NORTHERN OIL & GAS, INC. (NOG)

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with our financial statements and accompanying notes to financial statements appearing elsewhere in this report. See Item 7., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2023 for discussion and analysis of results of operations for the year ended December 31, 2022.

Executive Overview

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.

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.

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.

Our financial and operating performance for the year ended December 31, 2024 included the following:

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

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

We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties.  Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market.  We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil and natural gas production.  We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations.  The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.

Principal Components of Our Cost Structure

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

•Gain (loss) on commodity derivatives, net.  We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas. Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end.

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•Production expenses.  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.

•Production taxes.  Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.

•Depreciation, depletion, amortization and accretion.  Depreciation, depletion, amortization and accretion includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method. Accretion expense relates to the passage of time of our asset retirement obligations.

•General and administrative expenses.  General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance.

•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.

•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.

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

Selected Factors That Affect Our Operating Results

Our revenues, cash flows from operations and future growth depend substantially upon:

•the timing and success of drilling and production activities by our operating partners;

•the prices and the supply and demand for oil, natural gas and NGLs;

•the quantity of oil and natural gas production from the wells in which we participate;

•changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in commodity prices;

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

•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, 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 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.

Market Conditions

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

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows.  The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2024 and 2023.

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(1)Based on average NYMEX closing prices.

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

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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. For a summary as of December 31, 2024, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in Item 7A below. See also Note 12 to our financial statements.

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Results of Operations for 2024 and 2023

The following table sets forth selected operating data for the periods indicated.  Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.

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Oil and Natural Gas Sales

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

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.

Our production for the last two years is set forth in the following table:

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(1)Natural gas and NGLs are converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.

Commodity Derivative Instruments

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.

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. 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.

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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.

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.”

Production Expenses

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.

Production Taxes

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.

General and Administrative Expenses

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.

Depletion, Depreciation, Amortization and Accretion

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:

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Interest Expense

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.

Contingent Consideration Gain (Loss)

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 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.

Liquidity and Capital Resources

Overview

Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations, proceeds from equity and debt financings, credit facility borrowings and cash settlements of commodity derivative instruments.  Our primary uses of capital have been for the acquisition, development and operation of our oil and natural gas properties, cash settlements of commodity derivative instruments and for stockholder returns. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

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. 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

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commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.

With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months and, based on current expectations, for the foreseeable future. However, we may seek additional access to capital and liquidity.  We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all.

Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility.  Our capital expenditures could be curtailed if our cash flows decline from expected levels.  Because production from existing oil and natural gas wells declines over time, reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future.

Working Capital

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.

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

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.”

Our cash flows for the years ended December 31, 2024 and 2023 are presented below:

Cash Flows from Operating Activities

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.

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Cash Flows from Investing Activities

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.

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.

Development and acquisition activities are discretionary.  We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the years ended December 31, 2024 and 2023 are summarized in the following table:

Cash Flows from Financing Activities

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.

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 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.

Senior Notes due 2028

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.

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Senior Notes due 2031

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.

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; Planned Capital Expenditures

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.

Planned Capital Expenditures. 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. We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Revolving Credit Facility. The foregoing excludes larger acquisitions, which are typically not included in our annual capital expenditure budget. See also “Capital Requirements” below.

Capital Stock and Debt Security Repurchases. 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, 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, 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. Quantitative and Qualitative Disclosures About Market Risk.”

Capital Requirements

Development and acquisition activities are discretionary, and, for the near term, we expect such activities to be maintained at levels we can fund through cash on hand, internal cash flow and borrowings under our Revolving Credit Facility.  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

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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.  Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital.  If internally generated cash flow and borrowing capacity under our Revolving Credit Facility are not available or sufficient, we may issue additional equity or debt to fund capital expenditures, make acquisitions, extend maturities or to repay debt.

Satisfaction of Our Cash Obligations for the Next Twelve Months

With our Revolving Credit Facility and our cash flows from operations, we believe we will have sufficient capital to meet our drilling commitments, expected general and administrative expenses and other cash needs for the next twelve months and, based on current expectations, for the foreseeable future. Nonetheless, any strategic acquisition of assets or increase in drilling activity may lead us to seek additional capital.  We may also choose to seek additional capital rather than utilize our Revolving Credit Facility or other debt instruments to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions.  We will evaluate any potential opportunities for acquisitions as they arise.  However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.

Effects of Inflation and Pricing

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

Critical Accounting Estimates

The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our financial statements in accordance with generally accepted accounting principles in the United States (GAAP), as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions.

Use of Estimates

The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect our reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Our estimates of our proved oil and natural gas reserves, future development costs, estimates relating to certain oil and natural gas revenues and expenses, and fair value of derivative instruments are the most critical to our financial statements.

Oil and Natural Gas Reserves

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.  The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment.  For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change.  Approximately 27% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserve, future cash flows from our reserves, and future development of our proved undeveloped reserves.

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The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties.  Such information includes revisions of certain reserve estimates attributable to our properties included in the prior year’s estimates.  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, 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. In connection with our external petroleum engineers performing their independent reserve audits, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests.

Oil and Natural Gas Properties

The method of accounting we use to account for our oil and natural gas investments determines what costs are capitalized and how these costs are ultimately matched with revenues and expensed.

We utilize the full cost method of accounting to account for our oil and natural gas investments instead of the successful efforts method because we believe it more accurately reflects the underlying economics of our programs to explore and develop oil and natural gas reserves. The full cost method embraces the concept that dry holes and other expenditures that fail to add reserves are intrinsic to the oil and natural gas exploration business. Thus, under the full cost method, all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs, geological and geophysical costs that are directly attributable to the properties and capitalized interest. Although some of these costs will ultimately result in no additional reserves, they are part of a program from which we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. The full cost method differs from the successful efforts method of accounting for oil and natural gas investments. The primary difference between these two methods is the treatment of exploratory dry hole costs. These costs are generally expensed under the successful efforts method when it is determined that measurable reserves do not exist. Geological and geophysical costs are also expensed under the successful efforts method. Under the full cost method, both dry hole costs and geological and geophysical costs are initially capitalized and classified as unproved properties pending determination of proved reserves. If no proved reserves are discovered, these costs are then amortized with all the costs in the full cost pool.

Capitalized amounts except unproved costs are depleted using the units of production method.  The depletion expense per unit of production is the ratio of the sum of our unamortized historical costs and estimated future development costs to our proved reserve volumes.  Estimation of hydrocarbon reserves relies on professional judgment and use of factors that cannot be precisely determined.  Subsequent reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting periods.  For the year ended December 31, 2024, our average depletion expense per unit of production was $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 non-cash ceiling impairment. 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.  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 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. 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.

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Derivative Instrument Activities

We use derivative instruments from time to time to manage market risks resulting primarily from fluctuations in the prices of oil and natural gas.  We may periodically enter into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.  The notional amounts of these financial instruments are based on expected production from existing wells.  We may also use exchange traded futures contracts and option contracts to hedge the delivery price of oil at a future date.

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 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. See Note 12 to our financial statements for a description of the derivative contracts.

Recently Issued or Adopted Accounting Pronouncements

For discussion of recently issued or adopted accounting pronouncements, see Notes to Financial Statements—Note 2. Significant Accounting Policies.

Off-Balance Sheet Arrangements

We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with our financial statements and accompanying notes to financial statements appearing elsewhere in this report. See Item 7., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2022 for discussion and analysis of results of operations for the year ended December 31, 2021.

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. 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.

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.

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.

Our financial and operating performance for the year ended December 31, 2023 included the following:

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

•Cash flows from operations of $1.2 billion, a 27% increase compared to 2022

•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

Source of Our Revenues

We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties.  Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market.  We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil and natural gas production.  We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations.  The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.

Principal Components of Our Cost Structure

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

•Gain (loss) on commodity derivatives, net.  We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas. Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end.

•Production expenses.  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

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

•Production taxes.  Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.

