May 2017 NYSE MKT: NOG

May 2017 NYSE MKT: NOG

Statements included in this slide deck, or made by representatives of Northern Oil and Gas, Inc. ( Northern or the Company ) during the course of this presentation, that are not historical facts are forward-looking statements. These statements are based on certain assumptions and expectations made by the Company which reflect management s experience, estimates and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or anticipated in the forward-looking statements. These include risks relating to crude oil and natural gas prices; the pace of drilling and completions activity on our properties; our ability to acquire additional development opportunities; changes in our reserves estimates or the value thereof; our ability to raise or access capital; general economic or industry conditions, nationally and/or in the communities in which the Company conducts business; changes in the interest rate environment; legislation or regulatory requirements; conditions of the securities markets; changes in accounting principles, policies or guidelines; financial or political instability; acts of war or terrorism; other economic, competitive, governmental, regulatory and technical factors affecting our operations, products and prices; and other important factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. Northern undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information or future events. 2

Position: 151,672 net acres (1) Large net well inventory 82% held, 84% held in North Dakota (1) Production: 1Q 2017 averaged 13,299 BOE/d, 85% crude 214.6 net producing wells (2,973 gross) (1) 15.9 net wells-in-process (1) Hedges Protecting Liquidity: Swaps 2017 1,895,000 Bbls hedged @ $52.82 2018 1,717,000 Bbls hedged@ $53.52 Costless Collars 2017 225,000 Bbls collared @ $50.00 $60.06 2018 360,000 Bbls collared @ $50.00 $60.25 $196.5 million of liquidity on $325 million borrowing base (1)(2) Enterprise Value $956 (1) million: $127 million Market Cap (2) $700 million 8% coupon 2020 series bonds $134 million drawn on $325 million credit facility (1) (1) As of 3/31/17 (2) $325 million borrowing base became effective in May 2017 3

Northern Net Acreage Summary (2) 12% 18% 16% 88% 82% 84% North Dakota Montana Total % Held (1) Total % Non-Held ND % Held (1) ND % Non-Held Net Acres By County 30,490 27,714 Total Net Acreage: 151,672 (as of 3/31/17) ND: 133,967 Net Acres MT: 17,705 Net Acres 19,865 19,354 17,969 18,575 17,705 McKenzie Mountrail Williams Dunn Divide Other Montana North Dakota Montana (1) Includes acreage classified as held by production, held by operations or developed. (2) As of 3/31/2017 4

Extensive well database from the evaluation and participation in over 3000 gross wells in the basin drives investment decisions A sizable inventory of undrilled locations for future investment Net Undeveloped Breakeven Locations 557 607 466 325 $50 WTI $3.00 HH $60 WTI $3.00 HH $70 WTI $3.00 HH $80 WTI $3.00 HH Source: Company info, NDIC, and DrillingInfo NOG Leasehold NOG Producing Well 5

Increased activity levels has resulted in an increase in the number of inbound AFEs Permitting levels on Northern s acreage over the last 180 days supports continued investment opportunities Williston Basin Activity (1) 100 90 80 70 60 50 40 30 20 10 0 ND Well Spuds ND Rig Count Permits (1) As of March 31, 2017 Source: Company info, NDIC, and DrillingInfo NOG Leasehold Last 180 Days Permit on NOG s Acreage 6

$MM Committing Capital to the Highest Return Wells 50% 45% 40% 35% 30% 25% 20% 33% 26% 47% 29% Average IRR 26% 26% 28% 37% 36% 37% 16% 17% $10.0 $9.0 $8.0 $7.0 $6.0 $5.0 $4.0 9.0 9.3 8.4 7.9 8.6 7.3 8.2 Average AFE Costs 7.5 7.6 7.1 6.9 7.3 6.5 5.6 5.0 5.5 6.8 6.6 6.7 6.8 15% 12% 10% 13% 11% $3.0 10% 7% 7% $2.0 5% 1% 2% $1.0 0% Q4 '14 Q1 '15 Q2 '15 Q3 '15 Q4 '15 Q1 '16 Q2 '16 Q3 '16 Q4 '16 Q1 '17 $0.0 Q4 '14 Q1 '15 Q2 '15 Q3 '15 Q4 '15 Q1 '16 Q2 '16 Q3 '16 Q4 '16 Q1 '17 Consented IRR Non-Consent IRR Consented IRR Non-Consent IRR Source: All company wells as of March 31, 2017. IRRs based on internal estimate at time each well is evaluated for consent/non-consent. 7

