D.A. Davidson 17 th Annual Diversified Industrials & Services Conference September 20, 2018

Transcription

1 D.A. Davidson 17 th Annual Diversified Industrials & Services Conference September 20, 2018

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 facts that address activities, events or developments that Mammoth expects, believes or anticipates will or may occur in the future are forward-looking statements. The words anticipate, believe, ensure, expect, if, intend, plan, estimate, project, forecasts, predict, outlook, aim, will, could, should, potential, would, may, probable, likely and similar expressions, and the negative thereof, are intended to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this investor presentation may include statements, estimates and projections regarding Mammoth s business outlook and plans, future financial position, liquidity and capital resources, operations, performance, including under utility infrastructure restoration and reconstruction contracts of its wholly owned subsidiary Cobra Acquisitions LLC in Puerto Rico, acquisitions, returns, capital expenditure budgets, costs and other guidance regarding future developments. Forwardlooking statements are not assurances of future performance. These forward-looking statements are based on management s current expectations and beliefs, forecasts for Mammoth s existing operations, experience and perception of historical trends, current conditions, anticipated future developments and their effect on Mammoth, and other factors believed to be appropriate. Although management believes that the expectations and assumptions reflected in these forward-looking statements are reasonable as and when made, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all). Moreover, these forward-looking statements are subject to significant risks and uncertainties, including those described in Mammoth s Annual Report on Form 10-K, Quarterly Reports on Form 10 Q, Current Reports on Form 8 K and other filings Mammoth makes with the Securities and Exchange Commission ( SEC ), which may cause actual results to differ materially from its historical experience and 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: the failure to receive or delays in receiving governmental authorizations, approvals and/or payments; risks relating to economic conditions; 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; the effects of government regulation, permitting and other legal requirements; operating risks; the adequacy of our capital resources and liquidity; weather; natural disasters; litigation; competition in the oil and natural gas and infrastructure industries; and costs and availability of resources. Investors 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 and our filings with the SEC 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 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 Strong foundation in place providing platform by which to grow through organic expansion or acquisitions Wexford Capital and Gulfport Energy (NASDAQ: GPOR) capital partners IPO date October 14, 2016 June 18 May 18 June 17 Oct 07 Nov 10 Sep 11 Energy Services Oct 11 Coil Tubing Nov 12 May 12 Mar 12 Aug 13 Dec 12 Jun 14 April 17 May 17 Energy Services and Cementing Pressure Pumping Mammoth's assets have largely been developed organically 2

4 Integrated North American Energy Services Infrastructure Construction and Oilfield Services Infrastructure Services Fully capable infrastructure construction services including the following: Bare-hand live line up to 345KV Substation and switchyard services Overhead distribution up to 34.5KV Overhead (OH) and underground residential distribution (URD) tickets Aviation services (FAA 133, 137, 135) Presence in the Northeast, Midwest and Southwest portions of the U.S Contracts in place to help restore and reconstruct the electric utility infrastructure in Puerto Rico Oil Field Services Fully integrated oil field services model incorporating the following services: Hydraulic fracturing 6 High pressure fleets ~292,000 hhp Northern white frac sand Mmtpa of sand processing capabilities with production costs of $16-$18/ton Fully integrated cementing and acidizing offerings Sand hauling trucks capable of moving conventional pneumatic trailers as well as many of the box systems in use today Fully integrated rig moving business capable of moving two rigs at one time Crude hauling business active in both the SCOOP/STACK and Permian Basin Drilling rigs and directional drilling services Flowback and coil offerings Contract in place to help restore and reconstruct the electric utility infrastructure in Puerto Rico Pressure pumping contract in place with Gulfport Energy through 2021 (1) ~30% of sand capacity contracted under take-or-pay contracts ensuring stable cash flows (1) Contract in place for up to two fleets at the election of Gulfport 3

5 Infrastructure Services Provides Counter Cyclical Earnings Growth Infrastructure Construction Cobra acquired two separate transmission and distribution (T&D) businesses that were capital constrained but had with deep client relationships. 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 forecast annual North America T&D spending of $65-$70 billion for the next five years (1) Aging utility infrastructure provides potential for significant demand in the coming years with T&D spending expected to steadily increase Signed an initial contract in October 2017 which, as amended, provides for payments of up to $945 million to aid in the restoration of the electric utility infrastructure in Puerto Rico Signed a second contract in May 2018 which provides for payments of up to an additional $900 million to complete the restoration and support the initial phase of reconstruction of the electrical power system in Puerto Rico Backlog of ~$1.4 Billion (2) $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 2017 (2) As of June 30,

