nog-20200930

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, 2020

☐ 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)


Delaware			95-3848122
(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 class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, par value $0.001

NOG

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 2, 2020, there were 45,851,326 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.

Table of Contents

“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.

Table of Contents

“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.

iii

Table of Contents

“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

NORTHERN OIL AND GAS, INC.

FORM 10-Q

September 30, 2020

C O N T E N T S


		Page
PART I – FINANCIAL INFORMATION

Item 1.	Condensed Financial Statements (unaudited)	2
	Condensed Balance Sheets	2
	Condensed Statements of Operations	4
	Condensed Statements of Cash Flows	5
	Condensed Statements of Stockholders’ Equity	7
	Notes to Condensed Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	47

Item 4.	Controls and Procedures	49

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	51

Item 1A.	Risk Factors	51

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53

Item 6.	Exhibits	54

Signatures

Table of Contents

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, 2020		December 31, 2019
Assets	(Unaudited)
Current Assets:
Cash and Cash Equivalents	$	1,803	$	16,068
Accounts Receivable, Net	60,067		108,274
Advances to Operators	714		893
Prepaid Expenses and Other	1,697		1,964
Derivative Instruments	119,468		5,628
Income Tax Receivable	—		210
Total Current Assets	183,749		133,037

Property and Equipment:
Oil and Natural Gas Properties, Full Cost Method of Accounting
Proved	4,344,346		4,178,605
Unproved	10,328		11,047
Other Property and Equipment	2,215		2,157
Total Property and Equipment	4,356,889		4,191,809
Less – Accumulated Depreciation, Depletion and Impairment	(3,533,887)		(2,443,216)
Total Property and Equipment, Net	823,002		1,748,593

Derivative Instruments	6,826		8,554
Deferred Income Taxes	—		210
Acquisition Deposit	225		—
Other Noncurrent Assets, Net	11,722		15,071

Total Assets	$	1,025,524	$	1,905,465

Liabilities and Stockholders' Equity (Deficit)
Current Liabilities:
Accounts Payable	$	20,372	$	69,395
Accrued Liabilities	70,203		110,374
Accrued Interest	8,442		11,615

Derivative Instruments	5,438		11,298



Current Portion of Long-term Debt	65,000		—
Other Current Liabilities	1,000		795
Total Current Liabilities	170,455		203,477

Long-term Debt	918,327		1,118,161

Derivative Instruments	2,456		8,079


Asset Retirement Obligations	17,891		16,759
Other Noncurrent Liabilities	126		345

Total Liabilities	$	1,109,255	$	1,346,822

Commitments and Contingencies (Note 8)

Table of Contents


Stockholders’ Equity (Deficit)
Preferred Stock, Par Value $.001; 5,000,000 Shares Authorized; 2,218,732 Series A Shares Outstanding at 9/30/2020 1,500,000 Series A Shares Outstanding at 12/31/2019	2		2
Common Stock, Par Value $.001; 135,000,000* Shares Authorized; 45,556,326* Shares Outstanding at 9/30/2020 40,608,518* Shares Outstanding at 12/31/2019	448		406
Additional Paid-In Capital	1,554,053		1,431,438
Retained Deficit	(1,638,234)		(873,203)
Total Stockholders’ Equity (Deficit)	(83,731)		558,643
Total Liabilities and Stockholders’ Equity (Deficit)	$	1,025,524	$	1,905,465

___________

*Adjusted for the 1-for-10 reverse stock split. See Note 5.

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

Table of Contents

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)	2020		2019		2020		2019
Revenues
Oil and Gas Sales	$	73,680	$	157,989	$	224,541	$	440,519
Gain (Loss) on Commodity Derivatives, Net	(26,361)		75,892		277,582		(27,139)
Other Revenue	3		3		12		10
Total Revenues	47,322		233,883		502,135		413,389

Operating Expenses
Production Expenses	24,159		32,347		88,132		83,146
Production Taxes	6,936		15,391		20,750		41,944
General and Administrative Expense	4,605		4,206		14,185		15,506
Depletion, Depreciation, Amortization and Accretion	30,786		55,566		129,350		146,791
Impairment of Other Current Assets	—		5,275		—		7,969
Impairment Expense	199,489		—		962,205		—
Total Operating Expenses	265,975		112,784		1,214,622		295,355

