Emerge Energy Services LP Investor Presentation August 2017

Transcription

1 Emerge Energy Services LP Investor Presentation August PAGE 1

2 Forward Looking Statements, Non-GAAP Measures, & Reserve Estimates This presentation contains forward-looking statements. These statements can be identified by the use of forward-looking terminology including may, believe, will, expect, anticipate, or estimate. These forward-looking statements involve risks and uncertainties, and there can be no assurance that actual results will not differ materially from those expected by management of Emerge Energy Services LP. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in our annual report on Form 10-K filed with the SEC. The risk factors and other factors noted in our Form 10-K could cause our actual results to differ materially from those contained in any forward-looking statement. Except as required by law, Emerge Energy Services LP does not undertake any obligation to update or revise such forward-looking statements to reflect events or circumstances that occur after the date hereof. In this presentation, we present Adjusted EBITDA, a non-gaap financial measure. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financial statements, such as investors and commercial banks, to assess the financial performance of our assets without regard to the impact of financing methods, capital structure or historical cost basis of our assets; the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities; our liquidity position and the ability of our assets to generate cash sufficient to make debt payments and to make distributions; and our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital structure. We believe that Adjusted EBITDA provides useful information to investors because, when viewed with our GAAP results and the accompanying reconciliations, it provides a more complete understanding of our performance than GAAP results alone. We also believe that external users of our financial statements benefit from having access to the same financial measures that management uses in evaluating the results of our business. We define Adjusted EBITDA generally as: net income plus interest expense, income tax expense, depreciation, depletion and amortization expense, noncash charges and losses that are unusual or non-recurring less interest income, income tax benefits and gains that are unusual or non-recurring. We report Adjusted EBITDA (which as defined includes certain other adjustments, none of which impacted the calculation of Adjusted EBITDA herein) to our lenders under our revolving credit facility in determining our compliance with the interest coverage ratio test and certain senior consolidated indebtedness to Adjusted EBITDA tests thereunder. Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. Moreover, our Adjusted EBITDA as presented may not be comparable to similarly titled measures of other companies. A reconciliation of Adjusted EBITDA to net income, the most directly comparable GAAP financial measure, is included in the Appendix. The internal estimate of the San Antonio site s sand reserves is based on surveying, drill core analysis and other tests performed by Emerge Energy s geology and engineering staff. This estimate has not been reviewed by its independent reserve engineers and may be revised following ownership of the property. By its nature, this estimate is more speculative than proved or probable reserves and subject to greater risk that such reserves will not be realized. PAGE 2

3 Agenda I. Strategic Initiatives Update II. III. San Antonio Transaction Recap Appendix PAGE 3

4 Competitive Strengths High Quality, Strategically Located Assets Technology Driven New Products Diversified Product Offering Intrinsic Logistics Advantages Trusted Reputation w/ Customers and Suppliers Proven Management Team Low Cost Operating Structure PAGE 4

5 Accomplishing Our Strategic Initiatives Reduced Costs 1 During Downturn Implemented lower cost mining methods Restructured railcar leases Ran lowest cost plants Reduced overhead 3 Sold Fuel Business Received an attractive valuation Proceeds used to paydown debt Pure play sand company Expanded 5 Footprint San Antonio site offers high quality local inbasin frac sand Close proximity to prolific Texas basins Introduced New Products SandGuard TM trials successfully reduced dust from handling SandMaxX TM self suspending sand successfully pumped in several wells 4 Raised Equity Approximately $60mm gross equity raised Proceeds used for further debt reduction and balance sheet improvement 6 Next Steps Expand San Antonio site Further penetrate market with SandGuard TM and SandMaxX TM sand Gain market share PAGE 5

