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Item 7. Management’s Discussion and Analysis

2022-02-25 compared with 2021-03-12 · 149 added, 284 removed, 297 unchanged (59% of the section changed)

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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 participated in 6,640 gross (475.1 net) producing wells as of December 31, 2020.

As of December 31, 2020, we had leased approximately 183,527 net acres, of which approximately 90% were developed and substantially all were located in the Williston Basin in 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).

During 2020, we added 17.8 net wells to production, and we ended 2020 with 28.1 net wells in process.

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 gas sales of $324.1 million in 2020, plus an additional $188.3 million of cash settlements on commodity derivatives during 2020

• 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.

In addition, in March 2020, members of OPEC failed to agree on production levels which led to a substantial decrease in oil prices and an increasingly volatile market.

The oil price war ended in April 2020, with a deal to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand.

As a result of lower demand caused by the COVID-19 pandemic and the oversupply of crude oil, spot and future prices of crude oil fell to historic lows during the second quarter of 2020 and remained depressed through much of 2020.

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.

As a result of these factors, we reduced our 2020 developmental capital spending to $162.8 million, a reduction of 56% compared to our developmental capital expenditures in 2019.

Our 2020 production was significantly lower than originally expected due to actions by many of our operating partners to shut-in or curtail production and defer development plans as a result of the low commodity price environment.

We estimate that curtailments, shut-ins and delayed well completions reduced our average daily production by approximately 16,800 Boe per day in the second quarter of 2020 and by approximately 11,000 Boe per day in the third quarter of 2020.

We estimate that curtailments and shut-ins reduced our average daily production by approximately 4,200 Boe per day in the fourth quarter of 2020.

Conditions have improved with the recovery of commodity prices in late 2020 and early 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.

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.

As a result of low commodity prices during 2020, we incurred a full-cost ceiling test impairment charge of $1,066.7 million for the year ended December 31, 2020.

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.

Any ceiling test impairment charge would be non-cash in nature and should not impact any covenants under our various debt instruments.

In response to the COVID-19 pandemic, we have instituted various measures to protect our workforce and our business operations, such as remote working and business travel restrictions.

As a non-operator with no field operations, substantially all of our employees’ work can be completed from home.

We will continue to monitor the guidelines and recommendations provided by the relevant authorities, and we will continue to make decisions aimed at protecting and furthering the interests of all stakeholders.

Reverse Stock Split

On September 18, 2020, we effected a 1-for-10 reverse stock split of the Company’s issued and outstanding shares of common stock (the “Reverse Stock Split”).

References to numbers of shares of common stock and per share data have been adjusted to reflect the Reverse Stock Split on a retroactive basis.

See Note 5 to our financial statements for further information.

Source of Our Revenues

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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 production.

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.

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Principal Components of Our Cost Structure

• Oil price differentials .

The price differential between our well head price and the NYMEX WTI benchmark price is primarily driven by the cost to transport oil via train, pipeline or truck to refineries.

• 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.

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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 full cost pool.

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.

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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, an impairment expense or non-cash writedown is required.

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

• Income tax 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 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 Basin subjects our operating results to factors specific to this region.

These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, and the limitations of the developing infrastructure and transportation capacity in this region.

The price of oil in the Williston Basin can vary depending on the market in which it is sold and the means of transportation used to transport the oil to market.

Light sweet crude from the Williston Basin has a higher value at many major refining centers because of its higher quality relative to heavier and sour grades of oil;

however, because of the Williston Basin’s location relative to traditional oil transport centers, this higher value is generally offset to some extent by higher transportation costs.

While rail transportation has historically been more expensive than pipeline transportation, Williston Basin’s prices have at times justified shipment by rail to markets across the United States.

Additional pipeline infrastructure has increased takeaway capacity in the Williston Basin which has improved wellhead values in the region, specifically the Dakota Access Pipeline (“DAPL”) which has given the region low-cost transportation with access to Gulf Coast markets, which generally have higher benchmark pricing than WTI prices, offsetting some of the additional cost for the mode and increased distance of transportation.

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.

