Summit Midstream Partners, LP
Q2 2017 Earnings Call Transcript

Published: 4 Aug 2017

[Operator:]

Welcome to the Q2 2017 Summit Midstream Partners, LP Earnings Conference Call. My name is Nicole and I'll be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] Please note that this conference is being recorded. I'll now turn the call over to Marc Stratton. Mr. Stratton, you may begin.

[Marc Stratton:]

Thanks operator and good morning everyone. Thank you for joining us today to discuss our financial and operating results for the second quarter of 2017. If you don't already have a copy of our earnings release, please visit our website at www.summitmidstream.com, where you'll find it on the Homepage or in the News section. With me today to discuss our quarterly earnings is Steve Newby, our President and Chief Executive Officer; and Matt Harrison, our Chief Financial Officer. Before we start, I'd like to remind you that our discussion today may contain forward-looking statements. These statements may include, but are not limited to, our estimates of future volumes, operating expenses and capital expenditures. They may also include statements concerning anticipated cash flow, liquidity, business strategy, and other plans and objectives for future operations. Although, we believe that the expectations reflected in such forward-looking statements are reasonable, we can provide no assurance of such expectations will prove to be correct. Please see our 2016 Annual Report on 10-K which was filed with the SEC on February 27, 2017 as well as our other SEC filings for a listing of factors that could cause actual results to differ materially from expected results. Please also note that on this call, we use the terms EBITDA, adjusted EBITDA and distributable cash flow. These are non-GAAP financial measures and we have provided reconciliations to the most directly comparable GAAP measures in our most recent earnings release. And with that, I'll turn the call over to Steve Newby.

[Steve Newby:]

Thanks Mark, good morning everyone and thanks for joining us on the call this morning. As usual I'll begin with a few comments on the quarter and then I'll turn it over to our CFO, Matt Harrison for more detailed review on our quarterly financial results. I'll then wrap it up by discussing our outlook for the balance of the year. Yesterday we announced, our second quarter 2017 financial results which included $72.6 million of adjusted EBITDA, $50 million of distributable cash flow and a quarterly distribution coverage ratio of 1.11 times based upon our quarterly distribution of $0.575 per unit. Consistent with our expectations, adjusted EBITDA was up 1.7% over the first quarter of 2017, while DCF we found 5.6% due primarily to the seasonal nature of our maintenance CapEx activities. Overall for the first half of 2017 maintenance CapEx was in line with our financial guidance. However, it was higher by $3.7 million in the second quarter compared to the first quarter mainly due to seasonal activities. Distribution coverage for the first half of 2017 was 1.15 times. Before I turn the discussion towards our individual operating segments, I wanted to highlight our quarterly distribution announcement last week, in which we discussed our decision to lower the midpoint of our 2017 adjusted EBITDA guidance by approximately 4%. If you recall our original financial guidance for 2017 was backend loaded driven by an uptick in rig activity, upstream of our systems in the first half of 2017 that we expected would increase volumes and adjusted EBITDA in the second half of the year. Our drilling expectations have developed year-to-date as expecting and we currently have 13 rigs running behind our systems, a huge improvement from the [indiscernible] in the third quarter of 2016. What really drove us to lower our 2017 guidance is the expected delay, well completion activity of our producers. In some cases like in the Piceance and Utica segments, this was really just a push to the ride of few months, whereby certain wells originally expected early in the second half are now expected to be commissioned later in the second half 2017. For our Williston segment, we procured environment that we've seen this summer led to reduction in completion activity in completion activity by our largest Williston customer that will likely bleed into the first half of next year of 2018. So again, these are not loss volumes or permanent issues, but instead more of a timing discrepancy based on customer specific decisions. Further, we still expect to see sequential quarterly volume and adjusted EBITDA growth throughout the back half of this year. The building of a DUC inventory of our customers represents a future growth catalyst that we believe will have a positive impact on our results, in future periods. This growth visibility along with our commercial backlog being the most robust today that in any point in the past three years leads us to continue to optimism about Summit's growth prospects. Turning to performance of our operating segments, we had an active quarter which included a number of accomplishments that will highlight. In the Utica, our wholly owned and operated Summit Midstream Utica system commissioned the TPL7 connector project. This resulted in an immediate increase in volume throughput of more than 100 million cubic feet a day and helped us achieve a record volume for Summit in the dry gas Utica with an average 413 million cubic feet a day, an increase of more than 135 million cubic feet over the first quarter of year. We currently have one rig running behind our SMU system and expect several additional well completions in the back half of this year. As we discussed last quarter, we're reviewing options to expand this Summit Midstream Utica system to accommodate higher volumes than the current half of BCF of capacity the system can handle. We're working on expansion to system to 600 million cubic feet a day for very minimal capital cost. Basically some meter upgrades on the discharge side of the system. In addition, we've not yet installed compression on the Summit Midstream Utica system, we're currently evaluating the timing of this project and expect that we'll have compression installed sometime in 2018. Recall that once we install this compression, we should see an improvement in system pressures which should allow for higher gas flows and additionally [indiscernible] compression fee on the volumes we're currently gathering. To the west of our SMU system in our Ohio gathering JV, we commissioned Larew Compression Station in March, 2017. Addition compression to the Ohio Gathering has significantly improved pressures on the dry gas system, which in turn has enabled increased gas throughput from our anchor customer. Importantly, the addition of the compression to our suite of services in the play, is accompanied by incremental compression fee. We [indiscernible] additional revenues in all dry gas system throughput going forward. The Marcellus was another bright spot for us in the quarter generating average volume throughput of 480 million cubic feet a day, a 10.6% increase from the first quarter and the highest volume quarter for our Marcellus segment in more than two years. Higher volumes in the quarter were driven by Antero's decision to begin completing a number of wells in its DUC inventory behind our system, which we expect to continue into the second half of this year. Our Marcellus segments delivery point Sherwood Processing Complex continues to expand at a very rapid pace, which is in turn creating a number of commercial opportunities in the area. We believe we're well situated to participate in the portion of the volume growth that's occurring in this highly productive region. Moving to our Barnett and Piceance/DJ segments. Consistent with our internal expectations gathering volumes were down modestly with Barnett volumes lower by about 5% and Piceance/DJ volumes lower by 3% compared to the first quarter. We call these two operating areas in particular have experienced a high level of upstream M&A over the past 18 to 24 months, which is resulted in a number of new customer relationships for Summit. A number of these acreage trades have resulted in higher activity levels compared to the legacy operators and we currently have six rigs running upstream of our Barnett and Piceance/DJ segment. A level that is significantly higher than what we've seen throughout the current commodity cycle and a factor which we believe will drive cashless stability and near-term growth for these segments. In the Barnett, two of three rigs working in the entire Basin are drilling in our service area. Which along with the consistent level of workover activity in the area should provide for volume growth throughput on the system by the end of 2017? In the Piceance, just last week one of our existing customers Charis [ph] Oil and Gas closed the acquisition of Encana's Piceance operations. Encana was Summit's largest customer and had not been active in the area for multiple years. Charis [ph] who's an existing customer on our Piceance system has been one of the most active drillers in the area over the last three years. We maintain an excellent relationship with Charis [ph] and look forward to expanding our relationship in assisting them and executing their future growth plans in the Piceance and their ramp up of activity. In our DJ segment, activity levels remain high with both of our customers actively drilling in the first half of this year. Given this, we're exploring expansion opportunities on both the gathering and processing assets in this area. My expectation is that, we will have a more detailed update to share with you by the end of the year. Our liquid gathering business in the Williston Basin, gather 68.9 thousand barrels a day in the second quarter, a 9.8% decrease compared to the first quarter of 2017. Second quarter volumes were challenged primarily due to the natural production declines from existing wells connected to the system partially offset by six new well completions that occurred late in the quarter. Three to four rigs continue to operate upstream of our gathering system, a level which compares favorably to the one to two rig average we saw in 2016. Consistent with my opening remarks regarding our financial guidance. The Williston segment is where we're seeing the most completion deferrals which we believe is directly related to the recent volatility in crude oil prices. Partially offsetting that price volatility is the improved basis differentials as a result of the start-up of the Dakota access pipeline. So with that, I'll turn it over to Matt to review the quarter in little bit more detail.

