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):CurrentPrevious
1st Quarter – Actual34,568
2nd Quarter – Actual34,965
3rd Quarter – Actual40,786  
4th Quarter – Estimate43,500 – 44,50043,500 – 44,500
Annual – Estimate38,500 – 38,75038,650 – 39,150
2019 Guidance Ranges (in millions, except for net well data):CurrentPrevious
Organic(1) Net Wells Added to Production
33 – 3433 – 34
Organic(1) Drilling & Completion (D&C) Capital
$265 – $285$265 – $285
Ground Game 2019E Net Wells Added to Production5 – 73 – 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:CurrentPrevious
Production Expenses (per Boe)$8.00 – $8.50$8.00 – $8.50
Production Taxes10% 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,
 20192018% 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 Settlements47.00  53.96  (13)%
Costs and Expenses (per Boe):
Production Expenses$8.62  $7.39  17 %
Production Taxes4.10  5.53  (26)%
General and Administrative Expense1.12  1.90  (41)%
Depletion, Depreciation, Amortization and Accretion14.81  12.31  20 %
Net Producing Wells at Period End444.0  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 PeriodVolume (Bbls)Weighted Average Price (per Bbl)
2019:
4Q2,460,411  $58.96  
2020:
1Q2,490,106  $59.15  
2Q2,431,778  $58.44  
3Q2,340,348  $58.48  
4Q2,165,362  $58.00  
2021:
1Q1,690,050  $56.73  
2Q1,587,958  $57.24  
3Q1,418,410  $54.35  
4Q1,409,506  $54.37  
2022(1):
1Q453,780  $53.07  
2Q312,280  $52.30  
3Q306,576  $52.33  
4Q300,230  $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 PeriodTotal Volumes (Bbls)Weighted Average Differential
($/Bbl)
10/01/2019 - 12/31/2019951,000  ($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 Production13.3  
Net Producing Wells (Period-End)444.0  
Net Wells in Process (Period-End)24.2  
Increase in Wells in Process over 2018 Year-End1.4  
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)2019201820192018
REVENUES    
Oil and Gas Sales$157,989  $145,416  $440,519  $341,343  
Gain (Loss) on Derivative Instruments, Net75,892  (43,148) (27,139) (105,622) 
Other Revenue  10   
Total Revenues233,883  102,269  413,389  235,729  
OPERATING EXPENSES    
Production Expenses32,347  18,161  83,146  45,198  
Production Taxes15,391  13,579  41,944  31,633  
General and Administrative Expenses4,206  4,674  15,506  9,593  
Depletion, Depreciation, Amortization and Accretion55,566  30,258  146,791  71,485  
Impairment of Other Current Assets5,275  —  7,969  —  
Total Operating Expenses112,784  66,673  295,355  157,909  
INCOME FROM OPERATIONS121,100  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 TAXES94,381  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 – Basic396,044,887  300,517,497  382,044,068  188,152,998  
Weighted Average Shares Outstanding – Diluted396,530,767  301,755,419  382,744,304  188,152,998  




CONDENSED BALANCE SHEETS

(In thousands, except par value and share data)September 30, 2019December 31, 2018
ASSETS(Unaudited)
Current Assets:  
Cash and Cash Equivalents$1,901  $2,358  
Accounts Receivable, Net103,226  96,353  
Advances to Operators1,314  268  
Prepaid Expenses and Other2,717  12,360  
Derivative Instruments62,531  115,870  
Income Tax Receivable420  1,205  
Total Current Assets172,110  228,415  
Property and Equipment:  
Oil and Natural Gas Properties, Full Cost Method of Accounting  
Proved4,043,897  3,431,428  
Unproved11,145  4,307  
Other Property and Equipment1,999  998  
Total Property and Equipment4,057,041  3,436,732  
Less – Accumulated Depreciation, Depletion and Impairment(2,380,086) (2,233,987) 
Total Property and Equipment, Net1,676,955  1,202,745  
Derivative Instruments42,682  61,843  
Deferred Income Taxes420  420  
Other Noncurrent Assets, Net9,842  10,223  
Total Assets$1,902,009  $1,503,645  
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:  
Accounts Payable$112,698  $55,015  
Accrued Liabilities90,114  83,237  
Accrued Interest17,567  16,468  
Debt Exchange Derivative—  18,183  
Contingent Consideration10,058  58,069  
Other Current Liabilities387  555  
Total Current Liabilities230,824  231,526  
Long-term Debt, Net1,140,072  830,203  
Asset Retirement Obligations16,582  11,946  
Other Noncurrent Liabilities417  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 Capital1,278,976  1,226,371  
Retained Deficit(765,266) (796,884) 
Total Stockholders’ Equity514,114  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)2019201820192018
Net Income (Loss)$94,381  $18,979  $31,619  $(74,603) 
Add:            
Impact of Selected Items:            
(Gain) Loss on the Mark-to-Market of Derivative Instruments(57,506) 30,225  62,806  72,303  
Impairment of Other Current Assets5,275  —  7,969  —  
Loss on the Extinguishment of Debt—  9,542  425  100,375  
Debt Exchange Derivative (Gain) Loss23  (13,063) (1,390) (13,063) 
Contingent Consideration Loss5,262  —  28,633  —  
Acquisition Transaction Costs1,250  —  1,763  —  
Selected Items, Before Income Taxes(45,696) 26,705  100,204  159,615  
Income Tax of Selected Items(1)
(12,380) (11,195) (32,401) (21,107) 
Selected Items, Net of Income Taxes$(58,077) $15,510  $67,803  $138,508  
Adjusted Net Income$36,304  $34,489  $99,422  $63,905  
Weighted Average Shares Outstanding – Basic396,044,887  300,517,497  374,927,630  188,152,998  
Weighted Average Shares Outstanding – Diluted396,530,767  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)2019201820192018
Net Income (Loss)$94,381  $18,979  $31,619  $(74,603) 
Add:        
Interest Expense21,510  20,438  58,836  65,948  
Income Tax Provision (Benefit)—  —  —  —  
Depreciation, Depletion, Amortization and Accretion55,566  30,258  146,791  71,485  
Impairment of Other Current Assets5,275  —  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) Loss23  (13,063) (1,390) (13,063) 
Contingent Consideration Loss5,262  —  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