TGE Q3 2019 Earnings Call
Operator: Good day, everyone, and welcome to Tallgrass Energy Q3 2019 Earnings Call. Today’s call is being recorded. At this time I would like to turn the conference over to Nate Lien, Treasurer for Tallgrass. Please go ahead sir.
Nate Lien: Thanks Corey. And good afternoon and thank you for joining the Tallgrass Energy quarterly earnings call. As we discussed TG results for third quarter of 2019, which were released through our press release this morning and 10-Q this afternoon. Joining me on the call are David Dehaemers, Chief Executive Officer; Bill Moler, President and Chief Operating Officer; and Gary Brauchle, Executive Vice President and Chief Financial Officer. Before turning the call over 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 October 30, 2019. Please refer to our filings with the SEC, which are available on our website, which provide discussions of factors that may cause actual results to differ from management’s 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 measures 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, everyone. And thank you for joining our Tallgrass Energy third quarter earnings call. At the outsell provide a brief update on the non-binding TEG Private proposal from Blackstone, as I know it is the topic on everyone’s mind. We’ll not address anything beyond this update on this subject, even in the Q&A portion of the call. As most of you can appreciate this is a very public and complex transaction in both sides, that being Blackstone and then the Tallgrass’ Conflicts Committee, are working diligently in pursuit of a potential agreement. Given that the process is ongoing we can’t provide any update beyond that. It’s not that we don’t want to, but just that we legally can’t. This process cannot and should not be rushed. And as we’ve said before, we are confident in the rigor and integrity of the Conflicts Committee’s process. As many of you know – I know many of you want to hear about the recently filed Pony Express rates, status for our re-contracting efforts; Cheyenne Connector and Hub enhancement 7c certificates that we received and then the management side letters. We will get to all of that in a few minutes. But first we’re going to talk about the outstanding third quarter financial results produced by our team in the company. Adjusted EBITDA was $264 million. Cash available for dividends was $211 million producing dividend coverage of 1.36 times for the third quarter. The performance drove TGE’s 17th consecutive quarterly dividend increase. I guess I would also just point out that since Black Stone bought the general partner in March of this year and they have been in our Board meetings and been part of that process we have raised the dividend three times with them owning the general partner. And so $0.55 for the quarter or $2.20 annualized, which is a sequential increase of 1.9% from the second quarter of 2019 and an increase of 7.8% over the third quarter 2018 dividend. With that, I’ll turn the call over to Gary for additional comments.
Gary Brauchle: Thanks Dave and good afternoon everyone. Moving to the segment performance for the quarter, the Natural Gas Transportation segment produced adjusted EBITDA of $142 million in the third quarter of 2019 which is roughly in line with the performance from the second quarter of 2019. The primary driver of the performance in the segment was the distributions from our 75% interest in Rockies Express, which have increased in 2019 largely as a result of the lower interest expense at Rockies Express and the increased rate on the Encana contract. For the Crude Oil Transportation segment, adjusted EBITDA was $88 million for the third quarter, which was also roughly in line with the second quarter of 2019, primarily as a result of continued, strong, average transportation volumes on the pipe. The quarter averaged approximately 365,000 barrels a day compared to 348,000 barrels a day in the second quarter. While deliveries were higher adjusted EBITDA was relatively flat, primarily due to the use of prior shipper deficiencies as well as lower deficiency payments during the quarter. So those two items contributed to the adjusted EBITDA being lower, although volumes were higher. And again that was prior – use of prior shipper deficiencies and lower deficiency payments during the quarter. The Gathering, Processing and Terminalling segment generated adjusted EBITDA of $36 million for the third quarter, which was $12 million higher than the second quarter. This was primarily a result of the annual Casper and Douglas plant turnarounds that occurred during the second quarter, as well as strong performance from both our water and terminal businesses in the third quarter. Now moving on to capital structure, at the end of the third quarter our leverage was approximately 3.5 times based on the trailing 12-month adjusted EBITDA calculated according to our credit agreement. When including our 75% share of REX’s just over $2 billion in debt our consolidated leverage for the quarter would have been approximately 4.5 times. As expected both figures are down from the second quarter due to continued EBITDA growth. And as for liquidity today we have an undrawn revolver capacity of about $825 million. Again, that’s $825 million representing ample liquidity to continue funding organic growth projects and additional bolt on acquisitions that we may identify and execute on. With that, I’ll turn it over to Bill for the commercial update.
