NORTHERN OIL AND GAS, INC. The following discussion should be read in conjunction with the "Selected Financial Data" in Item 6 and the Financial Statements and accompanying Notes to Financial Statements appearing elsewhere in this report.
Executive Overview
We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas properties, primarily in the Bakken andThree Forks formations within theWilliston Basin inNorth Dakota andMontana . We believe the location, size and concentration of our acreage position in one ofNorth America's leading unconventional oil-resource plays provide us with drilling and development opportunities that will result in significant long-term value. Our primary focus is oil exploration and production through non-operated working interests in wells drilled and completed in spacing units that include our acreage. Using this strategy, we participated in 6,156 gross (458.7 net) producing wells as ofDecember 31, 2019 .
Our financial and operating performance for the year ended
•Oil and gas sales of
•Cash flows from operations of
•Average daily production of 38,604 Boepd in 2019, a 51% increase compared to 25,555 Boepd in 2018
•Added 133.2 net wells to production in 2019, including 90.1 net wells from the VEN Bakken acquisition
•Proved reserves of 163.3 MMBoe atDecember 31, 2019 , a 21% increase compared toDecember 31, 2018 , as estimated by our third-party reserve engineers underSEC guidelines •Accelerated our growth with the VEN Bakken Acquisition that closed onJuly 1, 2019 , which we estimate contributed approximately 7,912 Boepd, or 18%, of our average daily production in the fourth quarter of 2019
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 ourWilliston Basin well head price and the NYMEX WTI benchmark price is driven by the additional cost to transport oil from theWilliston Basin via train, pipeline or truck to refineries. •Gain (loss) on derivative instruments, net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of oil. Gain (loss) on derivative instruments, net is comprised of (i) cash gains and losses we recognize on settled derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on derivative instruments outstanding at period-end. •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
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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 impairment. Depreciation, depletion,
amortization and impairment includes the systematic expensing of the capitalized
costs incurred to acquire, explore and develop oil and natural gas properties.
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.
•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.
•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 our acreage and wells in theWilliston Basin subjects our operating results to factors specific to this region. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, and the limitations of the developing infrastructure and transportation capacity in this region. We believe that gas gathering and processing constraints in theWilliston Basin caused curtailments, shut-ins and completion delays that negatively impacted our production during 2019, and we expect these challenges to persist into 2020. 44 -------------------------------------------------------------------------------- Tab le of Contents The price of oil in theWilliston 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 theWilliston 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 ofNorth Dakota's location relative to traditional oil transport centers, this higher value is generally offset to some extent by higher transportation costs. While rail transportation has historically been more expensive than pipeline transportation,Williston Basin prices have at times justified shipment by rail to markets on the gulf coast and east coast, which offer prices benchmarked to LLS/Brent. Additional pipeline infrastructure has increased takeaway capacity in 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. 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 2019 was$6.28 per barrel, as compared to$7.12 per barrel in 2018. Fluctuations in our oil price differential are driven by various factors including (among others) takeaway capacity relative to production levels in theWilliston Basin , and seasonal refinery maintenance temporarily depressing crude demand. Another significant factor affecting our operating results is drilling costs. The cost of drilling wells can vary significantly, driven in part by volatility in oil prices that can substantially impact the level of drilling activity in theWilliston 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, the choice of proppant, and other factors related to the completion techniques utilized. During 2019, the weighted average authorization for expenditure (or AFE) cost for wells we elected to participate in was$8.0 million , compared to$8.1 million for the wells we elected to participate in during 2018.
Market Conditions
The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Being primarily an oil producer, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in terms of output, especially production from properties withinthe United States , the production quota set byOPEC , and the strength of theU.S. dollar can adversely impact oil prices. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production. Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the years endedDecember 31, 2019 , 2018 and 2017. December 31, 2019 2018 2017 Average NYMEX Prices(1) Oil (per Bbl)$ 57.02 $ 64.95 $ 50.85
Natural Gas (per Mcf) 2.56 3.16 3.02
________________________
(1)Based on average NYMEX closing prices.
