NYSE American: NOG February 2018

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 successfully complete the proposed exchange with the holders of our senior notes, including satisfying the conditions to such exchange; 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.

1) INTRODUCTION 2) Q4 EARNINGS AND GUIDANCE 3) CAPITAL STRUCTURE UPDATE 4) ASSET OVERVIEW 5) APPENDIX

4 ~50% Well Performance THE BAKKEN IS BACK = ~50% ~60% Basin Differentials ~Flat D&C Costs Rigs Active + + + Operational efficiencies offsetting the cost of enhanced completions… …resulting in bigger wells being drilled for the same cost as prior years Better wells coupled with lower oil differentials … …is driving higher activity levels in the basin which means… Source: DrillingInfo, Baker Hughes, NDIC, and North Dakota Pipeline Authority (1) Northern’s AFE’s averaged ~$7.66mm and ~$7.52mm in 2015 and 2017, respectively, resulting in a ~2% decrease between the two periods (2) As of 2/13/2018, total proppant per well averaged ~4.6 million lbs and ~9.1 millions lbs in the Williston Basin for the years 2015 and 20017, respectively (3) Represents average 6 month boe, from 2015 to 2017 normalized to 10,000’. (4) Represents difference between three months ended December 31, 2015 and December 31, 2017. (5) Represents average Q4 rig count in the Williston Basin from 2016 to 2017. (1,2) (3) (4) (5)

5

6 ~16.7 mboed 4Q17 production 143+ THOUSAND NET ACRES ~88% HELD by production or operations 45 operating PARTNERS 83% OIL-WEIGHTED of 4Q17 production#1 BAKKEN NON-OP PRODUCER Note: As of 12/31/2017 unless otherwise noted (1) Currently active wells (PDP & Drilling/Completing) presented on a gross basis (2) Working interest based on producing wells as of 12/31/2017 (3) Based on internal company estimates (4) Assumes 20 wells per rig over 365 day calendar year (5) Based on FYE17 strip prices (see appendix) and internal company estimates (6) WTI breakeven prices based on internal company estimates,$3.00/mmBtu Henry Hub Price, and minimum 10% return 3,500+ WELLS currently active (1) 7.0% AVERAGE working interest (2) ~704 NET REMAINING LOCATIONS (3) 35.2 RIG YEARS of net inventory (3,4) ~47% AVERAGE IRR%SingleWell (5) 73%+ of net inventory has <$50/bbl BREAKEVEN (6)

7 704 67 44 128 160 305 704 67 111 239 399 704 100%+ 75%+ 50%+ 25%+ <25% Total Net Undeveloped Locations by IRR(1) Avg. EUR (Mboe): 1,087 1,049 931 782 598 %Oil 79% 77% 80% 79% 79% Avg. PV-10 ($MM): 12.2 8.9 7.4 4.5 1.8 Economics by EUR & Commodity Price(2) (1) Uses FYE17 NYMEX Pricing (see appendix) and NOG internal type curves (2) Includes $4.00/bbl differential 61% 110% 181% 50% 91% 146% 40% 71% 115% 29% 52% 81% 22% 40% 65% 0% 20% 40% 60% 80% 100% 120% 140% 160% 180% 200% $50 WTI $3.00 HH $60 WTI $3.00 HH $70 WTI $3.00 HH IR R 1,100 Mboe: $7.5MM CWC 1,000 Mboe: $7.5MM CWC 900 Mboe: $7.5MM CWC 800 Mboe: $7.5MM CWC 700 Mboe: $7.5MM CWC

$510 $101 $147 $758mm Differentiated Value Proposition Total Net Inventory: 35+ Rig Years 8 Company Case PV10% Bridge (1) Represents reserves prepared in accordance with the guidance and pricing prescribed by the SEC in Industry Guide 2. The unescalated twelve month arithmetic average of the first day of the month posted prices were adjusted for transportation and quality differentials to arrive at prices of $45.90/bbl for oil and $3.34/mcf for natural gas, production costs were held constant for the life of the wells (2) PV10% may be considered a non-GAAP financial measure. See appendix for reconciliations to the most directly comparable GAAP measure (3) Using FYE17 strip pricing (see appendix), NOG internal type curves, a 20 net well per year drill schedule, and total 3P inventory. Production costs consistent with SEC case SEC Pricing(1,2) FYE17 NYMEX Pricing ~$1.7Bn+ PDP PDNP PUD NOG 3P PV10%(2,3) (Internal Estimates) FYE2017 Ryder Scott 1P PV10% (SEC 5 Year PUD Limitations)