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 3 years as of June 30, 2018 Geographic diversification Three fleets operating in the Utica/Marcellus Two fleets operating in the SCOOP/STACK One fleet operating in the Permian Completed 1,815 high pressure stages during 2Q 2018 Strong Customer Base Pressure Pumping EBITDA Margins 39% 29% 25% 24% 27% 19% 17% 21% 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 5

7 Natural Sand Proppant Services ~4.4 Million Tons Per Annum (Mmtpa) of Processing Capacity Services Summary Take-or-pay contracts in place covering ~30% of expected volumes, at attractive pricing Total effective processing capacity of 4.4 Mmtpa Brokered sand ~19% of total sold volumes in 2Q18 Unit train access on multiple railways, including the CN and UP More than 2,100 railcars leased (1) at attractive rates Average sales price in 2Q 2018 of $43.09/ton 2Q 2018 production 89% fine grades (2) Expected Blended Costs per Ton (Produced Sand) Sand Sales in 2Q18 $28.00 $28.00 SCOOP/STACK, 18% Other, 3% DJ, 16% $20.00 $19.50 $19.00 $18.00 $17.00 $16.00 Permian, 23% Marcellus/Utica, 31% 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18E 4Q18E Montney, 9% ~780M Tons (1) Including railcars leased at both Taylor and Muskie (2) 2Q 2018 production by grade 53% - 40/70, 22% - 30/50, 14% mesh, 11% - 20/40 6

8 Mammoth Metamorphosis Transition to Industrial Past Present Future Pure Oilfield Service Pressure pumping Natural proppant Sand transportation Drilling rigs and directional drilling Flowback and coil offerings % of Revenues 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Infrastructure 9% OFS 57% Energy Service Infrastructure Construction Transmission construction Substation construction Distribution construction Helicopter operations Oilfield Service Pressure pumping Natural proppant Sand and crude transportation Drilling rigs and directional drilling Flowback and coil offerings 66% 68% 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 Industrial Company Infrastructure Construction Transmission construction Substation construction Distribution construction Expanding helicopter operations Logistics Industrial Industries Exploring full service transportation Exploring 5G buildout Exploring IMO 2020 Exploring manufacturing Oilfield Service Pressure pumping Natural proppant Sand and crude transportation Drilling rigs and directional drilling Flowback and coil offerings Evaluated 135 individual deals in 2017, closed 6 Evaluated 122 individual deals in first half of 2018, closed 2 M&A focus has shifted to industrial 7

9 History of Strong Financial Performance Clean Balance Sheet Allows for Growth Debt (Year-end) ($MM) Cash (Year-end) ($MM) Revenues and EBITDA ($MM) $146 $29 Revenue EBITDA $961 $1,028 $95 $100 $17 $0 $40 $0 $4 $6 $10 $12 $276 $368 $55 $71 $231 $41 $165 $ Q18 2Q18 Energy Downturn $130 MM IPO Organic Growth Q18 2Q18 Energy Downturn $130 MM IPO Organic Growth H18 Energy Downturn Organic Growth Expect to deploy free cash flow into acquisitions and organic growth initiatives 8

10 Mammoth Value Creation Focused on Return on Capital 10/14/2016 (IPO Date) ~$500 Million Market Capitalization Up 156% 9/14/2018 ~$1.3 Billion 10/14/2016 (IPO Date) $13.26/share 130% Outperformance vs OSX 79% Outperformance vs S&P 500 9/14/2018 $28.54/share 2016 $41 Million 75,000 Hhp Purchased For ~$375/Hhp 37,500 Hhp Purchased For ~$610/Hhp Chieftain Assets $36 Million EBITDA Generation UP 4X Return on Invested Capital 2017 $165 Million Pressure Pumping Peers Trading At ~$1,600/Hhp (1) 3 Year ~$95 Million Contract Covering 50% of Volumes Infrastructure Investment ~$8 Million (2) ~$1.9 Billion in Contracts (3) (1) As of 9/14/2018 peer group includes BAS, FRAC, FTSI, LBRT, PUMP, RES (2) Purchase of Higher Power Electrical and 5 Star Electric combined totaled approximately $8 million, does not include growth capital of ~$77 million spent over the past 12 months (3) Includes announced $945 million and $900 million contracts with PREPA and contracts with investor owned utilities in the U.S. 9