The average 2019 NYMEX pricing was$57.02 per barrel of oil or 12% lower than the average NYMEX price per barrel in 2018, which was partially offset by a$6.86 per barrel of oil increase in settled derivatives in 2019 as compared to 2018. Our average 2019 realized oil price per barrel after reflecting settled derivatives was$54.66 compared to$54.84 in 2018. Our 2019 realized gas price per Mcf was$1.60 compared to$4.74 in 2018, which was primarily driven by gas gathering and processing constraints in theWilliston Basin as well as lower NYMEX pricing for both natural gas and natural gas liquids. 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. 45 -------------------------------------------------------------------------------- Tab le of Contents As ofDecember 31, 2019 , we had a total volume on open commodity swaps of 17.3 million barrels at a weighted average price of approximately$56.77 per barrel. The following table reflects the weighted average price of open commodity price swap derivative contracts as ofDecember 31, 2019 , by year with associated volumes. Weighted Average Price of Open Commodity Swap Contracts Weighted Year Volumes (Bbl) Average Price ($) 2020 9,815,844 57.98 2021(1) 6,151,174 55.78 2022(2) 1,372,866 52.57 ___________ (1)We have entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for additional periods. Options covering a notional volume of 0.1 million barrels for 2021 are exercisable on or aboutDecember 31, 2020 . If the counterparties exercise all such options, the notional volume of our existing crude oil derivative contracts will increase by 0.1 million barrels at a weighted average price of$57.63 per barrel for 2021. (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 2.4 million barrels for 2022 are exercisable on or aboutDecember 31, 2021 . If the counterparties exercise all such options, the notional volume of our existing crude oil derivative contracts will increase by 2.4 million barrels at a weighted average price of$55.05 per barrel for 2022. 46
-------------------------------------------------------------------------------- Tab le of Contents Results of Operations for 2019, 2018 and 2017
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,
2019 2018 2017
Net Production:
Oil (Bbl) 11,325,418 7,790,182 4,537,295
Natural Gas and NGLs (Mcf) 16,590,774 9,224,766 5,187,886
Total (Boe) 14,090,547 9,327,643 5,401,943
Net Sales (in thousands):
Oil Sales $ 574,616 $ 450,149 $ 204,581
Natural Gas and NGL Sales 26,601 43,760 19,382
Gain (Loss) on Settled Derivatives 44,377 (22,886) 3,777
Unrealized Gain (Loss) on Derivatives (173,214) 207,892 (18,443)
Other Revenue 21 9 23
Total Revenues 472,402 678,924 209,320
Average Sales Prices:
Oil (per Bbl) $ 50.74 $ 57.78 $ 45.09
Effect of Gain (Loss) on Settled Derivatives on
Average Price (per Bbl) 3.92 (2.94) 0.83
Oil Net of Settled Derivatives (per Bbl) 54.66 54.84 45.92
Natural Gas and NGLs (per Mcf) 1.60 4.74 3.74
Realized Price on a Boe Basis Including all
Realized Derivative Settlements 45.82 50.50 42.16
Operating Expenses (in thousands):
Production Expenses $ 118,899 $ 66,646 $ 49,733
Production Taxes 57,771 45,302 20,604
General and Administrative Expenses 23,624 14,568 18,988
Depletion, Depreciation, Amortization and
Accretion 210,201 119,780 59,500
Costs and Expenses (per Boe):
Production Expenses $ 8.44 $ 7.15 $ 9.21
Production Taxes 4.10 4.86 3.81
General and Administrative Expenses 1.68 1.56 3.52
Depletion, Depreciation, Amortization and
Accretion 14.92 12.84 11.01
Net Producing Wells at Period-End 458.7 325.1 229.0
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 2019, our oil, natural gas and NGL
sales, excluding the effect of settled derivatives, increased 22% from 2018,
driven by a 51% increase in production volumes offset by a 19% decrease in
realized price, excluding the effect of settled derivatives. The lower average
realized price in 2019 as compared to 2018 was principally driven by lower
average NYMEX
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oil and natural gas prices, and gas gathering and processing constraints in the
Williston Basin that lowered realized gas prices. The lower NYMEX oil prices
were partially offset by a lower average oil price differential in 2019 as
compared to 2018. The oil price differential during 2019 averaged $6.28 per
barrel, as compared to $7.12 per barrel in 2018.
In 2018, our oil, natural gas and NGL sales, excluding the effect of settled
derivatives, increased 121% from 2017, driven primarily by an 73% increase in
production levels and a 28% increase in realized price, excluding the effect of
settled derivatives. The higher average realized price in 2018 as compared to
2017 was principally driven by higher average NYMEX oil and natural gas prices.
These higher prices were partially offset by a higher average oil price
differential in 2018 as compared to 2017, which was the most pronounced in the
fourth quarter of 2018, coinciding with our highest levels of production for the
year. The oil price differential during 2018 averaged $7.12 per barrel, as
compared to $5.87 per barrel in 2017.