$203 $155 $700 $300 $344 2018 2019 2020 2021 2022 2023 2024 Debt Maturity by Year ($mm) $177 $348 – $400 Since 3Q17, Northern has been in the process of a financial transformation, positioning itself for growth in one of the nation’s premier “rate-of-change” oil plays with the following goals: Fin a n c ia l Reducing net leverage by 2.2x TURNS Nearly DOUBLING available liquidity Decreasing debt maturing within three years by $652mm 6.3x 4.1x 3.1x 2.5x 7.0x Total Liquidity ($mm) S truct u ra l Functionally “Clean” Balance Sheet First Step: Aligned Key Stakeholder Interest  Largest noteholders have agreed to roll ~$155mm into common equity  Will own ~30% of Pro-forma shares outstanding  Top 3 “insider” equity holders (and others) have agreed to inject $40mm of common equity into Northern Second Step: Execute Strategic Growth  Brought back Northern’s founder as strategic advisor to the board  Starting to evaluate “roll-up” opportunities in the Bakken  Only considering transactions that are accretive to all stakeholders (1) Note: 4Q17 Pro-Forma assumes execution of contemplated debt exchange, including the $156mm equity raise contemplated thereby (1) Total liquidity in 4Q17 includes committed delayed draw capacity under TPG term loan 3Q17 4Q17 Pro-Forma 4Q17 Annualized Pro-Forma Net Debt / Adjusted EBITDA TTM Adj. EBITDA Q4 Annualized Adj. EBITDA 9

Ba c k grou n d The s is  When evaluating acquisitions, Northern has a significant competitive advantage over its peers given considerable amounts of data accumulated over 10 years of participating in 3,500+ Bakken wells across its 143k net acres  We believe that the oil price downturn has created an outstanding buying opportunity…  Bakken core: 12mm acres which can support ~45,000 wells  There are presently ~12,500 wells in the core leaving ~32,500 remaining locations  Key Assumptions:  Current pace of drilling: 90 wells per month  Average rig cadence: 20 wells per year per rig  Well costs: $7.5mm  Average Op/Non-Op WI% split: 70% / 30% per wellbore  The Opportunity:  At the current drilling pace, non-op producers receive $203mm of capital calls per month to participate in Bakken development  ~$203mm = 90wells per month x $7.5mmD&C costs x 30%non-op WI%  As operators expand their Bakken drilling programs, non-op capital calls increase ~$19mm per month for every 5 rigs added to the basin Given Northern’s improved balance sheet, this significant monthly capital requirement uniquely positions us to be a non-op consolidator in the basin as very few non-operators (whether institutional or family owned) have the liquidity or desire for this level of capital exposure 10

11 Commentary General Considerations  Northern believes the current and future acquisition opportunities are attractive due to a dislocation in the market:  Forced sellers: As producers switch to pad drilling, many non-operators are undercapitalized to fund the increased AFE burden on their acreage  Proactive Sourcing: As AFEs hit, Northern has the opportunity to proactively approach other non-ops and purchase their WI% in units. Given NOG’s scale and expansive footprint, it sees more AFEs than any other company in the basin, which creates significant off-market acquisition opportunities  Strong Relationships: Deal flow is generated through strong networks and relationships which gain access to narrowly marketed assets  Lack of Buyer Competition: There is a limited buyer set interested in the size of deals available, which has created a “buyer’s market” Opportunity Set Purchase of Single Wellbore AFEs  As non-op players have become capital constrained due to the bank credit pull back, they have increasingly looked to defer capex and this is the first off-ramp  Owners are faced with the choice of either non-consenting proposed wells or selling the proposed wellbore’s working interest  Potential Counterparties: Small non-op companies and landowners Purchase of PDP and Acreage  Non-op entities looking to sell down their entire position including current production, working interest, and any outstanding AFEs  Potential Counterparties: Private equity backed non-op portfolio companies and institutionally owned non-op Clean-up Operator’s Non-op Position  As operators seek to concentrate their D&C budgets on operated positions, they are increasingly likely to sell AFEs in, or divest completely non-op assets  Potential Counterparties: Public operators, private equity backed operators, and operators who have recently emerged from bankruptcy

