NORTHERN OIL AND GAS, INC. 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 endedDecember 31, 2020 , which is incorporated herein by reference, for discussion and analysis of results of operations for the year endedDecember 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 withinthe United States . Using this strategy, we had participated in 7,436 gross (680.8 net) producing wells as ofDecember 31, 2021 . As ofDecember 31, 2021 , we had leased approximately 245,431 net acres, of which approximately 87% were developed and all were located inthe United States . Our average daily production for full year 2021 was 53,792 Boe per day, and in the fourth quarter of 2021 was 64,155 Boe per day (approximately 59% oil). This represented significant growth from 2020, which was driven in large part by three substantial acquisitions that we completed during 2021: the Reliance Acquisition, the CM Resources Acquisition and the Comstock Acquisition, each as defined and described in Note 3 to our financial statements (collectively, the "2021 Acquisitions"). During 2021, we added 35.8 new net wells to production, plus an additional 169.4 net wells added from acquisitions which were already producing when acquired. We ended 2021 with 42.5 net wells in process.
Our financial and operating performance for the year ended
•Oil and natural gas sales of
•Cash flows from operations of
•Proved reserves of 287.7 MMBoe at
•Grew and diversified the business through over
•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
•Issued$750.0 million in aggregate principal amount of senior unsecured notes due 2028 and$438.1 million in common stock (net of offering expenses), the proceeds of which were used (i) to fund our 2021 Acquisitions and in preparation for the Veritas Acquisition, (ii) to retire$417.8 million of term debt with near-term maturities, (iii) to repay revolving credit facility borrowings, allowing us to exit 2021 with$704.5 million in liquidity, and (iv) for general corporate purposes
Impacts of COVID-19 Pandemic and Economic Environment
The novel coronavirus disease (COVID-19) and efforts to mitigate the spread of the disease have created unprecedented challenges for our industry, including a drastic decline in demand for crude oil. This, combined withOPEC 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 theWilliston Basin responded by significantly decreasing drilling and completion activity, and by shutting in or curtailing production from a significant number of producing wells. Conditions have significantly improved with the recovery and rally of commodity prices from late 2020 through the end of 2021, but operators' decisions on these matters are evolving rapidly, and it remains difficult to predict the future effects on our company 40 -------------------------------------------------------------------------------- Table of Contents and its business. However, we expect that our cash flow from operations and borrowing availability under our Revolving Credit Facility will allow us to meet our liquidity needs for at least the next twelve 12 months.
Source of Our Revenues
We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market. We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil and natural gas production. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.
Principal Components of Our Cost Structure
•Commodity price differentials. The price differential between our well head price for oil and the NYMEX WTI benchmark price is primarily driven by the cost to transport oil via train, pipeline or truck to refineries. The price differential between our well head price for natural gas and NGLs and the NYMEXHenry Hub benchmark price is primarily driven by gathering and transportation costs. •Gain (loss) on commodity derivatives, net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas. Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end. •Production expenses. Production expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include field personnel compensation, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties. •Production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. •Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method. Accretion expense relates to the passage of time of our asset retirement obligations. •General and administrative expenses. General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance. •Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We capitalize a portion of the interest paid on applicable borrowings into our unproven cost pool. We include interest expense that is not capitalized into the full cost pool, the amortization of deferred financing costs and bond premiums (including origination and amendment fees), commitment fees and annual agency fees as interest expense. •Impairment expense. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, a non-cash impairment expense is required. •Income tax expense. Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax 41 -------------------------------------------------------------------------------- Table of Contents rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
Selected Factors That Affect Our Operating Results
Our revenues, cash flows from operations and future growth depend substantially upon:
•the timing and success of drilling and production activities by our operating partners;
•the prices and the supply and demand for oil, natural gas and NGLs;
•the quantity of oil and natural gas production from the wells in which we participate;
•changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in the price of oil;
•our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and
•the level of our operating expenses.
