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Item 7. Management’s Discussion and Analysis

2021-03-12 compared with 2020-03-12 · 192 added, 226 removed, 389 unchanged (52% of the section changed)

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with the “Selected Financial Data” in Item 6 and the Financial Statements and accompanying Notes to Financial Statements appearing elsewhere in this report.

The following discussion should be read in conjunction with our financial statements and accompanying notes to financial statements appearing elsewhere in this report.

Executive Overview

We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas properties, primarily in the Bakken and Three Forks formations within the Williston Basin in North Dakota and Montana.

We believe the location, size and concentration of our acreage position in one of North America’s leading unconventional oil-resource plays provide us with drilling and development opportunities that will result in significant long-term value.

Our primary focus is oil exploration and production through non-operated working interests in wells drilled and completed in spacing units that include our acreage.

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.

Our average daily production for full year 2020 was 33,078 Boe per day, and in the fourth quarter of 2020 was 35,738 Boe per day (approximately 76% oil).

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

Our financial and operating performance for the year ended December 31, 2020 included the following:

• Oil and gas sales of $601.2 million in 2019, compared to $493.9 million in 2018

• Cash flows from operations of $339.7 million in 2019, compared to $244.3 million in 2018

• Average daily production of 38,604 Boepd in 2019, a 51% increase compared to 25,555 Boepd in 2018

• Added 133.2 net wells to production in 2019, including 90.1 net wells from the VEN Bakken acquisition

• Proved reserves of 163.3 MMBoe at December 31, 2019, a 21% increase compared to December 31, 2018, as estimated by our third-party reserve engineers under SEC guidelines

• Accelerated our growth with the VEN Bakken Acquisition that closed on July 1, 2019, which we estimate contributed approximately 7,912 Boepd, or 18%, of our average daily production in the fourth quarter of 2019

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

• Cash flows from operations of $331.7 million in 2020

• Proved reserves of 122.6 MMBoe at December 31, 2020, as estimated by our third-party reserve engineers under SEC guidelines

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.

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.

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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• Oil price differentials .

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

• Gain (loss) on derivative instruments, net.

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of oil.

Gain (loss) on derivative instruments, net is comprised of (i) cash gains and losses we recognize on settled derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on derivative instruments outstanding at period-end.

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.

• Gain (loss) on commodity derivatives, net.

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas.

Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end.

• Production expenses.

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• Production taxes.

Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing

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We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions.

In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.

• Depreciation, depletion, amortization and impairment.

Depreciation, depletion, amortization and impairment includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties.

• Depreciation, depletion, amortization and accretion.

Depreciation, depletion, amortization and accretion includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties.

As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method.

Accretion expense relates to the passage of time of our asset retirement obligations.

• General and administrative expenses.

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We include interest expense that is not capitalized into the full cost pool, the amortization of deferred financing costs and bond premiums (including origination and amendment fees), commitment fees and annual agency fees as interest expense.

• Impairment expense.

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter.

The test determines a limit, or ceiling, on the book value of the proved oil and gas properties.

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

• Income tax expense.

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• the level of our operating expenses.

In addition to the factors that affect companies in our industry generally, the location of our acreage and wells in the Williston Basin subjects our operating results to factors specific to this region.

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.

We believe that gas gathering and processing constraints in the Williston Basin caused curtailments, shut-ins and completion delays that negatively impacted our production during 2019, and we expect these challenges to persist into 2020.

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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 North Dakota’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 prices have at times justified shipment by rail to markets on the gulf coast and east coast, which offer prices benchmarked to LLS/Brent.

Additional pipeline infrastructure has increased takeaway capacity in the Williston Basin which has improved wellhead values in the region.

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.

The price at which our oil production is sold typically reflects a discount to the NYMEX benchmark price.

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Our oil price differential to the NYMEX benchmark price during 2020 was $6.63 per barrel, as compared to $6.28 per barrel in 2019.

Fluctuations in our oil price differential are driven by various factors including (among others) takeaway capacity relative to production levels in the Williston Basin, and seasonal refinery maintenance temporarily depressing crude demand.

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.

Another significant factor affecting our operating results is drilling costs.

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Lower oil prices have generally had the opposite effect.

In addition, individual components of the cost can vary depending on numerous factors such as the length of the horizontal lateral, the number of fracture stimulation stages, the choice of proppant, and other factors related to the completion techniques utilized.