Thus, our operating results are also affected by changes in the oil price differentials between the NYMEX and the sales prices we receive for our oil production.

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.

Fluctuations in our oil price differential are due to several factors such as takeaway capacity relative to production levels in the Williston Basin, regional storage capacity, and seasonal refinery maintenance temporarily depressing crude demand.

As described in “Item 1A.

Risk Factors,” DAPL is subject to ongoing litigation and regulatory review that could threaten its continued operation.

During any period that DAPL is forced to shut down, we would expect our average oil price differential to increase, although it is difficult to predict with any precision what effect this would have.

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 oil prices that can substantially impact the level of drilling activity in the Williston Basin.

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.

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The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand.

Being primarily an oil producer, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas.

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.

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Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.

During the first half of 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices from $63.00 per Bbl in early January to an average of $27.95 per Bbl during the second quarter of 2020.

This sudden decline in oil prices was attributable to two primary factors:

(1) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (2) a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to increase its oil production to world markets following the failure of efforts by members of OPEC+ to agree on coordinated production cuts in March 2020.

The OPEC price war ended in April 2020, with a deal to cut global petroleum output but did not go far enough to offset the dramatic negative impact of COVID-19 on demand.

Oil prices improved since the second quarter of 2020, but the general outlook for commodity prices and the oil and natural gas industry remains uncertain, and we anticipate ongoing volatility.

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.

2020 2019 2018

Average NYMEX Prices (1)

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(1) Based on average NYMEX closing prices.

The average 2020 NYMEX pricing was $39.24 per barrel of oil or 31% lower than the average NYMEX price per barrel in 2019, which was partially offset by a $16.16 per barrel of oil increase in settled derivatives in 2020 as compared to 2019.

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.

Our 2020 realized gas price per Mcf was $1.14 compared to $1.60 in 2019, which was primarily driven by lower NYMEX pricing for both natural gas and natural gas liquids gas gathering as well as processing constraints in the Williston Basin.

Recent construction projects have greatly expanded processing capacity within the basin as well as a significant new natural gas liquids pipeline.

However, continued expansion of gathering systems in our basin will likely be required to fully harness these new systems and to improve long-term pricing realizations.

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.

The following tables reflect the weighted average price of open commodity price swap derivative contracts as of December 31, 2020, by year with associated volumes.

Weighted Average Price

of Open Oil Swap Contracts

Year Volumes (Bbl) Weighted

Average Price ($)

7,545,124 55.06

816,250 50.49

(1) We have entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for additional periods.

Options covering a notional volume of 3.1 million barrels for 2022 are exercisable on or about December 31, 2021.

If the counterparties exercise all such options, the notional volume of our existing crude oil derivative contracts will increase by 3.1 million barrels at a weighted average price of $52.68 per barrel for 2022.

(2) We have entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for additional periods.

Options covering a notional volume of 1.5 million barrels for 2023 are exercisable on or about December 31, 2022.

If the counterparties exercise all such options, the notional volume of our existing crude oil derivative contracts will increase by 1.5 million barrels at a weighted average price of $47.98 per barrel for 2023.

From time to time, we also hedge our oil basis differential to mitigate price risk associated with fluctuations in takeaway capacity.

As of December 31, 2020, we have hedged approximately 1.5 million barrels for 2021 at a weighted average price of $(2.39) per barrel.

See Note 12 to our financial statements.

Weighted Average Price

of Open Natural Gas Swap Contracts

Year Volumes (MMBtu) Weighted

Average Price ($)

2021 13,000,000 2.50

2022 3,650,000 2.61

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

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Years Ended December 31,

2020 2019 2018

Net Production:

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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 2020, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, decreased 46% from 2019, driven by a 14% decrease in production volumes coupled with a 37% decrease in realized prices, excluding the effect of settled commodity derivatives.

The lower average realized price in 2020 as compared to 2019 was principally driven by lower average NYMEX oil and natural gas prices.

The lower NYMEX oil prices were also affected by a higher average oil price differential in 2020 as compared to 2019.