1) INTRODUCTION 2) Q4 EARNINGS AND GUIDANCE 3) CAPITAL STRUCTURE UPDATE 4) ASSET OVERVIEW 5) APPENDIX

13 15,321 16,742 Q317 Q417 $35.7 $48.5 Q317 Q417 $8.94 $8.65 Q317 Q417 GREW PRODUCTION (Boed) Significant MOMENTUM Heading Into 2018Q3 Source: Company info INCREASED Adjusted EBITDA ($MM) DIFFERENTIALS DECREASED ($/Bbl) REDUCED CASH OPERATING COSTS PER BARREL ($/Bbl) ~10% ~45% ~5% 1 2 3 4 Q4 Quarterly Comparison ~35% $6.22 $3.51 Q317 Q417

13,299 13,794 15,321 16,742 14,800 17,200 - 17,800 1Q17 2Q17 3Q17 4Q17 2017 2018E Oil (Boed) Natural Gas (Boed) 14 FULL YEAR 2018 GUIDANCE SUMMARY 2017 Actuals 2018 Guidance Range Production Avg. Daily Prod. (Boed) 14,800 17,200 - 17,800 % Oil 84% 84% % Natural Gas 16% 16% Income Statement ($/Boe) Differential to WTI $5.87 $3.50 - $4.50 LOE (incl. workovers) $9.21 $8.75 - $9.25 G&A $3.51 $2.00 - $2.50 Prod Taxes (% Rev.) 9.8% 9.2% - 9.5% Capital Expenditures ($MM) Total Development Capital $144.0 $152 - $167 Other Capex $12.0 $13.0 Operated Completions Gross Well Adds 354 360 - 390(1) Net Completions 16.9 20 - 22 COMMENTARY Average Daily Production (Boed) Quarters Annual  Northern anticipates that net well additions will increase from 16.9 in 2017 to 20 – 22 in 2018  The Company believes completion activity will be weighted 35% / 65% between 1H18 and 2H18, respectively  Increased activity is expected to drive a 16 - 20% year over year increase in production (1) Based on 5.6% average WI on wells in process ~26%

1) INTRODUCTION 2) Q4 EARNINGS AND GUIDANCE 3) CAPITAL STRUCTURE UPDATE 4) ASSET OVERVIEW 5) APPENDIX

16 T P G T e rm Lo a n P rop o s e d B on d E x c h a ng e  The Company took an important first step in addressing its capital structure with the completion of a five year $400 million Term Loan Credit Facility with TPG in November 2017  Proceeds were used to refinance its pending September 2018 RBL maturity, providing the Company with considerable liquidity, financial flexibility, and runway  Northern is in the process of a comprehensive recapitalization transaction and has announced that it has entered into a privately negotiated exchange agreement with certain holders representing 71% of the principal outstanding of its $700 million, 8% senior unsecured notes due 2020 (the “Notes”)  Holders of $497 million of the Notes have entered into the exchange agreement in connection with the transaction structure outlined on the next slide, which includes raising $156 million of new equity, of which up to $78 million can be raised through the contribution of additional properties in the Williston Basin  Of the $78 million of new equity required to be raised in cash, $40 million is already committed at $3.00 per share (subject to adjustment) by TRT Holdings, Inc., Bahram Akradi, Michael Reger, and certain other investors, contingent on closing of the exchange

17 Exchange Agreement  Exchange Agreement entered into with Cooperating Group of Noteholders, holding approximately 71%, or $497 million, of Senior Notes due 2020  TRT Holdings ($205 million)  Other Cooperating Noteholders ($292 million)  Transaction will not be open to all bondholders Exchange Currency  Second Lien Senior Secured Notes due 2023 (8.5% Cash Pay plus 1.0% PIK) (the “New 2L Notes”)  Newly issued NOG equity at $3.00 per share (per share exchange price subject to adjustment based on outcome of equity raise) Terms and Conditions of Exchange Offer  Exchange terms for TRT at 60/40% debt/equity ratio:  100% participation of $205 million Notes position  60% of tendered bonds ($123 million) will be exchanged for New 2L Notes at 102% of par ($125 million)  40% of tendered bonds ($82 million) will be exchanged for equity at an exchange price of $3.00 per share, subject to adjustment  Exchange terms for all other Cooperating Noteholders:  75% of tendered bonds ($219 million) will be exchanged for New 2L Notes  25% of tendered bonds ($73 million) will be exchanged for equity at an exchange price of $3.00 per share, subject to adjustment  Share price for equitization subject to MFN with share price of equity raise (bondholders exchange price will be same as equity price received)  Cooperating Noteholders agree to lock-up on newly-issued NOG shares for 90 days after the Closing Date, 7/31/18 (assuming a 4/30/18 Closing Date)  Cooperating Noteholders are permitted to sell their Notes prior to Closing Date so long as transferee becomes a party to the Exchange Agreement Description of Equity Raise  At least $156 million of cash (or contribute up to 50% of the amount in assets) for newly issued NOG equity at $3.00 per share (52.00 million shares) (subject to adjustment)  The Company received commitments from certain initial investors to purchase $40 million of common equity at the date of the Exchange Agreement  Bahram Akradi, Michael Reger, and TRT Holdings, Inc., part of initial investors, agreed to lock-up on their newly-issued NOG shares until 90 days after the Closing Date, 7/31/18 (assuming 4/30/18 Closing Date) Key Conditions Precedent  Exchange offer contingent on $156 million equity raise ($40mm committed from key shareholders)  1L Noteholder consent required  Shareholder approval

Sources (in $ millions) New 8.5%/9.5% PIK Toggle 2L Notes due 2023 $344.3 Equitization of Debt 154.9 Equity Raise 156.0 Total Sources $655.2 Uses Exchange 8.00% Senior Unsecured Notes due 2020 $342.0 Equitize 8.00% Senior Unsecured Notes due 2020 154.9 Estimated Transaction Fees 10.1 Exchange Premium 2.0 Cash to Balance Sheet 146.2 Total Uses $655.2 18 COMMENTARY  The capitalization table below pro-formas Northern’s 12/31/17 balance sheet for a $156mm equity raise and the proposed bond exchange occurring contemporaneously  Per the exchange agreement, the depicted $156mm equity raise is required prior to the consummation of the bond exchange  It is anticipated that the bond exchange will close shortly after the equity offering As of Adj. Pro forma Adj. Pro forma (in $ millions) 12/31/2017 Equity Issuance for Equity Issuance Debt Swap for Debt Swap Cash $102.2 $146.2 $248.4 – $248.4 Secured Debt TPG Secured Term Facility $300.0 – $300.0 – $300.0 8.5%/9.5% PIK Toggle 2L Notes due 2023 – – – 344.3 344.3 Unsecured Debt 8.00% Senior Unsecured Notes due 2020 700.0 – 700.0 (496.9) 203.1 Total Debt $1,000.0 – $1,000.0 ($152.6) $847.4 Net Debt 897.8 (146.2) 751.6 (152.6) 599.0 Equity (491.6) 156.0 (335.6) 154.9 (180.8) Total Capitalization $508.4 $156.0 $664.4 $2.3 $666.7 Liquidity TPG Delayed Draw Term Facility Drawn $300.0 $300.0 $300.0 Available 100.0 100.0 100.0 Liquidity 202.2 348.4 348.4 Credit Metrics 4Q17 TTM EBITDA $144.7 $144.7 $144.7 Debt / 4Q17 TTM EBITDA 6.9x 6.9x 5.9x Net Debt / 4Q17 TTM EBITDA 6.2x 5.2x 4.1x 4Q17 Annualized EBITDA $194.0 $194.0 $194.0 Debt / 4Q17 Annualized EBITDA 5.2x 5.2x 4.4x Net Debt / 4Q17 Annualized EBITDA 4.6x 3.9x 3.1x

1) INTRODUCTION 2) Q4 EARNINGS AND GUIDANCE 3) CAPITAL STRUCTURE UPDATE 4) ASSET OVERVIEW 5) APPENDIX

20 89% 11% ND % Held ND % Non-Held North Dakota Montana 90% 10% North Dakota Montana 88% 12% Total % Held Total % Non-Held 30,008 27,499 18,722 17,783 16,703 18,032 14,506 McKenzie Mountrail Williams Dunn Divide Other Montana Total Net Acreage: 143,253(1) ND: 128,747 Net Acres MT: 14,506 Net Acres Net Acres By County (1) As of 12/31/17 (2) Includes acreage classified as held by production, held by operations or developed Northern Net Acreage Summary(1) (2) (2)

21 19.2% 11.4% 8.8% 6.7% 6.6% 5.5% 5.4% 4.2% 3.5% 3.2% 3.0% 22.5% Percentage of Net Producing Wells – By Operator Top 10 Operators 1 Slawson 2 Continental 3 Whiting 4 Hess 5 ConocoPhillips 6 Oasis 7 XTO Energy 8 EOG 9 Petro-Hunt Dakota 10 Statoil Source: Company info as of December 31, 2017 Petro-Hunt Dakota, LLC Other Operators (less than 3%)

