Northern Oil And Gas, Inc. · NYSE:NOG
Northern Oil And Gas — Q4 2017 Earnings Presentation
30 slides from Northern Oil And Gas's earnings presentation, Feb 26, 2018
Slide 1: February 2018
NYSE American: NOG February 2018
Slide 2: Forward-looking statements
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
Slide 3: Agenda
1) INTRODUCTION 2) Q4 EARNINGS AND GUIDANCE 3) CAPITAL STRUCTURE UPDATE 4) ASSET OVERVIEW 5) APPENDIX
Slide 4: The Bakken Is Back
4 ~50% Well Performance THE BAKKEN IS BACK = ~50% ~60% Basin Differentials ~Flat D&C Costs Rigs Active + + + Operational efficiencies offsetting the cost of enhanced completions… …resulting in bigger wells being drilled for the same cost as prior years Better wells coupled with lower oil differentia
Slide 5: 143K Net Acres Across the Bakken
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Slide 6: Northern at a glance: #1 Bakken non-op producer
6 ~16.7 mboed 4Q17 production 143+ THOUSAND NET ACRES ~88% HELD by production or operations 45 operating PARTNERS 83% OIL-WEIGHTED of 4Q17 production#1 BAKKEN NON-OP PRODUCER Note: As of 12/31/2017 unless otherwise noted (1) Currently active wells (PDP & Drilling/Completing) presented on a gross bas
Slide 7: Net undeveloped locations by IRR and economics
7 704 67 44 128 160 305 704 67 111 239 399 704 100%+ 75%+ 50%+ 25%+ <25% Total Net Undeveloped Locations by IRR(1) Avg. EUR (Mboe): 1,087 1,049 931 782 598 %Oil 79% 77% 80% 79% 79% Avg. PV-10 ($MM): 12.2 8.9 7.4 4.5 1.8 Economics by EUR & Commodity Price(2) (1) Uses FYE17 NYMEX Pricing (see appendix
Slide 8: Differentiated Value Proposition: PV10% Bridge
$510 $101 $147 $758mm Differentiated Value Proposition Total Net Inventory: 35+ Rig Years 8 Company Case PV10% Bridge (1) Represents reserves prepared in accordance with the guidance and pricing prescribed by the SEC in Industry Guide 2. The unescalated twelve month arithmetic average of the first d
Slide 9: Financial transformation and debt maturity
$203 $155 $700 $300 $344 2018 2019 2020 2021 2022 2023 2024 Debt Maturity by Year ($mm) $177 $348 – $400 Since 3Q17, Northern has been in the process of a financial transformation, positioning itself for growth in one of the nation’s premier “rate-of-change” oil plays with the following goals: Fin a
Slide 10: Acquisition thesis and background
Ba c k grou n d The s is When evaluating acquisitions, Northern has a significant competitive advantage over its peers given considerable amounts of data accumulated over 10 years of participating in 3,500+ Bakken wells across its 143k net acres We believe that the oil price downturn has created
Slide 11: Acquisition commentary and opportunity set
11 Commentary General Considerations Northern believes the current and future acquisition opportunities are attractive due to a dislocation in the market: Forced sellers: As producers switch to pad drilling, many non-operators are undercapitalized to fund the increased AFE burden on their acreag
Slide 12: Agenda
1) INTRODUCTION 2) Q4 EARNINGS AND GUIDANCE 3) CAPITAL STRUCTURE UPDATE 4) ASSET OVERVIEW 5) APPENDIX
Slide 13: Significant Momentum Heading Into 2018
13 15,321 16,742 Q317 Q417 $35.7 $48.5 Q317 Q417 $8.94 $8.65 Q317 Q417 GREW PRODUCTION (Boed) Significant MOMENTUM Heading Into 2018Q3 Source: Company info INCREASED Adjusted EBITDA ($MM) DIFFERENTIALS DECREASED ($/Bbl) REDUCED CASH OPERATING COSTS PER BARREL ($/Bbl) ~10% ~45% ~5% 1 2 3 4 Q4 Quarter
Slide 14: Full Year 2018 Guidance Summary
13,299 13,794 15,321 16,742 14,800 17,200 - 17,800 1Q17 2Q17 3Q17 4Q17 2017 2018E Oil (Boed) Natural Gas (Boed) 14 FULL YEAR 2018 GUIDANCE SUMMARY 2017 Actuals 2018 Guidance Range Production Avg. Daily Prod. (Boed) 14,800 17,200 - 17,800 % Oil 84% 84% % Natural Gas 16% 16% Income Statement ($/Boe) D
Slide 15: Agenda
1) INTRODUCTION 2) Q4 EARNINGS AND GUIDANCE 3) CAPITAL STRUCTURE UPDATE 4) ASSET OVERVIEW 5) APPENDIX
Slide 16: TPG Term Loan and Proposed Bond Exchange
16 T P G T e rm Lo a n P rop o s e d B on d E x c h a ng e The Company took an important first step in addressing its capital structure with the completion of a five year $400 million Term Loan Credit Facility with TPG in November 2017 Proceeds were used to refinance its pending September 2018 R
Slide 17: Exchange Agreement