The oil price differential during 2020 averaged $6.63 per barrel, as compared to $6.28 per barrel in 2019.

In 2019, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, increased 22% from 2018, driven primarily by a 51% increase in production levels offset by a 19% decrease in realized price, excluding the effect of settled derivatives.

The lower average realized price in 2019 as compared to 2018 was principally driven by lower average NYMEX oil and natural gas prices, and gas gathering and processing constraints in the Williston Basin that lowered realized gas prices.

The lower NYMEX oil prices were partially offset by a lower average oil price differential in 2019 as compared to 2018.

The oil price differential during 2019 averaged $6.28 per barrel, as compared to $7.12 per barrel in 2018.

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.

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.

Curtailments, shut-ins and completion delays due to the significant decline in commodity prices drove our 14% decrease in production levels in 2020 as compared to 2019, more than offsetting additions from acquisitions and new wells brought online.

See “Impacts of COVID-19 Pandemic and Economic Environment” above.

During 2019, our substantial acquisition activities (see Note 3 to our financial statements) combined with increased development activity and improved performance from enhanced completion techniques helped drive an increase in production levels as compared to 2018.

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 higher number of new well completions and per well productivity improvements drove the 51% increase in production as compared to 2018.

Our production for each of the last three years is set forth in the following table:

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:

Year Ended December 31,

2020 2019 2018

Oil (Bbl) 12,288,358 9,361,138

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

Our gain (loss) on commodity derivatives, net was a gain of $228.1 million in 2020, compared to a loss of $128.8 million in 2019, and a gain of $185.0 million in 2018.

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 2020, we realized a gain on settled commodity derivatives of $188.3 million, compared to a $44.4 million gain in 2019 and a $22.9 million loss in 2018.

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 2020, 2019, and 2018 was $58.04, $61.51, and $59.27, respectively.

Our average realized price (including all commodity derivative cash settlements) in 2020 was $42.32 per Boe compared to $45.82 per Boe in 2019, and $50.50 per Boe in 2018.

The gain (loss) on settled commodity derivatives increased our average realized price per Boe by $15.55 in 2020, increased our average realized price per Boe by $3.15 in 2019 and decreased our average realized price per Boe by $2.45 in 2018.

Unsettled commodity derivative gains and losses was a gain of $39.9 million in 2020 compared to a loss of $173.2 million in 2019 and a gain of $207.9 million in 2018.

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.

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Any gains on our unsettled commodity derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date.

At December 31, 2020, all of our derivative contracts are recorded at their fair value, which was a net asset of $33.7 million, an increase of $38.9 million from the $5.2 million net liability recorded as of December 31, 2019.

The increase in the net asset at December 31, 2020 as compared to December 31, 2019 was primarily due to changes in forward oil prices relative to prices on our open oil derivative contracts since December 31, 2019.

Our open oil derivative contracts are summarized in “Item 7A.

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.

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 $116.3 million in 2020 compared to $118.9 million in 2019 and $66.6 million in 2018.

On a per unit basis, production expenses increased 14% from $8.44 per Boe in 2019 to $9.61 per Boe in 2020 due primarily to fixed costs related to shut-in and/or curtailed production as well as higher per unit costs for processing.

On an absolute dollar basis, the 2% decrease in our production expenses in 2020 compared to 2019 was primarily due to a 14% decrease in production offset by a 14% increase in per unit costs.

On a per unit basis, our production expenses increased from $7.15 per Boe in 2018 to $8.44 per Boe in 2019 due primarily to fixed costs related to shut-in and/or curtailed production as well as higher per unit costs for processing and saltwater disposal charges.

On an absolute dollar basis, our production expenses in 2019 were 78% higher when compared to 2018 due primarily to a 51% increase in production and the 18% increase in per unit costs.

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 $29.8 million in 2020 compared to $57.8 million in 2019 and $45.3 million in 2018.

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 gas sales.

Oil sales are taxed at a higher rate than gas sales.

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 $18.5 million for 2020 compared to $23.6 million for 2019 and $14.6 million for 2018.