Bill Moler: Thanks, Gary. The third quarter was again marked by very strong operational performance and a number of positive commercial developments that David alluded to in his opening comments. Let’s jump right into it. As most of you may have seen through various publications in mid-September, we finally received our FERC 7(c) certificates for the Cheyenne Connector and REX Cheyenne hub expansion projects. Just recently we received the associated notices to proceed on each project and DCP has exercised its option to purchase a 50% interest in Cheyenne Connector which we expect to close in the fourth quarter. In addition, we received an additional 200 million cubic feet per day contract on the Cheyenne Hub project, increasing our total commitments on that project now to 800 million cubic feet per day. Construction crews have been mobilized and work on both projects has begun in earnest. We are very excited about these projects and what it means for our customers and the broader markets in the DJ Basin and at the Cheyenne Hub. While we are solidifying our final construction timeline and associated in service date, we currently anticipate that it will push past the end of the first quarter. That said, we expect completion in the first half of 2020. In addition to these positive developments at REX, we resolved the final outstanding issues with the tight rate case pre-settlement agreement and have also agreed in principle to a settlement with our Trailblazer’s shippers and Trailblazer’s rate case, both providing future clarity and stability for both of those assets. In the Crude Oil Transportation segment, we continue to experience very high utilization of the pipeline’s available capacity with average daily throughput for the third quarter of approximately 365,000 barrels per day as Gary mentioned earlier. For October, we expect throughput to be near 380,000 barrels per day running an excess of 420,000 barrels on a number of days during the month. We also expect similar throughput for November based on our awarded nominations and in December we currently anticipate moving in excess of 400,000 barrels per day. Based on recent speed tests and work yet to be completed, we believe the pipeline will be capable of running in excess of 450,000 barrels per on a consistent basis. In addition, we have made significant progress on contracting Pony Express since our last conference call late in July. We currently have signed contracts in excess of 165,000 barrels per day for varying paths, with average rates plus or minus $2.50 and terms ranging from three to five years. In addition, we are in active and advanced discussions for agreements that could result in an additional, approximately 70,000 barrels per day with average rates also in that same range of around plus or minus $2.50. Finally, as is the case with many other liquid pipelines in the country, we believe that certain existing shippers will ship under their valuable history they earned over the past five years at the newly posted uncommitted tariff rates as evidenced by our strong October throughput and November nominations. I would emphasize that these posted rates, are short term incentive rates that are subject to change at any time. So in summary, as we re-contract Pony Express, we are achieving our goal of contractual diversity with appropriate value using our diverse system. What I mean by that is we are executing contracts for various paths, terms, rates with a diverse set of customers. Therefore you can expect to see take or pay contracts, but also other types of creative contracts that incentivize customers in different ways to use our pipeline. And finally on this topic, we are pleased with the level of contracting and the rates our team has been able to achieve in a very competitive environment and remain confident that Pony Express will generate a significant amount of cash flow for Tallgrass going forward. Turning to BNN Water Solutions, our team continues to pursue several acquisitions and organic growth opportunities within the basins we serve, inclusive of working to commercialize a large scale pipeline project in the Utica that would serve many of our existing Rockies Express customers. Finally, for a quick update on Pony Express expansion, Seahorse and PLT, we continue to make incremental progress on each but are not yet ready to announce FID on any of the three at this time. And now David will conclude our remarks ahead of Q&A.