6 Expanding Footprint with Local In-Basin Sands San Antonio Plant s Competitive Advantages San Antonio Transaction Highlights Local in basin & regional sands have proved effective for certain completion designs and are now approximately 30 35% of the frac sand market Delivered cost of sand to the Eagle Ford basin will be one of the lowest in the country Onsite rail service via the Union Pacific Mostly fine mesh sand (40/70 and 100 mesh) Crush strength on frac grades meets API spec Best in class production costs Offers product lines other than frac sand (construction, foundry, and sports sands) Provides opportunity to diversify our reserve mix with in basin sands Completes our product offering for all customers needs (low, medium, and high quality raw sand plus technology driven proppants) Provides access to more rail origins Increases exposure to fine mesh reserves Attractive valuation compared to recently announced local sands transactions Financed with second lien debt no dilution to unit holders PAGE 6

7 Introducing Technology-Driven Proppants We are excited about our two technology-driven proppant products: our self-suspending SandMaxX TM sand and our dustless SandGuard TM sand. These products have unique properties compared to regular sand and provide significant benefits to our customers. SandMaxX TM When raw sand is coated with the proprietary SandMaxX TM polymer (we own 11 patents), the enhanced sand tends to stay suspended in liquid for extended periods of time SandMaxX TM contacts more fissures during the completions process, releasing a higher amount of hydrocarbons compared to completions using traditional raw frac sand The expected incremental hydrocarbon recovery in a well has the potential to drive a significant margin premium versus raw sand Successfully sold the product in several trial wells across five different basins SandGuard TM The new OSHA ruling will lower respirable silica from the current permissible exposure limit by 50%, effective June 2018 Frac sand users must monitor employees and take action if over exposed (>25 micrograms per cubic meter) SandGuard TM dustless proppant protects personnel by preventing harmful silica dust from being released into the air Eliminates the need for expensive mechanical dust control systems PAGE 7

8 Building Out a Comprehensive Logistics Platform Our sand facilities have direct access to four Class One rail lines and can reach all major shale plays in North America on single-line hauls. Logistics Highlights As of July 31 st, we had 19 transload locations positioned in seven key North American Shale plays Focus on exclusive partnerships Minimize capital investment / maximize ROIC Expanding unit train capabilities (currently in 9 locations) We have approximately 5,500 customer and leased railcars We can store approximately 1,070 railcars in our facilities rail yards Over 85% of our fleet is currently active and expecting full utilization later in 2017 We successfully renegotiated the majority of our railcar leases in 2016 Evaluating last mile collaboration with Solaris Oilfield Infrastructure Wide Geographic Presence Dry Plant Transload Location Corporate Headquarters PAGE 8

9 Deleveraging Our Balance Sheet We have taken drastic measures to lower our debt burden and improve our liquidity, which have positioned us well for the current recovery in the market. We are also currently in the market to refinance our senior debt and raise new capital for our San Antonio expansion. Change in ABL Balance ($ in mm) Proceeds from the fuel sale, equity issuances, operating cash flow, and the second lien term loan have cut the ABL balance in half Change in Debt Balance and Liquidity ($ in mm) while the reduced ABL balance has freed up liquidity and enabled us to finance the San Antonio transaction without diluting our unit holders. $350 $300 $313 $350 $300 $ $50 $44 $60 $50 $250 (154) $250 $34 $40 $200 $150 $100 $50 Balance as of 6/30/16 Fuel Sale Proceeds (55) Equity Raises (Net Proceeds) 55 Cash to Fund Business Through Downturn $159 3/31/17 Balance (22) Operating Cash Flow & 2nd Lien Term Loan Proceeds $137 6/30/17 Balance $200 $150 $ $163 $6 22 $198 $ /30/ /31/2016 3/31/2017 6/30/2017 ABL Balance Second Lien Term Loan Unsecured Debt Total Liquidity (Right) $30 $20 $10 $ PAGE 9

