Item 7. Management’s Discussion and Analysis
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read in conjunction with our financial statements and accompanying notes to financial statements appearing elsewhere in this report.
Executive Overview
Our primary strategy is to invest in non-operated minority working and mineral interests in oil and gas properties, with a core area of focus in the premier basins within the United States. Using this strategy, we participated in 6,640 gross (475.1 net) producing wells as of December 31, 2020. As of December 31, 2020, we had leased approximately 183,527 net acres, of which approximately 90% were developed and substantially all were located in the Williston Basin in the United States.
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 $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.
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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
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 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
• Oil price differentials . The price differential between our well head price and the NYMEX WTI benchmark price is primarily driven by the cost to transport oil via train, pipeline or truck to refineries.
• 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 full cost pool. We include interest expense that is not capitalized into the full cost pool, the amortization of deferred financing costs and bond premiums (including origination and amendment fees), commitment fees and annual agency fees as interest expense.
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• 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. Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
Selected Factors That Affect Our Operating Results
Our revenues, cash flows from operations and future growth depend substantially upon:
• the timing and success of drilling and production activities by our operating partners;
• the prices and the supply and demand for oil, natural gas and NGLs;
• the quantity of oil and natural gas production from the wells in which we participate;
• changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in 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 Basin subjects our operating results to factors specific to this region. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, and the limitations of the developing infrastructure and transportation capacity in this region.
The price of oil in the Williston Basin can vary depending on the market in which it is sold and the means of transportation used to transport the oil to market. Light sweet crude from the Williston Basin has a higher value at many major refining centers because of its higher quality relative to heavier and sour grades of oil; however, because of the Williston Basin’s location relative to traditional oil transport centers, this higher value is generally offset to some extent by higher transportation costs. While rail transportation has historically been more expensive than pipeline transportation, Williston Basin’s prices have at times justified shipment by rail to markets across the United States. Additional pipeline infrastructure has increased takeaway capacity in the Williston Basin which has improved wellhead values in the region, specifically the Dakota Access Pipeline (“DAPL”) which has given the region low-cost transportation with access to Gulf Coast markets, which generally have higher benchmark pricing than WTI prices, offsetting some of the additional cost for the mode and increased distance of transportation.
The price at which our oil production is sold typically reflects a discount to the NYMEX benchmark price. Thus, our operating results are also affected by changes in the oil price differentials between the NYMEX and the sales prices we receive for our oil production. 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 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.
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Another significant factor affecting our operating results is drilling costs. The cost of drilling wells can vary significantly, driven in part by volatility in oil prices that can substantially impact the level of drilling activity in the Williston Basin. 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 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.
Market Conditions
The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Being primarily an oil producer, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can adversely impact oil prices. 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.
During the first half of 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices from $63.00 per Bbl in early January to an average of $27.95 per Bbl during the second quarter of 2020. This sudden decline in oil prices was attributable to two primary factors: (1) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (2) a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to increase its oil production to world markets following the failure of efforts by members of OPEC+ to agree on coordinated production cuts in March 2020. The OPEC price war ended in April 2020, with a deal to cut global petroleum output but did not go far enough to offset the dramatic negative impact of COVID-19 on demand. Oil prices improved since the second quarter of 2020, but the general outlook for commodity prices and the oil and natural gas industry remains uncertain, and we anticipate ongoing volatility.
Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2020, 2019 and 2018.
December 31,
2020 2019 2018
Average NYMEX Prices (1)
Oil (per Bbl) $ 39.24 $ 57.02 $ 64.95
Natural Gas (per Mcf) 2.01 2.56 3.16
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(1) Based on average NYMEX closing prices.
The average 2020 NYMEX pricing was $39.24 per barrel of oil or 31% lower than the average NYMEX price per barrel in 2019, which was partially offset by a $16.16 per barrel of oil increase in settled derivatives in 2020 as compared to 2019. Our average 2020 realized oil price per barrel after reflecting settled derivatives was $52.69 compared to $54.66 in 2019. Our 2020 realized gas price per Mcf was $1.14 compared to $1.60 in 2019, which was primarily driven by lower NYMEX pricing for both natural gas and natural gas liquids gas gathering as well as processing constraints in the Williston Basin. Recent construction projects have greatly expanded processing capacity within the basin as well as a significant new natural gas liquids pipeline. However, continued expansion of gathering systems in our basin will likely be required to fully harness these new systems and to improve long-term pricing realizations.
