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Edited Transcript of EMES earnings conference call or presentation 6-Nov-18 9:00pm GMT

Q3 2018 Emerge Energy Services LP Earnings Call

Southlake Dec 3, 2018 (Thomson StreetEvents) -- Edited Transcript of Emerge Energy Services LP earnings conference call or presentation Tuesday, November 6, 2018 at 9:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Deborah Deibert

Emerge Energy Services LP - CFO of Emerge Energy Services GP LLC

* Richard J. Shearer

Emerge Energy Services LP - CEO, President & Director of Emerge Energy Services GP LLC

* Theodore William Beneski

Emerge Energy Services LP - Chairman of Emerge Energy Services GP LLC

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Conference Call Participants

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* Christopher F. Voie

Wells Fargo Securities, LLC, Research Division - Associate Analyst

* John H. Watson

Simmons & Company International, Research Division - VP & Senior Research Analyst of Oil Service

* Lucas Nathaniel Pipes

B. Riley FBR, Inc., Research Division - Senior VP & Equity Analyst

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Presentation

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Operator [1]

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Good afternoon, ladies and gentlemen, and welcome to the Q3 2018 Emerge Energy Services Earnings Conference Call. (Operator Instructions) As a reminder, this conference is being recorded.

I would now like to turn the call over to your host, Ms. Deb Deibert, Chief Financial Officer. Please go ahead.

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Deborah Deibert, Emerge Energy Services LP - CFO of Emerge Energy Services GP LLC [2]

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Thank you, operator. I'd like to welcome everyone to the Emerge Energy Services L.P. Third Quarter 2018 Conference Call. Just a quick note before we start, our discussion today may contain forward-looking statements. These statements may include, but are not limited to, our estimates of future volumes, operating expenses and capital expenditures. They may also include statements concerning anticipated cash flow, liquidity, business strategy, distributions and other plans and objectives for future capital expenditures and operations. These statements are based on management's beliefs and assumptions. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can provide no assurance that such expectations will prove to be correct. These statements are subject to certain risks and uncertainties. If one or more of these risks materialize or should the underlying assumptions prove incorrect, our actual results may vary materially from those expected. These risks are discussed in greater detail in our Annual Report 10-K on file with the Securities and Exchange Commission. Please also note that on this call, we may use the terms adjusted EBITDA and distributable cash flow. These are non-GAAP financial measures, and we have provided reconciliations to the most directly comparable GAAP measures in our earnings release published this morning for historical results. Please see our website for a reconciliation of our forecasted adjusted EBITDA to comparable GAAP measures. Also, we have posted a new investor presentation under the Investor Relations portion of our website.

And now I would like to turn the call over to our Chairman, Ted Beneski.

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Theodore William Beneski, Emerge Energy Services LP - Chairman of Emerge Energy Services GP LLC [3]

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Good afternoon, and thank you all for joining us to review the third quarter of 2018. As noted in our earnings announcement released this morning, we experienced disappointing results in the third quarter, driven by the short-term challenging market conditions and a delay in ramping up our new San Antonio operation. The downbeat industry completion trends to finish the year have been well documented in terms of budget exhaustion and pipeline constraints. Like several public energy companies who have already reported, our customers are slowing down activity to finish the year. So we are working through what we see as a temporary demand hiccup before completion activity improves in early 2019.

Our San Antonio project continues to progress but we did encounter extreme rainfall in South Texas during September and October, which caused construction delays for our new dry and wet plant. Several of our peers in South Texas and West Texas have cited similar construction interruptions due to unpredictable weather, labor shortages and contractor overruns. But we're working hard to overcome these issues and ramp up the San Antonio plant to full capacity in the fourth quarter of this year.

Despite the third quarter headwinds, we did achieve several accomplishments during the quarter: First, we received our new NSR air permit for the San Antonio plant at the end of August. Our team worked diligently with our consultants and the regulatory agencies to expedite the permitting process in what is now a very busy regulatory environment. We initially expected to obtain the permit by the end of the year, so we're pleased to be ahead of the original schedule. The project is also tracking to be under the original $65 million budget.

Second, we broke ground on our new in-basin plant in Kingfisher, Oklahoma, at the end of September, and we are anticipating dry sand production there in January. We continue to believe that this location holds significant competitive advantages compared to several sites 40 to 50 miles to the west because Kingfisher County is one of the leading areas in the mid-continent region. The combination of our new San Antonio and Oklahoma sites significantly lessens our dependency on Northern White. We will be 50-50 in terms of production capacity for in-basin in Northern White, but we will likely be much greater than 50% in basin for volumes sold next year due to the strong demand for our in-basin product.

Third, our customers are sending upbeat signals about activity in 2019, when budgets will be reloaded and Permian pipeline constraints should be resolved. Our customers are regularly communicating to us that activity in all basins, not just West Texas, will return to growth mode next year.

Fourth, we are working with our customers to settle take-or-pay volume shortfalls for 2018, given the market slowdown. We are in the middle of intense negotiations with our key contracted customers, and we expect a meaningful recovery on the shortfall provisions of our Northern White take-or-pay contracts.

Fifth and finally, we are responding to the transitory market issues by reducing costs across all areas of the company. Our team is working hard to optimize our existing Northern White footprint while preserving our market position for when Northern White rebounds next year.

Due to the short-term market weakness and our delayed in-basin production, we are lowering our full year 2018 adjusted EBITDA guidance to a range of $50 million to $65 million. Achieving our -- or exceeding the upper end of our guidance primarily depends on the outcome from our take-or-pay contract shortfalls settlement discussions with our Northern White customers.

And now, I will turn it over to Rick to review the quarter in more detail.

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Richard J. Shearer, Emerge Energy Services LP - CEO, President & Director of Emerge Energy Services GP LLC [4]

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Thanks, Ted. Our total volumes sold in the third quarter declined by 32% sequentially to 1.1 million tons, as higher volumes from San Antonio were offset by a decline in Northern White demand. Our adjusted EBITDA decreased by $15.4 million sequentially to $7.9 million for the third quarter and net income declined to negative $3.9 million compared to a positive $9.4 million in the second quarter. Lower volumes, falling Northern White prices and idle railcar and other logistics costs contributed to lower profitability in the quarter. Not only has West Texas activity faded to finish the year, but other key markets for us, such as the Bakken, Western Canada and the Rockies have also experienced a pullback.

After we achieved record volumes in May, the market flipped in August, as customers have roughly altered their completion activity plans for the rest of the third quarter. This coincided with a number of new in-basin Permian frac sand plants reaching full capacity, thereby amplifying the demand hit to Northern White and pressuring prices. Our average selling prices for Northern White fell by 8% in the third quarter, and we are expecting another 25% decline in Northern White average prices for the fourth quarter based on current leading-edge prices.

To respond to the sudden change in Northern White market conditions, we are reducing costs and idling over 50% of our Northern White capacity or approximately 3 million tons per year. We've scaled back a number of our dry plant shifts from 12 during the peak this summer to 5 currently. Our dry plants will operate on a batch basis, depending on which rail line the order needs to originate.

Since our Wisconsin operations are all located within a 20-mile radius, our crews can respond quickly and rotate around our 3 dry plants. As of now, Arland will be shut in until order patterns improve. We're also working with all parts of the Northern White supply chain to share in this lower demand environment. We have secured price reductions from our Wisconsin base sand trucking companies. We're working with the railroads on lower rates in the key basins as well. Our railcar lessors and mining contractors are also feeling the pressure from us for assistance during this time of transition as we are in the middle of negotiations for contract relief.

Despite the current oversupply of Northern White, we have several reasons to be optimistic for an improvement in the Northern White market conditions for 2019.

First, our customer base continues to reassure us the completion activity will improve next year with new budgets and new midstream infrastructure online. While the Permian is getting most of the attention on the market slowdown, other key basins around North America are also experiencing a softening. The New Year should bring a return to growth not just in the Permian, but in other basins where in-basin sand is not available. The growing drilled but uncompleted well count also provides a strong backlog and visibility for the industry.

Second, E&Ps are now devoting more attention to researching long-term well performance from using lower-quality sand. We're directly seeing more data points from large E&Ps, but they still need some Northern White for long-term well performance even in basins with local sand available. We're working with a few customers on bundling in-basin sand with Northern White for next year, and a large E&P has put out an RFP to the marketplace for sizable amount of Northern White sand to be used in the Permian basin starting mid-2019. This also plays into the trend of targeting E&Ps on direct-sourcing sand. We're experiencing an increasing level of interest from E&Ps to buy directly from us, whether the product demanded is Northern White or in-basin sand.

Third, sand suppliers are rationalizing Northern capacity quickly in light of the lower demand. We have heard reports that over 15 million tons of Northern capacity have been idled, including our 3 million tons noted.

We expect more Northern White capacity to come off-line in the coming months, especially the Tier 2 producers that are beholden to one rail line, have higher production costs and sell to a limited customer base. We also foresee numerous regional mines in Texas and Oklahoma getting pushed out by lower-cost in-basin mines that have similar-quality sand but are 100 to 200 miles closer to the wellhead.

Fourth, our team is responding to the changing Northern White market by refocusing our efforts on our core markets consisting of Western Canada, the Bakken and the Rockies. We built a leading position in these markets over the past several years because we are a low-cost logistics provider into these Northern and Western regions. Our rail capabilities allow us to supply these growing markets on 3 different Class I rail lines, and our customer relationships date back many years whereas some Northern White players are just now trying to break into this customer base.

Our relationships are proving to be a differentiator in the current environment, and we expect to grow our market position in these basins with new customers.

We're developing new business opportunities with both E&Ps and pressure pumpers, thanks to the hard work from our recently enhanced sales force and logistics team.

In Utah, we opened a new transload site to prepare for the Uintah basin growth, and we're shipping 2 unit trains in November there. Also, our Buick British Columbia terminal is poised to capture growth opportunities after the Kitimat LNG project was approved last month.

Overall, for 2019, we expect to hold serve on our Northern White market share of 8% to 10%, with potential to exceed that estimate by locking down new customers.

Before I move on from the Northern White topic, I would like to address our take-or-pay contracts that we signed during the last market upswing in late 2016 and early 2017. These contracts are proving critical as the market evolves. We put these contracts in place to provide downside assistance, and we're enforcing the volume shortfall penalties that several of our customers are approaching for 2018. We're in the middle of lengthy negotiations and are not able to comment in detail, but a positive outcome from these discussions could substantially boost our fourth quarter performance. In some negotiations, we are looking at a settlement for both 2018 and 2019 contract year projected shortfalls so that we can accelerate the cash recovery. These payments will help cover the fixed railcar lease costs and other terminal commitments to support our Northern White distribution network. In fact, the market shifted so quickly that we currently have 1,547 railcars in storage. We expect to hold around this level until the market improves at the beginning of next year, and we have about 600 cars coming off lease in the next 12 months.

We're also working with one of our largest railcar lessors on terminating a large block of railcars that were placed on order before the market downturn in 2015. We're expecting resolution on these important customer and railcar negotiations by the end of this year.

Now turning to our in-basin operations. Our frac sand production at San Antonio more than doubled in the third quarter compared to Q2, but the torrential rainfall and our overstretched contractor contributed to construction delays. These 2 issues are also creating problems for our competitors who are building in-basin plants in Texas, so we're not alone in facing prolonged construction timelines. With that said, we're working through these hurdles as a team and can see a path to full utilization at our new wet and dry plants by the end of November.

As Ted mentioned in his remarks, we're ahead of our original schedule of obtaining the NSR permit because we originally anticipated to have this permit by year-end, but we worked diligently with the regulatory agencies to receive this in August. We're also proud of staying under the original budget of $65 million as we're finishing up the capital spending this year and expect to finish the project for under the budgeted amount. Including the price of the owned sand reserves, our industry-leading site will be completed for around $85 million, which is a fraction of what some of our competitors have paid for comparable in-basin sites, often over $200 million to $300 million.

As the new plant ramps up to the full targeted capacity of 4 million tons per year, we expect to significantly reduce our production costs in the coming months. We now have permanent natural gas supplied and installed in the plant, and we're in the process of connecting to grid power. Running our new wet plant at full utilization will phase out purchasing expensive wet sand feed that we're sourcing from third parties currently. Furthermore, the high levels of recent rainfall have added significant moisture content to our wet sand stockpiles, requiring more natural gas to dry the sand. The dryer forecasted weather in Q4 should reduce the amount of gas per ton of sand to a more normalized level. All of these factors should drive an anticipated $10 to $15 per ton decrease in our overall San Antonio production costs.

Demand for our San Antonio product remains very strong, and we now have over 63% of the plant's capacity contracted, largely with blue-chip E&Ps and pressure pumpers. We're finalizing several other agreements, and we expect to be over 80% contracted by the end of this year. Several of our customers who have compared our plant to our peers' sites in the area have told us that our operation is the best in South Texas, given our central relocation, direct 4-lane highway access and multiple truckload outlanes. We concur with this assessment and believe that these reasons will keep our leading plant at a high contracted percentage despite new competition.

Not only does the San Antonio plant give us confidence about a strong 2019, but our Oklahoma operation is also generating positive momentum for us heading into next year. At the end of September, we broke ground on our new plant in Kingfisher County. We submitted our mining permit to the state, and the public comment period recently expired without any complaints. So we expect the state to officially issue our permit in the coming weeks.

Our targeted date to finish the dry plant construction is early January, while the wet plant will be in the spring, if we receive the permit quickly. We will fill the gap by bringing in third-party sands similar to what we've done in San Antonio. Our capital budget for Oklahoma has been upsized slightly to a range of $15 million to $20 million to allow for additional truck load-out features that customers highly value.

Our micro-targeting strategy for the midcontinent basin is playing out nicely because potential new customers in Kingfisher County are interested in signing with us over the competing sand plants that are 40 to 50 miles to the west in Dewey County. We're lining up E&P and pressure-pumping customers with an ultimate target of 80% of the plant's 1.5 million tons of annual capacity under contract. Our sales team has been regularly meeting with our potential new customers. We expect to have more than 50% contracted by the end of this year. Demand remains strong and margins still attractive, given the $8 to $10 a ton trucking advantage we have over sand plants to the west.

The final topic I want to cover is our last-mile strategy. We're not committing capital to this area because we have experienced the fixed cost overhang from railcars, so we want to avoid a repeat of underutilized assets. However, we are working with various trucking firms and silo and box providers to bid on projects and manage the sand all the way to the wellhead. Stevens Trucking is a great example of how we're using third parties to add a last-mile feature to our business. We have a strong relationship with Stevens through our San Antonio operation, and we're in the process of formalizing a closer arrangement to jointly address this market. We continue to be a free agent in terms of providing silos, boxes or another new type of sand container because the technology is still evolving and the customer values options.

In closing for my section, we acknowledge we have recently experienced setbacks, but we are overcoming them with our resiliency. We know there will be cycles in this industry, so we're staying focused on repositioning the company for long-term success. Our hard work right now is setting the table for an exciting and promising 2019. Upon completion of our San Antonio and Oklahoma sites, will be a leading producer of both in-basin and Northern White sand. Because of this diversified capability, we will be able to meet the market's constantly changing needs for frac sand.

And now let me turn it over to Deb.

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Deborah Deibert, Emerge Energy Services LP - CFO of Emerge Energy Services GP LLC [5]

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Thanks, Rick. Emerge Energy reported a net loss of $3.9 million, or negative $0.12 per diluted unit for the third quarter of 2018. This represents a decline from $9.4 million or $0.30 per diluted unit in the second quarter of this year driven by the lower volume sold, lower Northern White prices and unabsorbed fixed costs for our idled railcars in storage.

SG&A declined by $3.6 million sequentially due to lower employee-related costs, particularly for reduced incentive compensation. Interest expense totaled $6.9 million in the third quarter, which was relatively flat compared to $6.7 million in the second quarter. Other income of $1.5 million represented a mark-to-market gain on the fair value of warrants outstanding.

Net revenues were $63 million for the 3 months ended September 30, 2018, compared to $103.2 million for the 3 months ended September 30, 2017, and $101.8 million for the 3 months ended June 30, 2018.

Net revenues decreased due to lower Northern White volumes sold, as shift in mix away from higher-priced terminal sales and a decline in Northern White prices offset by higher in-basin production. Volume sold for our terminals totaled only 23% of the volume in the third quarter of 2018, compared to 45% in the third quarter of 2017, and 26% in the second quarter of 2018.

We generated $1.7 million of this distributable cash flow in the third quarter compared to $17.3 million in the second quarter of 2018, but our Board of Directors of our general partner have elected to not make a distribution for the quarter, and we are restricted into our new credit agreements from paying distributions this year.

Our capital expenditures for the third quarter totaled $8.3 million, substantially all of which was growth CapEx directed towards the new San Antonio and Oklahoma plants.

Our full year 2018 capital expenditures estimate remains in the range of $80 million to $90 million. We're working with our contractors on potential credits to the San Antonio project given the delays.

Turning to the balance sheet, we had no outstanding borrowings at third quarter end on our $75 million revolving credit facility, and our second lien notes had principal outstanding of $215 million. We had $2.8 million of cash and $61.5 million of availability under our revolver. At the end of the third quarter, we were in compliance with our total leverage, minimum liquidity and fixed charge coverage ratio covenant. But as usual, we remain in constant communication with our lenders regarding future liquidity and covenant compliance.

Our operating cash flows were positive $12 million in the third quarter, as our total net working capital decreased, primarily driven by lower accounts receivable balance from the reduced revenues.

Looking at the fourth quarter, we're seeing continued market weakness on the Northern White side in terms of volumes and pricing. Rick mentioned an expectation for Northern White project to decline by 25% in Q4 on average compared to Q3. Our volumes and profitability in the fourth quarter should benefit in the San Antonio plant ramping up to full capacity. Overall for the fourth quarter, we expect volumes to be flat to up 10%. Rick also noted our actions around settling the take-or-pay volume shortfalls. These collections will be important contributions to our bottom line in the fourth quarter.

Finally, our new full-year 2018 adjusted EBITDA guidance is a range of $50 million to $65 million.

Operator, we are now ready to open the call for questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question comes from the line of John Watson from Simmons Energy.

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John H. Watson, Simmons & Company International, Research Division - VP & Senior Research Analyst of Oil Service [2]

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Correct me if I'm mistaken here, but looking at the guidance for Q4, is there anything we should keep in mind with regard to the leverage ratio covenant for the quarter? And can you talk about how that might potentially impact your plans to continue the expansion at San Antonio and also build out Oklahoma?

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Deborah Deibert, Emerge Energy Services LP - CFO of Emerge Energy Services GP LLC [3]

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John, this is Deb. We are working with all of our creditors, our lenders, and looking forward to the [pitch] on our covenants that we do foresee. Right now, all the conversations are going quite well, and we do not foresee any kind of danger to the ongoing construction for San Antonio completion or the Oklahoma completion. And we have much faith that we will have some very positive resolutions before year-end.

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John H. Watson, Simmons & Company International, Research Division - VP & Senior Research Analyst of Oil Service [4]

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Okay. Great. That's helpful. And Rick, I think you made the comment that pricing was down roughly 8% in Q3, and correct me if I misheard that. Can you talk us through the different puts and takes other than price that led to the gross profit per ton falling quarter-over-quarter? It sounds like there was some added cost as well.

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Richard J. Shearer, Emerge Energy Services LP - CEO, President & Director of Emerge Energy Services GP LLC [5]

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Well, John, I think, yes, we've seen, as expected, with the transition as we call it, moving some of the Northern White into other basins and moving it into a reduced market because of the overall in-basin sand, a much more competitive environment. On the cost side, what this means is, we've got to be and we are very focused on driving more and more costs out because of the compression in the margins that the entire industry is seeing on Northern White, at least at the moment. One of the issues that really drove a lot of what we're doing is San Antonio. As we mentioned, we made a deliberate plan going forward to take a -- make a move to address our customers' needs sooner rather than later by actually producing shipping sand while the plant was still under construction. The downside of that, which we understood going in, was that the cost would be much higher than normal because, in fact, we were buying sand, damp feed, I'll call it, to dry and process from third-party sources. That came at an expense, and we knew that going in. So our costs were escalated beyond what they certainly normally will be. The other issue we touched on in the script is the weather. When you're trying to dry sand that is sloppy wet in many cases to meet the customer demand and to supply them as needed, that, of course, raises our dryer costs significantly, and it hurts the throughput of the plant. So we really feel like the San Antonio plant has a tremendous amount of upside as we go forward. The other thing on the cost side is with the reduction in the tonnage and the throughput in the plants, of course, on a per ton basis, our costs escalated some there as well.

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John H. Watson, Simmons & Company International, Research Division - VP & Senior Research Analyst of Oil Service [6]

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Okay. Makes sense. Do you think we'll see some of those costs for the Northern White facilities bleed into Q4, some of the idling costs you mentioned?

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Richard J. Shearer, Emerge Energy Services LP - CEO, President & Director of Emerge Energy Services GP LLC [7]

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On the Northern White side, we'll continue to have some elevated costs. I don't see them going up from what we saw in Q3. But only because of the reduced tonnage, at least during this interim period, those per-ton costs will remain higher than expected.

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Operator [8]

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(Operator Instructions) Our next question comes from the line of Chris Voie from Wells Fargo.

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Christopher F. Voie, Wells Fargo Securities, LLC, Research Division - Associate Analyst [9]

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Just a question on the guidance. So it sounds like, to some extent, the high end of the range of the guidance is predicated on positive developments in terms of settling the take-or-pay agreements. To what extent, does that apply to settling 3Q obligations versus 4Q? Can you give us some context on that? And would it be correct to assume that the low end, which would translate to maybe very minimal EBITDA in 4Q would be the underlying level of activity implied in 4Q absent extra payments? Just to think about how those payments accrue to your operating results.

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Richard J. Shearer, Emerge Energy Services LP - CEO, President & Director of Emerge Energy Services GP LLC [10]

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Chris, I think there's a couple of factors here. You're right about that as far as the contract negotiations around take-or-pay. That's going to be a driving factor whether we finish at the high-end of the guidance or not. We're optimistic, and we're well into those discussions. The other factor though that plays heavily into Q4 is the ramp-up of San Antonio. And as we mentioned, the plant is continuing to show improvement. We're continuing to produce and load out more tons each week, and we're going to keep pushing that once we finish the wet plant next week and begin to build some inventory of our own damp feed. Those costs will come down significantly, as we noted earlier. And the volume is certainly there. We've got customers queued up to take the sand as we can make it and as we ramp this plant up. So those 2 factors, San Antonio and the take-or-pay contract negotiations, will be the driving force and where we finish based on our guidance.

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Christopher F. Voie, Wells Fargo Securities, LLC, Research Division - Associate Analyst [11]

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Okay. So given the fact that Northern White might be -- or maybe, first, a question on that. Can you give, in discrete terms, the costs -- the excess costs that you're carrying in terms of rail for Northern White?

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Richard J. Shearer, Emerge Energy Services LP - CEO, President & Director of Emerge Energy Services GP LLC [12]

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Deb, do you have some comment on that?

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Deborah Deibert, Emerge Energy Services LP - CFO of Emerge Energy Services GP LLC [13]

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About $400,000 to $500,000 -- oh, sorry, it's over $0.25 million just on the storage on the railcars, so $4 million to $5 million a quarter on that overhead.

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Christopher F. Voie, Wells Fargo Securities, LLC, Research Division - Associate Analyst [14]

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Okay. And then just based on the guidance, it sounds like the Northern White contribution to your business is going to be pretty limited at least in 4Q. Can you give any sense – since San Antonio is such a critical part going forward and it sounds like much more profitable, can you give a sense of like the margin per ton that you had in the last quarter for San Antonio? And what you expect in 4Q or the extent of the tailwind, given the cost improvement compared to 3Q? It's going to be a very critical driver in 4Q. So just... some sense on the contribution margin generation potential from that plant in 4Q?

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Richard J. Shearer, Emerge Energy Services LP - CEO, President & Director of Emerge Energy Services GP LLC [15]

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I don't know that we can get into specifics on that necessarily. But as we noted in the script, we expect to $10 to $15 improvement certainly on the cost side.

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Operator [16]

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(Operator Instructions) Our next question comes from the line of Lucas Pipes from B. Riley FBR.

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Lucas Nathaniel Pipes, B. Riley FBR, Inc., Research Division - Senior VP & Equity Analyst [17]

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So we've now seen a few announcements in regards to reduced operating rates in Northern White. And I wanted to ask at what point would you expect maybe more permanent closures in the basin? I would appreciate your thoughts.

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Richard J. Shearer, Emerge Energy Services LP - CEO, President & Director of Emerge Energy Services GP LLC [18]

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Lucas, I think we're going to take the attitude of letting the market and the demand and the success that we have as we look to place Northern White into these other basins dictate that. Right now, we're sitting here at a pretty constant level of Northern White demand. We don't see it eroding at all from where we are right now. It's a question of how much and when the uptick will happen in the Northern White. And we've got a number of new contracts in negotiation right now. So we have optimism that at some point, we expect in the first quarter, we will start to see an improvement in the Northern White demand. But right now, it's not eroding any further. We've hit a stabilized level. And given the tons that we have on the table right now that we expect to remain in place for at least the next couple months, we're comfortable that we've taken a lot of cost out, shutting down -- shutting in, I'll say more correctly, the Arland plant. We have reduced -- 31 positions now have been reduced within the company, both in Wisconsin and our headquarters in Fort Worth. We've just reduced 43 additional seasonal positions by shutting down the mines for the season in Wisconsin. So we've taken the necessary steps to feel like the adjustments have been made for the tonnage that's in place right now. As I say, I'll repeat it, we don't see that number coming down from where we are. We think it will only improve. It's just a question of the timing of when we actually see that happen, and then we'll make adjustments accordingly to, again, meet those tons.

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Lucas Nathaniel Pipes, B. Riley FBR, Inc., Research Division - Senior VP & Equity Analyst [19]

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I appreciate that. And maybe just to circle back on your level of confidence for improving demand for Northern White down the road with potentially more in basin supply coming from places like Oklahoma, but also within maybe still some additions within the Permian. To what extent does that maybe reduce -- come back in Northern White in 2019?

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Richard J. Shearer, Emerge Energy Services LP - CEO, President & Director of Emerge Energy Services GP LLC [20]

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Lucas, I think our confidence level remains that Northern White will continue to be 35% to 40% long term of the total market demand. If anything, that might be low given the fact that we are seeing data points now as we mentioned in the script, of a number of E&Ps in particular coming back to us saying that they expect that they're going to need Northern White when maybe early on they said they didn't. But the well results are starting to show that Northern White does need to be in their formulation. So we're seeing some data points that say, even where there is local in-basin sand, Northern White looks like it will continue to play a role. That's not to mention the areas like we've suggested: the Bakken, the Rockies, Utah, Western Canada where we have a strong position, and we're building on that already. So our confidence remains high that there is a place in this market for Northern White. We've heard some say at frac sand conferences and elsewhere that Northern White is dead. That is absolutely not the case. I think we're proving that as we continue to build on our position. This is a timing thing. We're repositioning where we place our Northern White. We're confident and we're going to do that. It's just a question of when we put it to the bottom line.

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Lucas Nathaniel Pipes, B. Riley FBR, Inc., Research Division - Senior VP & Equity Analyst [21]

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That's very helpful. Maybe one more to sneak in. And it goes back to Northern White one more time. What's your sense of the steepness of the cost curve in Northern White? Could you maybe comment on like what makes for a higher cost mine? What makes for a lower cost mine? What's roughly the difference on a dollar-per-ton basis and where does that difference come from? Is it mining cost transportation and such? I would really appreciate your perspective on that.

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Richard J. Shearer, Emerge Energy Services LP - CEO, President & Director of Emerge Energy Services GP LLC [22]

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I think transportation, Lucas, is a real driver. I mean, there are some things that we've done to reduce costs in Wisconsin. We're continuing to work to reduce our costs. We've historically talked about that with hydro mining and some other interesting techniques. We put some equipment in recently that's going to allow us to produce more finer grade sand next spring and process less coarse sand out of the Wisconsin mine. So that's certainly going to help our COGS number. But a big issue around this is logistics, the hauling and the transporting of the sand and the distance that we deal with versus our competitors becomes very key as a driver on the cost side.

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Lucas Nathaniel Pipes, B. Riley FBR, Inc., Research Division - Senior VP & Equity Analyst [23]

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And when you refer to the distance, is that getting it kind of from the mine gate to the rail load-out? Is that what you're referring to? Or is it more generically that rail rate itself?

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Richard J. Shearer, Emerge Energy Services LP - CEO, President & Director of Emerge Energy Services GP LLC [24]

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From -- in many cases, including ours from the mine to the dry plant and the load-out at the dry plant, yes.

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Operator [25]

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And our next question comes from the line of Chris Voie from Wells Fargo.

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Christopher F. Voie, Wells Fargo Securities, LLC, Research Division - Associate Analyst [26]

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Just wanted to sneak a couple more in. Just curious on the SG&A, it came in pretty significantly lower in the quarter, and I know you made some personnel costs and shut a mine. But is that a sustainable level for 4Q in next year or should we assume any kind of bounce back in SG&A?

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Deborah Deibert, Emerge Energy Services LP - CFO of Emerge Energy Services GP LLC [27]

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Yes, that is not a sustainable level. We had a significant decrease because we wrote off a lot of our incentive compensation accruals. So that will not be a trend in the future.

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Christopher F. Voie, Wells Fargo Securities, LLC, Research Division - Associate Analyst [28]

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Can you give a sense of where it might shake out for 4Q or next year?

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Deborah Deibert, Emerge Energy Services LP - CFO of Emerge Energy Services GP LLC [29]

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I would say it would be closer to what we did in Q2. It will be lower than what we did in Q2 on an ongoing basis.

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Richard J. Shearer, Emerge Energy Services LP - CEO, President & Director of Emerge Energy Services GP LLC [30]

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And she is really talking about 2019. Q4 is going to continue to be low because the incentive comp is through the end of the calendar year.

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Deborah Deibert, Emerge Energy Services LP - CFO of Emerge Energy Services GP LLC [31]

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Yes, but we don't have that write-off of the prior accruals in Q4. So it will still be low, but not nearly what we saw in Q3.

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Christopher F. Voie, Wells Fargo Securities, LLC, Research Division - Associate Analyst [32]

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Okay. And then on Kingfisher, I'm wondering if you can give -- obviously, there's some time for things to shake out, but what kind of cadence you expect in terms of capacity in 1Q and 2Q next year? It sounds like you're going to start production in January, but they tend to start pretty slowly. So just curious if you have any sense on the capacity early next year.

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Richard J. Shearer, Emerge Energy Services LP - CEO, President & Director of Emerge Energy Services GP LLC [33]

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We certainly expect the ramp-up to go more smoothly than San Antonio, given the issues that we discussed in the script, the weather, the contractor stress points and so forth. So we're moving ahead very much on schedule, if not a little ahead of schedule. In Oklahoma, that project is going very nicely, typical of what we're used to seeing with our operations. The ramp-up, again, we're in the process of hiring. We've got a plant manager. We've got some key managers already in place. So we expect that, that will happen smoothly. It's a -- depending on the product mix, it will be 1 million, probably 1.2 million to 1.5 million tons a year. And we expect to have it ramped up to that run rate certainly within 60 days or less of when we open the plant up for production.

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Operator [34]

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I'm showing no further questions at this time. I'd now like to turn the conference back to Board Chairman, Ted Beneski.

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Theodore William Beneski, Emerge Energy Services LP - Chairman of Emerge Energy Services GP LLC [35]

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Okay, thank you. In closing, we just want to thank all of you for participating on the call today. Although this transitioning market has presented difficulties for us, we are confident that our hard work will pay off next year. And we're encouraged by our customers' outlook for an upbeat 2019. And we will continue to work diligently on improving our business. We look forward to speaking with you again next quarter.

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Operator [36]

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Ladies and gentlemen, this concludes today's conference. Thank you for your participation, and have a wonderful day. You may now disconnect.