We add production through drilling success as we place new wells into production
and through additions from acquisitions, which is offset by the natural decline
of our oil and natural gas production from existing wells. During 2019, our
substantial acquisition activities (see Note 3 to our financial statements)
combined with increased development activity and improved performance from
enhanced completion techniques helped drive a 51% increase in production levels
as compared to 2018. During 2019, we added 133.2 total net wells to production,
including 90.1 net wells from the VEN Bakken acquisition. Excluding the wells
added from acquisitions, this was a 38% increase as compared to 2018. Our
acquisition program is a significant driver of our net well additions. In 2018,
the number of net wells we added to production (excluding acquisitions)
increased by 85% as compared to 2017. The higher number of new well completions
and per well productivity improvements drove the 73% increase in production as
compared to 2017. Our production for each of the last three years is set forth
in the following table:
Year Ended December 31,
2019 2018 2017
Production:
Oil (Bbl) 11,325,418 7,790,182 4,537,295
Natural Gas and NGL (Mcf) 16,590,774 9,224,766 5,187,886
Total (Boe)(1) 14,090,547 9,327,643 5,401,943
Average Daily Production:
Oil (Bbl) 31,029 21,343 12,431
Natural Gas and NGL (Mcf) 45,454 25,273 14,213
Total (Boe)(1) 38,604 25,555 14,800
__________________________________
(1)Natural gas and NGLs are converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices. Derivative Instruments We enter into derivative instruments to mitigate the price risk attributable to future oil production. Our gain (loss) on derivative instruments, net was a loss of$128.8 million in 2019, compared to a gain of$185.0 million in 2018, and a loss of$14.7 million in 2017. Gain (loss) on derivative instruments, net is comprised of (i) cash gains and losses we recognize on settled derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on derivative instruments outstanding at period-end. For 2019, we realized a gain on settled derivatives of$44.4 million , compared to a$22.9 million loss in 2018 and a$3.8 million gain in 2017. The percentage of oil production hedged under our derivative contracts was 76%, 64%, and 62% in 2019, 2018, and 2017, respectively. The weighted average oil price on our settled derivative contracts in 2019, 2018, and 2017 was$61.51 ,$59.27 , and$52.61 , respectively. Our average realized price (including all cash derivative settlements) in 2019 was$45.82 per Boe compared to$50.50 per Boe in 2018, and$42.16 per Boe in 2017. The gain (loss) on settled derivatives increased our average realized price per Boe by$3.15 in 2019, decreased our average realized price per Boe by$2.45 in 2018 and increased our average realized price per Boe by$0.70 in 2017. 48 -------------------------------------------------------------------------------- Tab le of Contents Mark-to-market derivative gains and losses was a loss of$173.2 million in 2019 compared to a gain of$207.9 million in 2018 and a loss of$18.4 million in 2017. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Any gains on our derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date. AtDecember 31, 2019 , all of our derivative contracts are recorded at their fair value, which was a net liability of$5.2 million , a decrease of$182.9 million from the$177.7 million net asset recorded as ofDecember 31, 2018 . The decrease in the net liability atDecember 31, 2019 as compared toDecember 31, 2018 was primarily due to changes in forward oil prices relative to prices on our open oil derivative contracts sinceDecember 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$118.9 million in 2019 compared to$66.6 million in 2018 and$49.7 million in 2017. On a per unit basis, production expenses increased 18% from$7.15 per Boe in 2018 to$8.44 per Boe in 2019 due primarily to fixed costs related to shut-in and/or curtailed production as well as higher per unit costs for processing and saltwater disposal charges. On an absolute dollar basis, the 78% increase in our production expenses in 2019 compared to 2018 was primarily due to a 51% increase in production and an 18% increase in per unit costs. On a per unit basis, our production expenses decreased from$9.21 per Boe in 2017 to$7.15 per Boe in 2018 due primarily to higher production levels over which fixed costs are spread. On an absolute dollar basis, our production expenses in 2018 were 34% higher when compared to 2017 due primarily to a 73% increase in production and a 42% increase in net producing wells, offset by the decline in per unit costs.
Production Taxes
We pay production taxes based on realized oil and natural gas sales. Higher production levels in 2019 as compared to 2018, and in 2018 as compared to 2017, increased the taxable base that is used to calculate production taxes. Production taxes were$57.8 million in 2019 compared to$45.3 million in 2018 and$20.6 million in 2017. As a percentage of oil and natural gas sales, our production taxes were 9.6%, 9.2% and 9.2% in 2019, 2018 and 2017, respectively. The higher average production tax rates in 2019, compared to 2018 and 2017, is due to an increase in our oil sales as a percentage of our total oil and gas sales. Oil sales are taxed at a higher rate than gas sales.
General and Administrative Expenses
General and administrative expenses were$23.6 million for 2019 compared to$14.6 million for 2018 and$19.0 million for 2017. The increase in 2019 compared to 2018 was primarily due to a$5.7 million increase in compensation expense,$4.1 million of which was an increase in non-cash share-based compensation, due in part to additions to our executive team that occurred late in the second quarter of 2018 and the timing of our 2018 and 2019 performance-based equity awards. The increase in 2019 was also due to a$0.8 million cash severance charge incurred with the departure of an executive officer during the fourth quarter of 2019 and$1.8 million in legal and advisory fees incurred in 2019 in connection with the VEN Bakken Acquisition. General and administrative expenses in 2018 as compared to 2017 were lower due in part to a$3.6 million litigation settlement charge in the third quarter of 2017 and a$1.2 million reversal of non-cash share-based compensation expense in connection with the resignation of a former executive officer in the first quarter of 2018.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion ("DD&A") was $210.2 million
in 2019 compared to $119.8 million in 2018 and $59.5 million in 2017. Depletion
expense, the largest component of DD&A, was $14.84 per Boe in 2019 compared to
$12.75 per Boe in 2018 and $10.89 per Boe in 2017. The aggregate increase in
depletion expense for 2019 compared to 2018 was driven by a 51% increase in
production levels and a 16% increase in the depletion rate per Boe. The 2019
depletion rate per Boe was higher due to the impact of recent acquisitions in
2019 and 2018. The aggregate increase in depletion expense for 2018 compared to
2017 was driven by an 73% increase in production levels and a 17% increase in
the depletion rate per Boe. The 2018 depletion rate per Boe was higher due to an
increase in well costs and the impact of acquisitions in 2018. The following
table summarizes DD&A expense per Boe for 2019, 2018 and 2017:
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Year Ended December 31, Year Ended December 31,
2019 2018 Change Change 2018 2017 Change Change
Depletion $ 14.84 $ 12.75 $ 2.09 16 % $ 12.75 $ 10.89 $ 1.86 17 %
Depreciation, Amortization, and
Accretion 0.08 0.12 (0.04) (33) % 0.12 0.12 - - %
Total DD&A expense $ 14.92 $ 12.87 $ 2.05 16 % $ 12.87 $ 11.01 $ 1.86 17 %
Impairment of
We did not have any impairment of our proved oil and gas properties in 2019, 2018, and 2017. Depending on future commodity price levels, the trailing twelve-month average price used in the ceiling calculation may decline, which could cause future write downs of our oil and natural gas properties. 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$79.2 million in 2019 compared to$86.0 million in 2018 and$70.3 million in 2017. 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 inOctober 2018 . The increase in interest expense for 2018 as compared to 2017 was primarily due to an increase in average borrowings outstanding between periods, with higher interest rates and a lower amount of capitalized interest cost. A portion of the increased interest expense was non-cash payment-in-kind interest under our Second Lien Notes. The higher interest rates were associated in large part with our prior term loan facility, which was retired inOctober 2018 and replaced with a lower cost and more flexible Revolving Credit Facility.