We employ a hedging program that mitigates the risk associated with fluctuations in commodity prices. The following tables reflect the weighted average price of open commodity price swap derivative contracts as of December 31, 2020, by year with associated volumes.
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Weighted Average Price
of Open Oil Swap Contracts
Year Volumes (Bbl) Weighted
Average Price ($)
2021 (1)
7,545,124 55.06
2022 (2)
816,250 50.49
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(1) We have entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for additional periods. Options covering a notional volume of 3.1 million barrels for 2022 are exercisable on or about December 31, 2021. If the counterparties exercise all such options, the notional volume of our existing crude oil derivative contracts will increase by 3.1 million barrels at a weighted average price of $52.68 per barrel for 2022.
(2) We have entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for additional periods. Options covering a notional volume of 1.5 million barrels for 2023 are exercisable on or about December 31, 2022. If the counterparties exercise all such options, the notional volume of our existing crude oil derivative contracts will increase by 1.5 million barrels at a weighted average price of $47.98 per barrel for 2023.
From time to time, we also hedge our oil basis differential to mitigate price risk associated with fluctuations in takeaway capacity. As of December 31, 2020, we have hedged approximately 1.5 million barrels for 2021 at a weighted average price of $(2.39) per barrel. See Note 12 to our financial statements.
Weighted Average Price
of Open Natural Gas Swap Contracts
Year Volumes (MMBtu) Weighted
Average Price ($)
2021 13,000,000 2.50
2022 3,650,000 2.61
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Results of Operations for 2020, 2019 and 2018
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.
Years Ended December 31,
2020 2019 2018
Net Production:
Oil (Bbl) 9,361,138 11,325,418 7,790,182
Natural Gas and NGLs (Mcf) 16,473,287 16,590,774 9,224,766
Total (Boe) 12,106,686 14,090,547 9,327,643
Net Sales (in thousands):
Oil Sales $ 305,249 $ 574,616 $ 450,149
Natural Gas and NGL Sales 18,802 26,601 43,760
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
Total Revenues 552,210 472,402 678,924
Average Sales Prices:
Oil (per Bbl) $ 32.61 $ 50.74 $ 57.78
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
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):
Production Expenses $ 116,336 $ 118,899 $ 66,646
Production Taxes 29,783 57,771 45,302
General and Administrative Expenses 18,546 23,624 14,568
Depletion, Depreciation, Amortization and Accretion 162,120 210,201 119,780
Costs and Expenses (per Boe):
Production Expenses $ 9.61 $ 8.44 $ 7.15
Production Taxes 2.46 4.10 4.86
General and Administrative Expenses 1.53 1.68 1.56
Depletion, Depreciation, Amortization and Accretion 13.39 14.92 12.84
Net Producing Wells at Period-End 475.1 458.7 325.1
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Oil and Natural Gas Sales
Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. In 2020, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, decreased 46% from 2019, driven by a 14% decrease in production volumes coupled with a 37% decrease in realized prices, excluding the effect of settled commodity derivatives. The lower average realized price in 2020 as compared to 2019 was principally driven by lower average NYMEX oil and natural gas prices. The lower NYMEX oil prices were also affected by a higher average oil price differential in 2020 as compared to 2019. The oil price differential during 2020 averaged $6.63 per barrel, as compared to $6.28 per barrel in 2019.
In 2019, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, increased 22% from 2018, driven primarily by a 51% increase in production levels offset by a 19% decrease in realized price, excluding the effect of settled derivatives. The lower average realized price in 2019 as compared to 2018 was principally driven by lower average NYMEX oil and natural gas prices, and gas gathering and processing constraints in the Williston Basin that lowered realized gas prices. The lower NYMEX oil prices were partially offset by a lower average oil price differential in 2019 as compared to 2018. The oil price differential during 2019 averaged $6.28 per barrel, as compared to $7.12 per barrel in 2018.