David Dehaemers: Thanks Bill. So I’m going to conclude with remarks here and then we’ll go into the Q&A. I just want to say that given the recent interest in the letters, certain members of management sign in conjunction with the March 2019 Blackstone transaction, I would like to take a few minutes on that topic before we move into Q&A. In hindsight, these should have been called retention and lockup agreements. Most critics are looking at these agreements with the benefit of hindsight, but without considering and learning all the facts and circumstances at the time. Let me remind everyone of some of those facts and circumstances. People are fully entitled to their opinions, they’re not entitled to their own set of facts. And obviously for some of these facts you have to have a little bit of reasonable deduction versus just blathering on. The sale of the general partner of Tallgrass was a private transaction between the owners of the GP and Blackstone. Those owners at the time were Kelso, EMG, myself and a few members of my team. The key factor in that transaction is that Blackstone desire to own a hundred percent ownership of the general partner of Tallgrass in order to gain control of Tallgrass. There is a value in control and market transactions demonstrate that time and again. In this case the price for the private general partner was give or take $480 million. $480 million had nothing to do with the price per share other than it just so happened to work out to about $4 a share. For those of you that have to deal in pennies, that was $3.82 a share. If you take $26.25 and you subtract out $4 you get a net price for the LP shares that were sold of $22.25. Again, for everybody that wants to be more specific, $26.25 which was just a math add of $3.82 was what we were paid for, the general partner and $22.43 is what we were paid for our LP. No one other than Kelso, EMG and my team own any of the general partner asset and was never entitled to any of that through $4. So I want to make that clear. Blackstone also wanted certain protections around their significant investment in – Tallgrass primarily from specific members of the management team who also owned part of the privately held GP. Those protections, among other things required those individuals, including myself to retain a specific ownership interest in TGE to provide an incentive to grow the business. Non-solicitation agreement, non-competition restrictions, and lock up agreements relative to our ability to buy and sell our shares. So for example, I’ll just talk about myself. I agreed to a three-year noncompete agreement if I ever leave Tallgrass, which is significant to me. I agreed to 15-month lock up on not buying or selling any TGE, which again is significant to me. I’m unaware of any other shareholders there who simply own A shares, who would give up their rights to work in this industry for that period of time, or agree to not buy and sell shares for that period of time. So those were significant adders. As compensation for conceding valuable control and for agreeing to the other significant restrictions, Blackstone was willing for a short and defined period of time to purchase the retained ownership interest from these former owners of our general partner at the same price that was set with Blackstone in the March sale. It should be noted that approximately 1.5 million of those shares were Class D GP voting shares. Said another way they were GP controlled shares owned by four members of management and approximately 3.2 million of other shares owned by two members of management who agreed in March to sell Blackstone all their Class B GP voting shares. Again, speaking only for myself I will tell you that over the last seven years, aside from my GP ownership, I have accumulated over two million shares that I have bought. I’ve never sold a share until last March. I had numerous buys. You all can see that. And that is unlike some of our largest holders in 2019. If you guys really want to get at the root of why the stock has performed the way it has, I would encourage you to go look at the Form 3 Fs and Ds Chris, is that right?
Chris Jones: 13.
David Dehaemers: 13, Form 13.
Chris Jones: Yes Section 13 filings.
