Company Quick10K Filing
Northern Oil & Gas
Price1.98 EPS1
Shares404 P/E3
MCap801 P/FCF3
Net Debt1,144 EBIT309
TTM 2019-09-30, in MM, except price, ratios
10-Q 2020-03-31 Filed 2020-05-11
10-K 2019-12-31 Filed 2020-03-12
10-Q 2019-09-30 Filed 2019-11-12
10-Q 2019-06-30 Filed 2019-08-05
10-Q 2019-03-31 Filed 2019-05-10
10-K 2018-12-31 Filed 2019-03-18
10-Q 2018-09-30 Filed 2018-11-09
10-Q 2018-06-30 Filed 2018-08-09
10-Q 2018-03-31 Filed 2018-05-07
10-K 2017-12-31 Filed 2018-02-23
10-Q 2017-09-30 Filed 2017-11-09
10-Q 2017-06-30 Filed 2017-08-09
10-Q 2017-03-31 Filed 2017-05-08
10-K 2016-12-31 Filed 2017-03-02
10-Q 2016-09-30 Filed 2016-11-09
10-Q 2016-06-30 Filed 2016-08-05
10-Q 2016-03-31 Filed 2016-05-10
10-K 2015-12-31 Filed 2016-03-03
10-Q 2015-09-30 Filed 2015-11-05
10-Q 2015-06-30 Filed 2015-08-06
10-Q 2015-03-31 Filed 2015-05-08
10-K 2014-12-31 Filed 2015-02-27
10-Q 2014-09-30 Filed 2014-11-07
10-Q 2014-06-30 Filed 2014-08-08
10-Q 2014-03-31 Filed 2014-05-09
10-K 2013-12-31 Filed 2014-03-03
10-Q 2013-09-30 Filed 2013-11-08
10-Q 2013-06-30 Filed 2013-08-09
10-Q 2013-03-31 Filed 2013-05-07
10-K 2012-12-31 Filed 2013-03-01
10-Q 2012-09-30 Filed 2012-11-08
10-Q 2012-06-30 Filed 2012-08-09
10-Q 2012-03-31 Filed 2012-05-07
10-K 2011-12-31 Filed 2012-02-29
10-Q 2011-09-30 Filed 2011-11-09
10-Q 2011-06-30 Filed 2011-08-09
10-Q 2011-03-31 Filed 2011-05-10
10-K 2010-12-31 Filed 2011-03-04
10-Q 2010-11-08 Filed 2010-11-08
10-Q 2010-08-09 Filed 2010-08-09
10-Q 2010-05-06 Filed 2010-05-06
10-K 2009-12-31 Filed 2010-03-08
8-K 2020-07-30 Sale of Shares, Regulation FD, Exhibits
8-K 2020-07-08 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2020-07-02 Regulation FD, Exhibits
8-K 2020-06-22
8-K 2020-06-12
8-K 2020-06-01
8-K 2020-05-21
8-K 2020-05-13
8-K 2020-05-11
8-K 2020-05-04
8-K 2020-03-16
8-K 2020-03-12
8-K 2020-02-20
8-K 2020-01-15
8-K 2020-01-15
8-K 2019-12-30
8-K 2019-12-17
8-K 2019-11-21
8-K 2019-11-08
8-K 2019-10-30
8-K 2019-10-22
8-K 2019-09-04
8-K 2019-08-01
8-K 2019-07-31
8-K 2019-07-24
8-K 2019-07-16
8-K 2019-07-01
8-K 2019-06-28
8-K 2019-06-03
8-K 2019-05-23
8-K 2019-05-09
8-K 2019-04-18
8-K 2019-03-12
8-K 2019-03-07
8-K 2019-02-28
8-K 2019-01-22
8-K 2018-12-31
8-K 2018-12-12
8-K 2018-11-08
8-K 2018-10-05
8-K 2018-09-25
8-K 2018-09-21
8-K 2018-09-21
8-K 2018-09-19
8-K 2018-09-14
8-K 2018-09-11
8-K 2018-08-23
8-K 2018-08-07
8-K 2018-08-06
8-K 2018-07-27
8-K 2018-07-17
8-K 2018-07-09
8-K 2018-07-05
8-K 2018-06-20
8-K 2018-06-18
8-K 2018-06-12
8-K 2018-06-04
8-K 2018-06-01
8-K 2018-05-24
8-K 2018-05-15
8-K 2018-05-09
8-K 2018-05-08
8-K 2018-05-07
8-K 2018-04-26
8-K 2018-04-05
8-K 2018-04-02
8-K 2018-03-20
8-K 2018-03-18
8-K 2018-03-18
8-K 2018-02-26
8-K 2018-02-22
8-K 2018-01-31

NOG 10Q Quarterly Report

Part I - Financial Information
Item 1. Condensed Financial Statements.
Note 1 Organization and Nature of Business
Note 2 Basis of Presentation and Significant Accounting Policies
Note 3 Crude Oil and Natural Gas Properties
Note 4 Long - Term Debt
Note 5 Common and Preferred Stock
Note 6 Stock - Based Compensation
Note 7 Related Party Transactions
Note 8 Commitments & Contingencies
Note 9 Income Taxes
Note 10 Fair Value
Note 11 Derivative Instruments and Price Risk Management
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.
EX-10.1 mikekelly-employmentag.htm
EX-31.1 exhibit31120200331-10q.htm
EX-31.2 exhibit31220200331-10q.htm
EX-32.1 exhibit32120200331-10q.htm

Northern Oil & Gas Earnings 2020-03-31

Balance SheetIncome StatementCash Flow
Assets, Equity
Rev, G Profit, Net Income
Ops, Inv, Fin

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For the quarterly period ended March 31, 2020
 For the transition period from ____________ to____________
Commission File No. 001-33999
(Exact Name of Registrant as Specified in Its Charter)
(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)
(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 7, 2020, there were 405,793,741 shares of our common stock, par value $0.001, outstanding.

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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.


Table of Contents

March 31, 2020


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
Item 1.Legal Proceedings
Item 1A.Risk Factors
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds
Item 6.Exhibits


Table of Contents
Item 1. Condensed Financial Statements.

(In thousands, except par value and share data)March 31, 2020December 31, 2019
Current Assets:  
Cash and Cash Equivalents$8,512  $16,068  
Accounts Receivable, Net97,580  108,274  
Advances to Operators567  893  
Prepaid Expenses and Other2,216  1,964  
Derivative Instruments245,552  5,628  
Income Tax Receivable420  210  
Total Current Assets354,847  133,037  
Property and Equipment:  
Oil and Natural Gas Properties, Full Cost Method of Accounting  
Proved4,265,534  4,178,605  
Unproved10,846  11,047  
Other Property and Equipment2,156  2,157  
Total Property and Equipment4,278,536  4,191,809  
Less – Accumulated Depreciation, Depletion and Impairment(2,504,735) (2,443,216) 
Total Property and Equipment, Net1,773,801  1,748,593  
Derivative Instruments94,329  8,554  
Deferred Income Taxes  210  
Other Noncurrent Assets, Net14,409  15,071  
Total Assets$2,237,386  $1,905,465  
Current Liabilities:  
Accounts Payable$58,447  $69,395  
Accrued Liabilities101,302  110,374  
Accrued Interest9,308  11,615  
Derivative Instruments130  11,298  
Current Portion of Long-term Debt65,000    
Other Current Liabilities891  795  
Total Current Liabilities235,078  203,477  
Long-term Debt975,282  1,118,161  
Derivative Instruments547  8,079  
Asset Retirement Obligations17,198  16,759  
Other Noncurrent Liabilities273  345  
TOTAL LIABILITIES$1,228,379  $1,346,822  

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Preferred Stock, Par Value $.001; 5,000,000 Shares Authorized;
2,294,702 Series A Shares Outstanding at 3/31/2020
1,500,000 Series A Shares Outstanding at 12/31/2019
2  2  
Common Stock, Par Value $.001; 675,000,000 Shares Authorized;
 405,803,181 Shares Outstanding at 3/31/2020
 406,085,183 Shares Outstanding at 12/31/2019
406  406  
Additional Paid-In Capital1,513,516  1,431,438  
Retained Deficit(504,917) (873,203) 
Total Stockholders’ Equity1,009,007  558,643  

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

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Three Months Ended
March 31,
(In thousands, except share and per share data)20202019
Oil and Gas Sales$130,196  $132,684  
Gain (Loss) on Commodity Derivatives, Net376,581  (139,623) 
Other Revenue8  5  
Total Revenues506,785  (6,934) 
Production Expenses37,335  24,666  
Production Taxes11,896  12,520  
General and Administrative Expense4,871  6,051  
Depletion, Depreciation, Amortization and Accretion61,809  45,134  
Total Operating Expenses115,911  88,371  
Interest Expense, Net of Capitalization(16,551) (19,548) 
Gain (Loss) on Unsettled Interest Rate Derivatives, Net(677)   
Loss on Extinguishment of Debt(5,527)   
Debt Exchange Derivative Gain  6,287  
Contingent Consideration Gain  1,392  
Other Income  12  
Total Other Income (Expense)(22,755) (11,857) 
NET INCOME (LOSS)$368,286  $(107,162) 
Net Income (Loss) Per Common Share – Basic$0.90  $(0.29) 
Net Income (Loss) Per Common Share – Diluted$0.74  $(0.29) 
Weighted Average Shares Outstanding – Basic403,662,541  371,448,566  
Weighted Average Shares Outstanding – Diluted497,265,647  371,448,566  
The accompanying notes are an integral part of these condensed financial statements.

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Three Months Ended
March 31,
(In thousands)20202019
Net Income (Loss)$368,286  $(107,162) 
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:  
Depletion, Depreciation, Amortization and Accretion61,809  45,134  
Amortization of Debt Issuance Costs1,461  1,301  
Loss on Extinguishment of Debt5,527    
Amortization of Bond Premium on Long-term Debt(321) (746) 
Deferred Income Taxes210    
(Gain) Loss of Derivative Instruments(344,398) 152,169  
Gain on Debt Exchange Derivative  (6,287) 
Loss on Contingent Consideration  (1,392) 
PIK Interest on Second Lien Notes  1,742  
Stock-Based Compensation Expense1,079  2,751  
Other(57) (21) 
Changes in Working Capital and Other Items:  
Accounts Receivable, Net10,789  5,939  
Prepaid and Other Expenses(251) 178  
Accounts Payable(1,514) 5,783  
Accrued Interest(2,290) 426  
Accrued Liabilities327  (907) 
Net Cash Provided by Operating Activities100,654  98,908  
Drilling and Development Capital Expenditures(78,962) (69,786) 
Acquisition of Oil and Natural Gas Properties(25,537) (8,122) 
Purchases of Other Property and Equipment  (5) 
Net Cash Used for Investing Activities(104,500) (77,913) 
Advances on Revolving Credit Facility25,000  53,000  
Repayments on Revolving Credit Facility(15,000) (46,000) 
Repurchases of Second Lien Notes(13,277)   
Debt Issuance Costs Paid(37) (70) 
Debt Exchange Derivative Settlements  (894) 
Contingent Consideration Settlements  (9,778) 
Repurchases of Common Stock  (15,108) 
Restricted Stock Surrenders - Tax Obligations(396) (558) 
Net Cash Used for Financing Activities(3,710) (19,409) 
The accompanying notes are an integral part of these condensed financial statements.

Table of Contents

(In thousands, except share data)Common StockPreferred StockAdditional Paid-InRetained
Total Stockholders’
December 31, 2019406,085,183  $406  1,500,000  $2  $1,431,438  $(873,203) $558,643  
Issuance of Common Stock50,000    —  —  —  —    
Share Based Compensation—  —  —  —  1,263  —  1,263  
Restricted Stock Surrenders - Tax Obligations(332,002) —  —  —  (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, 2020405,803,181  $406  2,294,702  $2  $1,513,516  $(504,917) $1,009,007  

 Common StockPreferred StockAdditional Paid-InRetained
Total Stockholders’
(In thousands, except share data)SharesAmountSharesAmountCapital(Deficit)(Deficit)
December 31, 2018378,333,070  $378    $  $1,226,371  $(796,884) $429,865  
Issuance of Common Stock3,160,200  3  —  —  —  —  3  
Restricted Stock Forfeitures(4,802) —  —  —  —  —    
Stock-Based Compensation—  —  —  —  2,832  —  2,832  
Restricted Stock Surrenders - Tax Obligations(220,531) —  —  —  (558) —  (558) 
Repurchases of Common Stock(5,635,003) (6) —  —  (15,102) —  (15,108) 
Contingent Consideration Settlements1,167,544  1  —  —  2,886  —  2,887  
Net Loss—  —  —  —  —  (107,162) (107,162) 
March 31, 2019376,800,478  $377    $  $1,216,429  $(904,046) $312,760  

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

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MARCH 31, 2020


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.

For the three months ended March 31, 2020, crude oil accounted for 79% of the Company’s total production and 89% of its oil and gas sales.


Basis of Presentation

The financial information included herein is unaudited. The balance sheet as of December 31, 2019 has been derived from the Company’s audited financial statements for the year ended December 31, 2019. 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, 2019, which were included in the Company’s 2019 Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

Revenues, expenses, cash flows, assets and liabilities can and do vary during each quarter of the year. Additionally, in March 2020, the World Health Organization declared novel coronavirus 2019 (“COVID-19”) a pandemic. The broader implication of COVID-19 on our results of operations and overall financial performance remains uncertain. We may experience various effects that could materially adversely impact our business, financial condition, results of operations and overall financial performance in future periods.

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.

Adopted and Recently Issued Accounting Pronouncements

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Financial Instruments - Credit Losses (Topic 326) - Measurement of credit losses on financial instruments, which requires a company immediately recognize management’s current estimated credit losses (“CECL”) for all financial instruments that are not accounted for at fair value through net income. Previously, credit losses on financial assets were only required to be

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recognized when they were incurred. The Company adopted ASU 2016-13 on January 1, 2020. The guidance did not have a significant impact on the condensed financial statements or notes accompanying the condensed financial statements.

In August 2018, the FASB issued ASU No. 2018-13, Fair value measurement (Topic 820) - Disclosure framework - Changes to the disclosure requirements for fair value measurement, which modifies the disclosure requirements on fair value measurements in Topic 820. The Company adopted ASU 2018-13 on January 1, 2020. The guidance did not have a significant impact on the condensed financial statements or notes accompanying the condensed financial statements.

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 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.

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 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.

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, 2020 and 2019, 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 three months ended March 31, 2020 and 2019 were $116.3 million and $123.6 million, respectively. Natural gas and NGL sales for the three months ended March 31, 2020 and 2019 were $13.9 million and $9.1 million, respectively.

Concentrations of Market, Credit 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 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

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Company’s financial condition and results of operation could be adversely affected. These risks are heightened in the current 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, 2020, the Company’s top four operators made up 53% of total oil and gas sales, compared to 59% for the three months ended March 31, 2019.

The Company faces concentration risk due to the fact that all of its oil and natural gas properties are located in the Williston Basin, primarily in North Dakota and Montana. As a result, the Company is disproportionately exposed to risks affecting its single geographic area 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) 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.

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three months ended March 31, 2020 and 2019 are as follows:

 Three Months Ended
March 31,
(In thousands, except share and per share data)20202019
Net Income (Loss)$368,286  $(107,162) 
Less: Cumulative Dividends on Preferred Stock(3,729)   
Net Income (Loss) Attributable to Common Stock$364,557  $(107,162) 
Weighted Average Common Shares Outstanding:
Weighted Average Common Shares Outstanding – Basic403,662,541  371,448,566  
Plus: Dilutive Effect of Restricted Stock354,658    
Plus: Dilutive Effect of Preferred Shares93,248,448    
Weighted Average Common Shares Outstanding – Diluted497,265,647  371,448,566  
Net Income (Loss) per Common Share:
Basic$0.90  $(0.29) 
Diluted$0.74  $(0.29) 
Shares underlying Restricted Stock Awards Excluded from EPS Due to Anti-Dilutive Effect143,8181,278,489  


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Supplemental Cash Flow Information

The following reflects the Company’s supplemental cash flow information:

Three Months Ended March 31,
(In thousands)20202019
Supplemental Cash Items:
Cash Paid During the Period for Interest, Net of Amount Capitalized$15,990  $16,929  
Non-cash Investing Activities:
Oil and Natural Gas Properties Included in Accounts Payable and Accrued Liabilities143,220  133,872  
Capitalized Asset Retirement Obligations259  226  
Compensation Capitalized on Oil and Gas Properties184  84  
Non-cash Financing Activities:
Issuance of 8.50% Second Lien Notes due 2023 - PIK Interest
Issuance of Preferred Stock for 2L Notes Repurchase81,212    
Contingent Consideration Settlements  2,887  


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.

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 ceiling test impairment for the three months ended March 31, 2020 and 2019, respectively.

At March 31, 2020, the Company’s impairment review used prices that reflect an average of the trailing 12-month prices as prescribed pursuant to the SEC’s guidelines. The average prices used in the March 31, 2020 impairment review are significantly higher than the actual and currently forecasted prices for 2020. As lower average monthly pricing is reflected in the trailing 12-month average pricing calculation for future fiscal quarters, the present value of the Company’s future net revenues is expected to decline and a material impairment is expected to be recognized. Given the current oil and natural gas pricing environment, the Company expects it will have noncash ceiling test write-downs of its oil and natural gas properties in 2020.

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.


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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.

2019 Acquisitions

The Company acquired oil and natural gas properties, through a number of independent transactions, for a total of $8.4 million during the three months ended March 31, 2019.

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 $315.3 million, consisting of (i) $174.9 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 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$324,974  
  Asset retirement cost2,680  
Total assets acquired327,654  
  Asset retirement obligations(2,680) 
  Derivative instruments(9,694) 
Net assets acquired$315,280  
Fair value of consideration paid for net assets:
  Cash consideration$174,912  
  Issuance of common stock (5.6 million shares at $2.09 per share)
  Unsecured VEN Bakken Note128,660  
Total fair value of consideration transferred$315,280  

Pro Forma Information

The following summarized unaudited pro forma condensed statement of operations information for the three months ended March 31, 2019, assumes that the VEN Bakken Acquisition occurred as of January 1, 2019. There is no pro forma information included for the three months ended March 31, 2020, because the Company’s actual financial results for such period fully reflect this acquisition. 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 the acquisition as of January 1, 2019, or that would be attained in the future.

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