We add production through drilling success as we place new wells into production and through additions from acquisitions, which is offset by the natural decline of our oil and natural gas production from existing wells. Our acquisition program is a significant driver of our net well additions in certain years. Curtailments, shut-ins and completion delays due to the significant decline in commodity prices drove our 14% decrease in production levels in 2020 as compared to 2019, more than offsetting additions from acquisitions and new wells brought online. See “Impacts of COVID-19 Pandemic and Economic Environment” above. During 2019, our substantial acquisition activities (see Note 3 to our financial statements) combined with increased development activity and improved performance from enhanced completion techniques helped drive an increase in production levels as compared to 2018. In 2019, the number of net wells we added to production (excluding acquisitions) increased by 38% as compared to 2018. The higher number of new well completions and per well productivity improvements drove the 51% increase in production as compared to 2018. Our production for each of the last three years is set forth in the following table:
Year Ended December 31,
2020 2019 2018
Production:
Oil (Bbl) 9,361,138 11,325,418 7,790,182
Natural Gas and NGL (Mcf) 16,473,287 16,590,774 9,224,766
Total (Boe) (1)
12,106,686 14,090,547 9,327,643
Average Daily Production:
Oil (Bbl) 25,577 31,029 21,343
Natural Gas and NGL (Mcf) 45,009 45,454 25,273
Total (Boe) (1)
33,078 38,604 25,555
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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 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 commodity derivative contracts
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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 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. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”
Production Expenses
Production expenses were $116.3 million in 2020 compared to $118.9 million in 2019 and $66.6 million in 2018. On a per unit basis, production expenses increased 14% from $8.44 per Boe in 2019 to $9.61 per Boe in 2020 due primarily to fixed costs related to shut-in and/or curtailed production as well as higher per unit costs for processing. On an absolute dollar basis, the 2% decrease in our production expenses in 2020 compared to 2019 was primarily due to a 14% decrease in production offset by a 14% increase in per unit costs. On a per unit basis, our production expenses increased from $7.15 per Boe in 2018 to $8.44 per Boe in 2019 due primarily to fixed costs related to shut-in and/or curtailed production as well as higher per unit costs for processing and saltwater disposal charges. On an absolute dollar basis, our production expenses in 2019 were 78% higher when compared to 2018 due primarily to a 51% increase in production and the 18% increase in per unit costs.
Production Taxes
We pay production taxes based on realized oil and natural gas sales. Production taxes were $29.8 million in 2020 compared to $57.8 million in 2019 and $45.3 million in 2018. 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 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.
General and Administrative Expenses
General and administrative expenses were $18.5 million for 2020 compared to $23.6 million for 2019 and $14.6 million for 2018. The decrease in 2020 compared to 2019 was primarily due to a $4.1 million reduction in compensation expense, primarily due to lower non-cash share-based compensation and a decrease in cash severance charges incurred with the departure of an executive officer during the fourth quarter of 2019. Additionally, the decrease in 2020 compared to 2019 was due in part to a reduction in professional fees of $1.0 million.
General and administrative expenses in 2019 as compared to 2018 were higher primarily due to a $5.7 million increase in compensation expense, $4.1 million of which was an increase in non-cash share-based compensation, due in part to additions to our executive team that occurred late in the second quarter of 2018 and the timing of our 2018 and 2019 performance-based equity awards. The increase in 2019 was also due to a $0.8 million cash severance charge incurred with the departure of an executive officer during the fourth quarter of 2019 and $1.8 million in legal and advisory fees incurred in 2019 in connection with the VEN Bakken Acquisition.