Increasing Mix of High Intensity Completions 100% 90% 80% 70% 60% 50% 40% 79% 89% 90% 100% 98% 30% 59% 56% 62% 20% 39% 42% 10% 0% Q4 '14 Q1 '15 Q2 '15 Q3 '15 Q4 '15 Q1 '16 Q2 '16 Q3 '16 Q4 '16 Q1 '17 High Intensity Base Percentage of high intensity completions in Northern wells has increased significantly High intensity completions deliver best returns in current pricing environment Source: Company info, NDIC, and DrillingInfo NOG Leasehold NOG High Intensity Other Industry High Intensity 8

CCU Golden Creek 2-1-26MBH 1 Burlington (2016) Peak 30: 1,064 Boepd (90% oil) 10,162 Lateral Proppant: 523 lbs/lateral ft Fort Berthold 148-94-36D-25-10H 2 Halcon (2016) Peak 30: 1,030 Boepd (90% oil) Approx. 10,000 Lateral Proppant: Approx 500 lbs/lateral ft 3 BB-Eide-LE-151-95-3328H-1 Hess (2016) Peak 30: 1,624 Boepd (82% oil) 9,743 Lateral Proppant: 424 lbs/lateral ft 4 Rolfson S 5198 14-29 12B 5 Carscallen 31-14H Oasis (2016) Whiting (2016) Peak 30: 1,738 Boepd (78% oil) Peak 30: 1,877 Boepd (70% oil) Approx. 9,800 Lateral 10,706 Lateral Proppant: Approx 400 lbs/lateral ft Proppant: 823 lbs/lateral ft Lost Bridge Federal 148-96-9-4-10H Newfield (2016) 1 Peak 30: 1,143 Boepd (82% oil) 9,581 Lateral Proppant: 785 lbs/lateral ft 6 Peterson 6-4-4HC WPX (2016) Peak 30: 1,397 Boepd (91% oil) 14,928 Lateral Proppant: 900 lbs/lateral ft Rolla Federal 11-3-2TFH Whiting (2016) Peak 30: 1,988 Boepd (70% oil) 8,644 Lateral Proppant: 824 lbs/lateral ft 2 7 5 3 2 10 7 8 Nashville 5-21H 7 Continental (2016) Peak 30: 1,077 Boepd (86% oil) 12,326 Lateral Proppant: 1,950 lbs/lateral ft Wold 16-7TFH 3 Whiting (2016) Peak 30: 1,813 Boepd (70% oil) Approx. 9,700 Lateral Proppant: Approx 750 lbs/lateral ft 4 3 5 9 9 6 10 8 Rath Federal 5-22H Continental (2016) Peak 30: 1,166 Boepd (87% oil) 13,588 Lateral Proppant: 1,007 lbs/lateral ft Tat 5-33-28T2HD (2 nd Bench) 4 QEP (2016) Peak 30: 904 Boepd (91% oil) Approx. 10,000 Lateral Proppant: Approx 800 lbs/lateral ft 8 1 4 6 9 Maggie USA 21-4H Marathon (2016) Peak 30: 2,084 Boepd (85% oil) 9,473 Lateral Proppant: 1,579 lbs/lateral ft Fort Berthold 152-94-22D-15-10H Halcon (2016) 5 Peak 30: 1,290 Boepd (91% oil) Approx 10,000 Lateral Proppant: Approx 950 lbs/lateral ft 1 2 10 Rolla Federal 21-3-1H Whiting (2016) Peak 30: 1,879 Boepd (72% oil) 9,228 Lateral Proppant: 773 lbs/lateral ft NOG Leasehold Three Forks Wells Middle Bakken Wells Tackle 149-95-36C-25 TF Enerplus (2016) Peak 30: 1,165 Boepd (81% oil) 9,581 Lateral Proppant: 1,131 lbs/lateral ft Source: Company info, NDIC, and DrillingInfo 6 Brangus North 1-2H2 Continental (2016) Peak 30: 1,844 Boepd (85% oil) 9,838 Lateral Proppant: 1,015 lbs/lateral ft 7 Stenehjem 14H Abraxas (2016) Peak 30: 915 Boepd (75% oil) 9,449 Lateral Proppant: 803 lbs/lateral ft 8 Rufus USA 21-4TFH Marathon (2016) 9 Peterson 6 5-4HQ WPX (2016) 10 Peak 30: 2,474 Boepd (87% oil) 9,425 Lateral Proppant: 637 lbs/lateral ft Peak 30: 1,413 Boepd (91% oil) 14,887 Lateral Proppant: 611 lbs/lateral ft 9