•Depreciation, depletion, amortization and accretion.  Depreciation, depletion, amortization and accretion includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method. Accretion expense relates to the passage of time of our asset retirement obligations.

•General and administrative expenses.  General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance.

•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.

•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.

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

Selected Factors That Affect Our Operating Results

Our revenues, cash flows from operations and future growth depend substantially upon:

•the timing and success of drilling and production activities by our operating partners;

•the prices and the supply and demand for oil, natural gas and NGLs;

•the quantity of oil and natural gas production from the wells in which we participate;

•changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in commodity prices;

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

•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

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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.

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.

Market Conditions

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

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows.  The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2023 and 2022.

________________________

(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.

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We have entered into derivatives contracts to hedge commodity price risk on a portion of our future expected oil and natural gas production. For a summary as of December 31, 2023, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in Item 7A below. See also Note 12 to our financial statements.

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Results of Operations for 2023 and 2022

The following table sets forth selected operating data for the periods indicated.  Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.

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Oil and Natural Gas Sales

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.

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.

Our production for the last two years is set forth in the following table:

__________________________________

(1)Natural gas and NGLs are converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.

Commodity Derivative Instruments

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. 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.

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

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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.”

Production Expenses

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.

Production Taxes

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.

General and Administrative Expenses

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.

Depletion, Depreciation, Amortization and Accretion

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:

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Interest Expense

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.

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. As of December 31, 2023, 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. 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.

Liquidity and Capital Resources

Overview

Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations, proceeds from equity and debt financings, credit facility borrowings and cash settlements of commodity derivative instruments.  Our primary uses of capital have been for the acquisition, development and operation of our oil and natural gas properties, cash settlements of commodity derivative instruments and for stockholder returns. 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.

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

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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.

With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months and, based on current expectations, for the foreseeable future. However, we may seek additional access to capital and liquidity.  We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all.

Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility.  Our capital expenditures could be curtailed if our cash flows decline from expected levels.  Because production from existing oil and natural gas wells declines over time, reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future.

Working Capital

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).

Cash Flows

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.”

Our cash flows for the years ended December 31, 2023 and 2022 are presented below:

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

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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.

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. During 2023 and 2022, we added 76.6 and 56.8 net wells to production, respectively, excluding already producing wells from acquisitions.

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.

Development and acquisition activities are discretionary.  We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the years ended December 31, 2023 and 2022 are summarized in the following table:

Cash Flows from Financing Activities

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.

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. 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.

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Senior Notes due 2028

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.

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

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.

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 had no outstanding 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.

Known Contractual and Other Obligations; Planned Capital Expenditures

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.

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. As of December 31, 2023, we had incurred $236 million in capital expenditures that were included in accounts payable and accrued liabilities, and we estimate that we were committed to an additional approximately $393 million in development capital expenditures not yet incurred for wells we had elected to participate in. We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Revolving Credit Facility. The foregoing excludes larger acquisitions, which are typically not included in our annual capital expenditure budget. See also “Capital Requirements” below.

Capital Stock and Debt Security Repurchases. 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. 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. 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.  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,

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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. Quantitative and Qualitative Disclosures About Market Risk.”

Capital Requirements

Development and acquisition activities are discretionary, and, for the near term, we expect such activities to be maintained at levels we can fund through cash on hand, internal cash flow and borrowings under our Revolving Credit Facility.  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.  Also, our obligations may change due to acquisitions, divestitures and continued growth.  Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital.  If internally generated cash flow and borrowing capacity under our Revolving Credit Facility are not available or sufficient, we may issue additional equity or debt to fund capital expenditures, make acquisitions, extend maturities or to repay debt.

Satisfaction of Our Cash Obligations for the Next Twelve Months

With our Revolving Credit Facility and our cash flows from operations, we believe we will have sufficient capital to meet our drilling commitments, expected general and administrative expenses and other cash needs for the next twelve months and, based on current expectations, for the foreseeable future. Nonetheless, any strategic acquisition of assets or increase in drilling activity may lead us to seek additional capital.  We may also choose to seek additional capital rather than utilize our Revolving Credit Facility or other debt instruments to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions.  We will evaluate any potential opportunities for acquisitions as they arise.  However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.

Effects of Inflation and Pricing

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

Critical Accounting Estimates

The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our financial statements in accordance with generally accepted accounting principles in the United States (GAAP), as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions.

Use of Estimates

The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect our reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Our estimates of our proved oil and natural gas reserves, future development costs, estimates relating to certain oil and natural gas revenues and expenses, and fair value of derivative instruments are the most critical to our financial statements.

Oil and Natural Gas Reserves

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

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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.  For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change.  Approximately 31% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserve, future cash flows from our reserves, and future development of our proved undeveloped reserves.

The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties.  Such information includes revisions of certain reserve estimates attributable to our properties included in the prior year’s estimates.  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 estimates of proved reserves quantities were prepared in accordance with the rules promulgated by the SEC. In connection with our external petroleum engineers performing their independent reserve audits, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests.

Oil and Natural Gas Properties

The method of accounting we use to account for our oil and natural gas investments determines what costs are capitalized and how these costs are ultimately matched with revenues and expensed.

We utilize the full cost method of accounting to account for our oil and natural gas investments instead of the successful efforts method because we believe it more accurately reflects the underlying economics of our programs to explore and develop oil and natural gas reserves. The full cost method embraces the concept that dry holes and other expenditures that fail to add reserves are intrinsic to the oil and natural gas exploration business. Thus, under the full cost method, all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs, geological and geophysical costs that are directly attributable to the properties and capitalized interest. Although some of these costs will ultimately result in no additional reserves, they are part of a program from which we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. The full cost method differs from the successful efforts method of accounting for oil and natural gas investments. The primary difference between these two methods is the treatment of exploratory dry hole costs. These costs are generally expensed under the successful efforts method when it is determined that measurable reserves do not exist. Geological and geophysical costs are also expensed under the successful efforts method. Under the full cost method, both dry hole costs and geological and geophysical costs are initially capitalized and classified as unproved properties pending determination of proved reserves. If no proved reserves are discovered, these costs are then amortized with all the costs in the full cost pool.

Capitalized amounts except unproved costs are depleted using the units of production method.  The depletion expense per unit of production is the ratio of the sum of our unamortized historical costs and estimated future development costs to our proved reserve volumes.  Estimation of hydrocarbon reserves relies on professional judgment and use of factors that cannot be precisely determined.  Subsequent reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting periods.  For the year ended December 31, 2023, our average depletion expense per unit of production was $13.37 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.  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

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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.

At December 31, 2023, we performed an impairment review using prices that reflect an average of 2023’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, 2023 or 2022. 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.  See “Item 2. Properties” for a discussion of our reserve estimation assumptions.

Derivative Instrument Activities

We use derivative instruments from time to time to manage market risks resulting primarily from fluctuations in the prices of oil and natural gas.  We may periodically enter into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.  The notional amounts of these financial instruments are based on expected production from existing wells.  We may also use exchange traded futures contracts and option contracts to hedge the delivery price of oil at a future date.

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).  The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 12 to our financial statements for a description of the derivative contracts.

Recently Issued or Adopted Accounting Pronouncements

For discussion of recently issued or adopted accounting pronouncements, see Notes to Financial Statements—Note 2. Significant Accounting Policies.

Off-Balance Sheet Arrangements

We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with our financial statements and accompanying notes to financial statements appearing elsewhere in this report. See Item 7., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2021, which is incorporated herein by reference, for discussion and analysis of results of operations for the year ended December 31, 2020.

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. Using this strategy, we had participated in 8,672 gross (799.3 net) producing wells as of December 31, 2022. As of December 31, 2022, we had leased approximately 258,970 net acres, of which approximately 88% were developed and all were located in the United States.