10 Financial Performance Estimates During the downturn, we undertook substantial corrective actions to improve the competitive positioning of our business. Now we are estimating significant improvements in volume and Adjusted EBITDA for 2017 and Projected Total Volume Growth Tons in 000s Projected Annual Adjusted EBITDA $ in mm s 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 8,000 5,750 2, E 2018E (1) $200 $150 $150 $100 $50 $40 $ $(50) $(50) $(100) (3) (4) E 2018E (2) (4) Note: See appendix for reconciliation of Net Income to Adjusted EBITDA (1) Per midpoint of mm ton guidance on 5/3/17 earnings call (2) Per earnings call on 5/3/17 (3) Continuing operations Adjusted EBITDA for 2016 (4) Per guidance released on 5/3/17; 2018 is midpoint of $ mm PAGE 10

11 Capitalizing on a Strong End Market: Robust Demand for Frac Sand Estimates from Wall Street analysts indicate 2017 sand demand should surpass historical peak levels. The current recovery in the sand market is being driven by increased rig count and increases in drilling efficiencies, namely higher sand intensity per well and increased wells drilled per rig. North American Frac Sand Demand Forecast (tons in mm s) 170 Consensus TPH Estimate Average Proppant per Horizontal Well (tons in 000s) Jefferies Estimate GS Estimate Source: Wall Street Research and Spears & Associates E 2018P PAGE E 2018P

12 Agenda I. Strategic Initiatives Update II. III. San Antonio Transaction Recap Appendix PAGE 12

13 Introduction to the San Antonio Plant Property Details Production Capacity Product Sales Located 25 miles south of San Antonio, TX 650 total owned acres (surface and sand mineral rights) Estimated over 80 million (1) tons of reserves as of the acquisition date Wet plant: ~600k tons per year ( tpy ) frac Dry plant: approx. 300k tpy frac Expanding capacity to 600k tpy and then full scale 2.4mm tpy plant Prior operation had an 80+ year history Current volumes approximately 400k tpy, not serving the energy sector Selling to foundry, construction, and sport sands markets Sand Details 30/50, 40/70, and 100 mesh are all API spec Logistics Access Direct trucking to four lane US Highway 281 to serve in basin Eagle Ford demand Site has approx. 9,000 feet of property line on the Union Pacific mainline, rail spur comes into plant Access to BNSF mainline through our Elmendorf, TX terminal is approx. 15 miles from site Note: (1) Internal estimates; third party engineering underway to determine SEC proven and probable reserves standards PAGE 13

14 San Antonio Plant: Best in Class Business Model High quality reserves Large property and deposit In-basin location Dual rail service Minimal overburden All production operations located on site (avoids trucking) Owned reserves (no royalty) High recovery rate of produced to sellable material PAGE 14

15 Growing Demand for Frac Sand in Eagle Ford Basin While the Permian basin receives most of the attention, activity in the Eagle Ford basin, the second most active shale play, is gaining momentum with several notable operators in the area boosting their near term plans. Largest oil producer and acreage holder in the Eagle Ford Expecting to run 8 rigs for 2017 and complete 195 wells Estimated resource potential 3.2bn boe over 7,200 net wells 30% of $1.9bn D&C budget in 2017 directed to Eagle Ford 6 active rigs / 3 frac crews ( expected wells for 2017) <$40/bbl breakevens Completed $2.3bn Comanche Acquisition from Anadarko (155k net acres) in January 2017 Brings total net acreage in Eagle Ford to 360k Expecting to operate at least 5 rigs in 2017 Expecting to run 6 rigs for 2017; gross wells High GOR oil: >90% IRR Source: Company filings and presentations Eagle Ford Frac Sand Demand (mm tons) E 2018P Source: NavPort, Wall Street Research PAGE 15

16 San Antonio Plant s Strategic Location Major drilling activity is clustered in South and West Texas Overview Most of the Eagle Ford activity is within miles of the plant for direct to wellhead trucking Closest large scale frac sand operation to the Eagle Ford basin Ability to truck directly to wellhead, generating attractive margins Kosse In Basin Trucking and Railroad Access Average trucking costs from plant to wellhead estimated at $10 12/ton Site is located directly on the Union Pacific mainline Baker Hughes Rig Count as of 7/28/2017 Eagle Ford: 76 Permian: 379 Rail provides cost effective delivery into the Midland and Delaware basins EMES Plant 100 Mile Site Radius Access to BNSF mainline through our Elmendorf, TX terminal as an origin (~15 miles of trucking from plant) Exploring a new terminal in the Delaware basin PAGE 16