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 2020, the weighted average authorization for expenditure (or AFE) cost for wells we elected to participate in was $7.5 million, compared to $8.0 million for the wells we elected to participate in during 2019.

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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.

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Our average 2020 realized oil price per barrel after reflecting settled derivatives was $52.69 compared to $54.66 in 2019.

Our 2019 realized gas price per Mcf was $1.60 compared to $4.74 in 2018, which was primarily driven by gas gathering and processing constraints in the Williston Basin as well as lower NYMEX pricing for both natural gas and natural gas liquids.

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.

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As of December 31, 2019, we had a total volume on open commodity swaps of 17.3 million barrels at a weighted average price of approximately $56.77 per barrel.

The following table reflects the weighted average price of open commodity price swap derivative contracts as of December 31, 2019, by year with associated volumes.

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 Commodity Swap Contracts

of Open Oil Swap Contracts

Year Volumes (Bbl) Weighted

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816,250 50.49

1,372,866 52.57

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

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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.

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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

Results of Operations for 2020, 2019 and 2018

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Natural Gas and NGL Sales 18,802 26,601 43,760

Gain (Loss) on Settled Derivatives 44,377 (22,886) 3,777

Unrealized Gain (Loss) on Derivatives (173,214) 207,892 (18,443)

Gain (Loss) on Settled Commodity Derivatives 188,264 44,377 (22,886)

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

Other Revenue 17 21 9

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Oil (per Bbl) $ 32.61 $ 50.74 $ 57.78

Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl) 3.92 (2.94) 0.83

Oil Net of Settled Derivatives (per Bbl) 54.66 54.84 45.92

Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl) 20.08 3.92 (2.94)

Oil Net of Settled Oil Derivatives (per Bbl) 52.69 54.66 54.84

Natural Gas and NGLs (per Mcf) 1.14 1.60 4.74

Realized Price on a Boe Basis Including all Realized Derivative Settlements 45.82 50.50 42.16

Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.02 — —

Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) 1.16 1.60 4.74

Realized Price on a Boe Basis Excluding Settled Commodity Derivatives 26.77 42.67 52.95

Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) 15.55 3.15 (2.45)

Realized Price on a Boe Basis Including Settled Commodity Derivatives 42.32 45.82 50.50

Operating Expenses (in thousands):

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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 2019, our oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased 22% from 2018, driven by a 51% increase in production volumes 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

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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.

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 2018, our oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased 121% from 2017, driven primarily by an 73% increase in production levels and a 28% increase in realized price, excluding the effect of settled derivatives.

The higher average realized price in 2018 as compared to 2017 was principally driven by higher average NYMEX oil and natural gas prices.

These higher prices were partially offset by a higher average oil price differential in 2018 as compared to 2017, which was the most pronounced in the fourth quarter of 2018, coinciding with our highest levels of production for the year.

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.

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.

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 a 51% increase in production levels as compared to 2018.

During 2019, we added 133.2 total net wells to production, including 90.1 net wells from the VEN Bakken acquisition.

Excluding the wells added from acquisitions, this was a 38% increase as compared to 2018.

Our acquisition program is a significant driver of our net well additions.

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 2019, the number of net wells we added to production (excluding acquisitions) increased by 38% as compared to 2018.

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

Derivative Instruments

We enter into derivative instruments to mitigate the price risk attributable to future oil production.

Our gain (loss) on derivative instruments, net was a loss of $128.8 million in 2019, compared to a gain of $185.0 million in 2018, and a loss of $14.7 million in 2017.

For 2019, we realized a gain on settled derivatives of $44.4 million, compared to a $22.9 million loss in 2018 and a $3.8 million gain in 2017.

Commodity Derivative Instruments

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

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

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.

The percentage of oil production hedged under our derivative contracts was 104%, 76%, and 64% in 2020, 2019, and 2018, respectively.

The weighted average oil price on our settled derivative contracts in 2019, 2018, and 2017 was $61.51, $59.27, and $52.61, respectively.

Our average realized price (including all cash derivative settlements) in 2019 was $45.82 per Boe compared to $50.50 per Boe in 2018, and $42.16 per Boe in 2017.

The gain (loss) on settled derivatives increased our average realized price per Boe by $3.15 in 2019, decreased our average realized price per Boe by $2.45 in 2018 and increased our average realized price per Boe by $0.70 in 2017.

