UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): November 8, 2019

NORTHERN OIL AND GAS, INC.
(Exact name of Registrant as specified in its charter)
Delaware
001-33999 95-3848122
(State or other jurisdiction
of incorporation)
(Commission File Number)
(IRS Employer
Identification No.)

601 Carlson Parkway, Suite 990
Minnetonka, Minnesota
55305
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code   (952) 476-9800

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17CFR 240.14a-12)
o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

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 is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
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. ¨


Item 1.01.  Entry into a Material Definitive Agreement.

On November 8, 2019, Northern Oil and Gas, Inc. entered into an amendment (the “Amendment”) to its Amended and Restated Credit Agreement, dated October 5, 2018 (the “Credit Agreement”), governing the Company’s revolving credit facility with Royal Bank of Canada, as administrative agent, and the lenders party thereto. Pursuant to the Amendment, the Credit Agreement has been amended to (i) adjust the maximum ratio of total net debt to EBITDAX (as defined in the Credit Agreement) that the Company is permitted to maintain as of the end of any fiscal quarter to 3.75 to 1.00, and (ii) adjust the minimum current ratio (as defined in the Credit Agreement) that the Company is required to maintain as follows: 0.85 to 1.00 as of September 30, 2019; 0.65 to 1.00 as of December 31, 2019; 0.90 to 1.00 as of March 31, 2020; and 1.00 to 1.00 as of any subsequent fiscal quarter end.

A copy of the Amendment is attached hereto as Exhibit 10.1 and is incorporated herein by reference. The description of the Amendment in this report is a summary and is qualified in its entirety by the terms of the Amendment.


Item 2.02. Results of Operations and Financial Condition.

On November 12, 2019, Northern Oil and Gas, Inc. issued a press release announcing 2019 third quarter financial and operating results. A copy of the press release is furnished as Exhibit 99.1 hereto.


Item 9.01. Financial Statements and Exhibits.

Exhibit Number Description
   Fourth Amendment to the Amended and Restated Credit Agreement, dated November 8, 2019, by and among Northern Oil and Gas, Inc., Royal Bank of Canada, and the Lenders party thereto.
   Press release of Northern Oil and Gas, Inc., dated November 12, 2019.




SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned hereunto duly authorized.

Date: November 12, 2019
NORTHERN OIL AND GAS, INC.
By /s/ Erik J. Romslo
Erik J. Romslo
Executive Vice President, General Counsel and Secretary




Exhibit 10.1
Execution Version
FOURTH AMENDMENT TO
AMENDED AND RESTATED CREDIT AGREEMENT

This FOURTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (this “Amendment”) dated as of November 8, 2019, is among Northern Oil and Gas, Inc., a Delaware corporation (the “Borrower”), each of the Lenders party hereto and Royal Bank of Canada, as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”).
RECITALS
A. The Borrower, the Administrative Agent and the Lenders are party to that certain Amended and Restated Credit Agreement dated as of October 5, 2018, as amended by the First Amendment dated as of December 31, 2018, that Second Amendment dated as of January 14, 2019 and that Third Amendment dated as of April 18, 2019 (as it may be further amended, restated, amended and restated, supplemented or otherwise modified from time to time, the “Credit Agreement”), pursuant to which the Lenders have made certain credit available to and on behalf of the Borrower.
B. The Borrower has requested that the Lenders amend the Credit Agreement to, among other things, modify Section 9.01 of the Credit Agreement as more fully set forth herein.
D. NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:
Section 1.Defined Terms. Each capitalized term which is defined in the Credit Agreement, but which is not defined in this Amendment, shall have the meaning ascribed such term in the Credit Agreement after giving effect to this Amendment. Unless otherwise indicated, all references to sections in this Amendment refer to sections in the Credit Agreement as amended by this Amendment.
Section 2. Amendments to Credit Agreement. The Credit Agreement is hereby amended effective as of the Fourth Amendment Effective Date (as defined below) as follows:
2.1 The following defined term in Section 1.02 of the Credit Agreement shall be amended and restated in its entirety as follows:
“RP/Investment Conditions” means that: (a) no Default, Event of Default or Borrowing Base Deficiency has occurred and is continuing or would result therefrom; (b) at least 15% of the Commitments are unused; and (c) the Pro Forma Net Leverage Ratio is equal to or less than 2.75 to 1.00.
2.2 Section 9.01 of the Credit Agreement is hereby amended and restated in its entirety as follows:


“Section 9.01. Financial Covenants.
(a) Maximum Net Leverage Ratio. The Borrower will not permit, as of the last day of each fiscal quarter, the Net Leverage Ratio to exceed 3.75 to 1.00.
(b) Current ratio. The Borrower will not permit, as of the last day of (i) the fiscal quarter ending September 30, 2019, the Current Ratio to be less than 0.85 to 1.00, (ii) the fiscal quarter ending December 31, 2019, the Current Ratio to be less than 0.65 to 1.00, (iii) the fiscal quarter ending March 31, 2020, the Current Ratio to be less than 0.90 to 1.00, and (iv) any other fiscal quarter ending thereafter, the Current Ratio to be less than 1.00 to 1.00.”
Section 3. Conditions Precedent. This Amendment shall become effective on the date, when each of the following conditions is satisfied (the “Fourth Amendment Effective Date”):
3.1 The Administrative Agent shall have executed and received from Majority Lenders and the Borrower, counterparts (in such number as may be requested by the Administrative Agent) of this Amendment signed on behalf of each such Person.
3.2 Immediately after giving effect to this Amendment, no Default, Event of Default or Borrowing Base Deficiency shall have occurred and be continuing.
Section 4. Miscellaneous.
4.1 Confirmation. The Credit Agreement and each of the other Loan Documents, as specifically amended by this Amendment, are and shall continue to be in full force and effect and are hereby in all respects ratified and confirmed. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of any Lender or the Administrative Agent under any of the Loan Documents, nor constitute a waiver of any provision of any of the Loan Documents. On and after the Fourth Amendment Effective Date, this Amendment shall for all purposes constitute a Loan Document.
4.2 Representations and Warranties. The Borrower hereby (a) acknowledges and consents to the terms of this Amendment and (b) ratifies and affirms its obligations under, and acknowledges its continued liability under, each Loan Document and agrees that each Loan Document remains in full force and effect as expressly amended, restated, supplemented or otherwise modified hereby or otherwise in connection with a delivery made herewith and (c) represents and warrants to the Administrative Agent and the Lenders that as of the date hereof, after giving effect to the terms of this Amendment: (i) all of the representations and warranties contained in each Loan Document are true and correct in all material respects, except that (A) to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct in all material respects as of such specified earlier date and (B) to the extent any such representation and warranty is qualified by materiality, such representation and warranty (as so qualified) is true and correct in all respects and (ii) no Default or Event of Default has occurred and is continuing.
2



4.3 Counterparts. This Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall constitute one and the same instrument. Delivery of an executed counterpart of a signature page to this Amendment by telecopy, facsimile or other electronic means (e.g., .pdf) shall be effective as delivery of a manually executed counterpart hereof.
4.4 No Oral Agreement. This Amendment, the Credit Agreement and the other Loan Documents executed in connection herewith and therewith represent the final agreement between the parties and may not be contradicted by evidence of prior, contemporaneous, or unwritten oral agreements of the parties. There are no subsequent oral agreements between the parties.
4.5 GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK (INCLUDING SECTION 5-1401 AND SECTION 5-1402 OF THE GENERAL OBLIGATIONS LAW OF THE STATE OF NEW YORK), WITHOUT REFERENCE TO ANY OTHER CONFLICTS OR CHOICE OF LAW PRINCIPLES THEREOF.
4.6 Payment of Expenses. The Borrower agrees to pay or reimburse the Administrative Agent for all of its reasonable and documented out-of-pocket costs and expenses incurred in connection with this Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby in accordance with Section 12.03 of the Credit Agreement.
4.7 Severability. Any provision of this Amendment which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.
4.8 Successors and Assigns. This Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns.
4.9 Miscellaneous. Section 12.09(b), (c) and (d) of the Credit Agreement shall apply to this Amendment, mutatis mutandis.
[SIGNATURES BEGIN NEXT PAGE]

3



IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed effective as of the day and year first above written.