In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston, Appalachian and Permian Basins subjects our operating results to factors specific to these regions. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these regions. The price of oil can vary depending on the market in which it is sold and the means of transportation used to transport the oil to market, particularly in theWilliston Basin where a substantial majority of our revenues are derived. Additional pipeline infrastructure has increased takeaway capacity in theWilliston Basin which has improved wellhead values in the region. The price at which our oil production is sold typically reflects a discount to the NYMEX benchmark price. The price at which our natural gas production is sold may reflect either a discount or premium to the NYMEX benchmark price. Thus, our operating results are also affected by changes in the oil price differentials between the applicable benchmark and the sales prices we receive for our oil production. Our oil price differential to the NYMEX benchmark price during 2021 was$5.15 per barrel, as compared to$6.63 per barrel in 2020. Our net realized gas price during 2021 was$4.57 per Mcf, representing 100% realization relative to averageHenry Hub pricing, compared to a net realized gas price of$1.14 per Mcf during 2020. Fluctuations in our price differentials and realizations are due to several factors such as gathering and transportation costs, takeaway capacity relative to production levels, regional storage capacity, and seasonal refinery maintenance temporarily depressing demand. Another significant factor affecting our operating results is drilling costs. The cost of drilling wells can vary significantly, driven in part by volatility in commodity prices that can substantially impact the level of drilling activity. Generally, higher oil prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher. Lower oil prices have generally had the opposite effect. In addition, individual components of the cost can vary depending on numerous factors such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant. During 2021, the weighted average authorization for expenditure (or AFE) cost for wells we elected to participate in was$6.9 million , compared to$7.5 million for the wells we elected to participate in during 2020.
Market Conditions
The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Because our oil and gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in terms of output, especially production from properties withinthe United States , the production quota set byOPEC , and the strength of theU.S. dollar can adversely impact oil prices. 42 -------------------------------------------------------------------------------- Table of Contents Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production. Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the years endedDecember 31, 2021 and 2020. December 31, 2021 2020 Average NYMEX Prices(1) Oil (per Bbl)$ 68.09 $ 39.24 Natural Gas (per Mcf) 3.84 2.01
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(1)Based on average NYMEX closing prices.
The average 2021 NYMEX oil pricing was$68.09 per barrel of oil or 74% higher than the average NYMEX price per barrel in 2020. Our settled derivatives decreased our realized oil price per barrel by$10.17 in 2021 and increased our realized oil price per barrel by$20.08 in 2020. Our average 2021 realized oil price per barrel after reflecting settled derivatives was$52.77 compared to$52.69 in 2020. The average 2021 NYMEX natural gas pricing was$3.84 per Mcf, or 91% higher than the average NYMEX price per Mcf in 2020. Our settled derivatives decreased our realized natural gas price per Mcf by$0.92 in 2021 and increased our realized natural gas price per Mcf by$0.02 in 2020. Our 2021 realized gas price per Mcf was$3.65 compared to$1.16 in 2020, which was primarily driven by higher NYMEX pricing for natural gas and gas realizations, which was partially offset by decrease in settled derivatives. We employ a hedging program that mitigates the risk associated with fluctuations in commodity prices. For detailed information on our commodity hedging program, see Item 7A Quantitative and Qualitative Disclosures about Market Risk and Note 12 to our financial statements.
Results of Operations for 2021 and 2020
The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.
