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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
_________________________________
FORM 10-Q
_________________________________
 
  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2021
   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from ____________ to____________
 
Commission File No. 001-33999
NORTHERN OIL AND GAS, INC.
(Exact Name of Registrant as Specified in Its Charter)
Delaware95-3848122
(State or Other Jurisdiction of
Incorporation or Organization)
(I.R.S. Employer Identification No.)
601 Carlson Pkwy – Suite 990
Minnetonka, Minnesota 55305
(Address of Principal Executive Offices)
(952) 476-9800
(Registrant’s Telephone Number)
N/A
(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, par value $0.001NOG
NYSE American
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes   No

Indicate by check mark whether the registrant has submitted electronically every interactive data file required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes   No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:
Large Accelerated Filer  
Accelerated Filer  
Non-Accelerated Filer    

Smaller Reporting Company  
Emerging Growth Company 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes   No

As of May 3, 2021, there were 60,402,965 shares of our common stock, par value $0.001, outstanding.


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GLOSSARY OF TERMS

Unless otherwise indicated in this report, natural gas volumes are stated at the legal pressure base of the state or geographic area in which the reserves are located at 60 degrees Fahrenheit.  Crude oil and natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

The following definitions shall apply to the technical terms used in this report.

Terms used to describe quantities of crude oil and natural gas:

Bbl.”  One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.

Boe.”  A barrel of oil equivalent and is a standard convention used to express crude oil, NGL and natural gas volumes on a comparable crude oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil or NGL.

Boepd. Boe per day.

Btu or British Thermal Unit.”  The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

MBbl.”  One thousand barrels of crude oil, condensate or NGLs.

MBoe.”  One thousand Boe.

Mcf.”  One thousand cubic feet of natural gas.

MMBbl.”  One million barrels of crude oil, condensate or NGLs.

MMBoe.”  One million Boe.

MMBtu.”  One million British Thermal Units.

MMcf.”  One million cubic feet of natural gas.

NGLs.”  Natural gas liquids.  Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.

Terms used to describe our interests in wells and acreage:

Basin.”  A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Completion.”  The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs, and/or natural gas.

Conventional play.”  An area that is believed to be capable of producing crude oil, NGLs, and natural gas occurring in discrete accumulations in structural and stratigraphic traps.

Developed acreage.”  Acreage consisting of leased acres spaced or assignable to productive wells.  Acreage included in spacing units of infill wells is classified as developed acreage at the time production commences from the initial well in the spacing unit.  As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

Development well.”  A well drilled within the proved area of a crude oil, NGL, or natural gas reservoir to the depth of a stratigraphic horizon (rock layer or formation) known to be productive for the purpose of extracting proved crude oil, NGL, or natural gas reserves.

Differential.” The difference between a benchmark price of crude oil and natural gas, such as the NYMEX crude oil spot price, and the wellhead price received.
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Dry hole.”  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploratory well.”  A well drilled to find and produce crude oil, NGLs, or natural gas in an unproved area, to find a new reservoir in a field previously found to be producing crude oil, NGLs, or natural gas in another reservoir, or to extend a known reservoir.

Field.”  An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Formation.”  A layer of rock which has distinct characteristics that differs from nearby rock.

Gross acres or Gross wells.”  The total acres or wells, as the case may be, in which a working interest is owned.

Held by operations.”  A provision in an oil and gas lease that extends the stated term of the lease as long as drilling operations are ongoing on the property.

Held by production.”  A provision in an oil and gas lease that extends the stated term of the lease as long as the property produces a minimum quantity of crude oil, NGLs, and natural gas.

Hydraulic fracturing.”  The technique of improving a well’s production by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

Infill well.”  A subsequent well drilled in an established spacing unit of an already established productive well in the spacing unit.  Acreage on which infill wells are drilled is considered developed commencing with the initial productive well established in the spacing unit.  As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

Net acres.”  The percentage ownership of gross acres.  Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).

Net well.”  A well that is deemed to exist when the sum of fractional ownership working interests in gross wells equals one.

NYMEX.”  The New York Mercantile Exchange.

OPEC.”  The Organization of Petroleum Exporting Countries.

Productive well.”  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Recompletion.”  The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Reservoir.”  A porous and permeable underground formation containing a natural accumulation of producible crude oil, NGLs and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Spacing.”  The distance between wells producing from the same reservoir.  Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

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Unconventional play.”  An area believed to be capable of producing crude oil, NGLs, and/or natural gas occurring in cumulations that are regionally extensive but require recently developed technologies to achieve profitability.  These areas tend to have low permeability and may be closely associated with source rock as this is the case with crude oil and natural gas shale, tight crude oil and natural gas sands and coal bed methane.

Undeveloped acreage.”  Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil, NGLs, and natural gas, regardless of whether such acreage contains proved reserves.  Undeveloped acreage includes net acres held by operations until a productive well is established in the spacing unit.

Unit.”  The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests.  Also, the area covered by a unitization agreement.

Wellbore.”  The hole drilled by the bit that is equipped for natural gas production on a completed well.  Also called well or borehole.

West Texas Intermediate or WTI.”  A light, sweet blend of oil produced from the fields in West Texas.

Working interest.”  The right granted to the lessee of a property to explore for and to produce and own crude oil, NGLs, natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“Workover.” Operations on a producing well to restore or increase production.

Terms used to assign a present value to or to classify our reserves:

Possible reserves.”  The additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.

Pre-tax PV-10% or PV-10.”  The estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC.

Probable reserves.”  The additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but which together with proved reserves, are as likely as not to be recovered.

Proved developed producing reserves (PDPs).”  Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.  Additional crude oil, NGLs, and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved developed non-producing reserves (PDNPs). Proved crude oil, NGLs, and natural gas reserves that are developed behind pipe, shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor.  Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate, but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

Proved reserves.”  The quantities of crude oil, NGLs and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

Proved undeveloped drilling location.”  A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

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Proved undeveloped reserves” or PUDs.”  Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for development. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.  Estimates for proved undeveloped reserves will not be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir or an analogous reservoir.

(i)    The area of the reservoir considered as proved includes: (A) the area identified by drilling and limited by fluid contacts, if any, and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil, NGLs or natural gas on the basis of available geoscience and engineering data.

(ii)    In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)    Where direct observation from well penetrations has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)    Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) the project has been approved for development by all necessary parties and entities, including governmental entities.

(v)    Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions.

Standardized measure.”  Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

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NORTHERN OIL AND GAS, INC.
FORM 10-Q

March 31, 2021

C O N T E N T S
 Page
PART I – FINANCIAL INFORMATION 
  
Item 1.Condensed Financial Statements (unaudited)
Condensed Balance Sheets
Condensed Statements of Operations
Condensed Statements of Cash Flows
Condensed Statements of Stockholders’ Equity
Notes to Condensed Financial Statements
 
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Item 3.Quantitative and Qualitative Disclosures about Market Risk
 
Item 4. Controls and Procedures
 
PART II – OTHER INFORMATION
 
Item 1.Legal Proceedings
 
Item 1A.Risk Factors
 
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds
 
Item 6.Exhibits
 
Signatures

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PART I - FINANCIAL INFORMATION
Item 1. Condensed Financial Statements.
NORTHERN OIL AND GAS, INC.
CONDENSED BALANCE SHEETS
(In thousands, except par value and share data)March 31, 2021December 31, 2020
Assets(Unaudited)
Current Assets:  
Cash and Cash Equivalents$2,729 $1,428 
Accounts Receivable, Net94,804 71,015 
Advances to Operators431 476 
Prepaid Expenses and Other2,455 1,420 
Derivative Instruments2,005 51,290 
Total Current Assets102,424 125,629 
Property and Equipment:  
Oil and Natural Gas Properties, Full Cost Method of Accounting  
Proved4,431,977 4,393,533 
Unproved9,621 10,031 
Other Property and Equipment2,502 2,451 
Total Property and Equipment4,444,100 4,406,015 
Less – Accumulated Depreciation, Depletion and Impairment(3,701,715)(3,670,811)
Total Property and Equipment, Net742,385 735,204 
Derivative Instruments356 111 
Acquisition Deposit17,500  
Other Noncurrent Assets, Net10,578 11,145 
Total Assets$873,243 $872,089 
Liabilities and Stockholders' Equity (Deficit)
Current Liabilities:  
Accounts Payable$40,788 $35,803 
Accrued Liabilities72,667 68,673 
Accrued Interest5,769 8,341 
Derivative Instruments35,108 3,078 
Contingent Consideration618 493 
Current Portion of Long-term Debt 65,000 
Other Current Liabilities1,018 1,087 
Total Current Liabilities155,968 182,475 
Long-term Debt817,061 879,843 
Derivative Instruments61,987 14,659 
Asset Retirement Obligations18,884 18,366 
Other Noncurrent Liabilities26 50 
Total Liabilities$1,053,926 $1,095,393 
Commitments and Contingencies (Note 8)
Stockholders’ Equity (Deficit)  
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Preferred Stock, Par Value $.001; 5,000,000 Shares Authorized;
2,218,732 Series A Shares Outstanding at 3/31/2021
2,218,732 Series A Shares Outstanding at 12/31/2020
2 2 
Common Stock, Par Value $.001; 135,000,000* Shares Authorized;
 60,361,547* Shares Outstanding at 3/31/2021
 45,908,779* Shares Outstanding at 12/31/2020
462 448 
Additional Paid-In Capital1,689,567 1,556,602 
Retained Deficit(1,870,714)(1,780,356)
Total Stockholders’ Equity (Deficit)(180,682)(223,304)
Total Liabilities and Stockholders’ Equity (Deficit)$873,243 $872,089 
___________
*Adjusted for the 1-for-10 reverse stock split. See Note 5.

The accompanying notes are an integral part of these condensed financial statements.


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NORTHERN OIL AND GAS, INC.
CONDENSED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Ended
March 31,
(In thousands, except share and per share data)20212020
Revenues  
Oil and Gas Sales$157,331 $130,196 
Gain (Loss) on Commodity Derivatives, Net(135,935)376,581 
Other Revenue1 8 
Total Revenues21,397 506,785 
Operating Expenses 
Production Expenses34,312 37,335 
Production Taxes13,453 11,896 
General and Administrative Expense6,782 4,871 
Depletion, Depreciation, Amortization and Accretion31,221 61,809 
Total Operating Expenses85,768 115,911 
Income (Loss) From Operations(64,371)390,875 
Other Income (Expense)  
Interest Expense, Net of Capitalization(13,510)(16,551)
Gain (Loss) on Unsettled Interest Rate Derivatives, Net240 (677)
Loss on Extinguishment of Debt, Net(12,594)(5,527)
Contingent Consideration Loss(125) 
Other Income (Expense)3  
Total Other Income (Expense)(25,986)(22,755)
Income (Loss) Before Income Taxes(90,357)368,120 
Income Tax Provision (Benefit) (166)
Net Income (Loss)$(90,357)$368,286 
Cumulative Preferred Stock Dividend(3,830)(3,729)
Net Income (Loss) Attributable to Common Stockholders$(94,188)$364,557 
Net Income (Loss) Per Common Share – Basic*$(1.73)$9.03 
Net Income (Loss) Per Common Share – Diluted*$(1.73)$7.33 
Weighted Average Common Shares Outstanding – Basic*54,538,099 40,366,253 
Weighted Average Common Shares Outstanding – Diluted*54,538,099 49,721,264 
___________
*Adjusted for the 1-for-10 reverse stock split. See Note 5.

The accompanying notes are an integral part of these condensed financial statements.
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NORTHERN OIL AND GAS, INC.
CONDENSED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended
March 31,
(In thousands)20212020
Cash Flows from Operating Activities  
Net Income (Loss)$(90,357)$368,286 
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:  
Depletion, Depreciation, Amortization and Accretion31,221 61,809 
Amortization of Debt Issuance Costs1,014 1,461 
Loss on Extinguishment of Debt12,594 5,527 
Amortization of Bond Premium on Long-term Debt(122)(321)
Deferred Income Taxes 210 
Unrealized (Gain) Loss of Derivative Instruments128,398 (344,398)
Loss on Contingent Consideration125  
Stock-Based Compensation Expense769 1,079 
Other(61)(57)
Changes in Working Capital and Other Items:  
Accounts Receivable, Net(23,694)10,789 
Prepaid and Other Expenses(1,037)(251)
Accounts Payable5,057 (1,514)
Accrued Interest(2,588)(2,290)
Accrued Liabilities and Expenses1,447 327 
Net Cash Provided by Operating Activities62,766 100,654 
Cash Flows from Investing Activities  
Drilling and Development Capital Expenditures(33,331)(78,962)
Acquisition of Oil and Natural Gas Properties(1,790)(25,537)
Acquisition Deposit(17,500) 
Purchases of Other Property and Equipment(51) 
Net Cash Used for Investing Activities(52,672)(104,500)
Cash Flows from Financing Activities  
Advances on Revolving Credit Facility109,000 25,000 
Repayments on Revolving Credit Facility(378,000)(15,000)
Repurchases of Second Lien Notes due 2023(280,249)(13,277)
Repayment of Unsecured VEN Bakken Note due 2022(130,000) 
Debt Issuance Costs Paid(11,607)(37)
Issuance of Common Stock132,900  
Issuance of Unsecured Notes due 2028550,000  
Restricted Stock Surrenders - Tax Obligations(837)(396)
Net Cash Used for Financing Activities(8,793)(3,710)
Net Increase (Decrease) in Cash and Cash Equivalents1,301 (7,555)
Cash and Cash Equivalents - Beginning of Period1,428 16,068 
Cash and Cash Equivalents - End of Period2,729 8,512 

The accompanying notes are an integral part of these condensed financial statements.
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NORTHERN OIL AND GAS, INC.
CONDENSED STATEMENTS OF STOCKHOLDERS’ EQUITY
(UNAUDITED)

(In thousands, except share data)Common Stock*Preferred StockAdditional Paid-InRetained
Earnings
Total Stockholders’
Equity
 SharesAmountSharesAmountCapital(Deficit)(Deficit)
December 31, 202045,908,779 $448 2,218,732 $2 $1,556,602 $(1,780,357)$(223,304)
Issuance of Common Stock138,297  — — — —  
Share Based Compensation— — — — 916 — 916 
Restricted Stock Surrenders - Tax Obligations(60,529)— — — (837)— (837)
Equity Offerings, Net of Issuance Costs14,375,000 14 — — 132,885 — 132,900 
Net Loss— — — — — (90,357)(90,357)
March 31, 202160,361,547 $462 2,218,732 $2 $1,689,567 $(1,870,714)$(180,682)

(In thousands, except share data)Common Stock*Preferred StockAdditional Paid-InRetained
Earnings
Total Stockholders’
Equity
 SharesAmountSharesAmountCapital(Deficit)(Deficit)
December 31, 201940,608,518 $406 1,500,000 $2 $1,431,438 $(873,203)$558,643 
Issuance of Common Stock5,000  — — — —  
Share Based Compensation— — — — 1,263 — 1,263 
Restricted Stock Surrenders - Tax Obligations(33,200)— — — (396)— (396)
Issuance of Preferred Stock, Net of Issuance Costs— — 794,702 1 81,211 — 81,212 
Net Income— — — — — 368,286 368,286 
March 31, 202040,580,318 $406 2,294,702 $2 $1,513,516 $(504,917)$1,009,007 
__________
*Adjusted for the 1-for-10 reverse stock split. See Note 5.

The accompanying notes are an integral part of these condensed financial statements.

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NOTES TO CONDENSED FINANCIAL STATEMENTS
MARCH 31, 2021
(UNAUDITED)

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 in the United States. The Company’s primary strategy is investing in non-operated minority working and mineral interests in oil and gas properties in the United States.


NOTE 2     BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The financial information included herein is unaudited. The balance sheet as of December 31, 2020 has been derived from the Company’s audited financial statements for the year ended December 31, 2020. However, such information includes all adjustments (consisting of normal recurring adjustments and change in accounting principles) that are, in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods. The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year.

Certain information, accounting policies, and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”).  The condensed financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2020, which were included in the Company’s 2020 Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

Reverse Stock Split

On September 18, 2020, the Company effected a 1-for-10 reverse stock split of its common stock. Unless otherwise noted, impacted amounts and share information included in the financial statements and notes thereto, and elsewhere in this Form 10-Q, have been retroactively adjusted as if the reverse stock split occurred on the first day of the first period presented. Certain amounts may be slightly different than previously reported due to the settlement of fractional shares as a result of the reverse stock split and rounding. See Note 5 below for more information regarding the reverse stock split.

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, which includes limited control over future development plans as a non-operator, 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 crude oil and natural gas properties, asset retirement obligations and deferred income taxes.  Actual results may differ from those estimates.

The Company considered the impact of the novel coronavirus 2019 (“COVID-19”) pandemic on the assumptions and estimates used by management in the unaudited condensed financial statements for the reporting periods presented. Management’s estimates and assumptions were based on historical data and consideration of future market conditions. Given the uncertainty inherent in any projection, which is heightened by the possibility of unforeseen additional impacts from the COVID-19 pandemic, actual results may differ from the estimates and assumptions used, and conditions may change, which could materially affect amounts reported in the unaudited condensed financial statements in the near term.

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Adopted and Recently Issued Accounting Pronouncements

In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes, 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 adopted the new standard on January 1, 2021 on a prospective basis, which did not have a material impact on its financial position, results of operations, or cash flows.

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform, which provides temporary optional guidance to companies impacted by the transition away from the London Interbank Offered Rate (LIBOR). The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging
relationships, and other transactions that reference LIBOR as a benchmark rate are modified. This amendment is effective upon issuance and expires on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition and this ASU on the Company’s condensed financial statements.

Revenue Recognition

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 crude 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 contract 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 three months ended March 31, 2021 and 2020, 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 substantially all of the Company’s revenue comes from one geographic area, the Williston Basin in the United States, primarily in North Dakota and Montana. Oil sales for the three months ended March 31, 2021 and 2020 were $135.6 million and $116.3 million, respectively. Natural gas and NGL sales for the three months ended March 31, 2021 and 2020 were $21.7 million and $13.9 million, respectively.

Concentrations of Market, Credit Risk and Other Risks

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
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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, economic disruptions resulting from the COVID-19 pandemic, 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.

As a non-operator, 100% of the Company’s wells are operated by third-party operating partners. As a result, the Company is highly dependent on the success of these third-party operators. If they are not successful in the development, exploitation, production and exploration activities relating to the Company’s leasehold interests, or are unable or unwilling to perform, the Company’s financial condition and results of operation could be adversely affected. These risks are heightened in a low commodity price environment, which may present significant challenges to these third-party operators. The Company’s third-party operators will make decisions in connection with their operations that may not be in the Company’s best interests, and the Company may have little or no ability to exercise influence over the operational decisions of its third-party operators. For the three months ended March 31, 2021, the Company’s top four operators made up 55% of total oil and gas sales, compared to 53% for the three months ended March 31, 2020.

The Company faces concentration risk due to the fact that substantially all of its oil and natural gas properties are located in North Dakota, Montana and (after the closing of the Reliance Acquisition described in Note 12) Pennsylvania. As a result, the Company is disproportionately exposed to risks affecting these geographic areas of operations.

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.

Net Income (Loss) Per Common Share

Basic earnings per share (“EPS”) are computed by dividing net income (loss) attributable 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) attributable to common stockholders 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 or warrants 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 the treasury stock or if-converted method.

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three months ended March 31, 2021 and 2020 are as follows:
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 Three Months Ended
March 31,
(In thousands, except share and per share data)20212020
Net Income (Loss)$(90,357)$368,286 
Less: Cumulative Dividends on Preferred Stock(3,830)(3,729)
Net Income (Loss) Attributable to Common Stock$(94,188)$364,557 
Weighted Average Common Shares Outstanding:
Weighted Average Common Shares Outstanding – Basic54,538,099 40,366,253 
Plus: Dilutive Effect of Restricted Stock 35,470 
Plus: Dilutive Effect of Preferred Shares 9,319,541 
Weighted Average Common Shares Outstanding – Diluted54,538,099 49,721,264 
Net Income (Loss) per Common Share:
Basic$(1.73)$9.03 
Diluted$(1.73)$7.33 
Shares Excluded from EPS Due to Anti-Dilutive Effect:
Restricted Stock120,039 143,818 
Preferred Stock9,881,580  

Supplemental Cash Flow Information

The following reflects the Company’s supplemental cash flow information:
Three Months Ended March 31,
(In thousands)20212020
Supplemental Cash Items:
Cash Paid During the Period for Interest, Net of Amount Capitalized$12,525 $15,990 
Cash Paid During the Period for Income Taxes  
Non-cash Investing Activities:
Oil and Natural Gas Properties Included in Accounts Payable and Accrued Liabilities91,072 143,220 
Capitalized Asset Retirement Obligations205 259 
Compensation Capitalized on Oil and Gas Properties147 184 
Non-cash Financing Activities:
Issuance of Preferred Stock for 2L Notes Repurchase 81,212 


NOTE 3     CRUDE OIL AND NATURAL GAS PROPERTIES

The Company 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.

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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 Company did not have any impairment of its proved oil and gas properties for the three months ended March 31, 2021 and 2020, respectively.

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 condensed 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.

2021 Acquisitions

The Company acquired oil and natural gas properties, through a number of independent transactions, for a total of $4.4 million during the three months ended March 31, 2021. These amounts include $1.8 million of associated development costs.

See Note 12 regarding the Reliance Acquisition, which the Company closed on April 1, 2021.

2020 Acquisitions

The Company acquired oil and natural gas properties, through a number of independent transactions, for a total of $25.5 million during the three months ended March 31, 2020. These amounts include $18.4 million of development costs that occurred prior to the closings of the acquisitions.

Unproved Properties

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 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, which includes leases that have expired or have been deemed uneconomic, 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 three months ended March 31, 2021 and 2020, unproved properties of $0.2 million and $1.7 million, respectively, were impaired.







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NOTE 4     LONG-TERM DEBT

The Company’s long-term debt consisted of the following as of the dates indicated:

(In thousands)March 31, 2021December 31, 2020
Revolving Credit Facility$263,000 $532,000 
Unsecured Notes due 2028550,000  
Second Lien Notes due 202315,669 287,755 
Unsecured VEN Bakken Note due 2022 130,000 
Total principal828,669 949,755 
Unamortized debt discounts and premiums140 2,041 
Unamortized debt issuance costs(1)
(11,748)(6,953)
Total debt817,061 944,843 
Less current portion of long-term debt (65,000)
Total long-term debt$817,061 $879,843 
________________
(1)Debt issuance costs related to the Company’s revolving credit facility of $6.1 million and $6.5 million as of March 31, 2021 and December 31, 2020, respectively, are recorded in “Other Noncurrent Assets, Net” on the balance sheets.

2021 First Quarter Refinancing Transactions

During the three months ended March 31, 2021, the Company completed a series of financing transactions related to its debt arrangements, which are summarized as follows:

completed a common stock offering with net proceeds of $132.9 million, which was primarily intended to finance the cash purchase price for the Reliance Acquisition (see Note 12) that closed on April 1, 2021, but in the interim reduced the Company’s outstanding indebtedness;
issued $550.0 million in aggregate principal amount of new 8.125% senior unsecured notes due 2028 (the “2028 Notes”), priced at par, with estimated net proceeds of $538.4 million;
fully repaid and retired all $130.0 million in principal amount of the Company’s 6.0% senior unsecured promissory note due 2022 (the “Unsecured VEN Bakken Note”);
redeemed and retired $272.1 million in aggregate principal amount of the Company’s 8.500% senior secured second lien notes due 2023 (the “Second Lien Notes”) pursuant to a cash tender offer at a cost of $280.2 million including premiums; and
reduced the amount of borrowings outstanding under the Revolving Credit Facility (defined below) from $532.0 million as of December 31, 2020 to $263.0 million as of March 31, 2021.

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.

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 March 31, 2021 was $660.0 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.
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The Revolving Credit Facility contains negative covenants that limit the Company’s ability, among other things, to pay dividends, incur additional indebtedness, maintain excess cash liquidity, 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 is in compliance with these financial covenants as of March 31, 2021.

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 90% 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.

Unsecured Notes due 2028

On February 18, 2021, the Company and Wilmington Trust, National Association, as trustee, entered into an indenture (the “2028 Notes Indenture”), pursuant to which the Company issued $550.0 million in aggregate principal amount of the 2028 Notes. The proceeds were used to refinance existing indebtedness, pay a portion of the cash purchase price for the Reliance Acquisition (see Note 12) that closed on April 1, 2021, and for general corporate purposes. The 2028 Notes will mature on March 1, 2028. Interest on the 2028 Notes is payable semi-annually in arrears on each March 1 and September 1, commencing September 1, 2021, to holders of record on the February 15 and August 15 immediately preceding the related interest payment date, at a rate of 8.125% per annum.

Prior to March 1, 2024, the Company may redeem all or a part of the 2028 Notes at a redemption price equal to 100% of the principal amount of the 2028 Notes redeemed, plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On or after March 1, 2024, the Company may redeem all or a part of the 2028 Notes at redemption prices (expressed as percentages of principal amount) equal to 104.063% for the twelve-month period beginning on March 1, 2024, 102.031% for the twelve-month period beginning on March 1, 2025, and 100% beginning on March 1, 2026, plus accrued and unpaid interest to the redemption date.

The 2028 Notes Indenture contains covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries, if any, to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends or distributions in respect of equity interests or redeem, repurchase or retire equity securities or subordinated indebtedness; (iii) transfer or sell certain assets; (iv) make investments; (v) create liens to secure indebtedness; (vi) enter into agreements that restrict dividends or other payments from any non-guarantor subsidiary to the Company; (vii) consolidate with or merge with or into, or sell substantially all of the Company’s assets to, another person; (viii) enter into transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications, and many of these covenants will be terminated if the 2028 Notes achieve an investment grade rating from either Moody’s Investors Services, Inc. or S&P Global Ratings.

The 2028 Notes Indenture contains customary events of default, including, but not limited to: (i) default for 30 days in the payment when due of interest on the 2028 Notes; (ii) default in payment when due of the principal of, or premium, if any, on the 2028 Notes; (iii) failure by the Company or certain of its subsidiaries, if any, to comply with certain of their respective obligations, covenants or agreements contained in the 2028 Notes or the 2028 Notes Indenture, subject to certain notice and grace periods; (iv) failure by the Company or any of its restricted subsidiaries to pay indebtedness within any applicable grace period or the acceleration of any such indebtedness if the total amount of such indebtedness exceeds $35.0 million; (v) failure by the Company or any of its restricted subsidiaries that is a Significant Subsidiary (as defined in the 2028 Notes Indenture) to pay final non-appealable judgments aggregating in excess of $35.0 million, which judgments are not paid, discharged or stayed
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for a period of 60 days; (vi) except as permitted by the 2028 Notes Indenture, any guarantee of the 2028 Notes is held in any judicial proceeding to be unenforceable or invalid, or ceases for any reason to be in full force and effect, or is denied or disaffirmed by a Guarantor (as defined in the 2028 Notes Indenture); and (vii) certain events of bankruptcy or insolvency described in the 2028 Notes Indenture with respect to the Company and its restricted subsidiaries that are Significant Subsidiaries.

Second Lien Notes due 2023

In May 2018, the Company issued 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. In addition, as of and through March 31, 2021, 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.

During 2019, the Company repurchased and retired $10.1 million in aggregate principal amount of Second Lien Notes in open market transactions. In November 2019, the Company completed a cash tender offer to redeem and repay $200.0 million principal amount of Second Lien Notes. Also in November 2019, the Company redeemed and repaid $70.8 million principal amount of Second Lien Notes in exchange for shares of Series A Preferred Stock.

During 2020, the Company repurchased and retired $13.5 million in aggregate principal amount of Second Lien Notes in open market transactions for cash. During 2020, the Company also repurchased and retired $116.5 million in aggregate principal amount of Second Lien Notes pursuant to a number of independent, separately negotiated agreements in exchange for aggregate consideration consisting primarily of shares of Series A Preferred Stock and common stock.

During the three months ended March 31, 2021, the Company completed a cash tender offer (the “Tender Offer”) pursuant to which it redeemed and retired $272.1 million in aggregate principal amount of the Second Lien Notes. Immediately thereafter, there was $15.7 million in aggregate principal amount of Second Lien Notes remaining outstanding, which the Company intends to redeem and retire on or about May 15, 2021.

In connection with the Tender Offer, the Company also obtained the consent of holders to amend the indenture governing the Second Lien Notes (the “2L Indenture”). As a result, on February 18, 2021, the Company entered into the Fourth Supplemental Indenture (the “Fourth Supplemental Indenture”) with Wilmington Trust, National Association, as trustee and as collateral agent, which, among other things, amended the 2L Indenture to eliminate substantially all restrictive covenants and certain of the default provisions contained therein.

Unsecured VEN Bakken Note

On July 1, 2019, the Company issued a 6.0% unsecured promissory note due July 1, 2022, in the aggregate principal amount of $130.0 million to VEN Bakken, LLC in connection with the Company’s acquisition of certain oil and gas properties from VEN Bakken, LLC. Fifty percent (50%) of the original principal amount of the Unsecured VEN Bakken Note was required to be repaid by the Company on or before January 1, 2021, and the remaining unpaid principal amount was 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, was due quarterly in arrears on the first day of each calendar quarter, commencing on October 1, 2019. The Unsecured VEN Bakken Note did not include any financial maintenance covenants and is unsecured.

On January 4, 2021, the Company repaid $65.0 million in aggregate principal amount under the Unsecured VEN Bakken Note, which was a scheduled repayment thereunder. On February 18, 2021, the Company used a portion of the proceeds from the 2028 Notes to repay the remaining $65.0 million in aggregate principal amount outstanding under the Unsecured VEN Bakken Note, and as a result the note has been retired in full.



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NOTE 5    COMMON AND PREFERRED STOCK

Common Stock

On September 18, 2020, the Company effected a 1-for-10 reverse stock split of the Company’s issued and outstanding shares of common stock (the “Reverse Stock Split”). The Company’s common stock began trading on a split‑adjusted basis when the market opened on September 21, 2020. As a result of the Reverse Stock Split, every ten shares of the Company’s issued and outstanding common stock automatically converted into one share of common stock, without any change in the par value per share. A total of 44,663,990 shares of common stock were issued and outstanding immediately after the Reverse Stock Split became effective on September 18, 2020. No fractional shares were outstanding following the Reverse Stock Split.

In connection with the Reverse Stock Split, the number of authorized shares of the Company’s common stock was reduced to 135,000,000 shares of common stock, par value $0.001 per share. As of March 31, 2021, the Company had 60,361,547 shares of common stock issued and outstanding.

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 March 31, 2021, the Company had 2,218,732 shares of preferred stock issued and outstanding, 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 March 31, 2021, no dividends had been declared or paid, and there were $20.1 million of undeclared accumulated dividends on the Series A Preferred Stock. On April 23, 2021, the Company declared a dividend in the amount of $9.9163 per share to be paid on May 15, 2021 to the holders of record of the Series A Preferred Stock as of May 1, 2021. This dividend, which totals $22.0 million in the aggregate, is inclusive of all accrued and unpaid dividends from the original issue date of the Series A Preferred Stock.

The Reverse Stock Split did not affect the number of authorized or issued and outstanding shares of the Company’s preferred stock, nor the liquidation per share preference. As a result of the Reverse Stock Split and per the terms of the Certificate of Designations, the conversion rate for the Company’s outstanding Series A Preferred Stock was automatically decreased to 4.363 shares of common stock for each share of Series A Preferred Stock (previously it was 43.63 shares of common stock). The effect of the Reverse Stock Split resulted in the Company recalculating its historical, basic and diluted EPS to reflect the 1-for-10 reverse stock split, effective September 18, 2020.

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 March 31, 2021, the conversion rate was 4.363 shares of common stock for each share of Series A Preferred Stock (which is equivalent to a conversion price of approximately $22.92 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.

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2021 Activity

Common Stock

On February 9, 2021, the Company closed an underwritten public offering (the “Equity Offering”) of 14,375,000 shares of its common stock at a price to the public of $9.75 per share. The Equity Offering resulted in net proceeds of approximately $132.9 million, after deducting underwriting discounts and commissions and estimated offering expenses.

During the three months ended March 31, 2021, 60,529 shares of common stock were surrendered by certain employees of the Company to cover tax obligations in connection with their restricted stock awards.  The total value of these shares was approximately $0.8 million, which is based on the market prices on the dates the shares were surrendered.

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.

During the three months ended March 31, 2021 and March 31, 2020, 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 maintains its 2018 Equity Incentive Plan (the “2018 Plan”), which replaced the Company’s prior 2013 Incentive Plan (the “2013 Plan”), for making equity-based awards to employees, directors and other eligible persons. 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 March 31, 2021, there were 769,755 shares available for future awards under the 2018 Plan.

In connection with the Reverse Stock Split (see Note 5), the Company reduced the number of shares of common stock available for issuance under the Company’s equity incentive plans in proportion to the Reverse Stock Split ratio of 1-for-10. The Reverse Stock Split also reduced the number of shares of common stock issuable upon the vesting of its RSAs in proportion to the Reverse Stock Split ratio of 1-for-10 and caused a proportionate increase in share-based performance criteria applicable to such awards. The Reverse Stock Split has no impact on Net Income (Loss) or total Stockholders’ Equity and for the three months ended March 31, 2021 and 2020.

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 expenses” 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 in 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.
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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 following table reflects the outstanding RSAs and activity related thereto for the three months ended March 31, 2021:

Service-based AwardsService and Performance-based AwardsService and Market-based AwardsService, Performance, and Market-based Awards
Number of SharesWeighted-average Grant Date Fair ValueNumber of SharesWeighted-average Grant Date Fair ValueNumber of SharesWeighted-average Grant Date Fair ValueNumber of SharesWeighted-average Grant Date Fair Value
Outstanding at December 31, 2020268,602 $10.44 16,250 $27.00 5,245 $16.70 39,200 $9.80 
Shares granted138,297 11.76       
Shares forfeited        
Shares vested(91,071)10.60 (16,250)27.00 (5,245)16.70 (19,600)9.80 
Outstanding at March 31, 2021315,828 $10.97  $  $ 19,600 $9.80 

At March 31, 2021, there was $3.8 million of total unrecognized compensation expense related to unvested RSAs. That cost is expected to be recognized over a weighted average period of 1.2 years. For the three months ended March 31, 2021 and 2020, the total fair value of the Company’s restricted stock awards vested was $1.8 million and $1.2 million, respectively.


NOTE 7     RELATED PARTY TRANSACTIONS

The Company’s Audit Committee is responsible for approving all transactions involving related parties.


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 $4.3 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 $4.3 million in accounts receivable is included in “Other Noncurrent Assets, Net” in the condensed balance sheets. The Company fully maintains the validity of its interests in the crude oil and natural gas leases.



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NOTE 9     INCOME TAXES

Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The provision for income taxes for the three months ended March 31, 2021 and 2020 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income due to the recognition of a full valuation allowance during both the three months ended March 31, 2021 and 2020, respectively.

In assessing the realizability of deferred tax assets (“DTAs”), management considers whether it is more likely than not that some portion, or all, of the Company’s DTAs will not be realized. In making such determination, the Company considers 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. If the Company concludes that it is more likely than not that some portion, or all, of its DTAs will not be realized, the tax asset is reduced by a valuation allowance. The Company assesses the appropriateness of its valuation allowance on a quarterly basis. At March 31, 2021 and December 31, 2020, the Company maintains a full valuation allowance on its net DTAs.


NOTE 10     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 March 31, 2021 and December 31, 2020:

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 Fair Value Measurements at March 31, 2021 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 Assets$ $2,005 $ 
Commodity Derivatives – Noncurrent Assets 356  
Commodity Derivatives – Current Liabilities (34,508) 
Commodity Derivatives – Noncurrent Liabilities (61,808) 
Interest Rate Derivatives – Current Liabilities (600) 
Interest Rate Derivatives – Noncurrent Liabilities (179) 
Total$ $(94,734)$ 
 Fair Value Measurements at December 31, 2020 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 Assets$ $51,290 $ 
Commodity Derivatives – Current Liabilities (2,504) 
Commodity Derivatives – Noncurrent Assets 111  
Commodity Derivatives – Noncurrent Liabilities (14,214) 
Interest Rate Derivatives – Current Liabilities (574) 
Interest Rate Derivatives – Noncurrent Liabilities (445) 
Total$ $33,664 $ 

Commodity Derivatives. The Level 2 instruments presented in the tables above consist of commodity derivative instruments (see Note 11).  The fair value of the Company’s commodity derivative 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 commodity derivative contracts is reflected in the condensed balance sheet.  The current derivative asset and liability amounts represent the fair values expected to be settled in the subsequent twelve months.

Interest Rate Derivatives. The Level 2 instruments presented in the tables above consist of interest rate derivative instruments (see Note 11).  The fair value of the Company’s interest rate derivative instruments is determined based upon contracted notional amounts, active market-quoted LIBOR yield curves, and time to maturity, among other things. Counterparty statements are utilized to determine the value of the interest rate 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 interest rate derivative contracts is reflected in the condensed balance sheet.  The current derivative asset and liability amounts represent the fair values expected to be settled in the subsequent twelve months.

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 in 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 was
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$16.0 million and $256.1 million at March 31, 2021 and December 31, 2020, respectively. The fair value of the Company’s 2028 Notes was $547.3 million at March 31, 2021. The fair value of the Company’s Second Lien Notes and 2028 Notes are based on active market quotes, which represent Level 1 inputs.

There is no active market for the Revolving Credit Facility. 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 measurement for the Revolving Credit Facility represents a Level 2 input.

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 three months ended March 31, 2021 were approximately $0.2 million.

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 three months ended March 31, 2021.


NOTE 11     DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

The Company utilizes commodity price swaps, basis swaps, swaptions and call options to (i) reduce the effects of volatility in price changes on the crude oil and natural gas 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. In addition, from time to time the Company utilizes interest rate swaps to mitigate exposure to changes in interest rates on the Company’s variable-rate indebtedness.

All derivative instruments are recorded in the Company’s balance sheet as either assets or liabilities measured at their fair value (see Note 10).  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 Company’s condensed 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 Company has master netting agreements on individual derivative instruments with certain counterparties and therefore the current asset and liability are netted in the balance sheet and the non-current asset and liability are netted in the balance sheet for contracts with these counterparties.

Commodity Derivative Instruments

The following table presents settlements on commodity derivative instruments and unsettled gains and losses on open commodity derivative instruments for the periods presented which is recorded in the revenue section of our condensed financial statements:

 Three Months Ended
March 31,
(In thousands)20212020
Gain (Loss) on Settled Commodity Derivatives$(7,297)$31,506 
Gain (Loss) on Unsettled Commodity Derivatives(128,638)345,075 
Gain (Loss) on Commodity Derivatives, Net$(135,935)$376,581 

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The following table summarizes open commodity derivative positions as of March 31, 2021, for commodity derivatives that were entered into through March 31, 2021, for the settlement period presented:

2021202220232024
Oil:
WTI NYMEX - Swaps:
Volume (Bbl) 6,350,574 4,218,250 112,500  
Weighted-Average Price ($/Bbl)$54.80 $51.66 $51.65 $ 
WTI NYMEX - Swaptions(1):
Volume (Bbl)  1,496,125 3,691,000  
Weighted-Average Price ($/Bbl)$ $50.13 $50.31 $ 
Bakken Crude UHC to WTI NYMEX - Basis Swaps:
Volume (Bbl)4,155,800    
Weighted-Average Price ($/Bbl)$(2.40)$ $ $ 
WTI NYMEX - Call Options(1):
Volume (Bbl)  365,000 1,275,000 
Weighted-Average Price ($/Bbl)$ $ $55.00 $52.89 
Natural Gas:
Henry Hub NYMEX - Swaps:
Volume (MMBtu) 22,637,745 5,450,000