One Step Ahead of The Drill Bit November 2014 NYSE MKT: NOG
Statements 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 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
100% Williston Basin Bakken/Three Forks Pure Play: 185,000 Net Acres 1,300 Remaining Net Well Inventory (1) 76% of North Dakota Acreage Held (2), 64% Held in Total Production: (3rd Quarter 2014) Averaged 16,450 BOEpd; 90% Crude Oil 2,197 Gross (177.5 Net) Wells Producing; 359 Gross (25.0 Net) In-process Proved Reserves: Year-End 2013 84.2 MMBoe Proved (1P); $1.52 billion PV-10 Enterprise Value: ~$1.42 Billion: $700 Million Equity Market Cap $500 Million 8% coupon 2020 series bonds Liquidity of $330 million (Net $220mm drawn on $550mm borrowing base) (1) Based on 184,700net acres and 1,280 acre units - 10 wells per 1,280 unit. (2) Held defined as developed, held by production or held by operations. 3
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Largest, Exclusively Non-operator in the Williston Basin First-mover advantage in 2006 Strong balance sheet and liquidity for drilling and additional acquisitions Participation in over 2,600 Bakken/Three Forks wells yields a wealth of data Capital Flexibility Non-operator model allows for immediate paring of capital expenditures Northern non-consented 12% of inbound wells in Q3, 25% in October as oil dropped Participating in highest return wells factoring in lower price decks 6 million barrels hedged at ~$90 through June 2016 to stabilize cash flows Partnered with Leading Operators Exposure to the best operators in the best oil play Extensive multi-year drilling inventory (~1,300 net wells to drill) Down spacing and lower Three Forks benches add significant drilling inventory 5
Production (MMBoe) Net Wells 2014 CapEx Budget ($ in millions) Production and Net Well Additions Drilling and Completion* $415 Acreage and Other Expenditures $35 Total $450 25% Increase in Annual Production of approximately ~5.5 MMBoe 10% Increase in net well additions 44 for FY 2014 5.6 5.5 5.4 5.3 5.2 5.1 5.0 4.9 4.8 4.7 4.6 4.5 4.4 4.3 4.2 4.1 4.0 4.5 MMBoe 40 Wells 5.5 MMBoe 44 Wells 2013 (Actual) 2014 (Estimate) 45 44 43 42 41 40 39 Production Net Well Additions *Includes approximately $12 million in capitalized workover expenses 6
Strengthening the Foundation, Multi-Year Growth Profile 7
Buy Acreage One Step Ahead of the Drill Bit Deep knowledge of the Williston Basin Participated in ~25% of all Bakken/Three Forks wells drilled since 2006 2,197 gross producing wells; 359 gross wells drilling, completing or awaiting completion Good visibility on who operates, drilling plans, AFE costs and general economics prior to acreage acquisition Seek Lease Positions Contiguous to Large Operator Positions Reduce acquisition-to-value creation time Participate with operators we know Non Operating Clearinghouse Exclusive clearinghouse for minority, non-operated working interest Northern is the largest, exclusively non-op participant in the Williston Basin 8
Non-Operated Positions from Companies Preferring to Operate Larger Operators Seeking to Consolidate Operated Positions (Post-Acquisition) Smaller Parties With Funding Difficulties Steady Deal Flow Operators Looking to Sell Down Working Interests to Maintain CapEx and/or Reduce Risk 9
Foundation for Continued Growth Northern Net Acreage Summary 23% 36% 24% 77% 64% 76% Montana North Dakota Total % Held (1) Total % Non-Held ND % Held (1) ND % Non-Held Net Acres By County Total Net Acreage: ~184,700 (as of 9/30/2014) ND: 141,300 Net Acres MT: 43,400 Net Acres 39,900 43,400 29,000 24,600 28,300 19,500 Mountrail Dunn McKenzie Williams Other Montana North Dakota Montana 10 (1) Includes acreage classified as held by production, held by operations or developed.