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Years Ended
2021 2020
Net Production:
Oil (Bbl) 12,288,358 9,361,138
Natural Gas and NGLs (Mcf) 44,073,941 16,473,287
Total (Boe) 19,634,015 12,106,686
Net Sales (in thousands):
Oil Sales $ 773,470 $ 305,249
Natural Gas and NGL Sales 201,619 18,802
Gain (Loss) on Settled Commodity Derivatives (165,823) 188,264
Gain (Loss) on Unsettled Commodity Derivatives (312,370) 39,878
Other Revenue 3 17
Total Revenues 496,899 552,210
Average Sales Prices:
Oil (per Bbl) $ 62.94 $ 32.61Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl)
(10.17) 20.08
Oil Net of Settled Oil Derivatives (per Bbl) 52.77 52.69
Natural Gas and NGLs (per Mcf) 4.57 1.14
Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf)
(0.92) 0.02
Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf)
3.65 1.16
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives
49.66 26.77
Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe)
(8.45) 15.55
Realized Price on a Boe Basis Including Settled Commodity Derivatives
41.21 42.32
Operating Expenses (in thousands):
Production Expenses $ 170,817 $ 116,336
Production Taxes 76,954 29,783
General and Administrative Expenses 30,341 18,546
Depletion, Depreciation, Amortization and Accretion 140,828 162,120
Costs and Expenses (per Boe):
Production Expenses $ 8.70 $ 9.61
Production Taxes 3.92 2.46
General and Administrative Expenses 1.55 1.53
Depletion, Depreciation, Amortization and Accretion 7.17 13.39
Net Producing Wells at Period-End 680.8 475.1
Oil and Natural Gas Sales
Our revenues vary from year to year primarily as a result of changes in realized
commodity prices and production volumes. In 2021, our oil, natural gas and NGL
sales, excluding the effect of settled commodity derivatives, increased 201%
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from 2020, driven by a 62% increase in production volumes and an 86% increase in
realized prices, excluding the effect of settled commodity derivatives. The
higher average realized price in 2021 as compared to 2020 was driven by higher
average NYMEX oil and natural gas prices, a lower average oil price
differential, and higher average gas realizations in 2021 as compared to 2020.
Oil price differential during 2021 averaged $5.15 per barrel, as compared to
$6.63 per barrel in 2020.
We add production through drilling success as we place new wells into production
and through additions from acquisitions, which is offset by the natural decline
of our oil and natural gas production from existing wells. Our acquisition
program is a significant driver of our net well additions in certain years. In
2021, our substantial acquisition activities (see Note 3 to our financial
statements) combined with increased development activity helped drive an
increase in production levels as compared to 2020. In 2021, the number of net
wells we added to production (excluding acquisitions) increased by 101% as
compared to 2020. The 2021 Acquisitions and increased new well additions drove
the 62% increase in production in 2021 as compared to 2020.
Our production for the last two years is set forth in the following table:
Year Ended December 31,
2021 2020
Production:
Oil (Bbl) 12,288,358 9,361,138
Natural Gas and NGL (Mcf) 44,073,941 16,473,287
Total (Boe)(1) 19,634,015 12,106,686
Average Daily Production:
Oil (Bbl) 33,667 25,577
Natural Gas and NGL (Mcf) 120,751 45,009
Total (Boe)(1) 53,792 33,078
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(1)Natural gas and NGLs are converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
Commodity Derivative Instruments
We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our gain (loss) on commodity derivatives, net was a loss of$478.2 million in 2021, compared to a gain of$228.1 million in 2020. Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end. For 2021, we realized a loss on settled commodity derivatives of$165.8 million , compared to a$188.3 million gain in 2020. The percentage of oil production hedged under our derivative contracts was 73% and 104% in 2021 and 2020, respectively. The weighted average oil price on our settled commodity derivative contracts in 2021 and 2020 was$55.56 and$58.04 , respectively. Our average realized price (including all commodity derivative cash settlements) in 2021 was$41.21 per Boe compared to$42.32 per Boe in 2020. The gain (loss) on settled commodity derivatives decreased our average realized price per Boe by$8.45 in 2021, and increased our average realized price per Boe by$15.55 in 2020. Unsettled commodity derivative gains and losses was a loss of$312.4 million in 2021 compared to a gain of$39.9 million in 2020. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our commodity derivatives. Any gains on our unsettled commodity derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date. AtDecember 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 ofDecember 31, 2020 . The increase in the net liability atDecember 31, 2021 as compared toDecember 31, 2020 was primarily 45 -------------------------------------------------------------------------------- Table of Contents due to changes in forward commodity prices relative to prices on our open commodity derivative contracts sinceDecember 31, 2020 . Our open commodity derivative contracts are summarized in "Item 7A. Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk."
