses (per Boe):

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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.

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

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.

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Year Ended December 31,

Oil (Bbl) 22,012,986 16,090,072

Natural Gas and NGL (Mcf) 84,341,858 68,829,142

Total (Boe) (1)

Oil (MBbl) 26,511 22,013

Natural Gas and NGL (MMcf) 113,476 84,342

Total (MBoe) (1)

45,423 36,070

Average Daily Production:

Oil (Bbl) 60,310 44,082

Natural Gas and NGL (Mcf) 231,074 188,573

Total (Boe) (1)

98,822 75,511

Oil (MBbl) 72 60

Natural Gas (MMcf) 310 231

Total (MBoe) (1)

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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.

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.

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.

For 2024, we realized a gain on settled commodity derivatives of $83.2 million, compared to a $57.9 million gain in 2023.

The increased gain on settled derivatives was primarily due to a decrease in the average NYMEX oil and continued depressed NYMEX gas price in 2024 compared to 2023.

The average NYMEX oil price for 2024 was $75.76 per barrel, compared to $77.61 per barrel for 2023.

Further, the average NYMEX Henry Hub gas price for 2024 was 2.41 per Mcf, compared to 2.66 per Mcf for 2023.

During 2024, our derivative settlements included 10.5 million barrels of oil subject to swaps at an average settlement price of $74.93 per barrel, and we had an additional 8.9 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.

Additionally, during 2024, our derivative settlements included 41.7 million MMBtu of natural gas subject to swaps at an average settlement price of $3.50 per MMBtu, and we had an additional 29.6 million MMBtu of natural gas hedged subject to collars.

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 (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 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.

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.

The Company had unsettled commodity derivative losses of $21.3 million in 2024, compared to a gain of $201.3 million in 2023.

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.

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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.

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.

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Production expenses were $429.8 million in 2024, compared to $347.0 million in 2023.

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.

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.

Production Taxes

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Production taxes were $157.1 million in 2024, compared to $160.1 million in 2023.

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 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 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.

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.

General and Administrative Expenses

General and administrative expenses were $50.5 million for 2024, compared to $46.8 million for 2023.

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.

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.

Depletion, Depreciation, Amortization and Accretion

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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 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 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:

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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 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.

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.

Contingent Consideration Gain (Loss)

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.

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.

Income Tax Expense

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.

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 difference was due primarily to the release of our full valuation allowance and recording of deferred tax liabilities in 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.

Liquidity and Capital Resources

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We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

In May 2023, we issued $500.0 million in aggregate principal amount of Senior Notes due 2031, the proceeds of which were used primarily to refinance existing indebtedness, and for general corporate purposes.

In May 2023, we closed an underwritten public offering of 7,647,500 shares of our common stock at a price of $29.40 per share, after deducting underwriting discounts.

This offering resulted in net proceeds of approximately $224.7 million, after deducting underwriting discounts and commissions, which were used primarily to finance the cash consideration for the acquisition of Delaware Basin assets from Forge Energy II Delaware, LLC.

In October 2023, we closed an underwritten public offering of 7,475,000 shares of our common stock at a price of $38.88 per share, after deducting underwriting discounts.

This offering resulted in net proceeds of approximately $290.6 million, after deducting underwriting discounts and commissions, which were primarily used for the repayment of existing indebtedness, and for general corporate purposes.

During 2023, we repurchased and retired (i) 287,751 shares of our common stock for total consideration of $8.0 million and (ii) $19.1 million aggregate principal amount of our Senior Notes due 2028 for total consideration of $18.4 million, plus accrued and unpaid interest.

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.

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.

During 2024, we repurchased and retired 2,535,391 shares of our common stock for total consideration of $95.4 million, or an average price of $37.27 per share excluding excise taxes.

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.

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).

As of December 31, 2024, we had total liquidity of $818.9 million, consisting of $810.0 million of committed borrowing availability under the Revolving Credit Facility and $8.9 million of cash on hand.

One of the primary sources of variability in our cash flows from operating activities is commodity price volatility.

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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.

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.

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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.

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.

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).

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.

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.

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.

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.

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Net Cash Provided by Financing Activities 266,829 684,692

Net Change in Cash $ 5,667 $ (6,992)

Net Increase in Cash $ 738 $ 5,667

Cash Flows from Operating Activities

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.

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.

Cash Flows from Investing Activities

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.

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.

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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.

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.

Development and acquisition activities are discretionary.

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Net cash provided by financing activities was $266.8 million and $684.7 million for the years ended December 31, 2024 and 2023, respectively.

The cash provided by financing activities in 2024 was primarily related to $984.0 million in increased borrowings under our Revolving Credit Facility, partially offset by $455.0 million in repayments of borrowing under our Revolving Credit Facility, $94.5 million in repurchases of common stock, and $162.0 million in dividend payments to holders of our common stock.

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.

The cash provided by financing activities in 2022 was primarily related to $264.0 million of net advances under our Revolving Credit Facility and issuance of Convertible Notes of $483.0 million, which was partially offset by $81.2 million in repurchases of our 6.500 % Series A Perpetual Cumulative Convertible Preferred Stock (the “Series A Preferred Stock”), $54.5 million in repurchases of common stock, $24.9 million in repurchases of our Senior Notes due 2028, and $36.1 million of capped call purchases related to the issuance of our Convertible Notes.

Additionally, we paid common and preferred stock dividends of $51.6 million and $21.7 million, respectively, and spent $7.4 million in fees in connection with debt financing transactions in 2022.

Revolving Credit Facility

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.

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.

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See Note 4 to our financial statements for further details regarding the Senior Notes due 2028.

Convertible Notes due 2029

As of December 31, 2023, we had outstanding $500.0 million aggregate principal amount of our Convertible Notes.

