TGE Q1 2018 Earnings Call
Operator: Good day, ladies and gentlemen. Welcome to the Tallgrass Energy Q1 2018 Earnings Conference Call. Today's conference is being recorded. At this time, I'd like to turn the conference over to Nate Lien. Please go ahead, sir.
Nathan Lien: Thank you, Kathryn. Good afternoon, and thank you for joining the Tallgrass Energy Quarterly Earnings Call. As we discussed, TEP and TEGP's results from the first quarter of 2018, which were released through our joint press release this morning and 10-Qs this afternoon. Joining me on the call are David Dehaemers, President and Chief Executive Officer; Bill Moler, Executive Vice President and Chief Operating Officer; and Gary Brauchle, Executive Vice President and Chief Financial Officer. Before turning the call to David, let me remind you that this event is being recorded and a replay will be available for a limited time on our website. Additionally, our comments today will include forward-looking statements and estimates. These forward-looking comments are subject to various risks and uncertainties and reflect management's views as of May 3, 2018. Please refer to our filings with the SEC, which are available on our website, including our 10-Ks and 10-Qs, which provide discussions of factors that may cause actual results to differ from management projections, forecasts, estimates and expectations. Note that except to the extent required by law, Tallgrass undertakes no obligation to update any forward-looking statement. Please also refer to our earnings release and website for reconciliations between the non-GAAP financial measures referenced in this presentation and the most comparable financial measure or measures calculated and presented in accordance with GAAP. With that, let me now turn the call over to David for his opening remarks.
David Dehaemers: Good afternoon, everybody, and thanks to everyone for joining our Tallgrass Energy First Quarter Earnings Call. First quarter was another strong quarter for TEP with consistent performance in the natural gas and crude oil transportation segments and continued growth in our gathering and processing and terminaling segment. All this contributed to TEP's 19th consecutive quarterly distribution increase. Again, we started out at $1.15 when we annualized, we went public in 2013, and today we're at $3.90 annualized. And then also TEGP's 11th consecutive quarterly distribution increase. Again, just as a reminder we were $0.53 annualized May of '15 money when we went public and three years later we're $1.95 annualized. Now let's review the first quarter financial results, which were the catalyst for these increases. Adjusted EBITDA for TEP was $165 million, and DCF was $146.2 million, producing robust coverage of 1.3 times for the first quarter. TEP increased its quarterly distribution to $0.975 or like I said earlier, $3.90 annualized, which is an increase of 16.8% over the first quarter of 2017. TEGP increased its quarterly distribution to $0.4875 [ph] per quarter or $1.95 annualized, which again is an eye-popping increase of 69.6% over the first quarter 2017. I'm going to turn the call over to Gary now for further details on the financial performance, and then Bill will talk about some of our commercial items, and then I'll come back to wrap it up and start the Q&A.
Gary Brauchle: Thanks, Dave, and good afternoon, everyone. The natural gas transportation segment produced adjusted EBITDA of $90.5 million in the first quarter of '18, which is a very healthy quarter for the segment albeit lower as compared to Q4 of '17. The primary driver of the difference quarter-over-quarter is lower distributions from REX, which was partially the result of timing, which amounted to about $5 million again quarter-over-quarter and I'll come back to that topic in a minute. The other primary driver of the quarter-over-quarter decrease is about $4 million of lower opportunistic incremental available capacity sales on a short-term basis, and that delivered a substantial benefit this quarter and in Q4. REX was able to do that again in Q1 but to a lesser extent and, therefore, the benefit was still positive but lower quarter-over-quarter. You can be sure that REX remains focused on optimizing all available capacity whether it be westbound capacity like we saw in Q1 or eastbound capacity in Q4. In fact, I'd remind you that we announced in February that REX signed three new Zone three long-term firm contracts totaling 105 million cubic feet a day of that incremental capacity in Zone three East to West for terms of three to five years. One contract commenced in August of 2017, another in April of this year and the third begins in October of this year. To be clear, that capacity is over and above 800 million cubic feet per day from the Capacity Enhancement Project or Power Up project as it's called that is fully contracted for 15 years. So said plainly, REX is doing an excellent job of optimizing available capacity sales, and we continue to see a notable amount of that opportunity remaining in 2018, which will be over and above our budgeted amounts that are included in our guidance previously released. While we're talking about REX's financial results, let me go back to the Distribution timing that I mentioned a minute ago. In our press release, you will find summarized financial results for Rockies Express, excluding its DCF and distributions to members. In any given month, quarter or year, REX's DCF and distributions to members may not be the same. That's primarily because REX distributes cash every month to its partners near the end of the month based on its best estimate of revenue, cost and capital spending and, therefore, DCF. As we close the books after month end and expenses and capital spending or more precisely known are trued up as we call it, those estimates become actual results. Once that trued up amount is finalized, that's been included in the following month's distribution if positive or deducted if negative. So while it may appear that REX is over or under distributing at any one period the difference, which is typically immaterial or insignificant especially to TEP is simply due to a prior period true up based on the timing of the distribution. Also into the natural gas segment are TIGT and Trailblazer, and those assets produced an exceptional first quarter on the back of strong contracted cash