December NYSE American: NOG

Transcription

1 December 2017 NYSE American: NOG

2 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 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

3 Capital Allocation Participating in some of the best wells being drilled by some of the best operators in the Williston Basin. Wells in process are comprised of some of the best wells the company has ever participated in. Production growth returning despite significant capital spending reductions. Financial Extended nearest debt maturity to Increased liquidity and cash on hand. Continue to explore ways to reduce debt levels. Value Ongoing ground game adding additional investment opportunities in some outstanding wells. Seeking incremental acquisitions to grow EBITDA Core is improving AND expanding. (1) At November 1, 2017 comprised of approximately $135 million of cash on hand and $100 million of delayed draw term loan availability. 3

4 Position: 145,749 net acres (1) Large net well inventory 86% held, 87% held in North Dakota (1) Production: 3Q 2017 averaged 15,321 BOE/d, 84% crude net producing wells (3,143 gross) (1) 18.0 net wells-in-process (1) Hedges Protecting Liquidity: Swaps (3) 4Q17 418,500 Bbls $ ,050,000 Bbls $ ,779,000 Bbls hedged@ $ ,207,800 Bbls hedged@ $50.37 Costless Collars (3) 4Q17 50,000 Bbls $50.00 $60.06 $235.0 million of liquidity (4) Enterprise Value $983 (2) million: $118.3 million Market Cap (2) $700 million 8% coupon 2020 series bonds $300 million drawn on new credit facility (4) (1) As of 9/30/17 (2) As of 12/5/17 (3) Open crude oil derivative contracts scheduled to settle after November 1, 2017 (4) $300 million initial draw, liquidity comprised of approximately $135 million of cash on hand and $100 million of delayed draw term loan availability, as of November 1,

5 Northern Net Acreage Summary (2) 10% 14% 13% 90% 86% 87% North Dakota Montana Total % Held (1) Total % Non-Held ND % Held (1) ND % Non-Held Net Acres By County 29,973 27,537 Total Net Acreage: 145,749 (2) ND: 131,243 Net Acres MT: 14,506 Net Acres 19,545 18,719 17,198 18,271 14,506 McKenzie Mountrail Williams Dunn Divide Other Montana North Dakota Montana (1) Includes acreage classified as held by production, held by operations or developed (2) As of 9/30/17 5

6 Percentage of Producing Wells By Operator Top 10 Operators 1 Slawson 10.8% 9.1% 6.7% 2 Continental 3 Whiting 4 ConocoPhillips 19.5% 6.4% 5.6% 5 Hess 6 Oasis 7 XTO Energy Less Than 2% 4.4% 5.5% 8 EOG Resources 9 Petro-Hunt Dakota 10 Statoil 13.9% 3.6% 8.2% 3.3% 3.0% Petro-Hunt Dakota, LLC Between 2% and 3% 6 Source: Company info as of September 30, 2017

7 Extensive well database from the evaluation and participation in over 3000 gross wells in the basin drives investment decisions A sizable inventory of undrilled locations for future investment Net Undeveloped Breakeven Locations $50 WTI $3.00 HH $60 WTI $3.00 HH $70 WTI $3.00 HH $80 WTI $3.00 HH Source: Company info, NDIC, and DrillingInfo NOG Leasehold NOG Producing Well 7

8 Increased activity levels has resulted in an increase in the number of inbound AFEs Permitting levels on Northern s acreage over the last 180 days supports continued investment opportunities Williston Basin Activity (1) ND Well Spuds ND Rig Count Permits (1) As of September 30, 2017 Source: Company info, NDIC, and DrillingInfo NOG Leasehold Last 180 Days Permit on NOG s Acreage 8