Our average daily production for full year 2022 was 75,511 Boe per day, and in the fourth quarter of 2022 was 78,854 Boe per day (approximately 59% oil). This represented significant growth from 2021, which was driven in large part by our substantial acquisition activity in 2021 and 2022, as described in Note 3 to our financial statements.

During 2022, we added 56.8 new net wells to production, plus an additional 66.4 net wells added from acquisitions which were already producing when acquired. We ended 2022 with 55.4 net wells in process.

Our financial and operating performance for the year ended December 31, 2022 included the following:

•Oil and natural gas sales of $1,985.8 million, a 104% increase compared to 2021

•Cash flows from operations of $928.4 million, a 134% increase compared to 2021

•Proved reserves of 330.8 MMBoe at year-end, a 15% increase compared to year-end 2021

•Grew and diversified the business through over $955 million in substantial bolt-on acquisitions that closed during 2022

•Grew our quarterly common stock dividend from $0.08 per share for the fourth quarter of 2021 to $0.30 per share for the fourth quarter of 2022

•Expanded our stockholder return program by repurchasing and retiring $54.5 million of common stock, $57.5 million in liquidation value of our Series A Preferred Stock (as defined below), and $25.8 million in face value of our Senior Notes

•Simplified our balance sheet by exercising our right to force a mandatory conversion of all remaining shares of our Series A Preferred Stock in November 2022

•Issued $500.0 million in aggregate principal amount of Convertible Notes (as defined below), and used the net proceeds to reduce borrowings under our Revolving Credit Facility, fund acquisitions, and for other general corporate purposes

Source of Our Revenues

We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties.  Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market.  We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil and natural gas production.  We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations.  The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.

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Principal Components of Our Cost Structure

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

•Gain (loss) on commodity derivatives, net.  We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas. Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end.

•Production expenses.  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.

•Production taxes.  Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.

•Depreciation, depletion, amortization and accretion.  Depreciation, depletion, amortization and accretion includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method. Accretion expense relates to the passage of time of our asset retirement obligations.

•General and administrative expenses.  General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance.

•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 full 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.

•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.

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

Selected Factors That Affect Our Operating Results

Our revenues, cash flows from operations and future growth depend substantially upon:

•the timing and success of drilling and production activities by our operating partners;

•the prices and the supply and demand for oil, natural gas and NGLs;

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•the quantity of oil and natural gas production from the wells in which we participate;

•changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in commodity prices;

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

•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 2022 was $2.73 per barrel, as compared to $5.15 per barrel in 2021.  Our net realized gas price during 2022 was $7.43 per Mcf, representing 113% realization relative to average Henry Hub pricing, compared to a net realized gas price of $4.57 per Mcf during 2021, which represented 119% 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.

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. During 2022, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $8.0 million, compared to $6.9 million for the wells we elected to participate in during 2021.

Certain drilling and completion costs and costs of oilfield services, equipment, and materials decreased in 2020 as service providers reduced their costs in response to reduced demand arising from historically low crude oil prices. However, inflationary pressures returned in 2021 and have continued to persist in conjunction with the significant increase in commodity prices since that time, labor shortages, and other factors. Additionally, supply chain disruptions stemming from the COVID-19 pandemic have led to shortages of certain materials and equipment and resulting increases in material and labor costs. Our capital spending budget for 2023 includes an estimate for the impact of cost inflation and, despite inflationary pressures, we expect to continue generating significant amounts of free cash flow at current commodity price levels.

Market Conditions

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

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows.  The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2022 and 2021.

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(1)Based on average NYMEX closing prices.

For 2022, the average NYMEX pricing was $94.38 per barrel of oil, or 39% higher than in 2021. Our average realized oil price before reflecting settled oil derivatives was $91.65 per barrel of oil in 2022. Our average realized oil price after reflecting settled oil derivatives was $69.60 per barrel of oil in 2022, or 32% higher than in 2021, due to the higher average NYMEX price and a lower oil price differential, partially offset by a larger loss on settled oil derivatives in 2022 compared to 2021.

For 2022, the average NYMEX pricing for natural gas was $6.56 per Mcf, or 71% higher than in 2021. Our average realized natural gas price before reflecting settled natural gas derivatives was $7.43 per Mcf in 2022. Our average realized natural gas price after reflecting settled natural gas derivatives was $5.83 per Mcf in 2022, or 60% higher than in 2021, due to the higher average NYMEX price, partially offset by lower realizations and a larger loss on settled natural gas derivatives in 2022 compared to 2021.

We have entered into derivatives contracts to hedge commodity price risk on a portion of our future expected oil and natural gas production. For a summary as of December 31, 2022, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in Item 7A below. See also Note 12 to our financial statements.

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Results of Operations for 2022 and 2021

The following table sets forth selected operating data for the periods indicated.  Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.

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Oil and Natural Gas Sales

Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes.  In 2022, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, increased 104% from 2021, driven by a 40% increase in production volumes and a 45% increase in realized prices, excluding the effect of settled commodity derivatives. The higher average realized price in 2022 as compared to 2021 was driven by higher average NYMEX oil and natural gas prices, and a lower average oil price differential, partially offset by lower average natural gas realizations in 2022 as compared to 2021.  Oil price differential during 2022 averaged $2.73 per barrel, as compared to $5.15 per barrel in 2021.

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 2021 and 2022 (see Note 3 to our financial statements) helped drive the 40% increase in production levels in 2022 as compared to 2021. In addition, the number of net wells we added to production (excluding acquisitions) increased by 59% in 2022 as compared to 2021, due to our growing organic acreage footprint and increased development on our properties.

Our production for the last two years is set forth in the following table:

__________________________________

(1)Natural gas and NGLs are converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.

Commodity Derivative Instruments

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 loss of $415.3 million in 2022, compared to a loss of $478.2 million in 2021.  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 2022, we realized a loss on settled commodity derivatives of $455.4 million, compared to a $165.8 million loss in 2021.  The percentage of oil production hedged under our derivative contracts was 68% and 73% in 2022 and 2021, respectively. The weighted average oil price on our settled commodity derivative contracts in 2022 and 2021 was $62.52 and $55.56, respectively. Our average realized price (including all commodity derivative cash settlements) in 2022 was $55.53 per Boe compared to $41.21 per Boe in 2021.  The gain (loss) on settled commodity derivatives decreased our average realized price per Boe by $16.52 in 2022, and decreased our average realized price per Boe by $8.45 in 2021.

Unsettled commodity derivative gains and losses was a gain of $40.2 million in 2022 compared to a loss of $312.4 million in 2021.  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

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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, 2022, all of our derivative contracts are recorded at their fair value, which was a net liability of $236.5 million, a change of $41.2 million from the $277.7 million net liability recorded as of December 31, 2021.  The decrease in the net liability at December 31, 2022 as compared to December 31, 2021 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2021.  Our open commodity derivative contracts are summarized in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Production Expenses

Production expenses were $260.7 million in 2022 compared to $170.8 million in 2021.  On a per unit basis, production expenses increased 9%, from $8.70 per Boe in 2021 to $9.46 per Boe in 2022, due to higher processing costs due in part to elevated NGL pricing, which drives increased payments under percentage of proceeds contracts. Additionally, higher service and maintenance costs have contributed to an increase in production expense.  On an absolute dollar basis, the 53% increase in our production expenses in 2022 compared to 2021 was primarily due to a 40% increase in production volumes and a 9% increase in per unit costs.

Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $158.2 million in 2022 compared to $77.0 million in 2021.  The increase is due to higher production and higher realized prices, which significantly increased our oil and natural gas sales in 2022 as compared to 2021. As a percentage of oil and natural gas sales, our production taxes were 8.0% and 7.9% in 2022 and 2021, 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.

General and Administrative Expenses

General and administrative expenses were $47.2 million for 2022 compared to $30.3 million for 2021. The increase in 2022 compared to 2021 was primarily due to an $8.4 million increase in acquisition costs, a $5.4 million increase in compensation costs and a $1.5 million increase in professional fees.