Loss on the Extinguishment of Debt
As a result of the November 2019 refinancing transactions (see Note 4 to our
financial statements), we recorded a loss on the extinguishment of debt of $23.2
million for the year ended December 31, 2019 based on the differences between
the reacquisition costs of retiring the applicable debt and the net carrying
values thereof. During 2018, we recorded a loss on extinguishment of debt of
$173.4 million as a result of the exchange agreements and early redemptions of
our 8% senior unsecured notes and our term loan facility (see Note 4 to our
financial statements), based on the differences between the reacquisition costs
of retiring the applicable debt and the net carrying values thereof. During
2017, we recorded a loss on extinguishment of debt of $1.0 million as a result
of the early termination of a prior revolving credit facility.
Debt Exchange Derivative Gain (Loss)
In connection with certain exchange transactions with respect to our
Unsecured Notes (described as the "Additional 2018 Exchanges" in Note 4 to our
financial statements), we incurred debt exchange derivative liabilities during
2018. During the year ended December 31, 2019 , we recorded a debt exchange
derivative liability gain of $1.4 million due to the change in the fair value of
these liabilities (see Note 11 to our financial statements). During the year
ended December 31, 2018 , we recorded a debt exchange derivative liability loss
of $0.6 million due to the change in the fair value of these liabilities (see
Note 11 to our financial statements). There was no debt exchange derivative
liability gain or loss during 2017 because we did not incur any such liabilities
until 2018. As of December 31, 2019 , there were no remaining outstanding debt
exchange derivative liabilities.
Contingent Consideration Gain (Loss)
In connection with the W Energy Acquisition and the Pivotal Acquisition that
closed in 2018, (see Note 3 to our financial statements), we incurred contingent
consideration liabilities during 2018. During the year ended December 31, 2019 ,
and 2018, we recorded a contingent consideration loss of $29.5 million and $29.0
million , respectively, due to the change in the fair value of these liabilities
(see Note 11 to our financial statements). There was no contingent consideration
gain or loss during 2017 because we did not incur any such liabilities until
2018. As of December 31, 2019 , there were no remaining outstanding contingent
consideration liabilities.
50-------------------------------------------------------------------------------- Tab le of Contents Income Tax Benefit We recognized income tax benefit of zero,$0.1 million , and$1.6 million in 2019, 2018, and 2017, respectively. The effective tax rate was zero, zero, and 14.6% in 2019, 2018, and 2017, respectively. In 2018, and 2017, the tax benefits recognized related to the utilization of our alternative minimum tax credit as a result of favorable tax incentives. We have recorded a valuation allowance against effectively all of our net deferred tax assets due to uncertainty regarding their realization in 2019 and 2018. We intend to continue maintaining a full valuation allowance on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of these allowances. However, given our current earnings and potential future earnings, we believe that there is a reasonable possibility that within the next twelve months, sufficient positive evidence may become available to allow us to reach a conclusion that a significant portion of the valuation allowance will no longer be needed. Release of any portion of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense for the period the release is recorded. 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. 51
-------------------------------------------------------------------------------- Tab le of Contents 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$76.3 million (representing$0.20 per diluted share) for 2019, compared to net income of$143.7 million (representing$0.61 per diluted share) for 2018 and a net loss of$9.2 million (representing$0.15 per diluted share) for 2017. We define Adjusted Net Income (Loss) as net income (loss) excluding (i) unrealized (gain) loss on derivatives, net of tax, (ii) financing expense, net of tax, (iii) impairment of other current assets, net of tax, (iv) write-off of debt issuance costs, net of tax, (v) loss on the extinguishment of debt, net of tax, (vi) debt exchange derivative (gain) loss, net of tax, (vii) certain legal settlements, net of tax, (viii) contingent consideration loss, net of tax, and (ix) acquisition transaction costs, net of tax. Our Adjusted Net Income for 2019 was$120.9 million (representing$0.31 per diluted share) as compared to Adjusted Net Income for 2018 of$140.7 million (representing$0.59 per diluted share) and Adjusted Net Income of$8.5 million (representing$0.14 per diluted share) for 2017. The decrease in Adjusted Net Income in 2019 compared to 2018 was primarily due to lower realized commodity prices (after the effect of settled derivatives) and increased per unit production expenses, which were partially offset by higher production volumes and lower interest costs. The increase in Adjusted Net Income in 2018 compared to 2017 was primarily due to significantly higher production volumes as a result of our acquisitions and organic growth, decreased per unit expenses and higher realized commodity prices (after the effect of settled derivatives), which were partially offset by higher interest costs. We define Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization, and accretion, (iv) unrealized (gain) loss on derivatives, (v) non-cash stock based compensation expense, (vi) write-off of debt issuance costs, (vii) loss on the extinguishment of debt, (viii) impairment of other current assets, (ix) debt exchange derivative (gain) loss, (x) contingent consideration loss, (xi) financing expense, and (xii) cash severance expense. Adjusted EBITDA for 2019 was$454.2 million , compared to Adjusted EBITDA of$349.3 million in 2018 and$144.7 million in 2017. The increase in Adjusted EBITDA in 2019 as compared to 2018 was primarily due to significantly higher production volumes, partially offset by higher per unit production expenses and lower realized commodity prices (after the effect of settled derivatives). The increase in Adjusted EBITDA in 2018 as compared to 2017 was primarily due to significantly higher production volumes as a result of our acquisitions and organic growth, decreased per unit expenses and higher realized commodity prices (after the effect of settled derivatives). 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. 52
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Reconciliation of Adjusted Net Income
Years Ended December 31,
(In thousands, except share and per share data) 2019 2018 2017
Net Income (Loss) $ (76,318) $ 143,689 $ (9,194)
Add:
Impact of Selected Items:
Unrealized (Gain) Loss on Derivatives 173,214 (207,892) 18,443
Financing Expense 1,447 884 -
Impairment of Other Current Assets 6,398 - -
Write-off of Debt Issuance Costs - - 95
Loss on the Extinguishment of Debt 23,187 173,430 993
Debt Exchange Derivative (Gain) Loss (1,390) 598 -
Contingent Consideration Loss 29,512 28,968 -
Legal Settlements - - 3,589
Acquisition Transaction Costs 1,763 - -
Selected Items, Before Income Taxes 234,130 (4,012) 23,121
Income Tax of Selected Items(1) (36,898) 983 (5,388)
Selected Items, Net of Income Taxes 197,232 (3,029) 17,733
Adjusted Net Income $ 120,914 $ 140,660 $ 8,539
Weighted Average Shares Outstanding - Basic 387,084,651 236,206,457 62,408,855
Weighted Average Shares Outstanding - Diluted 394,805,513 236,773,911 62,769,234
Net Income (Loss) Per Common Share - Basic $ (0.20) $ 0.61 $ (0.15)
Add:
Impact of Selected Items, Net of Income Taxes 0.51 (0.01) 0.29
Adjusted Net Income Per Common Share - Basic $ 0.31 Net Income (Loss) Per Common Share - Diluted$ (0.19) $ 0.61 $ (0.15) Add: Impact of Selected Items, Net of Income Taxes 0.50 (0.02) 0.29
Adjusted Net Income Per Common Share - Diluted
_______________
(1)The 2019 column represents a tax impact using an estimated tax rate of 24.5% and includes an adjustment of$20.5 million for changes in our valuation allowance. The 2018 column represents a tax impact using an estimated tax rate of 24.5% and does not include any adjustments for changes in our valuation allowance. The 2017 column represents a tax impact using an estimated tax rate of 39.1% and includes adjustments for changes in our valuation allowance of$3.7 million , excluding the impact for the Act that was enacted onDecember 22, 2017 . 53
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Tab le of Contents
Reconciliation of Adjusted EBITDA
Year Ended December 31,
(In thousands) 2019 2018 2017
Net Income (Loss) $ (76,318) $ 143,689 $ (9,194)
Add:
Interest Expense 79,229 86,005 70,286
Income Tax Provision (Benefit) - (55) (1,570)
Depreciation, Depletion, Amortization and Accretion 210,201
119,780 59,500
Impairment of Other Current Assets 6,398 - -
Non-Cash Stock-Based Compensation 7,955 3,876 6,107
Write-off of Debt Issuance Costs - - 95
Loss on the Extinguishment of Debt 23,187 173,430 993
Debt Exchange Derivative (Gain) Loss (1,390) 598 -
Contingent Consideration Loss 29,512 28,968 -
Financing Expense 1,447 884 -
Cash Severance Expense 759 - -
Unrealized (Gain) Loss on Derivatives 173,214 (207,892) 18,443
Adjusted EBITDA 454,193 349,283 144,661
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 derivative contracts. Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position. OnJuly 1, 2019 , we closed on the VEN Bakken Acquisition, for which we paid total estimated consideration consisting of$175.5 million in cash, 5,602,147 shares of common stock and$130.0 million in principal amount of a newly issued 6.0% Senior Unsecured Promissory Note due 2022 (the "Unsecured VEN Bakken Note"). InNovember 2019 , we completed a series of refinancing transactions to improve liquidity, reduce fixed charges and strengthen our balance sheet. The primary components of these transactions included the following: •We amended and restated our Revolving Credit Facility, with various changes including an increase in the borrowing base from$425.0 million to$800.0 million . •We completed a cash tender offer to redeem and repay$200.0 million in principal amount of our 8.500% senior secured second lien notes due 2023 (the "Second Lien Notes"), funded with borrowings under our Revolving Credit Facility and cash proceeds from the issuance of shares of our new 6.500% Series A Perpetual Cumulative Convertible Preferred Stock (the "Series A Preferred Stock"). •We redeemed and repaid an additional$70.8 million in principal amount of Second Lien Notes in exchange for the issuance of additional shares of Series A Preferred Stock. •We completed a consent solicitation to amend certain terms of our Second Lien Notes, including, among various other changes, to (a) allow for the expansion of the Revolving Credit Facility by increasing the Company's debt capacity under the debt covenant, (b) remove certain restrictive covenants, and (c) provide for a customary restricted payments builder basket and other mechanics to facilitate our allocation of capital. 54