Cum Production (Boe) Increasing Well Productivity 240,000 220,000 200,000 180,000 160,000 2012-2014 Cum 2015 Cum 2016 Cum 700 Mboe Type Curve 800 Mboe Type Curve 900 Mboe Type Curve 140,000 120,000 100,000 80,000 60,000 40,000 20,000 - - 1 2 3 4 5 6 7 8 9 10 11 12 Producing Months 2016 240 day rates up 59% over 2015; wells tracking a 1 million Boe type curve 2015 12 month cum up 48% over 2014; wells continue to track above 700 Mboe type curve Source: Company information as of March 31, 2017. NOG Leasehold Wells WOC 2016 Spuds 2015 Spuds 2012-2014 Spuds 10

Cum Production (Boe) Superior Well Performance 400,000 350,000 300,000 Average 700 Mboe TC 800 Mboe TC 900 Mboe TC 250,000 200,000 150,000 100,000 50,000 - - 30 60 90 120 150 180 210 240 270 300 330 360 Normalized Producing Days - Excluding Downtime 27 wells completed with 10+ million pounds of proppant; average volume of 12.7 million pounds Average production up 36% over 900 Mboe type curve after 210 days Source: Company information as of March 31, 2017. NOG Leasehold NOG Super Frac Other Industry Super Frac 11

IRR 100% 80% 60% 40% 20% Economics by EUR & Commodity Price 900 Mboe: $7MM CWC 800 Mboe: $7MM CWC 700 Mboe: $7MM CWC 35% 26% 21% 64% 48% 38% 106% 78% 60% 0% $50 WTI $3.00 HH $60 WTI $3.00 HH $70 WTI $3.00 HH Source: Company info, NDIC, and DrillingInfo NOG Leasehold Wells WOC 2016 Spuds 2015 Spuds 2012-2014 Spuds 12

Production (Boepd) Cap-ex in millions Production vs Capital Expenditures $537.5 $536.9 16000 12000 $414.0 $439.1 12,261 15,794 16,285 13,552 13,933 13,442 13,688 13,653 13,299 13,700 $510 $410 10,274 $310 8000 $210 4000 5,275 $128.7 $102.2 $110 0 $18.1 $16.5 $15.8 $34.1 $27.3 2011 2012 2013 2014 2015 1Q '16 2Q '16 3Q '16 4Q '16 2016 1Q '17 2017 Est $10 Cap-ex 13

Protecting Liquidity and Cash Flows Contract Period 2017: 2018: Volume (Bbls) Swaps (1) Collars (1) Weighted Average Price (per Bbl) Volume (Bbls) Weighted Average Price (per Bbl) 2Q 631,000 $51.75 75,000 $50.00 - $60.06 3Q 632,000 $53.36 75,000 $50.00 - $60.06 4Q 632,000 $53.36 75,000 $50.00 - $60.06 1Q 450,000 $53.67 90,000 $50.00 - $60.25 2Q 451,000 $53.67 90,000 $50.00 - $60.25 3Q 452,000 $53.68 90,000 $50.00 - $60.25 4Q 364,000 $52.94 90,000 $50.00 - $60.25 (1) Open crude oil derivative contracts scheduled to settle after March 31, 2017. 14

