Simmons 18 th Annual Energy Conference February 2018

Transcription

1 Simmons 18 th Annual Energy Conference

2 Forward Looking and Cautionary Statements Forward-Looking Statements The information in this investor presentation of Mammoth Energy Services, Inc. ( Mammoth or Mammoth Energy ) includes forward-looking statements. All statements, other than statements of historical fact included in this presentation, regarding Mammoth s strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this presentation, the words could, believe, anticipate, intend, estimate, expect, project and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on Mammoth s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Our forward-looking statements are subject to significant risks and uncertainties, including those described in our Annual Report filed on Form 10-K filed with the SEC on February 24, 2017, our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings we make with the Securities and Exchange Commission (the SEC ), including those relating to our acquisitions and our contracts, many of which are beyond our control, which may cause actual results to differ materially from our historical experience and our present expectations or projections which are implied or expressed by the forward-looking statements. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, risks relating to economic conditions; volatility of crude oil and natural gas commodity prices; delays in or failure of delivery of current or future orders of specialized equipment; the loss of or interruption in operations of one or more key suppliers or customers; solvency of counterparties to our contracts and/or their ability to timely pay for our services; oil and gas market conditions; the effects of government regulation, permitting and other legal requirements, including new legislation or regulation of hydraulic fracturing; operating risks; the adequacy of our capital resources and liquidity; weather; litigation; competition in the oil and natural gas industry; and costs and availability of resources. You are cautioned not to place undue reliance on any forward-looking statements, which speak only as of the date of this presentation. Except as otherwise required by applicable law, we disclaim any duty to update and do not intend to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this presentation. This presentation includes financial measures that are not presented in accordance with generally accepted accounting principles ( GAAP ), including Adjusted EBITDA. While management believes such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. Please see the Appendix for reconciliations of those measures to comparable GAAP measures. Industry and Market Data This presentation has been prepared by Mammoth and includes market data and other statistical information from third-party sources, including independent industry publications, government publications or other published independent sources. Although Mammoth believes these third-party sources are reliable as of their respective dates, Mammoth has not independently verified the accuracy or completeness of this information. Some data are also based on the Mammoth s good faith estimates, which are derived from its review of internal sources as well as the third-party sources described above. 1

3 Key Investment Highlights Focused on Three Key Service Lines Demand Remains Strong Strong 4Q17 Results Revenues and EBITDA ($MM) 4Q17 revenues of $369 million, net income of $64 million and adjusted EBITDA of $110 million (1) Revenue EBITDA $369 4Q17 EBITDA margins increased to 30% (up from 19% in 3Q 2017) Completed 1,375 high pressure stages during 4Q17 Sold ~600,000 tons of sand during 4Q17; Average sales price of $42.99/ton Pressure Pumping ~292,000 Hhp or 6 high pressure fleets (2) underpinned with 1/3 capacity dedicated to Gulfport Energy under contract through 3Q 2018 Demand remains high in all of our operating areas Exploring adding additional fleets in 2018, if returns justify the investment Proppant and Logistics Sand processing capacity of 4.4 Mmtpa expected by mid-2018 (3) from three Wisconsin facilities producing high quality northern white sand ~50% of capacity expected to six frac fleets, ~30% contracted under takeor-pay contracts Last-mile solutions in the Marcellus/Utica, SCOOP/STACK and Permian Energy Infrastructure Construction $149 $110 $98 $69 $63 $65 $74 $35 $28 $13 $17 $14 $(2) $11 $15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 Corporate EBITDA margins 30% 27% 22% 19% 19% 15% 15% Expanding footprint across the Northeast, Southwest and Midwest portions of the U.S. and in Puerto Rico Expect controlled growth throughout 2018, contract backed Current backlog of $1 Billion -6% 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 (1) See reconciliation of Adjusted EBITDA to comparable GAAP measure in the appendix (2) High pressure fleets consist of ~50,000 Hhp. (3) Includes the expansion of Taylor Frac, which was completed in 1Q 2018 and expansion of capacity at Piranha which is expected to be completed by mid

4 Integrated North American Energy Services Completions Focused with Diversification into Infrastructure Completion and Production Services Natural Proppant Production Services Infrastructure Services Pressure Pumping Logistics Hydraulic fracturing and sand hauling services primarily located in the Utica/Marcellus and SCOOP/STACK Specifically designed for modern completions Capacity of ~292,000 HHP 62 Trucks providing last-mile logistics Taylor Frac Premier low cost mine with costs of $10-$12/ton and 1.75 Mmtpa capacity Piranha Proppant ~1.9 Mmtpa (1) sand mine with unit train capability located on the UP Muskie - ~0.7 million ton sand processing facility in Pierce County, WI Cobra offers infrastructure construction services Presence in the Northeast, Midwest and Southwest portions of the U.S. with activity in 11 states Contract in place to help restore the electric utility infrastructure in Puerto Rico Completions focused service lines with pressure pumping and sand the backbone of our oil field service business Comprehensive services offering including drilling, last-mile logistics, coil tubing and flow back services Contracts in place for 2 spreads (1/3 of HHP) through 3Q 2018 and 30% of sand capacity ensuring stable cash flows Entered energy infrastructure construction services in 2017 to further diversify the portfolio (1) Includes expansion of capacity at Piranha which is expected to be completed by mid