flows and lower expenses and maintenance capital. So all in all, the natural gas segment performed very well in Q1 driven once again by a stable long-term firm contracted cash flows. Moving on to the crude oil transportation segment, which is Pony Express. Distributable cash flow to TEP was $67.2 million, which was $3.9 million higher than Q4 of '17. On the third and fourth quarter calls of last year, we mentioned that one of our shippers used some previously shipped incremental volumes to meet current period committed volumes during those two quarters thereby reducing Pony Express' distributable cash flow in those quarters. We also mentioned at year-end that the total remaining incremental balance at the end of the fourth quarter was an insignificant $1.5 million. And so the impact of that to future quarters should be much lower. Again, that's all that we talked about last quarter. As we expected, during the first quarter, throughput volumes increased by 22,000 barrels per day to approximately 290,000 barrels per day. Approximately 97% of those barrels were third-party unaffiliated volumes. We believe this or a higher figure may be a more normalized run rate in 2018 if crude oil production continues to increase and prices show continued stability in the mid to high 60s. For example, April throughput on Pony Express was approximately 335,000 barrels per day and preliminary May nominations are well in excess of that figure at around 350,000 barrels per day. Now onto our next segment. The gathering, processing and terminalling segment generated adjusted EBITDA of $16.9 million for Q1, which was an increase of $1.9 million over Q4 of '17. This segment continues to grow nicely quarter-over-quarter, and we expect this trend to continue throughout '18 generally speaking as a result of the previously announced organic growth projects and acquisitions and our water infrastructure and terminals businesses. Now onto capital structure and TEP. At the end of the first quarter, TEP had over $925 million of liquidity available on its revolving credit facility. TEP's leverage as of quarter end was approximately 3.1 times based on the trailing 12-month adjusted EBITDA as calculated according to our credit agreement. This continues to be on the low end of our three to four times long-term leverage target indicating ample leverage capacity and TEP to fund third-party acquisitions, organic growth projects and Tallgrass' 75% share of REX's July 2018 debt maturity of $550 million. This assumes the merger transaction closes by the end of the second quarter. And with that, I'll turn it over to Bill now to talk about commercial update at Tallgrass
William Moler: Thanks, Gary. Good afternoon, everyone. It was another busy quarter for our commercial teams. Since the beginning of 2018, we have announced new organic growth projects and third-party acquisitions totaling $340 million. Other key accomplishments in that timeframe include placing the Platteville Extension and the ramp and Holly Frontier, El Dorado and CHS Macpherson refinery connections into service on Pony Express. We have also commenced construction on the terminal and the Iron Horse Pipeline, both of which are progressing well and on time. Finally, we signed another third-party long-haul contract on the Platteville Extension for transportation to Cushing of 15,000 barrels per day taking our total commitment on that project to 52,500 barrels per day, of which over 85% of those are third-party unaffiliated volumes. Within Tallgrass Midstream, we have connected or contracted approximately 30 additional natural gas wells to our midstream gathering assets in the Powder River Basin, increasing our gathered production approximately 38% since April of last year. We have promising proposals out in response to producer RFPs that represent significant acreage dedications and potential additional connections. Over the last year, we have grown processing volumes by 20% and expect our processing capacity to be fully subscribed by year-end. In anticipation of that growth - in anticipation of the growth we are seeing in the Powder River Basin, we are filing permit applications for 120 million cubic feet a day third processing train at our Douglas facility. We have seen a substantial increase in fractionator use at our Casper facility and are aggressively utilizing our stabilizer capacity for condensate produced in the basin. BNNs, recent acquisition of the North Dakota water disposal facilities is performing as expected, and our water gathering system project is kicked off and under construction. In addition, we are in discussions with as many as six producers in North Dakota, who desire both gathering and water disposal services. These expansion opportunities are incremental to the economic justification of the acquisition. These recent developments combined with the approximately $650 million of commercially developed projects and third-party acquisitions we announced last year and the additional projects we are working to prosecute demonstrate our continued ability to grow and further diversify the Tallgrass asset base. While individually, they may not be flashy, attention-grabbing projects and acquisitions, these are solid projects done at attractive multiples with strong standalone economics. Important, these projects and acquisitions demonstrate our continued growth. Before I turn the call back to David, I'd like to briefly address FERC's March 15 notice of proposed rulemaking in regards to the income tax allowance as we have received a number of inquiries related to the potential impact on Tallgrass revenues. As we mentioned in our press release that day, we do not expect any material financial impact as of revenues at our two largest assets, Rockies Express and Pony Express, are almost entirely generated by contracts with negotiated rates. However, we expect there could be some impact at both Trailblazer and Tallgrass interstate transmission. While many of the details will need to become much clearer in the future, we continue to believe that potential impact to be immaterial. If I had to quantify it today, we currently believe that potential impact to be less than $4 million and collective loss revenue annually given our expected corporate structure following the close of the proposed merger. With that, I will turn the call back to David for his concluding remarks.