Production Expenses
Production expenses were$170.8 million in 2021 compared to$116.3 million in 2020. On a per unit basis, production expenses decreased 9% from$9.61 per Boe in 2020 to$8.70 per Boe in 2021 due primarily to higher production volumes over which fixed costs can be spread and the mix of production expense by basin as we added production from the Permian and Appalachian Basins, which was partially offset by higher processing and saltwater disposal charges. On an absolute dollar basis, the 47% increase in our production expenses in 2021 compared to 2020 was primarily due to a 62% increase in production, offset by a 9% decrease in per unit costs. Production Taxes We pay production taxes based on realized oil and natural gas sales. Production taxes were$77.0 million in 2021 compared to$29.8 million in 2020. As a percentage of oil and natural gas sales, our production taxes were 7.9% and 9.2% in 2021 and 2020, respectively. The fluctuation in our average production tax rate from year to year is primarily due to changes in our oil sales as a percentage of our total oil and natural gas sales and the mix of our production volumes by basin. Oil sales are taxed at a higher rate than gas sales for the Williston and Permian Basins and we do not pay production taxes in theAppalachian Basin .
General and Administrative Expenses
General and administrative expenses were$30.3 million for 2021 compared to$18.5 million for 2020. The increase in 2021 compared to 2020 was primarily due to an$8.1 million increase in acquisition costs due to our 2021 Acquisitions, a$2.3 million increase in compensation costs and a$0.6 million increase in professional fees.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion ("DD&A") was $140.8 million
in 2021 compared to $162.1 million in 2020. Depletion expense, the largest
component of DD&A, was $7.07 per Boe in 2021 compared to $13.27 per Boe in
2020. The aggregate decrease in depletion expense for 2021 compared to 2020 was
driven by a 47% decrease in the depletion rate per Boe partially offset by a 62%
increase in production levels. The 2021 depletion rate per Boe was lower due to
the impact of impairments in 2020. The following table summarizes DD&A expense
per Boe for 2021 and 2020 :
Year Ended December 31,
2021 2020 Change Change
Depletion $ 7.07 $ 13.27 $ (6.20) (47) %Depreciation, Amortization, and Accretion 0.11 0.12
(0.01) (8) %
Total DD&A expense $ 7.18 $ 13.39 $ (6.21) (46) %
Impairment of
We did not record any impairment of our proved oil and gas properties in 2021. In 2020, as a result of low commodity prices and their effect on the proved reserve values of our properties, we recorded a non-cash ceiling test impairment of$1.1 billion . The impairment charge affected our reported net income in 2020 but did not reduce our cash flow. Depending on future commodity price levels, the trailing twelve-month average price used in the ceiling calculation may decline, which could cause additional future write downs of our oil and natural gas properties. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. 46
-------------------------------------------------------------------------------- Table of Contents Interest Expense Interest expense, net of capitalized interest, was$59.0 million in 2021 compared to$58.5 million in 2020. The increase in interest expense for 2021 as compared to 2020 was primarily due to the issuance of our Senior Notes due 2028 which was partially offset by a reduction in our outstanding borrowings on our Revolving Credit Facility in 2021.
Loss on the Extinguishment of Debt
As a result of refinancing transactions during 2021 (see Note 4 to our financial statements), we recorded a loss on the extinguishment of debt of$13.1 million for the year endedDecember 31, 2021 , based on the differences between the reacquisition costs of retiring our Second Lien Notes and the net carrying values thereof. During 2020, we recorded a loss on extinguishment of debt of$3.7 million as a result of a series of exchange transactions of our Second Lien Notes, based on the differences between the reacquisition costs of retiring the applicable debt and the net carrying values thereof.