David Dehaemers: The Section 13 D filings. And look at our largest institutional holders the same ones who are complaining about the way these types of things have come to be and look at what they have bought and sold, okay. Again, I accumulated over two million shares. I never sold a share until last March. Furthermore, I was unwilling to complete that transaction unless I was paid the same price for every share I owned. Here’s another fact, it did happen a couple times after the – after the Blackstone transaction that we traded well above the $22.25 or again, for those of you that have to have the exact numbers, $22.43. In fact, on March, 2019, we traded as high as $25.96 cents for an LP unit or I should say an A share. On May 22 this year we traded up to $24.88. Stock price is down – it was down to around $14 or $15 when Blackstone made their offer and that was due to sellers, okay that you could identify in the SEC filings, it had nothing to do with Blackstone selling. Blackstone hasn’t sold a share, nor has management since then. Furthermore, if TEG Private does not occur or is not signed within the specified time period, those members of management will only be paid the value of the control and of the other significant restrictions which equates to the approximately $4 per share, $3.82 for their general partner ownership and that would occur this coming March. We would all then own our TGE equity at the same market value that everybody else does. It should be mentioned that the retention lock-up agreements do not cover all the equity in TGE owned by the members of management, which include a significant number of A shares owned outright and also unvested equity participation shares all having the value of what it is today, yesterday and tomorrow equal to the traded market price. I guess again, I would note on a personal level, I’ve never gotten a share of restricted stock in this company. Gary, Bill, some of the other members here have, and that’s what that paragraph is telling you. Their shares are valued at the same way your shares are valued. So in summary, any characterization that members of management are getting paid a higher value for giving up the exact same thing as LP owners is patently false, as is any other characterization that management engineered something where they had nothing to lose and everything to gain. The fact is we agreed to lengthy lockups, lengthy non-compete agreements and other valuable things that benefited all stockholders, not just Blackstone. Finally, regarding the Blackstone, TEG Private, I will add one other thing. One investor, and I use investor very specifically, I recognize there are short sellers in the market. But what investor among all of us does not want to buy at a lower price and sell at a higher price? Blackstone does not set the market price, period. In fact, I’ve already told you the market sets it. We’ve had more sellers than we’ve had buyers and you guys could easily build a picture of who the sellers have been. Blackstone has made an offer for which they would like to buy the rest of the company and take it private. That offer may or may not be acceptable. I earlier said that I would give you a little bit more colored later in the conversation about the Conflicts Committee. Let me tell you that we have three independent board members that are on the Conflicts Committee negotiating with Blackstone, or trying to come to some resolution on that. These three members, one of them I have known for over 40 years has been on the Tallgrass Board since 2015 when we took TEGP public. The other two have been on the Tallgrass Board since 2013, one of which I’ve known for over 20 years. It is a very independent Conflicts Committee and I know they will work hard to do the right thing. As always, I want to thank our employees for what they do every day to keep themselves and our community safe and our assets operating reliably. Thank you as well to our shareholders for their confidence investing in TGE. And to everyone in this call for your interest in our company. With that operator, we’ll turn it over to you to handle the Q&A portion of the call with Nate.
Operator: Thank you. [Operator Instructions] We’ll take our first question from Colton Bean with Tudor, Pickering, Holt & Co.
Colton Bean: Good afternoon. I appreciate the detail on Pony Express re-contracting and just two questions related to that. So the first, are those new contracts primarily tied to the Bakken given that Northeast Colorado doesn’t roll until the next year, or are they spread out geographically?
Bill Moler: They’re, spread out geographically Colton. We have some at Guernsey which is both Powder and Bakken and a few at DJ that are just new volumes coming on.
David Dehaemers: Yes, Colton I think it’s a good question. And Bill is right, I guess, that we had to tranch. I mean you hit exactly the Northeast Colorado stuff that we did contract for five years doesn’t come due until later next year. But having said that, without disclosing the particular shippers, and volumes and rates it is a mix of locations, et cetera. We have more under contracts than what we simply told you about. We’re just telling you about the new stuff.
Colton Bean: Got it. In regard to those existing shippers that you mentioned, you expect them to continue either on a walkup basis or maybe there is still potential to convert them to firm. Can you just characterize the scale of those shippers? Is that two to three large shippers or a multitude of smaller shippers?
Bill Moler: Colton, we can’t answer that question. We just can’t answer that question. But I will tell you that they are shipping or will be shipping under history that they earned and that history that they earned puts them in a regular shipper category. I wouldn’t categorize it as walk up. They can ship on that history as long as they flow that history. And we suspect they will continue to flow that history for an extended period of time.
Colton Bean: Got it.
David Dehaemers: Said differently Colton they have first rights on that volume to ship whether they’ve contracted or not.
Colton Bean: Got it. And just to clarify that, given the scaling of the volume incentive rates, the expectation is that that 2.50% that you’ve highlighted wouldn’t change materially for those shippers.