David Dehaemers: Thanks, Bill. I want to finally talk about the TEGP acquisition of TEP and kind of give everybody a thumbnail sketch of where that is at as I know many of you are curious about its status. Hopefully, the majority of the questions that people have will be addressed through the earnings release today but for the earnings release today that we did do. But to briefly reiterate, the registration statement has not been declared effective. We anticipate that it will be declared effective and TEP will mail a definitive statement to its unitholders in the coming weeks. Frankly, we're filing the proxy tomorrow that we believe will be the last proxy and hope that will be effective as soon as next week. The record date for the unitholder meeting is May 18, which is coming up. It's 15 days from today with the unitholder meeting and vote occurring on June 26 here in Overland Park, Kansas. Barring any unforeseen delays, we continue to expect that the transaction will close by the end of the second quarter. With that clear, I hope you understand that we're not able to answer any questions about the merger in the Q&A session, but again you ought to be looking for the final proxy here in short order. Even with the ongoing TEGP, TEP merger activities and our focus on closing the introduction, our team continues to execute on the next chapter of the Tallgrass growth story. Hopefully with a lower cost of capital and improved credit profile, streamlined corporate structure and broader investor base, we believe Tallgrass will be better positioned for enhanced returns on future organic growth and acquisition opportunities that we will continue to produce and what we know our partners will expect in that and simply that is outstanding results. As Bill mentioned earlier, the project and acquisitions we have recently announced, and I think he gave you two numbers, $650 million and $340 million this year, which might add up to $990 million, just call it $1 billion over the last 15 months. Those projects and acquisitions we have - we are executing against and those will also further solidify Tallgrass as a premier and growing midstream company. As always, thank you to all our partners and shareholders for their confidence and investing with us. And thank you to everybody on this call for your interest in our companies. With that, operator, we'll turn it back to you to kick off the Q&A portion of our call.
Operator: Thank you. [Operator Instructions] And we'll first hear from Colton Bean with Tudor Pickering.
Colton Bean: Afternoon. So maybe just housekeeping question here for Gary. Is the line in the Rockies Express cash flow buildup denoted change in contract asset? Can you just provide a bit of context on what that's related to and whether it's recurring or one time in nature?
Gary Brauchle: Yes, sure, Colton. In the first quarter, Rockies Express and, frankly, TEP were required to implement a new generally accepted accounting pronouncement for revenue recognition. And at REX, you know Encana [ph] contract has a lower rate now and steps up in late 2019. The new accounting rules that we implemented or required to implement requires REX to recognize GAAP revenues from that contract on a straight line or linear basis. And so in 2018 and most of 2019, the GAAP revenues exceed the cash paid by Encana and therefore received by REX. So the change in the contract asset adjustment simply reduces those straight line or linear revenues and adjusted EBITDA to equate to the cash received. So you can expect to see that continue in 2018 for the same magnitude in nearly all of '19 as well.