Capital Expenditures ($ millions) Ave. Daily Production (Boe) Capital Expenditures ($ millions) Ave Daily Production (Boe) Production: Total Production Operating Expenses for 2017 ~ 5.0 MMBoe LOE ($ per Boe) $9.00 $9.30 Tax (% of Oil & Gas Revenue) 10% Total G&A ($ per Boe) $3.00 $3.50 Average Differential for 2017 NYMEX WTI ($7.00) ($9.00) Capital Budget $102.2 Million $141 (1) 2016 Capital Expenditures includes an $8.9 million property acquisition in the 4 th quarter of 2016. $600 $500 $400 $300 $200 $100 $0 $140 $120 $100 Capital Expenditures (1) & Production 15,794 16,285 $537 $129 13,653 13,700 $85 $102 2014 2015 2016 2017 Est CapEx Production 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 Capital Expenditures (1) & Production by Quarter $80 $60 $40 $20 $0 Q4 '14 $45 Q1 '15 $33 $27 $23 $18 $17 $16 Q2 '15 Q3 '15 Q4 '15 CapEx Q1 '16 Q2 '16 Q3 '16 Production $34 $27 Q4 '16 Q1 '17 0 20,000 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 15

Dominate Non-op Position in the Williston Basin High Quality Oil Levered Asset Base Strong Liquidity & Hedge Protection De-risked non-op position comprised of over 151,000 net acres of largely HBP acreage Participated in approximately 20% of gross wells drilled and completed to the Bakken & Three Forks; 2,973 gross (214.6 net) producing wells at March 31, 2017 Multi-year drilling inventory (325 net locations breakeven or better at $50/Bbl) Significant upside outside the core and in lower Three Forks zones as well productivity and/or oil prices improve Borrowing base of $325 million providing $196 million of liquidity (1) Significant hedge position for the remainder of 2017 & 2018 to help protect cash flows and returns Ability to adjust spending up and down as returns dictate Positioned for Future Growth (1) At March 31, 2017 Enhanced completion designs and the expansion of core to drive continued well productivity improvements Accretive bolt-on acquisitions as the non-op consolidator in the Williston Basin Increase in activity to provide more investment opportunities 16

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Takeaway Options Takeaway Capacity (Mbopd) (1) 3,000 2,500 2,000 1,500 1,000 500 - Pipeline/Refining Rail Basin Production NDIC Production Forecast Pipeline and rail provide multiple destinations for Bakken crude Take away capacity additions in 2016/2017 provide excellent optionality for low cost transportation Given the pipe and rail options, there is ample capacity for Bakken crude production Current Capacity Additions (Mbopd) 2015 2016 2017 Est Pipeline 739,000 763,000 470,000 Local Refining 88,000 88,000 - Rail 1,420,000 1,520,000 - Additions in Year 470,000 Total Takeaway 2,247,000 2,371,000 2,841,000 (1) North Dakota Pipeline Authority (Oil Export Options-November 16, 2016) 18

Year Ended December 31, Production: 2012 2013 2014 2015 2016 Oil (MBbls) 3,465.3 4,046.7 5,150.9 5,168.7 4,325.9 Natural Gas and NGLs 1,768.9 2,572.3 3,682.8 4,651.6 4,026.9 Total Production (Mboe) 3,760.1 4,475.4 5,764.7 5,944.0 4,997.1 Realized Oil Price, including settled derivatives ($ / Bbl) $ 83.11 $ 84.89 $ 77.70 $ 69.94 $ 49.44 Realized Natural Gas and NGL Price ($ / Mcf) 4.67 5.24 6.38 1.60 1.82 Total Oil & Gas Revenues, including settled derivatives (millions) $ 296.2 $ 357.0 $ 423.7 $ 363.7 $ 221.2 Adjusted EBITDA (millions) (1) $ 225.3 $ 268.0 $ 309.6 $ 277.3 $ 148.5 Key Operating Statistics ($ / Boe) Average Realized Price (2) $ 78.79 $ 79.77 $ 73.51 $ 61.19 $ 44.27 Production Expenses 8.61 9.35 9.66 8.77 9.14 Production Taxes 7.58 7.81 7.58 3.63 3.10 General & Administrative Expenses-Cash 2.64 2.63 2.57 2.15 2.31 Total Cash Costs $ 18.83 $ 19.79 $ 19.81 $ 14.55 $ 14.55 Operating Margin ($ / Boe) $ 59.96 $ 59.98 $ 53.70 $ 46.64 $ 29.72 Operating Margin % 76.1% 75.2% 73.1% 76.2% 67.1% (1) Adjusted EBITDA is a non-gaap financial measure. See reconciliation to net income later in the appendix. (2) Includes the effect of settled hedges. 19