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Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $162.1 million in 2020 compared to $210.2 million in 2019 and $119.8 million in 2018. Depletion expense, the largest component of DD&A, was $13.27 per Boe in 2020 compared to $14.84 per Boe in 2019 and $12.75 per Boe in 2018. The aggregate decrease in depletion expense for 2020 compared to 2019 was driven by a 14% decrease in production levels and a 11% decrease in the depletion rate per Boe. 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 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:
Year Ended December 31, Year Ended December 31,
2020 2019 Change Change 2019 2018 Change Change
Depletion $ 13.27 $ 14.84 $ (1.57) (11) % $ 14.84 $ 12.75 $ 2.09 16 %
Depreciation, Amortization, and Accretion 0.12 0.08 0.04 50 % 0.08 0.12 (0.04) (33) %
Total DD&A expense $ 13.39 $ 14.92 $ (1.53) (10) % $ 14.92 $ 12.87 $ 2.05 16 %
Impairment of Oil and Natural Gas Properties
As a result of low commodity prices and their effect on the proved reserve values of our properties, we recorded a non-cash ceiling test impairment of $1,066.7 million in 2020. We did not record any impairment of our proved oil and gas properties in 2019 or 2018. The impairment charge affected our reported net income but did not reduce our cash flow.
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.
Interest Expense
Interest expense, net of capitalized interest, was $58.5 million in 2020 compared to $79.2 million in 2019 and $86.0 million in 2018. The decrease in interest expense for 2020 as compared to 2019 was primarily due to a reduction in our outstanding debt balance during 2020 and lower interest rates on our Revolving Credit Facility. The decrease in interest expense for 2019 as compared to 2018 was primarily due to lower interest rates on our Revolving Credit Facility compared to our prior term loan facility, which was retired in October 2018.
Loss on the Extinguishment of Debt
As a result of a series of exchange transactions of our Second Lien Notes (see Note 4 to our financial statements), we recorded a loss on the extinguishment of debt of $3.7 million for the year ended December 31, 2020 based on the differences between the reacquisition costs of retiring the applicable debt and the net carrying values thereof. During 2019, we recorded a loss on extinguishment of debt of $23.2 million as a result of early redemptions of our Second Lien Notes (see Note 4 to our financial statements), based on the differences between the reacquisition costs of retiring the applicable debt and the net carrying values thereof. During 2018, we recorded a loss on extinguishment of debt of $173.4 million as a result of early redemptions of our prior senior unsecured notes and our prior term loan facility.
Debt Exchange Derivative Gain (Loss)
We incurred debt exchange derivative liabilities during 2018 in connection with certain exchange transactions with respect to previously outstanding senior unsecured notes. During the years ended December 31, 2019 and 2018, we recorded a debt exchange derivative liability gain of $1.4 million and loss of $0.6 million, respectively, due to the change in the fair value of these liabilities. As of December 31, 2019, there were no remaining outstanding debt exchange derivative liabilities, and as a result there were no associated gains or losses during 2020.
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Contingent Consideration Gain (Loss)
We incurred contingent consideration liabilities during 2018 in connection with certain acquisitions of oil and gas properties that closed in 2018. 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 $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.
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.
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Non-GAAP Financial Measures
Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. Net income (loss) is the most directly comparable GAAP measure for both Adjusted Net Income and Adjusted EBITDA, and tabular reconciliations for these measures are included below. We recorded a net loss of $906.0 million (representing $21.55 per diluted share) for 2020, compared to a net loss of $76.3 million (representing $2.00 per diluted share) for 2019 and net income of $143.7 million (representing $6.07 per diluted share) for 2018.
We define Adjusted Net Income (Loss) as net income (loss) excluding (i) unrealized (gain) loss on unsettled commodity derivatives, net of tax, (ii) financing expense, net of tax, (iii) impairment of other current assets, net of tax, (iv) write-off of debt issuance costs, net of tax, (v) loss on the extinguishment of debt, net of tax, (vi) debt exchange derivative (gain) loss, net of tax, (vii) contingent consideration loss, net of tax, (viii) acquisition transaction costs, net of tax, (ix) impairment expense, net of tax, and (x) loss on unsettled interest rate derivatives, net of tax. Our Adjusted Net Income for 2020 was $96.0 million (representing $1.82 per diluted share) as compared to Adjusted Net Income for 2019 of $120.9 million (representing $3.06 per diluted share) and Adjusted Net Income of $140.7 million (representing $5.94 per diluted share) for 2018. The decrease in Adjusted Net Income in 2020 compared to 2019 was primarily due to lower realized commodity prices (after the effect of settled derivatives), lower production volumes and increased per unit production expenses, which were partially offset by lower interest costs. The increase in Adjusted Net Income in 2019 compared to 2018 was primarily due to significantly higher production volumes as a result of our acquisitions and organic growth and lower interest costs, partially offset by increased per unit expenses and lower realized commodity prices (after the effect of settled derivatives).