22 (1) Wells assigned to years based on year in which they started producing. Cumulative type curves comprised of the following numbers of gross wells: 2012-2014 – 1,443; 2015 – 303; 2016 – 157; 2017 – 255. Includes producing wells as of December 31, 2017 with at least 30 days of production  2017 – 12 month cum up 29% over 2016;  2017 – Average wells tracking 970 Mboe type curve  Wells assigned by year completed NOG Leasehold Wells WOC 2017 Spuds 2016 Spuds 2015 Spuds 2012-2014 Spuds Increasing Well Productivity - 40,000 80,000 120,000 160,000 200,000 240,000 280,000 - 1 2 3 4 5 6 7 8 9 10 11 12 C u m P ro d u cti o n ( B o e ) Producing Months 2012 - 2014 Cum 2015 Cum 2016 Cum 2017 Cum 700 Mboe Type Curve 800 Mboe Type Curve 900 Mboe Type Curve 1,000 Mboe Type Curve (1) (1) (1) (1) ~29%

1) INTRODUCTION 2) Q4 EARNINGS AND GUIDANCE 3) CAPITAL STRUCTURE UPDATE 4) ASSET OVERVIEW 5) APPENDIX

24 Protecting Liquidity and Cash Flows Swaps(1) Contract Period Volume (Bbls) Weighted Average Price (per Bbl) 2018: 1Q 860,400 $53.42 2Q 829,000 $53.09 3Q 753,000 $53.42 4Q 643,000 $53.54 2019: 1Q 621,000 $53.01 2Q 600,600 $52.89 3Q 524,400 $52.30 4Q 469,200 $52.22 2020: 1Q 327,600 $50.49 2Q 309,400 $50.41 3Q 303,600 $50.37 4Q 303,600 $50.37 (1) Open crude oil derivative contracts scheduled to settle after December 31, 2017.

25 Year Ended December 31, 2013 2014 2015 2016 2017 Production: Oil (MBbls) 4,046.7 5,150.9 5,168.7 4,325.9 4,537.3 Natural Gas and NGLs (Mmcf) 2,572.3 3,682.8 4,651.6 4,026.9 5,187.9 Total Production (Mboe) 4,475.4 5,764.7 5,944.0 4,997.1 5,401.9 Revenue Realized Oil Price, including settled derivatives ($ / Bbl) $ 84.89 $ 77.70 $ 68.94 $ 49.44 $ 45.92 Realized Natural Gas and NGL Price ($ / Mcf) 5.24 6.38 1.60 1.82 3.74 Total Oil & Gas Revenues, including settled derivatives (millions) $ 357.0 $ 423.7 $ 363.7 $ 221.2 $ 227.7 Adjusted EBITDA (millions)(1) $ 268.0 $ 309.6 $ 277.3 $ 148.5 $ 144.7 Key Operating Statistics ($ / Boe) Average Realized Price(2) $ 79.77 $ 73.51 $ 61.19 $ 44.27 $ 42.16 Production Expenses 9.35 9.66 8.77 9.14 9.21 Production Taxes 7.81 7.58 3.63 3.10 3.81 General & Administrative Expenses-Cash 2.63 2.57 2.15 2.31 2.38 Total Cash Costs $ 19.79 $ 19.81 $ 14.55 $ 14.55 $ 15.40 Operating Margin ($ / Boe) $ 59.98 $ 53.70 $ 46.64 $ 29.72 $ 26.76 Operating Margin % 75.2% 73.1% 76.2% 67.1% 63.5% (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

26 ($'s in millions) Year Ended December 31, 2013 2014 2015 2016 2017 Assets Current assets $ 104.4 $ 226.0 $ 128.8 $ 46.9 $ 152.8 Property and equipment, net 1,397.3 1,761.9 589.3 376.2 473.2 Other assets 17.9 38.8 15.8 8.4 6.3 Total Assets $ 1,519.6 $ 2,026.7 $ 733.9 $ 431.5 $ 632.3 Liabilities Current liabilities $ 194.1 $ 285.7 $ 78.1 $ 77.4 $ 123.6 Debt 584.5 806.1 847.8 832.6 979.3 Other long-term liabilities 121.2 164.0 5.6 8.9 20.2 Stockholders' equity (Deficit) 619.8 770.9 (197.6) (487.4) (490.8) Total Liabilities & Equity $ 1,519.6 $ 2,026.7 $ 733.9 $ 431.5 $ 632.3 Credit Statistics Adjusted EBITDA(1) $ 268.0 $ 309.6 $ 277.3 $ 148.5 $ 144.7 Secured Debt $ 75.0 $ 298.0 $ 150.0 $ 144.0 $ 287.4 Total Debt $ 584.5 $ 806.1 $ 847.8 $ 832.6 $ 979.3 Secured Debt/Adjusted EBITDA(1) 0.3x 1.0x 0.5x 1.0x 2.0x Total Debt/Adjusted EBITDA(1) 2.2x 2.6x 3.1x 5.6x 6.8x (1) Adjusted EBITDA is a non-GAAP financial measure, see reconciliation to net income later in the appendix