December 31, ($'s in millions) 2012 2013 2014 2015 2016 Assets Current assets $ 94.2 $ 104.4 $ 226.0 $ 128.8 $ 46.9 Property and equipment, net 1,083.2 1,397.3 1,761.9 589.3 376.2 Other assets 13.5 17.9 38.8 15.8 8.4 Total Assets $ 1,190.9 $ 1,519.6 $ 2,026.7 $ 733.9 $ 431.5 Liabilities Current liabilities $ 100.5 $ 194.1 $ 285.7 $ 78.1 $ 77.4 Debt 424.0 584.5 806.1 847.8 832.6 Other long-term liabilities 80.2 121.2 164.0 5.6 8.9 Stockholders' equity (Deficit) 586.2 619.8 770.9 (197.6) (487.4) Total Liabilities & Equity (Deficit) $ 1,190.9 $ 1,519.6 $ 2,026.7 $ 733.9 $ 431.5 Credit Statistics Adjusted EBITDA (1) $ 225.3 $ 268.0 $ 309.6 $ 277.3 $ 148.5 Interest expense (1)(2) $ 13.9 $ 30.1 $ 40.7 $ 53.4 $ 57.6 Adjusted EBITDA/Interest (1)(2) 16.2x 8.9x 7.6x 5.2x 2.6x Secured Debt $ 124.0 $ 75.0 $ 298.0 $ 150.0 $ 144.0 Total Debt $ 424.0 $ 584.5 $ 806.1 $ 847.8 $ 832.6 Secured Debt/Adjusted EBITDA (1) 0.6x 0.3x 1.0x 0.5x 1.0x Total Debt/Adjusted EBITDA (1) 1.9x 2.2x 2.6x 3.1x 5.6x (1) Year ended December 31 st (2) GAAP expense per audited financial statements (excludes non-cash interest expense) 20

Quarter Ended March 31, December 31, September 30, June 30, (In thousands) 2017 2016 2016 2016 Net Income (Loss) $16,941 $(12,330) $(46,619) $(108,979) Add Back: Interest Expense 16,304 16,195 16,145 16,046 Income Tax Benefit - (1,402) - - Depreciation, Depletion, Amortization and Accretion 12,828 13,523 13,698 16,177 Impairment of Oil and Natural Gas Properties - - 43,821 88,881 Non- Cash Share Based Compensation (1) 623 873 (713) 1,630 Write-off of Debt Issuance Costs - - - - Unrealized Loss (Gain) on Derivative Instruments (17,057) 18,212 5,646 30,507 Adjusted EBITDA $29,639 $35,071 $32,978 $44,262 (1)-Stock forfeiture recapture exceeded non-cash compensation expense in Q3 2016 21

2016 2015 2014 2013 2012 (In Thousands) Net (Loss) Income $ (293,494) $ (975,355) $ 163,746 $ 53,067 $ 72,285 Add Back: Interest Expense 64,484 58,360 42,106 32,709 13,875 Income Tax Provision (Benefit) (1,402) (202,424) 99,367 31,768 43,002 Depreciation, Depletion, Amortization and Accretion 61,244 137,770 172,884 124,383 98,923 Impairment of Oil and Natural Gas Properties 237,013 1,163,959 Non-Cash Share Based Compensation 3,182 6,273 2,759 4,799 12,382 Write-off of Debt Issuance Costs 1,090 Unrealized Loss (Gain) on Derivative Instruments 76,348 88,716 (171,276) 21,259 (15,147) Adjusted EBITDA $148,465 $277,299 $309,586 $267,985 $225,320 22