We define Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization, and accretion, (iv) (gain) loss on unsettled commodity derivatives, (v) non-cash stock based compensation expense, (vi) write-off of debt issuance costs, (vii) loss on the extinguishment of debt, (viii) impairment of other current assets, (ix) debt exchange derivative (gain) loss, (x) contingent consideration loss, (xi) financing expense, (xii) impairment expense, (xiii) (gain) loss on unsettled interest rate derivatives, and (xiv) cash severance expense. Adjusted EBITDA for 2020 was $351.8 million, compared to Adjusted EBITDA of $454.2 million in 2019 and $349.3 million in 2018. The decrease in Adjusted EBITDA in 2020 as compared to 2019 was primarily due to lower production volumes, higher per unit production expenses, and lower realized commodity prices (after the effect of settled derivatives). The increase in Adjusted EBITDA in 2019 as compared to 2018 was primarily due to significantly higher production volumes as a result of our acquisitions and organic growth, partially offset by increased per unit expenses and lower realized commodity prices (after the effect of settled derivatives).
Management believes the use of these non-GAAP financial measures provide useful information to investors to gain an overall understanding of our current financial performance. Specifically, management believes the non-GAAP financial measures included herein provide useful information to both management and investors by excluding certain items that our management believes are not indicative of our core operating results. In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring our performance, and we believe that we are providing investors with financial measures that most closely align to our internal measurement processes. We consider these non-GAAP measures to be useful in evaluating our core operating results as they provide useful information regarding our essential revenue generating activities and direct operating expenses (resulting in cash expenditures) needed to perform these revenue generating activities. Our management also believes, based on feedback provided by the investment community, that the non-GAAP financial measures are necessary to allow the investment community to construct its valuation models to better compare our results with our competitors and market sector.
These measures should be considered in addition to our results of operations prepared in accordance with GAAP. In addition, these non-GAAP financial measures are not based on any comprehensive set of accounting rules or principles. We believe that non-GAAP financial measures have limitations in that they do not reflect all of the amounts associated with our results of operations as determined in accordance with GAAP and that these measures should only be used to evaluate our results of operations in conjunction with the corresponding GAAP financial measures.
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Reconciliation of Adjusted Net Income
Years Ended December 31,
(In thousands, except share and per share data) 2020 2019 2018
Net Income (Loss) $ (906,041) $ (76,318) $ 143,689
Add:
Impact of Selected Items:
(Gain) Loss on Unsettled Commodity Derivatives (39,878) 173,214 (207,892)
Impairment Expense 1,066,668 — —
Financing Expense — 1,447 884
Impairment of Other Current Assets — 6,398 —
Write-off of Debt Issuance Costs 1,543 — —
Loss on the Extinguishment of Debt 3,718 23,187 173,430
Debt Exchange Derivative (Gain) Loss — (1,390) 598
(Gain) Loss on Unsettled Interest Rate Derivatives 1,019 — —
Contingent Consideration Loss 169 29,512 28,968
Acquisition Transaction Costs — 1,763 —
Selected Items, Before Income Taxes 1,033,240 234,130 (4,012)
Income Tax of Selected Items (1)
(31,164) (36,898) 983
Selected Items, Net of Income Taxes 1,002,076 197,232 (3,029)
Adjusted Net Income $ 96,035 $ 120,914 $ 140,660
Weighted Average Shares Outstanding – Basic 42,744,639 38,708,460 23,620,646
Weighted Average Shares Outstanding – Diluted 52,659,217 39,482,135 23,677,391
Net Income (Loss) Per Common Share – Basic $ (21.20) $ (1.97) $ 6.08
Add:
Impact of Selected Items, Net of Income Taxes 23.45 5.09 (0.12)
Adjusted Net Income Per Common Share – Basic $ 2.25 $ 3.12 $ 5.95
Net Income (Loss) Per Common Share – Diluted $ (17.21) $ (1.93) $ 6.07
Add:
Impact of Selected Items, Net of Income Taxes 19.03 4.99 (0.13)
Adjusted Net Income Per Common Share – Diluted $ 1.82 $ 3.06 $ 5.94
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(1) The 2020 column represents a tax impact using an estimated tax rate of 24.5% and includes an adjustment of $222.0 million for changes in our valuation allowance. The 2019 column represents a tax impact using an estimated tax rate of 24.5% and includes an adjustment of $20.5 million for changes in our valuation allowance. The 2018 column represents a tax impact using an estimated tax rate of 24.5% and does not include any adjustments for changes in our valuation allowance.
