One Step Ahead of The Drill Bit November 2013 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
Position: 187,000 Net Acres ~1,000 Remaining Net Well Inventory (2) 61% Held (3), 71% Held in North Dakota Production: (3rd Quarter 2013) Averaged ~13,049 BOE/d, 90% Crude 1,585 Producing Wells (133.5 net) 260 Wells Drilling (18.8 net) (1) Proved Reserves: YE 2012 Proved Reserves ~68 MMBoe Enterprise Value: $1.53 Billion $1.0 Billion Equity Market Cap $500 million 8% coupon 2020 series bonds $33 million on revolving credit facility ($45 MM borrowed on $450 million borrowing base) (1), net of $12 million in cash. (1) As of 9/30/13 (2) Based on 187,000 net acres and 1,280 acre units -8 wells per 1,280 unit. (3) Held defined as developed, held by production or held by operations. 3
Leading Non-op Franchise in the Williston First-mover advantage in 2006 Strong balance sheet and liquidity for drilling and additional acquisitions Acquire only strategic non-operated acreage in the Bakken core Longstanding relationships with leading operators & land professionals Partnered with Leading Operators Exposure to the best operators in the best oil play 25+ operating partners diversifies risk Choose to participate with the best operators Visible Growth Potential Over Long-Term Extensive multi-year drilling inventory (1,000+ net wells to drill) Down spacing and lower Three Forks benches may add significant drilling inventory 4
($ in millions) Oil (MMBbls) P1 Category Net Proved Reserves as of 12/31/2012 Gas (Bcf) Total (MMBoe) SEC PV-10 (1) PDP 23.7 15.0 26.2 $795.7 PDNP 3.7 2.3 4.1 42.8 PUD 33.4 23.9 37.4 448.9 Total Proved Reserves 60.7 41.3 67.6 $1,287.4 Net Proved Reserves Proved Reserves (MMBoe) 80 35% 70 60 50 46.8 67.6 62% 6% PUD PDNP PDP Large Drilling Inventory (1). Reserves audited by Ryder Scott. SEC average realized prices in 2012 were $84.92/Bbl and $4.78/Mcf. 40 30 20 15.7 10 6.1 0.8 0 2008 2009 2010 2011 2012 5
Foundation for Continued Growth and Value Creation Northern Net Acreage Summary 22% 39% 29% 78% 61% 71% Montana North Dakota Total % Held(1) Total % Non-Held ND % Held (1) ND % Non-Held Net Acres By County 33,334 30,808 25,552 17,828 16,799 Total Net Acreage: 187,000 (as of 9/30/2013) ND: 146,500 Net Acres MT: 40,500Net Acres 32,097 7,247 6,714 5,524 2,523 212 3,994 3,589 717 Mountrail Dunn McKenzie Divide Williams Burke Billings Stark Golden Valley (1) Includes acreage classified as held by production, held by operations or developed. North Dakota McLean Richland Dawson Roosevelt Sheridan Montana 6
Gross Bakken run rate capex for these 12 operators is estimated at ~$10 billion 86% of rigs in North Dakota are currently running in townships / ranges where Northern holds acreage Company Current Williston Rigs (1) Estimated Gross Run Rate BakkenCapex (2) EOG Resources 16 $1,440 MM Hess 14 $1,260MM 16 $1,440 MM 11 $990 MM Statoil 10 $900 MM ExxonMobil 5 $450 MM Whiting 5 $450 MM 5 $450 MM Oasis Petroleum 9 $810 MM 6 $540 MM 7 $630 MM 6 $540 MM Total North Dakota Rigs (181) (1) 19% 81% NOG Operators Other Operators North Dakota Rigs (181) (1) 14% 86% (1) NDIC North Dakota rig count as of November 8, 2013 (2) Assumes one well per rig per month and $7.5 MM gross capex per well. Rigs Running in NOG Townships / Ranges 7
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 8
Acquisition and Development Investment Capital Shifting to Development $600 100% Capital Investment ($ in millions) $500 $400 $300 $200 $100 $0 $49.5 $18.7 $30.8 $198.5 $123.9 $74.5 $414.0 $302.6 $111.4 $538.1 $485.4 $51.2 $411 $381.0 $30.0 Percentage of Total Capital Investment 90% 80% 70% 60% 50% 40% 30% 20% 10% 38% 62% 62% 38% 73% 27% 90% 93% 0% 10% 7% 2009 2010 2011 2012 2013(E) Property Acquisition Development Property Acquisition Development (1) Based on capital budget from November 2013 9
Diversified Among the Best Operators in the Williston Basin (as a % of Net Wells) NOG participates in wells with most of the top operators in the Williston Basin 2.8% 4.4% 22.5% 12.5% 8.7% 7.8% 2.8% 3.7% 2.6% 2.8% 4.0% 5.5% 16.1% 4.0% Less Than 1% Between 1% and 2% 10