David Dehaemers: I think our highest walk up rate would be 3.25% if you looked at our tariff really hard. So I think we have three or four delineations depending on volume. And so I don’t know that I would agree that you ought to just characterize it as using 2.50% across the Board.
Colton Bean: Okay. But in regard to the scale, nothing to maybe to disclose there in terms of whether it would be higher or lower than that 2.50%?
David Dehaemers: Not this time Colton.
Colton Bean: Got it. Okay and then on Cheyenne Connector, I appreciate the detail there. Positive it’s moving to 800 million. I think as of Q4, so earlier this year you had noted that you had re-contracted about 30% of the west to east roll-off on Rockies Express. So with Cheyenne progressing, can you update us on where you stand there?
Bill Moler: We can, we had an open season for the available capacity that is coming up and due in November. That open season is on our EBB and on our postings, fairly public document. We continue to have some re-contracting from production in the Powder some in the DJ, in the fiancé. But we’re still working hard at it. I think when connector gets completed or as it gets closer to completion and especially the hub, which as a reminder Colton Hub has 800 million a day and the connector has 600 million a day. So the hub is capable of pulling gas from other pipes other than just the connector. But that is going to be supply that is going to fill all those gaps. As a reminder, our average flow volume of west to east in Q3 was 1.6 Bcf a day. The West Coast issues have resolved themselves as they did in Q2. And we’re back on path the supply is there. There’s a certain rate and term that we’ll contract with. And we’re looking forward to doing deals with our existing shippers and others.
David Dehaemers: I’d just add a little bit to what Bill said and say it may be just a little bit different way. We’re coming into a good period, I think, relative to weather wise, et cetera. And we’re happy to let the situation play out for a number of months here. We have gotten rates that are very acceptable albeit on a shorter tenure. But when the connector and hub go into service that 800 a day is going to show up right at the doorstep of REX. And that we believe on a long-term basis, will fill the gap at something that works for us financially as well as our shippers.
Colton Bean: Got it. And just the final one from me. So on Rockies Express, can you just frame how you’re evaluating counterparty exposure now given some of the movement we’ve seen in both debt yields and ratings among the natural gas producer community?
Gary Brauchle: Yes Colton it’s Gary. We’re continuing to evaluate potential counterparties the same as we always have and as is allowed under our tariff, we take the exposure seriously and if it’s a sub investment grade shipper on an existing pipe our tariff regulates how much credit we can accept from them. And so we’ll continue to deal with it in that regard. I think on the east end of the pipe, because we put a significant amount of capital into the ground, we were able to secure far more than what a normal, existing infrastructure asset would allow in terms of credit and we continue to hold that again according to our FERC tariff allowances. So we’re watching it. I can tell you that we talked last – and disclosed last quarter about one particular, very small shipper that that did default on their obligation. But as we continue to review monthly obligations from our shippers, none of them are significantly past due or represent any problems at this point that that we can see.
David Dehaemers: So across all of our pipes how much that we hold cash collaterals and equivalents Nate? How much?
Nate Lien: I don’t have…
David Dehaemers: You don’t have it the top of your head. Again I would supplement a little bit of what Gary says, particularly on the east end of REX the rates were that people are paying us for east to west movements Clarington West or actually very competitive and lower than a lot of other new build pipes where we just simply had to put in the compression and the new pump stations that we did. So that’s a good fact. And I think the other fact is, is that most of our FTE cut, I mean almost let’s just say 95% of our FTE customers are moving 95% of their FTE volumes in terms of actual molecule movements.
Colton Bean: I appreciate the time this afternoon.
David Dehaemers: You bet. Thank you.
Operator: Our next question comes from Michael Lapides with Goldman Sachs.
Michael Lapides: Hey guys, two questions real quick. First of all if you had to define it, how close are you on the incremental 75,000 barrels for Pony Express in terms of signing up that customer and having a little bit more certainty around that? That’s question one. Question two, can you kind of go around the different Pony expansion opportunities and just kind of give us, hey where are we on each of these? And we’ve been talking about these first six to 12 months that’s pretty normal in the industry. When you are thinking you’ll get closer to FID?