17 Industrial Sands End Market Central Texas (San Antonio and Austin metro areas) is one of the fastest growing regions in the country Approximately 4.5 million residents estimated as of 2016 Our San Antonio plant currently sells approximately 400k tons per year of product into foundry, sports sands, and construction markets We expect this end market to increase as our production volumes increase EMES San Antonio Plant PAGE 17

18 San Antonio Plant Expansion Plan Phase 1 Phase 2 Phase 3 TBD Frac Sand Production Cumulative Capacity (000 tons per year) Phase 3 Add On Initial Phase 3: 2,400 Timing Considerations Completed in July Received permit in July Currently under construction Operational by late Q3 Initial Phase 3 operational by early Q Add On timing depends on market demand; could be in 2018 Capital Cost N/A $2 3mm $50 55mm for Initial Add On to be determined but likely minimal amount Once at full scale, the San Antonio plant will be the closest large scale frac sand operation serving the Eagle Ford and will have favorable economics to the Permian via rail service. PAGE 18

19 Attractive Valuation for In-Basin Sand Acquisition ($ in mm's, except per ton metrics) EMES San Antonio Site Competitor A Competitor B Competitor C Announced Purchase Price $20 $145 $275 $214 Est. Capex for Plant Expansion $56 $80 $48 n/a (1) (3) (1) (4) (2) Total Invested Capital $76 $225 $323 $214 (5) Reserves (tons in mm's) > Total Invested Capital per Ton of Reserves $0.94 $1.88 $5.86 $5.23 (6) Production Capacity (mm tpy) Total Invested Capital per Ton of Production Capacity $31.46 $56.25 $ $ Source: SEC filings, public call scripts (1) Total disclosed capital outlay ($225mm) less EMES internal estimate on capital cost to build 4mm tpy dry plant ($80mm) (2) As per K (3) $3mm for Phase 2 expansion plus Initial Phase 3 midpoint of $50 55mm guidance (4) Midpoint of $45 50mm guidance (5) Internal estimate, includes all sand, currently being reviewed by third party engineering firm (6) Estimated total capacity with Initial Phase 3 expansion PAGE 19

20 Expanded Footprint and Balanced Mix The San Antonio site provides a more balanced footprint with a diversified mix of northern white and in basin sands. Before San Antonio After San Antonio Reserves (1) In basin 26% Northern White 74% In basin 58% Northern White 42% Fort Worth, TX HQ Total = 104.0mm tons Total = 184.0mm tons Headquarters Transload Facility Mine/Processing Facility Production (2) In basin 9% Northern White 91% In basin 32% Northern White 68% Total = 6.9mm tpy Total = 9.3mm tpy Note: (1) EMES internal estimates for San Antonio site; third party engineering study to follow for SEC proven and probable reserves standards (2) Initial Phase 3 expansion for San Antonio Plant PAGE 20

21 Agenda I. Strategic Initiatives Update II. III. San Antonio Transaction Recap Appendix PAGE 21

22 Summary Quarterly Performance $ in thousands, except per ton Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Continuing Operations: Total Tons Sold (tons in 000's) 1,392 1, Revenue $ 82,602 $ 75,344 $ 42,619 $ 31,285 $ 24,825 $ 29,670 $ 44,502 $ 60,654 Average Revenue per Ton $ $ $ $ $ $ $ $ % of Sand Sold through Terminals 39% 47% 50% 67% 57% 61% 52% 51% Adjusted EBITDA $ 7,534 $ 68 $ (10,543) $ (10,872) $ (16,028) $ (12,982) $ 665 $ 2,099 EBITDA per Ton $ 5.41 $ 0.05 $ (12.76) $ (22.05) $ (40.17) $ (29.57) $ 1.14 $ 2.63 Discontinued Operations: Volume of Refined Fuel Sold (gallons in million) ,651 61,549 62,222 55,768 64,567 Revenue $ - $ - $ - $ 67,095 $ 101,982 $ 80,481 $ 86,004 $ 115,666 Adjusted EBITDA $ - $ - $ (105) $ 2,759 $ 6,948 $ 3,469 $ 3,188 $ (1,835) Consolidated: Revenue $ 82,602 $ 75,344 $ 42,619 $ 98,380 $ 126,807 $ 110,151 $ 130,506 $ 176,320 Adjusted EBITDA $ 7,534 $ 68 $ (10,648) $ (8,113) $ (9,080) $ (9,513) $ 3,853 $ PAGE 22

23 Oil Price Breakevens by Basin Breakeven oil prices for most US shale plays are below the current WTI price. Several plays including areas in the Permian basin, Eagle Ford, and MidCon remain viable with WTI in the mid to high 30 s. Oil Breakevens by Basin (at 15% ATAX IRR) Assumes gas price of $3.00 per MMBtu ~ Source: Equity Research PAGE 23

24 Management and Board of Directors Name Title Years of Professional Experience Senior Management Team Rick Shearer Chief Executive Officer of EMES; CEO of SSS 43 Warren B. Bonham Vice President of EMES 32 Deborah Deibert Chief Financial Officer 29 Nadya Kurani Chief Accounting Officer 13 Board of Directors Ted W. Beneski Warren B. Bonham Kevin Clark* Peter Jones* Mark Gottfredson* Francis Kelly* Eliot Kerlin Rick Shearer Victor L. Vescovo Chairman of the Board, Partner and Co-Founder, Insight Equity Vice President of EMES and Partner, Insight Equity Associate Professor, Vanderbilt University, retired CEO, Hirschfeld Industries Director, Bain & Company President and CEO, CEOVIEW Branding Partner, Insight Equity President and Chief Executive Officer, Emerge Energy Services Partner and Co-Founder, Insight Equity * Denotes Independent Board Member PAGE 24

25 MLP Structure Historical Earned Distributions per Unit $1.50 $1.25 $1.00 $0.75 $0.70 (1) $1.13 $1.17 $1.00 $0.86 $1.38 $1.41 $1.00 $0.67 $0.50 $0.25 $0.00 2Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q 2017 ( 1) Full quarter results based on pro rated distribution of $0.37 Simplified MLP Structure All units are Common Units Non-economic General Partner No Incentive Distribution Rights (IDRs) No Minimum Quarterly Distributions (MQD) Our Sponsor, Insight Equity, which owns approximately 24% of the Common Units, has fully aligned its financial interests with our Public Unitholders EMES pays out 100% of its Distributable Cash Flow to Common Unitholders, subject to certain restrictions under our Credit Agreement Unlike a typical variable rate MLP, our gross margins are not based on the spread between two commodities that may or may not be correlated PAGE 25

26 From Mine to Railcar 1) Extract 2) Wash 3) Dry 4) Ship PAGE 26

27 Asset Summary Wet Plant Location Proven Recoverable Reserves (1) Primary Reserve Composition Plant Capacity (Thousands of Tons) 2016 Production (Thousands of Tons) New Auburn, WI 15.5 mm tons mesh 2,000 - Thompson Hills, WI 40.9 mm tons mesh 1, FLS (Wisconsin) 10.3 mm tons mesh 1, LP Mine (Wisconsin) 4.9 mm tons mesh 1, Church Road (Wisconsin) 5.3 mm tons mesh 1,200 - Kosse, TX 27.1 mm tons 100 mesh 1, San Antonio, TX 80.0 mm tons 40/ mesh 600 n/a Total mm tons 9,400 1,665 Dry Plant Location On-site Railcar Storage Capacity Plant Capacity (Thousands of Tons) 2016 Production Volumes (Thousands of Tons) New Auburn, WI 420 cars 1, Barron, WI 650 cars 2,400 1,588 Arland, WI (2) N/A 2, Kosse, TX N/A San Antonio, TX (3) NMF 300 n/a Total 1,070 7,200 2,266 (1) Except for San Antonio, reserves are estimated as of December 31, 2016 by third-party independent engineering firms based on core drilling results and in accordance with the SEC s definition of proven recoverable reserves and related rules for companies engaged in significant mining activities and represent marketable finished product. Reserves for San Antonio are internal EMES estimates and are not yet proven or probable. (2) We load sand from Arland onto rail at Barron, New Auburn, and at a third rail loadout near St. Paul, Minnesota. (3) Capacity for San Antonio, TX Dry Plant represents current capacity and excludes Phase 2 and 3 expansions PAGE 27