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Mark-to-market derivative gains and losses was a loss of $173.2 million in 2019 compared to a gain of $207.9 million in 2018 and a loss of $18.4 million in 2017.

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.

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 derivatives.

Any gains on our 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, 2019, all of our derivative contracts are recorded at their fair value, which was a net liability of $5.2 million, a decrease of $182.9 million from the $177.7 million net asset recorded as of December 31, 2018.

The decrease in the net liability at December 31, 2019 as compared to December 31, 2018 was primarily due to changes in forward oil prices relative to prices on our open oil derivative contracts since December 31, 2019.

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, 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.

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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 18% 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, the 78% increase in our production expenses in 2019 compared to 2018 was primarily due to a 51% increase in production and an 18% increase in per unit costs.

On a per unit basis, our production expenses decreased from $9.21 per Boe in 2017 to $7.15 per Boe in 2018 due primarily to higher production levels over which fixed costs are spread.

On an absolute dollar basis, our production expenses in 2018 were 34% higher when compared to 2017 due primarily to a 73% increase in production and a 42% increase in net producing wells, offset by the decline in per unit costs.

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 Taxes

We pay production taxes based on realized oil and natural gas sales.

Higher production levels in 2019 as compared to 2018, and in 2018 as compared to 2017, increased the taxable base that is used to calculate production taxes.

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

As a percentage of oil and natural gas sales, our production taxes were 9.2%, 9.6% and 9.2% in 2020, 2019 and 2018, respectively.

The higher average production tax rates in 2019, compared to 2018 and 2017, is due to an increase in our oil sales as a percentage of our total oil and 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 gas sales.

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

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General and administrative expenses were $18.5 million for 2020 compared to $23.6 million for 2019 and $14.6 million for 2018.

The increase in 2019 compared to 2018 was 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 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 in 2018 as compared to 2017 were lower due in part to a $3.6 million litigation settlement charge in the third quarter of 2017 and a $1.2 million reversal of non-cash share-based compensation expense in connection with the resignation of a former executive officer in the first quarter of 2018.

Depletion, Depreciation, Amortization and Accretion

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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.

The 2020 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 the impact of recent acquisitions in 2019 and 2018.

The aggregate increase in depletion expense for 2018 compared to 2017 was driven by an 73% increase in production levels and a 17% 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 2020, 2019 and 2018:

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Year Ended December 31, Year Ended December 31,

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Impairment of Oil and Natural Gas Properties

We did not have any impairment of our proved oil and gas properties in 2019, 2018, and 2017.

Depending on future commodity price levels, the trailing twelve-month average price used in the ceiling calculation may decline, which could cause future write downs of our 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.

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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.

The increase in interest expense for 2018 as compared to 2017 was primarily due to an increase in average borrowings outstanding between periods, with higher interest rates and a lower amount of capitalized interest cost.

A portion of the increased interest expense was non-cash payment-in-kind interest under our Second Lien Notes.

The higher interest rates were associated in large part with our prior term loan facility, which was retired in October 2018 and replaced with a lower cost and more flexible Revolving Credit Facility.

Loss on the Extinguishment of Debt

As a result of the November 2019 refinancing transactions (see Note 4 to our financial statements), we recorded a loss on the extinguishment of debt of $23.2 million for the year ended December 31, 2019 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 the exchange agreements and early redemptions of our 8% senior unsecured notes and our term loan facility (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 2017, we recorded a loss on extinguishment of debt of $1.0 million as a result of the early termination of a prior revolving credit facility.

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)

In connection with certain exchange transactions with respect to our Unsecured Notes (described as the “Additional 2018 Exchanges” in Note 4 to our financial statements), we incurred debt exchange derivative liabilities during 2018.

During the year ended December 31, 2019, we recorded a debt exchange derivative liability gain of $1.4 million due to the change in the fair value of these liabilities (see Note 11 to our financial statements).

During the year ended December 31, 2018, we recorded a debt exchange derivative liability loss of $0.6 million due to the change in the fair value of these liabilities (see Note 11 to our financial statements).

There was no debt exchange derivative liability gain or loss during 2017 because we did not incur any such liabilities until 2018.

As of December 31, 2019, there were no remaining outstanding debt exchange derivative liabilities.

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.

Contingent Consideration Gain (Loss)

In connection with the W Energy Acquisition and the Pivotal Acquisition that closed in 2018, (see Note 3 to our financial statements), we incurred contingent consideration liabilities during 2018.

During the year ended December 31, 2019, and 2018, we recorded a contingent consideration loss of $29.5 million and $29.0 million, respectively, due to the change in the fair value of these liabilities (see Note 11 to our financial statements).

There was no contingent consideration gain or loss during 2017 because we did not incur any such liabilities until 2018.

As of December 31, 2019, there were no remaining outstanding contingent consideration liabilities.

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

During the years ended December 31, 2019 and 2018, we recorded contingent consideration losses of $29.5 million and $29.0 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 zero, $0.1 million, and $1.6 million in 2019, 2018, and 2017, respectively.

The effective tax rate was zero, zero, and 14.6% in 2019, 2018, and 2017, respectively.

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.

We have recorded a valuation allowance against effectively all of our net deferred tax assets due to uncertainty regarding their realization in 2019 and 2018.

We have recorded a valuation allowance against effectively all of our net deferred tax assets due to uncertainty regarding their realization.

We intend to continue maintaining a full valuation allowance on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of these allowances.

However, given our current earnings and potential future earnings, we believe that there is a reasonable possibility that within the next twelve months, sufficient positive evidence may become available to allow us to reach a conclusion that a significant portion of the valuation allowance will no longer be needed.

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.

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

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Non-GAAP Financial Measures

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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 $76.3 million (representing $0.20 per diluted share) for 2019, compared to net income of $143.7 million (representing $0.61 per diluted share) for 2018 and a net loss of $9.2 million (representing $0.15 per diluted share) for 2017.

We define Adjusted Net Income (Loss) as net income (loss) excluding (i) unrealized (gain) loss on 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) certain legal settlements, net of tax, (viii) contingent consideration loss, net of tax, and (ix) acquisition transaction costs, net of tax.

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 2019 compared to 2018 was primarily due to lower realized commodity prices (after the effect of settled derivatives) and increased per unit production expenses, which were partially offset by higher production volumes and lower interest costs.

The increase in Adjusted Net Income in 2018 compared to 2017 was primarily due to significantly higher production volumes as a result of our acquisitions and organic growth, decreased per unit expenses and higher realized commodity prices (after the effect of settled derivatives), which were partially offset by higher interest costs.

We define Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization, and accretion, (iv) unrealized (gain) loss on 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, and (xii) cash severance expense.

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

The increase in Adjusted EBITDA in 2018 as compared to 2017 was primarily due to significantly higher production volumes as a result of our acquisitions and organic growth, decreased per unit expenses and higher realized commodity prices (after the effect of settled derivatives).

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.

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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.

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Reconciliation of Adjusted Net Income

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Impact of Selected Items:

Unrealized (Gain) Loss on Derivatives 173,214 (207,892) 18,443

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

Impairment Expense 1,066,668 — —

Financing Expense — 1,447 884

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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

Legal Settlements — — 3,589

Acquisition Transaction Costs — 1,763 —

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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.

The 2017 column represents a tax impact using an estimated tax rate of 39.1% and includes adjustments for changes in our valuation allowance of $3.7 million, excluding the impact for the Act that was enacted on December 22, 2017.

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Reconciliation of Adjusted EBITDA

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Cash Severance Expense — 759 —

Unrealized (Gain) Loss on Derivatives 173,214 (207,892) 18,443

(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

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 derivative contracts.

Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties.

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

On July 1, 2019, we closed on the VEN Bakken Acquisition, for which we paid total estimated consideration consisting of $175.5 million in cash, 5,602,147 shares of common stock and $130.0 million in principal amount of a newly issued 6.0% Senior Unsecured Promissory Note due 2022 (the “Unsecured VEN Bakken Note”).

In November 2019, we completed a series of refinancing transactions to improve liquidity, reduce fixed charges and strengthen our balance sheet.

The primary components of these transactions included the following:

• We amended and restated our Revolving Credit Facility, with various changes including an increase in the borrowing base from $425.0 million to $800.0 million.

• We completed a cash tender offer to redeem and repay $200.0 million in principal amount of our 8.500% senior secured second lien notes due 2023 (the “Second Lien Notes”), funded with borrowings under our Revolving Credit Facility and cash proceeds from the issuance of shares of our new 6.500% Series A Perpetual Cumulative Convertible Preferred Stock (the “Series A Preferred Stock”).

• We redeemed and repaid an additional $70.8 million in principal amount of Second Lien Notes in exchange for the issuance of additional shares of Series A Preferred Stock.