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation, amortization and accretion (“DD&A”) was $251.3 million in 2022 compared to $140.8 million in 2021.  The aggregate increase in DD&A expense for 2022 compared to 2021 was driven by a 40% increase in production levels and a 27% increase in the depletion rate per Boe. Depletion expense, the largest component of DD&A, was $9.01 per Boe in 2022 compared to $7.07 per Boe in 2021. The following table summarizes DD&A expense per Boe for 2022 and 2021 :

Impairment of Oil and Natural Gas Properties

We did not record any impairment of our proved oil and gas properties in 2022 or 2021.

Depending on future commodity price levels, the trailing twelve-month average price used in the ceiling calculation may decline, which could cause additional future write downs of our oil and natural gas properties. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods.

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Interest Expense

Interest expense, net of capitalized interest, was $80.3 million in 2022 compared to $59.0 million in 2021.  The increase in interest expense for 2022 as compared to 2021 was primarily due to higher levels of debt and higher weighted-average interest rates associated with our Revolving Credit Facility in 2022 compared to 2021.

Gain (Loss) on the Extinguishment of Debt

As a result of refinancing transactions during 2022 (see Note 4 to our financial statements), we recorded a gain on the extinguishment of debt of $0.8 million for the year ended December 31, 2022, based on the differences between the reacquisition costs of retiring the applicable debt and the net carrying values thereof. During 2021, we recorded a loss on extinguishment of debt of $13.1 million as a result of refinancing transactions, based on the differences between the reacquisition costs of retiring the applicable debt and the net carrying values thereof.

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, 2022 and 2021, we recorded a contingent consideration gain of $1.9 million compared to a loss of $0.3 million, respectively, due to the change in the fair value of these liabilities. As of December 31, 2022, there were $10.1 million of remaining outstanding contingent consideration liabilities.

Income Tax Expense (Benefit)

We recognized income tax expense (benefit) of $3.1 million and $0.2 million in 2022 and 2021, respectively. In 2022 and 2021, we recorded income tax expense as a result of state income tax requirements related to our Permian and Appalachian Basin properties.

We intend to continue maintaining a full valuation allowance on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of these allowances. Release of any portion of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense for the period the release is recorded. It is reasonably possible that sufficient positive evidence will exist within the next 12 months to release our current valuation allowance position, which would be indicative of our ability to utilize deferred tax assets in the future. The exact timing and amount of the valuation allowance release are subject to change based on the evaluation of all evidence and actual results, including, but not limited to, the level of profitability that we are forecasted to achieve in future periods. For further discussion of our valuation allowance, see Note 10 to our financial statements.

Liquidity and Capital Resources

Overview

Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations, proceeds from equity and debt financings, credit facility borrowings, and cash settlements of commodity derivative instruments.  Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties and cash settlements of commodity derivative instruments. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

During 2022, we repurchased and retired (i) 575,000 shares of our 6.500% Series A Perpetual Cumulative Convertible Preferred Stock (the “Series A Preferred Stock”) for total consideration of $81.2 million, (ii) 1,909,097 shares of our common stock for total consideration of $54.5 million and (iii) $25.8 million aggregate principal amount of our Senior Notes for total consideration of $24.9 million, plus accrued interest.

In October 2022, we issued $500.0 million in aggregate principal amount of the Convertible Notes, the proceeds of which were used to reduce borrowings under our Revolving Credit Facility, fund acquisitions, and for other general corporate purposes.

We completed over $955.3 million in substantial bolt-on acquisitions that closed during 2022 (see Note 3 to our financial statements). In addition, in January 2023 we completed an additional $320.0 million acquisition (the “MPDC Acquisition”) that was originally signed and announced during October 2022 (see Note 14 to our financial statements).

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As of December 31, 2022, we had outstanding debt consisting of $319.0 million of borrowings under our Revolving Credit Facility, $724.2 million aggregate principal amount of our Senior Notes, and $500.0 million aggregate principal amount of our Convertible Notes. We had total liquidity of $683.5 million as of December 31, 2022, consisting of $681.0 million of committed borrowing availability under the Revolving Credit Facility and $2.5 million of cash on hand.

One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 74% and 79% of our total oil and gas sales in 2022 and 2021, 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 2022 and 2021, we hedged approximately 68% and 73% of our crude oil production, respectively. For a summary as of December 31, 2022, of our open commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.

With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months. However, we may seek additional access to capital and liquidity.  We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all.

Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility.  Our capital expenditures could be curtailed if our cash flows decline from expected levels.  Because production from existing oil and natural gas wells declines over time, reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future.

Working Capital

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, 2022, we had a working capital deficit of $24.5 million, compared to a deficit of $112.2 million at December 31, 2021.  Current assets increased by $105.2 million and current liabilities increased by $17.4 million at December 31, 2022, compared to December 31, 2021.

The $105.2 million increase in current assets in 2022 as compared to 2021 was driven by a $77.8 million increase in accounts receivable, primarily due to higher production levels and higher commodity prices, and a $32.8 million increase in derivative instruments due to the change in fair value as a result of commodity price changes. These increases were partially offset by a $7.0 million decrease in our cash and cash equivalents balance.

The $17.4 million increase in current liabilities in 2022 as compared to 2021 was driven by a $79.3 million increase in accounts payable and accrued expenses, primarily as a result of increased development activity, a $10.1 million increase in contingent consideration liabilities related to our acquisition activities (see Note 3 to our financial statements), and a $3.8 million increase in accrued interest. These increases were partially offset by a $75.9 million decrease in our derivative instruments as a result of commodity price changes.

Cash Flows

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.”

Our cash flows for the years ended December 31, 2022 and 2021 are presented below:

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Cash Flows from Operating Activities

Net cash provided by operating activities in 2022 was $928.4 million, compared to $396.5 million in 2021. This increase was driven by a 40% year-over-year increase in production levels and a 35% increase in realized prices (including the effect of settled derivatives). 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, 2022 was a deficit of $62.4 million compared to a deficit of $85.8 million in 2021.

Cash Flows from Investing Activities

We had cash flows used in investing activities of $1,402.8 million and $634.4 million during the years ended December 31, 2022 and 2021, 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 2022 was attributable to our 2022 acquisitions. In addition, cash flows used in investing activities included a $43.0 million acquisition deposit for our MPDC Acquisition that was pending at year-end 2022. During 2022 and 2021, we added 56.8 and 35.8 net wells to production, respectively, in each case excluding already producing wells from acquisitions.

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, 2022, 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 $1,474.5 million, while the actual cash spend in this regard amounted to $1,355.2 million.

Development and acquisition activities are discretionary.  We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the years ended December 31, 2022 and 2021 are summarized in the following table:

Cash Flows from Financing Activities

Net cash provided by financing activities was $467.4 million and $246.1 million for the years ended December 31, 2022 and 2021, respectively.  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 Series A Preferred Stock, $54.5 million in repurchases of common stock, $24.9 million in repurchases of our Senior Notes, 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.

The cash provided by financing activities in 2021 was primarily related to $763.5 million of net proceeds for our offering of Unsecured Senior Notes due 2028 and $438.1 million of net proceeds from our offerings of common stock, which was partially offset by the retirement of our 8.500% senior secured second lien notes due 2023 of $295.9 million, retirement of our 6% senior unsecured promissory note due 2022 of $130.0 million, and net repayments under our Revolving Credit Facility

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of $477.0 million. Additionally, we paid common and preferred stock dividends of $4.9 million and $29.2 million, respectively, and spent $17.6 million in fees in connection with debt financing transactions in 2021.

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. As of December 31, 2022, the Revolving Credit Facility had a borrowing base of $1.6 billion and an elected commitment amount of $1.0 billion, and we had $319.0 million in borrowings outstanding under the facility, leaving $681.0 million in available committed borrowing capacity. See Note 4 to our financial statements for further details regarding the Revolving Credit Facility.

