Company presentation  December 2015    

 

 2  Forward Looking Statements  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.  

 

 find a place to hide in the storm  3 

 

 “Non-Op”…..what is it?  Do not drill or operate wellsWe own minority leasehold/working interest (WI) percentage in Drilling Spacing Units (DSU)Operator of the DSU initiates/proposes drill schedule State law requires the operator of the DSU to send all minority Leasehold/WI owners in the DSU a well proposalState law and Forced Pooling advantages for Non-Op participantsNo mandate for minority WI owners to participateOption to participate “heads-up” with the operator for our WI percentage, or non-consent the proposalNo long-term rig, frac, sand or takeaway contractsAbility to control large acreage postion, substantial production profile, and high-quality reserves with only 20 employeesDiversifed among the best opertors in the Williston Basin  4 

 

 Benefits of non-op   5 

 

 consent or non-consent a well  6    Non-ConsentAcreage still HBP even multiple zones with single wellRetain right to participate in other wells/zones in DSUEach well in unit is a standalone decision 

 

   Source: Company information for producing wells as of June 30, 2015.  Participating well locations  “Core” Inventory:200+ Net Locations$35 - $50 WTI BreakevenAvg AFE: ~$7.3 millionAvg EUR: ~750+ MBOE    7 

 

    8   Northern Average Well Profile by Year, Proposed IP Rates up 30% from 2014   Well productivity continues to improve 

 

 Disciplined investment decisions   9   Average YTD IRR on consented wells of 38%, average for non-consented wells of 9%  43% Increase  16% Decrease  Ave EUR for 1280 acre DSUsThrough 9/30/15 

 

 Liquidity profile  10  $550 million borrowing base reaffirmed – October 20159/30/15  Liquidity of$ 387 Million   

 

 crude oil Hedges        SWAPS       Contract Period    Volume (Bbls)    Weighted Average Price (per Bbl)  2015:          Q4    990,000    $89.82  2016:          Q1    450,000    $90.00  Q2    450,000    $90.00  Q3    450,000    $65.00  Q4    450,000    $65.00  11 

 

 LOWER COSTS IMPROVING Performance     12  Well Costs ($MM)  Cash Operating Costs ($/Boe) 

 

 Low Unit costs   13  TPLM data is TTM as of 7/31/2015  TTM Q3’15 Unit Costs per BOE (1)    $14.46  $16.53  $17.10  $19.70  $32.05  $19.72 

 

 High cash operating margin  14  Realized Price is defined as oil, gas and NGL sales, including the effects of realized hedging gains or losses. Data as of 9/30/15.Cash Operating Margin is defined as oil and gas sales, including settled derivatives, less production expenses, production taxes and cash G&A.TPLM data is TTM as of 7/31/2015  NOG Historical Cash Operating Margins per BOE (1)(2)  TTM Q3’15 Peer Cash Operating Margins per BOE (1)(2)   

 

 High-Quality Acreage portfolio  15  North Dakota  Montana  Includes acreage classified as held by production, held by operations or developed.   Net Acres By County   Northern Net Acreage Summary  Total Net Acreage: 169,000 (as of 9/30/2015)ND: 137,200 Net AcresMT: 31,900 Net Acres  A Solid Foundation 

 

 Partnered with leading operators  16  Percentage of Producing Wells – By Operator  Less Than 2%    Between 2% and 3%        Top 10 Operators  1  Slawson Exploration  2  Continental Resources  3  Whiting Petroleum  4  Hess  5  Oasis Petroleum  6  EOG Resources  7  XTO  8  ConocoPhillips  9  Statoil  10  Emerald Oil, Inc. 

 

   High intensity completions  Completion Trends:~80% of new consented wells are planned high intensity completions ~25% increase in EURs with new completion design2016 per-well productivity expected to improve  17  Source: NDIC and DrillingInfo 

 

 Improved recoveries across the basin  18  North Dakota Play to Date Completion Comparison  27% Uplift  19% Uplift  NOG Internal Estimates 

 

 Embracing the challenges  Capital Discipline2015 budget down 74% vs. 2014 actual capex spend2015 production expected to be flat vs. 2014 levelsMaintain Liquidity$387 million of available liquidity (up $18 million versus prior quarter)8% senior notes do not mature until 2020Allocate capital only to high IRR opportunitiesImproving Operational Efficiencies Weighted Average AFE Cost ~$7.7 mm – Down ~16% vs. 20143Q 2015 Cash Costs per BOE down 29% vs. 3Q 2014 Exposure to high intensity completions helping to drive per well productivity improvementsResilient Asset Strength & Inventory200+ net locations with breakeven pricing from $35 - $50 WTIAt current rate - 10+ years of inventory  19 

 

 2015 GUIDANCE & Recent developments  20  CapEx Decreases 74%  Production Flat  Capital Expenditures & Production   Capital Expenditures by Quarter  Capital Expenditures:Drilling and Completion $120 millionAcreage & Other $20 millionProduction:Total Production ~5.8 MMBoe Operating Expenses for 4Q15LOE ($ per Boe) $8.50 – $8.75Tax (% of Oil & Gas Revenue) 10.5%Total G&A ($ per Boe) $4.30 Cash G&A $2.00 Non-Cash G&A $2.30Average Differential for 4Q15NYMEX WTI ($9.00) to ($11.00) Revenue Charge in 4Q15$3.8 million revenue reduction due to a decrease in ownership interests in connection with two leasehold title dispute matters  E 

 

 Why Northern today?  21  ENDURANCE  DURABILITY  OPTIONALITY  Northern’s non-op business modelAccess to core acreage and best in class operatorsConsent v Non-Consent capital allocation processLiquidityAbility to adjust spending up or down based on rate of return 