9 Committing Capital to the Highest Return Wells 50% 45% 40% 35% 33% 47% Average IRR 37% 36% 37% 32% 35% $10.0 $9.0 $8.0 $ Average AFE Costs % 25% 26% 29% 26% 26% 28% $MM $6.0 $5.0 20% 15% 10% 12% 10% 7% 13% 11% 7% 16% 17% 10% 14% $4.0 $3.0 $2.0 5% 1% 2% $1.0 0% $0.0 Q3 '17 Q2 '17 Q1 '17 Q4 '16 Q3 '16 Q2 '16 Q1 '16 Q4 '15 Q3 '15 Q2 '15 Q1 '15 Q4 '14 Q3 '17 Q2 '17 Q1 '17 Q4 '16 Q3 '16 Q2 '16 Q1 '16 Q4 '15 Q3 '15 Q2 '15 Q1 '15 Q4 '14 Consented Wells Non-Consent Wells Consented Wells Source: All company wells as of September 30, IRRs based on internal estimate at time each well is evaluated for consent/non-consent. 9

10 7 Operators Represent 89% of In Process Wells & 90% of YTD Consented Wells Operator % of In Process Wells % of Total Consented Wells Weighted Average EUR Weighted Average IRR Continental Resources 35% 5% 910,000 40% Whiting Petroleum 18% 17% 928,000 32% Slawson Exploration 11% 29% 869,000 29% ConocoPhillips 8% 10% 831,000 34% Lime Rock Resources 7% 16% 622,000 34% Hess Corporation 6% 5% 557,000 24% Marathon Oil 4% 8% 784,000 55% EUR & IRR Estimates could prove conservative if more recent well results continue to outperform initial type curve estimates. Source: Consented wells as of October 31, IRRs and EURs based on internal estimates at time each well is evaluated for consent/non-consent. 10

11 Increasing Mix of High Intensity Completions 100% 90% 80% 70% 60% 50% 40% 79% 89% 90% 100% 98% 96% 100% 30% 59% 56% 62% 20% 39% 42% 10% 0% Q4 '14 Q1 '15 Q2 '15 Q3 '15 Q4 '15 Q1 '16 Q2 '16 Q3 '16 Q4 '16 Q1 '17 Q2 '17 Q3 '17 High Intensity(1) Base Percentage of high intensity completions in Northern wells has increased significantly High intensity completions deliver best returns in current pricing environment Source: Company info, NDIC, and DrillingInfo (1) Gross Well Completions using 5+ million pounds of proppant and/or slickwater completion. NOG Leasehold NOG High Intensity Other Industry High Intensity 11

12 1 Curtis 21-16MBH-2NH Burlington (Jul. 2017) Peak 30: 1,102 Boepd 2 Anna 2-34H Continental (Jul. 2017) Peak 30: 1,452 Boepd 3 Hereford Federal 9-20H Continental (Aug. 2017) Peak 30: 1,231 Boepd 4 Wiley 7-25H Continental (Aug.2017) Peak 30: 1,966 Boepd BB-Chapin A H-6 5 Hess (Jun. 2017) Peak 30: 1,292 Boepd Stenejhem 8H Abraxas (Jun. 2017) Peak 30: 1,085 Boepd 1 6 Moline 14-32H Marathon (Aug. 2017) Peak 30: 1,705 Boepd Alfsvaag 5-31H1 Continental (Aug. 2017) Peak 30: 1,406 Boepd Malm HLW Newfield (Jul. 2017) Peak 30: 1,680 Boepd Anna 9-34H1 Continental (Aug. 2017) Peak 30: 733 Boepd Hereford Federal 6-20H1 Continental (Aug. 2017) Peak 30: 1,514 Boepd Oyloe B Oasis (Jul. 2017) Peak 30: 1,743 Boepd Evitt 34-12H Whiting (Jun. 2017) Peak 30: 1,811 Boepd Harley 14-36TFH Marathon (Sep. 2017) Peak 30: 2,501 Boepd 5 10 Stenehjem 31X-28DXA XTO (Aug. 2017) Peak 30: 1,210 Boepd NOG Leasehold Three Forks Wells Middle Bakken Wells Stark 44-35TFH Marathon (Sep. 2017) Peak 30: 2,276 Boepd 6 Oyloe TX Oasis (Sep. 2017) Peak 30: 1,256 Boepd 7 White TX Oasis (Sep. 2017) Peak 30: 1,253 Boepd 8 Nelson TFHU 9 Rath Federal 8-22H2 10 Whiting (Sep. 2017) Continental (Sep.2017) Peak 30: 1,497 Boepd Peak 30: 1,628 Boepd Source: Company info, NDIC, and DrillingInfo 12