Senior Notes

As of December 31, 2022, we had outstanding $724.2 million aggregate principal amount of our 8.125% senior notes due 2028 (the “Senior Notes”). See Note 4 to our financial statements for further details regarding the Senior Notes.

Convertible Notes

As of December 31, 2022, 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.

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, 2022, we had no outstanding 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.

Known Contractual and Other Obligations; Planned Capital Expenditures

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.

Planned Capital Expenditures. For 2023, we are budgeting approximately $737 to $778 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. As of December 31, 2022, we had incurred $163.1 million in capital expenditures that were included in accounts payable, and we estimate that we were committed to an additional approximately $468.4 million in development capital expenditures not yet incurred for wells we had elected to participate in. We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Revolving Credit Facility. The foregoing excludes larger acquisitions, which are typically not included in our annual capital expenditure budget. For example, our MPDC Acquisition was pending as of December 31, 2022, and subsequently closed in January 2023 (see Note 14 to our financial statements). See also “Capital Requirements” below.

Capital Stock and Debt Security Repurchases. 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. 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, 2022 the Company repurchased 1,909,097 shares of its common stock under the stock repurchase program at a total cost of $54.5 million. During the year ended December 31, 2022, the Company also repurchased and retired $25.8 million in aggregate principal amount of the Senior Notes in open market transactions for a total of $24.9 million in cash, plus accrued interest. The Company may in the future engage in similar transactions.

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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.  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. Quantitative and Qualitative Disclosures About Market Risk.”

Capital Requirements

Development and acquisition activities are discretionary, and, for the near term, we expect such activities to be maintained at levels we can fund through cash on hand, internal cash flow and borrowings under our Revolving Credit Facility.  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.  Also, our obligations may change due to acquisitions, divestitures and continued growth.  Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital.  If internally generated cash flow and borrowing capacity is not available under our Revolving Credit Facility, we may issue additional equity or debt to fund capital expenditures, make acquisitions, extend maturities or to repay debt.

Satisfaction of Our Cash Obligations for the Next Twelve Months

With our revolving credit agreement and our cash flows from operations, we believe we will have sufficient capital to meet our drilling commitments, expected general and administrative expenses and other cash needs for the next twelve months and, based on current expectations, for the foreseeable future. Nonetheless, any strategic acquisition of assets or increase in drilling activity may lead us to seek additional capital.  We may also choose to seek additional capital rather than utilize our credit facility or other debt instruments to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions.  We will evaluate any potential opportunities for acquisitions as they arise.  However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.

Effects of Inflation and Pricing

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry.  Typically, as prices for oil and natural gas increase, so do all associated costs.  Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion.  Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions.  Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel.  Higher prices for oil and natural gas have resulted in increases in the costs of materials, services and personnel, and we are budgeting for a 5-10% increase in drilling and completion and other associated costs in 2023 compared to 2022.

Critical Accounting Estimates

The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our financial statements in accordance with generally accepted accounting principles in the United States (GAAP), as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions.

Use of Estimates

The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect our reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Our estimates of our proved oil and

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natural gas reserves, future development costs, estimates relating to certain oil and natural gas revenues and expenses, and fair value of derivative instruments are the most critical to our financial statements.

Oil and Natural Gas Reserves

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.  The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment.  For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change.  Approximately 35% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserve, future cash flows from our reserves, and future development of our proved undeveloped reserves.

The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties.  Such information includes revisions of certain reserve estimates attributable to our properties included in the prior year’s estimates.  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, 2022. Our estimates of proved reserves quantities were prepared in accordance with the rules promulgated by the SEC. In connection with our external petroleum engineers performing their independent reserve audits, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests.

Oil and Natural Gas Properties

The method of accounting we use to account for our oil and natural gas investments determines what costs are capitalized and how these costs are ultimately matched with revenues and expensed.

We utilize the full cost method of accounting to account for our oil and natural gas investments instead of the successful efforts method because we believe it more accurately reflects the underlying economics of our programs to explore and develop oil and natural gas reserves. The full cost method embraces the concept that dry holes and other expenditures that fail to add reserves are intrinsic to the oil and natural gas exploration business. Thus, under the full cost method, all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs, geological and geophysical costs that are directly attributable to the properties and capitalized interest. Although some of these costs will ultimately result in no additional reserves, they are part of a program from which we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. The full cost method differs from the successful efforts method of accounting for oil and natural gas investments. The primary difference between these two methods is the treatment of exploratory dry hole costs. These costs are generally expensed under the successful efforts method when it is determined that measurable reserves do not exist. Geological and geophysical costs are also expensed under the successful efforts method. Under the full cost method, both dry hole costs and geological and geophysical costs are initially capitalized and classified as unproved properties pending determination of proved reserves. If no proved reserves are discovered, these costs are then amortized with all the costs in the full cost pool.

Capitalized amounts except unproved costs are depleted using the units of production method.  The depletion expense per unit of production is the ratio of the sum of our unamortized historical costs and estimated future development costs to our proved reserve volumes.  Estimation of hydrocarbon reserves relies on professional judgment and use of factors that cannot be precisely determined.  Subsequent reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting periods.  For the year ended December 31, 2022, our average depletion expense per unit of production was $9.01 per Boe.

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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.  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.  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.

At December 31, 2022, we performed an impairment review using prices that reflect an average of 2022’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, 2022 or 2021, respectively. For the year ended 2020, we recorded a $1,066.7 million full cost impairment expense. If a low price environment reoccurs, we might be required to further 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.  See “Item 2. Properties” for a discussion of our reserve estimation assumptions.

Derivative Instrument Activities

We use derivative instruments from time to time to manage market risks resulting primarily from fluctuations in the prices of oil and natural gas.  We may periodically enter into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.  The notional amounts of these financial instruments are based on expected production from existing wells.  We may also use exchange traded futures contracts and option contracts to hedge the delivery price of oil at a future date.

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).  The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 12 to our financial statements for a description of the derivative contracts.

Recently Issued or Adopted Accounting Pronouncements

For discussion of recently issued or adopted accounting pronouncements, see Notes to Financial Statements—Note 2. Significant Accounting Policies.

Off-Balance Sheet Arrangements

We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with our financial statements and accompanying notes to financial statements appearing elsewhere in this report. See Item 7., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2020, which is incorporated herein by reference, for discussion and analysis of results of operations for the year ended December 31, 2019.

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. Using this strategy, we had participated in 7,436 gross (680.8 net) producing wells as of December 31, 2021. As of December 31, 2021, we had leased approximately 245,431 net acres, of which approximately 87% were developed and all were located in the United States.

Our average daily production for full year 2021 was 53,792 Boe per day, and in the fourth quarter of 2021 was 64,155 Boe per day (approximately 59% oil). This represented significant growth from 2020, which was driven in large part by three substantial acquisitions that we completed during 2021: the Reliance Acquisition, the CM Resources Acquisition and the Comstock Acquisition, each as defined and described in Note 3 to our financial statements (collectively, the “2021 Acquisitions”).

During 2021, we added 35.8 new net wells to production, plus an additional 169.4 net wells added from acquisitions which were already producing when acquired. We ended 2021 with 42.5 net wells in process.