Colton Bean: Got it, okay. And then I guess just on the Northeast Colorado. So with the Platteville [ph] extension online, you mentioned that you are up to a little over 50,000 barrels a day contracts there, and specifically had 15,000 plus long haul. So my understanding was that the original Northeast lateral had capacity of 90,000 barrels a day and was 90% contracted, so a little north of 80 there. So is the capacity actually greater than that 90,000 barrels a day or how are you facilitating these Platteville long haul movements?
William Moler: It's a good question and the answer is a couple of parts. The Northeast Colorado lateral that we built at inception was originally designed for 90,000 barrels a day. It has the capability of moving far greater than that. Its diameter and pressure allows for much more volume than the 90. The 52 that's landing at Buckingham is both...
Gary Brauchle: 200 plus.
William Moler: Yes. It's both serving existing FTE contracts or firm contracts, and then there are brand-new long-haul contracts all the way down to Cushing. So that line can do near 200,000 barrels a day from Northeast Colorado to Sterling where it will join Pony going south to Cushing.
Colton Bean: Got it, okay. And I guess just the last one on Rockies Express. I mean, it seems like most of the past discussions on REX interconnect has been weighing around projects like Perry States [ph] or SPL bringing connecting demand laterals. With Rover approaching full in-service, Nexus slated it to come on in Q3, it seems like we may have quite a bit of gas in the up and Midwest market. There is a handful of north to south pipelines that see legacy contracts rolling off over the next couple of years. Does that create an opportunity for REX to connect into those lines as part of the broader reversal to get gas in the Gold Coast? Or you guys have any discussions like that today?
William Moler: We are feeding types that had south in Zone three today. It is not unexpected that as their contracts roll off and they have increased ability to take gas out, that we can increase meter capacity in order to do that. We are already connected to almost every one of those north-south, south to north pipelines that come within striking distance of REX. So yes, the more of those that turns out for Gulf Coast export is more gas than we can move off of REX and add to LNG facilities in the Gulf.
David Dehaemers: Just what Bill says a little bit too. If you look at the NGI daily gas data, it shows all of our interconnects. I believe that every interconnect that we already have with the exception of one, the metering is already oversized for what we're actually contracted and pushing through.
William Moler: It is.
David Dehaemers: And so it's even more to your point specifically. We do have a lot of capacity already built into the system where almost all those north-south lines like ANR, Panhandle, et cetera, could take more volumes off of those.
Colton Bean: Got it. I appreciate. Leave it there.
David Dehaemers: Thank you.
Operator: Our next question comes from Christine Cho of Barclays.
Christine Cho: So I'm going to start by saying I'm not sure if you can answer this, but would you be able to share what re-contracting assumptions you're making in the pro forma projections in your S4?
David Dehaemers: You know that we can't answer that.
Christine Cho: Okay, had to try.
David Dehaemers: You're not only not sure. You know. Speaking of which, I think you're not able to write on us, are you? Or are you?
Christine Cho: No, I'm not. But I'm keeping tabs on you.
David Dehaemers: I'm glad to hear that. Love to answer your questions that we can answer.
Christine Cho: Okay. Then moving over to the comments about your filing permits for a third processing facility. Can you remind us as the two current plans are under acreage dedication or volume commitments?
William Moler: The two current plans, Douglas and Casper have for the most part, fee-for-service term contracts where the gas comes into the gathering system on Douglas and goes through the processing complex for a fee. We take that gas. Sometimes it's volume limited. Sometimes it's a pad dedication. Sometimes it's acreage dedication. So it's very much multifaceted, Christine. We don't have one simple contracting methodology that we use for either of those two plants.
Christine Cho: But so if you are moving forward with constructing the processing facility, it's because you have line of sight into more volumes through whatever contract you have, right?
William Moler: That is correct.
Christine Cho: Okay. And then the distributions from REX at TEGP, is that prorated for the timing you actually owned REX during the quarter? Asking sometimes I think you put in a full quarter and adjust it through purchase price.
Gary Brauchle: Yes, Christine, what you're seeing in TEGP's results is two months' worth of distributions from REX for the quarter because we acquired it near the beginning of February, so it got February and March distributions. And so just to make your math a little easier, if you wanted to add in the January 1, it would have been about $11 million.
Operator: [Operator Instructions] And we'll go to Barrett Blaschke with MUFG Securities.
Barrett Blaschke: Quick one. As we're thinking about what the world looks like after the business combination, are you going to holding back on potential projects at this point or holding back on any acquisitions you're looking at to try to get to a lower cost of capital world?
