One Ahead of The Drill Bit April 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
Position: 187,000 Net Acres 1,400+ Remaining Net Well Inventory (1) 73% of North Dakota Held (2), 63% Held in Total Production: (4th Quarter 2013) Averaged 13,946 BOEpd 90% Crude 1,758 Producing Wells (146.2 net) 252 Wells Drilling (18.8 net) (3) Proved Reserves: Year-End 2013 84.2 MMBoe; $1.5 billion PV10 Enterprise Value: ~$1.4 Billion: ~$835 Million Equity Market Cap $500 Million 8% coupon 2020 series bonds $69 Million drawn on credit facility ($75 million borrowed on $500 million borrowing base, net of $6 million in cash) (1) Based on 187,000 net 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) As of 1/31/2014 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 Partnered with Leading Operators Exposure to the best operators in the best oil play 25+ operating partners diversifies risk 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
Our Focus is Purely North Dakota & Montana 5
Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13 Jan-14 Feb-14 Daily Production (Mboe/d) Active Horizontal Rig Count North Dakota Active Rig Count and Production (1) 1150 250 950 200 750 550 350 150 100 150 50-50 0 Daily Oil Production (MBbl/d) Daily Gas Production (Mboe/d) Horizontal Rig Count North Dakota Wells Spud (1) Monthly Wells Spud and Rig Count (1) 2500 250 2000 200 1500 150 100 1000 50 500 0 0 2008 2009 2010 2011 2012 2013 (1) NDIC Updated March 2014 ND Well Spuds ND Rig Count 6
Production (Boepd) Producing Wells Strategy Drives Consistent Production Growth 14,000 12,000 10,000 10,274 12,261 180 160 140 120 8,000 100 6,000 4,000 2,000-5,275 2,435 140 773 2008 2009 2010 2011 2012 2013 Annual Production Well Count 80 60 40 20 0 7
308 Bakken Petroleum System Three Forks Bakken Three Forks Potential Increases Footprint Gamma Ray Resistivity Middle Bakken Traditional Focus Benches of Three Forks Opens New Resource Potential Upper Middle Lower 11,300 Three Forks Increases Effective Acreage Position and Drilling Inventory 1 st Bench 2 nd Bench 11,400 3 rd Bench 11,500 4 th Bench Charlotte 2-22H Log 11,600 8
Strengthening the Foundation, Multi-Year Growth Profile 9
Proven Business Model Converts Acreage Into Shareholder Value 2 Fund AFE 3 Grow Production & Grow Reserves 1 Buy Acreage Creating Value One Ahead of The Drill Bit 4 Realize High Return on Invested Capital 5 Repeat! 10
2 3 Buy Acreage One Ahead of the Drill Bit Deep knowledge of the Williston Basin Participated in 2,000+ gross wells Good visibility on who the operators are 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 Manage capital outlays Participate with operators we know Purchase at Discount to Market Low entry cost enhances returns 1 5 4 11
JOA State Law Ability to Propose Wells No Yes Ability to Change Operator No Yes Non-Consent Penalty Cost + 300-500% Cost + 200% Oil and Gas Marketing Limited Flexible Forced Pooling Metes and Bounds North Dakota (1) Texas (2) (1) Kodiak October 2012 Investor Presentation. (2) Magnum Hunter December 2012 Investor Presentation. 12 21
2 3 1 5 4 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 13
Net Acres Acquired $ / Acre 2 3 1 4 5 ~187,000 net acres in the Bakken/Three Forks play as of December 31, 2013 Acquired 20,900 net acres at an average price of $1,279 per acre in 2013 Majority of acreage acquisitions involve properties that are hand-picked by Northern on a lease-by-lease basis 60,000 45,000 30,000 15,000-49,032 $544 20,316 $1,052 Acquisition History 56,858 $1,043 43,239 $1,832 17,590 20,900 $1,788 $1,279 2008 2009 2010 2011 2012 2013 Net Acres Acquired $ / Acre $4,000 $3,200 $2,400 $1,600 $800 $- Increased percent of HBP/HBO Williston Basin acreage from ~3% in 2008 to ~63% in Q4 2013 (~73% in North Dakota) 187,000 Net Acres as of December 31, 2013 Non-Held 37% HBP/HBO 63% 14
2 3 1 4 Foundation for Continued Growth and Value Creation 5 Northern Net Acreage Summary 22% 37% 27% 78% 63% 73% Montana North Dakota Total % Held (1) Total % Non-Held ND % Held (1) ND % Non-Held Net Acres By County Total Net Acreage: ~187,000 (as of 12/31/2013) 33,024 29,717 25,495 ND: 145,335 Net Acres MT: 41,709 Net Acres 18,159 16,667 22,273 41,709 Mountrail Dunn McKenzie Divide Williams Other Montana North Dakota Montana 15 (1) Includes acreage classified as held by production, held by operations or developed.