David Dehaemers: So was your first question on a really Seahorse when you talked about 75,000 barrels?
Michael Lapides: No, when you talked about the re-contracting at $2.5 a barrel on existing Pony, you said there was an amount that was already signed and then I thought you said you had another 75 that you thought you were close with.
David Dehaemers: Yes I got you. It was in the prepared comments, it was 70,000…
Michael Lapides: Okay.
David Dehaemers: That were close on agreements with. And let Bill take that second. Let me – and Bill will probably supplement what I say on the first here. If you look at what we’ve done from macro standpoint, I think, in 2019 we’re not including what I’m going to tell you about now, but in 2019, we will have spent a roughly $360 million on small tuck in acquisitions and/or expansion projects. Just this week or actually today with the Board, we approved somewhere roughly $75 million more in projects across the assets. Two of those projects were Pony type projects. And so do you want to kind of add onto that?
Bill Moler: Yes Michael, I think, that the 70,000 barrels and you said, it’s been a very competitive environment. We have fought hard four barrels and we have folks who were close to getting there. And I wish I could tell you exact timing. I wish it was tomorrow. But it’s a moving target at this point, hard to say exactly.
Michael Lapides: Got it. Thanks guys. Much appreciated.
David Dehaemers: Yes sure. Thank you.
Operator: [Operator Instructions] We will take our next question from Ethan Bellamy with Baird.
Ethan Bellamy: Hey gentlemen, g afternoon. There has been significant trepidation on the Street about a potential federal frack ban if certain democratic presidential candidates were to win. What do you see as your indirect federal land exposure of customers in Wyoming and Colorado? And how if at all concerned your customers appear to be about committing long-term under some of that sort of existential threat that some of those candidates might represent?
Bill Moler: Ethan, first I’d like to say that your vote matters. So I’ll put that out there for what that’s worth. Who knows if they’re going end up doing that. We do have some producers in Wyoming in particular that are on federal lands. We also have probably an equal amount of producers in Wyoming that are on a state or fee owned properties. Yes, I don’t know that federal outweighs the state and fee-owned, but we do have some. If there is a federal frack ban, I think, it is primarily going to impact us somewhat in Wyoming, which is tied to Powder barrels and potentially Powder gas volumes. But I will tell you that Wyoming is a very oil-friendly state. And that seems like – not saying it can’t happen, but that seems like something that would have significant pushback by the State of Wyoming.
Ethan Bellamy: Okay. Thanks Bill, I appreciate that. Dave, I appreciate you taking on the topic of the side letter directly. Just to close the loop on this if the G. P. Matthew ran through 3.82, I mean that gives you what, like 22 in change and the Blackstone take out is 19.50. So there’d still be a delta between compensating the G. P. insiders versus where the stock is now, firstly. And then secondly, I mean, what’s structured that way at all. Why not just do cash retention bonuses and sell a stock at the time of the deal?
Gary Brauchle: Yes.
Ethan Bellamy: I’m just kind of confused about why you guys did this [indiscernible]?
David Dehaemers: I’m sorry, Ethan, what did you say?
Ethan Bellamy: I just said cosmetically, at a minimum it does not look great.