93% of Current Drilling Located in the Big Four Counties Mountrail McKenzie 27% 30% Other 7% Dunn 10% 26% Williams 11
Percentage of PDP s By Operator Top 10 Operators 21.5% 10.8% 7.2% 6.2% 1 2 Slawson Exploration Continental Resources 3 Hess Less Than 2% Between 2% and 3% 14.0% 10.1% 4.3% 3.2% 3.9% 3.8% 5.5% 5.2% 4.4% 4 Whiting Petroleum 5 Oasis Petroleum 6 EOG Resources 7 XTO 8 ConocoPhillips 9 Emerald Oil, Inc. 10 Statoil 12
High Cash Margin (93% Oil) Production 13
($/Boe) ($/Boe) % Margin $90.00 $80.00 $70.00 $60.00 $50.00 $40.00 $30.00 $20.00 $10.00 $0.00 Historical Cash Operating Margins per BOE (1) 79.0% $75.85 $78.79 $79.77 $77.74 69.0% 76.2% 76.0% 75.2% $66.39 73.2% $57.77 $59.87 $59.97 $51.55 $52.44 $56.92 $35.57 2009 2010 2011 2012 2013 TTM Q3 2014 Realized Price (BOE) Cash Operating Margin (BOE) Margin % 100.0% 75.0% 50.0% 25.0% TTM Q3 14 Peer Cash Operating Margins per BOE (1) 90.00 80.00 70.00 60.00 50.00 40.00 30.00 20.00 10.00 - $82.70 $82.34 $80.44 $78.87 $75.65 $69.44 Average Realized Price of $72.49 per Boe Average Cash Operating Margin of $46.10 per Boe $56.76 $56.43 $56.68 $54.94 $54.72 $60.73 $49.73 $43.83 $27.42 $17.98 OAS EOX KOG WLL NOG CLR EOG MHR Realized Price / Boe Cash Operating Margin / Boe (1) Realized Price is defined as oil, gas and NGL sales, including the effects of realized hedging gains or losses. Data as of 9/30/14. (2) Cash Operating Margin is defined as oil and gas sales, including settled derivatives, less production expenses, production taxes and cash G&A. 14
Strong Fundamental Performance in Key Operational Metrics Three-Year F&D Cost 2011-2013 ($/Boe) (1) Cash Operating Margin TTM 09/30/2014 ($/Boe) $30.0 $60.0 $25.0 $50.0 $20.0 $40.0 $15.0 $30.0 $10.0 $20.0 $5.0 $10.0 $- MHR WLL EOG KOG EOX OAS NOG CLR $- OAS WLL KOG NOG CLR EOG EOX MHR (1) F&D Cost is cost incurred in oil and gas activities excluding abandonment, divided by the sum of extensions, discoveries, revisions and purchases of proved reserves over a 3-year period. (2) Asset Intensity is calculated as TTM production multiplied by 3-year F&D cost per Boe all divided by TTM cash flow from operations. 15
Northern Generated $3.17 in EBITDA for Each $1.00 Invested in F&D 500% 450% 450% 400% 350% 300% 250% 200% 150% 355% 317% 257% 204% 183% 160% 100% 50% 0% CLR OAS NOG KOG WLL EOG EOX Capital Efficiency is calculated by dividing TTM EBITDA per TTM production (per Boe) by three-year finding and development cost per Boe as of 9/30/2014. F&D Cost is cost incurred in oil and gas activities excluding abandonment, divided by the sum of extensions, discoveries, revisions and purchases of proved reserves over a 3-year period. 16
Production (Boepd) Net Producing Wells Consistent Growth 18,000 200 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,435 5,275 10,274 12,261 ~15,300 180 160 140 120 100 80 60 40 2,000-140 773 2008 2009 2010 2011 2012 2013 2014E 20 0 Annual Production Well Count 17