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Reconciliation of Adjusted EBITDA
Year Ended December 31,
(In thousands) 2020 2019 2018
Net Income (Loss) $ (906,041) $ (76,318) $ 143,689
Add:
Interest Expense 58,503 79,229 86,005
Income Tax Provision (Benefit) (166) — (55)
Depreciation, Depletion, Amortization and Accretion 162,120 210,201 119,780
Impairment of Other Current Assets — 6,398 —
Non-Cash Stock-Based Compensation 4,119 7,955 3,876
Write-off of Debt Issuance Costs 1,543 — —
Loss on the Extinguishment of Debt 3,718 23,187 173,430
Debt Exchange Derivative (Gain) Loss — (1,390) 598
Contingent Consideration Loss 169 29,512 28,968
Financing Expense — 1,447 884
Cash Severance Expense — 759 —
(Gain) Loss on Unsettled Interest Rate Derivatives 1,019 — —
(Gain) Loss on Unsettled Commodity Derivatives (39,878) 173,214 (207,892)
Impairment Expense 1,066,668 — —
Adjusted EBITDA 351,774 454,193 349,283
Liquidity and Capital Resources
Overview
Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations, proceeds from equity and debt financings, credit facility borrowings, and cash settlements of commodity derivative instruments. Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.
As of December 31, 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; and
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• 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. Oil accounted for 77% and 80% of our total production volumes in 2020 and 2019, 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 the price of crude oil with respect to a portion of our expected oil production. For the years ended 2020 and 2019, we hedged approximately 104% and 76% of our crude oil production, respectively. For a summary as of December 31, 2020, of our open commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.
With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months. However, we may seek additional access to capital and liquidity. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all.
Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility. Our capital expenditures could be curtailed if our cash flows decline from expected levels. Because production from existing oil and natural gas wells declines over time, reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future.
Working Capital
Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, collection of receivables, expenditures related to our development and production operations and the impact of our outstanding derivative instruments.
At December 31, 2020, we had a working capital deficit of $56.8 million, compared to a deficit of $70.4 million at December 31, 2019. Current assets decreased by $7.4 million and current liabilities decreased by $21.0 million at December 31, 2020, compared to December 31, 2019. The decrease in current assets in 2020 as compared to 2019 is primarily due to a decrease of $37.3 million in accounts receivable primarily due to our lower production levels and reduced commodity prices and a lower cash balance, which was partially offset by an increase of $45.7 million in our derivative instruments, due to the change in fair value as a result of oil price projections. The change in current liabilities in 2020 as compared to 2019 is primarily due to a decrease of $75.3 million in accounts payable and accrued expenses primarily as a result of reduced development activity and an $8.2 million decrease in derivative instruments as a result of forward oil price changes, which was partially offset by the current maturity of our first Unsecured VEN Bakken Note payment of $65.0 million that was paid on January 4, 2021. Additionally, our accrued interest was reduced by $3.3 million as a result of lower levels of debt outstanding in 2020 as compared to 2019.
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. 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.”