Growth Track Record from Consistent Execution of Business Strategy Oil & Gas Revenue ($MM) (1) Adjusted EBITDA ($MM) (2) $400.0 $350.0 $300.0 $296.2 $345.8 $300.0 $250.0 $225.3 $260.6 $250.0 $200.0 $200.0 $150.0 $146.0 $150.0 $100.0 $112.3 $100.0 $50.0 $- $59.0 $4.3 $14.5 2008 2009 2010 2011 2012 2013 TTM $50.0 $- $47.1 $2.5 $10.7 2008 2009 2010 2011 2012 2013 TTM Source: SEC filings. (1) As of 9/30/2013 includes realized gain/loss from hedging activity. (2) See appendix for Adjusted EBITDA reconciliation. (3) Realized Price is defined as oil, gas and NGL sales, including the effects of realized hedging gains or losses. Data as of 9/30/13. 11
($/Boe) $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) 69.0% 79.0% $82.78 $82.58 $75.85 $78.79 76.7% $79.80 76.2% 76.0% 73.9% 75.4% $66.39 $63.46 $57.77 $59.87 $62.25 $58.93 $51.55 $52.44 $35.57 2009 2010 2011 2012 Q1 2013 Q2 2013 Q3 2013 Realized Price (BOE) Cash Operating Margin (BOE) Margin % 100.0% 75.0% 50.0% 25.0% % Margin 2013 TTM Peer Cash Operating Margins per BOE (1) ($/Boe) 100.00 80.00 60.00 40.00 20.00 - $88.58 $84.76 $82.48 Average Realized Price of $70.57 per BOE Average Cash Operating Margin of $45.88 per BOE $66.76 $63.78 $66.21 $62.25 $74.68 $74.29 $53.81 $46.10 $42.32 $37.83 $39.77 $24.68 $23.36 OAS KOG NOG REN CWEI MHR CRZO REXX 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 9/30/13. (2) Cash Operating Margin is defined as oil and gas sales, including settled derivatives, less production expenses, production taxes and cash G&A. 12
Northern Generated $3.62 in EBITDA for Each $1.00 Invested in F&D 500% 450% 462% 456% 400% 350% 362% 300% 250% 200% 150% 261% 216% 198% 152% 100% 50% 0% OAS CLR NOG KOG HES WLL EOG Capital Efficiency is calculated by dividing TTM EBITDA per TTM production (per Boe) by three-year finding and development cost per Boe. 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. 13
Northern Delivers Strong Fundamental Performance in Key Operational Metrics $35.0 $30.0 $25.0 $20.0 $15.0 $10.0 $5.0 $- Three-Year F&D Cost 2010-2012 ($/Boe) (1) HES EOG WLL KOG MHR NOG OAS CLR Low Asset Intensity (2) = Cash Flow to Grow Cash Operating Margin TTM 9/30/2013 ($/Boe) $80.0 $70.0 $60.0 $50.0 $40.0 $30.0 $20.0 $10.0 $- OAS KOG NOG CLR HES WLL EOG MHR Three-Year Production Replacement (2010-2012) 1.6 1.4 1.2 1 0.8 0.6 0.4 0.2 0 MHR HES EOG WLL KOG NOG OAS CLR 2000% 1500% 1000% 500% 0% MHR KOG NOG OAS CLR WLL HES EOG (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. 14
EV / Proved Reserves (YE 2012) EV / Production (TTM Q3 13) $60 $250 $50 $200 $/Boe ($ in thousands) $40 $30 $20 $/Boepd($ in thousands) $150 $100 $10 $50 $0 As of 11/8/2013 KOG OAS MHR CLR EOG WLL NOG HES $0 OAS KOG CLR MHRNOG WLL EOG HES 15
Financial Resources to Stay One Step Ahead $800 Liquidity (as of 9/30/2013) $ in millions $700 $600 $500 $400 $300 $200 $100 $0 $260 $260 $405 $405 $12 $12 Cash Credit Facility(3) Adjusted EBITDA (TTM) Available Liquidity + Adjusted EBITDA(1) $266 MM Surplus (Est) $411 Capex (2013E)(2) (1) See Appendix for calculation of non-gaap measured Adjusted EBITDA (2) CapEx as stated August 2013 (3) Includes $450 million borrowing base, net of $45 million in borrowings as of 9/30/2013 16
COSTLESS COLLARS SWAPS Contract Period 2013: Volume (Bbls) Weighted Average Floor/Ceiling Price (Bbl) Volume (Bbls) Weighted Average Floor/Ceiling Price (Bbl) Q4 532,864 $ 90.45 - $ 104.29 495,000 $ 91.13 2014: Q1 60,000 $ 90.00 - $ 99.05 900,000 $ 91.17 Q2 60,000 $ 90.00 - $ 99.05 930,000 $ 91.15 Q3 60,000 $ 90.00 - $ 99.05 945,000 $ 89.81 Q4 60,000 $ 90.00 - $ 99.05 975,000 $ 89.77 2015: Q1 900,000 $ 89.04 Q2 900,000 $ 89.04 Q3 450,000 $ 89.00 Q4 450,000 $ 89.00 17
One Step Ahead of the Drill Bit Proven Acquisition Model Acquire High-Potential Acreage About to be Drilled Focused on the Bakkenand Three Forks A Premier Crude Oil Play in North America Strong Well Economics Deep Knowledge of the Bakkenand Three Forks Go-To Non-Op Acreage Buyer Steady Deal Flow from Multiple Sources Ample Liquidity to Fund AFE s as well as Acquisitions Partnered with Leading Operators in the Bakken Partnered with the Bakken s Best and Most Active Drillers Strong Financial Foundation and Liquidity to Fund Growth Visible Growth Potential Extensive Multi-Year Drilling Inventory Ability to Continue Acquiring Non-Op Working Interests Rights to Multiple Zones, Multiple Depths 18
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