5 Capex Budget Focused on Growing Organically 2018 Major Projects 2018 Capex (in Millions) Organically growing the continental U.S. infrastructure business by roughly 100%, on a crew count, ultimately dependent on contract coverage $21 Upgrade facilities at Piranha, growing total sand capacity to 4.4 Mmtpa by mid-2018 Completion & Production Expand rental division into the Mid-Continent Exploring adding additional pressure pumping fleets, if returns justify the investment $56 Infrastructure Proppant & Logistics $24 Anticipate free cash flow throughout 2018, which will be used for debt repayment and further expansion opportunities, including potential acquisitions Drilling Other $10 ~$125 million $13 4

6 Pressure Pumping Services Strong Reputation Among Leading E&P Companies Pressure Pumping Services 6 high pressure pumping fleets (~50,000 Hhp each) 117 high-pressure fracturing units and ancillary equipment ~292,000 Hydraulic Horsepower (Hhp) Average age of just over 2.5 years as of December 31, 2017 Geographic diversification Three fleets operating in the Utica/Marcellus Two fleets operating in the SCOOP/STACK One fleet operating in the Permian Exploring adding additional fleets in 2018 Completed 1,375 high pressure stages during 4Q 2017 Strong Customer Base Pressure Pumping EBITDA Margins 39% 28% 29% 25% 24% 27% 19% -20% 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 5

7 Natural Sand Proppant Services ~4.4 Million Tons Per Annum (Mmtpa) of Processing Capacity (1) Services Summary Take-or-pay contracts in place covering ~30% of expected volumes, at attractive pricing Expansion of Taylor Frac and Piranha facilities on track increasing capacity to 4.4 Mmtpa by mid-2018 (1) Brokered sand reduced to ~26% of total sold volumes in 4Q17 down from ~49% in 2Q17 Unit train access on multiple railways, including the CN and UP More than 2,100 railcars leased (2) at attractive rates Average selling price in 4Q 2017 of $42.99/ton Expected Blended Costs per Ton (Produced Sand) $28.00 $28.00 Sand Sales in 4Q17 SCOOP/STACK, 31% Bakken, 4% DJ, 19% $20.00 $19.50 $19.00 $18.00 $17.00 $16.00 Permian, 16% Marcellus/Utica, 22% 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Montney, 5% ~600M Tons (1) Includes the expansion of Taylor Frac, which was completed in 1Q 2018 and expansion of capacity at Piranha which is expected to be completed by mid-2018 (2) Including railcars leased at both Taylor and Muskie 6

8 Infrastructure Services Provides Counter Cyclical Earnings Growth Infrastructure Construction Cobra acquired two separate businesses in mid 2017, which were well respected in the T&D industry with deep client relationships, but were capital constrained. Expect to further deploy capital to grow at attractive margins Senior management of infrastructure business has an average of 25 years experience with significant experience in storm recovery work Crews deployed to both Texas and Florida following Hurricanes Harvey and Irma to help restore power to the affected areas Industry experts (1) forecast annual North America T&D spending of $65-$70 billion for the next five years Aging utility infrastructure provides potential for significant demand in the coming years with T&D spending expected to steadily increase Signed a contract which provides for payments of up to $945 million to aid in the restoration of the electric utility infrastructure in Puerto Rico Current backlog of $1 Billion $75 $70 $65 $60 $55 $50 $45 Expected North American T&D Spending ($ Billions) (1) $ E 2018E 2019E 2020E 2021E 2022E (1) Data from The C Three Group dated September

9 Mammoth Value Creation Focused on Return on Capital 1/1/2017 $570 Million Market Capitalization Up 54% 12/31/2017 $875 Million 1/1/2017 $15.20/share 21% Outperformance vs Pressure Pumping Peers; 76% Outperformance vs Proppant Peers; 49% Outperformance vs OSX 12/31/2017 $19.63/share 2016 $41 Million EBITDA Generation UP 4X 2017 $165 Million 75,000 Hhp Purchased For ~$375/Hhp 37,500 Hhp Purchased For ~$610/Hhp Chieftain Assets $36 Million Return on Invested Capital Pressure Pumping Peers Trading At ~$2,100/Hhp (1) 3 Year ~$95 Million Contract Covering 50% of Volumes Infrastructure Investment ~$8 Million (2) $1+ Billion in Contracts (3) (1) As of 2/16/2018 peer group includes BAS, FRAC, LBRT, PUMP, PTEN, RES (2) Purchase of Higher Power Electrical and 5 Star Electric combined totaled approximately $8 million, does not include growth capital of $20 million during 2017 (3) Includes announced $945 million contract with PREPA and US contracts with IOUs. 8