 

 APPENDIX: Supplemental information  22 

 

 CORPORATE PROFILE  23  As of 10/31/2015As of 12/3/15As of 9/30/15As of 12/31/14     NYSE MKT:  NOG      Shares Outstanding (Fully-Diluted)(1)  ~62.9 million  Market Capitalization(2)  ~$302 million  Enterprise Value(2)  ~$1,180 billion  Adjusted EBITDA (TTM)  $291.2 million  Net Producing Wells(3)  201.9 net  Average Q3 2015 Daily Production  15,844 Boepd  Production (2015 Estimate)  ~5.8 MMBoe   Oil    (87%)   Natural Gas    (13%)  Proved Reserves(4)  100.7 MMBoe   % Proved Developed  51%   % Oil  88%  Net Acreage  169,000 acres 

 

 production and cash flow  24  Adjusted EBITDA ($ millions)  Adjusted EBITDA 72% CAGR  Annual Production 67% CAGR  Annual Production (Boepd)  Cash Flow from Operation ($ millions)  Growth in production, cash flow, and EBITDA through cyclesFocus capital on high return, organic growth, funded by cash flow and prudent financial leverageMaintain a strong balance sheet and liquidity position 

 

 Williston Basin activity  25  Daily Production (Mboe/d)  Active Horizontal Rig Count  NDICAnnualized figure based on actual data through August 2015  North Dakota Wells Spud(1)  North Dakota Monthly Wells Spud and Rig Count(1)   North Dakota Active Horizontal Rig Count and Production(1)  Actual  Est. 

 

 Getting production to market  26  NDIC  Takeaway Capacity (Mbopd) (1)  Takeaway Capacity Options  Pipeline and rail provide multiple destinations for Bakken crudeNew pipelines in 2016/2017 provide excellent optionality for low cost transportationGiven the pipe and rail options, there is ample capacity for Bakken crude production  

 

 Historical operating information  27           Year Ended December 31,                 First 9 months           2011     2012     2013     2014     2015  Production                          Oil (MBbls)     1,792.0      3,465.3      4,046.7      5,150.9      3,904.8     Natural Gas and NGLs      800.2      1,768.9      2,572.3      3,682.8      3,559.6  Total Production (Mboe)       1,925.3      3,760.1      4,475.4      5,764.7      4,498.1                                                    Realized Oil Price, including settled derivatives ($ / Bbl)     $ 78.53      $ 83.11      $ 84.89      $ 77.70      $ 69.47     Realized Natural Gas and NGL Price ($ / Mcf)     6.63      4.67      5.24      6.38      1.68  Total Oil & Gas Revenues, including settled derivatives (millions)       $ 146.0      $ 296.2      $ 357.0      $ 423.7      $ 277.2                                                  Adjusted EBITDA (millions)        $ 112.3      $ 225.3      $ 268.0      $ 309.6      $ 209.6                                                   Key Operating Statistics ($ / Boe)                          Average Realized Price     $ 75.85      $ 78.79      $ 79.77      $ 73.51      $ 61.63    Production Expenses     6.77      8.61      9.35      9.66      8.97     Production Taxes     7.43      7.58      7.81      7.58      3.85     General & Administrative Expenses-Cash     3.87      2.73      2.63      2.57      2.22      Total Cash Costs     $ 18.07      $ 18.92      $ 19.79      $ 19.81      $ 15.04   Operating Margin ($ / Boe)       $ 57.78      $ 59.87      $ 59.98      $ 53.70      $ 46.59                          Operating Margin %      76.2%    76.0%    75.2%    73.1%    75.6% 

 

 Cash operating margin reconciliation   ($/Boe, except % Margin)              Year  Realized Price*  Production Expense  Production Taxes  Cash G&A  Margin  % Margin  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%  2014  73.51  9.66  7.58  2.57  53.70  73.1%  2015 (Q3 TTM)  63.21  9.20  4.85  2.31  47.33  75.0%                28  *Realized Price: Including effect of settled hedges.  

 

 adjusted ebitda by quarter                     Quarter Ended                           September 30,   June 30,   March 31,   December 31,     In thousands                 2015   2015   2015   2014                             Net Income                  $(323,242)   $(250,061)   $(229,739)   $103,584    Add Back:                            Interest Expense                 16,154    14,388    11,737    11,258     Income Tax Provision                 (78)    (66,867)    (135,480)    62,967     Depreciation, Depletion, Amortization and Accretion                  36,671    36,746    45,213    48,926     Impairment of Oil and NaturalGas Properties                 354,423    281,964    360,429   -    Non- Cash Share Based Compensation                 1,141    1,050    1,030    739     Unrealized Loss (Gain) on Derivative Instruments                 (8,409)    53,193    14,331    (145,842)       Adjusted EBITDA              $71,660   $70,414   $67,522   $81,627                             29 

 

 adjusted ebitda by year    2014  2013  2012  2011  2010                   (In Thousands)               Net Income   $ 163,746    $ 53,067    $ 72,285    $ 40,611    $ 6,917      Add Back:               Interest Expense   42,106    32,709    13,875    586    583      Income Tax Provision    99,367    30,768    43,002    26,835    4,419      Depreciation, Depletion, Amortization and Accretion   172,884    124,383    98,923    41,170    17,083      Non-Cash Share Based Compensation   2,759    4,799    12,382    6,164    3,566      Unrealized Loss (Gain) on Derivative Instruments   (171,276)   21,259   (15,147)   (3,072)   14,545      Adjusted EBITDA  $309,586  $267,985  $225,320  $112,294  $47,113                                30