2 3 Gross Bakken run rate capex for these 12 operators is estimated at ~$11 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 Bakken Capex (2) EOG Resources 20 $1,800 MM Hess 19 $1,710 MM 15 $1,350 MM 10 $900 MM Statoil 12 $1,080 MM ExxonMobil 7 $630 MM Whiting 6 $540 MM 6 $540 MM Oasis Petroleum 15 $1,350 MM 6 $540 MM 6 $540 MM 6 $540 MM Total North Dakota Rigs (197) (1) Total North North Dakota Rigs Rigs (181) (197) (1) (1) 14% 95% NOG Operators 1 5% Other Operators 86% 5 4 (1) NDIC North Dakota rig count as of March 21, 2014 (2) Assumes one well per rig per month and $7.5 MM gross capex per well. Rigs Running in NOG Townships / Ranges 16
2 3 1 4 5 Diversify Risk Among Active Drillers in the Williston Basin 10.9% 21.9% 7.2% 3.4% 4.0% 3.3% 3.0% 4.2% 5.5% 11.9% 6.2% 5.4% 3.9% 9.3% Between 2% and 3% Less Than 2% 17
2 3 Proved Reserves as of 12/31/2013 1 5 4 ($ in millions) Oil (MMBbls) P1 Category Gas (Bcf) Total (MMBoe) SEC PV-10 (1) PDP 26.2 16.5 28.9 $881.7 PDNP 5.9 4.1 6.6 151.1 PUD 43.8 29.5 48.7 488.5 Total Proved Reserves 75.8 50.2 84.2 $1,521.3 Proved Reserves Proved Reserves (MMBoe) 34% 58% 8% PUD PDNP PDP Large Drilling Inventory (1). Reserves audited by Ryder Scott. SEC average realized prices in 2013 were $88.00/Bbl and $5.23/Mcf. 90 84.2 80 70 67.6 60 46.8 50 40 30 15.7 20 6.1 10 0.8 0 2008 2009 2010 2011 2012 2013 18
($/Boe) ($/Boe) % Margin 2 3 $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 69.0% 76.2% 76.0% 75.2% $66.39 $57.77 $59.87 $59.97 $51.55 $52.44 $35.57 2009 2010 2011 2012 2013 Realized Price (BOE) Cash Operating Margin (BOE) Margin % 1 100.0% 75.0% 50.0% 25.0% 5 4 2013 TTM Peer Cash Operating Margins per BOE (1) 100.00 80.00 $86.97 $84.40 $83.84 Average Realized Price of $74.35 per Boe Average Cash Operating Margin of $49.93 per Boe 60.00 40.00 20.00 - $71.46 $63.98 $62.94 $79.77 $59.97 $75.96 $56.97 $57.79 $53.47 $54.61 $42.18 $38.83 $21.13 OAS EOX KOG NOG WLL CLR EOG MHR Realized Price / Boe Cash Operating Margin / Boe (1) Realized Price is defined as oil, gas and NGL sales, including the effects of realized hedging gains or losses. Data as of 12/31/13. (2) Cash Operating Margin is defined as oil and gas sales, including settled derivatives, less production expenses, production taxes and cash G&A. 19
2 3 1 4 Strong Fundamental Performance in Key Operational Metrics 5 Three-Year F&D Cost 2011-2013 ($/Boe) (1) Cash Operating Margin TTM 12/31/2013 ($/Boe) $30.0 $25.0 $70.0 $60.0 $20.0 $50.0 $15.0 $10.0 $5.0 $40.0 $30.0 $20.0 $10.0 $- MHR WLL EOG KOG EOX OAS NOG CLR $- OAS KOG NOG CLR WLL EOG EOX MHR Low Asset Intensity (2) = Cash Flow to Grow Three-Year Production Replacement (2011-2013) 200% 150% 100% 50% 1500% 1000% 500% 0% EOX MHR EOG WLL KOG NOG OAS CLR 0% EOX KOG OAS CLR NOG MHR WLL 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. 20