Contingent Consideration Gain (Loss)
We have incurred contingent consideration liabilities in connection with certain acquisitions of oil and gas properties. During the years endedDecember 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 ofDecember 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 andAppalachian Basin properties. In 2020, the tax benefits recognized related to the utilization of our alternative minimum tax credit as a result of favorable tax incentives. We have recorded a valuation allowance against effectively all of our net deferred tax assets due to uncertainty regarding their realization. We intend to continue maintaining a full valuation allowance on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of these allowances. Release of any portion of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense for the period the release is recorded. However, the exact timing and amount of the valuation allowance release are subject to change on the basis of the level of profitability that we are able to actually achieve. For further discussion of our valuation allowance, see Note 10 to our financial statements.
Liquidity and Capital Resources
Overview
Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations, proceeds from equity and debt financings, credit facility borrowings, and cash settlements of commodity derivative instruments. Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position. As ofDecember 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 ofDecember 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, inJanuary 2022 we completed the Veritas Acquisition pursuant to a purchase and sale agreement that we entered into and announced inNovember 2021 (see Note 14 to our financial statements).
During 2021 we completed a number of significant financing transactions, many of which were related to these acquisitions, including:
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•a common stock offering in February 2021 with net proceeds of $132.9 million ,
which was primarily intended to finance the cash purchase price for the Reliance
Acquisition that closed on April 1, 2021 ;
•a common stock offering in June 2021 with net proceeds of $95.3 million , which
was primarily intended to finance the cash purchase price for the CM Resources
Acquisition that closed in the third quarter of 2021;
•a common stock offering in November 2021 with net proceeds of $209.9 million ,
which was primarily intended to finance the cash purchase price for the Veritas
Acquisition that closed in the first quarter of 2022, and in the interim was
used to pay down outstanding borrowings under our Revolving Credit Facility;
•the issuance of $750.0 million in aggregate principal amount of new 8.125%
senior unsecured notes due 2028 (the "2028 Notes"), of which $550.0 million was
issued in February 2021 and an additional $200.0 million was issued in November
2021 ;
•the full repayment and retirement of all $130.0 million in principal amount of
our 6.0% senior unsecured promissory note due 2022 (the "Unsecured VEN Bakken
Note");
•the full redemption and retirement of all $287.8 million in principal amount of
our 8.500% senior secured second lien notes due 2023 (the "Second Lien Notes");
and
•the reduction of amount of borrowings outstanding under our Revolving Credit
Facility from
One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 63% and 77% of our total production volumes in 2021 and 2020, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices. We seek to maintain a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the years ended 2021 and 2020, we hedged approximately 73% and 104% of our crude oil production, respectively. For a summary as ofDecember 31, 2021 , of our open commodity swap contracts for future periods, see "Item 7A. Quantitative and Qualitative Disclosures about Market Risk" below. With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months. However, we may seek additional access to capital and liquidity. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all. Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility. Our capital expenditures could be curtailed if our cash flows decline from expected levels. Because production from existing oil and natural gas wells declines over time, reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future. Working Capital Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, collection of receivables, expenditures related to our development and production operations and the impact of our outstanding derivative instruments. AtDecember 31, 2021 , we had a working capital deficit of$112.2 million , compared to a deficit of$56.8 million atDecember 31, 2020 . Current assets increased by$89.7 million and current liabilities increased by$145.1 million atDecember 31, 2021 , compared toDecember 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 onJanuary 4, 2021 . Additionally, our accrued interest increased by$12.2 million as a result of the timing 48 -------------------------------------------------------------------------------- Table of Contents of interest payments on our newly issued 2028 Notes compared to the timing of interest payments on our prior debt instruments outstanding during 2020.
Cash Flows
Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. The Company typically enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future oil and gas production for the next 12 to 24 months. See "Item 7A. Quantitative and Qualitative Disclosures about Market Risk." Our cash flows for the years endedDecember 31, 2021 and 2020 are presented below: Year Ended December 31, (In thousands) 2021 2020 Net Cash Provided by Operating Activities$ 396,467 $ 331,685 Net Cash Used for Investing Activities (634,434)
(283,926)
Net Cash Provided by (Used for) Financing Activities 246,059
(62,399)
Net Change in Cash $ 8,092 $ (14,640) Cash Flows from Operating Activities
Net cash provided by operating activities in 2021 was$396.5 million , compared to$331.7 million in 2020. This increase was driven by a 62% year-over-year increase in production levels, which was partially offset by a 3% decrease in realized prices (including the effect of settled derivatives). Net cash provided by operating activities is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital and other items (as reflected in our statements of cash flows) in the year endedDecember 31, 2021 was a decrease of$85.8 million compared to an increase of$34.1 million in 2020.
Cash Flows from Investing Activities
We had cash flows used in investing activities of$634.4 million and$283.9 million during the years endedDecember 31, 2021 and 2020, respectively, primarily as a result of our capital expenditures for drilling, development and acquisition costs. The year-over-year increase in cash used in investing activities in 2021 was attributable to our 2021 Acquisitions and higher development spending as a result of the higher commodity price environment from the rebound of the COVID-19 pandemic. In addition, cash flows used in investing activities included a$40.7 million acquisition deposit for our Veritas Acquisition that was pending at year-end 2021. During 2021 and 2020 we added 35.8 and 17.8 net wells to production, respectively, in each case excluding already producing wells from acquisitions. Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred. As a result, our actual cash spending is not always reflective of current levels of development activity. For instance, during the year endedDecember 31, 2021 , our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g. drilling and completion costs, acquisitions, and other capital expenditures) amounted to$656.2 million , while the actual cash spend in this regard amounted to$593.2 million . Development and acquisition activities are discretionary. We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the years endedDecember 31, 2021 and 2020 are summarized in the following table: Year Ended December
31,
(In millions) 2021
2020
Drilling and Development Capital Expenditures$ 180.8 $ 235.4 Acquisition of Oil and Natural Gas Properties$ 410.4 47.0 Other Capital Expenditures$ 2.0 1.2 Total$ 593.2 $ 283.6 49
-------------------------------------------------------------------------------- Table of Contents Cash Flows from Financing Activities Net cash (used for) provided by financing activities was$246.1 million and$(62.4) million for the years endedDecember 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
InNovember 2019 , we entered into a revolving credit facility withWells Fargo Bank , as administrative agent, and the lenders from time to time party thereto (the "Revolving Credit Facility"), which amended and restated our existing revolving credit facility that was entered into onOctober 5, 2018 . The Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to our oil and gas properties. As ofDecember 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 ofDecember 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 ofDecember 31, 2021 , we had 2,218,732 outstanding shares of 6.500% Series A Perpetual Cumulative Convertible Preferred Stock (the "Series A Preferred Stock"), having an aggregate liquidation preference of$221.9 million (excluding accumulated dividends). See Note 5 to our financial statements for further details regarding the Series A Preferred Stock.
Known Contractual and Other Obligations; Planned Capital Expenditures
Contractual and Other Obligations. We have contractual commitments under our debt agreements, including interest payments and principal repayments. See Note 4 to our financial statements. We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 12 to our financial statements. We have firm commitments on certain assets that we assumed in the Reliance Acquisition. See "Item 2-Properties-Delivery Commitments" above. We have future obligations related to the abandonment of our oil and natural gas properties. See Note 9 to our financial statements. With respect to all of these items, except for our commitments under our debt agreements, we cannot determine with accuracy the amount and/or timing of such payments. Planned Capital Expenditures. For 2022, we are budgeting approximately$350 to$415 million in total planned capital expenditures, including development expenditures and our smaller day-to-day acquisition activity, which we refer to as our "ground game" acquisition activity. As ofDecember 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 ofDecember 31, 2021 , and subsequently closed onJanuary 27, 2022 (see Note 14 to our financial statements). See also "Capital Requirements" below. The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors. If oil, NGL and natural gas prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and 50 -------------------------------------------------------------------------------- Table of Contents potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, reduction of service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control. For additional information on the impact of changing prices and market conditions on our financial position, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk."