• We completed a consent solicitation to amend certain terms of our Second Lien Notes, including, among various other changes, to (a) allow for the expansion of the Revolving Credit Facility by increasing the Company’s debt capacity under the debt covenant, (b) remove certain restrictive covenants, and (c) provide for a customary restricted payments builder basket and other mechanics to facilitate our allocation of capital.

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As of December 31, 2019 , we had (i) long-term debt consisting of $580.0 million of borrowings under our Revolving Credit Facility, $417.7 million aggregate principal amount of Second Lien Notes and $130.0 million aggregate principal amount under the Unsecured VEN Bakken Note, and (ii) $236.1 million in liquidity, consisting of $220.0 million of borrowing base availability under our Revolving Credit Facility and $16.1 million of cash on hand.

Subsequent to the end of 2019, in January 2020, we further strengthened our balance sheet by entering into several separately negotiated agreements whereby, in the aggregate, we repurchased and retired $76.7 million in principal amount of Second Lien Notes in exchange for aggregate consideration to the holders consisting of $2.5 million in cash and 794,702 newly-issued shares of Series A Preferred Stock having an aggregate liquidation preference of $79.5 million.

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.

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

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We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all.

Our recent capital commitments have been to fund drilling in the Williston Basin and to fund acquisitions of acreage and oil and gas properties.

Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties.

We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility.

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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 2019 as compared to 2018 is primarily due to a decrease of $110.2 million in our derivative instruments, due to the change in fair value as a result of oil price projections, which was partially offset by an $11.9 million increase in accounts receivable primarily due to our increased production levels and a cash balance of $13.7 million.

The change in current liabilities in 2019 as compared to 2018 is primarily due to a $58.1 million reduction in contingent consideration liabilities incurred in connection with our Pivotal and W Energy Acquisitions (see Notes 3 and 11 to our financial statements), and an $18.2 million reduction in our debt exchange derivative liabilities (see Notes 4 and 11 to our financial statements).

The foregoing was partially offset by an increase of $41.5 million in accounts payable and accrued expenses primarily as a result of increased development activity and an $11.3 million increase in derivative instruments as a result of forward oil prices changes.

Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts.

Our cash flows from operations also are impacted by changes in working capital.

Any payments due to counterparties under our derivative contracts are generally funded by proceeds received from the sale of our production.

Production receipts, however, lag payments to the counterparties.

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.

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.

As of December 31, 2019, we had entered into derivative swap contracts hedging 9.8 million barrels of oil in 2020 at an average price of $57.98 per barrel, 6.2 million barrels of oil in 2021 at an average price of $55.78 per barrel and 1.4 million barrels of oil in 2022, at an average price per barrel of $52.57, respectively.

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.

Quantitative and Qualitative Disclosures about Market Risk.”

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Our cash flows for the years ended December 31, 2020, 2019 and 2018 are presented below:

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Net Cash Used for Investing Activities (283,926) (569,128) (474,519)

Net Cash Provided by Financing Activities 243,088 130,431 141,970

Net Cash Provided by (Used for) Financing Activities (62,399) 243,088 130,431

Net Change in Cash $ (14,640) $ 13,710 $ (99,826)

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Net cash provided by operating activities in 2020 was $331.7 million, compared to $339.7 million in 2019.

This increase was due a 51% year-over-year increase in production levels and lower interest costs, partially offset by a 9% decrease in realized prices (including the effect of settled derivatives).

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.

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, 2019 was a decrease of $37.5 million compared to a decrease of $25.7 million in 2018.

The increase in net cash provided by operating activities in 2018 was caused by improving commodity prices and a 73% year-over-year increase in production levels, which was partially offset by a $26.7 million reduction in settled derivatives when compared to 2017.

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.

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 increase in cash used in investing activities in 2019 was attributable to higher development spending and our VEN Bakken acquisition.

Additionally, the amount of capital expenditures included in accounts payable (and thus not included in cash flows from investing activities) was $161.7 million and $129.5 million at December 31, 2019 and 2018, respectively, as a result of increased activity in the Williston Basin.

The year-over-year increase in cash used in investing activities in 2018 was attributable to higher development spending and acquisitions, in particular our Salt Creek, Pivotal and W Energy acquisitions when compared to 2017.

During 2019, 2018 and 2017 we added 43.0 (excluding already producing wells from acquisitions), 31.2 and 16.9 net wells to production, respectively.