David Dehaemers: No, I wouldn't - that's a good question. I wouldn't say we're holding back. We've got a number of things in the queue. Now that you bring that up, we talked about it before relative to our - so the answer to that is no. I think given that we have a use of cash for paint on the REX notes, we've already committed to with Philip 66 that come in July. We still have a lot of liquidity, like $0.5 billion there. A lot of our projects that we're already prosecuting now are already more than half-funded. So we feel like you've got a lot of land out there relative to funding those. But at some point, with regard to the $2.3 billion worth of projects, and that includes the $350 million that we had so just call it $2 billion worth of projects backlog kind of probability weighted that's probably more like a $1.3 billion, so that leaves us - minus $300 million, leaves us with $1 billion worth of projects backlog. I would not say we're holding them back. But clearly if we were to prosecute all those at some point, we would want to have a much better cost of capital than a 10% yield. So I hope that answers your question and maybe gives you a little more information that you were looking for.
Operator: We'll continue on to Michael Blum with Wells Fargo.
Michael Blum: Maybe just to follow along the last question a little bit. It's kind of a longer-term question. How are you thinking about long-term financing your growth however large it may get? And I guess specifically, where do you want to keep your consolidated leverage and your dividend coverage basically as targets?
David Dehaemers: Well, I think we've kind of all along said three to four times in B investment grade. We are at 3 times now, probably see us unconsolidated - we're 3 times now standalone. We're arguably less than that. We'll be less than that into '19 even on a consolidated basis, less than 4 times, I should say. So I mean I think we still want to keep around that 4x, and we're still hopeful to get the investment grade rated. On the other, 1.3 times covered now. We were one point three or four times covered all last year.
William Moler: Better than 1.4.
David Dehaemers: Better than 1.4 covered last year. I think our plan right now this year is to probably be 1.25 times covered throughout the year, but that will depend. I mean, the cynic in me would say, maybe we ought to do something like the other guys out there and say we're going to increase distributions $0.05 a quarter until it goes to 1 0 or maybe we ought to do like some of the other ones and go to 0.9 coverage. They seem to get better cost of capital than we do. But taking your question seriously, again I think long, long term, the business like ours, kind of a 1.15 coverage is a good goal. But again, that can change just depending on time and circumstances. Was there another part of your question, Mike?
Michael Blum: No, I think you covered all that. I did have another question. I'm just wondering if you can give us kind of your updated views on REX and specifically I know you've talked in the past about potentially being able to make REX bidirectional all the way through all the zones. Obviously, as some time to be that original legacy contract rolls off but just wanted to get your latest thoughts on kind of the evolution of REX especially given what seems like a lot of changes in the natural gas markets with flow kind of shifting around?
David Dehaemers: Yes, you bet. I'll start off and then Bill can fill and maybe throw you back a little bit, but there is always the looping are not looping, but the only Zones one and two bidirectional in REX is still possible. It's very small capital amount. I think it is somewhere in the neighborhood of $75 million to do that. Other than looping all of REX Zone three at REX, which is a project and could be done and be a big project anywhere from $1.5 billion to $2 billion, and that could happen at some point. It could happen in smaller chunks. And we still have what I think is probably $300 million to $500 million worth of projects that we can do on REX that would include that $75 million of doing zones one and two. I think what we're finding out on REX when we put the power up last year we found out that we over engineered it, which is good. And depending on BTu content, et cetera, that we're able to we've been able to contract more than 800 a day that the power up goddess. We have moved over 3 Bcf on the entire pipeline - I'm sorry on that segment. So on some days we had as much as 400 a day more than what we originally planned for. And so that's been incrementally like Gary said, incrementally last year that helped us even in the fourth quarter make almost $10 million extra dollars. That's still there. We're finding a lot of opportunity in the West. I would say we're probably - we think REX West and reconstructing and so I really don't even want to other than to say to the extent we do have volumes to contract out there, we're starting to have those discussions. In the meantime, we are selling short-term firm services on the West, a lot more than we thought we would in our plan. And I mean in a meaningful way, I mean, millions of dollars a quarter. So does that translate into me right now telling you hey we're going to have another $25 million on REX, which 75% is ours? I'm not prepared to tell you that right now but I did looking really good and positive for us both this year, next and beyond. So if you want to follow up with anything?