2 3 400% Northern Generated $3.33 in EBITDA for Each $1.00 Invested in F&D 1 5 4 350% 339% 333% 327% 300% 250% 273% 200% 183% 176% 150% 100% 112% 50% 0% CLR NOG OAS KOG WLL EOG EOX Capital Efficiency is calculated by dividing TTM EBITDA per TTM production (per Boe) by three-year finding and development cost per Boe. F&D Cost is cost incurred in oil and gas activities excluding abandonment, divided by the sum of extensions, discoveries, revisions and purchases of proved reserves over a 3-year period. 21
Consistent Execution of Business Strategy Oil & Gas Sales ($MM) (1) Adjusted EBITDA ($MM) (2) $400.0 $350.0 $369.2 $300.0 $268.0 $300.0 $296.6 $250.0 $225.3 $250.0 $200.0 $200.0 $150.0 $159.4 $150.0 $100.0 $112.3 $100.0 $50.0 $- $59.4 $4.3 $15.1 2008 2009 2010 2011 2012 2013 $50.0 $- $47.1 $2.5 $10.7 2008 2009 2010 2011 2012 2013 Source: SEC filings. (1) As of 12/31/2013. (2) See appendix for Adjusted EBITDA reconciliation. 22
Capital and Liquidity to Continue Growth Path 23
$ in millions Financial Resources to Stay One Ahead $800 Liquidity $700 $600 $500 $400 $300 $200 $100 $0 $268 $268 $425 $425 $6 $6 Cash Credit Facility(3) Adjusted EBITDA (TTM) Available Liquidity + Adjusted EBITDA(1) $264 MM Surplus (Est.) $435 Capex 2014E(2) (1) See Appendix for calculation of non-gaap measured Adjusted EBITDA. (2) Mid-Point of CapEx as stated February 2014. (3) $500 million borrowing base, net of $75 million in borrowings as of 12/31/2013. 24
Capital Investment ($ 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 $389.5 $435 $400.0 90% 80% 70% 60% 50% 40% 30% 38% 62% 62% 73% 90% 89% 92% $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% 8% 2009 2010 2011 2012 2013 2014 (Est) Property Acquisition Development Property Acquisition Development (1) Based on capital budget from February 2014. 25
COSTLESS COLLARS SWAPS Contract Period Volume (Bbls) Weighted Average Floor/Ceiling Price (Bbl) Volume (Bbls) Weighted Average Floor/Ceiling Price (Bbl) 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: 2,880,000 89.02 26
$/Boe ($ in thousands) $/Boepd ($ in thousands) EV / Proved Reserves (YE 2013) EV / Production (TTM Q4 13) $40 $35 $30 $25 $250 $200 $150 $20 $15 $100 $10 $5 $50 $0 As of 3/21/2014 MHR KOG EOX OAS EOG CLR WLL NOG $0 EOX MHR OAS CLR KOG NOG EOG WLL 27