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.

During 2020, 2019 and 2018 we added 17.8, 43.0 and 31.2 net wells to production, respectively, in each case excluding already producing wells from acquisitions.

Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred.

As a result, our actual cash spending is not always reflective of current levels of development activity.

For instance, during the year ended December 31, 2019, our capitalized costs incurred, excluding non-cash consideration, assumed derivative liabilities, and the issuance of the Unsecured VEN Bakken Note from our VEN Bakken Acquisition, for oil and natural gas properties (e.g.

For instance, during the year ended December 31, 2020, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g.

drilling and completion costs, acquisitions, and other capital expenditures) amounted to $213.9 million, while the actual cash spend in this regard amounted to $283.6 million.

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Total $ 283.6 $ 567.8 $ 474.5

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Cash Flows from Financing Activities

Net cash provided by financing activities was $243.1 million, $130.4 million and $142.0 million for the years ended December 31, 2019, 2018 and 2017, respectively.

The cash provided by financing activities in 2019 was primarily related to net increase in borrowings of $440.0 million and $70.9 million for issuance of preferred stock (See Note 5 to our financial statements) which was partially offset by repayments of our Second Lien Notes of $227.5 million in connection with our November 2019 refinancing transaction (See Note 4 to our financial statements).

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 during 2018.

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.

The cash provided by financing activities in 2017 was primarily related to a net increase in borrowings of $156.0 million which was partially offset by $13.4 million in fees in connection with debt financing transactions in 2017.

Revolving Credit Facility

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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 to our financial statements for further details regarding the Revolving Credit Facility.

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 to our financial statements for further details regarding 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 to our financial statements for further details regarding the Unsecured VEN Bakken Note.

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

Series A Preferred Stock

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Quantitative and Qualitative Disclosures About Market Risk.”

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Capital Requirements

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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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(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 gas properties, as we cannot determine with accuracy the amount and/or timing of such payments.

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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

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

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, debt derivative exchange liabilities, and contingent consideration liabilities 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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Approximately 31% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves.

Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves.

Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserve, future cash flows from our reserves, and future development of our proved undeveloped reserves.

The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties.

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(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 independent petroleum 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, 2019.

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, 2020.

Oil and Natural Gas Properties

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These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs, geological and geophysical costs that are directly attributable to the properties and capitalized interest.

Although some of these costs will ultimately result in no additional reserves, they are part of a program

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from which we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones.

Although some of these costs will ultimately result in no additional reserves, they are part of a program from which we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones.

The full cost method differs from the successful efforts method of accounting for oil and natural gas investments.

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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.

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For the year ended December 31, 2020, our average depletion expense per unit of production was $13.27 per Boe.

A 10% decrease in our estimated net proved reserves at December 31, 2019 would result in a $2.28 per Boe increase in our 12-month per unit depletion rate.

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.

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At December 31, 2020, we performed an impairment review using prices that reflect an average of 2020’s monthly prices as prescribed pursuant to the SEC’s guidelines.

For the years ended December 31, 2019, 2018 and 2017, we did not record any full cost impairment expense.

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.

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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Properties” for a discussion of our reserve estimation assumptions.

Revenue Recognition

We recognize revenue in accordance with FASB ASC Topic 606 – Revenue from Contracts with Customers, which we adopted effective January 1, 2018 using the modified retrospective approach.

Refer to the “Significant Accounting Policies” footnote in the notes to the financial statements for more information on our adoption of this new accounting standard.

We derive revenue primarily from the sale of the crude oil and natural gas from our interests in producing wells.

Revenue is recognized when we meet our performance obligation to deliver the product and control is transferred to the customer.

We receive payment for product sales from one to three months after delivery.

At the end of each month when the performance obligation is satisfied, the amount of production delivered and the price we will receive can be reasonably estimated and amounts due from customers are accrued in accounts receivable trade, net in the balance sheets.

Variances between our estimated revenue and actual payments are recorded in the month the payment is received.

However, differences have been and are insignificant.

As of December 31, 2019, our natural gas production was in balance, meaning our cumulative portion of natural gas production taken and sold from wells in which we have an interest equaled our entitled interest in natural gas production from those wells.

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Derivative Instrument Activities

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We may also use exchange traded futures contracts and option contracts to hedge the delivery price of oil at a future date.