-------------------------------------------------------------------------------- Tab le of Contents As ofDecember 31, 2019 , we had (i) long-term debt consisting of$580.0 million of borrowings under our Revolving Credit Facility,$417.7 million aggregate principal amount of Second Lien Notes and$130.0 million aggregate principal amount under the Unsecured VEN Bakken Note, and (ii)$236.1 million in liquidity, consisting of$220.0 million of borrowing base availability under our Revolving Credit Facility and$16.1 million of cash on hand. Subsequent to the end of 2019, inJanuary 2020 , we further strengthened our balance sheet by entering into several separately negotiated agreements whereby, in the aggregate, we repurchased and retired$76.7 million in principal amount of Second Lien Notes in exchange for aggregate consideration to the holders consisting of$2.5 million in cash and 794,702 newly-issued shares of Series A Preferred Stock having an aggregate liquidation preference of$79.5 million . One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 80% and 84% of our total production volumes in 2019 and 2018, 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 2019 and 2018, we hedged approximately 76% and 64% of our crude oil production, respectively. For a summary as ofDecember 31, 2019 , 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 drilling in theWilliston Basin and to fund acquisitions of acreage and oil and 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, 2019 , we had a working capital deficit of$70.4 million , compared to a deficit of$3.1 million atDecember 31, 2018 . Current assets decreased by$95.4 million and current liabilities decreased by$28.0 million atDecember 31, 2019 , compared toDecember 31, 2018 . The decrease in current assets in 2019 as compared to 2018 is primarily due to a decrease of$110.2 million in our derivative instruments, due to the change in fair value as a result of oil price projections, which was partially offset by an$11.9 million increase in accounts receivable primarily due to our increased production levels and a cash balance of$13.7 million . The change in current liabilities in 2019 as compared to 2018 is primarily due to a$58.1 million reduction in contingent consideration liabilities incurred in connection with our Pivotal and W Energy Acquisitions (see Notes 3 and 11 to our financial statements), and an$18.2 million reduction in our debt exchange derivative liabilities (see Notes 4 and 11 to our financial statements). The foregoing was partially offset by an increase of$41.5 million in accounts payable and accrued expenses primarily as a result of increased development activity and an$11.3 million increase in derivative instruments as a result of forward oil prices changes.
Cash Flows
Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts. Our cash flows from operations also are impacted by changes in working capital. Any payments due to counterparties under our derivative contracts are generally funded by proceeds received from the sale of our production. Production receipts, however, lag payments to the counterparties. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. As ofDecember 31, 2019 , we had entered into derivative swap contracts hedging 9.8 million barrels of oil in 2020 at an average price of$57.98 per barrel, 6.2 million barrels of oil in 2021 at an average price of$55.78 per barrel and 1.4 million barrels of oil in 2022, at an average price per barrel of$52.57 , respectively. See "Item 7A. Quantitative and Qualitative Disclosures about Market Risk." 55
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Tab le of Contents Our cash flows for the years endedDecember 31, 2019 , 2018 and 2017 are presented below: Year Ended December 31, (In thousands) 2019 2018 2017
Net Cash Provided by Operating Activities
(119,240)
Net Cash Provided by Financing Activities 243,088 130,431
141,970 Net Change in Cash$ 13,710 $ (99,826) $ 95,697
Cash Flows from Operating Activities
Net cash provided by operating activities in 2019 was$339.7 million , compared to$244.3 million in 2018. This increase was due a 51% year-over-year increase in production levels and lower interest costs, partially offset by a 9% decrease in realized prices (including the effect of settled derivatives). 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, 2019 was a decrease of$37.5 million compared to a decrease of$25.7 million in 2018. The increase in net cash provided by operating activities in 2018 was caused by improving commodity prices and a 73% year-over-year increase in production levels, which was partially offset by a$26.7 million reduction in settled derivatives when compared to 2017.