Our financial and operating performance for the year ended December 31, 2021 included the following:

•Oil and natural gas sales of $975.1 million in 2021

•Cash flows from operations of $396.5 million in 2021

•Proved reserves of 287.7 MMBoe at December 31, 2021, as estimated by our third-party reserve engineers under SEC guidelines

•Grew and diversified the business through over $400 million in substantial bolt-on acquisitions in multiple basins, conservatively financed through a combination of debt and equity

•Initiated a shareholder return program in the form of quarterly cash dividends on our common stock, which started at $0.03 per share for the second quarter of 2021 and grew to $0.08 per share for the fourth quarter of 2021

•Reduced outstanding indebtedness from $949.8 million at December 31, 2020 to $805.0 million at December 31, 2021

•Issued $750.0 million in aggregate principal amount of senior unsecured notes due 2028 and $438.1 million in common stock (net of offering expenses), the proceeds of which were used (i) to fund our 2021 Acquisitions and in preparation for the Veritas Acquisition, (ii) to retire $417.8 million of term debt with near-term maturities, (iii) to repay revolving credit facility borrowings, allowing us to exit 2021 with $704.5 million in liquidity, and (iv) for general corporate purposes

Impacts of COVID-19 Pandemic and Economic Environment

The novel coronavirus disease (COVID-19) and efforts to mitigate the spread of the disease have created unprecedented challenges for our industry, including a drastic decline in demand for crude oil. This, combined with OPEC actions in early 2020, led to spot and future prices of crude oil falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020. Operators in the Williston Basin responded by significantly decreasing drilling and completion activity, and by shutting in or curtailing production from a significant number of producing wells. Conditions have significantly improved with the recovery and rally of commodity prices from late 2020 through the end of 2021, but operators’ decisions on these matters are evolving rapidly, and it remains difficult to predict the future effects on our company

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and its business. However, we expect that our cash flow from operations and borrowing availability under our Revolving Credit Facility will allow us to meet our liquidity needs for at least the next twelve 12 months.

Source of Our Revenues

We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties.  Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market.  We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil and natural gas production.  We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations.  The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.

Principal Components of Our Cost Structure

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

•Gain (loss) on commodity derivatives, net.  We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas. Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end.

•Production expenses.  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.

•Production taxes.  Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.

•Depreciation, depletion, amortization and accretion.  Depreciation, depletion, amortization and accretion includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method. Accretion expense relates to the passage of time of our asset retirement obligations.

•General and administrative expenses.  General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance.

•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 unproven cost pool.  We include interest expense that is not capitalized into the full 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.

•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.

•Income tax expense.  Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities.  Deferred tax assets and liabilities are measured using enacted tax

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rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

Selected Factors That Affect Our Operating Results

Our revenues, cash flows from operations and future growth depend substantially upon:

•the timing and success of drilling and production activities by our operating partners;

•the prices and the supply and demand for oil, natural gas and NGLs;

•the quantity of oil and natural gas production from the wells in which we participate;

•changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in the price of oil;

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

•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, Appalachian and Permian 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 of oil can vary depending on the market in which it is sold and the means of transportation used to transport the oil to market, particularly in the Williston Basin where a substantial majority of our revenues are derived. Additional pipeline infrastructure has increased takeaway capacity in the Williston Basin which has improved wellhead values in the region.

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 oil price differentials between the applicable benchmark and the sales prices we receive for our oil production.  Our oil price differential to the NYMEX benchmark price during 2021 was $5.15 per barrel, as compared to $6.63 per barrel in 2020.  Our net realized gas price during 2021 was $4.57 per Mcf, representing 100% realization relative to average Henry Hub pricing, compared to a net realized gas price of $1.14 per Mcf during 2020. Fluctuations in our price differentials and realizations are due to several factors such as gathering and transportation costs, takeaway capacity relative to production levels, regional storage capacity, and seasonal refinery maintenance temporarily depressing demand.

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. During 2021, the weighted average authorization for expenditure (or AFE) cost for wells we elected to participate in was $6.9 million, compared to $7.5 million for the wells we elected to participate in during 2020.

Market Conditions

The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand.  Because our oil and gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas.  World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can adversely impact oil prices.

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Historically, commodity prices have been volatile and we expect the volatility to continue in the future.  Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows.  The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2021 and 2020.

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(1)Based on average NYMEX closing prices.

The average 2021 NYMEX oil pricing was $68.09 per barrel of oil or 74% higher than the average NYMEX price per barrel in 2020. Our settled derivatives decreased our realized oil price per barrel by $10.17 in 2021 and increased our realized oil price per barrel by $20.08 in 2020. Our average 2021 realized oil price per barrel after reflecting settled derivatives was $52.77 compared to $52.69 in 2020. The average 2021 NYMEX natural gas pricing was $3.84 per Mcf, or 91% higher than the average NYMEX price per Mcf in 2020. Our settled derivatives decreased our realized natural gas price per Mcf by $0.92 in 2021 and increased our realized natural gas price per Mcf by $0.02 in 2020. Our 2021 realized gas price per Mcf was $3.65 compared to $1.16 in 2020, which was primarily driven by higher NYMEX pricing for natural gas and gas realizations, which was partially offset by decrease in settled derivatives.

We employ a hedging program that mitigates the risk associated with fluctuations in commodity prices. For detailed information on our commodity hedging program, see Item 7A Quantitative and Qualitative Disclosures about Market Risk and Note 12 to our financial statements.

Results of Operations for 2021 and 2020

The following table sets forth selected operating data for the periods indicated.  Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.

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Oil and Natural Gas Sales

Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes.  In 2021, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, increased 201%

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from 2020, driven by a 62% increase in production volumes and an 86% increase in realized prices, excluding the effect of settled commodity derivatives. The higher average realized price in 2021 as compared to 2020 was driven by higher average NYMEX oil and natural gas prices, a lower average oil price differential, and higher average gas realizations in 2021 as compared to 2020.  Oil price differential during 2021 averaged $5.15 per barrel, as compared to $6.63 per barrel in 2020.

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 acquisition program is a significant driver of our net well additions in certain years. In 2021, our substantial acquisition activities (see Note 3 to our financial statements) combined with increased development activity helped drive an increase in production levels as compared to 2020. In 2021, the number of net wells we added to production (excluding acquisitions) increased by 101% as compared to 2020. The 2021 Acquisitions and increased new well additions drove the 62% increase in production in 2021 as compared to 2020.

Our production for the last two years is set forth in the following table:

__________________________________

(1)Natural gas and NGLs are converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.

Commodity Derivative Instruments

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 loss of $478.2 million in 2021, compared to a gain of $228.1 million in 2020.  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 2021, we realized a loss on settled commodity derivatives of $165.8 million, compared to a $188.3 million gain in 2020.  The percentage of oil production hedged under our derivative contracts was 73% and 104% in 2021 and 2020, respectively. The weighted average oil price on our settled commodity derivative contracts in 2021 and 2020 was $55.56 and $58.04, respectively. Our average realized price (including all commodity derivative cash settlements) in 2021 was $41.21 per Boe compared to $42.32 per Boe in 2020.  The gain (loss) on settled commodity derivatives decreased our average realized price per Boe by $8.45 in 2021, and increased our average realized price per Boe by $15.55 in 2020.

Unsettled commodity derivative gains and losses was a loss of $312.4 million in 2021 compared to a gain of $39.9 million in 2020.  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, 2021, all of our derivative contracts are recorded at their fair value, which was a net liability of $277.7 million, a change of $311.3 million from the $33.7 million net asset recorded as of December 31, 2020.  The increase in the net liability at December 31, 2021 as compared to December 31, 2020 was primarily

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due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2020.  Our open commodity derivative contracts are summarized in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Production Expenses

Production expenses were $170.8 million in 2021 compared to $116.3 million in 2020.  On a per unit basis, production expenses decreased 9% from $9.61 per Boe in 2020 to $8.70 per Boe in 2021 due primarily to higher production volumes over which fixed costs can be spread and the mix of production expense by basin as we added production from the Permian and Appalachian Basins, which was partially offset by higher processing and saltwater disposal charges.  On an absolute dollar basis, the 47% increase in our production expenses in 2021 compared to 2020 was primarily due to a 62% increase in production, offset by a 9% decrease in per unit costs.

Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $77.0 million in 2021 compared to $29.8 million in 2020.  As a percentage of oil and natural gas sales, our production taxes were 7.9% and 9.2% in 2021 and 2020, 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 natural gas sales and the mix of our production volumes by basin. Oil sales are taxed at a higher rate than gas sales for the Williston and Permian Basins and we do not pay production taxes in the Appalachian Basin.