10 TUSK Well Positioned vs Peers Compelling Value Compelling value opportunity versus peers Trading at substantial discount to peer group despite superior balance sheet and service diversification Market capitalization (1) of ~$1.1 Billion, current Enterprise Value of ~$1.2 Billion, based on debt of ~$100 million and ~$6 million of cash at the end of 2017 Broad based earnings growth potential Reflected in integrated portfolio EV / 2018 EBITDA (Consensus Estimates) (2) 10.0x 8.7x 8.1x 4.9x 4.2x 4.5x ~40% of revenue in 4Q 2017 generated from completion activities Mammoth Proppant Peers Pressure Pumping Peers Revenue by Segment in 4Q Adj. EBITDA Margin % (2) Transmission and Distribution Land Driller Peers Large Cap Peers Contract Drilling 4% Natural Sand 11% Other 4% Infrastructure 53% Pressure Pumping 28% 23% 7% 11% 15% 17% 20% Mammoth T&D Large Cap Peers Pressure Pumping Peers Land Driller Peers Proppant Peers Source: Company estimates, Factset (1) Pricing as of 2/27/2018 (2) Large Cap (SLB, HAL, BHGE, WFT); Proppant (SLCA, FMSA, HCLP, SND, EMES); Land Drillers (NBR, HP, PDS, PES, ICD); Pressure Pumping (BAS, FRAC, LBRT, PUMP, RES, CFW TSX, TCW-TSX); Transmission and Distribution (MYRG, PWR, MTZ, EME) (3) Adjusted EBITDA margins are based on data from Factset 9

11 Appendix

12 US Rig Count Driving Pressure Pumping Demand Service Intensity Driving Larger Pressure Pumping Fleets Rig count & efficiency driving frac demand Rig efficiencies and longer laterals are driving the need for more pressure pumping fleets per rig Given the increase in rig count over , the demand for pressure pumping fleets needed to service the rig count has more than doubled over the past 18 months Higher intensity completions have driven the need for higher horsepower pressure pumping fleets US Rig Count 1,400 1,200 1, Based on a projected year-end 2018 rig count of ~1,200, we see demand for million Hhp up from a current working capacity of ~14 million Hhp (1) Avg. Fleet Size is Increasing Year Avg. Fleet size Hhp Rigs per fleet ,000-30, ,000-40, ,000-45, ,000-50, ,000-50, Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18 Required PP fleets expected to increase with rig count Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18 Source: Raymond James Research; Company Estimates (1) Based on a year-end 2018 rig count forecast of 1,200 from Raymond James Research using 2.75 rigs per active Hhp fleet and 45,000 HHP per fleet. 11

13 Opportunities Created by Regional Sands No Matter The Outcome, The Need For Last-Mile Trucking Will Increase Regional Sands 4Q 2017 Sand Sales by Basin ~60 million tons of new regional capacity announced to date spread across 16 plants. Majority of the reserves in place are 100 mesh, which is approximately 85% of sand currently used in the Delaware Basin (16% in Midland Basin). (1) Regional 40/70 grades may not prove suitable for deep formations as they have a crush factor of 4-7K, vs 9-11K for northern white formations. SCOOP/STACK 32% Bakken 4% DJ 20% Based on 24 tons per pneumatic truck, we calculate the need for up to ~2.5 million truck loads per year, assuming all announced plants get built. Recently expanded last-mile operations to the Permian Basin with 20 trucks/trailers currently in the area. Exploring further last-mile expansion as regional demand increases. Permian 16% Montney 5% Marcellus/Utica 23% Proppant by grade (1) Permian Basin Activity (2) (1) Per IHS report dated November 14, 2017 (2) Source: Jefferies Equity Research, Digital Globe, Google Maps, TCEQ, Baker Hughes 12

14 Sand Assets Strategically Positioned ~4.4 Million Tons per Annum (Mtpa) of Capacity Located on Multiple National Railways (1) Direct Access to Major Railways Taylor Frac located on the Canadian National Railway (CN) providing low cost access into the Utica/Marcellus and Western Canada markets Piranha Proppant located on the Union Pacific Railway (UP) with unit train capabilities providing low cost transportation into the Mid-continent and Texas markets Muskie Proppants has access to multiple class 1 railways including the CN, CP, BNSF and UP Multiple transload facilities in the Utica/Marcellus with both rail and barge capabilities Transload facility in the SCOOP/STACK in support of announced pressure pumping expansion into the area Last-mile logistics in place in the Utica/Marcellus, SCOOP/STACK and Permian Basins (1) Reflects approximately 0.7 Mtpa at Muskie, approximately 1.75 Mtpa at Taylor Frac following the expansion of facilities completed in 1Q 2018 and, approximately 1.9 Mtpa at Piranha Proppant (formerly Chieftain Sand) following the expansion of facilities by mid-year