Cash Flows from Investing Activities
We had cash flows used in investing activities of$569.1 million ,$474.5 million and$119.2 million during the years endedDecember 31, 2019 , 2018 and 2017, respectively, primarily as a result of our capital expenditures for drilling, development and acquisition costs. The year-over-year increase in cash used in investing activities in 2019 was attributable to higher development spending and our VEN Bakken acquisition. Additionally, the amount of capital expenditures included in accounts payable (and thus not included in cash flows from investing activities) was$161.7 million and$129.5 million atDecember 31, 2019 and 2018, respectively, as a result of increased activity in theWilliston Basin . The year-over-year increase in cash used in investing activities in 2018 was attributable to higher development spending and acquisitions, in particular ourSalt Creek , Pivotal and W Energy acquisitions when compared to 2017. During 2019, 2018 and 2017 we added 43.0 (excluding already producing wells from acquisitions), 31.2 and 16.9 net wells to production, respectively. 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, 2019 , our capitalized costs incurred, excluding non-cash consideration, assumed derivative liabilities, and the issuance of the Unsecured VEN Bakken Note from our VEN Bakken Acquisition, for oil and natural gas properties (e.g. drilling and completion costs, acquisitions, and other capital expenditures) amounted to$603.9 million , while the actual cash spend in this regard amounted to$568.0 million . Development and acquisition activities are discretionary. We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the years endedDecember 31, 2019 , 2018 and 2017 are summarized in the following table: Year Ended December 31, (In millions) 2019 2018 2017
Drilling and Development Capital Expenditures
14.4 Other Capital Expenditures 1.3 0.7 0.8 Total$ 567.8 $ 474.5 $ 119.4 56
-------------------------------------------------------------------------------- Tab le of Contents Cash Flows from Financing Activities Net cash provided by financing activities was$243.1 million ,$130.4 million and$142.0 million for the years endedDecember 31, 2019 , 2018 and 2017, respectively. The cash provided by financing activities in 2019 was primarily related to net increase in borrowings of$440.0 million and$70.9 million for issuance of preferred stock (See Note 5 to our financial statements) which was partially offset by repayments of our Second Lien Notes of$227.5 million in connection with ourNovember 2019 refinancing transaction (See Note 4 to our financial statements). Additionally, we repurchased$15.1 million of common stock and spent$12.2 million in fees in connection with debt financing transactions in 2019. The cash provided by financing activities in 2018 was primarily related to$141.7 million in equity offerings, as well as a net increase in borrowings of$40.0 million during 2018. Additionally, we repurchased$22.2 million of common stock and spent$26.6 million in fees in connection with debt financing transactions in 2018. The cash provided by financing activities in 2017 was primarily related to a net increase in borrowings of$156.0 million which was partially offset by$13.4 million in fees in connection with debt financing transactions in 2017.
Revolving Credit Facility
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, 2019 , the Revolving Credit Facility had a borrowing base of$800.0 million and we had$580.0 million of borrowings outstanding under the facility, leaving$220.0 million in available borrowing capacity. See Note 4 to our financial statements for further details regarding the Revolving Credit Facility.
Second Lien Notes due 2023
As ofDecember 31, 2019 , we had$417.7 million in outstanding principal amount of our 8.500% senior secured second lien notes due 2023 (the "Second Lien Notes"). See Note 4 to our financial statements for further details regarding the Second Lien Notes. Unsecured VEN Bakken Note As ofDecember 31, 2019 , we had$130.0 million in outstanding principal amount under the Unsecured VEN Bakken Note. See Note 4 to our financial statements for further details regarding the Unsecured VEN Bakken Note.
Series A Preferred Stock
As ofDecember 31, 2019 , we had 1.5 million outstanding shares of 6.500% Series A Perpetual Cumulative Convertible Preferred Stock (the "Series A Preferred Stock"), having an aggregate liquidation preference of$150.0 million . See Note 5 to our financial statements for further details regarding the Series A Preferred Stock.
2020 Capital Expenditure Budget
Our board of directors has approved a capital expenditure budget for calendar
year 2020. 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."
57-------------------------------------------------------------------------------- Tab le of Contents 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 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 atDecember 31, 2019 to make future payments under certain contracts, aggregated by category of contractual obligation, for specified time periods: Payment due by Period (In thousands) Less than More than Contractual Obligations 1 year 1-3 years 3-5 years 5 years Total Office Leases(1)$ 361 $ 340 $ - $ -$ 701 Long Term Debt(2) - 547,733 580,000 - 1,127,733 Cash Interest Expense on Debt(3) 68,128 130,406 60,304 - 258,838 Total$ 68,489 $ 678,479 $ 640,304 $ -$ 1,387,272 _______________________ (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 gas properties, as we cannot determine with accuracy the amount and/or timing of such payments. 58 -------------------------------------------------------------------------------- Tab le of Contents 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 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, debt derivative exchange liabilities, and contingent consideration liabilities 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 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 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 theSEC . 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 independent petroleum engineers,Cawley, Gillespie & Associates, Inc. , evaluated 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as ofDecember 31, 2019 .
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
59
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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 ended December 31, 2019 , our average depletion
expense per unit of production was $14.84 per Boe. A 10% decrease in our
estimated net proved reserves at December 31, 2019 would result in a $2.28 per
Boe increase in our 12-month per unit depletion rate.
To the extent the capitalized costs in our full cost pool (net of depreciation,
depletion and amortization and related deferred taxes) exceed the sum of the
present value (using a 10% discount rate and based on 12-month/SEC oil and
natural gas prices) of the estimated future net cash flows from our proved oil
and natural gas reserves and the capitalized cost associated with our unproved
properties, we would have a capitalized ceiling impairment. 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, 2019 , we performed an impairment review using prices that reflect an average of 2019's monthly prices as prescribed pursuant to theSEC's guidelines. For the years endedDecember 31, 2019 , 2018 and 2017, 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.
Revenue Recognition
We recognize revenue in accordance with FASB ASC Topic 606 - Revenue from Contracts with Customers, which we adopted effectiveJanuary 1, 2018 using the modified retrospective approach. Refer to the "Significant Accounting Policies" footnote in the notes to the financial statements for more information on our adoption of this new accounting standard. We derive revenue primarily from the sale of the crude oil and natural gas from our interests in producing wells. Revenue is recognized when we meet our performance obligation to deliver the product and control is transferred to the customer. We receive payment for product sales from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the amount of production delivered and the price we will receive can be reasonably estimated and amounts due from customers are accrued in accounts receivable trade, net in the balance sheets. Variances between our estimated revenue and actual payments are recorded in the month the payment is received. However, differences have been and are insignificant. As ofDecember 31, 2019 , our natural gas production was in balance, meaning our cumulative portion of natural gas production taken and sold from wells in which we have an interest equaled our entitled interest in natural gas production from those wells. 60
-------------------------------------------------------------------------------- Tab le of Contents 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 on 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.
Income Taxes
As of
As part of the process of preparing the financial statements, we are required to estimate the federal and state income taxes in each of the jurisdictions in which we operate. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items such as derivative instruments, depletion, depreciation and amortization, and certain accrued liabilities for tax and financial accounting purposes. These differences and our net operating loss carry-forwards result in deferred tax assets and liabilities, which are included in our balance sheet. We must then assess, using all available negative and positive evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. If we believe that recovery is not likely, we must establish a valuation allowance. Generally, to the extent we establish a valuation allowance or increase or decrease this allowance in a period, we must include an expense or reduction of expense within the tax provision in the statement of operations. Under accounting guidance for income taxes, an enterprise must use judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence should be commensurate with the extent to which it can be objectively verified. The more negative evidence that exists (i) the more positive evidence is necessary and (ii) the more difficult it is to support a conclusion that a valuation allowance is not needed for all or a portion of the deferred tax asset. Among the more significant types of evidence that we consider are: •our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition;
•the ability to recover our net operating loss carry-forward deferred tax assets in future years;
•the existence of significant proved oil and natural gas reserves;
•our ability to use tax planning strategies, such as electing to capitalize intangible drilling costs as opposed to expensing such costs;
•current price protection utilizing oil and natural gas hedges;
•current market prices for oil, NGL and natural gas; and
•future revenue and operating cost projections that indicate we will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures.
During 2019, in evaluating whether it was more-likely-than-not that our deferred
tax asset was recoverable from future net income, we considered all positive and
negative evidence available. We will continue to assess the need for a valuation
allowance against deferred tax assets considering all available evidence
obtained in future reporting periods. See Note 10 to our financial statements
for additional discussion of our income taxes.
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On December 22, 2017 , the United States enacted the Act which made significant
changes that affect the Company. The Act is a comprehensive tax reform bill
containing a number of other provisions that either currently or in the future
could impact the Company. The Company has completed the analysis of the Act and
does not expect a material change due to the transition impacts. Any changes
that do arise due to changes in interpretations of the Act, legislative action
to address questions that arise because of the Act, changes in accounting
standards for income taxes or related interpretations in response to the Act, or
any updates or changes to estimates the Company has utilized to calculate the
transition impacts will be disclosed in future periods as they arise. The effect
of certain limitations effective for the tax year 2018 and forward, specifically
related to the deductibility of executive compensation and interest expense,
have been evaluated.
Asset Retirement Obligations ("ARO")
We record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and natural gas properties, this is the period in which the well is drilled or acquired. For midstream service assets, this is the period in which the asset is placed in service. The ARO represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and for oil and natural gas properties the capitalized cost is depreciated on the unit of production method or for midstream service assets depreciated over its useful life. The accretion expense is recorded in the line item "Accretion of asset retirement obligations" in our statement of operations. We determine the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Included in the fair value calculation are assumptions and judgments including the ultimate costs, inflation factors, credit-adjusted risk-free discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Business Combinations
We account for business combinations using the acquisition method, which is the only method permitted under FASB ASC Topic 805 - Business Combinations, and involves the use of significant judgment.
Under the acquisition method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess, if any, of the consideration given to acquire an entity over the net amounts assigned to its assets acquired and liabilities assumed is recognized as goodwill. The excess, if any, of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity is recognized immediately to earnings as a gain from bargain purchase. Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the assets and liabilities acquired do not have fair values that are readily determinable. Different techniques may be used to determine fair values, including market prices (where available), appraisals, comparisons to transactions for similar assets and liabilities, and present values of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available. The business combinations completed during the prior three years consisted of crude oil and natural gas properties. In general, the consideration we have paid to acquire these properties was entirely allocated to the fair value of the assets acquired and liabilities assumed at the time of acquisition and consequently, there was no goodwill nor any bargain purchase gains recognized on our business combinations.
Recently Issued or Adopted Accounting Pronouncements
For discussion of recently issued or adopted accounting pronouncements, see Notes to Financial Statements-Note 2. Significant Accounting Policies.
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Off-Balance Sheet Arrangements
We currently do not have any off-balance sheet arrangements that have or are
reasonably likely to have a current or future effect on our financial condition,
changes in financial condition, revenues or expenses, results of operations,
liquidity, capital expenditures or capital resources that is material to
investors.
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