BORROWER:
NORTHERN OIL AND GAS, INC.

By: /s/ Nicholas O’Grady
Name: Nicholas O’Grady
Title: Chief Financial Officer













Signature Page to Fourth Amendment to Credit Agreement
Northern Oil and Gas, Inc.






ROYAL BANK OF CANADA,
as Administrative Agent

By: /s/ Rodica Dutka
Name: Rodica Dutka
Title: Manager, Agency Services Group



Signature Page to Fourth Amendment to Credit Agreement
Northern Oil and Gas, Inc.






ROYAL BANK OF CANADA,
as Issuing Bank and a Lender

By: /s/ Don J. McKinnerney
Name: Don J. McKinnerney
Title: Authorized Signatory




Signature Page to Fourth Amendment to Credit Agreement
Northern Oil and Gas, Inc.






WELLS FARGO BANK, NATIONAL
ASSOCIATION, as a Lender

By: /s/ Erin Grasty
Name: Erin Grasty
Title: Vice President



Signature Page to Fourth Amendment to Credit Agreement
Northern Oil and Gas, Inc.





CAPITAL ONE, NATIONAL ASSOCIATION,
as a Lender


By: /s/ Cameron Breitenbach
Name: Cameron Breitenbach
Title: Vice President



Signature Page to Fourth Amendment to Credit Agreement
Northern Oil and Gas, Inc.





ABN AMRO CAPITAL USA LLC,
as a Lender

By: /s/ Beth Johnson
Name: Beth Johnson
Title: Executive Director

By: /s/ Darrell Holley
Name: Darrell Holley
Title: Managing Director




Signature Page to Fourth Amendment to Credit Agreement
Northern Oil and Gas, Inc.





CITIZENS BANK, N.A.,
as a Lender

By: /s/ David Slye
Name: David Slye
Title: Managing Director




Signature Page to Fourth Amendment to Credit Agreement
Northern Oil and Gas, Inc.





CATHAY BANK,
as a Lender

By: /s/ Stephen V Bacala II
Name: Stephen V Bacala II
Title: Vice President



Signature Page to Fourth Amendment to Credit Agreement
Northern Oil and Gas, Inc.





MORGAN STANLEY BANK, N.A.,
as a Lender

By: /s/ John Kuhns
Name: John Kuhns
Title: Authorized Signatory




Signature Page to Fourth Amendment to Credit Agreement
Northern Oil and Gas, Inc.





CARGILL INCORPORATED,
as a Lender

By: /s/ Tyler R. Smith
Name: Tyler R. Smith
Title: Authorized Signer






Signature Page to Fourth Amendment to Credit Agreement
Northern Oil and Gas, Inc.



Exhibit 99.1

Northern Oil and Gas, Inc. Announces Third Quarter 2019 Results

•Third quarter production increased 53% over the prior year, and 17% sequentially, averaging 40,786 barrels of oil equivalent (“Boe”) per day.
•Cash flow from operations, excluding a $32.5 million net decrease from changes in working capital and other items, was $103.5 million for the third quarter, an 11% increase versus the second quarter.
•Organic drilling and development capital expenditures totaled $80.1 million during the third quarter.
•Northern closed the VEN Bakken acquisition and also added another 13.3 net wells to production during the third quarter, which helped offset the curtailments, shut-ins and completion delays that negatively impacted production by an estimated 4,500 Boe per day during the quarter.
•Ground Game success continued in the third quarter, with $9.9 million of acquisition capital and an additional $23.0 million of associated development capital allocated to drive cash flow for shareholder returns in 2020.

MINNEAPOLIS (BUSINESS WIRE) - November 12, 2019 - Northern Oil and Gas, Inc. (NYSE American: NOG) (“Northern”) today announced the company’s third quarter results.

Third quarter 2019 production totaled 3.8 million Boe and averaged 40,786 Boe per day, a 53% increase from the prior year and a 17% increase sequentially. Oil and gas sales in the third quarter totaled $158.0 million. Net income in the third quarter was $94.4 million or $0.24 per diluted share. Adjusted Net Income in the third quarter was $36.3 million or $0.09 per diluted share. Adjusted EBITDA totaled $124.4 million in the third quarter, a 27% increase from the prior year. (See “Non-GAAP Financial Measures” below.)

“Strong net well additions from our organic well opportunities and the success we have had in our ground game acquisitions generated strong production growth during the quarter,” commented Brandon Elliott, Chief Executive Officer. “While well performance and net well additions have remained robust, they did not completely offset 4,500 Boe per day of shut-ins and curtailments during the quarter. The good news is we expect the well performance and net well additions to remain strong while we expect the infrastructure issues to begin to subside as we close out 2019. Future cash flows will support plans to reduce debt ratios and return capital to shareholders in 2020.”

Production and Operating Costs

Total third quarter production was 3.8 million Boe, driven by the closing of the VEN Bakken acquisition and an additional 13.3 net wells added to production during the quarter. Strong well results were offset by continued infrastructure-driven constraints. Midstream system expansions, while beginning to come online, did not offset the negative effects on production and natural gas and NGL prices during the quarter. Oil price differentials averaged $5.48 per barrel, a 4% increase from the second quarter of 2019. Ongoing production curtailments resulted in a 5% sequential increase in lease operating expenses (“LOE”) to $8.62 per Boe in the third quarter. General and administrative expenses were $1.12 per Boe in the third quarter.

2019 Capital Allocation and Ground Game Activity

Northern continues to focus capital to the highest returns on capital employed in an effort to grow cash flow as it prepares to begin returning capital to shareholders in 2020. During the third quarter, Northern spent $80.1 million on organic development capital and an additional $32.9 million related to its ground game acquisition strategy (“Ground Game”), which is Northern's regular acquisition activity excluding larger, separately announced deals such as the recent VEN Bakken acquisition. Of the total Ground Game spend, $9.9 million was acquisition capital and an additional $23.0 million was associated development capital.

The third quarter was extremely active for Northern’s Ground Game. With many operators and non-operating participants seeking to reduce their short term capital obligations, the landscape for high return opportunities, particularly for near term drilling, has been robust. In the third quarter, Northern acquired approximately 3,100 net acres and 4.4 net wells in process. Of those net wells in process, approximately 2.0 net wells came online in the third quarter, 1.1 of which came online ahead of schedule late in the quarter. Northern's Ground Game success in 2019 will allow it to moderate its acquisition activity in 2020, as the Company looks to harvest cash flows from its 2019 acquisitions. Northern will, however, continue to monitor and evaluate potential acquisitions for distressed and high-return opportunities.


2019 Production Guidance Updated for Ground Game Acquisitions and Continued Curtailments

Northern expects to add 33 – 34 net organic wells to production in 2019. Due to Ground Game success over the last 12 months and an acceleration in development activity, Northern expects to add an additional 5 – 7 net wells to production from the Ground Game, for a total of 38 – 41 total net wells added to production during 2019.

Additional information regarding Northern’s current expectations are included in the tables below.

2019 Production (Boe per day): Current Previous
1st Quarter – Actual 34,568
2nd Quarter – Actual 34,965
3rd Quarter – Actual 40,786   
4th Quarter – Estimate 43,500 – 44,500 43,500 – 44,500
Annual – Estimate 38,500 – 38,750 38,650 – 39,150
2019 Guidance Ranges (in millions, except for net well data): Current Previous
Organic(1) Net Wells Added to Production
33 – 34 33 – 34
Organic(1) Drilling & Completion (D&C) Capital
$265 – $285 $265 – $285
Ground Game 2019E Net Wells Added to Production 5 – 7 3 – 5
Ground Game Acquisition Capital $30 – $40 $25 – $50
Ground Game D&C Capital $40 – $70 $30 – $60
___________
(1)Organic includes estimated net wells and D&C capital from recently acquired VEN Bakken assets (post-closing).

2019 Full Year Operating Expenses Guidance: Current Previous
Production Expenses (per Boe) $8.00 – $8.50 $8.00 – $8.50
Production Taxes 10% of crude oil sales; $0.075 per mcf of gas ~ 9.3% of oil and gas sales
General and Administrative Expense (per Boe):
Cash
$0.95 – $1.15 $0.95 – $1.15
Non-Cash $0.50 $0.50
Average Differential to NYMEX WTI $4.50 – $6.50 $4.50 – $6.50





THIRD QUARTER 2019 RESULTS

The following tables set forth selected operating and financial data for the periods indicated.