15 Geographic Diversification Focused on the Most Active Basins by Design Basins Gas plays Oil / liquid plays Service Center Locations Headquarters 14

16 Contract Land Drilling and Rig Moving Services Horizontal and Vertical Drilling and Related Services Services Summary Contract drilling services in the Permian Basin for both horizontal and vertical wells 13 drilling rigs 9 horizontal (7 electric, 2 mechanical) 4 vertical Performed several rig upgrades (high pressure fluid ends, walking systems) to keep pace with current market demands Rig market improving Pricing and utilization improving Bison Trucking offers rig moving services capable of moving two rigs per day Rig moving fleet (32 trucks) 20 sand hauling trucks Rig Average Day Rate $15,964 $13,590 $14,400 $14,100 $14,803 4Q Q Q Q Q

17 Directional Drilling Services Personnel and Tools to Accurately Drill Unconventional Reservoirs Services Summary Panther directional drilling services allow for efficient drilling of wellbores within precise location parameters 7 Measurement While Drilling (MWD) Systems 3 Electromagnetic Telemetry (EM) MWD Systems 58 Mud Motors Panther is currently conducting operations in all of the major unconventional plays including the Utica/Marcellus, SCOOP/STACK, Eagle Ford and Permian Basin Management team has more than 100 years of combined experience with directional supervisors having an average of 16 years experience Panther has an agreement in place to utilize DoubleBarrel Rotary Steerable Systems (RSS) (1) which are currently in use in multiple unconventional basins (1) DoubleBarrel RSS is wholly owned by Wexford Capital 16

18 Well Services Cementing, Water Transfer, Rental Equipment, Pressure Control and Flowback Services Stingray Cementing Services Trusted provider of cementing services in the Utica/Marcellus Expanded fleet 66% in 2017 to meet customer demand 5 Twin Cementers, 5 Bulk Trucks, 1 Bulk Plant Stingray Energy Services Provides water transfer services from local water sources to well sites for completion operations Provider of a full suite of rental equipment for drilling and completion operations Located in the Appalachian Basin with more than 350 pieces of equipment currently rented across multiple well sites Expanding into the Mid-Continent region Redback Energy Services Provides coiled tubing services to perform various wellservicing and workover operations Provides flowback services consisting of production testing, solids control, hydrostatic testing and torque services Pressure control and flowback services support our pressure pumping services 17

19 History of The Mammoth Energy Portfolio Steady Organic Development and Diversification Mammoth is a platform for management teams to flourish Built to support in-demand services for unconventional resources in attractive basins June 17 May 17 Oct 07 Nov 10 Sep 11 Energy Services Oct 11 Coil Tubing May 12 Mar 12 Nov 12 Aug 13 Dec 12 Jun 14 Sep 14 Oct 14 April 17 Energy Services Cementing Pressure Pumping Mammoth's assets have largely been developed organically 18

20 Adjusted EBITDA Reconciliation Reconciliation of Adjusted EBITDA to net income (000 s) Three Months Ended December 31, 2017 Three Months Ended December 31, 2016 Year Ended December 31, 2017 Year Ended December 31, 2016 Net Income (Loss) $65,915 ($57,706) $58,964 ($92,453) Depreciation, Depletion, Accretion and Amortization Expense $27,770 $17,832 $92,124 $72,315 Impairment of long-lived Assets 4,146 $4,146 $1,871 Acquisition Related Costs $51 $264 $2,506 - One-Time IPO Compensation Charges - $1,201 $1,201 Equity Based Compensation $1,093 $520 $3,741 $501 Bargain Purchase Gain ($4,012) - Interest Expense $1,381 $763 $4,310 $4,096 Other (Income) Expense, net ($28) $214 $677 ($158) (Benefit) Provision for Income Taxes $10,155 $51,146 $2,832 $53,885 Adjusted EBITDA $110,483 $13,970 $165,288 $41,258 Adjusted EBITDA is a supplemental non-gaap financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) before depreciation, depletion, accretion and amortization expense, impairment of long-lived assets, acquisition related costs, one-time IPO compensation charges, equity based compensation, bargain purchase gain, interest expense, other (income) expense, net, and (benefit) provision for income taxes. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company s financial performance, such as a company s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements. 19

21 Company Headquarters Caliber Drive, Suite 300 Oklahoma City, OK