Capital Requirements
Development and acquisition activities are discretionary, and, for the near term, we expect such activities to be maintained at levels we can fund through cash on hand, internal cash flow and borrowings under our Revolving Credit Facility. To the extent capital requirements exceed internal cash flow and borrowing capacity under our Revolving Credit Facility, additional financings from the capital markets may be pursued to fund these requirements. We monitor our capital expenditures on a regular basis, adjusting the amount up or down and also between our projects, depending on commodity prices, cash flow and projected returns. Also, our obligations may change due to acquisitions, divestitures and continued growth. Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital. If internally generated cash flow and borrowing capacity is not available under our Revolving Credit Facility, we may issue additional equity or debt to fund capital expenditures, acquisitions, extend maturities or to repay debt.
Satisfaction of Our Cash Obligations for the Next Twelve Months
With our revolving credit agreement and our cash flows from operations, we believe we will have sufficient capital to meet our drilling commitments, expected general and administrative expenses and other cash needs for the next twelve months. Nonetheless, any strategic acquisition of assets or increase in drilling activity may lead us to seek additional capital. We may also choose to seek additional capital rather than utilize our credit facility or other debt instruments to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions. We will evaluate any potential opportunities for acquisitions as they arise. However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.
Effects of Inflation and Pricing
The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. Higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel, which we expect to occur in 2022 compared to 2021.
Critical Accounting Estimates
The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our financial statements in accordance with generally accepted accounting principles inthe United States (GAAP), as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions.
Use of Estimates
The preparation of financial statements under GAAP requires management to make
estimates and assumptions that affect our reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Our estimates of our proved oil and natural gas
reserves, future development costs, estimates relating to certain oil and
natural gas revenues and expenses, and fair value of derivative instruments are
the most critical to our financial statements.
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Oil and Natural Gas Reserves
The determination of depreciation, depletion and amortization expense as well as
impairments that are recognized on our oil and natural gas properties are highly
dependent on the estimates of the proved oil and natural gas reserves
attributable to our properties. Our estimate of proved reserves is based on the
quantities of oil and natural gas which geological and engineering data
demonstrate, with reasonable certainty, to be recoverable in the future years
from known reservoirs under existing economic and operating conditions. The
accuracy of any reserve estimate is a function of the quality of available data,
engineering and geological interpretation, and judgment. For example, we must
estimate the amount and timing of future operating costs, production taxes and
development costs, all of which may in fact vary considerably from actual
results. In addition, as the prices of oil and natural gas and cost levels
change from year to year, the economics of producing our reserves may change and
therefore the estimate of proved reserves may also change. Approximately 41% of
our proved oil and gas reserve volumes are categorized as proved undeveloped
reserves. Any significant variance in these assumptions could materially affect
the estimated quantity and value of our reserve, future cash flows from our
reserves, and future development of our proved undeveloped reserves.
The information regarding present value of the future net cash flows
attributable to our proved oil and natural gas reserves are estimates only and
should not be construed as the current market value of the estimated oil and
natural gas reserves attributable to our properties. Such information includes
revisions of certain reserve estimates attributable to our properties included
in the prior year's estimates. These revisions reflect additional information
from subsequent activities, production history of the properties involved and
any adjustments in the projected economic life of such properties resulting from
changes in oil and natural gas prices.
External petroleum engineers independently estimated all of the proved reserve
quantities included in our financial statements, and were prepared in accordance
with the rules promulgated by the SEC . In connection with our external petroleum
engineers performing their independent reserve estimations, we furnish them with
the following information that they review: (1) technical support data, (2)
technical analysis of geologic and engineering support information, (3) economic
and production data and (4) our well ownership interests. The third-party
independent reserve engineers, Cawley, Gillespie & Associates, Inc. , evaluated
100% of our estimated proved reserve quantities and their related pre-tax future
net cash flows as of December 31, 2021 .