13 Cum Production (Boe) Increasing Well Productivity 300, Cum(1) 280, Cum(1) 260, Cum(1) 700 Mboe Type Curve 240, Mboe Type Curve 220, Mboe Type Curve 200, Mboe Type Curve 180, , , , ,000 80,000 60,000 40,000 20, Producing Months month cum up 76% over 2015; 2016 Wells tracking a 1,000 Mboe type curve Wells assigned by year proposed (1) Wells assigned to years based on year in which they were proposed, regardless of when they actually began producing. Cumulative type curves comprised of the following numbers of gross wells: ,902; ; As of September 30, 2017 NOG Leasehold Wells WOC 2017 Spuds 2016 Spuds 2015 Spuds Spuds 13

14 Superior Well Performance Cum Production (Boe) 340, , , , , , , , , , , , ,000 80,000 60,000 40,000 20,000 - Average (Wells Completed in 2017) 700 Mboe Type Curve 800 Mboe Type Curve 900 Mboe Type Curve 1200 Mboe Type Curve Normalized Producing Days - Excluding Downtime 2017 Completions where Northern has a working interest Represents 167 gross (8.9 net) wells (1) (1) 2017 Completions Wells Northern has a working interest and daily production totals, excludes gross/net wells where Northern purchased an interest in an older producing well. Data normalized to 9,500 foot lateral. Source: Company information as of September 30, NOG Leasehold 2017 Completions 14

15 450, , ,000 Average 700 Mboe Type Curve 800 Mboe Type Curve 900 Mboe Type Curve 1200 Mboe Type Curve Cum Production (Boe) 300, , , , ,000 50, Normalized Producing Days - Excluding Downtime 55 gross wells completed with 10+ million pounds of proppant; average volume of 12.8 million pounds Average production tracking 1,000 Mboe type curve Source: Company information as of September 30, NOG Leasehold NOG Super Frac Other Industry Super Frac 15

16 Continually Improving Results Cum Production (Boe) 300, , , , , , , , , , ,000 80,000 60,000 40,000 20,000 - Average (Wells Completed in 2017) Average (Wells Completed in 2016) 700 Mboe Type Curve 800 Mboe Type Curve 900 Mboe Type Curve 1200 Mboe Type Curve Normalized Producing Days - Excluding Downtime Northern has a 7.1% working interest in unit 14 gross wells completed in Bakken, 8 Three Forks 10 gross wells competed in Bakken, 5 Three Forks Wells completed in 2017 performing 23% better than 2016 wells Source: Company information as of September 30, NOG Leasehold 2017 Completions 2016 Completions 16

17 Economics by EUR & Commodity Price IRR 140% 120% 100% 80% 60% 40% 20% 0% 1000 Mboe: $7.5MM CWC 900 Mboe: $7.5MM CWC 800 Mboe: $7.5MM CWC 700 Mboe: $7.5MM CWC 49% 35% 26% 20% $50 WTI $3.00 HH 88% 62% 47% 35% $60 WTI $3.00 HH 142% 98% 74% 55% $70 WTI $3.00 HH Source: Company info NOG Leasehold Wells WOC 2017 Spuds 2016 Spuds 2015 Spuds Spuds 17

18 Production vs Capital Expenditures $600 Production (Boepd) 16,000 12,000 8,000 4,000 $ ,275 $ ,274 $ ,261 $ ,794 16,285 13,552 13,933 13,442 13,688 13,653 13,299 13,794 15,321 $500 $400 $300 $200 Capital Expenditures (in millions) $128.7 $18.1 $16.5 $15.8 $34.1 $27.3 $30.7 $40.7 $ Q '16 2Q '16 3Q '16 4Q ' Q '17 2Q '17 3Q '17 $0 Production (Boepd) Capital Expenditures (in millions) 18