The decrease in 2020 compared to 2019 was primarily due to a $4.1 million reduction in compensation expense, primarily due to lower non-cash share-based compensation and a decrease in cash severance charges incurred with the departure of an executive officer during the fourth quarter of 2019.

Additionally, the decrease in 2020 compared to 2019 was due in part to a reduction in professional fees of $1.0 million.

General and administrative expenses in 2019 as compared to 2018 were higher primarily due to a $5.7 million increase in compensation expense, $4.1 million of which was an increase in non-cash share-based compensation, due in part to additions to our executive team that occurred late in the second quarter of 2018 and the timing of our 2018 and 2019 performance-based equity awards.

The increase in 2019 was also due to a $0.8 million cash severance charge incurred with the departure of an executive officer during the fourth quarter of 2019 and $1.8 million in legal and advisory fees incurred in 2019 in connection with the VEN Bakken Acquisition.

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 $162.1 million in 2020 compared to $210.2 million in 2019 and $119.8 million in 2018.

Depletion expense, the largest component of DD&A, was $13.27 per Boe in 2020 compared to $14.84 per Boe in 2019 and $12.75 per Boe in 2018.

The aggregate decrease in depletion expense for 2020 compared to 2019 was driven by a 14% decrease in production levels and a 11% decrease in the depletion rate per Boe.

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 aggregate increase in depletion expense for 2019 compared to 2018 was driven by a 51% increase in production levels and a 16% increase in the depletion rate per Boe.

The 2019 depletion rate per Boe was higher due to an increase in well costs and the impact of acquisitions in 2019.

The following table summarizes DD&A expense per Boe for 2021 and 2020 :

Year Ended December 31, Year Ended December 31,

2020 2019 Change Change 2019 2018 Change Change

Year Ended December 31,

2021 2020 Change Change

Depletion $ 7.07 $ 13.27 $ (6.20) (47) %

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Impairment of Oil and Natural Gas Properties

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 $1,066.7 million in 2020.

We did not record any impairment of our proved oil and gas properties in 2019 or 2018.

The impairment charge affected our reported net income but did not reduce our cash flow.

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.

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Interest Expense

Interest expense, net of capitalized interest, was $58.5 million in 2020 compared to $79.2 million in 2019 and $86.0 million in 2018.

The decrease in interest expense for 2020 as compared to 2019 was primarily due to a reduction in our outstanding debt balance during 2020 and lower interest rates on our Revolving Credit Facility.

The decrease in interest expense for 2019 as compared to 2018 was primarily due to lower interest rates on our Revolving Credit Facility compared to our prior term loan facility, which was retired in October 2018.

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

During 2019, we recorded a loss on extinguishment of debt of $23.2 million as a result of early redemptions of our Second Lien Notes (see Note 4 to our financial statements), based on the differences between the reacquisition costs of retiring the applicable debt and the net carrying values thereof.

During 2018, we recorded a loss on extinguishment of debt of $173.4 million as a result of early redemptions of our prior senior unsecured notes and our prior term loan facility.

Debt Exchange Derivative Gain (Loss)

We incurred debt exchange derivative liabilities during 2018 in connection with certain exchange transactions with respect to previously outstanding senior unsecured notes.

During the years ended December 31, 2019 and 2018, we recorded a debt exchange derivative liability gain of $1.4 million and loss of $0.6 million, respectively, due to the change in the fair value of these liabilities.

As of December 31, 2019, there were no remaining outstanding debt exchange derivative liabilities, and as a result there were no associated gains or losses during 2020.

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 incurred contingent consideration liabilities during 2018 in connection with certain acquisitions of oil and gas properties that closed in 2018.

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, 2019, there were no remaining outstanding contingent consideration liabilities, and as a result there were no associated gains or losses during 2020.

Income Tax Benefit

We recognized income tax benefit of $0.2 million, zero, and $0.1 million in 2020, 2019, and 2018, respectively.

The effective tax rate was zero in each of 2020, 2019, and 2018, due to our full valuation allowance on our deferred tax assets.