28 North American Sand Markets We have single-line access to four Class One railroads, which provide direct rail access to every major basin in North America National Network BNSF CN/GTW CP/SOO CSX /NS KCS/KSCSM UP Basin Highest Quality Sand Source: Association of American Railroads & U.S. Geological Survey. Mine Locations SSS Transload Sites Corporate HQ PAGE 28

29 Consolidated Net Income to Adjusted EBITDA Reconciliation $ in thousands Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Net income $ (6,082) $ (11,390) $ (20,775) $ 5,117 $ (22,897) $ (34,215) $ (9,888) $ (11,898) Depreciation, depletion and amortization 5,675 4,656 4,662 4,687 4,870 7,261 7,116 7,530 Provision for income taxes - - (220) Interest expense, net 5,082 3,198 3,448 8,458 5,969 5,191 3,528 3,271 Non-capitalized expenses from equity issuance Changes in fair value of stock warrants (3,008) 696 (885) 2, Equity-based compensation expense (204) 340 (63) 368 Write-down of sand inventory , Provision for doubtful accounts (535) 38 1, Write-off of assets & contract terminations (25) 10 4,026 1,308 (68) Cost to retire an asset 66 (6) Accretion Reduction in force Fuel segment selling expenses (679) Other state and local taxes Non-cash deferred lease expense 2,329 1,901 2,079 2,072 1, Gain on sale of fuel segment (31,699) Reduction in escrow receivable 2, Other adjustments under Credit Agreement Adjusted EBITDA $ 7,534 $ 68 $ (10,648) $ (8,113) $ (9,080) $ (9,513) $ 3,853 $ PAGE 29

30 Consolidated Adjusted EBITDA to Operating Cash Flow Reconciliation $ in thousands Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Adjusted EBITDA $ 7,534 $ 68 $ (10,648) $ (8,113) $ (9,080) $ (9,513) $ 3,853 $ 264 Interest expense, net (3,975) (2,684) (3,001) (4,682) (4,347) (4,642) (4,094) (2,826) Non-Cash Income Tax Expense (456) (424) (170) (558) (578) (642) (464) (633) Contract and project term - - (3) 25 - (25) Reduction in force (76) (362) - Change in other operating assets and liabilities 4,973 (7,785) (3,589) (82) 5,714 18,036 5,476 5,777 Write-down of sand inventory (5,394) - - Cost to retire assets Fuel division selling expenses (679) Non-cash deferred lease expense (2,329) (1,901) (2,079) (2,072) (1,607) Other adjustments under Credit Agreement - (213) (1) - (173) (35) - - Operating Cash Flow $ 5,766 $ (12,939) $ (19,491) $ (14,803) $ (10,741) $ (2,291) $ 4,762 $ 2,650 PAGE 30

31 Guidance: Net Income to Consolidated Adjusted EBITDA ($ in millions) Full Year Low 2018 High Net Income $ (13.0) $ 97.0 $ Interest expense, net Depreciation, depletion and amortization Provision for income taxes EBITDA $ 27.1 $ $ Equity based compensation expense Accretion expense Other state and local taxes Permitted acquisition transaction expenses Non cash deferred lease expense 8.0 (2.8) (2.8) Unrealized loss on fair value of warrant Other adjustments allowable under our existing credit agreement Adjusted EBITDA $ 40.0 $ $ PAGE 31