David Dehaemers: Well, I can’t help the cosmetics. I mean it was a transaction between two private parties and again it’s fine for you to think about it the way you want to, you are entitled to that. But we had two parties here. If I would’ve had my way, it would have been a certain way, but we had to come to the middle. So less $3.82 you’re right, get you to $22.43, Blackstone offered $19.50. I have no control over where the market is and what Blackstone offered to that, okay. If we wouldn’t be having this conversation, if the stock was at $23 right, and Blackstone offered $23 plus a 10% premium. So I mean trying to make you feel good about that isn’t going to work. If you think that – my most valuable asset for the March transaction with Blackstone in my life was my general partner ownership, okay. And I wasn’t going to do the transaction, Blackstone wanted badly, badly for myself, Gary, Bill and others to continue to have ownership in the company. And we had Kelso and EMG who were going to get totally cashed out. And what we agreed to was we’ll leave some equity in the company, but for a period of time you have to give us kind of a put on that, particularly since you demanding of us that we not compete with you if we leave – after a period of time we leave, particularly since you won’t let us buy or sell anything. I would have been – I mean, again, history’s hindsight and you can choose whether to believe this statement or not. But I would love to have been buying a number of times here since March, just straight up. And so that’s pretty much all I got to say about it Ethan. I did try to take it on directly. I told you the facts. Certainly any selling that has occurred to drive the price down, like I said, and I will reemphasize, has not been selling of Blackstone, or us, or GIC, or Enagás.
Ethan Bellamy: Okay. One more fundamental question Appalachian has been a real train wreck and most of the equities there have gotten punished and bond yields are inflated. Do you have any customer credit quality concerns either on the public or the private side? And how has the weakening environment there have impacted REX?
David Dehaemers: I mean, I’ll take a stab at it Gary might jump in. I think Gary somewhat tried to answer that on a macro level relative to how we watch it. I mean, you are exactly right. We do have customers there that at a $2.25 gas price and the production profile and the FT commitments they’ve made, we try to kind of answer that directly. In that what I said previously, which is all of our FT customers and were sold out on the east end are moving – 95% of our customers are actually moving 95% of the molecules. And they’re making it pay. I’m not saying they are making a lot of money and they may be actually, if they continue to drill losing money on a year-over-year basis, but they’re able to pay the tariff, and pay for their drilling costs, et cetera. It’s not a great situation, but we just continue to monitor it and don’t keep talking to them. Do you want to add anything to that?
Gary Brauchle: No, I mean, I think yes, I would. I mean, I think the things that I spoke of earlier and what we do we also monitor the shipments, we monitor the receivable collectability. And in a situation of default, we have obviously legal things that we need to make sure that we comply with, but we have claims that we can make, we have mitigation and remarketing. So those are all the things that we think of in terms of making sure that we get paid for the valuable transportation that we provide.
Ethan Bellamy: Thank you.
David Dehaemers: It’s not a little bit – there are so many different producers, right, some big, some small. I’m not telling you anything you don’t know. I’m just kind of vocalizing you hear that. And while we’re not able to have cartels in this country, but it’s nothing that a little bit of a supply demand discipline wouldn’t take care of. I mean our pipes are full, the gas is being used somewhere, but the fact of the matter is the reason the price is down is because there’s too much supply. And if there was some supply constriction there would be a healthier price and that might not be so bad for everybody.
Ethan Bellamy: Thanks for taking my questions Dave. I appreciate it.
David Dehaemers: You bet.
Operator: Our next question comes from Michael Blum with Wells Fargo.
Michael Blum: Thanks. Maybe just to continue along this last question that Ethan just asked, I guess I’m curious, have you seen any of your Northeast producer shippers on racks come to you and talk about some kind of renegotiation of the rates, blend and extend, anything like that?
David Dehaemers: Mike – Bill can add to this? We don’t want to talk about specific customers, et cetera, it wouldn’t be surprising to know that every customer that we have would always love to pay a lower rate. And so it wouldn’t be surprising to know that from time to time we get inquiries about that. But I wouldn’t say it’s anything that is – that we: a) can do and/or b) that has caused concerned to us. Do you want to add anything to that?
Bill Moler: No, I think that’s absolutely spot on.
Gary Brauchle: Then I would say it is not systemic either.
Bill Moler: No, not at all.
Michael Blum: Okay. But if I’m hearing you correctly, you’re saying you’re not really open to that at this point.
Bill Moler: Yes, I don’t think that was really the question. Your question was, are we getting questions about that from our shippers? Are we open to it? Everything is an economic analysis.
Michael Blum: Okay. And then the second question also on racks, but just more on the original legacy west to east contract, just if you have any update on how those talks are progressing? Thanks.