One Ahead of the Drill Bit Proven Acquisition Model Acquire High-Potential Acreage Focused on the Bakken and Three Forks A Premier Crude Oil Play in North America Deep Knowledge of the Bakken and Three Forks Go-To Non-Op Acreage Buyer Steady Deal Flow from Multiple Sources Ample Liquidity to Fund AFE s as well as Acquisitions Partnered with Leading Operators Partnered with the Bakken s Best and Most Active Drillers Strong Financial Foundation and Liquidity to Fund Growth Visible Growth Extensive Multi-Year Drilling Inventory Ability to Continue Acquiring Non-Op Working Interests Rights to Multiple Zones, Multiple Depths 28
APPENDIX: Supplemental Information 29
Year Ended December 31, 2013 2012 2011 2010 2009 Production Oil (MBbls) 4,046.7 3,465.3 1,792.0 849.8 274.3 Natural Gas and NGLs 2,572.2 1,768.9 800.2 234.4 47.3 Total Production (Mboe) 4,475.4 3,760.1 1,925.4 888.9 282.2 Realized Oil Price ($ / Bbl) $ 84.89 $ 83.11 $ 78.53 $ 67.72 $ 52.32 Realized Natural Gas and NGL Price ($ / Mcf) 5.24 4.67 6.63 6.26 4.11 Total Oil & Gas Revenues including settled derivatives (millions) $ 314.5 $ 296.2 $ 146.0 $ 89.0 $ 14.5 Operating Expenses ($ / Boe) Average Realized Price ($/ Boe) $ 79.77 $ 78.79 $ 75.85 $ 66.39 $ 51.55 Production Expenses 9.35 8.61 6.77 3.70 2.68 Production Taxes 7.80 7.58 7.43 6.16 4.61 General & Administrative Expenses - Cash 2.63 2.64 3.88 4.09 8.70 Depreciation, Depletion and Amortization 26.77 26.31 21.38 19.22 15.42 Adjusted EBITDA (millions) $ 267.8 $ 225.3 $ 112.3 $ 47.1 $ 10.7 ($ / Boe) $ 59.88 $ 59.92 $ 58.33 $ 52.99 $ 37.92 30
2013 2012 2011 2010 2009 2008 (In Thousands) Net Income $ 53,067 $ 72,285 $ 40,611 $ 6,917 $ 2,798 $ 2,424 Add Back: Interest Expense 32,709 13,875 586 583 535 28 Income Tax Provision 30,768 43,002 26,835 4,419 1,466 (830) Depreciation, Depletion, Amortization and Accretion 124,383 98,923 41,170 17,083 4,350 746 Non-Cash Share Based Compensation 4,799 12,382 6,164 3,566 1,233 105 Unrealized Loss (Gain) on Derivative Instruments 21,259 (15,147) (3,072) 14,545 363 - Adjusted EBITDA $267,985 $225,320 $112,294 $47,113 $10,745 $2,473 31
Quarter Ended March 31, June 30, September 30, December 31, In thousands 2013 2013 2013 2013 Net Income $8,951 $25,011 $1,702 $17,401 Add Back: Interest Expense 6,108 7,819 9,212 9,569 Income Tax Provision 5,604 14,630 1,028 10,505 Depreciation, Depletion, Amortization, and Accretion 26,792 26,559 32,103 38,928 Non- Cash Share Based Compensation 1,122 1,185 1,239 1,251 Unrealized Loss (Gain) on Derivative Instruments 14,910 (17,009) 29,353 (5,995) Adjusted EBITDA $63,489 $58,196 $74,640 $71,659 32
($/Boe, except % Margin) Year Realized Price* Production Expense Production Taxes Cash G&A Margin % Margin 2009 51.55 2.67 4.60 8.70 35.57 69.0% 2010 66.39 3.70 6.16 4.09 52.44 79.0% 2011 75.85 6.77 7.43 3.88 57.77 76.2% 2012 78.79 8.61 7.58 2.64 59.96 76.0% 2013 79.77 9.35 7.81 2.63 59.98 75.2% *Realized Price: Oil and gas sales, including effect of settled hedges, divided by total production (Boe). 33