What changed in this filing

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Item 7. Management’s Discussion and Analysis

2023-02-24 compared with 2022-02-25 · 114 added, 121 removed, 325 unchanged (42% of the section changed)

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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 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”).

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.

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

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.

• 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

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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 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.

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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.

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.

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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 the price of oil;

• 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;

• 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.

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 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.

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 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.

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.

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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.

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

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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.

dollar can significantly impact oil prices.

Historically, commodity prices have been volatile and we expect the volatility to continue in the future.

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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.

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.

Results of Operations for 2022 and 2021

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Gain (Loss) on Unsettled Commodity Derivatives 40,187 (312,370)

Other Revenue 3 17

Total Revenues 1,570,535 496,899

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Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes.

In 2021, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, increased 201%

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.

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 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 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:

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We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production.

Our gain (loss) on commodity derivatives, net was a loss of $478.2 million in 2021, compared to a gain of $228.1 million in 2020.

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 2021, we realized a loss on settled commodity derivatives of $165.8 million, compared to a $188.3 million gain in 2020.

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.

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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 $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.

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 mark-to-market value of our commodity derivatives.

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

due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2020.

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.

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Production expenses were $260.7 million in 2022 compared to $170.8 million in 2021.

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.

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

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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 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.

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 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.

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 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 2022 and 2021 :

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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.

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.

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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 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.

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, 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.

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 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.

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.

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.

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.

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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.

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.

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:

• 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”);

• 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.

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).

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 63% and 77% of our total production volumes in 2021 and 2020, respectively.

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.

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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 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

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

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 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.

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.

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Net Cash Used for Investing Activities (1,402,777) (634,434)

Net Cash Provided by (Used for) Financing Activities 246,059 (62,399)

Net Cash Provided by Financing Activities 467,367 246,059

Net Change in Cash $ (6,992) $ 8,092

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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 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).

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, 2021 was a decrease of $85.8 million compared to an increase of $34.1 million in 2020.

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 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.

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.

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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.

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 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.

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

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

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.

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, 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.

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.

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.

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

As of December 31, 2021, we h ad 2,218,732 outsta nding 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.

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 h ad no outsta nding shares of Series A Preferred Stock.

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

Known Contractual and Other Obligations;

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See Note 12 to our financial statements.

We have firm commitments on certain assets that we assumed in the Reliance Acquisition.

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.

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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).

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.

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

We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, fluctuations in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

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

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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.

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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.

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

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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.

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

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

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:

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.

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

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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.

For the year ended 2021, we did not record any full cost impairment expense.

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.

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.

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

What changed 10-K

Item 7. Management’s Discussion and Analysis