In 2020 and 2018, the tax benefits recognized related to the utilization of our alternative minimum tax credit as a result of favorable tax incentives.

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.

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For further discussion of our valuation allowance, see Note 10 to our financial statements.

Non-GAAP Financial Measures

Adjusted Net Income and Adjusted EBITDA are non-GAAP measures.

Net income (loss) is the most directly comparable GAAP measure for both Adjusted Net Income and Adjusted EBITDA, and tabular reconciliations for these measures are included below.

We recorded a net loss of $906.0 million (representing $21.55 per diluted share) for 2020, compared to a net loss of $76.3 million (representing $2.00 per diluted share) for 2019 and net income of $143.7 million (representing $6.07 per diluted share) for 2018.

We define Adjusted Net Income (Loss) as net income (loss) excluding (i) unrealized (gain) loss on unsettled commodity derivatives, net of tax, (ii) financing expense, net of tax, (iii) impairment of other current assets, net of tax, (iv) write-off of debt issuance costs, net of tax, (v) loss on the extinguishment of debt, net of tax, (vi) debt exchange derivative (gain) loss, net of tax, (vii) contingent consideration loss, net of tax, (viii) acquisition transaction costs, net of tax, (ix) impairment expense, net of tax, and (x) loss on unsettled interest rate derivatives, net of tax.

Our Adjusted Net Income for 2020 was $96.0 million (representing $1.82 per diluted share) as compared to Adjusted Net Income for 2019 of $120.9 million (representing $3.06 per diluted share) and Adjusted Net Income of $140.7 million (representing $5.94 per diluted share) for 2018.

The decrease in Adjusted Net Income in 2020 compared to 2019 was primarily due to lower realized commodity prices (after the effect of settled derivatives), lower production volumes and increased per unit production expenses, which were partially offset by lower interest costs.

The increase in Adjusted Net Income in 2019 compared to 2018 was primarily due to significantly higher production volumes as a result of our acquisitions and organic growth and lower interest costs, partially offset by increased per unit expenses and lower realized commodity prices (after the effect of settled derivatives).

We define Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization, and accretion, (iv) (gain) loss on unsettled commodity derivatives, (v) non-cash stock based compensation expense, (vi) write-off of debt issuance costs, (vii) loss on the extinguishment of debt, (viii) impairment of other current assets, (ix) debt exchange derivative (gain) loss, (x) contingent consideration loss, (xi) financing expense, (xii) impairment expense, (xiii) (gain) loss on unsettled interest rate derivatives, and (xiv) cash severance expense.

Adjusted EBITDA for 2020 was $351.8 million, compared to Adjusted EBITDA of $454.2 million in 2019 and $349.3 million in 2018.

The decrease in Adjusted EBITDA in 2020 as compared to 2019 was primarily due to lower production volumes, higher per unit production expenses, and lower realized commodity prices (after the effect of settled derivatives).

The increase in Adjusted EBITDA in 2019 as compared to 2018 was primarily due to significantly higher production volumes as a result of our acquisitions and organic growth, partially offset by increased per unit expenses and lower realized commodity prices (after the effect of settled derivatives).

Management believes the use of these non-GAAP financial measures provide useful information to investors to gain an overall understanding of our current financial performance.

Specifically, management believes the non-GAAP financial measures included herein provide useful information to both management and investors by excluding certain items that our management believes are not indicative of our core operating results.

In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring our performance, and we believe that we are providing investors with financial measures that most closely align to our internal measurement processes.

We consider these non-GAAP measures to be useful in evaluating our core operating results as they provide useful information regarding our essential revenue generating activities and direct operating expenses (resulting in cash expenditures) needed to perform these revenue generating activities.

Our management also believes, based on feedback provided by the investment community, that the non-GAAP financial measures are necessary to allow the investment community to construct its valuation models to better compare our results with our competitors and market sector.

These measures should be considered in addition to our results of operations prepared in accordance with GAAP.

In addition, these non-GAAP financial measures are not based on any comprehensive set of accounting rules or principles.

