USD Partners LP
Q4 2016 Earnings Call Transcript

Published: 9 Mar 2017

[Operator:]

Ladies and gentlemen, thank you for standing by. And welcome to the USD Partners LP fourth quarter 2016 results conference call. At this time all participants have been placed on a listen-only mode. The poll will be open for you questions following the prepared remarks [Operator Instructions]. It is now my pleasure to turn the call over to Ashley Means, Director of Finance and Investor Relations, for opening remarks. Please go ahead.

[Ashley Means:]

Good morning. And thank you for, joining us. Welcome to our fourth quarter 2016 earnings call. With me today are Dan Borgen, our Chief Executive Officer; Adam Altsuler, our Chief Financial Officer; Brad Sanders, our Chief Commercial Officer, as well as several other members of our senior management team. Yesterday evening, we issued a press release announcing results for the three and 12-months ended December 31, 2016. If you would like a copy of the press release, you can find one on our Web site at usdpartners.com. Before Dan and Adam proceed with the prepared remarks, please note that the Safe Harbor disclosure statements regarding forward-looking statements in last night's press release applies to the statements of management on this call. Also, please note that information presented on today's call speaks only as of today, March 9, 2017. Any time-sensitive information provided may no longer be accurate at the time of any webcast replay or reading of the transcript. Finally, today's call will include discussion of non-GAAP financial measures. Please see last night's press release for reconciliations to the most comparable GAAP measures. And with that, I'll turn the call over to Dan.

[Dan Borgen:]

Thank you, Ashley. Good morning and thank you everyone for joining us to discuss our fourth quarter results. Adam will cover more of the financial details in a minute but overall the partnership had another great quarter as a result of our highly contracted cash flows with our quality of customers, as well as the successful performance of the Casper acquisition. This enables us to announce seventh consecutive distribution increase with more than 2 times to distribution coverage for the quarter. In recent months, our thesis about the Western Canada crude oil market has began to play out; long-haul export pipelines are running near or full utilization; a portion meant has continued to trend higher and producers have announced several new projects to increase capacity at the oil sands facilities; some of which have been previously deferred. We expect that this new production will require new takeaway capacity, and our terminals are very well positioned at the right locations to meet customer needs in a timely and capital efficient way. Both our Hardisty and Casper terminals have scalable designs, which should provide us with a competitive advantage relative to any newly propose projects for a variety of reasons. The catalyst for re-contracting with our customers will ultimately be the spread of discount that Western Canada crude receives relative to competing grades or crude oil, such as Maya in the Gulf Coast. As production begins to exceed pipeline capacity, producers of Western Canada crude will begin to offer lower prices in order to incentivize refiners to utilize alternative modes of transportation to access those barrels. Already, Canada reported 14 month high for crude by rail exports during the month of December. Remember, the Partnership owns the only unit train capable terminal serving the Hardisty Hub, and the only unit train capable terminal directly connected to the express pipeline. So, we firmly believe that our terminals represent two of the best alternatives for the industry, and that the demand for our services will continue and increase. That being said, we do have renewal risk as online stream businesses do, including a near-term contracting opportunity, resulting from the scheduled expiration of a customer contract for our Casper terminal at the end of August. While that customer did not exercise this option to extend for another three year term, they invested in real takeaway infrastructure and originally committed at the terminal to create advantaged access to discounted feedstock for their refineries. They've stated they continue -- will continue to use the facility, and are actively involved in negotiations with us to do so. As a reminder, Casper has been one of our most active terminals and we believe, we expect strong utilization over the next cycle. As such, we're in active dialogue with that customer, as well as potential new customers to utilize the space going forward and remain confident in the timing and quality of our discussions with both producers and refiners. In addition to term contracts, we have the capacity to serve spot volumes to Casper, which could result in throughput rates above what would receive for committed volumes. Lastly, we are in discussions with partners and customers create new and unique ways to utilize both our rail and storage assets at Casper. Based on customer demand, we recently invested in the asset to add additional flexibility to source and deliver crude oil, which we look forward to talking about more on future calls. On the destination side, our sponsors, Texas Deepwater development in the Houston Ship Channel stands to benefit not only from the growing volumes in Western Canada, which should displace other imports into the Gulf Coast but also from the tremendous growth expected out of the Permian Basin in West Texas. We estimate that recent announcements of additional Permian pipeline capacity with delivery into the Houston area will translate into demand for over 15 million barrels of crude storage plus potentially more for the associated refined products. As such, we're busy at work with multiple potential partners and customers to assess how best to leverage our large deepwater position to serve crude, refined products and blending components, as well as build our connectivity within the Houston market which offers the most optionality. While more likely a late 2018 early 2019 event, dropping these assets in through the MLP would substantially grow and diversify the Partnership’s cash flows and add more high quality integrated energy companies to our customer list. On the M&A front, we have capital to spend and look forward to executing on attractive opportunities, including assets and venture opportunities outside of those broadly marketed by the Street. We are currently in the final negotiations of purchase and sell agreement to do exactly that within an off market asset that fits our strategy well. And we look forward to giving more update on that. In closing, I'm confident about the strategic positioning of our assets, about the positive macro signals emerging in the market and with continued market demand our ability to deliver another year of 5% to 10% distribution growth to our unit holders. With that, I'll turn the call over to Adam.