19 Protecting Liquidity and Cash Flows Swaps (1) Collars (1) Contract Period Volume (Bbls) Weighted Average Price (per Bbl) Volume (Bbls) Weighted Average Price (per Bbl) 2017: 4Q 418,500 $ ,000 $ $ : 1Q 825,000 $ Q 829,000 $ Q 753,000 $ Q 643,000 $ : 1Q 450,000 $ Q 455,000 $ Q 480,000 $ Q 414,000 $ : 1Q 303,300 $ Q 303,300 $ Q 303,600 $ Q 303,600 $50.37 (1) Open crude oil derivative contracts scheduled to settle after November 1,

20 Production: Total Production Increase 5% to 6% over 2016 Operating Expenses for 4 th Quarter 2017 LOE ($ per Boe) $9.00 $9.25 Tax (% of Oil & Gas Revenue) 9.4% Total G&A ($ per Boe) $3.00 $3.25 Average Differential for 2 nd Half 2017 NYMEX WTI ($6.00) ($7.00) Capital Budget $130.0 Million $141 (1) 2016 Capital Expenditures includes an $8.9 million property acquisition in the 4 th quarter of (2) Prodcution Estimate is at mid-point of 5 to 6% guidance on a per day basis. Capital Expenditures ($ millions) Capital Expenditures ($ millions) $600 $500 $400 $300 $200 $100 $0 $140 $120 $100 Capital Expenditures (1) & Production (2) 15,794 16,285 $537 $129 13,653 $85 14,440 $ Est CapEx Production 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 Capital Expenditures (1) & Production by Quarter $80 $60 $40 $20 $0 Q4 '14 $45 $33 $27 $24 $18 $17 $16 $34 $27 $31 $41 Q1 '15 Q2 '15 Q3 '15 Q4 '15 Q1 '16 CapEx Q2 '16 Q3 '16 Q4 '16 Q1 '17 Production Q2 '17 Q3 ' ,000 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 Ave Daily Production (Boe) Ave. Daily Production (Boe) 20

21 Dominate Non-op Position in the Williston Basin High Quality Oil Levered Asset Base De-risked non-op position comprised of over 145,000 net acres of largely HBP acreage Participated in approximately 20% of gross wells drilled and completed to the Bakken & Three Forks; 3,143 gross (222.3 net) producing wells at September 30, 2017 Multi-year drilling inventory (313 net locations breakeven or better at $50/Bbl) Significant upside outside the core and in lower Three Forks zones as well productivity and/or oil prices improve Strong Liquidity & Hedge Protection $235 million of liquidity (1) Hedge position helps protects returns and cash flow Ability to adjust spending up and down as returns dictate Positioned for Value Creation Enhanced completion designs and the expansion of core to drive continued well productivity improvements Increase in activity to provide more investment opportunities Accretive bolt-on acquisitions as the non-op consolidator in the Williston Basin (1) At November 1, 2017 comprised of approximately $135 million of cash on hand and $100 million of delayed draw term loan availability. 21

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23 North Dakota Active Horizontal Rig Count and Production (1) Daily Production (Mboe/d) Active Horizontal Rig Count Daily Oil Production (MBbl/d) Daily Gas Production (Mboe/d) Horizontal Rig Count North Dakota Wells Spud (1) North Dakota Monthly Wells Spud and Wells Completed (1) ,175 1,528 2,086 2,2542,624 1, , (1) NDIC ND Well Spuds ND Completions 23

24 Takeaway Options Takeaway Capacity (Mbopd) (1) 3,000 2,500 2,000 1,500 1, Pipeline/Refining Rail Basin Production NDIC Production Forecast Pipeline and rail provide multiple destinations for Bakken crude Take away capacity additions in 2016/2017 provide excellent optionality for low cost transportation Given the pipe and rail options, there is ample capacity for Bakken crude production Current Capacity Additions (Mbopd) Est Pipeline 739, , ,000 Local Refining 88,000 88,000 - Rail 1,420,000 1,520,000 - Additions in Year 470,000 Total Takeaway 2,247,000 2,371,000 2,841,000 (1) North Dakota Pipeline Authority (Oil Export Options-November 16, 2016) 24

25 Year Ended December 31, Production: Oil (MBbls) 3, , , , ,325.9 Natural Gas and NGLs 1, , , , ,026.9 Total Production (Mboe) 3, , , , ,997.1 Realized Oil Price, including settled derivatives ($ / Bbl) $ $ $ $ $ Realized Natural Gas and NGL Price ($ / Mcf) Total Oil & Gas Revenues, including settled derivatives (millions) $ $ $ $ $ Adjusted EBITDA (millions) (1) $ $ $ $ $ Key Operating Statistics ($ / Boe) Average Realized Price (2) $ $ $ $ $ Production Expenses Production Taxes General & Administrative Expenses-Cash Total Cash Costs $ $ $ $ $ Operating Margin ($ / Boe) $ $ $ $ $ Operating Margin % 71.0% 75.2% 73.1% 76.2% 67.1% (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. 25

26 December 31, ($'s in millions) Assets Current assets $ 94.2 $ $ $ $ 46.9 Property and equipment, net 1, , , Other assets Total Assets $ 1,190.9 $ 1,519.6 $ 2,026.7 $ $ Liabilities Current liabilities $ $ $ $ 78.1 $ 77.4 Debt Other long-term liabilities Stockholders' equity (Deficit) (197.6) (487.4) Total Liabilities & Equity (Deficit) $ 1,190.9 $ 1,519.6 $ 2,026.7 $ $ Credit Statistics Adjusted EBITDA (1) $ $ $ $ $ Interest expense (1)(2) $ 13.9 $ 30.1 $ 40.7 $ 53.4 $ 57.6 Adjusted EBITDA/Interest (1)(2) 16.2x 8.9x 7.6x 5.2x 2.6x Secured Debt $ $ 75.0 $ $ $ Total Debt $ $ $ $ $ Secured Debt/Adjusted EBITDA (1) 0.6x 0.3x 1.0x 0.5x 1.0x Total Debt/Adjusted EBITDA (1) 1.9x 2.2x 2.6x 3.1x 5.6x (1) Year ended December 31 st (2) GAAP expense per audited financial statements (excludes non-cash interest expense) 26

27 Quarter Ended September 30, June 30, March 31, December 31, (In thousands) Net Income (Loss) $(16,087) $13,802 $16,941 $(12,330) Add Back: Interest Expense 16,673 16,428 16,304 16,195 Income Tax Benefit (1,402) Depreciation, Depletion, Amortization and Accretion 15,358 13,682 12,828 13,523 Non- Cash Share Based Compensation 3, Write-off of Debt Issuance Costs Unrealized Loss (Gain) on Derivative Instruments 16,058 (14,172) (17,057) 18,212 Adjusted EBITDA $35,734 $30,746 $29,639 $35,071 (1)-Stock forfeiture recapture exceeded non-cash compensation expense in Q

28 (In Thousands) Net (Loss) Income $ (293,494) $ (975,355) $ 163,746 $ 53,067 $ 72,285 Add Back: Interest Expense 64,486 58,360 42,106 32,709 13,875 Income Tax Provision (Benefit) (1,402) (202,424) 99,367 31,768 43,002 Depreciation, Depletion, Amortization and Accretion 61, , , ,383 98,923 Impairment of Oil and Natural Gas Properties 237,013 1,163,959 Non-Cash Share Based Compensation 3,182 6,273 2,759 4,799 12,382 Write-off of Debt Issuance Costs 1,090 Unrealized Loss (Gain) on Derivative Instruments 76,347 88,716 (171,276) 21,259 (15,147) Adjusted EBITDA $148,466 $277,299 $309,586 $267,985 $225,320 28