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Table of Contents
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 September 30, 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 PkwySuite 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 November 1, 2021, there were 66,195,089 shares of our common stock, par value $0.001, outstanding.


Table of Contents
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

September 30, 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)September 30, 2021December 31, 2020
Assets(Unaudited)
Current Assets:  
Cash and Cash Equivalents$2,006 $1,428 
Accounts Receivable, Net158,047 71,015 
Advances to Operators5,137 476 
Prepaid Expenses and Other2,393 1,420 
Derivative Instruments 51,290 
Total Current Assets167,583 125,629 
Property and Equipment:  
Oil and Natural Gas Properties, Full Cost Method of Accounting  
Proved4,804,687 4,393,533 
Unproved24,656 10,031 
Other Property and Equipment2,779 2,451 
Total Property and Equipment4,832,122 4,406,015 
Less – Accumulated Depreciation, Depletion and Impairment(3,767,613)(3,670,811)
Total Property and Equipment, Net1,064,509 735,204 
Derivative Instruments 111 
Other Noncurrent Assets, Net11,970 11,145 
Total Assets$1,244,062 $872,089 
Liabilities and Stockholders' Equity (Deficit)
Current Liabilities:  
Accounts Payable$65,912 $35,803 
Accrued Liabilities100,443 68,673 
Accrued Interest4,248 8,341 
Derivative Instruments182,692 3,078 
Contingent Consideration242 493 
Current Portion of Long-term Debt 65,000 
Other Current Liabilities1,635 1,087 
Total Current Liabilities355,172 182,475 
Long-term Debt858,415 879,843 
Derivative Instruments156,731 14,659 
Asset Retirement Obligations27,106 18,366 
Other Noncurrent Liabilities4,349 50 
Total Liabilities$1,401,773 $1,095,393 
Commitments and Contingencies (Note 8)
Stockholders’ Equity (Deficit)  
Preferred Stock, Par Value $.001; 5,000,000 Shares Authorized;
2,218,732 Series A Shares Outstanding at 9/30/2021
2,218,732 Series A Shares Outstanding at 12/31/2020
2 2 
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Common Stock, Par Value $.001; 135,000,000 Shares Authorized;
 66,178,148 Shares Outstanding at 9/30/2021
 45,908,779 Shares Outstanding at 12/31/2020
468 448 
Additional Paid-In Capital1,790,542 1,556,602 
Retained Deficit(1,948,723)(1,780,356)
Total Stockholders’ Equity (Deficit)(157,710)(223,304)
Total Liabilities and Stockholders’ Equity (Deficit)$1,244,062 $872,089 
______________
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
September 30,
Nine Months Ended
September 30,
(In thousands, except share and per share data)2021202020212020
Revenues    
Oil and Gas Sales$259,669 $73,680 $642,717 $224,541 
Gain (Loss) on Commodity Derivatives, Net(128,163)(26,361)(465,010)277,582 
Other Revenue1 3 2 12 
Total Revenues131,507 47,322 177,709 502,135 
Operating Expenses   
Production Expenses43,236 24,159 120,246 88,132 
Production Taxes19,932 6,936 51,899 20,750 
General and Administrative Expense5,490 4,605 19,878 14,185 
Depletion, Depreciation, Amortization and Accretion35,885 30,786 98,013 129,350 
Impairment Expense 199,489  962,205 
Total Operating Expenses104,543 265,975 290,036 1,214,622 
Income (Loss) From Operations26,964 (218,653)(112,327)(712,487)
Other Income (Expense)    
Interest Expense, Net of Capitalization(14,586)(14,637)(43,120)(45,145)
Write-off of Debt Issuance Costs (1,543) (1,543)
Gain (Loss) on Unsettled Interest Rate Derivatives, Net92 224 454 (1,205)
Gain (Loss) on Extinguishment of Debt, Net 1,592 (13,087)(3,718)
Contingent Consideration Gain (Loss)82  (292) 
Other Income (Expense)2 13 5 14 
Total Other Income (Expense)(14,410)(14,351)(56,040)(51,597)
Income (Loss) Before Income Taxes12,554 (233,004)(168,367)(764,084)
Income Tax Provision (Benefit)   (166)
Net Income (Loss)$12,554 $(233,004)$(168,367)$(763,918)
Cumulative Preferred Stock Dividend(3,605)(3,718)(11,154)(10,986)
Net Income (Loss) Attributable to Common Stockholders$8,949 $(236,722)$(179,521)$(774,904)
Net Income (Loss) Per Common Share – Basic$0.14 $(5.44)$(2.97)$(18.53)
Net Income (Loss) Per Common Share – Diluted$0.13 $(5.44)$(2.97)$(18.53)
Weighted Average Common Shares Outstanding – Basic65,856,479 43,517,074 60,404,584 41,812,553 
Weighted Average Common Shares Outstanding – Diluted66,629,566 43,517,074 60,404,584 41,812,553 
______________
The accompanying notes are an integral part of these condensed financial statements.
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NORTHERN OIL AND GAS, INC.
CONDENSED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
(In thousands)20212020
Cash Flows from Operating Activities  
Net Loss$(168,367)$(763,918)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:  
Depletion, Depreciation, Amortization and Accretion98,013 129,350 
Amortization of Debt Issuance Costs2,750 3,999 
Write-off of Debt Issuance Costs 1,543 
Loss on Extinguishment of Debt13,087 3,718 
Amortization of Bond Premium on Long-term Debt(130)(802)
Deferred Income Taxes 210 
Unrealized (Gain) Loss of Derivative Instruments373,086 (123,595)
Loss on Contingent Consideration292  
Stock-Based Compensation Expense2,247 3,182 
Impairment Expense 962,205 
Other3,293 (172)
Changes in Working Capital and Other Items:  
Accounts Receivable, Net(86,747)48,491 
Prepaid and Other Expenses(975)268 
Accounts Payable21,683 (1,127)
Accrued Interest(3,965)(3,199)
Accrued Liabilities and Expenses9,098 (1,501)
Net Cash Provided by Operating Activities263,365 258,652 
Cash Flows from Investing Activities  
Drilling and Development Capital Expenditures(118,196)(218,193)
Acquisition of Oil and Natural Gas Properties(246,282)(31,075)
Acquisition Deposit (225)
Purchases of Other Property and Equipment(339)(59)
Net Cash Used for Investing Activities(364,817)(249,552)
Cash Flows from Financing Activities  
Advances on Revolving Credit Facility428,000 56,000 
Repayments on Revolving Credit Facility(641,000)(65,000)
Repurchases of Second Lien Notes due 2023(295,918)(13,514)
Repayment of Unsecured VEN Bakken Note due 2022(130,000) 
Debt Issuance Costs Paid(12,436)(447)
Issuance of Common Stock228,199  
Issuance of Unsecured Notes due 2028550,000  
Restricted Stock Surrenders - Tax Obligations(839)(404)
Preferred Dividends Paid(22,002) 
Common Dividends Paid(1,975) 
Net Cash Provided (Used) for Financing Activities102,029 (23,365)
Net Increase (Decrease) in Cash and Cash Equivalents578 (14,265)
Cash and Cash Equivalents - Beginning of Period1,428 16,068 
Cash and Cash Equivalents - End of Period2,006 1,803 
______________
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 StockPreferred 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)
Issuance of Common Stock30,957 —  —   — 
Share Based Compensation—    851  851 
Restricted Stock Surrenders - Tax Obligations(82)—   (2) (2)
Equity Offerings, Net of Issuance Costs5,750,000 6   95,293  95,299 
Issuance of Common Stock Warrants    30,512  30,512 
Contingent Consideration Settlements21,977 —   354  354 
Preferred Stock Dividends    (22,002) (22,002)
Common Stock Dividends Declared, $0.03 per Share
    (1,985) (1,985)
Net Loss     (90,563)(90,563)
June 30, 202166,164,399 $468 2,218,732 $2 $1,792,589 $(1,961,276)$(168,217)
Issuance of Common Stock17,876 — — —   — 
Restricted Stock Forfeitures(14,355)— — — —  — 
Share Based Compensation— — — — 728  728 
Contingent Consideration Settlements10,228 — — — 189  189 
Common Stock Dividends Declared, $0.0450 per Share
— — — — (2,963) (2,963)
Net Income— — — — — 12,554 12,554 
September 30, 202166,178,148 $468 2,218,732 $2 $1,790,542 $(1,948,723)$(157,710)

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(In thousands, except share data)Common StockPreferred 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 
Issuance of Common Stock219,562 2 — — — — 2 
Restricted Stock Forfeitures(271)— — — — — — 
Share Based Compensation— — — — 1,313 — 1,313 
Restricted Stock Surrenders - Tax Obligations(944)— — — (8)— (8)
Issuance under Debt Exchange Agreements2,845,326 28 — — 29,586 — 29,615 
Net Loss— — — — — (899,200)(899,200)
June 30, 202043,643,991 $436 2,294,702 $2 $1,544,407 $(1,404,117)$140,729 
Issuance of Common Stock66,025 — — — — —  
Share Based Compensation— — — — 990 — 990 
Issuance under Debt Exchange Agreements1,319,615 6 — — 7,548 — 7,554 
Issuance under Series A Preferred Exchange Agreements526,695 6 (75,970)— 1,108 (1,113) 
Net Loss— — — — — (233,004)(233,004)
September 30, 202045,556,326 $448 2,218,732 $2 $1,554,053 $(1,638,234)$(83,731)

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

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NOTES TO CONDENSED FINANCIAL STATEMENTS
SEPTEMBER 30, 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) 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.

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.

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.
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In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. The Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01.

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 and nine months ended September 30, 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 primary sources: oil sales, and natural gas and NGL sales. Substantially all of the Company’s oil and gas sales come from three geographic areas in the United States: the Williston Basin (North Dakota and Montana), the Appalachian Basin (Pennsylvania), and the Permian Basin (New Mexico and Texas). The following tables present the disaggregation of the Company’s oil revenues and natural gas and NGL revenues by basin for the three and nine months ended September 30, 2021 and 2020.


 Three Months Ended
September 30, 2021
Three Months Ended
September 30, 2020
(In thousands)Williston Permian Appalachian TotalWilliston Permian Appalachian Total
Oil Revenues$192,424 $10,810 $ $203,234 $70,595 $ $ $70,595 
Natural Gas and NGL Revenues37,653 1,792 16,990 56,436 3,085   3,085 
Total$230,077 $12,602 $16,990 $259,669 $73,680 $ $ $73,680 

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 Nine Months Ended
September 30, 2021
Nine Months Ended
September 30, 2020
(In thousands)WillistonPermianAppalachian TotalWilliston Permian Appalachian Total
Oil Revenues$507,797 $15,353 $ $523,150 $215,712 $ $ $215,712 
Natural Gas and NGL Revenues89,416 2,126 28,025 119,567 8,829   8,829 
Total$597,213 $17,479 $28,025 $642,717 $224,541 $ $ $224,541 

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 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 nine months ended September 30, 2021, the Company’s top four operators made up 55% of total oil and gas sales, compared to 49% for the nine months ended September 30, 2020.

The Company faces concentration risk due to the fact that a substantial majority of its oil and natural gas revenue is sourced from North Dakota. Recent acquisitions have diversified our portfolio to include New Mexico and Pennsylvania. But the Company remains disproportionately exposed to risks affecting a limited number of 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 and nine months ended September 30, 2021 and 2020 are as follows:
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 Three Months Ended
September 30,
Nine Months Ended
September 30,
(In thousands, except share and per share data)2021202020212020
Net Income (Loss)$12,554 $(233,004)$(168,367)$(763,918)
Less: Cumulative Dividends on Preferred Stock(3,605)(3,718)(11,154)(10,986)
Net Income (Loss) Attributable to Common Stock$8,949 $(236,722)$(179,521)$(774,904)
Weighted Average Common Shares Outstanding:
Weighted Average Common Shares Outstanding – Basic65,856,479 43,517,074 60,404,584 41,812,553 
Plus: Dilutive Effect of Restricted Stock and Warrants773,087    
Plus: Dilutive Effect of Preferred Shares    
Weighted Average Common Shares Outstanding – Diluted66,629,566 43,517,074 60,404,584 41,812,553 
Net Income (Loss) per Common Share: