Exhibit 99.1

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

Second quarter production increased 66% over the prior year, averaging 34,965 barrels of oil equivalent (“Boe”) per day.
Cash flow from operations, excluding a $5.8 million net increase from changes in working capital, was $93.6 million in the second quarter, a 7% increase versus the first quarter.
Organic drilling and development capital expenditures totaled $71.9 million during the second quarter, a 3% decrease versus the first quarter.
Northern spent $10.5 million on senior note repurchases and $22.0 million on ground game acquisitions and associated development during the second quarter.

MINNEAPOLIS (BUSINESS WIRE) - August 1, 2019 - Northern Oil and Gas, Inc. (NYSE American: NOG) (“Northern”) today announced the company’s second quarter results and provided updated 2019 guidance.

Second quarter 2019 production totaled 3.2 million Boe and averaged 34,965 Boe per day, a 66% increase from the prior year. Oil and gas sales in the second quarter increased 37% from the prior year to $149.8 million. Net income in the second quarter was $44.4 million or $0.12 per diluted share. Adjusted Net Income in the second quarter was $45.5 million or $0.12 per diluted share. Adjusted EBITDA totaled $110.8 million in the second quarter, a 57% increase from the prior year or 6% increase sequentially. (See “Non-GAAP Financial Measures” below.)

“We continue to execute on our 2019 capital allocation plan, focusing on the highest returns available to us including our organic well opportunities and ground game acquisitions. This approach allowed us to remain within our production guidance despite approximately 2,500 Boe per day of curtailments due to continued basin-level infrastructure constraints,” commented Brandon Elliott, Chief Executive Officer. “Strong well performance, the closing of our VEN Bakken acquisition and continued success in our ground game are expected to expand our free cash flow profile to support additional debt reduction along with a stable and consistent return of capital to shareholders.”

Production and Operating Costs

Total second quarter production was 3.2 million Boe, driven by an additional 8.1 net wells added to production during the quarter, offset in part by continued infrastructure-driven curtailments. Midstream system expansions scheduled to come online in the second half of 2019 and early 2020 are expected to alleviate curtailments late in 2019. Oil price differentials of $5.29 per barrel are trending as expected, a 15% improvement from the first quarter of 2019. Ongoing production curtailments resulted in an increase in lease operating expenses (“LOE”) to $8.21 per Boe in the second quarter. Cash general and administrative expenses were $1.13 per Boe in the second quarter, up 7% from the first quarter primarily due to transaction and legal costs associated with the VEN Bakken acquisition. Northern anticipates a one-time expense of $1.3 million for advisory fees for this transaction to be expensed in the third quarter of 2019.

2019 Cash Flow Allocation

Northern continues to closely manage its discretionary cash flow allocation in an effort to produce the highest returns on capital employed. Northern spent, in aggregate, $22.0 million in the second quarter on ground game acquisitions and associated development capital. “Ground game” refers to Northern’s regular acquisition activity excluding larger, separately announced transactions such as the recent VEN Bakken acquisition. These transactions and wells in process will serve to increase Northern’s production and cash flows in 2019 and 2020, and bring forth additional future drilling opportunities. Northern spent $10.5 million on Senior Note repurchases in the second quarter. Northern expects sequential production, cash flow and net income growth throughout the remainder of 2019 and into 2020, due to the strong success of the ground game, the closing of the VEN Bakken acquisition, and relief from infrastructure constraints.

2019 Production Guidance Updated for Ground Game Acquisitions, VEN Bakken and Continued Curtailments

Current Williston Basin activity levels remain stable, and Northern now expects, on an organic basis combined with VEN Bakken, to drill 33 – 34 net wells in 2019. In addition, Northern expects to add an additional 3 – 5 net wells during the year through its ground game acquisition strategy, for a total of 36 – 39 total net wells added to production during 2019. Northern now expects production (inclusive of six months of production from the VEN Bakken acquisition that closed on July 1, 2019)



to average between 38,650 – 39,150 Boe per day for the full year of 2019. Northern’s previous cost and capital spending plan are being adjusted as well. LOE guidance is being adjusted to account for higher unit costs driven by curtailments and the higher LOE per unit costs associated with the VEN Bakken assets. Production taxes are being raised modestly, due to weaker overall gas and NGL prices in relation to crude oil prices, as a percentage of sales. Cash G&A per Boe guidance is being lowered to reflect higher expected production volumes, but partially offset by an estimated $1.9 million in transaction costs and fees incurred or expected to be incurred in connection with the VEN Bakken acquisition.

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 – Actual34,96534,500 – 35,500
3rd Quarter – Estimate41,500 – 42,500
4th Quarter – Estimate43,500 – 44,500
Annual – Estimate38,650 – 39,15035,000 – 36,000
2019 Guidance Ranges (in millions, except for net well data):CurrentPrevious
Organic(1) Net Wells Added to Production
33 – 3428 – 32
Organic(1) Drilling & Completion (D&C) Capital
$265 – $285$227 – $260
Ground Game 2019E Net Wells Added to Production3 – 5
Ground Game Acquisition Capital$25 – $50$20 – $25
Ground Game D&C Capital$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$6.75 – $7.75
Production Taxes (% of Oil & Gas Sales)~ 9.3%~ 9.1%
General and Administrative Expense (per Boe):
Cash(2)
$0.95 – $1.15$1.00 – $1.25
Non-Cash$0.50$0.50
Average Differential to NYMEX WTI$4.50 – $6.50$4.50 – $6.50
__________
(2) Inclusive of approximately $1.9 million of transaction costs and fees incurred or expected to be incurred in connection with the VEN Bakken acquisition.




SECOND QUARTER 2019 RESULTS

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

 Three Months Ended June 30,
 2019 2018 % Change
Net Production:   
Oil (Bbl)2,562,513 1,625,788 58 %
Natural Gas and NGLs (Mcf)3,715,936 1,736,651 114 %
Total (Boe)3,181,835 1,915,230 66 %
Average Daily Production:
Oil (Bbl)28,159 17,866 58 %
Natural Gas and NGLs (Mcf)40,834 19,084 114 %
Total (Boe)34,965 21,046 66 %
Average Sales Prices:
Oil (per Bbl)$54.56 $62.20 (12)%
Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl)1.85 (7.55)
Oil Net of Settled Derivatives (per Bbl)56.41 54.65 %
Natural Gas and NGLs (per Mcf)2.70 4.61 (41)%
Realized Price on a Boe Basis Including all Realized Derivative Settlements48.58 50.58 (4)%
Costs and Expenses (per Boe):
Production Expenses$8.21 $7.60 %
Production Taxes4.41 5.29 (17)%
General and Administrative Expense1.65 1.70 (3)%
Depletion, Depreciation, Amortization and Accretion14.49 11.80 23 %
Net Producing Wells at Period End340.6 248.3 37 %




Second Quarter Discretionary Capital Summary (in millions):Q2 2019
Senior Note Repurchases$10.5 
Ground Game Acquisition Capital$8.0 
Ground Game D&C Capital$14.0 
Total$32.5 




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 June 30, 2019.

Crude Oil Derivative Swaps
Contract PeriodVolume (Bbls)Weighted Average Price (per Bbl)
2019:
3Q2,430,444 $61.89 
4Q2,460,411 $62.01 
2020:
1Q2,476,456 $59.16 
2Q2,390,828 $58.48 
3Q2,340,348 $58.48 
4Q2,165,362 $58.00 
2021:
1Q1,375,050 $57.09 
2Q1,269,458 $57.75 
3Q636,410 $53.64 
4Q627,506 $53.67 
2022:
1Q453,780 $53.07 
2Q312,280 $52.30 
3Q306,576 $52.33 
4Q300,230 $52.35 


Crude Oil Derivative Basis Swaps(1)
Contract PeriodTotal Volumes (Bbls)Weighted Average Differential
($/Bbl)
07/01/2019 - 12/31/20191,840,000 ($2.41)
________________
(1) Basis swaps are settled using the TMX UHC 1a index, as published by NGX.

LIQUIDITY

As of June 30, 2019, Northern had $2.8 million in cash, $31.0 million in a restricted acquisition deposit, and $173.0 million outstanding on its revolving credit facility. Northern had total liquidity of $254.8 million as of June 30, 2019, consisting of cash and borrowing availability under the revolving credit facility. Northern repurchased $10.1 million in principal amount of its Senior Notes in the second quarter, offset partially by $1.7 million for the final anticipated PIK interest payment. The total amount of Senior Notes outstanding was $688.5 million as of June 30, 2019. Net of cash and the restricted acquisition deposit, Northern’s total debt was reduced by $12.2 million from the prior quarter.



CAPITAL EXPENDITURES & DRILLING ACTIVITY

(in millions, except for net well data)Three Months Ended June 30, 2019
Capital Expenditures Incurred:
Organic Drilling and Development Capital Expenditures$71.9 
Ground Game Acquisition Capital Expenditures$8.0 
Ground Game Drilling and Development Capital Expenditures$14.0 
Acquisition of Oil and Natural Gas Properties and Other$4.0 
Net Wells Added to Production8.1 
Net Producing Wells (Period-End)340.6 
Net Wells in Process (Period-End)25.0 
Increase in Wells in Process over 2018 Year-End2.2 
Weighted Average AFE for Wells Elected to During the Second Quarter$7.7 
Weighted Average AFE for Wells Elected to Year-to-Date$8.0 

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 2.2 well increase in net wells in process during the six months ended June 30, 2019 are reflected in the amounts incurred year-to-date for drilling and development capital expenditures.

ACREAGE

As of June 30, 2019, Northern controlled leasehold of approximately 163,558 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.

SECOND 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 Friday, August 2, 2019 at 11:00 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: 13692790 - Northern Oil and Gas, Inc. Second Quarter 2019 Conference Call
Replay Dial-In Number: (877) 660-6853 (US/Canada) and (201) 612-7415 (International)
Replay Access Code: 13692790 - Replay will be available through August 9, 2019

UPCOMING CONFERENCE SCHEDULE

EnerCom’s The Oil & Gas Conference
        August 12 - 13, 2019, Denver, CO

8th Annual Intellisight Conference
        August 14, 2019, Minneapolis, MN

Seaport Global Energy & Industrials Conference
        August 27 - 28, 2019, Chicago, IL




2019 Midwest IDEAS Investor Conference
August 28 - 29, 2019, Chicago IL

Johnson Rice & Company 2019 Energy Conference
        September 23- 29, 2019, New Orleans, LA

Friess Associates Research Round-Up
October 3, 2019, Jackson WY

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 and any properties pending acquisition, 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 consummate any pending acquisition transactions, other risks and uncertainties related to the closing of pending acquisition transactions, 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
Chief Financial Officer
952-476-9800
ir@northernoil.com





CONDENSED STATEMENTS OF OPERATIONS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2019 AND 2018
(UNAUDITED)

Three Months Ended
June 30,
Six Months Ended
June 30,
(In thousands, except share and per share data)2019201820192018
REVENUES    
Oil and Gas Sales$149,847 $109,047 $282,530 $195,928 
Gain (Loss) on Derivative Instruments, Net36,591 (42,203)(103,031)(62,474)
Other Revenue
Total Revenues186,440 66,846 179,506 133,459 
OPERATING EXPENSES    
Production Expenses26,132 14,549 50,799 27,037 
Production Taxes14,034 10,132 26,553 18,054 
General and Administrative Expenses5,250 3,251 11,300 4,918 
Depletion, Depreciation, Amortization and Accretion46,091 22,596 91,225 41,227 
Impairment of Other Current Assets2,694 — 2,694 — 
Total Operating Expenses94,200 50,528 182,571 91,236 
INCOME (LOSS) FROM OPERATIONS92,239 16,318 (3,065)42,223 
OTHER INCOME (EXPENSE)    
Interest Expense, Net of Capitalization(17,778)(22,403)(37,327)(45,510)
Loss on the Extinguishment of Debt(425)(90,833)(425)(90,833)
Debt Exchange Derivative Gain/(Loss)(4,873)— 1,413 — 
Contingent Consideration Loss(24,763)— (23,371)— 
Other Income (Expense)(1)371 14 538 
Total Other Income (Expense)(47,840)(112,865)(59,697)(135,805)
INCOME (LOSS) BEFORE INCOME TAXES44,399 (96,547)(62,762)(93,582)
INCOME TAX PROVISION (BENEFIT)— — — — 
NET INCOME (LOSS)$44,399 $(96,547)$(62,762)$(93,582)
Net Income (Loss) Per Common Share – Basic$0.12 $(0.49)$(0.17)$(0.71)
Net Income (Loss) Per Common Share – Diluted$0.12 $(0.49)$(0.17)$(0.71)
Weighted Average Shares Outstanding – Basic378,368,462 196,140,610 374,927,630 131,039,552 
Weighted Average Shares Outstanding – Diluted378,724,511 196,140,610 374,927,630 131,039,552 




CONDENSED BALANCE SHEETS
JUNE 30, 2019 AND DECEMBER 31, 2018 

(In thousands, except par value and share data)June 30, 2019December 31, 2018
ASSETS(Unaudited)
Current Assets:  
Cash and Cash Equivalents$2,794 $2,358 
Accounts Receivable, Net87,697 96,353 
Advances to Operators1,425 268 
Prepaid Expenses and Other8,226 12,360 
Derivative Instruments32,531 115,870 
Income Tax Receivable395 1,205 
Total Current Assets133,068 228,415 
Property and Equipment:  
Oil and Natural Gas Properties, Full Cost Method of Accounting  
Proved3,607,214 3,431,428 
Unproved9,249 4,307 
Other Property and Equipment1,609 998 
Total Property and Equipment3,618,072 3,436,732 
Less – Accumulated Depreciation, Depletion and Impairment(2,324,790)(2,233,987)
Total Property and Equipment, Net1,293,282 1,202,745 
Derivative Instruments26,610 61,843 
Deferred Income Taxes420 420 
Acquisition Deposit31,000 — 
Other Noncurrent Assets, Net10,012 10,223 
Total Assets$1,494,391 $1,503,645 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:  
Accounts Payable$175,164 $135,483 
Accrued Expenses2,070 2,769 
Accrued Interest15,050 16,468 
Debt Exchange Derivative2,791 18,183 
Derivative Instruments95 — 
Contingent Consideration36,992 58,069 
Other Current Liabilities566 555 
Total Current Liabilities232,726 231,526 
Long-term Debt, Net857,198 830,203 
Derivative Instruments1,644 — 
Asset Retirement Obligations12,845 11,946 
Other Noncurrent Liabilities329 105 
TOTAL LIABILITIES$1,104,742 $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;
389,435,991 Shares Outstanding at 6/30/2019
378,333,070 Shares Outstanding at 12/31/2018
389 378 
Additional Paid-In Capital1,248,906 1,226,371 
Retained Deficit(859,647)(796,884)
Total Stockholders’ Equity389,649 429,865 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY$1,494,391 $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 June 30,Six Months Ended June 30,
(In thousands, except share and per share data)2019 2018 2019 2018 
Net Income (Loss)$44,399 $(96,547)$(62,762)$(93,582)
Add:        
Impact of Selected Items:        
(Gain) Loss on the Mark-to-Market of Derivative Instruments(31,857)29,936 120,311 42,077 
Impairment of Other Current Assets2,694 — 2,694 — 
Loss on the Extinguishment of Debt425 90,833 425 90,833 
Debt Exchange Derivative (Gain) Loss4,873 — (1,413)— 
Contingent Consideration (Gain) Loss24,763 — 23,371 — 
Acquisition Transaction Costs513 — 513 — 
Selected Items, Before Income Taxes1,411 120,769 145,901 132,910 
Income Tax of Selected Items(1)(346)(6,180)(20,696)(9,912)
Selected Items, Net of Income Taxes$1,065 $114,589 $125,205 $122,998 
Adjusted Net Income$45,465 $18,042 $62,443 $29,417 
Weighted Average Shares Outstanding – Basic378,368,462 196,140,610 374,927,630 131,039,552 
Weighted Average Shares Outstanding – Diluted378,724,511 196,413,013 375,736,820 131,248,726 
Net Income (Loss) Per Common Share – Basic$0.12 $(0.49)$(0.17)$(0.71)
Add:    
Impact of Selected Items, Net of Income Taxes— 0.58 0.33 0.93 
Adjusted Net Income Per Common Share – Basic$0.12 $0.09 $0.16 $0.22 
Net Income (Loss) Per Common Share – Diluted$0.12 $(0.49)$(0.17)$(0.71)
Add:    
Impact of Selected Items, Net of Income Taxes— 0.58 0.33 0.93 
Adjusted Net Income Per Common Share – Diluted$0.12 $0.09 $0.16 $0.22 
_____________



(1)For the three months ended June 30, 2019, this represents a tax impact using an estimated tax rate of 24.5%, which does not include an adjustment for a change in valuation allowance. For the six months ended June 30, 2019, this represents a tax impact using an estimated tax rate of 24.5%, and includes a $15.1 million adjustment for an increase in valuation allowance. For the three and six months ended June 30, 2018, this represents a tax impact using an estimated tax rate of 24.5%, which includes an adjustment of $23.4 million and $22.7 million, respectively, for a reduction in valuation allowance.


Reconciliation of Adjusted EBITDA

 Three Months Ended June 30,Six Months Ended June 30,
(In thousands)2019 2018 2019 2018 
Net Income (Loss)$44,399 $(96,547)$(62,762)$(93,582)
Add:      
Interest Expense17,778 22,403 37,327 45,510 
Income Tax Provision (Benefit)— — — — 
Depreciation, Depletion, Amortization and Accretion46,091 22,596 91,225 41,227 
Impairment of Other Current Assets2,694 — 2,694 — 
Non-Cash Stock-Based Compensation1,643 1,324 4,394 438 
Loss on the Extinguishment of Debt425 90,833 425 90,833 
Debt Exchange Derivative (Gain) Loss4,873 — (1,413)— 
Contingent Consideration (Gain) Loss24,763 — 23,371 — 
(Gain) Loss on the Mark-to-Market of Derivative Instruments(31,857)29,936 120,311 42,077 
Adjusted EBITDA$110,810 $70,546 $215,572 $126,504