Bill Moler: I think we answered this with the first question. But we continue to work west to east, we continue to sign contracts of size and term on the west to east. We had an open season. That open season post the available capacity that is on the system, it’s a public document. And we are working hard to get connector and the hub done to flood Cheyenne with an incremental 600 million cubic feet to 800 million cubic feet more. And the closer we get to being done with that project, the more contracts and ultimately re-contracting will be done when that’s placed in service.
David Dehaemers: In an effort to be helpful here, Michael if you refer back to the presentation that we made in Las Vegas last year, 2018 where we took a great deal of time to kind of lay out on one or two pages, the differentials of EBITDA, perhaps in REX’s case post 2019, so 2020 and beyond, I would say that if you look at those carefully, we feel very comfortable that the two upper sides of that graphical representation are going to come to be.
Michael Blum: Great. Thank you.
David Dehaemers: You bet.
Operator: Our next question comes from Selman Akyol with Stifel Nicolaus.
Selman Akyol: Thank you. Just slightly different on gathering and processing those results came in while above what we were looking for. So I was wondering if you could just spend some time maybe discussing that and then sort of your outlook for that segment.
Gary Brauchle: Yes so I mean it’s Gary the Q3 results, as we know, were very strong. I mean, there were – first of all, we didn’t have the turnarounds of Casper and Douglas in Q3 that we experienced in Q2. So when comparing the two quarters, you need to just bear that in mind that Q2 was low because of that. We had the Grasslands and Guernsey terminals come in to service and contribute in Q3. We also had a full quarter of one of the BNN acquisitions and are seeing continued strength in the water assets, et cetera. And so those are the things that I would point you to relative to the very good quarter that GP&T delivered.
Selman Akyol: And so as you look forward – I apologize.
David Dehaemers: No, no, no. I was just going to if I could just add to Gary’s comments Selman. GP&T isn’t just simply that relative to another company as you might think about. As a GP&T company we do have water in there, we do have the unregulated terminals for Pony. We don’t have 10 different business for segments, but that is a segment that has a lot of – we kind of view it really as our unregulated safe segment in other words, and it’s not just gathering and processing. And so two things: one, as Gary told you about water and then obviously the new terminals at Pony that were additive to that. And then I think anticipating a little bit of your question, I don’t know that I would say that that is a – that quarterly run rate is kind of an annualizable number if that’s where you’re ready.
Selman Akyol: I do appreciate that. And then I guess just on the Cheyenne connector, just listening to you guys it sounds like it’s going to ramp very quickly once it comes online. Is that correct?
David Dehaemers: Yes, yes.
Selman Akyol: Okay, very good.
David Dehaemers: Yes.
Selman Akyol: Thank you.
David Dehaemers: You bet. Thank you.
Operator: [Operator Instructions] There are currently no questioners in the queue.
David Dehaemers: Yes I know operator that you asked just now, but if you just give another 30 seconds here and then ask one more time, we’d appreciate that.
Operator: Yes, sir.
David Dehaemers: Operator, you would you ask one more time please?
Operator: [Operator Instructions] And there are currently no questioners in the queue, sir.
David Dehaemers: Yes, so I would like to end with one thing. I kind of put one of our guys here, Nate on the spot a little bit earlier about asking what kind of credit, cash and cash equivalent credits we have on our shippers. We did find the answer in the meantime on that, we have well in excess of $200 million in collateral on REX that is kind of in cash postings and LCs kind of cash equivalents. So it’s not an un-meaningful number. And so anyway, I hope that’s helpful. Really appreciate everybody’s time. We took a great deal of care trying to give as much information as we felt comfortable on this call. And we hope it’s helpful to you all. And do appreciate everybody’s interest in Tallgrass. So with that everybody have a good evening.
Operator: Thank you ladies and gentlemen, for joining today’s Q3, 2019 earnings call for Tallgrass Energy. This concludes today’s teleconference call. You may now disconnect.