Investor Presentation November 2018

Transcription

1 Investor Presentation November 2018

2 Forward Looking Statements and Non GAAP Measures 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. PAGE 2

3 Agenda I. Strategic Initiatives Update II. III. IV. Oklahoma Details San Antonio Details Appendix PAGE 3

4 Competitive Strengths High Quality, Strategically Located Assets Low Cost Operating Structure Diversified Product Offering Intrinsic Logistics Advantages Trusted Reputation w/ Customers and Suppliers Proven Management Team Balanced Mix of Assets and Product Types PAGE 4

5 Accomplishing Our Strategic Initiatives 1 Reduced Costs Implemented lower cost mining methods Restructured railcar leases Ran lowest cost plants Reduced overhead 3 Raised Equity Approximately $60mm gross equity raised Proceeds used for further debt reduction and balance sheet improvement 5 Refinanced Balance Sheet Next Steps Amended $75mm revolving credit facility Issued new $215mm second lien notes and $6mm of equity Expansion capital Ramp up San Antonio plant to full capacity Progress on Oklahoma construction Grow last mile program Downturn Recovery 2 Sold Fuel Business Received an attractive valuation Proceeds used to paydown debt Pure play sand company Expanded 4 Footprint San Antonio site offers high quality in basin frac sand Close proximity to prolific Texas basins Attractive valuation Opened New San 6 Antonio Plant First dryer opened late April 18 Executed new customer contracts Received new NSR air permit in August 18 PAGE 5

6 Expanding Footprint and Diversifying Product Mix The San Antonio and Oklahoma sites provide a more balanced footprint with a diversified mix of northern white and in-basin sands. Before San Antonio and Oklahoma After San Antonio and Oklahoma Reserves (1,2) In basin 26% Northern White 74% In basin 60% Northern White 40% Fort Worth, TX HQ Total = 104.0mm tons Total = 190.0mm tons Headquarters Transload Facility Mine/Processing Facility Production (3) In basin 9% Northern White 91% In basin 49% Northern White 51% Total = 6.9mm tons per year ( tpy ) Total = 12.4mm tpy Note: (1) Includes San Antonio proven and probable reserves of 66mm tons based on evaluation by third party engineering firm (2) Oklahoma reserves are estimated, according to internal analysis; a third party engineering group will conduct an independent reserves analysis (3) Assumes 4mm tpy San Antonio capacity; Oklahoma capacity of 1.5mm tpy PAGE 6

7 San Antonio Offers Attractive In Basin Model Competitive Advantages Transaction Highlights Local in basin & regional sands have proven effective for certain completion designs and are now approximately 40 45% (1) of the frac sand market Delivered cost of sand to the Eagle Ford basin is one of the lowest in the country Mostly fine mesh sand (40/70 and 100 mesh) Best in class production costs Direct trucking to four lane US Highway 281 to serve in basin Eagle Ford demand Onsite rail service via the Union Pacific Access to BNSF mainline through our Elmendorf, TX terminal is approx. 15 miles Crush strength on frac grades meets API spec Offers product lines other than frac sand (construction, foundry, and sports sands); approx. 400k tpy Diversifies our reserve mix with in basin sands Increases exposure to fine mesh reserves 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 Attractive valuation compared to recently announced local sands transactions Source: (1) Tudor, Pickering, Holt & Co. Investment Research PAGE 7

8 San Antonio New Plant Progress Old Production Circuit New Plant, Existing Permit New Plant, New Permit 4,000 Frac Sand Production Cumulative Capacity (000 tons per year) 2, Timing Considerations Completed Q Construction began October 2017 Dry plant started up in April 2018 (first dryer) Received NSR permit in August 2018 Wet and dry plant under construction through Nov. Expect to ramp to full capacity in late November Capital Cost $3mm Total New Wet and Dry Plant Est: $65mm Our San Antonio plant is one of the closest large scale frac sand operations directly serving the Eagle Ford basin. PAGE 8

9 Oklahoma Offers Attractive In Basin Model Competitive Advantages Transaction Highlights Demand for in basin sand in the Mid Continent Basin ( Mid Con ) is strong as indicated by several large operators in the area We are in the process of signing up customers under contract Delivered cost of sand to the STACK portion of the basin (Kingfisher, Blaine, and Canadian counties in Oklahoma) will one of the lowest in the country Fine mesh sand (40/70 and 100 mesh); crush strength meets API spec Low production costs Early mover advantage expect plant to be operational in early 2019 Direct trucking to US Highway 81, a four lane highway serving central Oklahoma Rail service is less than three miles from the plant Pursuing opportunities to bundle northern white sand with local product Further diversifies our reserve mix with in basin sand and increases exposure to fine mesh sand Entered into a 25 year lease agreement for mining rights on 600 acres with an attractive royalty rate Low cost of capital: estimating $15 20 million total cost deploying existing equipment on hand for a portion of the dry plant; purchasing used equipment Attractive valuation compared to recently announced local sands transactions PAGE 9

10 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 Wide Geographic Presence As of 10/31/18, we had 12 transload locations positioned in six key North American Shale plays Recently expanded in Western Canada and Utah Primarily exclusive partnerships Minimize capital investment / maximize ROIC Seven unit train capable terminals We have approximately 5,100 railcars in our fleet We can store approximately 1,080 railcars in our facilities rail yards Our fleet is currently 70% active Evaluating last mile collaboration with several providers Mining / Processing Operation Transload Location Corporate Headquarters PAGE 10

11 Diversified Sales by Basin We have diversified our sales across multiple basins in North America. Our logistics capabilities and access to multiple class I railroads provide attractive economics into several regions. Given this diversification, we are well positioned to mitigate the penetration of Permian in-basin sand. 2018E Total Frac Sand Consumption by Market EMES LTM Sales Volume by Market (as of 3Q18) The Permian will account for nearly 40% of total 2018 estimated demand. MidCon 7% Northeast 12% Haynesville 8% Rockies 6% Bakken 6% Source: Wall Street Research Other US 4% Canada 5% Eagle Ford 14% Permian 38%.while only 21% of our LTM volume was consumed in the Permian. We have a strong presence in Western Canada, the Rockies, and the Bakken, and our share of the Eagle Ford and Mid Con basins should increase with our new in basin operations. Northeast 3% Other 14% MidCon 6% Canada 12% Rockies 14% Bakken 10% Permian 21% Eagle Ford 20% PAGE 11

12 Capitalizing on a Strong End Market: Robust Demand for Frac Sand Frac sand demand in 2017 surpassed historical peak levels, and further growth is expected for 2018 and Average proppant intensity per horizontal well continues to move higher, approaching nearly 7,000 tons per well compared to less than 2,000 tons in North American Frac Sand Demand Forecast (tons in mm s) 170 Consensus TPH Estimate 120 Jefferies Estimate Rystad Energy Estimate A 2018E 2019P Average Proppant per Horizontal Well (tons in 000s) E 2019P Source: Wall Street Research, Rystad Energy, Spears & Associates PAGE 12

13 Agenda I. Strategic Initiatives Update II. III. IV. Oklahoma Details San Antonio Details Appendix PAGE 13

14 Favorable Location in Mid Continent There are currently 144 rigs drilling in Oklahoma, of which half are located within a 75 mile radius of our site. New plants under construction are further west than our facility. Three legacy regional plants are currently operating in southern OK, but these sites do not have economical trucking beyond 75 miles. In Basin Competitor 1 EMES (1.5mm tpy) 75 mile site radius In Basin Competitor 2 In Basin Competitor 3, 4, 5, 6 Existing Regional Competitor 7 Existing Regional Competitor 8 Existing Regional Competitor 9 Source: Baker Hughes rig count as of 11/2/18 PAGE 14

15 Mid Continent Market Research The Mid-Continent basin is an attractive drilling and growing region due to the stacked layers of oil and gas producing zones. Mid Con Annual Frac Sand Demand (tons in millions) Mid Con demand was 7 million tons in 2017 and is expected to hit 13 million tons by We estimate 70% of the market is fine grades. Customers are still seeking 30/50 and some 20/ Source: PLS Database; Tudor Pickering Holt & Co. Research, Rystad Energy Proppant Intensity Tons per Horizontal Well (Tons in 000s) 16Q1 16Q2 16Q3 16Q4 17Q1 17Q2 17Q3 17Q4 18Q1 18Q2 MidCon Industry Permian Eagle Ford Northeast Bakken MidCon 5.2k tons per well Source: PLS Database PAGE A 2018E 2019P Proppant intensity is much lower in the Mid Con (currently 5.5k tons per well) compared to other leading basins that are 7 10k tons per well. Leading edge operators are continuing to push intensity higher in the basin with longer laterals. The MidCon also currently uses less multi well pad drilling than other basins (lower wells drilled per rig).

16 Agenda I. Strategic Initiatives Update II. III. IV. Oklahoma Details San Antonio Details Appendix PAGE 16

17 San Antonio Plant: Best in Class Business Model Early-mover advantage Take-or-pay contracts in place High quality reserves Large property and deposit In-basin location Minimal overburden All production operations located on site (avoids trucking) Owned reserves (no royalty) High recovery rate of produced to sellable material Dual rail service PAGE 17

18 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 Projecting an average of 9 rigs and 7 completion crews for 2018, 260 net wells completed Estimated resource potential 3.2bn boe over 7,200 net wells 245k acres in Eagle Ford; 3,100 undrilled locations Expect to run 4 5 rigs in the basin during 2018 $30 $40/bbl breakevens; enhanced completions yielding improved well results 285k net acres in Eagle Ford with over 1bn boe of resource potential (15 year inventory) Expect to drill 80 Eagle Ford wells in % of 2018 plan targets Tier 1 locations with IRRs >50% 31% of $2.3bn 2018 capital budget plan directed towards the Eagle Ford Expect to complete Eagle Ford wells in 2018 Successful new high intensity completion designs Source: Company filings and presentations Eagle Ford Frac Sand Demand (mm tons) PAGE A 2018E 2019P Source: Wall Street Research, Rystad Energy

19 San Antonio Plant s Strategic Location Overview Major drilling activity is clustered in South and West Texas Most of the Eagle Ford activity is within miles of the plant for direct to wellhead trucking One of the closest large scale frac sand operations to the Eagle Ford Kosse In Basin Trucking and Railroad Access Ability to truck directly to wellhead, generating attractive margins Average trucking costs from plant to wellhead are $10 to 15/ton 100 Mile Site Radius San Antonio Plant Site is located directly on the Union Pacific mainline Baker Hughes as of 11/2/18 Rail service provides potential cost effective delivery into other basins Access to BNSF mainline through our Elmendorf, TX terminal as an origin (~15 miles of trucking from plant) PAGE 19

20 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 $66 $80 $48 n/a (1) (3) (1) (4) (2) Total Invested Capital $86 $225 $323 $214 (5) Reserves (tons in mm's) Total Invested Capital per Ton of Reserves $1.30 $1.88 $3.07 $5.23 (6) Production Capacity (mm tpy) Total Invested Capital per Ton of Production Capacity $21.38 $56.25 $ $ Source: SEC filings, public call scripts (1) Total disclosed capital outlay ($225mm) less EMES internal estimate on capital cost ($80mm) (2) As per K (3) Midpoint of $60 65mm guidance plus $3mm for current plant (4) Midpoint of $45 50mm guidance (5) Third party engineering study concluded 66mm of SEC proven and probable frac reserves (6) Estimated total plant capacity with new NSR permit PAGE 20

21 Agenda I. Strategic Initiatives Update II. III. IV. Oklahoma Details San Antonio Details Appendix PAGE 21

22 Summary Quarterly Performance $ in thousands, except per ton Continuing Operations: Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Total Tons Sold (tons in 000's) 1,073 1,589 1,503 1,410 1,480 1,392 1, Revenue $ 62,961 $ 101,842 $ 106,750 $ 103,141 $ 103,215 $ 82,602 $ 75,344 $ 42,619 Average Revenue per Ton $ $ $ $ $ $ $ $ % of Sand Sold through Terminals 23% 26% 39% 46% 45% 39% 47% 50% Adjusted EBITDA $ 7,927 $ 23,362 $ 17,386 $ 18,638 $ 18,743 $ 7,534 $ 68 $ (10,543) EBITDA per Ton $ 7.39 $ $ $ $ $ 5.41 $ 0.05 $ (12.76) Net Income $ (3,853) $ 9,428 $ 1,486 $ 5,626 $ 5,482 $ (3,425) $ (11,390) $ (20,669) Discontinued Operations: Volume of Refined Fuel Sold (gallons in million) Revenue $ - $ - $ - $ - $ - $ - $ - $ - Adjusted EBITDA $ - $ - $ - $ - $ - $ - $ - $ (105) Net Income $ - $ - $ - $ - $ (468) $ (2,657) $ - $ (106) Consolidated: Revenue $ 62,961 $ 101,842 $ 106,750 $ 103,141 $ 103,215 $ 82,602 $ 75,344 $ 42,619 Adjusted EBITDA $ 7,927 $ 23,362 $ 17,386 $ 18,638 $ 18,743 $ 7,534 $ 68 $ (10,648) Net Income $ (3,853) $ 9,428 $ 1,486 $ 5,626 $ 5,014 $ (6,082) $ (11,390) $ (20,775) PAGE 22

23 Management and Board of Directors Name Title Years of Professional Experience Senior Management Team Rick Shearer Chief Executive Officer of EMES; CEO of SSS 44 Warren B. Bonham Vice President of EMES 33 Deborah Deibert Chief Financial Officer 30 Nadya Kurani Chief Accounting Officer 14 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 Partner, Insight Equity and CEO, Panolam Surface Systems 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 23

24 MLP Structure Historical Earned Distributions per Unit $1.50 $1.25 $1.00 $0.75 $0.50 $0.25 $0.00 $1.13 $1.17 $1.00 $0.86 (1) $0.70 2Q Q Q Q 2014 Simplified MLP Structure 2Q 2014 $1.38 $1.41 3Q 2014 All units are Common Units Non-economic General Partner 4Q 2014 $1.00 1Q 2015 $0.67 2Q Q Q Q Q Q Q Q Q Q Q 2017 No Incentive Distribution Rights (IDRs) No Minimum Quarterly Distributions (MQD) Our Sponsor, Insight Equity, which owns approximately 23% 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 1Q Q Q 2018 ( 1) Full quarter results based on pro rated distribution of $ PAGE 24

25 From Mine to Railcar 1) Extract 2) Wash 3) Dry 4) Ship PAGE 25

26 Asset Summary Wet Plant Location Proven Recoverable Reserves (1) Plant Capacity (Thousands of Tons) 2017 Wet Production (Thousands of Tons) New Auburn, WI 16.4 mm tons 2,000 1,276 Thompson Hills, WI 38.2 mm tons 1,600 1,394 FLS (Wisconsin) 7.9 mm tons 1,400 1,496 LP Mine (Wisconsin) 3.8 mm tons 1,200 1,163 Church Road (Wisconsin) 4.4 mm tons 1, Kosse, TX 26.8 mm tons 1, San Antonio, TX (2) 47.6 mm tons 4, Kingfisher, Oklahoma (3) See Note 3 2,000 - Total mm tons 15,500 6,651 Dry Plant Location On-site Railcar Storage Capacity Plant Capacity (Thousands of Tons) 2017 Dry Production (Thousands of Tons) New Auburn, WI 420 cars 1,400 1,272 Barron, WI 650 cars 2,400 2,081 Arland, WI (4) N/A 2,500 1,800 Kosse, TX N/A San Antonio, TX (5) 10 cars 4, Kingfisher, OK N/A 1,500 - Total 1,080 cars 12,400 5,434 (1) Reserves are estimated as of December 31, 2017, 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. (2) The San Antonio facility also has 18.6 million tons of probable frac sand reserves. The new wet plant is currently under construction with an estimated start up in Sept (3) Oklahoma reserves are estimated at 20 million tons, according to internal analysis; a third-party engineering group will conduct an independent reserves analysis (4) We load sand from Arland onto rail at Barron, New Auburn, and at a third rail loadout near St. Paul, Minnesota. (5) Assumes 4mm tpy San Antonio capacity with new NSR permit expected late-august PAGE 26

27 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 Source: Association of American Railroads & U.S. Geological Survey. Railroad Network BNSF CN/GTW CP/SOO CSX /NS KCS/KSCSM UP FWWR / Texas Pacifico Shortline Basin Highest Quality Sand Mine Locations SSS Transload Sites Corporate HQ PAGE 27

28 Consolidated Net Income to Adjusted EBITDA Reconciliation $ in thousands Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Net income $ (3,853) $ 9,428 $ 1,486 $ 5,626 $ 5,014 $ (6,082) $ (11,390) $ (20,775) Depreciation, depletion and amortization 5,316 5,355 4,861 5,490 6,078 5,675 4,656 4,662 Provision for income taxes (58) - - (220) Interest expense, net 6,907 6,736 10,492 5,818 5,073 5,082 3,198 3,448 Non-capitalized expenses from equity issuance Changes in fair value of stock warrants (gain) (1,467) 245 (677) (996) (900) (3,008) 696 (885) Equity-based compensation expense Write-down of sand inventory Provision for doubtful accounts Write-off of assets & contract terminations - - 1, Cost to retire an asset (6) 350 Accretion Reduction in force Fuel segment selling expenses Other state and local taxes Non-cash deferred lease expense (208) 355 (2,576) 1,582 2,223 2,329 1,901 2,079 Gain on sale of fuel segment Reduction in escrow receivable , Other adjustments under Credit Agreement - - 1, Adjusted EBITDA $ 7,927 $ 23,362 $ 17,386 $ 18,638 $ 18,743 $ 7,534 $ 68 $ (10,648) PAGE 28

29 Consolidated Adjusted EBITDA to Operating Cash Flow Reconciliation $ in thousands Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Adjusted EBITDA $ 7,927 $ 23,362 $ 17,386 $ 18,638 $ 18,743 $ 7,534 $ 68 $ (10,648) Interest expense, net (5,852) (5,722) (5,964) (4,669) (4,169) (3,975) (2,684) (3,001) Non-Cash Income Tax Expense (429) (447) (493) (668) (419) (456) (424) (170) Contract and project term (3) Reduction in force Change in other operating assets and liabilities 10,453 8,520 (1,612) 65 (18,646) 4,973 (7,785) (3,589) Write-down of sand inventory Cost to retire assets (19) Fuel division selling expenses Non-cash deferred lease expense 208 (355) 2,576 (1,582) (2,223) (2,329) (1,901) (2,079) Other adjustments under Credit Agreement - - (1,149) (213) (1) Operating Cash Flow $ 12,288 $ 25,358 $ 10,744 $ 11,784 $ (6,714) $ 5,766 $ (12,939) $ (19,491) PAGE 29

30 2018 Guidance: Net Income to Consolidated Adjusted EBITDA ($ in millions) Low End 2018 High End 2018 Net income $ (4.5) $ 10.0 Interest expense, net Depreciation, depletion, and amortization Provision for income taxes EBITDA Equity based compensation expense Contract and project termination Other state and local taxes Non cash deferred lease expense (3.1) (3.1) Other adjustments allowable under our credit agreement Adjusted EBITDA $ 50.0 $ PAGE 30