  Three Months Ended September 30,
  2019 2018 % Change
Net Production:      
Oil (Bbl) 3,002,789    2,064,092    45  %
Natural Gas and NGLs (Mcf) 4,496,860    2,358,162    91  %
Total (Boe) 3,752,266    2,457,119    53  %
Average Daily Production:
Oil (Bbl) 32,639    22,436    45  %
Natural Gas and NGLs (Mcf) 48,879    25,632    91  %
Total (Boe) 40,786    26,708    53  %
Average Sales Prices:
Oil (per Bbl) $ 50.90    $ 65.45    (22) %
Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl) 6.12    (6.26)  
Oil Net of Settled Derivatives (per Bbl) 57.02    59.19    (4) %
Natural Gas and NGLs (per Mcf) 1.15    4.41    (74) %
Realized Price on a Boe Basis Including all Realized Derivative Settlements 47.00    53.96    (13) %
Costs and Expenses (per Boe):
Production Expenses $ 8.62    $ 7.39    17  %
Production Taxes 4.10    5.53    (26) %
General and Administrative Expense 1.12    1.90    (41) %
Depletion, Depreciation, Amortization and Accretion 14.81    12.31    20  %
Net Producing Wells at Period End 444.0    284.3    56  %





HEDGING

Northern hedges portions of its expected production volumes to increase the predictability of its cash flow and to help maintain a strong financial position. The following tables summarize Northern’s open crude oil derivative and basis swap contracts scheduled to settle after September 30, 2019.

Crude Oil Derivative Swaps
Contract Period Volume (Bbls) Weighted Average Price (per Bbl)
2019:
4Q 2,460,411    $58.96   
2020:
1Q 2,490,106    $59.15   
2Q 2,431,778    $58.44   
3Q 2,340,348    $58.48   
4Q 2,165,362    $58.00   
2021:
1Q 1,690,050    $56.73   
2Q 1,587,958    $57.24   
3Q 1,418,410    $54.35   
4Q 1,409,506    $54.37   
2022(1):
1Q 453,780    $53.07   
2Q 312,280    $52.30   
3Q 306,576    $52.33   
4Q 300,230    $52.35   

_____________
(1)The Company has entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for additional periods. Options covering a notional volume of 2.4 million barrels for 2022 are exercisable on or about December 31, 2021. If the counterparties exercise all such options, the notional volume of the Company’s existing crude oil derivative contracts will increase as follows for 2022: (i) for the first quarter of 2022, by 807,750 barrels at a weighted average price of $54.89 per barrel, (ii) for the second quarter of 2022, by 816,725 barrels at a weighted average price of $54.89 per barrel, (iii) for the third quarter of 2022, by 365,700 barrels at a weighted average price of $55.04 per barrel, and (iv) for the fourth quarter of 2022, by 365,700 barrels at a weighted average price of $55.04 per barrel.

Crude Oil Derivative Basis Swaps(1)
Contract Period Total Volumes (Bbls) Weighted Average Differential
($/Bbl)
10/01/2019 - 12/31/2019 951,000    ($2.40)  
________________
(1) Basis swaps are settled using the TMX UHC 1a index, as published by NGX.

LIQUIDITY

As of September 30, 2019, Northern had $1.9 million in cash and $327.0 million outstanding on its revolving credit facility. Northern had total liquidity of $99.9 million as of September 30, 2019, consisting of cash and borrowing availability under the revolving credit facility.


CAPITAL EXPENDITURES & DRILLING ACTIVITY

(in millions, except for net well data) Three Months Ended September 30, 2019
Capital Expenditures Incurred:
Organic Drilling and Development Capital Expenditures $ 80.1   
Ground Game Acquisition Capital Expenditures $ 9.9   
Ground Game Drilling and Development Capital Expenditures $ 23.0   
Acquisition of Oil and Natural Gas Properties and Other $ 325.7   
Net Wells Added to Production 13.3   
Net Producing Wells (Period-End) 444.0   
Net Wells in Process (Period-End) 24.2   
Increase in Wells in Process over 2018 Year-End 1.4   
Weighted Average AFE for Wells Elected to During the Third Quarter $ 7.7   
Weighted Average AFE for Wells Elected to Year-to-Date $ 7.9   

Capitalized costs are a function of the number of net well additions during the period, and changes in wells in process from the prior year-end. Capital expenditures attributable to the 1.4 well increase in net wells in process during the nine months ended September 30, 2019 are reflected in the amounts incurred year-to-date for drilling and development capital expenditures.