Our cash flows for the years ended December 31, 2020, 2019 and 2018 are presented below:
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Year Ended December 31,
(In thousands) 2020 2019 2018
Net Cash Provided by Operating Activities $ 331,685 $ 339,750 $ 244,262
Net Cash Used for Investing Activities (283,926) (569,128) (474,519)
Net Cash Provided by (Used for) Financing Activities (62,399) 243,088 130,431
Net Change in Cash $ (14,640) $ 13,710 $ (99,826)
Cash Flows from Operating Activities
Net cash provided by operating activities in 2020 was $331.7 million, compared to $339.7 million in 2019. 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, 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 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, 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.
Development and acquisition activities are discretionary. We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the years ended December 31, 2020, 2019 and 2018 are summarized in the following table:
Year Ended December 31,
(In millions) 2020 2019 2018
Drilling and Development Capital Expenditures $ 235.4 $ 337.5 $ 216.0
Acquisition of Oil and Natural Gas Properties 47.0 229.0 257.8
Other Capital Expenditures 1.2 1.3 0.7
Total $ 283.6 $ 567.8 $ 474.5
Cash Flows from Financing Activities
Net cash (used for) provided by financing activities was $(62.4) million, $243.1 million and $130.4 million for the years ended December 31, 2020, 2019 and 2018, respectively. The cash used for financing activities in 2020 was primarily related to a net decrease in borrowings of $48.0 million on our Revolving Credit Facility and repurchases of $13.5 million of aggregate principal amount of our Second Lien Notes (See Note 4 to our financial statements)
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The cash provided by financing activities in 2019 was primarily related to a net increase in borrowings of $440.0 million on our Revolving Credit Facility and $70.9 million for the issuance of preferred stock which was partially offset by repayments of our Second Lien Notes of $227.5 million in connection with a prior refinancing transaction (See Note 4 to our financial statements). Additionally, we repurchased $15.1 million of common stock and spent $12.2 million in fees in connection with debt financing transactions in 2019. The cash provided by financing activities in 2018 was primarily related to $141.7 million in equity offerings, as well as a net increase in borrowings of $40.0 million on our Revolving Credit Facility. Additionally, we repurchased $22.2 million of common stock and spent $26.6 million in fees in connection with debt financing transactions in 2018.
Revolving Credit Facility
In November 2019, we entered into a revolving credit facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto (the “Revolving Credit Facility”), which amended and restated our existing revolving credit facility that was entered into on October 5, 2018. The Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to our oil and gas properties. As of December 31, 2020, the Revolving Credit Facility had a borrowing base of $660.0 million and we had $532.0 million of borrowings outstanding under the facility, leaving $128.0 million in available borrowing capacity. See Note 4 and Note 14 to our financial statements for further details regarding the Revolving Credit Facility.
Second Lien Notes due 2023
As of December 31, 2020, we had $287.8 million in outstanding principal amount of our 8.500% senior secured second lien notes due 2023 (the “Second Lien Notes”). See Note 4 and Note 14 to our financial statements for further details regarding the Second Lien Notes.
Unsecured VEN Bakken Note
As of December 31, 2020, we had $130.0 million in outstanding principal amount under the Unsecured VEN Bakken Note. See Note 4 and Note 14 to our financial statements for further details regarding the Unsecured VEN Bakken Note.
Series A Preferred Stock
As of December 31, 2020, we had 2.2 million outstanding shares of 6.500% Series A Perpetual Cumulative Convertible Preferred Stock (the “Series A Preferred Stock”), having an aggregate liquidation preference of $221.9 million. See Note 5 to our financial statements for further details regarding the Series A Preferred Stock.
2021 Capital Expenditure Budget
Our board of directors has approved a capital expenditure budget for calendar year 2021. However, the amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors. If oil, NGL and natural gas prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. 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
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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 require 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. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.