General and Administrative Expenses

General and administrative expenses were $30.3 million for 2021 compared to $18.5 million for 2020. The increase in 2021 compared to 2020 was primarily due to an $8.1 million increase in acquisition costs due to our 2021 Acquisitions, a $2.3 million increase in compensation costs and a $0.6 million increase in professional fees.

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation, amortization and accretion (“DD&A”) was $140.8 million in 2021 compared to $162.1 million in 2020.  Depletion expense, the largest component of DD&A, was $7.07 per Boe in 2021 compared to $13.27 per Boe in 2020.  The aggregate decrease in depletion expense for 2021 compared to 2020 was driven by a 47% decrease in the depletion rate per Boe partially offset by a 62% increase in production levels. The 2021 depletion rate per Boe was lower due to the impact of impairments in 2020. The following table summarizes DD&A expense per Boe for 2021 and 2020 :

Impairment of Oil and Natural Gas Properties

We did not record any impairment of our proved oil and gas properties in 2021. In 2020, as a result of low commodity prices and their effect on the proved reserve values of our properties, we recorded a non-cash ceiling test impairment of $1.1 billion. The impairment charge affected our reported net income in 2020 but did not reduce our cash flow.

Depending on future commodity price levels, the trailing twelve-month average price used in the ceiling calculation may decline, which could cause additional future write downs of our oil and natural gas properties. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods.

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Interest Expense

Interest expense, net of capitalized interest, was $59.0 million in 2021 compared to $58.5 million in 2020.  The increase in interest expense for 2021 as compared to 2020 was primarily due to the issuance of our Senior Notes due 2028 which was partially offset by a reduction in our outstanding borrowings on our Revolving Credit Facility in 2021.

Loss on the Extinguishment of Debt

As a result of refinancing transactions during 2021 (see Note 4 to our financial statements), we recorded a loss on the extinguishment of debt of $13.1 million for the year ended December 31, 2021, based on the differences between the reacquisition costs of retiring our Second Lien Notes and the net carrying values thereof. During 2020, we recorded a loss on extinguishment of debt of $3.7 million as a result of a series of exchange transactions of our Second Lien Notes, based on the differences between the reacquisition costs of retiring the applicable debt and the net carrying values thereof.

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, 2021 and 2020, we recorded contingent consideration losses of $0.3 million and $0.2 million, respectively, due to the change in the fair value of these liabilities. As of December 31, 2021, there were no remaining outstanding contingent consideration liabilities.

Income Tax Expense (Benefit)

We recognized income tax expense (benefit) of $0.2 million and $(0.2) million in 2021 and 2020, respectively. In 2021, we recorded income tax expense as a result of state income tax requirements related to our Permian and Appalachian Basin properties. In 2020, the tax benefits recognized related to the utilization of our alternative minimum tax credit as a result of favorable tax incentives. We have recorded a valuation allowance against effectively all of our net deferred tax assets due to uncertainty regarding their realization.

We intend to continue maintaining a full valuation allowance on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of these allowances. Release of any portion of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense for the period the release is recorded. However, the exact timing and amount of the valuation allowance release are subject to change on the basis of the level of profitability that we are able to actually achieve. For further discussion of our valuation allowance, see Note 10 to our financial statements.

Liquidity and Capital Resources

Overview

Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations, proceeds from equity and debt financings, credit facility borrowings, and cash settlements of commodity derivative instruments.  Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties.  We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

As of December 31, 2021, we had outstanding debt consisting of $55.0 million of borrowings under our Revolving Credit Facility, and $750.0 million aggregate principal amount of senior unsecured notes due 2028 (the “2028 Notes”). We had $704.5 million in liquidity as of December 31, 2021, consisting of $695.0 million of committed borrowing availability under the Revolving Credit Facility and $9.5 million of cash on hand.

We completed three substantial acquisitions during 2021: the Reliance Acquisition, the CM Resources Acquisition and the Comstock Acquisition (collectively, the “2021 Acquisitions”) (see Note 3 to our financial statements). In addition, in January 2022 we completed the Veritas Acquisition pursuant to a purchase and sale agreement that we entered into and announced in November 2021 (see Note 14 to our financial statements).

During 2021 we completed a number of significant financing transactions, many of which were related to these acquisitions, including:

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•a common stock offering in February 2021 with net proceeds of $132.9 million, which was primarily intended to finance the cash purchase price for the Reliance Acquisition that closed on April 1, 2021;

•a common stock offering in June 2021 with net proceeds of $95.3 million, which was primarily intended to finance the cash purchase price for the CM Resources Acquisition that closed in the third quarter of 2021;

•a common stock offering in November 2021 with net proceeds of $209.9 million, which was primarily intended to finance the cash purchase price for the Veritas Acquisition that closed in the first quarter of 2022, and in the interim was used to pay down outstanding borrowings under our Revolving Credit Facility;

•the issuance of $750.0 million in aggregate principal amount of new 8.125% senior unsecured notes due 2028 (the “2028 Notes”), of which $550.0 million was issued in February 2021 and an additional $200.0 million was issued in November 2021;

•the full repayment and retirement of all $130.0 million in principal amount of our 6.0% senior unsecured promissory note due 2022 (the “Unsecured VEN Bakken Note”);

•the full redemption and retirement of all $287.8 million in principal amount of our 8.500% senior secured second lien notes due 2023 (the “Second Lien Notes”); and

•the reduction of amount of borrowings outstanding under our Revolving Credit Facility from $532.0 million as of December 31, 2020 to $55.0 million as of December 31, 2021.

One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 63% and 77% of our total production volumes in 2021 and 2020, 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 2021 and 2020, we hedged approximately 73% and 104% of our crude oil production, respectively. For a summary as of December 31, 2021, of our open commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.

With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months. However, we may seek additional access to capital and liquidity.  We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all.

Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility.  Our capital expenditures could be curtailed if our cash flows decline from expected levels.  Because production from existing oil and natural gas wells declines over time, reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future.

Working Capital

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, 2021, we had a working capital deficit of $112.2 million, compared to a deficit of $56.8 million at December 31, 2020.  Current assets increased by $89.7 million and current liabilities increased by $145.1 million at December 31, 2021, compared to December 31, 2020.  The increase in current assets in 2021 as compared to 2020 is primarily due to an increase of $122.5 million in accounts receivable primarily due to our higher production levels and higher commodity prices and an increased cash balance, which was partially offset by a decrease of $48.8 million in our derivative instruments, due to the change in fair value as a result of commodity price projections.  The change in current liabilities in 2021 as compared to 2020 is primarily due to an increase of $66.6 million in accounts payable and accrued expenses primarily as a result of increased development activity and an increase of $131.2 million in derivative instruments as a result of forward commodity price changes, which was partially offset by the current maturity of our first Unsecured VEN Bakken Note payment of $65.0 million that was paid on January 4, 2021. Additionally, our accrued interest increased by $12.2 million as a result of the timing

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of interest payments on our newly issued 2028 Notes compared to the timing of interest payments on our prior debt instruments outstanding during 2020.

Cash Flows

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.  The Company typically enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future oil and gas production for the next 12 to 24 months. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”

Our cash flows for the years ended December 31, 2021 and 2020 are presented below:

Cash Flows from Operating Activities

Net cash provided by operating activities in 2021 was $396.5 million, compared to $331.7 million in 2020. This increase was driven by a 62% year-over-year increase in production levels, which was partially offset by a 3% decrease in realized prices (including the effect of settled derivatives). 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, 2021 was a decrease of $85.8 million compared to an increase of $34.1 million in 2020.

Cash Flows from Investing Activities

We had cash flows used in investing activities of $634.4 million and $283.9 million during the years ended December 31, 2021 and 2020, 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 2021 was attributable to our 2021 Acquisitions and higher development spending as a result of the higher commodity price environment from the rebound of the COVID-19 pandemic. In addition, cash flows used in investing activities included a $40.7 million acquisition deposit for our Veritas Acquisition that was pending at year-end 2021. During 2021 and 2020 we added 35.8 and 17.8 net wells to production, respectively, in each case excluding already producing wells from acquisitions.