Gary Brauchle: Just to remind everybody that we are underway on our 600 million a day fully contracted Cheyenne connector that brings incremental supplies to the West and of REX at Cheyenne. Our Cheyenne hub enhancement is going to allow us to be the pre-eminent pipe for getting gas out of the Rockies. The DJ continues to ramp up and gas production and oil. The powder is ramping up in both gas and oil. All of that gas goes to Cheyenne and it has to go somewhere. In fact, our recent and for many days in Q1, our West to East volumes were ranging 1.7 to 1.75 BCF a day. So the pipeline that was would not be flowing gas west to east any longer because of the Marcellus and Utica is actually been flowing near capacity for a substantial part of 2018 thus far.
Operator: We'll now hear from Ethan Bellamy from Robert W. Baird.
Ethan Bellamy: Has the strength in crude changed the tenor of the conversations with crude shippers at all?
David Dehaemers: I would say it has, Ethan. We are having more discussions. The Platteville extension has been wildly successful for us. That was a good move to get into the heart of the DJ and have that supply connected to us even in the ramp in Kansas has been flowing at capacity. Guernsey trading has started to revert back to sub WTI numbers, which is good. Its reflecting basis is increasing as crude reduction picks up and prices go up so yes, I will tell you the tenor right now is cautiously positive.
Ethan Bellamy: Okay. A rising steel prices imaging anything in your backlog, shadow backlog?
David Dehaemers: Not as of yet. We - I'm going to say very smartly, it might've been very luckily. The Cheyenne connector pipe we got on order very quick ahead of all the tariff discussion in DC so we - what we have in our plate now that is moving and actionable, we've got this deal already in hand and not overly concerned about. It if we land some of these backlog projects that Dave alluded to. We'll have to make sure and get the best deal we can on steel on those projects. Yes, just to be clear, we have the pipe already for iron horse and Platteville is already in the ground so [indiscernible]
Ethan Bellamy: Got it. Okay, and then, Gary, is it safe to assume that you're going to turn out the REX you bring on the Tallgrass balance sheet? And if so, when should be model that?
Gary Brauchle: Ethan, I think it's safe to say that we look to do that when the opportunity presents itself at the most cost-effective manner. We are in discussions with rating agencies, and we'll continue to do that and as you know, we've looked for the right time to turn out debt on a long-term basis, and we'll continue to do that. So I think it's safe to say we'll do that. I can't really at this point tell you whether that's going to be this year or next year. But the revolver has been a very good low cost capital source of funds for us, and I think we continue to see utilization on the revolver but we'll manage the short-term available liquidity on that with the long-term debt as we have in the past.
Ethan Bellamy: Okay. And then what do you think stands between you and the best credit rating now?
Gary Brauchle: I think there's probably elevate of size and magnitude of just complete cash flows and those type of things. I think that they are becoming much more comfortable with Rockies Express and our also doing that on Pony Express, and I think that we just need to continue to have those conversations. Those conversations evolve over time, and the metrics that they look at change over time and so we're - I can't tell you I have a perfectly clear answer for you to now but we continue to work through that with them.
Ethan Bellamy: Okay. And then could you talk about the volumes maybe on monthly basis on Pony? And is there anything at all we can take away from that as to the long-term re-contacting or rate environment on Pony?
Gary Brauchle: Yes, Ethan, I mentioned in my prepared remarks that that April was about 335,000 barrels a day and May, preliminary May nominations are about 350,000 barrels a day. One thing - so those are obviously very strong volumetric figures for Pony and the quarter was about 200 - the first quarter is about 290,000 barrels a day, so again very strong. The deficiency payments, I think, is something that maybe you wrote about today and over the course of history, Pony has seen deficiency payments on a quarterly basis anywhere from $2 million to $14 million. And so this quarter's number at about $8 million is not concerning to us and I'll tell you that there's primarily one shipper that has been running may continue to run deficient and so. But on the other side of that coin as we have seen shippers run incremental to their minimum are committed volumes. And so the deficiency payments are not concerning to us. It's certainly at a level that we saw in the first quarter and based on historical performance and, Bill, Dave anything you want to add longer term on Pony volumes?
David Dehaemers: Yes, I would just add a bit to that. So, Ethan, again just repeat, 290,000 barrels in the first quarter, 335,000 in April, 350,000-plus in May, that's all trending good. Some of that is Salt Lake City refineries been down a little bit, so we're getting the benefit of that a little bit. But like Bill said we're having very, very good conversations with a lot of people. We have told you about the success of your having with Platteville and what that's going to be on that iron horse is going and we are having a lot of meaningful conversations with our partner there. What's that again the...
