NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2019
NOTE 1 ORGANIZATION AND NATURE OF BUSINESS
Northern Oil and Gas, Inc. (the “Company,” “Northern,” “our” and words of similar import), a Delaware corporation, is an independent energy company engaged in the acquisition, exploration, exploitation, development and production of crude oil and natural gas properties. The Company’s common stock trades on the NYSE American market under the symbol “NOG”.
Northern’s principal business is crude oil and natural gas exploration, development, and production with operations that primarily target the Bakken and Three Forks formations in the Williston Basin of the United States. The Company acquires leasehold interests that comprise of non-operated working interests in wells and in drilling projects within its area of operations.
NOTE 2 SIGNIFICANT ACCOUNTING POLICIES
These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In connection with preparing the financial statements for the year ended December 31, 2019, the Company has evaluated subsequent events for potential recognition and disclosure through the date of this filing and determined that there were no subsequent events which required recognition or disclosure in the financial statements through the date of this filing.
Use of Estimates
The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect the 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.
The most significant estimates relate to proved crude oil and natural gas reserves, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of derivative instruments, fair value of contingent consideration, acquisition date fair values of assets acquired and liabilities assumed, impairment of oil and natural gas properties, asset retirement obligations and deferred income taxes. Actual results may differ from those estimates.
Reclassifications
Certain prior period balances in the balance sheets have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net income (loss), cash flows or stockholders’ equity (deficit) previously reported.
Correction of Presentation
Subsequent to the issuance of the Company’s financial statements as of and for the period ended December 31, 2018, the Company identified an immaterial error in the supplemental footnote disclosure of non-cash investing activities in which a “Change in Prepaid Expenses and Other” was improperly included in the amount of $29.4 million. Accordingly, within the “Supplemental Cash Flow Information” section included in this Note 2 below, the Company has removed the line item previously reported as the amount of “Change in Prepaid Expenses and Other.” The error did not impact the Statement of Cash Flows.
Cash and Cash Equivalents
Northern considers highly liquid investments with insignificant interest rate risk and original maturities to the Company of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts. The Company’s cash positions represent assets held in checking and money market accounts. Cash and cash equivalents are generally available on a daily or weekly basis and are highly liquid in nature. Due to the balances being greater than $250,000, the Company does not have FDIC coverage on the entire amount of bank deposits. The Company believes this risk is minimal. In addition, the Company is subject to Security Investor Protection Corporation (“SIPC”) protection on a vast majority of its financial assets.
Accounts Receivable
Accounts receivable are carried on a gross basis, with no discounting. The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual balances. Accounts receivable not expected to be collected within the next twelve months are included within Other Noncurrent Assets, Net on the balance sheets.
As of December 31, 2019 and 2018, the allowance for doubtful accounts was $4.6 million and $5.2 million, respectively. The amount charged to operations for doubtful accounts was zero, zero and $0.7 million for the years ended December 31, 2019, 2018 and 2017, respectively. As of December 31, 2019 and 2018, the amount charged against the allowance for doubtful accounts was $0.7 million and $0.3 million, respectively.
As of December 31, 2019 and 2018, the Company included accounts receivable of $4.7 million and $5.1 million, respectively, in Other Noncurrent Assets, Net due to their long-term nature.
Advances to Operators
The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid.
Other Property and Equipment
Property and equipment that are not crude oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than crude oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-crude oil and natural gas long-lived assets.
Oil and Gas Properties
Northern follows the full cost method of accounting for crude oil and natural gas operations whereby all costs related to the exploration and development of crude oil and natural gas properties are capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the years ended December 31, 2019, 2018 and 2017, respectively:
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December 31,
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(In thousands)
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2019
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2018
|
|
2017
|
|
Capitalized Certain Payroll and Other Internal Costs
|
$
|
995
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|
|
$
|
882
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|
|
$
|
930
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|
|
Capitalized Interest Costs
|
644
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|
|
147
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|
|
148
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Total
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$
|
1,638
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|
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$
|
1,029
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|
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$
|
1,078
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As of December 31, 2019, the Company held leasehold interests in the Williston Basin of the United States on acreage targeting the Bakken and Three Forks formations.
Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool. In the years ended December 31, 2019, 2018 and 2017, there were no property sales that resulted in a significant alteration.
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. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing twelve-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives designated as hedges for accounting purposes, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required.
The Company did not have any ceiling test impairment for the years ended December 31, 2019, 2018 and 2017. Impairment charges affect the Company’s reported net income but do not reduce the Company’s cash flow.
The Company computes the provision for depletion of oil and natural gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unproved costs and related carrying costs are excluded from the depletion base until the properties associated with these costs are considered proved. The following table presents depletion and depletion per BOE sold of the Company’s proved oil and natural gas properties for the periods presented:
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Year Ended December 31,
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(In thousands)
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2019
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2018
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2017
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Depletion of Proved Oil and Natural Gas Properties
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$
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209,050
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$
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118,974
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$
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58,801
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Depletion per BOE Sold
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$
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14.84
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|
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$
|
12.75
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|
|
$
|
10.89
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|
The Company believes that the majority of its unproved costs will become subject to depletion within the next five years by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of its reserves.
Capitalized costs associated with impaired unproved properties and capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs, are depleted and amortized on the unit-of-production method. Under this method, depletion is calculated at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the period. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion and full cost ceiling calculations. For the years ended December 31, 2019, 2018 and 2017, the Company expired leases of $3.6 million, $9.4 million, and $18.7 million, respectively.
Asset Retirement Obligations
The Company accounts for its abandonment and restoration liabilities under Financial Accounting Standards Board (“FASB”) ASC Topic 410, “Asset Retirement and Environmental Obligations” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset upon initial recognition. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.
Business Combinations
The Company accounts for its acquisitions that qualify as a business using the acquisition method under FASB ASC Topic 805, “Business Combinations.” Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain.
Financial Instruments
The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, commodity derivative assets and liabilities, contingent consideration, debt exchange derivative liability, and long-term debt. The carrying amounts of cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the Company’s derivative instruments assets and liabilities are based on a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil price curves, discount rates, volatility factors and credit risk adjustments. The fair values of the Company’s contingent consideration and debt exchange derivative liabilities are determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as (i) the Company’s common stock price, (ii) risk-free rates based on U.S. Treasury rates, (iii) volatility of the Company’s common stock, and (iv) expected average daily trading volumes.
The carrying amount of long-term debt associated with borrowings outstanding under the Company’s Revolving Credit Facility approximates fair value as borrowings bear interest at variable rates. The carrying amounts of the Company’s Second Lien Notes may not approximate fair value because carrying amounts are net of unamortized premiums and debt issuance costs, and the Second Lien Notes bear interest at fixed rates. See Note 11 for additional discussion.
Debt Issuance Costs
Debt issuance costs related to the Company’s Second Lien Notes and Unsecured VEN Bakken Note (see Note 4 below) are included as a deduction from the carrying amount of long-term debt in the balance sheets and are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the Revolving Credit Facility are included in other noncurrent assets and are amortized to interest expense on a straight-line basis over the term of the agreement.
Debt Premiums and Discounts
Debt discounts and premiums related to the Company’s Second Lien Notes and Unsecured VEN Bakken Note are included as a deduction from or addition to the carrying amount of the long-term debt in the balance sheets and are amortized to interest expense using the effective interest method over the term of the related notes.
Revenue Recognition
The Company adopted ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) and the series of related accounting standard updates that followed, on January 1, 2018 using the modified retrospective method of adoption. Adoption of the ASU did not require an adjustment to the opening balance of equity and did not change the Company’s amount and timing of revenues.
The Company’s revenues are primarily derived from its interests in the sale of oil and natural gas production. The Company recognizes revenue from its interests in the sales of oil and natural gas in the period that its performance obligations are satisfied. Performance obligations are satisfied when the customer obtains control of product, when the Company has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The sales of oil and natural gas are made under contracts which the third-party operators of the wells have negotiated with customers, which typically include variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. The Company receives payment from the sale of oil and natural gas production from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in trade receivables, net in the balance sheets. Variances
between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, however, differences have been and are insignificant. Accordingly, the variable consideration is not constrained.
The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.
The Company’s oil is typically sold at delivery points under contracts terms that are common in our industry. The Company’s natural gas produced is delivered by the well operators to various purchasers at agreed upon delivery points under a limited number of contract types that are also common in our industry. Regardless of the contract type, the terms of these contracts compensate the well operators for the value of the oil and natural gas at specified prices, and then the well operators will remit payment to the Company for its share in the value of the oil and natural gas sold.
A wellhead imbalance liability equal to the Company’s share is recorded to the extent that the Company’s well operators have sold volumes in excess of its share of remaining reserves in an underlying property. However, for the years ended December 31, 2019, 2018 and 2017, the Company’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in natural gas production from those wells.
The Company’s disaggregated revenue has two revenue sources, which are oil sales and natural gas and NGL sales, and the Company only operates in one geographic area, the Williston Basin in the United States, primarily in North Dakota and Montana. Oil sales for the years ended December 31, 2019, 2018 and 2017 were $574.6 million, $450.1 million and $204.6 million, respectively. Natural gas and NGL sales for the years ended December 31, 2019, 2018 and 2017 were $26.6 million, $43.8 million and $19.4 million, respectively.
Concentrations of Market and Credit Risk
The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas. The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.
The Company operates in the exploration, development and production sector of the crude oil and natural gas industry. The Company’s receivables include amounts due, indirectly via the third-party operators of the wells, from purchasers of its crude oil and natural gas production. While certain of these customers, as well as third-party operators of the wells, are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations have been immaterial.
The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its counterparties is generally high. In the normal course of business, letters of credit or parent guarantees may be required for counterparties which management perceives to have a higher credit risk.
Stock-Based Compensation
The Company records expense associated with the fair value of stock-based compensation. For fully vested stock and restricted stock grants, the Company calculates the stock-based compensation expense based upon estimated fair value on the date of grant. In determining the fair value of performance-based share awards subject to market conditions, the Company utilizes a Monte Carlo simulation prepared by an independent third party. For stock options, the Company uses the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant. Option pricing models require the input of highly
subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate.
Treasury Stock
Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result of share repurchases under the share repurchase program or from the withholding of shares of stock to satisfy employee tax withholding obligations that arise upon the lapse of restrictions on their stock-based awards at the employees’ election.
Stock Issuance
The Company records any stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable.
Income Taxes
The Company’s income tax expense, deferred tax assets and deferred tax liabilities reflect management’s best assessment of estimated current and future taxes to be paid. The Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing for income taxes on a current year-to-date basis. The Company’s only taxing jurisdiction is the United States (federal and state).
Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements, which will result in taxable or deductible amounts in the future. In evaluating the Company’s ability to recover its deferred tax assets, the Company considers all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. In projecting future taxable income, the Company begins with historical results and incorporates assumptions about the amount of future state and federal pretax operating income adjusted for items that do not have tax consequences. The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates the Company is using to manage the underlying businesses.
Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. In assessing the need for a valuation allowance for the Company’s deferred tax assets, a significant item of negative evidence considered was the current year book loss and cumulative book losses in recent years, driven primarily by the full cost ceiling impairments over that period. Additionally, the Company’s revenue, profitability and future growth are substantially dependent upon prevailing and future prices for oil and natural gas. The markets for these commodities continue to be volatile. Changes in oil and natural gas prices have a significant impact on the value of the Company’s reserves and on its cash flows. Due to these factors, management has placed a lower weight on the prospect of future earnings in its overall analysis of the valuation allowance. Accordingly, the valuation allowance against the Company’s deferred tax asset at December 31, 2019 and 2018 was $144.2 million and $123.7 million respectively.
Derivative Instruments and Price Risk Management
The Company uses derivative instruments to manage market risks resulting from fluctuations in the prices of crude oil. The Company enters 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 crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. The Company may also use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date.
The Company follows the provisions of FASB ASC 815, “Derivatives and Hedging” as amended. It requires that all derivative instruments be recognized as assets or liabilities on the balance sheet, measured at fair value and 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. See Note 12 for a description of the derivative contracts into which the Company has entered.
Impairment
Long-lived assets to be held and used are required to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Proved oil and natural gas properties accounted for using the full cost method of accounting are excluded from this requirement but continue to be subject to the full cost method’s impairment rules. There was no impairment of other long-lived assets recorded for the years ended December 31, 2019, 2018 and 2017.
Employee Benefit Plans
The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at the date of hire. The plan allows eligible employees to make pre-tax contributions up to 100% of their annual compensation, not to exceed annual limits established by the federal government. Employees are 100% vested in the employer contributions upon receipt.
Net Income (Loss) Per Common Share
Basic earnings per share (“EPS”) are computed by dividing net income (loss) available to common stockholders (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income (loss) by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include shares issuable upon exercise of stock options and vesting of restricted stock awards, and shares issuable upon conversion of the Series A Preferred Stock (see Note 5). The number of potential common shares outstanding are calculated using treasury stock or if-converted method.
Supplemental Cash Flow Information
The following reflects the Company’s supplemental cash flow information for the years ended December 31, 2019, 2018 and 2017 :
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December 31,
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(In thousands)
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2019
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2018
|
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2017
|
|
Supplemental Cash Items:
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Cash Paid During the Period for Interest
|
$
|
78,596
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$
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78,865
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$
|
65,566
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Non-cash Operating Activities:
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|
|
|
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Contingent Consideration Settlements in Excess of Acquisition-date Liabilities
|
21,349
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|
|
|
—
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|
|
|
—
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Non-cash Investing Activities:
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Oil and Natural Gas Properties Included in Accounts Payable and Accrued Liabilities
|
161,743
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|
129,452
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|
|
85,002
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Capitalized Asset Retirement Obligations
|
4,042
|
|
|
2,854
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|
|
1,188
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|
|
Contingent Consideration
|
—
|
|
|
32,312
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|
|
—
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|
|
Compensation Capitalized on Oil and Gas Properties
|
412
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|
|
369
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|
|
275
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Issuance of Common Stock - Acquisitions of Oil and Natural Gas Properties
|
11,708
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|
—
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|
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—
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Issuance of Unsecured VEN Bakken Note
|
128,660
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|
—
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—
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Non-cash Financing Activities:
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Issuance of 8.50% Second Lien Notes due 2023
|
—
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|
|
344,279
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|
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—
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Issuance of Common Stock - fair value at issuance date
|
—
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326,783
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—
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Issuance of Preferred Stock in Exchange for 8.5% Second Lien Notes due 2023
|
75,000
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|
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—
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|
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—
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Debt Exchange Derivative Liability - fair value at issuance date
|
—
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|
|
19,354
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|
|
—
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Issuance of 8.50% Second Lien Notes due 2023 - PIK Interest
|
3,480
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|
|
|
—
|
|
|
|
—
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|
|
Debt Exchange Derivative Liability Settlements
|
15,749
|
|
|
|
—
|
|
|
|
—
|
|
|
Contingent Considerations Settlements
|
17,822
|
|
|
|
—
|
|
|
|
—
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|
|
8.00% Unsecured Senior Notes due 2020 - carrying value
|
—
|
|
|
(590,041)
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|
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—
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|
New Accounting Pronouncements
From time to time, new accounting pronouncements are issued by the FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.
In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”). The objective of this ASU is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. FASB subsequently issued various ASUs which provided additional implementation guidance, and these ASUs collectively make up FASB ASC Topic 842 – Leases (“ASC 842”). ASC 842 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The standard permits retrospective application through recognition of a cumulative-effect adjustment at the beginning of either the earliest reporting period presented or the period of adoption. ASC 842 does not apply to leases used in the exploration or use of minerals, oil, natural gas, or other similar non-regenerative resources. The Company adopted ASC 842 effective January 1, 2019 using the modified retrospective method as of the adoption date. The Company has completed the assessment of its existing accounting policies and enhancement of its internal controls. The standard did not have a material impact on the Company’s condensed balance sheets, statement of operations or cash flows.
In June 2016 FASB issued ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company is finalizing its evaluation of the new standard and does not expect it to have a material impact on its financial statements.
In August 2018, the FASB issued new guidance in ASC 820, Fair Value Measurement, to modify disclosure requirements. The amendments in this ASU remove, modify, and add certain disclosure requirements as a part of the disclosure framework project, which primarily focus on improving the effectiveness of disclosures in the notes to the financial statements. The guidance is effective for annual periods beginning after December 31, 2019, and interim periods within those annual periods. The Company is currently assessing the impact of the guidance, however it does not expect any impact of this new guidance on its financial statements to be material.
In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which simplifies the accounting for income taxes by removing certain exceptions to the general principles and also simplification of areas such as separate entity financial statements and interim recognition of enactment of tax laws or rate changes. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, including interim reporting periods within those years. The Company is currently evaluating the effect of ASU 2019-12, but does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or result of operations.
NOTE 3 CRUDE OIL AND NATURAL GAS PROPERTIES
The book value of the Company’s crude oil and natural gas properties consists of all acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying statements of operations from the closing date of the acquisition. Acquired assets and liabilities assumed are recorded based on their estimated fair value at the time of the acquisition. Acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. Development capital expenditures and purchases of properties that were in accounts payable and not yet paid in cash at December 31, 2019 and 2018 were approximately $161.7 million and $129.5 million, respectively.
2019 Acquisitions
During 2019, excluding the VEN Bakken Acquisition described below, the Company acquired oil and natural gas properties through a number of independent transactions for a total of $53.4 million. This amount includes $22.6 million of development costs that occurred prior to the closings of the acquisitions.
VEN Bakken Acquisition
On July 1, 2019, the Company completed its acquisition (the “VEN Bakken Acquisition”) of certain oil and gas properties and interests from VEN Bakken, LLC (“VEN Bakken”), effective as of July 1, 2019. VEN Bakken is a wholly-owned subsidiary of Flywheel Bakken, LLC. At closing the acquired assets consisted of approximately 90.1 net producing wells and 3.3 net wells in process, as well as approximately 18,000 net acres substantially all in North Dakota. The Company also assumed certain crude oil derivative contracts from VEN Bakken as part of the acquisition. The VEN Bakken Acquisition was completed pursuant to the purchase and sale agreement between the Company and VEN Bakken, dated as of April 18, 2019.
The total estimated consideration paid by the Company was $315.9 million, consisting of (i) $175.5 million in cash, (ii) 5,602,147 shares of Company common stock valued at $11.7 million, based on the $2.09 per share closing price of Company common stock on the closing date of the acquisition and (iii) $128.7 million of value attributable to a 6.0% unsecured promissory note due July 1, 2022 issued by the Company to VEN Bakken in the aggregate principal amount of $130.0 million (the “Unsecured VEN Bakken Note”). The results of operations from the July 1, 2019 closing date through December 31, 2019, represented approximately $54.1 million of revenue and $16.1 million of income from operations. The Company incurred $1.8 million of transactions costs in connection with the acquisition, which are included in general and administrative expense in the condensed statement of operations. The following table reflects the fair values of the net assets and liabilities as of the date of acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Fair value of net assets:
|
|
|
|
Proved oil and natural gas properties
|
|
$
|
325,572
|
|
|
Asset retirement cost
|
|
2,680
|
|
|
Total assets acquired
|
|
328,252
|
|
|
Asset retirement obligations
|
|
(2,680)
|
|
|
Derivative instruments
|
|
(9,694)
|
|
|
Net assets acquired
|
|
$
|
315,878
|
|
|
|
|
|
|
Fair value of consideration paid for net assets:
|
|
|
|
Cash consideration
|
|
$
|
175,510
|
|
|
Issuance of common stock (5.6 million shares at $2.09 per share)
|
|
11,708
|
|
|
Unsecured VEN Bakken Note
|
|
128,660
|
|
|
Total fair value of consideration transferred
|
|
$
|
315,878
|
|
Pro Forma Information
The following summarized unaudited pro forma statement of operations information for the years ended December 31, 2019 and 2018 assumes that the VEN Bakken Acquisition, W Energy Acquisition and Pivotal Acquisition each occurred as of January 1, 2018. The Company prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had the Company completed these acquisitions on the dates indicated, or that would be attained in the future.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
(In thousands)
|
|
2019
|
|
2018
|
|
Revenues
|
|
$
|
500,728
|
|
|
$
|
879,925
|
|
|
Net Income
|
|
$
|
(95,812)
|
|
|
$
|
144,279
|
|
2018 Acquisitions
During 2018, excluding the W Energy, Pivotal and Salt Creek acquisitions described in more detail below, the Company acquired leasehold interests covering approximately 10,932 net acres.
W Energy Acquisition
On July 27, 2018, the Company entered into a purchase and sale agreement, which was subsequently amended on September 25, 2018 (as amended, the “W Energy Purchase Agreement”), with WR Operating LLC (“W Energy”), to acquire, effective as of July 1, 2018, approximately 27.2 net producing wells and 5.9 net wells in progress, as well as approximately 10,633 net acres in North Dakota (the “W Energy Acquisition”). On October 1, 2018, the Company closed on the acquisition for total estimated consideration of $341.6 million, consisting of (i) $97.8 million in cash (which reflects the $117.1 million in cash consideration under the W Energy Purchase Agreement, less $2.2 million of working capital adjustments made at closing and $17.0 million of additional estimated post-closing working capital adjustments), (ii) 51,476,961 shares of Company common stock valued at $220.8 million, based on the $4.29 per share closing price of Company common stock on the closing date of the acquisition, and (iii) $23.0 million in value attributable to potential additional contingent consideration in the future (described in more detail below). No material transaction costs were incurred in connection with this acquisition. The following table reflects the fair values of the net assets and liabilities as of the date of acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Fair value of net assets:
|
|
|
|
Proved oil and natural gas properties
|
|
$
|
341,633
|
|
|
Asset retirement cost
|
|
939
|
|
|
Total assets acquired
|
|
342,572
|
|
|
Asset retirement obligations
|
|
(939)
|
|
|
Net assets acquired
|
|
$
|
341,633
|
|
|
Fair value of consideration paid for net assets:
|
|
|
|
Cash consideration
|
|
$
|
97,838
|
|
|
Issuance of common stock (51.5 million shares at $4.29 per share)
|
|
220,836
|
|
|
Contingent consideration
|
|
22,959
|
|
|
Total fair value of consideration transferred
|
|
$
|
341,633
|
|
A contingent consideration liability arising from potential additional consideration in connection with the W Energy Acquisition has been recognized at its fair value. The amount of additional contingent consideration payable by the Company, if any, was dependent upon the performance of the Company’s share price over a thirteen month period ending with October 2019. The acquisition date fair value of the potential additional consideration, totaling $23.0 million, was recorded within contingent consideration liabilities on the Company’s balance sheets. Changes in the fair value of the liability (that were not accounted for as revisions of the acquisition date fair value) were recorded in other income (expense) on the Company’s statement of operations. As of December 31, 2019, there was no remaining contingent consideration liability associated with the W Energy Acquisition.
Pivotal Acquisition
On July 17, 2018, the Company entered into purchase and sale agreements with Pivotal Williston Basin, LP and Pivotal Williston Basin II, LP, to acquire approximately 20.8 net producing wells and 2.2 net wells in process, as well as approximately 444 net acres in North Dakota (the “Pivotal Acquisition”). On September 17, 2018, the Company closed on the acquisition for total estimated consideration of $146.1 million, consisting of (i) $48.2 million in cash (which reflects the $68.4 million of aggregate cash consideration provided for in the purchase agreements, less $7.8 million of working capital adjustments made at closing and $12.4 million of additional estimated post-closing working capital adjustments), (ii) 25,753,578 shares of the Company’s common stock valued at $88.6 million, based on the $3.44 per share closing price of the Company’s common stock on the closing date of the acquisition, and (iii) $9.4 million in value attributable to potential additional contingent consideration (described in more detail below). No material transaction costs were incurred in connection with this acquisition. The following table reflects fair values of the net assets and liabilities as of the date of acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Fair value of net assets:
|
|
|
|
Proved oil and natural gas properties
|
|
$
|
146,134
|
|
|
Asset retirement cost
|
|
$
|
644
|
|
|
Total assets acquired
|
|
$
|
146,778
|
|
|
Asset retirement obligations
|
|
$
|
(644)
|
|
|
Net assets acquired
|
|
$
|
146,134
|
|
|
|
|
|
|
Fair value of consideration paid for net assets:
|
|
|
|
Cash consideration
|
|
$
|
48,189
|
|
|
Issuance of common stock (25.8 million shares at $3.44 per share)
|
|
$
|
88,592
|
|
|
Contingent consideration
|
|
$
|
9,353
|
|
|
Total fair value of consideration transferred
|
|
$
|
146,134
|
|
A contingent consideration liability arising from potential additional consideration in connection with the Pivotal Acquisition has been recognized at its fair value. The amount of additional contingent consideration payable by the Company, if any, was dependent upon the performance of the Company’s share price over a thirteen month period ending with October 2019. The acquisition date fair value of the potential additional consideration, totaling $9.4 million, was recorded within contingent consideration liabilities on the Company’s balance sheets. Changes in the fair value of the liability (that were not accounted for as revisions of the acquisition date fair value) were recorded in other income (expense) on the Company’s statement of operations. As of December 31, 2019, there was no remaining contingent consideration liability associated with the Pivotal Acquisition.
Salt Creek Acquisition
On April 25, 2018, the Company entered into a purchase and sale agreement with Salt Creek Oil and Gas, LLC, to acquire 64 gross, 5.5 net producing (PDP) wells, 31 gross, 1.5 net drilling and completing (PDNP) wells and 1,319 net acres located in McKenzie and Mountrail counties of North Dakota. On June 4, 2018, the Company closed the transaction for consideration of $60.0 million which is comprised of $44.7 million of cash consideration and $15.2 million of common stock consideration. No material transaction costs were incurred in connection with this acquisition. The following table reflects the fair values of the net assets and liabilities as of the date of acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Fair value of net assets:
|
|
|
|
Proved oil and natural gas properties
|
|
$
|
59,978
|
|
|
Asset retirement cost
|
|
154
|
|
|
Total assets acquired
|
|
60,132
|
|
|
Asset retirement obligations
|
|
(154)
|
|
|
Net assets acquired
|
|
$
|
59,978
|
|
|
Fair value of consideration paid for net assets:
|
|
|
|
Cash consideration
|
|
$
|
44,738
|
|
|
Issuance of common stock (6.0 million shares at $2.54 per share)
|
|
15,240
|
|
|
Total fair value of consideration transferred
|
|
$
|
59,978
|
|
Pro Forma Information
The following summarized unaudited pro forma statement of operations information for the years ended December 31, 2018 and 2017 assumes that the W Energy Acquisition and Pivotal Acquisition each occurred as of January 1, 2017. The Company prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had the Company completed these acquisitions on the dates indicated, or that would be attained in the future.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
(In thousands)
|
|
2018
|
|
2017
|
|
Revenues
|
|
$
|
797,847
|
|
|
$
|
294,862
|
|
|
Net Income
|
|
$
|
174,070
|
|
|
$
|
283
|
|
Divestitures
From time-to-time the Company may divest assets. In addition, the Company may trade leasehold interests with operators to balance working interests in spacing units to facilitate and encourage a more expedited development of the Company’s acreage.
Unproved Properties
Unproved properties not being amortized comprise approximately 16,464 net acres and 11,054 net acres of undeveloped leasehold interests at December 31, 2019 and 2018, respectively. The Company believes that the majority of its unproved costs will become subject to depletion within the next five years by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of its reserves.
Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years. The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion at December 31, 2019 by year incurred.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
(In thousands)
|
2019
|
|
2018
|
|
2017
|
|
Prior Years
|
|
Property Acquisition
|
$
|
6,594
|
|
|
$
|
3,497
|
|
|
$
|
75
|
|
|
$
|
881
|
|
|
Development
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
$
|
6,594
|
|
|
$
|
3,497
|
|
|
$
|
75
|
|
|
$
|
881
|
|
All properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion. Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion.
The Company historically has acquired unproved properties by purchasing individual or small groups of leases directly from mineral owners, landmen or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators. The Company generally participates in drilling activities on a heads up basis by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling.
The Company assesses all items classified as unproved property on an annual basis, or if certain circumstances exist, more frequently, for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and amortization.
NOTE 4 LONG-TERM DEBT
The Company’s long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
|
|
|
|
|
|
(In thousands)
|
Principal Balance
|
|
Unamortized Net Premium (Discount
|
|
Debt Issuance Costs, Net
|
|
Long-term Debt, Net
|
|
|
|
|
|
|
|
|
|
|
Second Lien Notes due 2023
|
$
|
417,733
|
|
|
$
|
6,031
|
|
|
$
|
(14,283)
|
|
|
$
|
409,482
|
|
|
Revolving Credit Facility (1)
|
580,000
|
|
|
—
|
|
|
—
|
|
|
580,000
|
|
|
Unsecured VEN Bakken Note
|
130,000
|
|
|
(1,172)
|
|
|
(149)
|
|
|
$
|
128,679
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
$
|
1,127,733
|
|
|
$
|
4,860
|
|
|
$
|
(14,432)
|
|
|
$
|
1,118,161
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
|
|
|
|
|
|
Principal Balance
|
|
Unamortized Net Premium
|
|
Debt Issuance Costs, Net
|
|
Long-term Debt, Net
|
|
Second Lien Notes due 2023
|
$
|
695,140
|
|
|
$
|
13,237
|
|
|
$
|
(18,174)
|
|
|
$
|
690,203
|
|
|
Revolving Credit Facility (1)
|
140,000
|
|
|
—
|
|
|
—
|
|
|
$
|
140,000
|
|
|
Total
|
$
|
835,140
|
|
|
$
|
13,237
|
|
|
$
|
(18,174)
|
|
|
$
|
830,203
|
|
_____________________
(1)Debt issuance costs related to the Company’s revolving credit facility of $9.8 million and $5.1 million as of December 31, 2019 and 2018, are recorded in “Other Noncurrent Assets, Net” on the balance sheets.
November 2019 Refinancing Transactions
During November 2019, the Company completed a series of refinancing transactions related to its debt arrangements, which are summarized as follows (with additional detail included below):
•Amended and restated the Company’s Revolving Credit Facility (defined below), with various changes including an increase in the borrowing base from $425.0 million to $800.0 million.
•Completed a cash tender offer to redeem and repay $200.0 million in principal amount of Second Lien Notes (defined below) for $212.0 million in cash, which was funded with borrowings under the Revolving Credit Facility and cash proceeds from the issuance of 750,000 shares of Series A Preferred Stock having an aggregate liquidation preference of $75.0 million (see Note 6 below).
•Redeemed and repaid $70.8 million of Second Lien Notes in exchange for the issuance of an additional 750,000 shares of Series A Preferred Stock having an aggregate liquidation preference of $75.0 million.
•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 the Company’s allocation of capital.
Revolving Credit Facility
On November 22, 2019, the Company entered into a Second Amended and Restated Credit Agreement (the “Revolving Credit Facility”) with Wells Fargo Bank, National Association, as administrative agent, and the lenders from time to time party thereto, which amended and restated the Company’s prior revolving credit facility that was entered into on October 5, 2018. The Revolving Credit Facility is scheduled to mature on November 22, 2024, provided that the maturity date shall be 91 days prior to the scheduled maturity date of the earlier of (i) the Second Lien Notes (defined below) if any Second Lien Notes remain outstanding on such date or (ii) the Unsecured VEN Bakken Note if any principal amount of the Unsecured VEN Bakken Note remains outstanding on such date.
The Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to the Company and its subsidiaries’ (if any) oil and gas properties. The borrowing base as of December 31, 2019 was $800.0 million. The borrowing base will be redetermined semiannually on or around April 1st and October 1st, with one interim “wildcard” redetermination available between scheduled redeterminations. The April 1st scheduled redetermination shall be based on a January 1st engineering report audited by a third party (reasonably acceptable by the Agent).
At the Company’s option, borrowings under the Revolving Credit Facility shall bear interest at the base rate or LIBOR plus an applicable margin. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points. The applicable margin for base rate loans ranges from 100 to 200 basis points, and the applicable margin for LIBOR loans ranges from 200 to 300 basis points, in each case depending on the percentage of the Borrowing Base utilized.
The Revolving Credit Facility contains negative covenants that limit the Company’s ability, among other things, to pay dividends, incur additional indebtedness, sell assets, enter into certain derivatives contracts, change the nature of its business or operations, merge, consolidate, or make certain types of investments. In addition, the Revolving Credit Facility requires that the Company comply with the following financial covenants: (i) as of the date of determination, the ratio of total net debt to EBITDAX (as defined in the Revolving Credit Facility) shall be no more than 3.50 to 1.00, measured on a pro forma rolling four quarter basis, and (ii) the current ratio (defined as consolidated current assets including unused amounts of the total commitments, but excluding non-cash assets under FASB ASC 815, divided by consolidated current liabilities excluding current non-cash obligations under FASB ASC 815 and current maturities under the Revolving Credit Facility, the Second Lien Notes and the Unsecured VEN Bakken Note) shall not be less than 1.00 to 1.00.
The Company’s obligations under the Revolving Credit Facility may be accelerated, subject to customary grace and cure periods, upon the occurrence of certain Events of Default (as defined in the Revolving Credit Facility). Such Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of us or the Company’s subsidiaries, defaults related to judgments and the occurrence of a Change in Control (as defined in the Revolving Credit Facility).
The Company’s obligations under the Revolving Credit Facility are secured by mortgages on not less than 85% of the value of proven reserves associated with the oil and gas properties included in the determination of the Borrowing Base. Additionally, the Company entered into a Guaranty and Collateral Agreement in favor of the Agent for the secured parties, pursuant to which the Company’s obligations under the Revolving Credit Facility are secured by a first priority security interest in substantially all of the Company’s assets.
Second Lien Notes due 2023
In May 2018, the Company issued 8.500% senior secured second lien notes due 2023 (the “Second Lien Notes”) with an aggregate principal amount of $344.3 million (the “Original 2L Notes”) in exchange for certain previously outstanding 8.000% senior unsecured notes due June 1, 2020 (the “Unsecured Notes”). In October 2018, the Company issued an additional $350.0 million aggregate principal amount of Second Lien Notes (the “Additional 2L Notes”), the proceeds of which were used in connection with the retirement of the Company’s prior term loan credit agreement with TPG Specialty Lending, Inc., as administrative agent, and the lenders from time to time party thereto (the “TPG Term Loan Facility”). In addition, as of and through December 31, 2019, the Company had issued another $4.3 million of additional aggregate principal amount of Second Lien Notes pursuant to the interest payment-in-kind provisions thereof.
In November 2019, the Company completed a cash tender offer to redeem and repay $200.0 million in principal amount of Second Lien Notes for $212.0 million in cash. Also in November 2019, the Company redeemed and repaid $70.8 million in principal amount of Second Lien Notes in exchange for shares of Series A Preferred Stock. In addition, during the year ended December 31, 2019, the Company repurchased and retired 10.1 million in aggregate principal amount of Second Lien Notes in open market transactions.
The terms of the Second Lien Notes include those stated in the Indenture entered into on May 15, 2018 by the Company and Wilmington Trust, National Association, as trustee (the “Original 2L Indenture”), as amended by the First Supplemental Indenture, dated September 18, 2018 (the “First Supplemental 2L Indenture”), the Second Supplemental Indenture, dated October 5, 2018 (the “Second Supplemental 2L Indenture”), and the Third Supplemental Indenture, dated November 22, 2019 (the “Third Supplemental 2L Indenture” and, together with the Original 2L Indenture, the First Supplemental 2L Indenture, and the Second Supplemental 2L Indenture, the “2L Indenture”).
The Second Lien Notes are the senior secured obligations of the Company and rank equal in right of payment to all existing and future senior indebtedness of the Company and its subsidiaries. The Second Lien Notes are secured by second priority security interests in substantially all assets of the Company, subject to certain exceptions. The Second Lien Notes will be guaranteed by all of the Company’s direct and indirect subsidiaries that guarantee indebtedness under any other indebtedness for borrowed money of the Company or any of the Company’s subsidiary guarantors. As of December 31, 2019, the Company did not have any subsidiaries. The Second Lien Notes will mature on May 15, 2023.
Interest on the Second Lien Notes accrues at a rate of 8.500% per annum payable in cash quarterly in arrears on the first day of each calendar quarter. Additional interest may accrue depending on the Company’s total debt to EBITDAX ratio as of each December 31st and June 30th, provided that any such additional interest would be payable in kind (the “PIK Interest”). No PIK Interest will accrue so long as the Company’s total debt to EBITDAX ratio remains below 2.50 to 1.00 as of each applicable measurement date. PIK Interest of 1.00% per annum will accrue if the Company’s total debt to EBITDAX ratio is less than 2.75 to 1.00 but equal to or greater than 2.50 to 1.00. PIK Interest of 2.00% per annum will accrue if the Company’s total debt to EBITDAX ratio is less than 3.00 to 1.00 but equal to or greater than 2.75 to 1.00. PIK Interest of 3.00% per annum will accrue if the Company’s total debt to EBITDAX ratio is greater than or equal to 3.00 to 1.00. Default interest will be payable in cash on demand at the then applicable interest rate plus 3.000% per annum.
The Company may redeem all or a portion of any of the Second Lien Notes at the following redemption prices during the following time periods (plus accrued and unpaid interest on the Second Lien Notes redeemed): (i) from and after May 15, 2018 until May 15, 2021, 104%, (ii) on and after May 15, 2021 until May 15, 2022, 102%, and (iii) on and after May 15, 2022, 100%; provided that any redemption of Second Lien Notes (or the acceleration of Second Lien Notes) prior to May 15, 2020 shall also be accompanied by a make whole premium. Subject to the terms of an intercreditor agreement, the Company is also required to offer to prepay the Second Lien Notes with 100% of the net cash proceeds of asset sales, casualty events and condemnations in excess of $20.0 million not required to be used to pay down the loans under the Revolving Credit Facility, subject to customary exclusions and reinvestment provisions. Mandatory prepayment offers will be subject to payment of the make whole premium and redemption price set forth above, as applicable.
If a change of control occurs, the Company will be required to offer to repurchase the Second Lien Notes at the repurchase price of 101% of the principal amount of repurchased Second Lien Notes (subject to the prepayment provisions of the Revolving Credit Facility). The Second Lien Notes contain negative covenants that limit the Company’s ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain derivatives contracts, change the nature of its business or operations, merge, consolidate, make certain types of investments, amend other debt documents, and incur any additional debt on a subordinated or junior basis to the Revolving Credit Facility and on a senior basis to the Second Lien Notes. The Second Lien Notes do not include any financial maintenance covenants.
The obligations of the Company under the Second Lien Notes may be accelerated upon the occurrence of an Event of Default (as such term is defined in the 2L Indenture). Events of Default include customary events for a capital markets debt financing of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of the Company or its subsidiaries, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as such term is defined in the 2L Indenture).
Unsecured VEN Bakken Note
On July 1, 2019, in connection with the completion of the VEN Bakken Acquisition, the Company issued the Unsecured VEN Bakken Note in the original principal amount of $130.0 million (see Note 3 above). Fifty percent (50%) of the original principal amount of the Unsecured VEN Bakken Note is required to be repaid by the Company on or before January 1, 2021, and the remaining unpaid principal amount is required to be repaid by the Company on or before July 1, 2022, in each case together with all accrued but unpaid interest thereon. Interest, at a rate of 6.0% per annum, is due quarterly in arrears on the first day of each calendar quarter, commencing on October 1, 2019. The Unsecured VEN Bakken Note does not include any financial maintenance covenants and is unsecured.
The obligations of the Company under the Unsecured VEN Bakken Note may be accelerated, subject to certain grace and cure periods, upon the occurrence of an event of default. Events of default include customary events, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of certain affirmative or negative covenants, defaults on other indebtedness of the Company, and bankruptcy or insolvency related defaults. The Unsecured VEN Bakken Note contains negative covenants that limit the Company’s ability, among other things, to pay dividends, repurchase equity, incur additional indebtedness, sell assets, terminate or unwind certain derivatives contracts, change the nature of its business or operations and merge or consolidate. In addition, the Unsecured VEN Bakken Note is subject to a mandatory prepayment offer in connection with a change of control.
Overview of 2018 Refinancing Transactions
During 2018, the Company completed various refinancing transactions related to its debt arrangements, which are summarized as follows:
•In May 2018, closed an exchange transaction (the “May 2018 Exchange”) whereby the Company issued $344.3 million of Second Lien Notes and 103.2 million shares of common stock in exchange for the redemption of $496.7 million in principal amount of the Company’s previously outstanding 8.000% senior unsecured notes due 2020 (the “Unsecured Notes”).
•During the second and third quarters of 2018, closed ten additional independent, separately negotiated exchange agreements with holders of the Company’s Unsecured Notes (the “Additional 2018 Exchanges”), whereby the Company issued shares of common stock in exchange for the redemption of $100.5 million in total principal amount of Unsecured Notes.
•In October 2018, (i) entered into the Revolving Credit Facility (which was subsequently amended and restated in November 2019), (ii) issued an additional $350.0 million aggregate principal amount of Second Lien Notes, (iii) repaid all $360.0 million in loans under, and retired in full, the Company’s prior TPG Term Loan Facility, and (iv) redeemed and repaid in full all remaining outstanding Unsecured Notes, which consisted of $102.8 million in principal amount as of the final redemption date.
NOTE 5 COMMON AND PREFERRED STOCK
Common Stock
The Company is authorized to issue up to 675,000,000 shares of common stock, par value $0.001 per share. As of December 31, 2019 and 2018, the Company had 406,085,183 and 378,333,070 shares of common stock issued and outstanding, respectively.
Preferred Stock
The Company is authorized to issue up to 5,000,000 shares of preferred stock, par value $0.001 per share, with such designations, voting and other rights and preferences as may be determined from time to time by the Board of Directors. As of December 31, 2019 and 2018, the Company had 1,500,000 and zero shares of preferred stock issued and outstanding, respectively, all of which were shares of 6.500% Series A Perpetual Cumulative Convertible Preferred Stock (the “Series A Preferred Stock”).
The terms of the Series A Preferred Stock are set forth in the Certificate of Designations for the Series A Preferred Stock (the “Certificate of Designations”), as originally filed with the Delaware Secretary of State on November 22, 2019, and as amended thereafter. The Series A Preferred Stock ranks senior to the Company’s common stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding-up. Holders of the Series A Preferred Stock are entitled to receive, when, as and if declared by the board of directors of the Company, cumulative dividends in cash, at a rate of 6.500% per annum on the sum of (i) the $100 liquidation preference per share of Series A Preferred Stock (the “Liquidation Preference”) and (ii) all accumulated and unpaid dividends (if any), payable semi-annually in arrears on May 15 and November 15 of each year, commencing on May 15, 2020. As of December 31, 2019, there were $1.0 million of undeclared accumulated dividends on the Series A Preferred Stock.
The Series A Preferred Stock is convertible at the holders’ option (an “Optional Conversion”) into common stock at a conversion rate set forth in the Certificate of Designations, subject to customary adjustments as provided for therein. As of December 31, 2019, the conversion rate was 43.63 shares of common stock for each share of Series A Preferred Stock (which is equivalent to a conversion price of approximately $2.292 per share of Common Stock). Holders may be entitled to additional shares of common stock or cash in connection with a conversion that occurs in connection with a Fundamental Change (as defined in the Certificate of Designations). The Series A Preferred Stock is convertible at the Company’s option (a “Mandatory Conversion”) if the closing sale price of the Company’s common stock equals or exceeds 145% of the conversion price for at least 20 trading days (whether or not consecutive) in a period of 30 consecutive trading days. A Mandatory Conversion would also entitle the holder to a cash payment equal to eight semi-annual dividend payments, less an amount equal to all cash dividend payments made in respect of such holder’s shares of Series A Preferred Stock prior to such Mandatory Conversion. The occurrence of any Optional Conversion or Mandatory Conversion is subject to various terms and limitations set forth in the Certificate of Designations.
The Certificate of Designations also sets forth additional information relating to the payment of dividends, voting, conversion rights, consent rights, liquidation rights, the ranking of the Series A Preferred Stock in comparison with the Company’s other securities, and other matters.
2019 Activity
Preferred Stock
In November 2019, the Company issued an aggregate of 1,500,000 shares of Series A Preferred Stock. Of these shares, 750,000 shares of Series A Preferred Stock were issued in exchange for $70.8 million in aggregate principal amount of Second Lien Notes, and 750,000 shares of Series A Preferred Stock were issued for an aggregate cash purchase price of $75.0 million (before fees and expenses).
Common Stock
In July 2019, the Company issued 5.6 million shares of common stock as a part of the consideration for the VEN Bakken Acquisition (see Note 3).
In 2019, the Company elected to issue 10.2 million shares of common stock to satisfy contingent consideration owed in connection with the Pivotal Acquisition (see Note 3).
In 2019, the Company elected to issue 7.6 million shares of common stock to satisfy contingent consideration owed in connection with the W Energy Acquisition (see Note 3).
In 2019, the Company elected to issue 7.2 million shares of common stock to satisfy obligations owed in connection with the debt exchange derivative liabilities (see Note 11) related to the Additional 2018 Exchanges (see Note 4).
2018 Activity
Exchange Transactions
In May 2018, the Company issued 103.2 million shares of common stock at closing of the May 2018 Exchange (see Note 4).
In 2018, the Company issued 32.8 million shares of common stock as consideration in connection with the Additional 2018 Exchanges (see Note 4).
Equity Offerings
On April 10, 2018, the Company completed an underwritten public offering of common stock (the “Public Offering”) pursuant to which it issued 58.7 million shares of common stock and received net proceeds of $84.5 million after underwriting discounts, commissions, and offering expenses. On April 16, 2018, the underwriters exercised their option to purchase an additional 3.6 million shares and the Company received additional net proceeds of $5.2 million after underwriting discounts.
In May 2018, the Company issued 34.7 million shares to various investors through subscription agreements for net proceeds of $52.0 million.
Acquisitions
In June 2018, the Company issued 6.0 million shares of common stock as a part of the consideration for the Salt Creek Acquisition (see Note 3).
In September 2018, the Company issued 25.8 million shares of common stock as a part of the consideration for the Pivotal Acquisition (see Note 3).
In October 2018, the Company issued 51.5 million shares of common stock as a part of the consideration for the W Energy Acquisition (see Note 3).
Stock Repurchase Program
In May 2011, the Company’s board of directors approved a stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock. The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions.
In 2019, the Company repurchased 5.6 million shares of its common stock under the stock repurchase program at a total cost of $16.3 million. Of the shares repurchased in 2019, 3.7 million were repurchased from W Energy at a total cost of approximately $11.1 million, of which $1.2 million was recorded as a settlement of contingent consideration liabilities. In 2018, the Company repurchased 7.4 million shares of its common stock under the stock repurchase program from the Pivotal Entities and W Energy at a cost of approximately $23.9 million, of which $1.7 million was recorded as a settlement of contingent consideration liabilities. In 2017, the Company did not repurchase shares of its common stock under the stock repurchase program.
The Company’s accounting policy upon the repurchase of shares is to deduct its par value from common stock and to reflect any excess of cost over par value as a deduction from Additional Paid-in Capital. All repurchased shares are now included in the Company’s pool of authorized but unissued shares.
NOTE 6 STOCK-BASED COMPENSATION
The Company’s 2018 Equity Incentive Plan (the “2018 Plan”), which replaced the Company’s prior 2013 Incentive Plan (the “2013 Plan”), authorized 15,000,000 shares for grant under the 2018 Plan, plus the 769,775 shares remaining available for future grants under the 2013 Plan on the date the stockholders approved the 2018 Plan. No future awards will be made under the 2013 Plan. The 2013 Plan continues to govern awards that were made thereunder, which remain in effect pursuant to their terms. As of December 31, 2019 there were 12.6 million shares available for future awards under the 2018 Plan.
The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company’s stock-based compensation awards are accounted for as equity instruments and are included in the “General and administrative” line item in the unaudited statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the “Oil and natural gas properties” line item on the unaudited balance sheets.
The 2018 Plan and 2013 Plan award types are summarized as follows:
Restricted Stock Awards
The Company issues restricted stock awards (“RSAs”) subject to various vesting conditions as compensation to executive officers, employees and directors of the Company. RSAs issued to employees and executive officers generally vest over three years, provided that any performance and/or market conditions are also met. RSAs issued to directors generally vest over one year, provided that any performance and/or market conditions are also met. For RSAs subject to service and/or performance vesting conditions, the grant-date fair value is established based on the closing price of the Company’s common stock on such date. Stock-based compensation expense for awards subject to only service conditions is recognized on a straight-line basis over the service period. Stock-based compensation expense for awards with both service and performance conditions is recognized on a graded basis only if it is probable that the performance condition will be achieved. The Company accounts for forfeitures of awards granted under these plans as they occur in determining stock-based compensation expense.
For awards subject to a market condition, the grant-date fair value is estimated using a Monte Carlo valuation model. The Company recognizes stock-based compensation expense for awards subject to market-based vesting conditions regardless of whether it becomes probable that these conditions will be achieved or not, and stock-based compensation expense for any such awards is not reversed if vesting does not actually occur. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility is calculated based on the historical volatility and implied volatility of the Company’s common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period. The key assumptions used in valuing these market-based awards were as follows:
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|
|
|
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|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
Risk-free interest rate
|
2.57
|
%
|
|
2.10
|
%
|
|
Dividend yield
|
—
|
%
|
|
—
|
%
|
|
Expected volatility
|
85.00
|
%
|
|
100.00
|
%
|
|
|
|
|
|
During 2019, 2018 and 2017, 1,747,200, 1,050,355 and 911,335 shares, respectively, of service-based RSAs were granted to executive officers, employees and directors under the 2013 and 2018 Equity Plans. The weighted average grant date fair value of service-based RSAs was $2.14 per share, $2.67 per share and $2.10 per share for the years ended December 31, 2019, 2018, and 2017, respectively.
During 2018, RSAs subject to service and performance-based vesting conditions were granted to employees and executive officers under the 2013 Plan. Vesting of these awards was contingent on the Company’s annualized Adjusted EBITDA as compared to specified targets for the fourth quarter of 2018 (“2018 Performance Award I”). The Company assessed the probability of achieving the performance condition throughout the performance period using its internal financial forecasts. The weighted average grant date fair value of these service and performance-based RSAs was $2.70 per share. Also during 2018, RSAs subject to service and market-based vesting conditions were granted to employees, executive officers, and directors under the 2013 Plan. Vesting of these awards was contingent on the Company’s stock price performance relative to specified targets (“2018 Performance Award II”). The weighted average grant date fair value of these service and market-based RSAs was $1.67 per share.
During 2019, RSAs subject to service, market, and performance-based vesting conditions were granted to employees and executive officers under the 2018 Plan. Vesting of these awards is contingent on the Company’s debt-adjusted cash flow per share as compared to specified targets (“2019 Performance Award I”). The weighted average grant date fair value of these service, performance, and market-based RSAs was $0.98 per share. Also during 2019, RSAs subject to service and market-based vesting conditions were granted to employees, executive officers, and directors under the 2018 Plan. Vesting of these awards is contingent on the Company’s stock price performance relative to specified targets (“2019 Performance Award II”). The weighted average grant date fair value of these service and market-based RSAs was $1.82 per share.
The following table reflects the outstanding RSAs and activity related thereto for the year ended December 31, 2019:
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Service-based Awards
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Service and Performance-based Awards
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Service and Market-based Awards
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Service, Performance, and Market-based Awards
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|
Number of Shares
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|
Weighted-average Grant Date Fair Value
|
|
Number of Shares
|
|
Weighted-average Grant Date Fair Value
|
|
Number of Shares
|
|
Weighted-average Grant Date Fair Value
|
|
Number of Shares
|
|
Weighted-average Grant Date Fair Value
|
|
Outstanding at December 31, 2018
|
632,759
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|
|
$
|
2.72
|
|
|
1,018,500
|
|
|
$
|
2.70
|
|
|
1,176,600
|
|
|
$
|
1.67
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|
|
—
|
|
|
$
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—
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|
|
Shares granted
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1,747,200
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|
|
2.14
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|
|
—
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|
|
—
|
|
|
1,254,000
|
|
|
1.82
|
|
|
1,068,000
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|
|
0.98
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|
|
Shares forfeited
|
(32,402)
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|
|
2.76
|
|
|
(4,000)
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|
|
2.70
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|
|
(976,733)
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|
|
1.70
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|
|
—
|
|
|
—
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|
|
Shares vested
|
(1,933,553)
|
|
|
2.27
|
|
|
(639,500)
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|
|
2.70
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|
|
(264,206)
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|
|
1.67
|
|
|
(360,000)
|
|
|
0.98
|
|
|
Outstanding at December 31, 2019
|
414,004
|
|
|
$
|
2.41
|
|
|
375,000
|
|
|
$
|
2.70
|
|
|
1,189,661
|
|
|
$
|
1.80
|
|
|
708,000
|
|
|
$
|
0.98
|
|
At December 31, 2019, there was $3.5 million of total unrecognized compensation expense related to unvested RSAs. That cost is expected to be recognized over a weighted average period of 0.68 years. For the year ended December 31, 2019, 2018 and 2017, the total fair value of the Company’s restricted stock awards vested was $6.6 million, $3.5 million and $2.0 million, respectively.
In December 2019, the compensation committee of the board of directors modified both the 2019 Performance Award I and the 2019 Performance Award II. The 2019 Performance Award I was modified to deem the debt-adjusted cash flow per share targets as having been achieved, the effect of which was to essentially convert these awards into RSAs having only service-based vesting conditions. The fair value of the modified 2019 Performance Award I was $1.88 per share, resulting in incremental compensation expense of $2.0 million as a result of the modification, which will be expensed over the requisite service periods. The 2019 Performance Award II was modified (solely for executive officers and employees, not for directors) such that the shares subject thereto now vest contingent on the Company’s average closing stock price meeting specified targets for any consecutive twenty trading day period ending on or before December 31, 2020. The fair value of the modified 2019
Performance Award II was $1.04 per share and was estimated using a Monte Carlo simulation. This resulted in incremental compensation expense of $1.1 million as a result of the modification, which will be expensed over the requisite service periods.
The assumptions used to estimate the fair value of the 2019 Performance Award II granted as of the date presented are as follows:
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Pre-Modification
|
|
At Modification
|
|
|
|
January 4, 2019
|
|
December 13, 2019
|
|
December 13, 2019
|
|
Risk-free interest rate
|
|
2.57
|
%
|
|
1.53
|
%
|
|
1.53
|
%
|
|
Dividend yield
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
Expected volatility
|
|
85.00
|
%
|
|
65.00
|
%
|
|
65.00
|
%
|
In December 2018, the compensation committee of the board of directors modified the 2018 Performance Award II such that the shares subject thereto now vest contingent on the Company’s average closing stock price meeting specified targets for any consecutive twenty trading day period ending on or before December 31, 2019. The grant date fair value of the modified 2018 Performance Award II shares was estimated using Monte Carlo simulations. This resulted in incremental compensation expense of $1.8 million as a result of the modification to both employees’ and directors’ 2018 Performance Award II shares, which will be expensed over the requisite service periods.
The assumptions used to estimate the fair value of the 2018 Performance Award II granted as of the date presented are as follows:
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|
|
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|
|
|
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|
|
Pre-Modification
|
|
At Modification
|
|
|
|
June 1, 2018
|
|
December 19, 2018
|
|
December 19, 2018
|
|
Risk-free interest rate
|
|
2.10
|
%
|
|
2.35
|
%
|
|
2.62
|
%
|
|
Dividend yield
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
Expected volatility
|
|
100.00
|
%
|
|
80.00
|
%
|
|
85.00
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 7 RELATED PARTY TRANSACTIONS
November 2019 Refinancing Transactions
On October 21, 2019, the Company announced the commencement of (i) a cash tender offer (the “Tender Offer”) to purchase up to $200.0 million in aggregate principal amount of the Company’s Second Lien Notes; (ii) an exchange offer (the “Exchange Offer”) to eligible holders of Second Lien Notes to exchange up to $70.8 million in aggregate principal amount of Second Lien Notes for shares of the Company’s newly issued Series A Preferred Stock; (iii) a related solicitation of consents (the “Consent Solicitation”) to adopt certain proposed amendments to the Second Lien Indenture and (iv) an offer to eligible holders of Second Lien Notes to subscribe to purchase for up to $75.0 million in cash additional shares of Series A Preferred Stock (the “Subscription Offer”). Parties affiliated with TRT Holdings, Inc. (collectively, the “TRT Parties”) held Second Lien Notes and thus had the right to participate in the Tender Offer, Exchange Offer, Consent Solicitation and Subscription Offer on terms identical to the terms offered to all holders of Second Lien Notes. These transactions closed on November 22, 2019, with the TRT Parties (i) exchanging $1.0 million aggregate principal amount of Second Lien Notes for 10,947 shares of Series A Preferred Stock pursuant to the Exchange Offer and (ii) acquiring 10,947 additional shares of Series A Preferred Stock for a purchase price of $1.1 million pursuant to the Subscription Offer. The TRT Parties and their affiliates beneficially owned in excess of 10% of the Company’s outstanding common stock at the time of the transactions.
Share Repurchases
In November 2018, the Company repurchased 2.9 million shares of Company common stock from W Energy Partners LLC (“W Energy”) for cash consideration of $10.0 million. In January 2019, the Company repurchased 3.7 million shares of Company common stock from W Energy for cash consideration of $11.1 million. The repurchased shares were originally issued by the Company as partial consideration for the W Energy Acquisition described in Note 3 above. W Energy beneficially owned in excess of 10% of the Company’s outstanding common stock at the time of the repurchase transactions.
May 2018 Exchange and Related Transactions
Exchange Agreement
On January 31, 2018, the Company entered into an exchange agreement that was subsequently amended (as amended, the “Exchange Agreement”) with holders (the “Supporting Noteholders”) of approximately $496.7 million, or 71%, of the aggregate principal amount of its outstanding 8.000% senior unsecured notes due 2020 (the “Unsecured Notes”), pursuant to which the Supporting Noteholders agreed to exchange all of the Unsecured Notes held by each such Supporting Noteholder for approximately $155.0 million of its common stock and approximately $344.3 million in aggregate principal amount of new Second Lien Notes (such exchange, the “Exchange Transaction”). Closing under the Exchange Agreement occurred on May 15, 2018.
Certain TRT Parties (together, the “TRT Noteholders”) were Supporting Noteholders and received, upon consummation of the Exchange Transaction, in the aggregate, approximately 54.6 million shares of the Company’s common stock and approximately $125.3 million aggregate principal amount of Second Lien Notes in exchange for the $204.7 million of Unsecured Notes that they exchanged. Two of the Company’s directors, Michael Frantz and Mike Popejoy, are employed by TRT, and each of the TRT Noteholders individually beneficially owned in excess of 10% of the Company’s outstanding common stock when the Exchange Agreement was entered into. The principal amounts of any Second Lien Notes held by the TRT Noteholders as of December 31, 2019 are included in the Company’s long-term debt balances, and the Company’s interest expense includes interest attributable to any Unsecured Notes and Second Lien Notes held by TRT during the applicable period.
The obligations of the Supporting Noteholders under the Exchange Agreement were subject to the conditions set forth in the Exchange Agreement, which were satisfied at or prior to closing, including (among others) the successful completion of an equity transaction (the “Equity Raise”) comprised of $140.0 million in gross proceeds from the sale of the Company’s common stock, including the funding of up to $52.0 million of commitments received under the Subscription Agreements (as defined below).
Subscription Agreements and Equity Raise
On January 31, 2018, and in connection with the Exchange Transaction, the Company and Bahram Akradi (the Chairman of its board of directors), Michael Reger (who subsequently joined the Company as an executive officer in May 2018), TRT and certain other investors each entered into subscription agreements (the “Subscription Agreements”) whereby such investors agreed to purchase up to $40.0 million of the Company’s common stock at a price per share equal to the lowest price per share in the Equity Raise, and subject to the closing of the Exchange Transaction. Pursuant to their respective Subscription Agreements, Mr. Akradi purchased $12.0 million of the Company’s common stock, Mr. Reger purchased $10.0 million of the Company’s common stock, and TRT purchased $10.0 million of the Company’s common stock. Based on the pricing of the Equity Raise, the lowest price of which was $1.50 per share, Mr. Akradi purchased 8.0 million shares, Mr. Reger purchased 6.7 million shares and TRT purchased 6.7 million shares. The TRT Parties beneficially owned in excess of 10% of the Company’s outstanding common stock when their respective Subscription Agreements were entered into.
On April 10, 2018, to satisfy, in part, the Company’s obligation to complete the Equity Raise, the Company completed an underwritten public offering (the “Offering”), whereby it sold 58,666,667 shares of its common stock at a public offering price of $1.50 per share. As part of the Offering, Mr. Akradi purchased 1.0 million shares of the Company’s common stock from the underwriters of the Offering for an aggregate purchase price of $1.5 million.
Registration Rights
In accordance with the terms of the Exchange Agreement, at the closing of the Exchange Transaction, the Company entered into registration rights agreements with (i) the Supporting Noteholders, including the TRT Noteholders, pursuant to which the Company agreed to file with the SEC a registration statement registering for resale the shares of common stock and the Second Lien Notes issued in the Exchange Transaction, and (ii) the TRT Noteholders and an affiliate of TRT, pursuant to which the Company agreed to file with the SEC a registration statement registering for resale all of the shares of common stock held by the TRT Noteholders and such affiliate, excluding shares of common stock that the TRT Noteholders received pursuant to the Exchange Transaction. The required registration statements were filed and declared effective by the SEC during 2018.
The Company’s Audit Committee is responsible for approving all transactions involving related parties, including each of the transactions identified above.
NOTE 8 COMMITMENTS & CONTINGENCIES
Litigation
The Company is engaged in various proceedings incidental to the normal course of business. Due to their nature, such legal proceedings involve inherent uncertainties, including but not limited to, court rulings, negotiations between affected parties and governmental intervention. Based upon the information available to the Company and discussions with legal counsel, it is the Company’s opinion that the outcome of the various legal actions and claims that are incidental to its business will not have a material impact on the Company’s financial position, results of operations or cash flows. Such matters, however, are subject to many uncertainties, and the outcome of any matter is not predictable with assurance.
The Company’s interests in certain crude oil and natural gas leases from the State of North Dakota are subject to an ongoing dispute over the ownership of minerals underlying the bed of the Missouri River within the boundaries of the Fort Berthold Reservation. The ongoing dispute is between the State of North Dakota and three affiliated tribes, both of whom have purported to lease mineral rights in tracts of riverbed within the reservation boundaries. In the event the ongoing dispute results in a final judgment that is adverse to the Company’s interests, the Company would be required to reverse approximately $4.7 million in revenue (net of accrued taxes) that has been accrued since the first quarter of 2013 based on the Company’s purported interest in the crude oil and natural gas leases at issue. Due to the long-term nature of this title dispute, the $4.7 million in accounts receivable is included in “Other Noncurrent Assets, Net” on the balance sheets. The Company fully maintains the validity of its interests in the crude oil and natural gas leases.
NOTE 9 ASSET RETIREMENT OBLIGATION
The Company has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. Initially, the fair value of a liability for an ARO is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, an adjustment to the full cost pool is recognized. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.
Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit-adjusted risk-free discount rates, timing of retirement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO, a corresponding adjustment is made to the oil and gas property balance. For example, as the Company analyzes actual plugging and abandonment information, the Company may revise its estimate of current costs, the assumed annual inflation of the costs and/or the assumed productive lives of its wells. During 2019 and 2018, there were no adjustments to the aforementioned assumptions requiring revisions of previous estimates.
The following table summarizes the Company’s asset retirement obligation transactions recorded during the years ended December 31, 2019 and 2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
(in thousands)
|
2019
|
|
2018
|
|
Beginning Asset Retirement Obligation
|
$
|
12,501
|
|
|
$
|
9,128
|
|
|
Liabilities Acquired During the Period
|
2,680
|
|
|
1,737
|
|
|
Liabilities Incurred During the Period
|
1,361
|
|
|
1,118
|
|
|
|
|
|
|
|
Accretion of Discount on Asset Retirement Obligations
|
973
|
|
|
683
|
|
|
Liabilities Settled During the Period
|
(216)
|
|
|
(165)
|
|
|
Ending Asset Retirement Obligation
|
$
|
17,299
|
|
|
$
|
12,501
|
|
NOTE 10 INCOME TAXES
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, 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 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 (loss) in the period that includes the enactment date.
The income tax provision (benefit) for the years ended December 31, 2019, 2018, and 2017 consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
2019
|
|
2018
|
|
2017
|
|
Current
|
|
|
|
|
|
|
Federal
|
$
|
(210)
|
|
|
$
|
(420)
|
|
|
$
|
(785)
|
|
|
State
|
—
|
|
|
—
|
|
|
—
|
|
|
Deferred
|
|
|
|
|
|
|
Federal
|
(16,676)
|
|
|
91,958
|
|
|
126,501
|
|
|
State
|
(3,578)
|
|
|
11,636
|
|
|
(12,983)
|
|
|
Valuation Allowance
|
20,464
|
|
|
(103,229)
|
|
|
(114,303)
|
|
|
Total Tax Benefit
|
$
|
—
|
|
|
$
|
(55)
|
|
|
$
|
(1,570)
|
|
The following is a reconciliation of the reported amount of income tax benefit for the years ended December 31, 2019, 2018, and 2017 to the amount of income tax expenses that would result from applying the statutory rate to pretax income (loss).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
2019
|
|
2018
|
|
2017
|
|
Income (Loss) Before Taxes and NOL
|
$
|
(76,318)
|
|
|
$
|
143,634
|
|
|
$
|
(10,764)
|
|
|
Federal Statutory Rate
|
21.00
|
%
|
|
21.00
|
%
|
|
35.00
|
%
|
|
Taxes Computed at Federal Statutory Rates
|
(16,027)
|
|
|
30,163
|
|
|
(3,767)
|
|
|
State Taxes, Net of Federal Taxes
|
(2,630)
|
|
|
9,143
|
|
|
(8,476)
|
|
|
Deferred Tax Adjustment
|
(1,891)
|
|
|
—
|
|
|
—
|
|
|
Share Based Compensation Tax Deficiency
|
33
|
|
|
316
|
|
|
—
|
|
|
Federal Rate Reduction
|
—
|
|
|
—
|
|
|
124,493
|
|
|
Section 382 Limitation
|
—
|
|
|
63,573
|
|
|
—
|
|
|
Other
|
51
|
|
|
(21)
|
|
|
483
|
|
|
Valuation Allowance
|
20,464
|
|
|
(103,229)
|
|
|
(114,303)
|
|
|
Reported Tax Benefit
|
$
|
—
|
|
|
$
|
(55)
|
|
|
$
|
(1,570)
|
|
The Company’s May 15, 2018 closing under the Exchange Agreement and related transactions triggered an ownership change within the meaning of Section 382 of the Internal Revenue Code (“IRC”) due to the share issuances that resulted from the Exchange Agreement and related transactions. In general, an ownership change, as defined in IRC Section 382, results from a transaction or series of transactions over a three-year period resulting in an ownership change of more than 50% of the outstanding stock of a company by certain stockholders or public groups. Since the Company has experienced an ownership change, utilization of net operating losses (“NOL”) and other tax carryforward attributes are subject to an annual limitation. Accordingly, the Company reduced its deferred tax assets and related valuation allowance by $63.6 million during 2018.
A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. During 2019, in evaluating whether it was more likely than not that the Company’s net deferred tax assets were realized through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the projected future income and results of operations, and (iv) its ability to use tax planning strategies. Based on all the evidence available, management determined it was more likely than not that the net deferred tax assets, other than the deferred tax asset related to the Company’s alternative minimum tax credit, were not realizable. The Company’s valuation allowance at December 31, 2019 was $144.2 million.
At December 31, 2019, the Company had a net operating loss carryforward for federal income tax purposes of $341.7 million, which is net of the IRC Section 382 limitation, and state NOL carryforwards of $524.6 million. The determination of the state NOL carryforwards is dependent upon apportionment percentages and state laws that can change from year to year and that can thereby impact the amount of such carryforwards. If unutilized, the federal net operating losses will expire from 2031 to 2037 and the state net operating losses will expire from 2020 to 2037.
The significant components of the Company’s deferred tax assets (liabilities) were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
(in thousands)
|
2019
|
|
2018
|
|
Net Operating Loss (NOLs) and Tax Credit Carryforwards
|
$
|
91,392
|
|
|
$
|
96,700
|
|
|
Share Based Compensation
|
190
|
|
|
146
|
|
|
Accrued Interest
|
1,061
|
|
|
637
|
|
|
Allowance for Doubtful Accounts
|
1,117
|
|
|
1,279
|
|
|
Crude Oil and Natural Gas Properties and Other Properties
|
(11,447)
|
|
|
16,904
|
|
|
Interest Carryforwards
|
49,011
|
|
|
40,614
|
|
|
Derivative Instruments
|
13,196
|
|
|
(31,981)
|
|
|
Other
|
(112)
|
|
|
(145)
|
|
|
Total Net Deferred Tax Assets (Liabilities) Before Valuation Allowance
|
144,408
|
|
|
124,154
|
|
|
|
|
|
|
|
Valuation Allowance
|
(144,198)
|
|
|
(123,734)
|
|
|
|
|
|
|
|
Total Net Deferred Tax Assets
|
$
|
210
|
|
|
$
|
420
|
|
Tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in the Company’s tax returns that do not meet these recognition and measurement standards. The Company has no liabilities for unrecognized tax benefits.
The Company’s policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expense. For the years ended December 31, 2019, 2018 and 2017, the Company did not recognize any interest or penalties in its statements of operations, nor did it have any interest or penalties accrued in its balance sheet at December 31, 2019 and 2018 relating to unrecognized benefits.
The tax years 2019, 2018, 2017, and 2016 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which the Company is subject. Additionally, NOLs from 2011-2015 could be adjusted in the future when such NOLs are utilized.
On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (the “Act”) which made significant changes that affect the Company, resulting in significant modifications to existing law. The Tax Act, among other things, (i) reduced the U.S. corporate income tax rate, (ii) repealed the corporate alternative minimum tax, (iii) imposed new limitations on the utilization of net operating losses and (iv) provided for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense. The Company recognizes the effects of changes in tax laws and rates on deferred tax assets and liabilities and the retroactive effects of changes in tax laws in the period in which the new legislation is enacted. The enactment date in the U.S. is the date the bill becomes law, which is when the President signs the bill.
As a result of the Act, the Company is also subject to certain statutory restrictions on its current interest and debt loss deductions under IRC Section 163(j) which limits interest deductions to business interest income plus 30% of adjusted taxable income. Deferred interest expense carryforwards do not expire, but can only be utilized in future years when adjusted taxable income provides excess limitation. For the year ended December 31, 2019, the company generated a $8.4 million interest expense carryforward attribute, which has a full valuation allowance. The Act also repeals the corporate alternative minimum tax for tax years beginning after December 31, 2017 and provides that prior alternative minimum tax credits will be refundable. The Company has credits that are expected to be refunded between 2019 and 2021 as a result of the Act and monetization opportunities under current tax laws. In 2019, the Company utilized $0.2 million of its alternative minimum tax credit. The Company has an additional $0.2 million of alternative minimum tax credits that will be refunded in future years.
NOTE 11 FAIR VALUE
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The Company uses a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value which are the following:
Level 1 - Quoted prices in active markets for identical assets or liabilities.
Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
Financial Assets and Liabilities
As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019 and 2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at Using
|
|
|
|
|
|
|
December 31, 2019 Using
|
|
|
|
|
|
(In thousands)
|
Quoted Prices In Active Markets for Identical Assets
(Liabilities)
(Level 1)
|
|
Significant Other Observable Inputs
(Level 2)
|
|
Significant Unobservable Inputs
(Level 3)
|
|
Commodity Derivatives – Current Asset (crude oil price swaps)
|
$
|
—
|
|
|
$
|
5,628
|
|
|
$
|
—
|
|
|
Commodity Derivatives – Current Liabilities (crude oil price swaps)
|
$
|
—
|
|
|
$
|
(11,298)
|
|
|
$
|
—
|
|
|
Commodity Derivatives – Noncurrent Asset (crude oil price swaps and crude oil price swaptions)
|
—
|
|
|
8,554
|
|
|
—
|
|
|
Commodity Derivatives – Noncurrent Liabilities (crude oil price swaps and crude oil swaptions)
|
—
|
|
|
(8,079)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
$
|
—
|
|
|
$
|
(5,195)
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at
|
|
|
|
|
|
|
December 31, 2018 Using
|
|
|
|
|
(In thousands)
|
Quoted Prices In Active Markets for Identical Assets
(Liabilities)
(Level 1)
|
|
Significant Other Observable Inputs
(Level 2)
|
|
Significant Unobservable Inputs
(Level 3)
|
|
Commodity Derivatives – Current Asset (crude oil price and basis swaps)
|
$
|
—
|
|
|
$
|
115,870
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
Commodity Derivatives – Non-Current Asset (crude oil price swaps)
|
—
|
|
|
61,843
|
|
|
—
|
|
|
Contingent Consideration - Current Liabilities
|
—
|
|
|
—
|
|
|
(58,069)
|
|
|
Debt Exchange Derivatives - Current Liabilities
|
—
|
|
|
—
|
|
|
(18,183)
|
|
|
Commodity Derivatives – Noncurrent Liabilities (crude oil price swaps)
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
$
|
—
|
|
|
$
|
177,713
|
|
|
$
|
(76,252)
|
|
Commodity Derivatives. The Level 2 instruments presented in the tables above consist of commodity derivative instruments (see Note 12). The fair value of the Company’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The Company’s and the counterparties’ nonperformance risk is evaluated. The fair value of all derivative contracts is reflected on the balance sheet. The current derivative asset and liability amounts represent the fair values expected to be settled in the subsequent twelve months.
Contingent Consideration. The fair value of the contingent consideration potentially payable by the Company in connection with both the Pivotal Acquisition and W Energy Acquisition, which in certain circumstances the Company was permitted to settle in either cash or shares of common stock, was determined using Monte Carlo simulation models. Significant inputs used in the fair value measurements include (i) the Company’s common stock price, (ii) risk-free rates based on U.S. Treasury rates, (iii) volatility of the Company’s common stock, and (iv) expected average daily trading volumes. The expected volatility and average daily trading volumes used in the valuation were unobservable in the marketplace and significant to the valuation methodology, and the contingent consideration’s fair value was therefore designated as Level 3 in the valuation hierarchy. Changes in the fair value of this liability are included in other income (expense) in the Company’s statements of operations. As of December 31, 2019, there were no remaining outstanding contingent consideration liabilities.
Debt Exchange Derivatives. During the second and third quarters of 2018, the Company entered into and closed a number of independent, separately negotiated exchange agreements with holders of the Company’s previously outstanding Unsecured Notes (described as the “Additional 2018 Exchanges” in Note 4 above). Pursuant to each such exchange agreement, the Company agreed to issue the holder shares of its common stock in exchange for certain Unsecured Notes held by such holder. The Company had embedded derivatives related to certain of these exchange agreements that contained provisions whereby if at the end of the applicable restricted sale period the Company’s common stock trades below specified levels, the Company would be required to pay additional consideration to the holder in the form of cash or additional shares of common stock. The Company determined these provisions were not clearly and closely related to the shares of common stock issued under the exchange agreements and, therefore, bifurcated these embedded features and reflected them at fair value in the financial statements. Prior to their settlements, the fair values of these embedded derivatives were determined using Monte Carlo simulations which considered various inputs including (i) the Company’s common stock price, (ii) risk-free rates based on U.S. Treasury rates, (iii) volatility of the Company’s common stock, and (iv) expected average daily trading volumes. The expected volatility and average daily trading volumes used in the valuation were unobservable in the marketplace and significant to the valuation methodology, and the embedded derivatives’ fair value was therefore designated as Level 3 in the valuation hierarchy. Changes in the fair values of these liabilities are included in other income (expense) in the Company’s statements of operations. As of December 31, 2019, there were no remaining outstanding debt exchange derivative liabilities.
The following table summarizes the changes in fair value of the Company’s financial instruments classified as Level 3 in the fair value hierarchy:
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Year Ended December 31, 2019
|
|
Beginning Balance
|
|
$
|
(76,252)
|
|
|
|
|
|
|
|
|
|
|
Debt exchange derivative liability settlements
|
|
16,793
|
|
|
Change in fair value of debt exchange derivative liability
|
|
1,390
|
|
|
Contingent consideration settlements
|
|
87,581
|
|
|
Change in fair value of contingent consideration
|
|
(29,512)
|
|
|
Ending Balance
|
|
$
|
—
|
|
Fair Value of Other Financial Instruments
The carrying amounts of cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments.
Long-term debt is not presented at fair value on the balance sheets, as it is recorded at carrying value, net of unamortized debt issuance costs and unamortized premium or discount (see Note 4). The fair value of the Company’s Second Lien Notes is $434.4 million and $670.8 million at December 31, 2019 and 2018. The fair value of the Company’s Second Lien Notes are based on active market quotes, which represent Level 1 inputs.
There is not active market for the Revolving Credit Facility and the Unsecured VEN Bakken Note. The recorded value of the Revolving Credit Facility approximates its fair value because of its floating rate structure based on the LIBOR spread, secured interest, and the Company’s borrowing base utilization. The fair value measurements for the Revolving Credit Facility and the Unsecured VEN Bakken Note represent Level 2 inputs.
Non-Financial Assets and Liabilities
The Company estimates asset retirement obligations pursuant to the provisions of ASC 410. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and natural gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligations liability is deemed to use Level 3 inputs. Asset retirement obligations incurred and acquired during the year ended December 31, 2019 were approximately $4.0 million.
The Company accounts for acquisitions of oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of oil and natural gas properties. The fair value of these properties is measured using a discounted cash flow model that converts future cash flows to a single discounted amount. These assumptions represent Level 3 inputs under the fair value hierarchy. See Note 3 for additional discussion of the Company’s acquisitions of oil and natural gas properties during the year ended December 31, 2019 and discussion of the significant inputs to the valuations.
Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. There were no transfers of financial assets or liabilities between Level 1, Level 2 or Level 3 inputs for the years ended December 31, 2019 and 2018.
NOTE 12 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT
The Company utilizes commodity price swaps, basis swaps, swaptions and collars (purchased put options and written call options) to (i) reduce the effects of volatility in price changes on the crude oil commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending.
All derivative instruments are recorded on the Company’s balance sheet as either assets or liabilities measured at their fair value (see Note 11). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in the fair value are recognized in the revenues section of the Company’s statements of operations as a gain
or loss on derivative instruments. Mark-to-market gains and losses represent changes in fair values of derivatives that have not been settled. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
The following table presents cash settlements on matured or liquidated derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect proceeds received upon early liquidation of derivative positions and gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period-end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured or were liquidated during the period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
|
|
|
|
(In thousands)
|
2019
|
|
2018
|
|
2017
|
|
Cash Received (Paid) on Settled Derivatives (1)
|
$
|
44,377
|
|
|
$
|
(22,886)
|
|
|
$
|
3,776
|
|
|
Unrealized Gain (Loss) on Derivatives
|
(173,214)
|
|
|
207,892
|
|
|
(18,443)
|
|
|
Gain (Loss) on Derivative Instruments, Net
|
$
|
(128,837)
|
|
|
$
|
185,006
|
|
|
$
|
(14,667)
|
|
_____________
(1)The year ended December 31, 2019, includes approximately $12.4 million of net cash proceeds from crude oil derivative contracts that were restructured in 2019 prior to their contractual maturities.
The Company has master netting agreements on individual commodity contracts with certain counterparties and therefore the current asset and liability are netted on the balance sheet and the non-current asset and liability are netted on the balance sheet for contracts with these counterparties.
As of December 31, 2019, the Company had a total volume on open commodity price swaps of 17.3 million barrels at a weighted average price of approximately $56.77 per barrel. The following table reflects the weighted average price of open commodity price swap derivative contracts as of December 31, 2019, by year with associated volumes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Price
of Open Commodity Swap Contracts
|
|
|
|
|
|
Year
|
|
Volumes (Bbl)
|
|
Weighted
Average Price ($)
|
|
2020
|
|
9,815,844
|
|
|
57.98
|
|
|
2021(1)
|
|
6,151,174
|
|
|
55.78
|
|
|
2022(2)
|
|
1,372,866
|
|
|
52.57
|
|
___________
(1)The Company has 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 about December 31, 2020. If the counterparties exercise all such options, the notional volume of the Company’s 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)The Company has 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 about December 31, 2021. If the counterparties exercise all such options, the notional volume of the Company’s existing crude oil derivative contracts will increase by 2.4 million barrels at a weighted average price of $55.05 per barrel for 2022.
The following table sets forth the amounts, on a gross basis, and classification of the Company’s outstanding derivative financial instruments at December 31, 2019 and 2018, respectively. Certain amounts may be presented on a net basis on the financial statements when such amounts are with the same counterparty and subject to a master netting arrangement:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
Estimated Fair Value
|
|
|
|
Type of Crude Oil Contract
|
|
Balance Sheet Location
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
Derivative Assets:
|
|
|
|
(In thousands)
|
|
|
|
Price Swap Contracts
|
|
Current Assets
|
|
$
|
20,164
|
|
|
$
|
108,514
|
|
|
Basis Swap Contracts
|
|
Current Assets
|
|
—
|
|
|
7,356
|
|
|
Price Swap Contracts
|
|
Noncurrent Assets
|
|
16,069
|
|
|
61,843
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Derivative Assets
|
|
|
|
$
|
36,233
|
|
|
$
|
177,713
|
|
|
|
|
|
|
|
|
|
|
Derivative Liabilities:
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
Current Liabilities
|
|
$
|
(25,834)
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
Noncurrent Liabilities
|
|
(5,273)
|
|
|
—
|
|
|
Price Swaptions Contracts
|
|
Noncurrent Liabilities
|
|
(10,321)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Total Derivative Liabilities
|
|
|
|
$
|
(41,428)
|
|
|
$
|
—
|
|
The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. When the Company has netting arrangements with its counterparties that provide for offsetting payables against receivables from separate derivative instruments these assets and liabilities are netted on the balance sheet. The tables presented below provide reconciliation between the gross assets and liabilities and the amounts reflected on the balance sheet. The amounts presented exclude derivative settlement receivables and payables as of the balance sheet dates.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value at December 31, 2019
|
|
|
|
|
|
(In thousands)
|
Gross Amounts of Recognized Assets (Liabilities)
|
|
Gross Amounts Offset in the
Balance Sheet
|
|
Net Amounts of Assets (Liabilities) Presented in the Balance Sheet
|
|
Offsetting of Derivative Assets:
|
|
|
|
|
|
|
Current Assets
|
$
|
20,164
|
|
|
$
|
(14,536)
|
|
|
$
|
5,628
|
|
|
Non-Current Assets
|
16,069
|
|
|
(7,515)
|
|
|
8,554
|
|
|
Total Derivative Assets
|
$
|
36,233
|
|
|
$
|
(22,051)
|
|
|
$
|
14,182
|
|
|
|
|
|
|
|
|
|
Offsetting of Derivative Liabilities:
|
|
|
|
|
|
|
Current Liabilities
|
$
|
(25,834)
|
|
|
$
|
14,536
|
|
|
$
|
(11,298)
|
|
|
Non-Current Liabilities
|
(15,594)
|
|
|
7,515
|
|
|
(8,079)
|
|
|
Total Derivative Liabilities
|
$
|
(41,428)
|
|
|
$
|
22,051
|
|
|
$
|
(19,377)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value at December 31, 2018
|
|
|
|
|
|
(In thousands)
|
Gross Amounts of Recognized Assets (Liabilities)
|
|
Gross Amounts Offset in the
Balance Sheet
|
|
Net Amounts of Assets (Liabilities) Presented in the Balance Sheet
|
|
Offsetting of Derivative Assets:
|
|
|
|
|
|
|
Current Assets
|
$
|
116,620
|
|
|
$
|
(750)
|
|
|
$
|
115,870
|
|
|
Non-Current Assets
|
61,857
|
|
|
(15)
|
|
|
61,843
|
|
|
Total Derivative Assets
|
$
|
178,477
|
|
|
$
|
(764)
|
|
|
$
|
177,713
|
|
|
|
|
|
|
|
|
|
Offsetting of Derivative Liabilities:
|
|
|
|
|
|
|
Current Liabilities
|
$
|
(750)
|
|
|
$
|
750
|
|
|
$
|
—
|
|
|
Non-Current Liabilities
|
(15)
|
|
|
15
|
|
|
—
|
|
|
Total Derivative Liabilities
|
$
|
(764)
|
|
|
$
|
764
|
|
|
$
|
—
|
|
All of the Company’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“ISDAs”). The Company’s obligations under the derivative instruments are secured pursuant to the Company’s Revolving Credit Facility, and no additional collateral had been posted by the Company as of December 31, 2019. The ISDAs may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. See Note 11 for the aggregate fair value of all derivative instruments that were in a net liability position at December 31, 2019 and 2018.
NOTE 13 EARNINGS PER SHARE
The reconciliation of the numerators and denominators used to calculate basic EPS and diluted EPS for the years ended December 31, 2019, 2018 and 2017 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
(In thousands, except share and per share data)
|
2019
|
|
2018
|
|
2017
|
|
Net Income (Loss)
|
$
|
(76,318)
|
|
|
|
$
|
143,689
|
|
|
|
$
|
(9,194)
|
|
|
Less: Cumulative Dividends on Preferred Stock
|
1,029
|
|
|
—
|
|
|
—
|
|
|
Net Income (Loss) Attributable to Common Stock
|
$
|
(77,347)
|
|
|
$
|
143,689
|
|
|
$
|
(9,194)
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding:
|
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding – Basic
|
387,084,651
|
|
|
236,206,457
|
|
|
62,408,855
|
|
|
Plus: Dilutive Effect of Stock Options, Restricted Stock and Preferred Shares
|
—
|
|
|
567,454
|
|
|
—
|
|
|
Weighted Average Common Shares Outstanding – Diluted
|
387,084,651
|
|
|
236,773,911
|
|
|
62,408,855
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) per Common Share:
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.20)
|
|
|
$
|
0.61
|
|
|
$
|
(0.15)
|
|
|
Diluted
|
$
|
(0.20)
|
|
|
$
|
0.61
|
|
|
$
|
(0.15)
|
|
For the years ended December 31, 2019 and 2017, the Company’s potentially dilutive securities, which include stock options, restricted stock and convertible preferred shares, have been excluded from the computation of diluted net loss per share as the effect would be to reduce the net loss per share. Therefore, the weighted average number of common shares outstanding used to calculate both basic and diluted net loss per share attributable to common shareholders is the same.
The following securities have been excluded from the calculation of diluted weighted average common shares outstanding as the inclusion of these securities would have an anti-dilutive effect:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
Stock Options and Restricted Stock
|
673,037
|
|
|
50,685
|
|
|
1,109,511
|
|
|
Preferred Shares
|
7,079,907
|
|
|
—
|
|
|
—
|
|
|
Total
|
7,752,944
|
|
|
50,685
|
|
|
1,109,511
|
|
NOTE 14 SUBSEQUENT EVENTS
In January 2020, the Company closed four independent, separately negotiated securities purchase and sale agreements with holders of the Company’s Second Lien Notes. Pursuant to these agreements, in the aggregate, the Company repurchased and retired $76.7 million in principal amount of Second Lien Notes. In exchange, the Company paid 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.
SUPPLEMENTAL OIL AND GAS INFORMATION
(UNAUDITED)
Oil and Natural Gas Exploration and Production Activities
Oil and gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profits interest, and other contractual provisions. Production expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of crude oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts. The results of operations for the Company’s crude oil and natural gas production activities are provided in the Company’s related statements of income.
Costs Incurred and Capitalized Costs
The costs incurred in crude oil and natural gas acquisition, exploration and development activities are highlighted in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
(In thousands)
|
2019
|
|
2018
|
|
2017
|
|
Costs Incurred for the Year:
|
|
|
|
|
|
|
Proved Property Acquisition and Other
|
$
|
375,145
|
|
|
$
|
582,697
|
|
|
$
|
15,722
|
|
|
Unproved Property Acquisition
|
9,540
|
|
|
4,903
|
|
|
717
|
|
|
Development
|
369,233
|
|
|
260,945
|
|
|
139,532
|
|
|
Total
|
$
|
753,918
|
|
|
$
|
848,545
|
|
|
$
|
155,971
|
|
Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years. The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion at December 31, 2019 by year incurred.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
(In thousands)
|
2019
|
|
2018
|
|
2017
|
|
Prior Years
|
|
Property Acquisition
|
$
|
6,594
|
|
|
$
|
3,497
|
|
|
$
|
75
|
|
|
$
|
881
|
|
|
Development
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
$
|
6,594
|
|
|
$
|
3,497
|
|
|
$
|
75
|
|
|
$
|
881
|
|
Oil and Natural Gas Reserves and Related Financial Data
Information with respect to the Company’s crude oil and natural gas producing activities is presented in the following tables. Reserve quantities, as well as certain information regarding future production and discounted cash flows, were determined by Cawley, Gillespie & Associates, Inc., independent petroleum consultants based on information provided by the Company.
Oil and Natural Gas Reserve Data
The following tables present the Company’s independent petroleum consultants’ estimates of its proved crude oil and natural gas reserves. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
Natural Gas
(MCF)
|
|
Oil
(BBLS)
|
|
BOE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed and Undeveloped Reserves at December 31, 2016
|
46,832
|
|
|
46,275
|
|
|
54,081
|
|
|
|
|
|
|
|
|
|
Revisions of Previous Estimates
|
8,839
|
|
|
890
|
|
|
2,363
|
|
|
Extensions, Discoveries and Other Additions
|
27,637
|
|
|
20,184
|
|
|
24,791
|
|
|
|
|
|
|
|
|
|
Production
|
(5,188)
|
|
|
(4,537)
|
|
|
(5,402)
|
|
|
|
|
|
|
|
|
|
Proved Developed and Undeveloped Reserves at December 31, 2017
|
78,121
|
|
|
62,812
|
|
|
75,832
|
|
|
|
|
|
|
|
|
|
Revisions of Previous Estimates
|
426
|
|
|
3,470
|
|
|
3,541
|
|
|
Extensions, Discoveries and Other Additions
|
28,348
|
|
|
28,516
|
|
|
33,241
|
|
|
Purchases of Minerals in Place
|
37,397
|
|
|
25,965
|
|
|
32,198
|
|
|
Production
|
(9,225)
|
|
|
(7,790)
|
|
|
(9,328)
|
|
|
|
|
|
|
|
|
|
Proved Developed and Undeveloped Reserves at December 31, 2018
|
135,066
|
|
|
112,973
|
|
|
135,484
|
|
|
|
|
|
|
|
|
|
Revisions of Previous Estimates
|
(5,146)
|
|
|
|
(15,497)
|
|
|
|
(16,355)
|
|
|
Extensions, Discoveries and Other Additions
|
22,019
|
|
|
|
19,992
|
|
|
|
23,662
|
|
|
Purchases of Minerals in Place
|
53,969
|
|
|
|
25,611
|
|
|
|
34,606
|
|
|
Production
|
(16,591)
|
|
|
|
(11,325)
|
|
|
|
(14,091)
|
|
|
|
|
|
|
|
|
|
Proved Developed and Undeveloped Reserves at December 31, 2019
|
189,318
|
|
|
|
131,754
|
|
|
|
163,307
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
December 31, 2016
|
32,808
|
|
|
32,245
|
|
|
37,713
|
|
|
December 31, 2017
|
46,518
|
|
|
38,593
|
|
|
46,346
|
|
|
December 31, 2018
|
82,315
|
|
|
62,497
|
|
|
76,216
|
|
|
December 31, 2019
|
116,846
|
|
|
77,160
|
|
|
96,634
|
|
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
December 31, 2016
|
14,024
|
|
|
14,030
|
|
|
16,368
|
|
|
December 31, 2017
|
31,603
|
|
|
24,220
|
|
|
29,487
|
|
|
December 31, 2018
|
52,752
|
|
|
50,476
|
|
|
59,268
|
|
|
December 31, 2019
|
72,473
|
|
|
54,594
|
|
|
66,673
|
|
Proved reserves are estimated quantities of crude oil and natural gas, which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are included for reserves for which there is a high degree of confidence in their recoverability and they are scheduled to be drilled within the next five years.
Notable changes in proved reserves for the year ended December 31, 2019 included the following:
•Extensions and discoveries. In 2019, total extensions and discoveries of 23.7 MMBOE were primarily attributable to successful drilling in the Williston Basin as well as the addition of proved undeveloped locations. Included in these extensions and discoveries were 11.3 MMBOE as a result of successful drilling in the Williston Basin and 12.3 MMBOE as a result of additional proved undeveloped locations.
•Purchases of minerals in place. In 2019, total purchases of minerals in place of 34.6 MMBOE were primarily attributable to acquisitions of oil and natural gas properties (see Note 3).
•Revisions to previous estimates. In 2019, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 16.4 MMBOE. Included in these revisions were 9.8 MMBOE of downward adjustments caused by lower crude oil and natural gas prices, a 2.0 MMBOE downward adjustment attributable to well performance when comparing the Company’s reserve estimates at December 31, 2019 to December 31, 2018 and 4.6 MMBOE of downward adjustments related to the removal of undeveloped drilling locations related to the 5 year rule.
Notable changes in proved reserves for the year ended December 31, 2018 included the following:
•Extensions and discoveries. In 2018, total extensions and discoveries of 33.2 MMBOE were primarily attributable to successful drilling in the Williston Basin as well as the addition of proved undeveloped locations. Included in these extensions and discoveries were 20.9 MMBOE as a result of successful drilling in the Williston Basin and 12.3 MMBOE as a result of additional proved undeveloped locations.
•Purchases of minerals in place. In 2018, total purchases of minerals in place of 32.2 MMBOE were primarily attributable to acquisitions of oil and natural gas properties (see Note 3).
•Revisions to previous estimates. In 2018, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 3.5 MMBOE. Included in these revisions were 1.4 MMBOE of upward adjustments caused by higher crude oil and natural gas prices and a 3.9 MMBOE upward adjustment attributable to well performance when comparing the Company’s reserve estimates at December 31, 2018 to December 31, 2017 which was partially offset by 4.4 MMBOE of downward adjustments related to the removal of undeveloped drilling locations related to the 5 year rule.
Notable changes in proved reserves for the year ended December 31, 2017 included the following:
•Extensions and discoveries. In 2017, total extensions and discoveries of 24.8 MMBOE were primarily attributable to successful drilling in the Williston Basin as well as the addition of proved undeveloped locations. Included in these extensions and discoveries were 5.9 MMBOE as a result of successful drilling in the Williston Basin and 18.9 MMBOE as a result of additional proved undeveloped locations.
•Revisions to previous estimates. In 2017, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 2.4 MMBOE. Included in these revisions were 1.8 MMBOE of upward adjustments caused by higher crude oil and natural gas prices and a 3.1 MMBOE upward adjustment attributable to well performance when comparing the Company’s reserve estimates at December 31, 2017 to December 31, 2016 which was partially offset by 2.5 MMBOE of downward adjustments related to the removal of undeveloped drilling locations related to the 5 year rule.
Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein
The following table presents a standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved crude oil and natural gas were prepared in accordance with the provisions of ASC 932 Extractive Activities - Oil and Gas. Future cash inflows were computed by applying average prices of crude oil and natural gas for the last 12 months to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income tax expenses were calculated by applying appropriate year end tax rates to future pretax cash flows relating to proved crude oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carry forwards relating to crude oil and natural gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s crude oil and natural gas reserves.
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December 31,
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(In thousands)
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2019
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2018
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2017
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Future Cash Inflows
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$
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7,059,586
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$
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7,524,587
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$
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3,143,604
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Future Production Costs
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(2,868,762)
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(2,605,279)
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(1,265,525)
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Future Development Costs
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(855,041)
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(784,615)
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(409,360)
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Future Income Tax Expense
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(320,528)
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(611,989)
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(27,476)
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Future Net Cash Inflows
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$
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3,015,255
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$
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3,522,704
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$
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1,441,243
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10% Annual Discount for Estimated Timing of Cash Flows
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(1,337,194)
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(1,643,061)
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(687,257)
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Standardized Measure of Discounted Future Net Cash Flows
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$
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1,678,061
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$
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1,879,643
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$
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753,986
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The twelve month average prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company’s reserves. The price of other liquids is included in natural gas. The prices for the Company’s reserve estimates were as follows:
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Natural Gas
MCF
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Oil
Bbl
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December 31, 2019
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$
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2.12
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$
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50.53
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December 31, 2018
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$
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4.50
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$
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61.23
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December 31, 2017
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$
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3.34
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$
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45.90
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The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows. As a result of available net operating loss carryforwards and the remaining tax basis of its assets at December 31, 2019, the Company’s future income taxes were significantly reduced.
Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% per annum follow:
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December 31,
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(In thousands)
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2019
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2018
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2017
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Beginning of Period
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$
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1,879,643
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$
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753,986
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$
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379,026
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Sales of Oil and Natural Gas Produced, Net of Production Costs
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(424,548)
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(381,961)
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(153,626)
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Extensions and Discoveries
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282,528
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549,353
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217,146
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Previously Estimated Development Cost Incurred During the Period
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100,987
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115,542
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46,834
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Net Change of Prices and Production Costs
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(680,119)
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484,122
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216,217
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Change in Future Development Costs
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(174,729)
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(91,829)
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(34,753)
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Revisions of Quantity and Timing Estimates
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(226,721)
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66,185
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28,915
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Accretion of Discount
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218,023
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75,800
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37,942
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Change in Income Taxes
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156,621
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(296,571)
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(3,617)
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Purchases of Minerals in Place
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338,289
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502,193
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—
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Other
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208,087
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102,823
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19,902
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End of Period
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$
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1,678,061
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$
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1,879,643
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$
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753,986
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