The method of accounting we use to account for our oil and natural gas investments determines what costs are capitalized and how these costs are ultimately matched with revenues and expensed.
We utilize the full cost method of accounting to account for our oil and natural gas investments instead of the successful efforts method because we believe it more accurately reflects the underlying economics of our programs to explore and develop oil and natural gas reserves. The full cost method embraces the concept that dry holes and other expenditures that fail to add reserves are intrinsic to the oil and natural gas exploration business. Thus, under the full cost method, all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs, geological and geophysical costs that are directly attributable to the properties and capitalized interest. Although some of these costs will ultimately result in no additional reserves, they are part of a program from which we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. The full cost method differs from the successful efforts method of accounting for oil and natural gas investments. The primary difference between these two methods is the treatment of exploratory dry hole costs. These costs are generally expensed under the successful efforts method when it is determined that measurable reserves do not exist. Geological and geophysical costs are also expensed under the successful efforts method. Under the full cost method, both dry hole costs and geological and geophysical costs are initially capitalized and classified as unproved properties pending determination of proved reserves. If no proved reserves are discovered, these costs are then amortized with all the costs in the full cost pool. Capitalized amounts except unproved costs are depleted using the units of production method. The depletion expense per unit of production is the ratio of the sum of our unamortized historical costs and estimated future development costs to our proved reserve volumes. Estimation of hydrocarbon reserves relies on professional judgment and use of factors that cannot be precisely determined. Subsequent reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting periods. For the year endedDecember 31, 2021 , our average depletion expense per unit of production was$7.07 per Boe. 52 -------------------------------------------------------------------------------- Table of Contents To the extent the capitalized costs in our full cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the sum of the present value (using a 10% discount rate and based on 12-month/SEC oil and natural gas prices) of the estimated future net cash flows from our proved oil and natural gas reserves and the capitalized cost associated with our unproved properties, we would have a capitalized ceiling impairment. Such costs would be charged to operations as a reduction of the carrying value of oil and natural gas properties. The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are depressed, even if the low prices are temporary. In addition, capitalized ceiling impairment charges may occur if we experience poor drilling results or if estimations of our proved reserves are substantially reduced.
A
capitalized ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and stockholders' equity. Once recognized, a capitalized ceiling impairment charge to oil and natural gas properties cannot be reversed at a later date. The risk that we will experience a ceiling test writedown increases when oil and natural gas prices are depressed or if we have substantial downward revisions in our estimated proved reserves. AtDecember 31, 2021 , we performed an impairment review using prices that reflect an average of 2021's monthly prices as prescribed pursuant to theSEC's guidelines. For the year ended 2021, we did not record any full cost impairment expense. For the year ended 2020, we recorded a$1,066.7 million full cost impairment expense. For the year ended 2019, we did not record any full cost impairment expense. If a low price environment reoccurs, we might be required to further write down the value of our oil and gas properties. In addition, capitalized ceiling impairment charges may occur if estimates of proved reserves are substantially reduced or estimates of future development costs increase significantly. See "Item 2. Properties" for a discussion of our reserve estimation assumptions.
Derivative Instrument Activities
We use derivative instruments from time to time to manage market risks resulting primarily from fluctuations in the prices of oil and natural gas. We may periodically enter into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. We may also use exchange traded futures contracts and option contracts to hedge the delivery price of oil at a future date. All derivative positions are carried at their fair value in the balance sheet and are marked-to-market at the end of each period. Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net on the statements of operations rather than as a component of accumulated other comprehensive income or other income (expense). The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 12 to our financial statements for a description of the derivative contracts.
Recently Issued or Adopted Accounting Pronouncements
For discussion of recently issued or adopted accounting pronouncements, see Notes to Financial Statements-Note 2. Significant Accounting Policies.
Off-Balance Sheet Arrangements
We currently do not have any off-balance sheet arrangements that have or are
reasonably likely to have a current or future effect on our financial condition,
changes in financial condition, revenues or expenses, results of operations,
liquidity, capital expenditures or capital resources that is material to
investors.
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