Contractual Obligations and Commitments
The following table summarizes our obligations and commitments at December 31, 2020 to make future payments under certain contracts, aggregated by category of contractual obligation, for specified time periods:
Payment due by Period
(In thousands)
Contractual Obligations Less than
1 year 1-3 years 3-5 years More than
5 years Total
Office Leases (1)
$ 340 $ — $ — $ — $ 340
Long Term Debt (2)
65,000 352,755 532,000 — 949,755
Cash Interest Expense on Debt (3)
43,872 66,606 13,855 — 124,333
Total $ 109,212 $ 419,361 $ 545,855 $ — $ 1,074,428
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(1) Office leases through 2021
(2) Revolving Credit Facility, Second Lien Notes and Unsecured VEN Bakken Note (see Note 4 to our financial statements)
(3) Cash interest on our Revolving Credit Facility, Second Lien Notes and Unsecured VEN Bakken Note are estimated assuming no principal repayment until the due date.
The above contractual obligations schedule does not include future anticipated settlement of derivative contracts or estimated amounts expected to be incurred in the future associated with the abandonment of our oil and natural gas properties, as we cannot determine with accuracy the amount and/or timing of such payments.
Critical Accounting Policies
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
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alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions.
Use of Estimates
The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect our reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Our estimates of our proved oil and natural gas reserves, future development costs, estimates relating to certain oil and natural gas revenues and expenses, and fair value of derivative instruments are the most critical to our financial statements.
Oil and Natural Gas Reserves
The determination of depreciation, depletion and amortization expense as well as impairments that are recognized on our oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change. Approximately 31% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserve, future cash flows from our reserves, and future development of our proved undeveloped reserves.
The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. Such information includes revisions of certain reserve estimates attributable to our properties included in the prior year’s estimates. These revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in oil and natural gas prices.
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, 2020.
Oil and Natural Gas Properties
The method of accounting we use to account for our oil and natural gas investments determines what costs are capitalized and how these costs are ultimately matched with revenues and expensed.
We utilize the full cost method of accounting to account for our oil and natural gas investments instead of the successful efforts method because we believe it more accurately reflects the underlying economics of our programs to explore and develop oil and natural gas reserves. The full cost method embraces the concept that dry holes and other expenditures that fail to add reserves are intrinsic to the oil and natural gas exploration business. Thus, under the full cost method, all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs, geological and geophysical costs that are directly attributable to the properties and capitalized interest. Although some of these costs will ultimately result in no additional reserves, they are part of a program from which we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. The full cost method differs from the successful efforts method of accounting for oil and natural gas investments. The primary difference between these two methods is the treatment of exploratory dry hole costs. These costs are generally expensed under the successful efforts method when it is determined that measurable reserves do not exist. Geological and geophysical costs are also expensed under the successful efforts method. Under the full cost method, both dry hole costs and geological and geophysical
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costs are initially capitalized and classified as unproved properties pending determination of proved reserves. If no proved reserves are discovered, these costs are then amortized with all the costs in the full cost pool.
Capitalized amounts except unproved costs are depleted using the units of production method. The depletion expense per unit of production is the ratio of the sum of our unamortized historical costs and estimated future development costs to our proved reserve volumes. Estimation of hydrocarbon reserves relies on professional judgment and use of factors that cannot be precisely determined. Subsequent reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting periods. For the year ended December 31, 2020, our average depletion expense per unit of production was $13.27 per Boe.
To the extent the capitalized costs in our full cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the sum of the present value (using a 10% discount rate and based on 12-month/SEC oil and natural gas prices) of the estimated future net cash flows from our proved oil and natural gas reserves and the capitalized cost associated with our unproved properties, we would have a capitalized ceiling impairment. Such costs would be charged to operations as a reduction of the carrying value of oil and natural gas properties. The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are depressed, even if the low prices are temporary. In addition, capitalized ceiling impairment charges may occur if we experience poor drilling results or if estimations of our proved reserves are substantially reduced. A capitalized ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and stockholders’ equity. Once recognized, a capitalized ceiling impairment charge to oil and natural gas properties cannot be reversed at a later date. The risk that we will experience a ceiling test writedown increases when oil and natural gas prices are depressed or if we have substantial downward revisions in our estimated proved reserves.
At December 31, 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 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. 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 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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