Consistent Execution of Business Strategy Oil & Gas Sales ($MM) (1) Adjusted EBITDA ($MM) (2) $500.0 $350.0 $450.0 $400.0 $350.0 $300.0 $296.6 $369.2 $436.3 $300.0 $250.0 $200.0 $225.3 $268.0 $299.6 $250.0 $200.0 $150.0 $159.4 $150.0 $100.0 $112.3 $100.0 $50.0 $- $4.3 $15.1 $59.4 2008 2009 2010 2011 2012 2013 TTM Q3'14 $50.0 $- $2.5 $10.7 $47.1 2008 2009 2010 2011 2012 2013 TTM Q3'14 Source: SEC filings. (1) As of 9/30/2014. (2) See appendix for Adjusted EBITDA reconciliation. 18
Capital and Liquidity to Continue Growth Path 19
$ in millions Financial Resources to Stay One Step Ahead $600 Liquidity $500 $400 $300 $550 $228 Liquidity of $330 Million $8 $200 $322 $322 $100 $0 Credit Facility(1) Outstanding Borrowings Available Credit Facility $8 Cash Available Liquidity (1) $550 million borrowing base 20
Annual Production (Boepd) Capital Expenditures ($MM) Organic Disciplined Growth 16,000 15,000 ~15,300 $700 $650 14,000 13,000 12,000 $538 12,261 $600 $550 11,000 10,000 9,000 10,274 $439 CapEx $450 $500 $450 8,000 2012 2013 2014 (Est) Annual Production CapEx $400 21
Capital Investment ($ in millions) Percentage of Total Capital Investment Acquisition and Development Investment (1) Capital Shifting to Development (1) $600 100% $500 $400 $300 $200 $198.5 $414.0 $302.6 $537.5 $485.4 $439.1 ~$450 $389.5 $415.0 90% 80% 70% 60% 50% 40% 30% 38% 62% 62% 73% 90% 89% 93% $100 $0 $49.5 $18.7 $30.8 $123.9 $74.5 $111.4 $52.1 $49.6 $35.0 2009 2010 2011 2012 2013 2014 (Est) 20% 10% 0% 38% 27% 10% 11% 7% 2009 2010 2011 2012 2013 2014 (Est) Property Acquisition Development Property Acquisition Development (1) Based on capital budget from August 2014. 22
SWAPS COSTLESS COLLARS Contract Period Volume (Bbls) Weighted Average Floor/Ceiling Price (Bbl) Volume (Bbls) Weighted Average Floor/Ceiling Price (Bbl) 2014: Q4 975,000 $ 89.77 60,000 $ 90.00 - $ 99.05 2015: Q1 990,000 $89.03 - - Q2 990,000 $89.03 - - Q3 990,000 $89.82 - - Q4 990,000 $89.82 - - 2016: Q1 450,000 $90.00 - - Q2 450,000 $90.00 - - 23
Proven Acquisition Model Acquire High-Potential Acreage Participated in over 2,600 Bakken/Three Forks wells; ~25% of all Bakken/TF Drilling Deep Knowledge of the Bakken and Three Forks Go-To Non-Op Acreage Buyer Steady Deal Flow from Multiple Sources as the Exclusive Non-Op Clearinghouse Ample Liquidity to Fund Drilling as well as New Acquisitions Strong Financial Foundation and Liquidity to Fund Growth Partnered with Leading Operators Top 10: Slawson, Continental, Hess, Whiting, Oasis, EOG, XTO, Conoco, EOX, Statoil Visible Growth Extensive Multi-Year Drilling Inventory Ability to Continue Acquiring Non-Op Working Interests Rights to Multiple Zones, Multiple Depths 24
$/Boe $/Boepd ($ in thousands) EV / Proved Reserves (YE 2013) EV / Production (TTM Q3 14) $35 $30 $25 $20 $15 $10 $5 $0 KOG MHR EOG OAS EOX CLR WLL NOG As of 9/30/2014 $200 $180 $160 $140 $120 $100 $80 $60 $40 $20 $0 EOX CLR MHR KOG OAS WLL NOG EOG 25