ACREAGE

As of September 30, 2019, Northern controlled leasehold of approximately 183,518 net acres targeting the Bakken and Three Forks formations of the Williston Basin, and approximately 90% of this total acreage position was developed, held by production, or held by operations.

THIRD QUARTER 2019 EARNINGS RELEASE CONFERENCE CALL

In conjunction with Northern’s release of its financial and operating results, investors, analysts and other interested parties are invited to listen to a conference call with management on Tuesday, November 12, 2019 at 10:00 a.m. Central Time.

Those wishing to listen to the conference call may do so via the company’s website, www.northernoil.com, or by phone as follows:

Dial-In Number: (866) 373-3407 (US/Canada) and (412) 902-1037 (International)
Conference ID: 13696040 - Northern Oil and Gas, Inc. Third Quarter 2019 Conference Call
Replay Dial-In Number: (877) 660-6853 (US/Canada) and (201) 612-7415 (International)
Replay Access Code: 13696040 - Replay will be available through November 19, 2019

UPCOMING CONFERENCE SCHEDULE

Bank of America 2019 Leveraged Finance Conference
December 2 - 4, 2019, Boca Raton, FL

Capital One Securities 14th Annual Energy Conference
December 10 - 12, 2019, Houston, TX

Piper Jaffray 20th Annual Energy Conference
March 23 - 25, 2020, Las Vegas, NV



ABOUT NORTHERN OIL AND GAS

Northern Oil and Gas, Inc. is an exploration and production company with a core area of focus in the Williston Basin Bakken and Three Forks play in North Dakota and Montana. More information about Northern Oil and Gas, Inc. can be found at www.northernoil.com.

SAFE HARBOR

This press release contains forward-looking statements regarding future events and future results that are subject to the safe harbors created under the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”). All statements other than statements of historical facts included in this release regarding Northern’s financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this release, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: changes in crude oil and natural gas prices, the pace of drilling and completions activity on Northern’s current properties, infrastructure constraints and related factors affecting Northern’s properties, Northern’s ability to acquire additional development opportunities, changes in Northern’s reserves estimates or the value thereof, general economic or industry conditions, nationally and/or in the communities in which Northern conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, Northern’s ability to raise or access capital, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting Northern’s operations, products and prices.

Northern has based these forward-looking statements on its current expectations and assumptions about future events. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond Northern’s control. Northern does not undertake any duty to update or revise any forward-looking statements, except as may be required by the federal securities laws.

CONTACT:

Nicholas O’Grady
President and Chief Financial Officer
952-476-9800
ir@northernoil.com




CONDENSED STATEMENTS OF OPERATIONS
(UNAUDITED)