We believe that non-GAAP financial measures have limitations in that they do not reflect all of the amounts associated with our results of operations as determined in accordance with GAAP and that these measures should only be used to evaluate our results of operations in conjunction with the corresponding GAAP financial measures.

Reconciliation of Adjusted Net Income

Years Ended December 31,

(In thousands, except share and per share data) 2020 2019 2018

Net Income (Loss) $ (906,041) $ (76,318) $ 143,689

Impact of Selected Items:

(Gain) Loss on Unsettled Commodity Derivatives (39,878) 173,214 (207,892)

Impairment Expense 1,066,668 — —

Financing Expense — 1,447 884

Impairment of Other Current Assets — 6,398 —

Write-off of Debt Issuance Costs 1,543 — —

Loss on the Extinguishment of Debt 3,718 23,187 173,430

Debt Exchange Derivative (Gain) Loss — (1,390) 598

(Gain) Loss on Unsettled Interest Rate Derivatives 1,019 — —

Contingent Consideration Loss 169 29,512 28,968

Acquisition Transaction Costs — 1,763 —

Selected Items, Before Income Taxes 1,033,240 234,130 (4,012)

Income Tax of Selected Items (1)

(31,164) (36,898) 983

Selected Items, Net of Income Taxes 1,002,076 197,232 (3,029)

Adjusted Net Income $ 96,035 $ 120,914 $ 140,660

Weighted Average Shares Outstanding – Basic 42,744,639 38,708,460 23,620,646

Weighted Average Shares Outstanding – Diluted 52,659,217 39,482,135 23,677,391

Net Income (Loss) Per Common Share – Basic $ (21.20) $ (1.97) $ 6.08

Impact of Selected Items, Net of Income Taxes 23.45 5.09 (0.12)

Adjusted Net Income Per Common Share – Basic $ 2.25 $ 3.12 $ 5.95

Net Income (Loss) Per Common Share – Diluted $ (17.21) $ (1.93) $ 6.07

Impact of Selected Items, Net of Income Taxes 19.03 4.99 (0.13)

Adjusted Net Income Per Common Share – Diluted $ 1.82 $ 3.06 $ 5.94

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(1) The 2020 column represents a tax impact using an estimated tax rate of 24.5% and includes an adjustment of $222.0 million for changes in our valuation allowance.

The 2019 column represents a tax impact using an estimated tax rate of 24.5% and includes an adjustment of $20.5 million for changes in our valuation allowance.

The 2018 column represents a tax impact using an estimated tax rate of 24.5% and does not include any adjustments for changes in our valuation allowance.

Reconciliation of Adjusted EBITDA

Year Ended December 31,

(In thousands) 2020 2019 2018

Net Income (Loss) $ (906,041) $ (76,318) $ 143,689

Interest Expense 58,503 79,229 86,005

Income Tax Provision (Benefit) (166) — (55)

Depreciation, Depletion, Amortization and Accretion 162,120 210,201 119,780

Impairment of Other Current Assets — 6,398 —

Non-Cash Stock-Based Compensation 4,119 7,955 3,876

Write-off of Debt Issuance Costs 1,543 — —

Loss on the Extinguishment of Debt 3,718 23,187 173,430

Debt Exchange Derivative (Gain) Loss — (1,390) 598

Contingent Consideration Loss 169 29,512 28,968

Financing Expense — 1,447 884

Cash Severance Expense — 759 —

(Gain) Loss on Unsettled Interest Rate Derivatives 1,019 — —

(Gain) Loss on Unsettled Commodity Derivatives (39,878) 173,214 (207,892)

Impairment Expense 1,066,668 — —

Adjusted EBITDA 351,774 454,193 349,283

Liquidity and Capital Resources

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

As of December 31, 2020, we had outstanding debt consisting of $532.0 million of borrowings under our Revolving Credit Facility, $287.8 million aggregate principal amount of our 8.500% senior secured second lien notes due 2023 (the “Second Lien Notes”) and $130.0 million aggregate principal amount under our 6.0% Senior Unsecured Promissory Note due 2022 (the “Unsecured VEN Bakken Note”).