17 Exchange Agreement Exchange Agreement entered into with Cooperating Group of Noteholders, holding approximately 71%, or $497 million, of Senior Notes due 2020 TRT Holdings ($205 million) Other Cooperating Noteholders ($292 million) Transaction will not be open to all bondholders Exchange
Slide 18: Sources and Uses; Pro Forma Capitalization
Sources (in $ millions) New 8.5%/9.5% PIK Toggle 2L Notes due 2023 $344.3 Equitization of Debt 154.9 Equity Raise 156.0 Total Sources $655.2 Uses Exchange 8.00% Senior Unsecured Notes due 2020 $342.0 Equitize 8.00% Senior Unsecured Notes due 2020 154.9 Estimated Transaction Fees 10.1 Exchange Premiu
Slide 19: Agenda
1) INTRODUCTION 2) Q4 EARNINGS AND GUIDANCE 3) CAPITAL STRUCTURE UPDATE 4) ASSET OVERVIEW 5) APPENDIX
Slide 20: Northern Net Acreage Summary
20 89% 11% ND % Held ND % Non-Held North Dakota Montana 90% 10% North Dakota Montana 88% 12% Total % Held Total % Non-Held 30,008 27,499 18,722 17,783 16,703 18,032 14,506 McKenzie Mountrail Williams Dunn Divide Other Montana Total Net Acreage: 143,253(1) ND: 128,747 Net Acres MT: 14,506 Net Acres N
Slide 21: Percentage of Net Producing Wells by Operator
21 19.2% 11.4% 8.8% 6.7% 6.6% 5.5% 5.4% 4.2% 3.5% 3.2% 3.0% 22.5% Percentage of Net Producing Wells – By Operator Top 10 Operators 1 Slawson 2 Continental 3 Whiting 4 Hess 5 ConocoPhillips 6 Oasis 7 XTO Energy 8 EOG 9 Petro-Hunt Dakota 10 Statoil Source: Company info as of December 31, 2017 Petro-Hu
Slide 22: Increasing Well Productivity
22 (1) Wells assigned to years based on year in which they started producing. Cumulative type curves comprised of the following numbers of gross wells: 2012-2014 – 1,443; 2015 – 303; 2016 – 157; 2017 – 255. Includes producing wells as of December 31, 2017 with at least 30 days of production 2017 –
Slide 23: Appendix
1) INTRODUCTION 2) Q4 EARNINGS AND GUIDANCE 3) CAPITAL STRUCTURE UPDATE 4) ASSET OVERVIEW 5) APPENDIX
Slide 24: Protecting Liquidity and Cash Flows
24 Protecting Liquidity and Cash Flows Swaps(1) Contract Period Volume (Bbls) Weighted Average Price (per Bbl) 2018: 1Q 860,400 $53.42 2Q 829,000 $53.09 3Q 753,000 $53.42 4Q 643,000 $53.54 2019: 1Q 621,000 $53.01 2Q 600,600 $52.89 3Q 524,400 $52.30 4Q 469,200 $52.22 2020: 1Q 327,600 $50.49 2Q 309,40
Slide 25: Operating and financial summary 2013-2017
25 Year Ended December 31, 2013 2014 2015 2016 2017 Production: Oil (MBbls) 4,046.7 5,150.9 5,168.7 4,325.9 4,537.3 Natural Gas and NGLs (Mmcf) 2,572.3 3,682.8 4,651.6 4,026.9 5,187.9 Total Production (Mboe) 4,475.4 5,764.7 5,944.0 4,997.1 5,401.9 Revenue Realized Oil Price, including settled deriva
Slide 26: Balance sheet and credit statistics
26 ($'s in millions) Year Ended December 31, 2013 2014 2015 2016 2017 Assets Current assets $ 104.4 $ 226.0 $ 128.8 $ 46.9 $ 152.8 Property and equipment, net 1,397.3 1,761.9 589.3 376.2 473.2 Other assets 17.9 38.8 15.8 8.4 6.3 Total Assets $ 1,519.6 $ 2,026.7 $ 733.9 $ 431.5 $ 632.3 Liabilities Cu
Slide 27: Quarterly Adjusted EBITDA reconciliation
27 ($’s thousands) Quarter Ended December 31, September 30, June 30, March 31, 2017 2017 2017 2017 Net Income (Loss) $ (23,849) $ (16,087) $ 13,802 $ 16,941 Add Back: Interest Expense 20,882 16,673 16,428 16,304 Income Tax Benefit (1,570) - - - Depreciation, Depletion, Amortization and Accretion 17,
Slide 28: Annual Adjusted EBITDA reconciliation
28 ($’s thousands) Year Ended December 31, 2017 2016 2015 2014 2013 Net (Loss) Income $ (9,194) $ (293,494) $ (975,355) $ 163,746 $ 53,067 Add Back: Interest Expense 70,286 64,486 58,360 42,106 32,709 Income Tax Provision (Benefit) (1,570) (1,402) (202,424) 99,367 31,768 Depreciation, Depletion, Amo
Slide 29: Standardized Measure Reconciliation
29(1) Represents reserves prepared in accordance with the guidance and pricing prescribed by the SEC in Industry Guide 2. The unescalated twelve month arithmetic average of the first day of the month posted prices were adjusted for transportation and quality differentials to arrive at prices of $45.
Slide 30: FYE17 Strip Pricing
30 FYE17 Strip Pricing Period WTI ($/bbl) HHub ($/MMbtu) 2018: 1Q $61.61 $3.17 2Q $60.24 $2.75 3Q $59.42 $2.80 4Q $58.39 $2.89 2019: 1Q $57.41 $3.05 2Q $56.52 $2.68 3Q $55.73 $2.72 4Q $55.11 $2.81 2020: 1Q $54.55 $2.99 2Q $53.95 $2.68 3Q $53.46 $2.73 4Q $53.08 $2.86 2021: 1Q $52.73 $3.05 2Q $52.40 $