Three Months Ended
September 30, 		Nine Months Ended
September 30,
(In thousands, except share and per share data) 2019 2018 2019 2018
REVENUES        
Oil and Gas Sales $ 157,989    $ 145,416    $ 440,519    $ 341,343   
Gain (Loss) on Derivative Instruments, Net 75,892    (43,148)   (27,139)   (105,622)  
Other Revenue 3    2    10    5   
Total Revenues 233,883    102,269    413,389    235,729   
OPERATING EXPENSES        
Production Expenses 32,347    18,161    83,146    45,198   
Production Taxes 15,391    13,579    41,944    31,633   
General and Administrative Expenses 4,206    4,674    15,506    9,593   
Depletion, Depreciation, Amortization and Accretion 55,566    30,258    146,791    71,485   
Impairment of Other Current Assets 5,275    —    7,969    —   
Total Operating Expenses 112,784    66,673    295,355    157,909   
INCOME FROM OPERATIONS 121,100    35,597    118,034    77,820   
OTHER INCOME (EXPENSE)        
Interest Expense, Net of Capitalization (21,510)   (20,438)   (58,836)   (65,948)  
Loss on the Extinguishment of Debt —    (9,542)   (425)   (100,375)  
Debt Exchange Derivative Gain/(Loss) (23)   13,063    1,390    13,063   
Contingent Consideration Loss (5,262)   —    (28,633)   —   
Other Income (Expense) 75    299    88    838   
Total Other Income (Expense) (26,719)   (16,618)   (86,416)   (152,423)  
INCOME (LOSS) BEFORE INCOME TAXES 94,381    18,979    31,619    (74,603)  
INCOME TAX PROVISION (BENEFIT) —    —    —    —   
NET INCOME (LOSS) $ 94,381    $ 18,979    $ 31,619    $ (74,603)  
Net Income (Loss) Per Common Share – Basic $ 0.24    $ 0.06    $ 0.08    $ (0.40)  
Net Income (Loss) Per Common Share – Diluted $ 0.24    $ 0.06    $ 0.08    $ (0.40)  
Weighted Average Shares Outstanding – Basic 396,044,887    300,517,497    382,044,068    188,152,998   
Weighted Average Shares Outstanding – Diluted 396,530,767    301,755,419    382,744,304    188,152,998   



CONDENSED BALANCE SHEETS

(In thousands, except par value and share data) September 30, 2019 December 31, 2018
ASSETS (Unaudited)
Current Assets:    
Cash and Cash Equivalents $ 1,901    $ 2,358   
Accounts Receivable, Net 103,226    96,353   
Advances to Operators 1,314    268   
Prepaid Expenses and Other 2,717    12,360   
Derivative Instruments 62,531    115,870   
Income Tax Receivable 420    1,205   
Total Current Assets 172,110    228,415   
Property and Equipment:    
Oil and Natural Gas Properties, Full Cost Method of Accounting    
Proved 4,043,897    3,431,428   
Unproved 11,145    4,307   
Other Property and Equipment 1,999    998   
Total Property and Equipment 4,057,041    3,436,732   
Less – Accumulated Depreciation, Depletion and Impairment (2,380,086)   (2,233,987)  
Total Property and Equipment, Net 1,676,955    1,202,745   
Derivative Instruments 42,682    61,843   
Deferred Income Taxes 420    420   
Other Noncurrent Assets, Net 9,842    10,223   
Total Assets $ 1,902,009    $ 1,503,645   
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:    
Accounts Payable $ 112,698    $ 55,015   
Accrued Liabilities 90,114    83,237   
Accrued Interest 17,567    16,468   
Debt Exchange Derivative —    18,183   
Contingent Consideration 10,058    58,069   
Other Current Liabilities 387    555   
Total Current Liabilities 230,824    231,526   
Long-term Debt, Net 1,140,072    830,203   
Asset Retirement Obligations 16,582    11,946   
Other Noncurrent Liabilities 417    105   
TOTAL LIABILITIES $ 1,387,894    $ 1,073,780   
COMMITMENTS AND CONTINGENCIES (NOTE 8)
STOCKHOLDERS’ EQUITY    
Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding —    —   


Common Stock, Par Value $.001; 675,000,000 Shares Authorized;
404,346,470 Shares Outstanding at 9/30/2019
378,333,070 Shares Outstanding at 12/31/2018 		404    378   
Additional Paid-In Capital 1,278,976    1,226,371   
Retained Deficit (765,266)   (796,884)  
Total Stockholders’ Equity 514,114    429,865   
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY $ 1,902,009    $ 1,503,645   


Non-GAAP Financial Measures

Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. Northern defines Adjusted Net Income (Loss) as net income (loss) excluding (i) (gain) loss on the mark-to-market of derivative instruments, net of tax, (ii) impairment of other current assets, net of tax, (iii) loss on the extinguishment of debt, net of tax, (iv) debt exchange derivative (gain) loss, net of tax, (v) contingent consideration (gain) loss, net of tax, and (vi) certain acquisition transaction costs, net of tax. Northern defines Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization and accretion, (iv) impairment of other current assets, (v) non-cash stock-based compensation expense, (vi) loss on the extinguishment of debt, (vii) debt exchange derivative (gain) loss, (viii) contingent consideration (gain) loss, and (ix) (gain) loss on the mark-to-market of derivative instruments. A reconciliation of each of these measures to the most directly comparable GAAP measure is included below. Management believes the use of these non-GAAP financial measures provides useful information to investors to gain an overall understanding of current financial performance. Specifically, management believes the non-GAAP financial measures included herein provide useful information to both management and investors by excluding certain expenses and unrealized commodity gains and losses that management believes are not indicative of Northern’s core operating results. In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring Northern’s performance, and management believes it is providing investors with financial measures that most closely align to its internal measurement processes.

Reconciliation of Adjusted Net Income

  Three Months Ended September 30, Nine Months Ended September 30,
(In thousands, except share and per share data) 2019 2018 2019 2018
Net Income (Loss) $ 94,381    $ 18,979    $ 31,619    $ (74,603)  
Add:                    
Impact of Selected Items:                    
(Gain) Loss on the Mark-to-Market of Derivative Instruments (57,506)   30,225    62,806    72,303   
Impairment of Other Current Assets 5,275    —    7,969    —   
Loss on the Extinguishment of Debt —    9,542    425    100,375   
Debt Exchange Derivative (Gain) Loss 23    (13,063)   (1,390)   (13,063)  
Contingent Consideration Loss 5,262    —    28,633    —   
Acquisition Transaction Costs 1,250    —    1,763    —   
Selected Items, Before Income Taxes (45,696)   26,705    100,204    159,615   
Income Tax of Selected Items(1)
(12,380)   (11,195)   (32,401)   (21,107)  
Selected Items, Net of Income Taxes $ (58,077)   $ 15,510    $ 67,803    $ 138,508   
Adjusted Net Income $ 36,304    $ 34,489    $ 99,422    $ 63,905   
Weighted Average Shares Outstanding – Basic 396,044,887    300,517,497    374,927,630    188,152,998   
Weighted Average Shares Outstanding – Diluted 396,530,767    301,755,419    375,736,820    188,709,068   
Net Income (Loss) Per Common Share – Basic $ 0.24    $ 0.06    $ 0.08    $ (0.40)  
Add:        
Impact of Selected Items, Net of Income Taxes (0.15)   0.05    0.19    0.74   
Adjusted Net Income Per Common Share – Basic $ 0.09    $ 0.11    $ 0.27    $ 0.34   
Net Income (Loss) Per Common Share – Diluted $ 0.24    $ 0.06    $ 0.08    $ (0.40)  
Add:        
Impact of Selected Items, Net of Income Taxes (0.15)   0.05    0.18    0.74   
Adjusted Net Income Per Common Share – Diluted $ 0.09    $ 0.11    $ 0.26    $ 0.34   


_____________
(1)For the three and nine months ended September 30, 2019, this represents a tax impact using an estimated tax rate of 24.5%, which includes an adjustment of $23.6 million and $7.9 million, respectively, for a change in valuation allowance. For the three and nine months ended September 30, 2018, this represents a tax impact using an estimated tax rate of 24.5%, which includes an adjustment of $4.7 million and $18.0 million, respectively, for a reduction in valuation allowance.


Reconciliation of Adjusted EBITDA

  Three Months Ended September 30, Nine Months Ended September 30,
(In thousands) 2019 2018 2019 2018
Net Income (Loss) $ 94,381    $ 18,979    $ 31,619    $ (74,603)  
Add:              
Interest Expense 21,510    20,438    58,836    65,948   
Income Tax Provision (Benefit) —    —    —    —   
Depreciation, Depletion, Amortization and Accretion 55,566    30,258    146,791    71,485   
Impairment of Other Current Assets 5,275    —    7,969    —   
Non-Cash Stock-Based Compensation (114)   1,535    4,280    1,973   
Loss on the Extinguishment of Debt —    9,542    425    100,375   
Debt Exchange Derivative (Gain) Loss 23    (13,063)   (1,390)   (13,063)  
Contingent Consideration Loss 5,262    —    28,633    —   
(Gain) Loss on the Mark-to-Market of Derivative Instruments (57,506)   30,225    62,806    72,303   
Adjusted EBITDA $ 124,396    $ 97,914    $ 339,968    $ 224,418