[Adam Altsuler:]

Thank you, Dan. And thank you for joining us on the call this morning. Please note that we issued our fourth quarter earnings release yesterday afternoon. In addition, we intend to file our full year 2016 10-K after market close today, to be accessible on the SEC's Web site at www.sec.gov. For the fourth quarter, we reported net cash provided by operating activities of $16 million, adjusted EBITDA of $16.8 million and distributable cash flow of $16 million. Our results reflect the stable and predictable nature of our cash flows, from primarily investment grade customers, with approximately 96% of our adjusted EBITDA before corporate expenses, generated from take-or-pay contract. The Partnership achieved significant growth during the fourth quarter of 2016 relative to the fourth quarter of 2015. Net cash provided by operating activities increased by 61%, while adjusted EBITDA and distributable cash flow increased by 31% and 56%, respectively. This growth is primarily attributable to the Partnership’s acquisition of the Casper terminal in November 2015, and was partially offset by higher interest expense on additional borrowings used to fund the acquisition, as well as additional operating costs associated with managing and operating the terminal. Distributable cash flow for the fourth quarter of 2016 also benefited from a partial tax refund with respect to 2015 of approximately $2.3 million, related to the activities of its foreign subsidiaries. Additionally, the Partnership received the remaining outstanding tax refund of approximately CAD900,000 in February of 2017, which will show up in our Q1 2017 numbers. And we do not expect to receive any additional refunds with respect to our 2015 Canadian income taxes. The Partnership expects to pay approximately CAD5.7 million in Canadian income taxes with respect to 2017. These estimates for income taxes are based on the Partnership's current operations, and are subject to fluctuations in the operating results of our foreign subsidiaries, and the exchange rate between the U.S. dollar and the Canadian dollar, among other factors. Net income for the fourth quarter decreased by 41% as compared to the fourth quarter of 2015, primarily as a result of a non-cash impairment charge of $3.5 million associated with our San Antonio Ethanol terminal. We are currently in discussions with an investment grade customer about providing an alternative industry solution, using a new advantage location servicing the San Antonio Ethanol market. We look forward to communicating more details about this opportunity as things continue to develop. On February 1st, the Partnership declared a quarterly cash distribution of $0.33 per unit, or $1.32 per unit on an annualized basis, which represents growth of 2.3% relative to the third quarter of 2016, and 10% relative to the fourth quarter of 2015. The distribution was paid on February 17th to unit-holders of record as of February 13th. As of December 31st, the Partnership had total available liquidity of approximately $189 million, including $11.7 million of unrestricted cash and cash equivalents, and undrawn borrowing capacity of $177 million on its $400 million senior secured credit facility, subject to continued compliance with financial covenants. The Partnership is in compliance with its financial covenants and has no maturities under our senior secured credit facility until July 2019. In summary, we are pleased with our strong liquidity position and strong distribution coverage for the quarter. And as Dan mentioned, we believe that our high-quality customer base and strategically located assets will continue to provide a solid foundation for future growth, will now will enable us to generate distribution growth of 5% to 10% in 2017. And with that, I would like now to open up the call for questions.

[Operator:]

Thank you [Operator Instructions]. Our first question comes from Gabe Moreen with Bank of America.

[Derek Walker:]

This is Derek on for Gabe. Just a couple quick ones, you mentioned the ethanol opportunity at San Antonio. Is that something that would be taken on at the USD level or the USDP level?

[Adam Altsuler:]

That would be taken out to the USDP level.

[Derek Walker:]

Then as far as the re-contracting risk, you mentioned around Casper. I just want to get a little more color there. So, the customer there did not renew, and are they expected to use spot volumes around that. Is that how I heard that?

[Dan Borgen:]

The best way to answer that is that contractually the customer had an extended period of time to renew discussions around the renewal. And so we've not -- it's in the affirmative, so we have to get a renewal declaration from them to do so. And so, we just wanted to advise the market that we have not received that at this time. However, a customer said they want to continue to use the facility. And obviously, for competitive and negotiation leverage, I’d probably do the same thing, if I were them. But we're at the table with them to discuss what they do plan on using the facility, and it could -- we're negotiating an additional term agreement or as we have other demand for the team loan as well and other customers at the table, new customers; we may choose to shift that to more of a spot volume deal with them perhaps, depending upon the negotiated rates.

[Derek Walker:]

And just as far as with the existing contract. Do you have a sense on how much that contributes in annual EBITDA?

[Adam Altsuler:]

So the customer we referenced for approximately $12 million of adjusted EBITDA in 2016. But when you think about the impact, going forward, it's hard to say the exact impact based on what Dan said and in our view that we think they’ll be material and significant spot volume relative to terminal going forward.

[Dan Borgen:]

Derek additional color on that. This customer has converted several other refineries to handle the product that comes through this facility, and continues to be one of our strongest users of the facility today. And as I said, their plan is to continue to use facility, especially as we see a cheaper feedstock for them that was their whole intent to spend the capital that they did at the refineries, as well as investing with us in this terminal. So, we feel pretty bullish about where we are there. But obviously we're in a negotiation period with them as was intended by the contract. And so, we look forward to been able to get something done with them on -- that’s favorable to the Partnership, and we'll continue to utilize the terminal.

[Derek Walker:]

I guess the last one from me, is just and I think previously mentioned some preliminary groundwork around Hardisty. And how do you see that evolving throughout 2018?

[Dan Borgen:]

So, we have completed a phase through the winter months that we wanted to try to complete, and we brought that on just last week. So we feel very good about where we are there in terms of keeping up with our customer demand for future expansions. We have cut our timeframe down from one year to nine month completion by doing the work that we did. We look for a full third train loading capability -- sole loading capability at that facility. So we feel very good about that and that came in on budget on time. So, we're very proud of our project team for doing that.

[Operator:]

Our next question comes from Poe Fratt with D.A. Davidson.

[Poe Fratt:]

Just to drill down a little bit more on the contract renewal. When you will get the $12 million of EBITDA, relative to what actual volumes versus the contracted volumes, how well you utilized. Can you give us a flavor of how closely we're to fully utilizing that contracted volume?

[Adam Altsuler:]

They're one of the more active shippers at the terminal. But as you probably known, we don’t give customer volumes, or really out of respect for our shippers. But I would say they are more and more active customers at the terminal.

[Poe Fratt:]

Then if you look at your contracts in ’18 and ’19, can you give us an appreciation for, either on an EBITDA basis or percentage of EBITDA basis, what the contracts' expirations represent?

[Adam Altsuler:]

So, all of our Hardisty contracts expire in 2019. And at the Casper terminal, they've been staggered. So, we have one, obviously in ‘17, one in ’18 and one in ‘19. But again, we don’t give specific EBITDA breakouts for the customer contracts.

[Poe Fratt:]

Yes, I get that. And what I was trying to do is look at -- you have 80% of 2016 EBITDA expiring over the next two years. And just trying to get an appreciation for how that's weighted in ‘18 and ’19? And if I am hearing correctly, it sounds like it's more weighted towards ’19 than it is ’18.

[Adam Altsuler:]

That's, right. The Hardisty terminal is, I think it's about 60% of our adjusted EBITDA, so more heavily weighted towards ‘19.

[Dan Borgen:]

Let me just add some color, maybe to that. We're in a renewable business, right. And it happens all the time, what we like is that the renewal of these contracts, both in ’17 and ’18, are coming up in a high-demand period or high-demand cycle. We like that. That's the best time to have renewals come up. We have no signals from ’18 or ’19 customers, obviously that they would change their tone or tune. Remember, the build of the Casper asset was to take advantage of cheaper feedstocks coming out of Canada. That's why all of the customers at the terminal are refiners and integrated. So, they like that opportunity, that's the full intent of what the Casper facility was built for. And so we look forward to this negotiation period, quite frankly, because we have an opportunity to perhaps increase. We've seen that before in demand cycles at other terminals where we've had contracts renew and we’ve been able to increase our unit price, I would call it, for the throughput. So, we look at it like the portfolio, but we look at do we take a shorter term higher price, should we take a longer-term, obviously the longer the term generally the better the price. But do like the period that we’re entering into there’s high-demand and like the market leverage that that provides all terminal operators.

[Poe Fratt:]

Yes, understood. It's a little higher than I anticipated, as far as the percentage that was expiring in 2017. So, I was just trying to calibrate ‘18.

[Dan Borgen:]

Sure.

[Poe Fratt:]

When you look at the distribution growth range that you've given for ’17 of 5% to 10%, can you talk about the parameters that would make you look at the high end versus low end?

[Adam Altsuler:]

I think we feel good about where we are with regard to distribution growth. If you look at -- we feel like we can end 2017 with the full-year 2017 average of distribution coverage of 1.2 or greater, just given our existing business. And obviously our assets are well positioned to benefit from the Western Canada production story. So as that continues to play out, we'll continue to give more color on that as we meet with our Board on a quarterly basis and report.

[Dan Borgen:]

We continue to remain bullish about where we’re going from a distribution growth standpoint. But the 5% to 10% based on what we're seeing today, is very reasonable for us. And so we feel confident on that. But obviously, that's subject to market conditions and the way the wind flow.

[Poe Fratt:]

And I know it's difficult to give any color on the asset that you're talking about, you’re in final negotiations. But can you -- would you be willing to offer size and multiple at this point in time, or is it just too early? And then also when you think this might get over the finish line, as far as whether it's first half of '17 event or whether it's potentially a second half? Any color would be helpful.

[Dan Borgen:]

So, let me say this. We are close. We will be spending some additional dollars on the asset to retro it to handle to fit our specific need. Our perspective revenue start would come towards later in the year versus shorter in the year. But it is asset that fits us well that will -- that fits our strategy from, I'll call it, more of a destination versus an origination. And we look forward to trying to been able to talk more about that in the near term. This is again not a, I'll say, publicly competed but a discussion between ourselves and both a prior customer and a corporate entity that is sizeable. And so, we have exchanged documents back and forth and we're getting closer on that. That's probably as much color as I can give at it this time.

[Poe Fratt:]

As far as sizing, Dan, any color on just how large this transaction might be?

[Dan Borgen:]

Really now levered to say exact sizing, but I would say it'd be meaningful for the Partnership.

[Poe Fratt:]

And then, Adam, do you just CapEx numbers for 2017 either total or maintenance and growth?

[Adam Altsuler:]

We've got a small amount of maintenance CapEx budgeted for the full year. And it'd be in line with last year, I would say. Growth, we've got one identified project that Dan mentioned, at Casper, and that’s just investing in the asset to be more flexible with regard to sourcing and delivering the crude [multiple speakers]. That'd be growth capital. It's a relatively small deal but it's been -- we're doing that really in response to customer demand and the market opportunity we see. So, I'd call it less than $500,000, but we feel like it'd get adequate returns given the market opportunity we're seeing.