11 TUSK Well Positioned vs Peers Compelling Value Compelling value opportunity versus peers Trading at discount to peer group despite superior balance sheet and service diversification EV / 2019 EBITDA (Consensus Estimates) (2) Market capitalization (1) of ~$1.3 billion, enterprise value of ~$1.3 billion, based on zero debt and ~$11 million of cash on 6/30/ x 7.0x 9.7x Broad based earnings growth potential Reflected in integrated portfolio 3.2x 4.2x 4.6x ~35% of revenue in 2Q 2018 generated from oil field services Mammoth Proppant Peers Pressure Pumping Peers Land Driller Peers Transmission and Distribution Large Cap Peers Revenue by Segment in 2Q Stock Performance YTD (2) Contract Drilling Natural Sand 3% 10% Other 4% Pressure Pumping 18% 45% 1% Infrastructure 65% (11%) (18%) (30%) (32%) Mammoth Land Driller Peers Transmission & Distribution Large Cap Peers Pressure Pumping Peers Proppant Peers Source: Company estimates, Factset (1) Based on 9/14/2018 closing price (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, FTSI, PUMP, RES, CFW TSX, TCW-TSX); Transmission and Distribution (EME, DY, MTZ, MYRG, PWR) 10

12 Appendix

13 Strong Financial Performance Shift to Industrial Underway Strong 2Q18 Results 2Q18 revenues of ~$534 million, net income of ~$43 million and adjusted EBITDA of $149 million (1) 2Q18 adjusted EBITDA margins were 28% Fully repaid debt ($39.9 million) Spent $72 million on growth capex Grew infrastructure backlog to $1.4 billion as of June 30, 2018 (up from $900 million on March 31, 2018) Completed 1,815 high pressure stages during 2Q18 Sold ~780,000 tons of sand during 2Q18; Average sales price of $43.09/ton Revenues and Adjusted EBITDA ($MM) Revenue by Segment in 2Q 2018 Contract Drilling 3% Natural Sand 10% Other 4% Infrastructure 65% Pressure Pumping 18% Corporate Adjusted EBITDA margins Revenue Adjusted EBITDA $494 $534 $369 27% 30% 26% 28% 22% 19% $63 $65 $74 $98 $17 $14 $11 $15 $149 $28 $110 $131 $149 15% 15% 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 (1) See reconciliation of Adjusted EBITDA to comparable GAAP measure in the appendix and our filings with the SEC 12

14 Capex Budget Focused on Growing Organically 2018 Major Projects 2018 Capex (in Millions) Organically growing the continental U.S. infrastructure business by roughly 100%, ultimately dependent on contract coverage Upgrade of sand processing capabilities, growing total sand capacity to 4.4 Mmtpa Expand rental division into the Mid-Continent Pressure Pumping $21 Natural Sand $25 Expand crude transportation fleet $98 Infrastructure Anticipate free cash flow for the balance of 2018, which will be used for further expansion opportunities, including potential acquisitions Capex spend of ~$109 million during the first half of the year, inline with forecasts, the majority of which was related to the expansion of our infrastructure segment and expansion of sand facilities Drilling $14 ~$205 million Other $47 13

15 US Rig Count Driving Pressure Pumping Demand Service Intensity Driving Larger Pressure Pumping Fleets Rig count & efficiency driving frac demand US Rig Count 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 1,600 1,400 1,200 1, ,050 Based on a projected year-end 2019 rig count of 1,238, we see demand for million Hhp up from a current working capacity of ~19 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-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18 Jan-19 Jul-19 Required PP fleets expected to increase with rig count Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18 Jan-19 Jul-19 Source: Raymond James Research; Company Estimates (1) Based on a year-end 2019 rig count forecast of 1,238 from Raymond James Research using 2.5 rigs per active Hhp fleet and 45,000 HHP per fleet. 14

16 Adjusted EBITDA Reconciliation Reconciliation of Adjusted EBITDA to net income (000 s) Three Months Ended June 30, 2018 Three Months Ended June 30, 2017 Net Income (Loss) $42,700 ($1,170) Depreciation, Depletion, Accretion and Amortization Expense $30,795 $19,893 Impairment of Long Lived Assets $ Acquisition Related Costs $77 $961 Public Offering Costs $ Equity Based Compensation $17, Stock Based Compensation $,1660 $1,050 Bargain Purchase Gain -- ($4,012) Interest Expense $959 $1,112 Other Expense, net $486 $203 (Benefit) Provision for Income Taxes $53,512 ($2,804) Adjusted EBITDA $148,594 $15,233 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, public offering costs, equity based compensation, stock based compensation, bargain purchase gain, interest expense, other 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. 15

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