See Note 4 to our financial statements for further details regarding the Convertible Notes.

Senior Notes due 2031

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See Note 4 to our financial statements for further details regarding the Senior Notes due 2031.

Series A Preferred Stock

In November 2022, we exercised in full our mandatory conversion rights on the Series A Preferred Stock.

All outstanding shares of Series A Preferred Stock automatically converted into shares of common stock on November 15, 2022.

As of December 31, 2023, we h ad no outsta nding shares of Series A Preferred Stock.

See Note 5 to our financial statements for further details regarding the Series A Preferred Stock and the mandatory conversion.

Convertible Notes due 2029

As of December 31, 2024, we had outstanding $500.0 million aggregate principal amount of our Convertible Notes.

See Note 4 to our financial statements for further details regarding the Convertible Notes.

Known Contractual and Other Obligations;

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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.

Planned Capital Expenditures.

For 2024, we are budgeting approximately $825 to $900 million in total planned capital expenditures, including development expenditures and our smaller day-to-day acquisition activity, which we refer to as our “ground game” acquisition activity.

For 2025, we are budgeting approximately $1.05 billion to $1.20 billion in total planned capital expenditures, including development expenditures and our smaller day-to-day acquisition activity, which we refer to as our “ground game” acquisition activity.

As of December 31, 2024, we had incurred $331.0 million in capital expenditures that were included in accounts payable and accrued liabilities, and we estimate that we were committed to an additional approximately $376.9 million in development capital expenditures not yet incurred for wells we had elected to participate in.

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In May 2022, the Company’s board of directors approved a stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock.

In July 2024, the Company’s board of directors terminated the prior stock repurchase program, and approved a new stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock.

The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions.

During the year ended December 31, 2023 the Company repurchased 287,751 shares of its common stock under the stock repurchase program at a total cost of $8.0 million.

During the year ended December 31, 2023, the Company also repurchased and retired $19.1 million in aggregate principal amount of the Senior Notes due 2028 in open market transactions for a total of $18.4 million in cash, plus accrued interest.

During the year ended December 31, 2024 the Company repurchased 2,535,391 shares of its common stock under the stock repurchase programs at a total cost of $95.4 million (including commissions and $0.9 million in excise tax).

The Company may in the future engage in similar transactions.

The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors.

If oil, NGL and natural gas prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow.

If oil, natural gas and NGL prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow.

We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive.

We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs,

fluctuations in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

For additional information on the impact of changing prices and market conditions on our financial position, see “Item 7A.

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To the extent capital requirements exceed internal cash flow and borrowing capacity under our Revolving Credit Facility, additional financings from the capital markets may be pursued to fund these requirements.

We monitor our capital expenditures on a regular basis, adjusting the amount up or down and also between our projects, depending on commodity prices, cash flow and projected returns.

We monitor our capital expenditures

on a regular basis, adjusting the amount up or down and also between our projects, depending on commodity prices, cash flow and projected returns.

Also, our obligations may change due to acquisitions, divestitures and continued growth.

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The determination of depreciation, depletion and amortization expense as well as impairments that are recognized on our oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties.

Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and

engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions.

Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions.

The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment.

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These revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in oil and natural gas prices.

Our third-party independent reserve engineers, Cawley, Gillespie & Associates, Inc., audited 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2023.

Our third-party independent reserve engineers, Cawley, audited 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2024.

Our estimates of proved reserves quantities were prepared in accordance with the rules promulgated by the SEC.

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For the year ended December 31, 2024, our average depletion expense per unit of production w as $16.22 per Boe.

To the extent the capitalized costs in our full cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the sum of the present value (using a 10% discount rate and based on 12-month/SEC oil and natural gas prices) of the estimated future net cash flows from our proved oil and natural gas reserves and the capitalized cost associated with our unproved properties, we would have a capitalized ceiling impairment.

Such costs would be charged to operations as a reduction of the carrying value of oil and natural gas properties.

Such impairment costs would be charged to operations as a reduction of the carrying value of oil and natural gas properties.

The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are depressed, even if the low prices are temporary.

In addition, capitalized ceiling impairment charges may occur if we experience poor drilling results or if

estimations of our proved reserves are substantially reduced.

In addition, capitalized ceiling impairment charges may occur if we experience poor drilling results or if estimations of our proved reserves are substantially reduced.

A capitalized ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and stockholders’ equity.

Once recognized, a capitalized ceiling impairment charge to oil and natural gas properties cannot be reversed at a later date.

The risk that we will experience a ceiling test writedown increases when oil and natural gas prices are depressed or if we have substantial downward revisions in our estimated proved reserves.

Once recognized, a ceiling impairment charge to oil and natural gas properties cannot be reversed at a later date.

At December 31, 2024, we performed an impairment review using prices that reflect an average of 2024’s monthly prices as prescribed pursuant to the SEC’s guidelines.

We did not record any full cost impairment expense for the years ended December 31, 2024 or 2023.

If a low price environment reoccurs, we might be required to write down the value of our oil and gas properties.

In addition, capitalized ceiling impairment charges may occur if estimates of proved reserves are substantially reduced or estimates of future development costs increase significantly.

Properties” for a discussion of our reserve estimation assumptions.

Average commodity prices have declined in recent months.

Derivative Instrument Activities

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All derivative positions are carried at their fair value in the balance sheet and are marked-to-market at the end of each period.

Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net on the statements of operations rather than as a component of accumulated other comprehensive income or other income (expense).

Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses on unsettled derivatives, are aggregated and recorded to gain (loss) on derivative instruments, net on the statements of operations rather than as a component of accumulated other comprehensive income or other income (expense).

The resulting cash flows from derivatives are reported as cash flows from operating activities.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis