Energy Transfer LP
Q1 2020 Earnings Call Transcript

Published: 12 May 2020

[Operator:]

Greetings, and welcome to Energy Transfer First Quarter Earnings Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded.

[Thomas Long:]

Thank you operator, and good afternoon, everyone, and welcome to the Energy Transfer first quarter 2020 earnings call, and we really want to thank all of you for joining us today. I’m also joined today by Kelcy Warren, Mackie McCrea, and other members of the senior management team, who are here to help answer your questions after our prepared remarks. Hopefully all of you have seen our press release we issued earlier this afternoon, as well as the slides posted to our website. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Security Exchange Act (sic) of 1934. These statements are based upon our current beliefs, as well as certain assumptions and information currently available to us and are discussed in more detail in our Quarterly Report on Form 10-Q for the first quarter of 2020. I’ll also refer to adjusted EBITDA, distributable cash flow, or DCF, and distribution coverage ratio, all of which are non-GAAP financial measures. You’ll find a reconciliation of our non-GAAP measures on our website. And we expect our 10-Q to be filed later today. The current COVID-19 pandemic has impacted our nation in more ways than one. As we navigate through this uncertainty, we want to start today by thanking our team of more than 12,000 men and women across the country for their remarkable contributions and incredible commitment during this challenging time. We understand and appreciate the tremendous amount of hard work and coordination it requires to keep our assets running safely and efficiently while keeping the energy products moving both for the benefit of our partnership and our country. Now before addressing the current market conditions brought on by COVID-19 and the OPEC oversupply, I’m going to start with a few of our first quarter 2020 highlights. For the first quarter, we generated adjusted EBITDA of $2.64 billion and DCF attributable to the partners of ET as adjusted of $1.42 billion, and our coverage ratio for the quarter was 1.72 times which resulted in excess cash flow after distributions of $594 million. Adjusted EBITDA was adversely affected by inventory valuation adjustments of $213 million in the first quarter of 2020, which I will discuss further in the segment reviews. Without these adjustments, first quarter adjusted EBITDA would have been approximately $2.85 billion, and both adjusted EBITDA and DCF results would have been above our expectations.

[Operator:]

Thank you. At this time, we’ll be conducting a question-and-answer session. In the interest of time, please limit to one question and one follow-up question then rejoin the queue for any additional questions. Your first question comes from the line of Jeremy Tonet with JPMorgan. Please proceed with your question.

[Jeremy Tonet:]

Good afternoon. Just want to start off with discussing, I guess, your assumptions on the recovery post-COVID as far as both on the demand side and the supply side. Just trying to think through how you guys view the world, how that factored into your guidance. And if you could kind of bounce us off the agencies and if they were kind of comfortable with your outlook at this point.

[Marshall McCrea:]

This is Mackie. Yeah. Let me start and then Tom can follow up. As everybody knows, we’re in kind of unprecedented times that nobody could ever predict, the entire world - country be shut down. So things really got difficult kind of last part of April and then in May. However, how it’s impacting our assets in a couple of ways is we - for example, in our G&P assets, we have had some volumes shut in. However, just to give an example, in the Midland Basin, we’ve had about 8% of the volumes shut in. That was beginning of May. And as of today, we’ve seen about 25% of that turn back on. So as we look at that as an example and as we look through all of our assets in all of our segments, we see that things have bottomed out in our opinion and that things are improving and they’re going to grow. A lot of it, of course, depends on WTI, where’s WTI going to go. We are pleased by how it’s kind of strengthened and hanging in the mid-$25 range and the curves kind of show it growing throughout the rest of the year, and we’re pretty optimistic that’s going to be the path that we’re on. So, from an Energy Transfer perspective, we think things have bottomed out. How quickly they’ll grow remains to be seen. But we do expect, if not faster growth, at least gradual growth for the next quarter. And we’ve injected that in our projections and in our discussions with the rating agencies.

[Thomas Long:]

I’ll chime in. Jeremy, I’ll chime in here real quick on the rating agency part of it. We do continue to work with them very close as they continue to evaluate projections and et cetera. As always, we feel like we have great credibility with them. We’re going to continue to work with them. We’re also highlighting all the other levers, various levers that we have to pull, the CapEx like we’ve talked about, that aspect of it, the cost, several things that we’ve looked at. So, all-in-all, our dialogue with the agencies continued and we will, like always, just given the best information, the best forecast we have.

[Jeremy Tonet:]

That’s helpful. Thanks. And just wanted to touch on the CapEx side. What would get you to the other side as far as point down the incremental $300 million to $400 million for CapEx that’s under evaluation and how do you see CapEx trending in 2021 at this point?

[Marshall McCrea:]

This is Mackie again. We look at our projects, we look at the realization and timing of fueling those projects and some of the hurdles that we have. In addition to that, we consistently look at those projects that, as we’ve talked about, are down the road away but where it might make sense to push some of those dollars further out into 2021 or even further in some cases. So it’s if not day-to-day, certainly a weekly analysis that we make, and those are real dollars that we believe are quite possible that we could push out of 2020, getting us closer to that $3 billion range. But there’s a lot of unknowns right now. Certain things can happen in the Middle East. We heard Saudi Arabia cut another 1 million barrels today. I mean, there’s things that could really turn this around in a big way that would cause us to continue on the path we’re on and bring those projects on timely. But we’re certainly looking at it closely and we’ll do everything we can from the standpoint of delaying costs where it’s prudent and where it makes sense.

[Thomas Long:]

And we’re not trying to give guidance for 2021 right now, but I will say $2 billion or less, we do feel good about right now for 2021 and beyond.

[Jeremy Tonet:]

Great. That’s helpful. That’s it for me. Thanks.

[Operator:]

Your next question comes from line of Shneur Gershuni with UBS. Please proceed with your question.

[Shneur Gershuni:]

Hi. Good afternoon, everyone. Maybe to start off, Mackie and Kelcy, just wanted to touch on the CapEx side. I realize it’s difficult to make adjustments to the 2020 CapEx numbers when you’ve got so many big projects that are in flight right now. Tom just mentioned CapEx under $2 billion for the next three to four years. Is there a scenario where 2021 could be materially lower than $2 billion if we kind of have an environment that we’re in right now or a little bit better than what we’re in right now? I’m just trying to understand how low can CapEx go if we’re in an oversupply situation for crudes heading into next year.

[Marshall McCrea:]

Yes, Shneur, this is Mackie. Here’s how I’d answer that is that the projects, even some of the projects that we’ve deferred, we have commitments and, in many cases, demand charges that are kicking in. So it really doesn’t make sense at some point to delay those projects past a certain point, a certain kind of deadline for those so when the commitments and the demand charges kick in. So, to answer that question, do we think it could materially and say knock it down to $1 billion or less, that’s unlikely. I think Tom said it well, we expect it to be between $1.5 billion and $2 billion over the next three or four years. But certainly, depending on circumstances, we’ll continue to evaluate that up or down, but that’s a pretty good range right now.

[Shneur Gershuni:]

Okay. No, appreciate the color. And maybe as a follow-up for Tom. Appreciate the slides that you guys shared with us today and you have these sensitivities updated now for 5% to 10% for commodities and spreads and so forth. Just trying to understand the sensitivity around that. So, when I look at that today, do I look at your current guidance today and say there’s 5% to 10% of exposure there? But is that based on where NGL prices are today and gas prices are today and where spreads are today and so things would have to be materially worse to see the downside with respect to those types of sensitivities?

[Marshall McCrea:]

Yes, it is. That’s the short answer. It is based upon our current prices - both prices and spreads.

[Shneur Gershuni:]

Perfect. Thank you very much, guys. Appreciate the color. And please stay safe.

[Marshall McCrea:]

Thank you.

[Thomas Long:]

Thank you.

[Operator:]

Your next question comes from the line of Jean Ann Salisbury with Bernstein. Please proceed with your question.

[Jean Ann Salisbury:]

Hi. It seems like your expectation around spread earnings have fallen by a few hundred million dollars since the beginning of the year guidance, which is somewhat surprising, given the contangos in crude and refined product. Can you just say what the moving pieces are in that bucket, maybe the inventory valuations in there?

[Thomas Long:]

As far as the inventory valuations, we do not have that baked in to the guidance other than what we’ve reported here in the first quarter.

[Marshall McCrea:]

And I’ll follow up to that. On certainly the spreads across Texas on our crude business have tightened. However, offsetting that is we’re seeing in our storage business significant contango spreads that we haven’t seen in a long, long time that kind of counteracts the negative impacts to the narrowing spreads on the crude business.

[Jean Ann Salisbury:]

Okay. It looks like overall it went down, though, I guess, versus the last time. So is the - I guess the crude pipeline spread loss is bigger the contango spreads gain? I just want to make sure I kind of get it.

[Thomas Long:]

I need to make sure I’m following your question on this one. You’re saying went down or as far as the guidance goes?

[Jean Ann Salisbury:]

Yes. That’s it.

[Thomas Long:]

Oh, yes, yes.

[Jean Ann Salisbury:]

Okay. Cool.

[Thomas Long:]

You are correct.

[Jean Ann Salisbury:]

Thank you. And then is there - it’s kind of related to Jeremy’s question earlier, but is there a decline in overall US or Permian production that you’re using this year to kind of get to this forecast and kind of anchor that if it’s better or worse than that then you’ll be better or worse than that?

[Marshall McCrea:]

This is Mackie. I’ll start. As I mentioned earlier we have seen some shut ins and certainly it’s significant slowing down. However, based on where kind of WTI is now and our optimism that we think that we’ll see it kind of hang in there and start to strengthen, we think volumes will recover maybe faster than some others over the next 30 to 60 days. So we don’t anticipate notwithstanding some significant circumstances, we don’t anticipate volumes stand down where they are for any significant period of time.

[Jean Ann Salisbury:]

That’s really helpful. Thank you.

[Marshall McCrea:]

Yeah.

[Operator:]

Your next question comes from the line of Michael Blum with Wells Fargo. Please proceed with your question.

[Michael Blum:]

Good afternoon, everybody. Maybe just to make sure, just clarify one of the questions was just asked. So in the slide deck, the 2.5% to 5% of the pie that is labeled as spread, does that capture for your 2020 guidance? Does that - that captures your contango upside this year? I just want to clarify that.

[Thomas Long:]

Yes, it does.

[Michael Blum:]

Okay. Great. My other question was just on Frac VII that just went into service and then Frac VIII. Is Frac VII fully contracted? And where does Frac VIII kind of stem at the point? Or do you still have capacity left to turn out there?

[Marshall McCrea:]

Yeah, Michael, this is Mackie. Frac VII is completely full. It’s running at 97%. If you look at all of our fracs, we’re running significantly above the nameplate of those. And so those volumes were, of course, designated to go to Frac VIII. We’re able to extend Frac VIII out to 2022 because of the additional capacity that we have above nameplate. But right now, we have a lot of NGLs in and storage as we brought it on. And so some of it’s going out of storage but we’ve been running our frac full and will for a number of days and months as current status.

[Michael Blum:]

Thank you.

[Operator:]

Your next question comes from the line of Michael Lapides with Goldman Sachs. Please proceed with your question.

[Michael Lapides:]

Hey, guys. Thank you for taking my questions. Just looking at slides 4 and 5, the pie chart on slide for where you show the adjusted EBITDA breakout in 90% to 95% fee-based. Can you break that large piece of the pie into what percent of that is take or pay and what percent of that is you’ve got the fee or the tariff set but you’ve got volumetric exposure?

[Thomas Long:]

Well, Michael, I’ll start with start with that one. Probably if you turn to slide 5 in the deck, that’s the way we’ve captured it for 2019. I don’t know that that’s necessarily moving a lot. We obviously can follow up with you afterwards, but I think you can kind of see how much of that, from at least from a midstream standpoint, is fee-based versus keep-whole, POP, et cetera. And then if you look at the other pie chart beside it, you’ll see the MVCs. Is that the question you’re...

[Michael Lapides:]

Yeah. Kind of on remark, except I’m not just referring to the midstream segment, I’m referring to the entire business. So if I look on slide 5, the table on the right-hand side, like very easy question, how much of the EBITDA of crude oil is take or pay versus volumetric albeit fixed fee but volumetric? And same thing on interstate transport, like how much of that is take or pay?

[Thomas Long:]

And, Michael, we don’t have that broke out here right now. We’ll have to follow back up with you later this week.

[Michael Lapides:]

Happy to follow up with Bill and team offline. Hey, just one other question. Can you all clarify a little bit about the in-service dates on Mariner East 2X and just kind of what you’re seeing and when you expect the in-service? I know you mentioned it on the call in the prepared remarks, but can you just clarify the timeline for that?

[Marshall McCrea:]

You bet. This is Mackie. Well, first of all, we are bringing on additional capacity, about 25,000 barrels June 1, so that’s very positive and that is already committed with demand charges. And then we now have moved slightly from fourth quarter this year to first quarter of next year, and next significant expansion completion of Mariner. And then the final 2X, we expect to be completed in the second quarter of 2021.

[Michael Lapides:]

Got it. Thank you, guys. Much appreciate it.

[Thomas Long:]

Thank you.

[Operator:]

Your next question comes from line of Spiro Dounis with Credit Suisse. Please proceed with your question.

[Spiro Dounis:]

Hey, afternoon, everyone. Just want to go back to the cost cuts. You all mentioned in the slides, it’s like $200 million and $250 million for the year versus budget. How much of that showed up in the first quarter? And I guess how should we think about you realizing that the rest of the year? And then more broadly, how much would you characterize as sustainable so we could see it happening again in 2021 versus maybe just deferring out some costs?

[Thomas Long:]

Yeah. Listen, this is Tom. Do you mind is starting over with the question? When you started off, it came through a little fuzzy.

[Spiro Dounis:]

Yeah. No worries. Hopefully, this time works better. Just on the cost cuts, the $200 million to $250 million. Just curious how much of that showed up in the first quarter and then how should we think about you realizing those savings for the rest of the year? In other words, how much of that is really sustainable versus just deferred?

[Thomas Long:]

No, I would put all of it really as sustainable. And as far as how it’s spread through the year, it’s going to be spread very even through the year. If you really take the first quarter and evaluate that and then kind of go through - remember this is G&A and OpEx. So if you will kind of spread those throughout the year, you’ll see those. And we may - actually, as we continue to evaluate, we may be able to identify additional amounts there.

[Spiro Dounis:]

Okay. Perfect. Second one, just on M&A, I’d just love to get your mindset as far as that goes now. It would seem like this is an opportune time to consolidate the industry here. You guys have obviously not been shy about doing that in the past where you could. So I would appreciate your view right now of the M&A landscape both on individual assets but also just on corporate M&A, too.

[Kelcy Warren:]

Yes. This is Kelcy, and you’re correct, it’s just part of our business plan and always will be. We are - it’s all hands on deck right now to make sure our business is healthy and performing. But it is something that we look at every day. We talk about it every day. I will tell you one thing if there’s any guidance I’d give you on this is that we would not do anything that was not deleveraging. So you can then begin to look at possibilities that may or may not be there and that would certainly need to apply to wherever possibilities that were.

[Spiro Dounis:]

Very helpful. Thanks, everyone. Be well.

[Operator:]

Your next question comes from the line of Christine Cho with Barclays. Please proceed with your question.

[Christine Cho:]

Thank you. So if I could start with the CapEx, you guys say that 70% of this year’s CapEx is for projects that are more than half complete or to put the in-service this year or next year. For the $300 million to $400 million that you’re evaluating to further reduce, would you say that is looking to reduce spend on the projects that are supposed to come online this year or next year, and you’re maybe thinking about deferring it? Or are those reductions mostly types of projects that are contemplated to be in service post-2021?

[Marshall McCrea:]

It’s Mackie. I’ll start, Tom would follow up, but it’s a little bit of both. Some of the projects we’re optimistic and hopeful that we do come in under what our expectations and what our budget is. And then some of these are we - whether we get them completely by the end of this year or push them into next year, and then kind of the third basket is are there some that as we evaluate it as I said earlier over the coming weeks and months, does it make sense to defer those and push some of those projects in next year and out of 2020.

[Christine Cho:]

Okay. That makes sense. And then if I could go move over to the DAPL expansion, can you tell us how much you’re expanding it and what sort of flexibility do the customers have to potentially push back this in-service date if we are in a prolonged downturn? I’m just trying to reconcile the need for additional capacity versus the current outlook for production in the basin. And would be curious if this is one of those projects in that $300 million to $400 million being evaluated.

[Marshall McCrea:]

Certainly, it’s in that one of those baskets. But right now, DAPL has been such an incredible project and it’s been such a shot in the arm for North Dakota and really for our country so it’s got exceptionally well. Our open season went exceptionally well. We do expect to have expanded in 2021 and we’re hopeful to get the final regulatory approval soon. However, that doesn’t mean that depending on circumstances and depending on shippers and shippers’ interest and different approaches, that there might not be some options or some things we can do. But the bottom line is we have commitments. These are demand charge-based commitments for long periods of time. And if other arrangements are not made and we’re in service the second quarter of 2021, those commitments will kick in.

[Christine Cho:]

And are you able to tell us how much you’re going to be expanding by?

[Marshall McCrea:]

The open season is completed, as you know, and right now we anticipate expanding somewhere in the 740,000, 750,000 barrel range. That certainly can change as discussions go on but that’s kind of a ballpark.

[Christine Cho:]

Great. Thank you so much.

[Marshall McCrea:]

Yeah.

[Operator:]

Your next question comes from the line of Pearce Hammond with Simmons Energy. Please proceed with your question.

[Pearce Hammond:]

Yeah. Good afternoon, and thanks for taking my questions. Two questions here. First, other midstream companies have highlighted some strength in the LPG export business and it sounded like in your prepared remarks that you’re seeing the same. So I wanted to get some color from you on that. And then the second question which dovetails with the first, what is your outlook for ethane, propane, and butane demand this year? Thank you.

[Marshall McCrea:]

This is Mackie again. What an exciting part of our business. We needed to build fracs for all the transportation we signed up, then we needed to find a home as we kind of saturated - the industry kind of saturated the domestic market. We kicked off Mariner South a number of years ago, and that’s gone exceptionally well for us, and we’re close to adding another, as you heard, 300,000 barrels of LPG capability, and it’s much needed. With all the downturn and all the turmoil and everything that’s been going on the last 30, 45 days, that’s been a shining light. We have tremendous amount of demand. We’re in constant conversations. We’re in the process of selling out whatever capacity that we’re adding for some periods of time. And we see that to be a significant growth vehicle for our partnership for many years to come.

[Pearce Hammond:]

And then my quick follow-up pertains to storage upside, as well as on the SPR, but tell us a little bit more about the upside that you’ve got from your storage capabilities, and what does it mean being the successful bidder on that leased crude oil storage capacity in the SPR?

[Marshall McCrea:]

Well, as you can imagine, right now having storage of a number of products, of course, including crude is very valuable. Our existing Nederland and other storage that we have around the state and the country has been benefited in a big way and will for the remainder of this year. And the contango spreads and, likewise, the SPR winning that bid was important from the standpoint of revenue for us and locking in contango, but it also is as important for our producers. When it looked like there wasn’t going to be any markets and that all these barrels that we buy on a consistent basis and transport on a consistent basis to try to kind of make sure there was a market for all that we thought was necessary for our customers to find more space, more capacity for their barrels. And so, things certainly have slowed down on the market side but we needed that to have that, call it, market for all the barrels that we buy for our customers to make sure our customers’ barrels move.

[Pearce Hammond:]

Thank you, Mackie.

[Marshall McCrea:]

You bet.

[Operator:]

Your next question comes from the line of Ujjwal Pradhan with Bank of America. Please proceed with your question.

[Ujjwal Pradhan:]

Good afternoon, everyone. Thanks for taking my question. First one on the Haynesville Basin and some that you have operating there. We have heard from few of your peers on the growing interest in the assets and activity in the basin. Can you speak to what you’re seeing or what your expectations are across your gathering assets as well as the Tiger Pipeline?

[Marshall McCrea:]

Yeah. The Haynesville’s been an interesting area in that it had tremendous potential on growth a number of years and then slowed down for a number of years and now it’s got its second leg. I mean we’ve - on any given day, we’re moving 2 Bcf, and the interesting thing and the very beneficial thing about Haynesville and our Tiger system is it’s a bidirectional system. So, not only can we move east which is predominantly where gas has always wanted to go, but where now the interest is find its way back into Texas, into our intrastate network, ultimately finding its way down to the Ship Channel into LNG market. So, that’s been a very positive growth area for our assets. We expect those to keep Tiger full for many years to come. Likewise, a lot of the gathering assets we have kind of in North Louisiana, especially the gas that needs treating, even in these times when there’s been kind of some areas where gases - I mean, our products are being shut in. We’re seeing growth in the leaner gas plays which is, of course, the Haynesville play. So, that’s a really - as I mentioned earlier, at a tough time when a lot of gas and oil is being shut in, we see that as a growth area even as we speak.

[Ujjwal Pradhan:]

Got it. Thanks for that. And maybe on your expectation for positive free cash flow starting in 2021, could you please speak to the commodity price and spread opportunity assumptions baked in it? And how big of a priority this is for ET today?

[Thomas Long:]

Well, we’ve not put out guidance for 2021, as you know, but I think it is worth talking about when you look at 2019, we had over $3 billion of what we call retained cash flow. That’s above the distributions. When you really look at this year and you see where our guidance - where we currently have guidance, you’ll see that we have free cash flow, we’re right at that cusp. When you get to the $2 billion and less than $2 billion for 2021, you can really look and see what type of now free cash flow we have. And that’s what we’re going to continue to use as our EBITDA grows as these projects we’ve talked about today, that’s what we’re going to be using to start lowering the debt levels from that standpoint. But we’ll probably talk more about later in the year on 2021. Right now, it’s about looking at where you think the curves are, where the price deck - when you look out at some of the longer-term price decks.

[Ujjwal Pradhan:]

That’s helpful. Thank you.

[Operator:]

Your next question comes from the line of Keith Stanley with Wolfe Research. Please proceed with your question.

[Keith Stanley:]

Hi. Thank you. Wanted to start just with two clarifications. So, on the Bakken Pipeline, do you have firm commitments for most of that capacity step-up from 570,000 to 750,000 barrels a day, or is the expansion size larger than the commitments? And then second one was just, I want to confirm that the $200 million inventory write-down headwind in EBITDA for the first quarter, you’re assuming that headwind is in the $10.6 billion to $10.8 billion guidance for the year. So, absent that, the guidance would have been even $200 million higher.

[Marshall McCrea:]

I’ll start. This is Mackie. I’ll start with the first and let Tom on the second. Yes, in our open season we’ve got commitment for significant volumes and so the vast majority of the capacity we’re expanding is demand charge capacity. Of course, we’ve got a whole room for walk up and that type of capacity, but yes, the majority of it is demand. And as far as the second part of your question, I would say that the $213 million you saw in the first quarter, yes, it is baked into the $10.6 billion to $10.8 billion guidance we have.

[Keith Stanley:]

Okay. Great. And then Tom, on the balance sheet, can you just remind us though the leverage target for the company? And you talked about using free cash flow starting next year to potentially be a vehicle to pay down debt. Has the strategy changed at all on how you’re approaching the balance sheet and leverage just given what’s happened in the oil market?

[Thomas Long:]

Obviously a very, very good question, Keith, and no, it is not. We’re going to continue to target that 4 to 4.5 times. When you really look out at 2021, I know we keep using the free cash flow term, but we’re excited to get into that phase of being able to now start paying down the debt as you see projects come on, as we continue to pull the other levers of lowering some of the CapEx. So a lot of our growth is going to come from nothing more than a lot of the projects you’ve heard us talk about here today. But nothing changed as far as strategy goes.

[Keith Stanley:]

Thank you.

[Operator:]

Your next question comes from the line of Colton Bean with Tudor, Pickering, Holt & Company. Please proceed with your question.

[Colton Bean:]

Good afternoon. So just a quick clarification around the contango discussion thus far. I think, Tom, you may have noted that the 2.5% to 5% capture the marketing contribution there. But footnote looks like there should be some degree of earnings in fee-based as well. So is the bulk of the benefit showing up in spread or is the market base rate that you’re charging yourself, is that actually accounting for the majority showing up in fee?

[Thomas Long:]

I would not - let me think through that for a moment. We do have some showing up in the fee, any of the portion that’s held by the marketing arm but I would not say the majority of it, no.

[Colton Bean:]

Okay. And so fair to say that the market base rate has not moved up materially just given what we’ve seen in the last month and a half or so.

[Thomas Long:]

That’s correct.

[Colton Bean:]

Got it. And then just on midstream, as you evaluate your Northeast gathering footprint, can you frame for us the relative dry versus rich exposure and particularly in the condensate handling?

[Marshall McCrea:]

This is Mackie again. Yeah. Clearly, condensate handling has become an issue really not just northeast but elsewhere. We are working closely with producers and they really don’t have a lot of options to utilize some of our assets to help them move their condensate, how long this will last, who knows. Like we said earlier we don’t think it’s going to last a long time and things are going to recover, demand’s going to increase and we’ll find a home for that. But around the condensate, we really don’t see it as a long-term problem and we’re doing everything we can to help producers in the short term. And then I don’t know if that answers your entire question or not.

[Colton Bean:]

Yeah. That’s helpful. And I guess one, I guess, have you seen any curtailment date on condensate? And then two, just kind of your broader rich gas exposure relative to dry.

[Marshall McCrea:]

Yeah. I’m not aware of any condensate that has impacted ours, mainly talking about a condensate with other midstream companies where they’re looking for help for their home for their condensate.

[Colton Bean:]

Thank you.

[Operator:]

Ladies and gentlemen, we have reached the end of the question-and-answer session, and I would like to turn the call back to Mr. Thomas Long for closing remarks.

[Thomas Long:]

Thank all of you once again for joining us today. We really do appreciate your support. We really enjoy talking with you, and we look forward to follow-up calls after this one. Thank you.

[Operator:]

This concludes today’s conference. You may disconnect your lines at this time. Thank you for your participation.