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

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

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

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

As of December 31, 2019 and 2018, we had recorded $0.2 million and $0.4 million net deferred tax assets, respectively.

As part of the process of preparing the financial statements, we are required to estimate the federal and state income taxes in each of the jurisdictions in which we operate.

This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items such as derivative instruments, depletion, depreciation and amortization, and certain accrued liabilities for tax and financial accounting purposes.

These differences and our net operating loss carry-forwards result in deferred tax assets and liabilities, which are included in our balance sheet.

We must then assess, using all available negative and positive evidence, the likelihood that the deferred tax assets will be recovered from future taxable income.

If we believe that recovery is not likely, we must establish a valuation allowance.

Generally, to the extent we establish a valuation allowance or increase or decrease this allowance in a period, we must include an expense or reduction of expense within the tax provision in the statement of operations.

Under accounting guidance for income taxes, an enterprise must use judgment in considering the relative impact of negative and positive evidence.

The weight given to the potential effect of negative and positive evidence should be commensurate with the extent to which it can be objectively verified.

The more negative evidence that exists (i) the more positive evidence is necessary and (ii) the more difficult it is to support a conclusion that a valuation allowance is not needed for all or a portion of the deferred tax asset.

Among the more significant types of evidence that we consider are:

• our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition;

• the ability to recover our net operating loss carry-forward deferred tax assets in future years;

• the existence of significant proved oil and natural gas reserves;

• our ability to use tax planning strategies, such as electing to capitalize intangible drilling costs as opposed to expensing such costs;

• current price protection utilizing oil and natural gas hedges;

• current market prices for oil, NGL and natural gas;

• future revenue and operating cost projections that indicate we will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures.

During 2019, in evaluating whether it was more-likely-than-not that our deferred tax asset was recoverable from future net income, we considered all positive and negative evidence available.

We will continue to assess the need for a valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.

See Note 10 to our financial statements for additional discussion of our income taxes.

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On December 22, 2017, the United States enacted the Act which made significant changes that affect the Company.

The Act is a comprehensive tax reform bill containing a number of other provisions that either currently or in the future could impact the Company.

The Company has completed the analysis of the Act and does not expect a material change due to the transition impacts.

Any changes that do arise due to changes in interpretations of the Act, legislative action to address questions that arise because of the Act, changes in accounting standards for income taxes or related interpretations in response to the Act, or any updates or changes to estimates the Company has utilized to calculate the transition impacts will be disclosed in future periods as they arise.

The effect of certain limitations effective for the tax year 2018 and forward, specifically related to the deductibility of executive compensation and interest expense, have been evaluated.

Asset Retirement Obligations (“ARO”)

We record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset.

For oil and natural gas properties, this is the period in which the well is drilled or acquired.

For midstream service assets, this is the period in which the asset is placed in service.

The ARO represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws.

The liability is accreted to its present value each period and for oil and natural gas properties the capitalized cost is depreciated on the unit of production method or for midstream service assets depreciated over its useful life.

The accretion expense is recorded in the line item “Accretion of asset retirement obligations” in our statement of operations.

We determine the ARO by calculating the present value of estimated cash flows related to the liability.

Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration.

Included in the fair value calculation are assumptions and judgments including the ultimate costs, inflation factors, credit-adjusted risk-free discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.

To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Business Combinations

We account for business combinations using the acquisition method, which is the only method permitted under FASB ASC Topic 805 – Business Combinations , and involves the use of significant judgment.

Under the acquisition method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given.

The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values.

The excess, if any, of the consideration given to acquire an entity over the net amounts assigned to its assets acquired and liabilities assumed is recognized as goodwill.

The excess, if any, of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity is recognized immediately to earnings as a gain from bargain purchase.

Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the assets and liabilities acquired do not have fair values that are readily determinable.

Different techniques may be used to determine fair values, including market prices (where available), appraisals, comparisons to transactions for similar assets and liabilities, and present values of estimated future cash flows, among others.

Since these estimates involve the use of significant judgment, they can change as new information becomes available.

The business combinations completed during the prior three years consisted of crude oil and natural gas properties.

In general, the consideration we have paid to acquire these properties was entirely allocated to the fair value of the assets acquired and liabilities assumed at the time of acquisition and consequently, there was no goodwill nor any bargain purchase gains recognized on our business combinations.

Recently Issued or Adopted Accounting Pronouncements

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Significant Accounting Policies.

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Off-Balance Sheet Arrangements

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

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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