Income (Loss) From Operations	(218,653)		121,100		(712,487)		118,034

Other Income (Expense)
Interest Expense, Net of Capitalization	(14,637)		(21,510)		(45,145)		(58,836)
Write-off of Debt Issuance Costs	(1,543)		—		(1,543)		—
Gain (Loss) on Unsettled Interest Rate Derivatives, Net	224		—		(1,205)		—
Gain (Loss) on Extinguishment of Debt, Net	1,592		—		(3,718)		(425)
Debt Exchange Derivative Gain/(Loss)	—		(23)		—		1,390
Contingent Consideration Loss	—		(5,262)		—		(28,633)

Other Income (Expense)	13		75		14		88
Total Other Income (Expense)	(14,351)		(26,719)		(51,597)		(86,416)

Income (Loss) Before Income Taxes	(233,004)		94,381		(764,084)		31,619

Income Tax Provision (Benefit)	—		—		(166)		—

Net Income (Loss)	$	(233,004)	$	94,381	$	(763,918)	$	31,619

Cumulative Preferred Stock Dividend	(3,718)		—		(10,986)		—

Net Income (Loss) Attributable to Common Shareholders	$	(236,722)	$	94,381	$	(774,904)	$	31,619

Net Income (Loss) Per Common Share – Basic*	$	(5.44)	$	2.38	$	(18.53)	$	0.83
Net Income (Loss) Per Common Share – Diluted*	$	(5.44)	$	2.38	$	(18.53)	$	0.83
Weighted Average Common Shares Outstanding – Basic*	43,517,074		39,604,482		41,812,553		38,204,403
Weighted Average Common Shares Outstanding – Diluted*	43,517,074		39,653,070		41,812,553		38,274,426

___________

*Adjusted for the 1-for-10 reverse stock split. See Note 5.

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

Table of Contents

NORTHERN OIL AND GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Nine Months Ended September 30,
(In thousands)	2020		2019
Cash Flows from Operating Activities
Net Income (Loss)	$	(763,918)	$	31,619
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Depletion, Depreciation, Amortization and Accretion	129,350		146,791
Amortization of Debt Issuance Costs	3,999		3,948
Write-off of Debt Issuance Costs	1,543		—
Loss on Extinguishment of Debt	3,718		425
Amortization of Bond Premium on Long-term Debt	(802)		(2,165)
Deferred Income Taxes	210		—
(Gain) Loss of Derivative Instruments	(123,595)		62,806
Gain on Debt Exchange Derivative	—		(1,390)
Loss on Contingent Consideration	—		28,633

PIK Interest on Second Lien Notes	—		1,742
Stock-Based Compensation Expense	3,182		4,280
Impairment of Other Current Assets	—		7,969
Impairment Expense	962,205		—
Other	(172)		(41)
Changes in Working Capital and Other Items:
Accounts Receivable, Net	48,491		(6,589)
Prepaid and Other Expenses	268		1,674
Accounts Payable	(1,127)		1,058
Accrued Interest	(3,199)		2,813
Accrued Liabilities	(1,501)		6,916
Payment of Contingent Consideration	—		(21,164)
Net Cash Provided by Operating Activities	258,652		269,323

Cash Flows from Investing Activities
Drilling and Development Capital Expenditures	(218,193)		(206,306)
Acquisition of Oil and Natural Gas Properties	(31,075)		(210,642)
Acquisition Deposit	(225)		—


Purchases of Other Property and Equipment	(59)		(1,001)
Net Cash Used for Investing Activities	(249,552)		(417,948)

Cash Flows from Financing Activities
Advances on Revolving Credit Facility	56,000		313,000
Repayments on Revolving Credit Facility	(65,000)		(126,000)




Repurchases of Second Lien Notes	(13,514)		(10,488)

Debt Issuance Costs Paid	(447)		(328)
Debt Exchange Derivative Settlements	—		(1,044)
Contingent Consideration Settlements	—		(11,278)


Repurchases of Common Stock	—		(15,108)
Restricted Stock Surrenders - Tax Obligations	(404)		(584)
Net Cash (Used for) Provided by Financing Activities	(23,365)		148,169

Net Decrease in Cash and Cash Equivalents	(14,265)		(456)

Table of Contents


Cash and Cash Equivalents - Beginning of Period	16,068	2,358

Cash and Cash Equivalents - End of Period	1,803	1,901

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

Table of Contents

NORTHERN OIL AND GAS, INC.