William Moler: Silver Creek.
David Dehaemers: Silver Creek. And the producers there, we think that's going to be a homerun, a triple maybe be a homerun for volumes coming out of the powder. We're starting to have kind of dip your toe in conversations with some of our existing shippers on Pony. Again, it just takes time and I know everybody would love concrete answers as to what it's going to look like 18 months from now. That's just going to take some time. But everything is really looking up and it's hard to argue. 350,000 barrels a day in May. I would tell you also that we're going to spend the capital. It's not huge capital but we've already ordered some impellers, and we're going to make it so that day in day out, Pony can do from all the way down to Cushing in combination with nickel 425,000 barrels a day. So like we talked about before, 300,000 barrels a day at $3 is the same as 400,000 barrels at $2 is the same as 200,000 barrels a day at $4. So we feel very, very - did I screw that up somehow? We feel very confident and frankly are sleeping a lot better than it sound like a lot of investors are better people making up stories about us so ...
Ethan Bellamy: I appreciate that, Dave. Bill or Dave, maybe just one follow-up question on that. Is there anything else you can tell us about the commercial environment that the market may not be widely appreciating such as competitive pipes doing NGL conversions or just anything you're hearing from producers about their ability to make sure that they can move barrels, et cetera?
David Dehaemers: I'll just say what I'm going to say but you probably have much better things to say than I do but - we don't know for sure. We do so think some competitors in the DJ will probably convert some other line to NGL take away. Again, we're not sure on that but we've been on communications with them because, frankly, our pipeline may - if that were to happen may help take up some of the slack on their crude commitments, that's number one. Number two is, I mean it's the same thing, which is we sat if you go back and look at the record of things that we've said, I've always said to me what crude is going to be and I will tell you kind of what I think the economics are going to be on Pony. I was saying that two years ago, 2.5 years ago and I think that's playing true here. I don't know whether crude's going to be $40 again or it's going to be $80 or $100 per kind of in this period of $60 to $70 or $55 to $70, it has a lot of value, people's breakeven is a lot lower. There's a lot of drilling activity going on. We keep talking about the powder and activity there we're not really liberty to start naming names are everything but the activity looks really good. People are hitting that geology there are hitting really good wells. And by our way of thinking, Pony - we can argue about iron horse and competing with Genesis line or someone but Genesis line again is kind of a line to know where it's always good as where it goes. So Pony is really the main market out of for a lot of people. And it's kind of like having a gallon of water in the middle of desert, gallon of water may be worth $5 in a mountain value water cooler. But if it's in a middle of a desert it's not worth anything. And so the point being that a barrel of oil or 100,000 barrels of oil underground aren't worth anything to get it out to get it to market where it's liquid. So we feel really good about that. Bill, if you want to throw on top of that?
William Moler: What we're seeing, Ethan, is that DJ is ramping up. People need take away capacity. We're seeing and Wyoming mix suite being the favored crude flavor that's going for the ice value on the pipe and we're flowing incredible volumes right now Dave mentioned and part of it is due to the refinery being down. But I think we are people to get a handle on what pony can do. We're seeing our new refinery connections take more and more crude as they get used to it, still taking crude. We've got more volumes going to third-party connected refineries than we've ever had, and it's starting to prove our thesis is about making this a more of a market driven pipeline that is supply driven pipeline.
Operator: [Operator Instructions] We'll hear from Ted Durbin with Goldman Sachs.
Ted Durbin: Canadian barrels on Pony clearly the producers up there I would say getting nervous given that regular issues to grip there's any thoughts on getting Canadian barrels into Pony?
David Dehaemers: That's probably the best thing that we can say about it as we continue to work it. There is a very healthy spread for Canadian barrels versus WTI. It's a little bit like putting a puzzle together to get that barrel from Canada down to Guernsey, down to Cushing. And so we were working those puzzle parts right now and hope to be able to ship our first Canadian barrels sometime this year but there's a lot of parts and pieces that have to fall together to make that happen.
Operator: And we have no additional questions at this time.
Nathan Lien: Will give you the audience one more opportunity, operator, before we complete the call?
Operator: Absolutely. [Operator Instructions] No further questions, gentlemen.
David Dehaemers: All right. Well, everybody, thank you for your attendance on the call. I hope it was helpful. We've had a good quarter. Those of you that are co-inventors, we really appreciate you doing this with us, and thank you. Have a great day.