We had $129.4 million in liquidity as of December 31, 2020, consisting of $128.0 million of borrowing availability under the Revolving Credit Facility and $1.4 million of cash on hand.

Subsequent to the end of 2020, in February 2021, we entered into an agreement to acquire producing natural gas properties in the Appalachian Basin from Reliance Marcellus, LLC (the “Reliance Acquisition”), which we anticipate will close in April 2021.

In February 2021, we also completed a number of significant financing transactions, including:

• a common stock offering with estimated net proceeds of $132.4 million, which is primarily intended to finance a portion of the cash purchase price for the pending Reliance Acquisition;

• the issuance of $550.0 million in aggregate principal amount of new 8.125% senior unsecured notes due 2028 (the “2028 Notes”), with estimated net proceeds of $537.0 million that are primarily intended to refinance the Second Lien Notes, refinance the Unsecured VEN Bakken Note, fund any remaining cash purchase price for the pending Reliance Acquisition, and repay borrowings under the Revolving Credit Facility;

• fully repaid and retired the Unsecured VEN Bakken Note;

• redeemed and retired $272.1 million in aggregate principal amount of our Second Lien Notes pursuant to a cash tender offer, leaving $15.7 million in aggregate principal amount of Second Lien Notes remaining outstanding immediately thereafter.

See Note 14 to our financial statements for further details regarding the pending Reliance Acquisition and the February 2021 financing transactions described above.

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.

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

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As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices.

We seek to maintain a robust hedging program to mitigate volatility in the price of crude oil with respect to a portion of our expected oil production.

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.

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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 decreased by $7.4 million and current liabilities decreased by $21.0 million at December 31, 2020, compared to December 31, 2019.

The decrease in current assets in 2020 as compared to 2019 is primarily due to a decrease of $37.3 million in accounts receivable primarily due to our lower production levels and reduced commodity prices and a lower cash balance, which was partially offset by an increase of $45.7 million in our derivative instruments, due to the change in fair value as a result of oil price projections.

The change in current liabilities in 2020 as compared to 2019 is primarily due to a decrease of $75.3 million in accounts payable and accrued expenses primarily as a result of reduced development activity and an $8.2 million decrease in derivative instruments as a result of forward oil 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 was reduced by $3.3 million as a result of lower levels of debt outstanding in 2020 as compared to 2019.

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

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 from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital.

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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.

As of December 31, 2020, we had entered into oil derivative swap contracts hedging 7.5 million barrels of oil in 2021 at an average price of $55.06 per barrel and 0.8 million barrels of oil in 2022 at an average price per barrel of $50.49.

In addition, we had entered into natural gas derivative swap contracts hedging 13.0 million MMbtu in 2021 at an average price of $2.50 per MMbtu, and 3.7 million MMbtu in 2022 at an average price of $2.61 per MMbtu.

See “Item 7A.

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Net cash provided by operating activities in 2021 was $396.5 million, compared to $331.7 million in 2020.

This decrease was driven by a 14% year-over-year reduction in production levels and an 8% decrease in realized prices (including the effect of settled derivatives), which was partially offset by lower interest costs.

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, 2020 was an increase of $34.1 million compared to a decrease of $37.5 million in 2019.

The increase in net cash provided by operating activities in 2019 was due to a 51% year-over-year increase in production levels and lower interest costs, which was partially offset by a 9% decrease in realized prices (including the effect of settled derivatives) compared to 2018.

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 $283.9 million, $569.1 million and $474.5 million during the years ended December 31, 2020, 2019 and 2018, respectively, primarily as a result of our capital expenditures for drilling, development and acquisition costs.

The year-over-year decrease in cash used in investing activities in 2020 was attributable to lower development spending as a result of the lower commodity price environment and our VEN Bakken acquisition that closed in 2019.

Additionally, the amount of capital expenditures included in accounts payable (and thus not included in cash flows from investing activities) was $88.6 million and $161.7 million at December 31, 2020 and 2019, respectively, with the reduction due to decreased activity in our core development areas.