27 ($’s thousands) Quarter Ended December 31, September 30, June 30, March 31, 2017 2017 2017 2017 Net Income (Loss) $ (23,849) $ (16,087) $ 13,802 $ 16,941 Add Back: Interest Expense 20,882 16,673 16,428 16,304 Income Tax Benefit (1,570) - - - Depreciation, Depletion, Amortization and Accretion 17,632 15,358 13,682 12,828 Non - Cash Share Based Compensation 841 3,732 911 623 Write - off of Debt Issuance Costs - - 95 - Loss on Extinguishment of Debt 993 - - - Unrealized Loss (Gain) on Derivative Instruments (33,614) 16,058 (14,172) (17,057) Adjusted EBITDA(1) $ 48,542 $ 35,734 $ 30,746 $ 29,639 (1) Adjusted EBITDA is a non-GAAP financial measure

28 ($’s thousands) Year Ended December 31, 2017 2016 2015 2014 2013 Net (Loss) Income $ (9,194) $ (293,494) $ (975,355) $ 163,746 $ 53,067 Add Back: Interest Expense 70,286 64,486 58,360 42,106 32,709 Income Tax Provision (Benefit) (1,570) (1,402) (202,424) 99,367 31,768 Depreciation, Depletion, Amortization and Accretion 59,500 61,244 137,770 172,884 124,383 Impairment of Oil and Natural Gas Properties - 237,013 1,163,959 - - Non - Cash Share Based Compensation 6,107 3,182 6,273 2,759 4,799 Write - off of Debt Issuance Costs 95 1,090 - - - Loss on Extinguishment of Debt 993 - - - - Unrealized Loss (Gain) on Derivative Instruments 18,443 76,347 88,716 (171,276) 21,259 Adjusted EBITDA(1) $ 144,660 $ 148,466 $ 277,299 $ 309,586 $ 267,985 (1) Adjusted EBITDA is a non-GAAP financial measure

29(1) Represents reserves prepared in accordance with the guidance and pricing prescribed by the SEC in Industry Guide 2. The unescalated twelve month arithmetic average of the first day of the month posted prices were adjusted for transportation and quality differentials to arrive at prices of $45.90/bbl for oil and $3.34/mcf for natural gas. Production costs were held constant for the life of the wells (2) Using FYE17 strip pricing (see appendix), NOG internal type curves, a 20 net well per year drill schedule, and total 3P inventory. Production costs consistent with SEC case Cases Standardized Measure Reconciliation (in thousands) SEC Case(1) NOG Internal Case(2) Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%) $758,000 $1,718,431 Future Income Taxes, Discounted at 10% (4,014) (245,740) Standardized Measure of Discounted Future Net Cash Flows $753,986 $1,472,691 Proved Reserves (December 31, 2017) SEC Case(1) Oil (Mbbl) Developed 38,593 Undeveloped 24,220 Total 62,812 Natural Gas (Mmcf) Developed 46,518 Undeveloped 31,603 Total 78,121 Total Proved Reserves (Mboe) 75,832

30 FYE17 Strip Pricing Period WTI ($/bbl) HHub ($/MMbtu) 2018: 1Q $61.61 $3.17 2Q $60.24 $2.75 3Q $59.42 $2.80 4Q $58.39 $2.89 2019: 1Q $57.41 $3.05 2Q $56.52 $2.68 3Q $55.73 $2.72 4Q $55.11 $2.81 2020: 1Q $54.55 $2.99 2Q $53.95 $2.68 3Q $53.46 $2.73 4Q $53.08 $2.86 2021: 1Q $52.73 $3.05 2Q $52.40 $2.71 3Q $52.12 $2.76 4Q $51.91 $2.88 2022: 1Q $51.75 $3.08 2Q $51.69 $2.75 3Q $51.63 $2.80 4Q $51.61 $2.93 2023: 1Q $51.59 $3.12 2Q $51.56 $2.78 3Q $51.59 $2.83 4Q $51.64 $2.97 Source: Bloomberg