[Poe Fratt:]

So, total CapEx shouldn't be -- should be under $5 million ex this acquisition opportunity?

[Adam Altsuler:]

It would be much lower than that. The maintenance CapEx, call it around, $100,000 to $200,000 and the growth CapEx less than $500,000. And that’s just for the identified projects of course something else should up it would change that number, but just for what we referenced on the call today.

[Operator:]

[Operator Instructions] Our next question comes from Mike Gyure with Janney.

[Mike Gyure:]

Talk a little bit about the rail rate environment, and what's going on there. Now that you're seeing more drilling and more activity and more, I'd say, demand on the rail system from users like frac sand and places like that?

[Dan Borgen:]

So we work very well with our rail road partners, and the railroads have been, I would say, aggressive to replace lost revenues from coal. And so it's a great time for us to be at the table growing rail revenues. I think that we are working with our customers and railroads to get some term volume and pricing on freight rates. We think the railroads have told us that they can handle both the increased frac sand demand, as well as growing demand for crude and related products on rail without a problem. There is some ramp up from -- several of them have reduced crew counts. There is plenty of locomotive power, and it's approximately three to six-months, seven-months lead-up in terms of training crudes and that kind of thing to bring that back to work to handle growing volume. The volumes that we’re seeing and forecasting now are easily served by both of the servicing railroads that we currently use at several of our facilities. So, long answer to say we've got bullish partners that want more revenue. They want to be aggressive and they want to grow the revenue. They've all pushed their operating ratios very well and continue to drive cost out of their business. And so, it's important for them to create additional revenue opportunities across the top.

[Mike Gyure:]

And then maybe a follow-up on your Hardisty asset up there, expansion plans, I think originally, you were thinking later 2017. It sounds like maybe 2018 might be more of the time when the CapEx would start working on the expansion. Can you maybe kind of update…

[Dan Borgen:]

We would like to drive through the summer months as hard as we could, in terms of expansion there. And as I said earlier, we've reduced our build time from one year to approximately nine months, maybe even little less than that. And so, we would like to see those dollars, those CapEx dollars, spent wherein sooner than 2018. Obviously, we have the months, nine months from today, if we started today that would put us pretty much revenue start into ’18. But in terms of building and constructing and bringing that to the table, we're seeing some of our producing customers in Canada accelerating their production faster than they thought they could. Bring in the more production online. And these are existing customers that we have as well as new customers. So, our existing customers have asked us to remain vigilant with the growth that we have. And we're in good contact with them about our timing of that. Obviously, we would have like to -- they are coming out of a tough winner, where they had to throttle back some of their production to be able to, just because of the cold conditions. And so there I think they're trying to ramp back up and catch up with some of that. We’re continuing to see inventory builds up there, and obviously pipeline allocations are in the high 30s-40s. So, it's all the drivers and all the signals with there that additional train capacity is going to be needed. We're already permitted. We're already ready to go from that standpoint, and we've -- as I said, we had a lot of work through this period of time and completed that. So that we could get be in place to meet the demand at the request of the customers.

[Operator:]

Our next question comes from Robert Balsamo with FBR.

[Robert Balsamo:]

You addressed the supply growth out of Canada, refiners’ preference for some of these crudes, the goal. I think that's something that we’ve heard from other operators in the midstream space with greater demand for heavier quality and coming as great imports and exports of the lighter volumes. Could you address maybe just -- as growth comes out of Canada, like what volumes might be displaced?

[Dan Borgen:]

I think I'm going to ask Brad Sanders who is on the call as well to -- our Chief Marketing Officer, to speak about that. And then I can follow-up. Brad?

[Brad Sanders:]

You did state correctly that U.S. continues to be an importer of heavy crude, heavy sour crude and an exporter of the lighter grades. The production from the shale formations, as an example as we get new production there on the margin, that production will have to find access to water. But from a heavy standpoint, the Canadian barrel headed towards the Gulf Coast, primarily the Houston region, which is importing, I would say the Gulf Coast region generally, somewhere between 1 million and 1.5 million a day of heavy oil, will displace production from the Middle East, heavy production from the Middle East; but primarily Venezuelan grades and grades from Mexico Maya in particular. So, it's what I would call regional grades and then on the margin grades from the Middle East.

[Operator:]

And we have a follow-up from the line of Poe Fratt with D.A. Davidson.

[Poe Fratt:]

On Hardisty, it sounds like you've done a lot of work in getting shortening the lead time there. Can you give us some idea of just cost of that potential project?

[Dan Borgen:]

No, we don't disclose our capital costs, Poe. And on, that we're being efficient in our spend there. But we do not disclose our capital costs on project.

[Poe Fratt:]

Dan just to clarify, would that be done at USDP -- at the Partnership or the GP?

[Dan Borgen:]

It'll be upstairs. We do it up there to take the construction risk out and get all that out, and then drop it in as a performing asset.

[Operator:]

We've a question from the line of Elliot Miller, a Private Investor.

[Unidentified Analyst:]

I was curious about the impact of the border adjustment tax, if it passes. And how that would be affected by the displacements by Canadian crude or other foreign crudes?

[Dan Borgen:]

I think that's a great question. Elliot, I think that we continue to monitor that. And I think that there -- I was at a senior level get-together recently that folks more and they now plugged in on that, gave it a less than 20% chance of passing in terms of a broader tax. I think, obviously, with the new administration there is some stable rambling about those types of things from a beer tax to a variety of things. But remember that Canada is one of -- let's just talk about Canada for a minute. Canada is one of the, is the largest, importer of U.S. produced crude, primarily in the Eastern Canada. So to complete that game if they wanted to. They also are big importer of automobiles and other things. So, I think it's a -- I think it certainly something we need to keep our eye on. We're not overly concerned or worried about that. We think that the demand of the U.S. refiners and the heavier U.S. intermediate to heavy refiners will continue to demand the product that they need. We think that the light suite of Bakken, Permian, clearly as others have stated much better than I can, are looking to go export. The demand, the in-country demand U.S. demand for a intermediate to heavy crude, is something that I think will continue to drive crude being put into the U.S. refiners. And whether a broader tax is implemented, it will be absorbed through this system. But we think based on what we're seeing that's a lesser likelihood than 50% I'll say. Also, remember that competing barrels are also imports. So, if the heavy [multiple speakers], that's right. So, if it's Venezuelan barrel or if it's a Mexico barrel, it's an imported and I think would be subject to more of broader tax than from a friendly country of adjacent neighbor to us in terms of coming from Canada a good trading partner of ours versus Venezuela, who arguably is not as friendly a trading partner with us.

[Unidentified Analyst:]

The other question I want to raise is about competition from the Keystone. What are your thoughts on that?

[Dan Borgen:]

It's great question. Pipelines are additional takeaway opportunities. And so anytime a pipeline is being built of nine points whatever billion, I think latest number from TransCanada on the XL program it could have an impact on crude takeaway. It fills the need. Now, our view is it still has some hurdles to get through, not just the matter of getting over the border but on state-by-state county-by-county fight getting through. I think there are still some challenges. I think the other side is we have had a production -- when all of those pipelines were originally contemplated, whether the Energy East, TMX, XL, any of those, production in Canada was estimated to be 2.7 million barrels; its south of 2 million barrels today. So the driver demand for long term high cost pipelines are something that could be debatable; so one, it's a high price alternative; two it takes some time to get in place; and the need and demand is now, and we are uniquely situated with 200 -- approximately 40,000 barrels a day of permitted capacity that can come out of and help deliver Canadian production to refining centers uniquely situated in the Gulf Coast, United States. So, it is an alternative, don't misunderstand me. Clearly, it's an alternative. But it's out there a few years and it's expensive, and it's got some headwinds. We've had some producers that say regardless we are still, rail is still part of our portfolio and will continue to be, regardless of that. And because rail gives us things that a pipeline doesn’t give us, flexibility. Remember, rail does a few different things. It does not only a physical takeaway but it gives the opportunity to take the best markets. You put in a pipeline you basically go from point A to point B, at point B might be where you want to go but the quality of the product also that's put into rail can be segregated and maintained and kept, delivered to the market [multiple speakers].

[Unidentified Analyst:]

No, I've seen all of that presentation, I'm familiar with it, believe me, honestly, I'm familiar with that. Is it safe to say that when Keystone XL does happen, and I understand that there are barriers that have to be met and crossed but it's -- when that happens, it will still not be priced competitive with USD's rail business?

[Dan Borgen:]

I would say that we don't know what the pricing on a delivered Keystone XL program would be. But if you were running East Coast barrel today, it currently is not in the money to do that. It could be a physical takeaway, but it's not in the money today. And you'd prefer to run rail to the Gulf Coast, because it'd be more competitive. So, I can answer it that way. We and the railroads will continue to remain competitive, whether it'd be a pipeline barrel, for all the reasons we've previously discussed. So, we compete with pipelines every day and as they do with us, but we also think that they're just part of the takeaway portfolio. Like I said, our customers have -- continued to remain committed to rail. As a part of it, they own railcars. They're in place with those. They like that optionality. So like any portfolio, they like that whether it'd be peaking for them, whether it'd be peaking asset or whether it'd be something that's moving every day. They like the optionality that rail provides to them. And I think they're looking at multi-year commitments on freights, on railroads, should be able to maintain a competitive cost component. Because remember the freight rate is, from the railroads, is the significant portion of the overall move, we're very-very small. So, from a insurance standpoint, they can continue to hold place that our terminal had a relatively small cost; and as one side to me it's cheaper than the insurance that I pay on the pipeline. So, it's a good alternative to have that capability when it's needed.

[Operator:]

And that does conclude our Q&A session for today. I will now hand over program back over to Dan Borgen for any additional or closing remarks.

[Dan Borgen:]

Very good, thank you. Just I think we've covered a lot of ground today, and some great questions and great concerns. But with all of that said, we remain very bullish about our business, and we remain confident in the drivers, the macro and micro drivers that we’re seeing. We've been talking about this for a while. And certainly, we’ve come out of a valley that has been impactful to the entire industry. There is renewed momentum, both in Canada and in obviously at select areas here in United States, and so we remain bullish. We see the drivers are supporting what we've been saying. I know you've read the stories in the announcements from a lot of our customers, in Canada, who continue to reduce their costs on a produced barrel to remain very competitive, south of $20 a barrel in some case south of $17 a barrel and other cases. So, they have gotten very efficient through this downturn as we all have. And so, we continue to have customers demanding rail takeaway solution. And we've reduced our construction now to our next phase of expansion up there down to nine months and end to be able to meet that demand. I think that all signals are lining up that we should have some positive announcements around that in the future. The renewal options are coming at strong demand periods. And I'll just say this frankly. If you’re not comfortable with renewal risk in the mid-stream business, you probably shouldn’t be in it. Because the renewal risk is just part of the business that we have, but we were very much like the opportunity to have those renewals come in at strong demand periods. And we’re entering those cycles. We've seen it before. We've been doing this for a long-time, cycles come and go, but strategic assets are important and needed. And we like the opportunity to be able to renegotiate pricing. Again, previous cycles that we've been through, we've seen, I will say, doubling and tripling of unit pricing to meet demand when demand is strongly on and there is more supply than takeaway, that's the market that we’re headed towards. And my committing that we’re going to see double and triple certainly not, but we've seen those markets before and we like the opportunity to have revive at the apple and renew. And we've got new customers at the table now talking to us, new potential customers, at the table. So we like that marketing and leverage that that gives us as well. And rail as you see the numbers, and these are all fact points you can verify independently. But the rail -- crude on rail is growing and in Canada, and so it's proving the point that there is not enough pipeline takeaway that any new pipeline are few to several years away, if at all. And so demand is going to be on in the period that we are uniquely capable of solving for them. So, with that, I'll say thank you. And appreciate the time today and we look forward to talk about other positive things concerning our partnership. Thanks so much.

[Operator:]

Ladies and gentlemen, this does conclude the USDP Partners’ fourth quarter 2016 earnings call. You may now disconnect your lines.