The year-over-year increase in cash used in investing activities in 2019 was attributable to higher development spending and the VEN Bakken acquisition, when compared to 2018.

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.

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Cash Flows from Financing Activities

Net cash (used for) provided by financing activities was $(62.4) million, $243.1 million and $130.4 million for the years ended December 31, 2020, 2019 and 2018, respectively.

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 of aggregate principal amount of our Second Lien Notes (See Note 4 to our financial statements)

The cash provided by financing activities in 2019 was primarily related to a net increase in borrowings of $440.0 million on our Revolving Credit Facility and $70.9 million for the issuance of preferred stock which was partially offset by repayments of our Second Lien Notes of $227.5 million in connection with a prior refinancing transaction (See Note 4 to our financial statements).

Additionally, we repurchased $15.1 million of common stock and spent $12.2 million in fees in connection with debt financing transactions in 2019.

The cash provided by financing activities in 2018 was primarily related to $141.7 million in equity offerings, as well as a net increase in borrowings of $40.0 million on our Revolving Credit Facility.

Additionally, we repurchased $22.2 million of common stock and spent $26.6 million in fees in connection with debt financing transactions in 2018.

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

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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, 2020, the Revolving Credit Facility had a borrowing base of $660.0 million and we had $532.0 million of borrowings outstanding under the facility, leaving $128.0 million in available borrowing capacity.

See Note 4 and Note 14 to our financial statements for further details regarding the Revolving Credit Facility.

Second Lien Notes due 2023

As of December 31, 2020, we had $287.8 million in outstanding principal amount of our 8.500% senior secured second lien notes due 2023 (the “Second Lien Notes”).

See Note 4 and Note 14 to our financial statements for further details regarding the Second Lien Notes.

Unsecured VEN Bakken Note

As of December 31, 2020, we had $130.0 million in outstanding principal amount under the Unsecured VEN Bakken Note.

See Note 4 and Note 14 to our financial statements for further details regarding the Unsecured VEN Bakken Note.

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, 2020, we had 2.2 million 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.

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.

2021 Capital Expenditure Budget

Our board of directors has approved a capital expenditure budget for calendar year 2021.

However, 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.

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.

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.

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

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

and projected returns.

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

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

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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 require us to seek additional capital.

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.

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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.

While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

Contractual Obligations and Commitments

The following table summarizes our obligations and commitments at December 31, 2020 to make future payments under certain contracts, aggregated by category of contractual obligation, for specified time periods:

Payment due by Period

(In thousands)

Contractual Obligations Less than

1 year 1-3 years 3-5 years More than

5 years Total

Office Leases (1)

$ 340 $ — $ — $ — $ 340

Long Term Debt (2)

65,000 352,755 532,000 — 949,755

Cash Interest Expense on Debt (3)

43,872 66,606 13,855 — 124,333

Total $ 109,212 $ 419,361 $ 545,855 $ — $ 1,074,428

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(1) Office leases through 2021

(2) Revolving Credit Facility, Second Lien Notes and Unsecured VEN Bakken Note (see Note 4 to our financial statements)

(3) Cash interest on our Revolving Credit Facility, Second Lien Notes and Unsecured VEN Bakken Note are estimated assuming no principal repayment until the due date.

The above contractual obligations schedule does not include future anticipated settlement of derivative contracts or estimated amounts expected to be incurred in the future associated with the abandonment of our oil and natural gas properties, as we cannot determine with accuracy the amount and/or timing of such payments.

Critical Accounting Policies

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.

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

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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.

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.

3 unchanged sentences

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, 2020, our average depletion expense per unit of production was $13.27 per Boe.

For the year ended December 31, 2021, our average depletion expense per unit of production w as $7.07 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.

6 unchanged sentences

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 December 31, 2020, we recorded a $1,066.7 million full cost impairment expense.

For the years ended 2019 and 2018, we did not record any full cost impairment expense.

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.

2 unchanged sentences

Derivative Instrument Activities

We use derivative instruments from time to time to manage market risks resulting from fluctuations in the prices of oil and natural gas.

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.

11 unchanged sentences

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