CONDENSED STATEMENTS OF STOCKHOLDERS’ EQUITY

(UNAUDITED)


(In thousands, except share data)	Common Stock*			Preferred Stock			Additional Paid-In		Retained Earnings		Total Stockholders’ Equity
	Shares	Amount		Shares	Amount		Capital		(Deficit)		(Deficit)
December 31, 2019	40,608,518	$	406	1,500,000	$	2	$	1,431,438	$	(873,203)	$	558,643

Issuance of Common Stock	5,000	—		—	—		—		—		—

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, 2020	40,580,318	$	406	2,294,702	$	2	$	1,513,516	$	(504,917)	$	1,009,007

Issuance of Common Stock	219,562	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 Agreements	2,845,326	28		—	—		29,586		—		29,615



Net Loss	—	—		—	—		—		(899,200)		(899,200)

June 30, 2020	43,643,991	$	436	2,294,702	$	2	$	1,544,407	$	(1,404,117)	$	140,729
Issuance of Common Stock	66,025	—		—	—		—		—		—

Share Based Compensation	—	—		—	—		990		—		990


Issuance under Debt Exchange Agreements	1,319,615	6		—	—		7,548		—		7,554
Issuance under Series A Preferred Exchange Agreements	526,695	6		(75,970)	—		1,108		(1,113)		—



Net Loss	—	—		—	—		—		(233,004)		(233,004)

September 30, 2020	45,556,326	$	448	2,218,732	$	2	$	1,554,053	$	(1,638,234)	$	(83,731)

__________

*Adjusted for the 1-for-10 reverse stock split. See Note 5.

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

Table of Contents


	Common Stock*			Preferred Stock			Additional Paid-In		Retained Earnings		Total Stockholders’ Equity
(In thousands, except share data)	Shares	Amount		Shares	Amount		Capital		(Deficit)		(Deficit)
December 31, 2018	37,833,307	$	378	—	$	—	$	1,226,371	$	(796,884)	$	429,865

Issuance of Common Stock	316,020	3		—	—		—		—		3
Restricted Stock Forfeitures	(480)	—		—	—		—		—		—
Stock-Based Compensation	—	—		—	—		2,832		—		2,832
Restricted Stock Surrenders - Tax Obligations	(22,053)	—		—	—		(558)		—		(558)




Repurchases of Common Stock	(563,500)	(6)		—	—		(15,102)		—		(15,108)
Contingent Consideration Settlements	116,754	1		—	—		2,886		—		2,887
Net Loss	—	—		—	—		—		(107,162)		(107,162)

March 31, 2019	37,680,048	$	377	—	$	—	$	1,216,429	$	(904,046)	$	312,760

Issuance of Common Stock	900	—		—	—		—		—		—
Restricted Stock Forfeitures	(40,203)	—		—	—		—		—		—
Stock-Based Compensation	—	—		—	—		1,750		—		1,750
Restricted Stock Surrenders - Tax Obligations	(944)	—		—	—		(26)		—		(26)
Equity Offerings	—	—		—	—		—		—		—
Issuance under Debt Exchange Agreements	524,988	5		—	—		12,186		—		12,192



Contingent Consideration Settlements	778,811	8		—	—		18,567		—		18,575
Net Income	—	—		—	—		—		44,399		44,399

June 30, 2019	38,943,600	$	389	—	$	—	$	1,248,906	$	(859,647)	$	389,649
Issuance of Common Stock	—	—		—	—		—		—		—
Restricted Stock Forfeitures	(4,560)	—		—	—		—		—		—
Stock-Based Compensation	—	—		—	—		(8)		—		(8)
Restricted Stock Surrenders - Tax Obligations	—	—		—	—		—		—		—
Equity Offerings	—	—		—	—		—		—		—
Issuance under Debt Exchange Agreements	198,553	2		—	—		3,541		—		3,543
Acquisition of Oil and Natural Gas Properties	560,215	6		—	—		11,703		—		11,708
Net Exercise of Stock Options	—	—		—	—		—		—		—
Repurchases of Common Stock	—	—		—	—		—		—		—
Contingent Consideration Settlements	736,840	7		—	—		14,833		—		14,841
Net Income	—	—		—	—		—		94,381		94,381

September 30, 2019	40,434,648	$	404	—	$	—	$	1,278,976	$	(765,266)	$	514,114

__________

*Adjusted for the 1-for-10 reverse stock split. See Note 5.

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

Table of Contents

NOTES TO CONDENSED FINANCIAL STATEMENTS

SEPTEMBER 30, 2020

(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 that primarily target the Bakken and Three Forks formations in the Williston Basin of 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, 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.

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 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. As a result of the significant decline in current and expected future commodity prices, the Company recognized a material impairment charge during the three and nine months ended September 30, 2020 (see Note 3). 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

Table of Contents

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 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 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 and nine months ended September 30, 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 has revenue from one geographic area, the Williston Basin in the United States, primarily in North Dakota and Montana. Oil sales for the three months ended September 30, 2020 and 2019 were $70.6 million and $152.8 million, respectively. Natural gas and NGL sales for the three months ended September 30, 2020 and 2019 were $3.1 million and $5.2 million, respectively. Oil sales for the nine months ended September 30, 2020 and 2019 were $215.7 million and $416.3 million, respectively. Natural gas and NGL sales for the nine months ended September 30, 2020 and 2019 were $8.8 million and $24.3 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

Table of Contents

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 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 and nine months ended September 30, 2020, the Company’s top four operators made up 48% and 49%, respectively, of total oil and gas sales, compared to 45% and 52% for the three and nine months ended September 30, 2019.

The Company faces concentration risk due to the fact that substantially 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 this 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) 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 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, 2020 and 2019 are as follows:

Table of Contents


	Three Months Ended September 30,				Nine Months Ended September 30,
(In thousands, except share and per share data)	2020		2019		2020		2019
Net Income (Loss)	$	(233,004)	$	94,381	$	(763,918)	$	31,619
Less: Cumulative Dividends on Preferred Stock	(3,718)		—		(10,986)		—
Net Income (Loss) Attributable to Common Stock	$	(236,722)	$	94,381	$	(774,904)	$	31,619

Weighted Average Common Shares Outstanding:
Weighted Average Common Shares Outstanding – Basic	43,517,074		39,604,482		41,812,553		38,204,403
Plus: Dilutive Effect of Restricted Stock	—		48,588		—		70,023
Plus: Dilutive Effect of Preferred Shares	—		—		—		—
Weighted Average Common Shares Outstanding – Diluted	43,517,074		39,653,070		41,812,553		38,274,426

Net Income (Loss) per Common Share:
Basic	$	(5.44)	$	2.38	$	(18.53)	$	0.83
Diluted	$	(5.44)	$	2.38	$	(18.53)	$	0.83

Shares Excluded from EPS Due to Anti-Dilutive Effect:
Restricted Stock	84,319		8,821		54,885		4,033
Preferred Stock	10,057,601		—		9,880,344		—

Supplemental Cash Flow Information

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


	Nine Months Ended September 30,
(In thousands)	2020		2019
Supplemental Cash Items:
Cash Paid During the Period for Interest, Net of Amount Capitalized	$	42,736	$	52,916
Cash Paid During the Period for Income Taxes	—		—

Non-cash Operating Activities:
Contingent Consideration Settlements in Excess of Acquisition-Date Liabilities	—		18,480

Non-cash Investing Activities:
Oil and Natural Gas Properties Included in Accounts Payable and Accrued Liabilities	76,498		178,772
Capitalized Asset Retirement Obligations	457		3,703
Compensation Capitalized on Oil and Gas Properties	385		296
Issuance of Common Stock - Acquisitions of Oil and Natural Gas Properties	—		11,708
Issuance of Unsecured VEN Bakken Note	—		128,660