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, 2021, 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 $656.2 million, while the actual cash spend in this regard amounted to $593.2 million.

Development and acquisition activities are discretionary.  We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the years ended December 31, 2021 and 2020 are summarized in the following table:

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Cash Flows from Financing Activities

Net cash (used for) provided by financing activities was $246.1 million and $(62.4) million for the years ended December 31, 2021 and 2020, respectively.  The cash provided by financing activities in 2021 was primarily related to $763.5 million of net proceeds from our offering of 2028 Notes and $438.1 million of net proceeds from our offerings of common stock, which was partially offset by $295.9 million in repurchases of Second Lien Notes, retirement of our Unsecured VEN Bakken Note of $130.0 million and net repayments under our Revolving Credit Facility of $477.0 million. Additionally, we paid common and preferred stock dividends of $4.9 million and $29.2 million, respectively, and spent $17.6 million in fees in connection with debt financing transactions in 2021.

The cash used for financing activities in 2020 was primarily related to a net decrease in borrowings of $48.0 million on our Revolving Credit Facility and repurchases of $13.5 million aggregate principal amount of our Second Lien Notes.

Revolving Credit Facility

In November 2019, we 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”), which amended and restated our existing revolving credit facility that was entered into on October 5, 2018. 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, 2021, the Revolving Credit Facility had a borrowing base of $850.0 million and an elected commitment amount of $750.0 million, and we had $55.0 million in borrowings outstanding under the facility, leaving $695.0 million in available committed borrowing capacity. See Note 4 to our financial statements for further details regarding the Revolving Credit Facility.

Unsecured Notes due 2028

As of December 31, 2021, we had outstanding $750.0 million aggregate principal amount of our 2028 Notes. See Note 4 to our financial statements for further details regarding the 2028 Notes.

Series A Preferred Stock

As of December 31, 2021, we had 2,218,732 outstanding shares of 6.500% Series A Perpetual Cumulative Convertible Preferred Stock (the “Series A Preferred Stock”), having an aggregate liquidation preference of $221.9 million (excluding accumulated dividends). See Note 5 to our financial statements for further details regarding the Series A Preferred Stock.

Known Contractual and Other Obligations; Planned Capital Expenditures

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 the Reliance Acquisition. 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.

Planned Capital Expenditures. For 2022, we are budgeting approximately $350 to $415 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. As of December 31, 2021, we had incurred $111.9 million in capital expenditures that were included in accounts payable, and we estimate that we were committed to an additional approximately $316.6 million in development capital expenditures not yet incurred for wells we had elected to participate in. We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Revolving Credit Facility. The foregoing excludes larger acquisitions, which are typically not included in our annual capital expenditure budget. For example, our unbudgeted Veritas Acquisition was pending as of December 31, 2021, and subsequently closed on January 27, 2022 (see Note 14 to our financial statements). See also “Capital Requirements” below.

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

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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, reduction of 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. Quantitative and Qualitative Disclosures About Market Risk.”

Capital Requirements

Development and acquisition activities are discretionary, and, for the near term, we expect such activities to be maintained at levels we can fund through cash on hand, internal cash flow and borrowings under our Revolving Credit Facility.  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.  Also, our obligations may change due to acquisitions, divestitures and continued growth.  Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital.  If internally generated cash flow and borrowing capacity is not available under our Revolving Credit Facility, we may issue additional equity or debt to fund capital expenditures, acquisitions, extend maturities or to repay debt.

Satisfaction of Our Cash Obligations for the Next Twelve Months

With our revolving credit agreement and our cash flows from operations, we believe we will have sufficient capital to meet our drilling commitments, expected general and administrative expenses and other cash needs for the next twelve months.  Nonetheless, any strategic acquisition of assets or increase in drilling activity may lead us to seek additional capital.  We may also choose to seek additional capital rather than utilize our credit facility or other debt instruments to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions.  We will evaluate any potential opportunities for acquisitions as they arise.  However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.

Effects of Inflation and Pricing

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry.  Typically, as prices for oil and natural gas increase, so do all associated costs.  Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion.  Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions.  Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel.  Higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel, which we expect to occur in 2022 compared to 2021.

Critical Accounting Estimates

The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our financial statements in accordance with generally accepted accounting principles in the United States (GAAP), as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions.

Use of Estimates

The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect our reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Our estimates of our proved oil and natural gas reserves, future development costs, estimates relating to certain oil and natural gas revenues and expenses, and fair value of derivative instruments are the most critical to our financial statements.

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Oil and Natural Gas Reserves

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.  The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment.  For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change.  Approximately 41% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserve, future cash flows from our reserves, and future development of our proved undeveloped reserves.

The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties.  Such information includes revisions of certain reserve estimates attributable to our properties included in the prior year’s estimates.  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.

External petroleum engineers independently estimated all of the proved reserve quantities included in our financial statements, and were prepared in accordance with the rules promulgated by the SEC. In connection with our external petroleum engineers performing their independent reserve estimations, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests. The third-party independent reserve engineers, Cawley, Gillespie & Associates, Inc., evaluated 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2021.

Oil and Natural Gas Properties

The method of accounting we use to account for our oil and natural gas investments determines what costs are capitalized and how these costs are ultimately matched with revenues and expensed.

We utilize the full cost method of accounting to account for our oil and natural gas investments instead of the successful efforts method because we believe it more accurately reflects the underlying economics of our programs to explore and develop oil and natural gas reserves. The full cost method embraces the concept that dry holes and other expenditures that fail to add reserves are intrinsic to the oil and natural gas exploration business. Thus, under the full cost method, all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs, geological and geophysical costs that are directly attributable to the properties and capitalized interest. Although some of these costs will ultimately result in no additional reserves, they are part of a program from which we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. The full cost method differs from the successful efforts method of accounting for oil and natural gas investments. The primary difference between these two methods is the treatment of exploratory dry hole costs. These costs are generally expensed under the successful efforts method when it is determined that measurable reserves do not exist. Geological and geophysical costs are also expensed under the successful efforts method. Under the full cost method, both dry hole costs and geological and geophysical costs are initially capitalized and classified as unproved properties pending determination of proved reserves. If no proved reserves are discovered, these costs are then amortized with all the costs in the full cost pool.

Capitalized amounts except unproved costs are depleted using the units of production method.  The depletion expense per unit of production is the ratio of the sum of our unamortized historical costs and estimated future development costs to our proved reserve volumes.  Estimation of hydrocarbon reserves relies on professional judgment and use of factors that cannot be precisely determined.  Subsequent reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting periods.  For the year ended December 31, 2021, our average depletion expense per unit of production was $7.07 per Boe.

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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.  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.  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.

At December 31, 2021, we performed an impairment review using prices that reflect an average of 2021’s monthly prices as prescribed pursuant to the SEC’s guidelines.  For the year ended 2021, we did not record any full cost impairment expense. For the year ended 2020, we recorded a $1,066.7 million full cost impairment expense. For the year ended 2019, we did not record any full cost impairment expense. If a low price environment reoccurs, we might be required to further 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.  See “Item 2. Properties” for a discussion of our reserve estimation assumptions.

Derivative Instrument Activities

We use derivative instruments from time to time to manage market risks resulting primarily from fluctuations in the prices of oil and natural gas.  We may periodically enter into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.  The notional amounts of these financial instruments are based on expected production from existing wells.  We may also use exchange traded futures contracts and option contracts to hedge the delivery price of oil at a future date.

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).  The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 12 to our financial statements for a description of the derivative contracts.

Recently Issued or Adopted Accounting Pronouncements

For discussion of recently issued or adopted accounting pronouncements, see Notes to Financial Statements—Note 2. Significant Accounting Policies.

Off-Balance Sheet Arrangements

We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

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