[Matt Harrison:]

SMLP reported net income of $11.2 million for the three months ended June 30, 2017 compared to a net loss of $50.6 million in the second quarter of 2016. The second quarter of 2017 included $2.8 million of gathering revenue related to previously billed but unearned revenue and crude oil and produced water volumes that a customer trucked around our gathering system in the second half of 2016. Second quarter 2017 also included a $5.1 million decrease of deferred purchase price obligation. Second quarter 2016 included an impairment charge of approximately $37.8 million net to SMLP associated with the Ohio condensate stabilization facility and $17.5 million increase of deferred purchase price obligation. In conjunction with 2016 Drop Down transaction, we recognize the liability on our balance sheet for the deferred purchase price obligation to reflect the estimate of remaining consideration to be paid in 2020 for the acquisition of 2016 Drop Down asset. We discount the remaining consideration on the balance sheet and recognize the change in present value on the income statement. The change in present value comprises both a time value of money concept as well as any adjustments to the expected value of the deferred purchase price obligation. Adjusted EBITDA for the second quarter 2017 totaled $72.6 million compared to $72.4 million for the second quarter of 2016. The second quarter 2017 included $2.8 million gathering revenue related to the previously billed but unearned revenue in crude oil and produce water volumes that a customer trucked around our gathering system in the second half 2016. Relative to the second quarter 2016 natural gas volume throughput increased on our Utica Shale, Piceance/DJ Basins and Marcellus Shale segments. This increase was offset by natural gas volume declines on our Ohio gathering Barnett Shale and Williston Basin segment. And by this decrease of liquids volume throughout our Williston Basin segment in the second quarter of 2017 compared to the second quarter of 2016. The volume decreases were primarily attributable to deferred expected completion activities from certain of our customers in the Williston Basin, Piceance/DJ Basin and Utica Shale segment. In most cases, we'd expect these well completions to occur later in 2017 than originally expected and in some cases in the first half 2018. Adjusted EBITDA in the second quarter of 2017 included approximately $15.7 million related to MVC mechanisms from our natural gas gathering and crude oil transportation agreement. Additional tabular detail regarding MVC's is included in the second quarter earnings release. Distributable cash flow totaled $15 million in the second quarter of 2017. This implies the distribution coverage ratio of 1.11 times relative to the second quarter 2017 distribution of $0.575 per limited partner unit to be paid on August, 14. Second quarter 2017 was impacted by seasonally high maintenance CapEx. SMLP's distribution coverage ratio for the six months of 2017 was 1.15 times. CapEx for the second quarter of 2017 totaled approximately $31.5 million of which approximately $5.9 million was classified as maintenance CapEx. Also the partnership made $10.7 million of capital contributions related to Ohio gathering in the second quarter of 2017. We had $491 million of debt outstanding under our $1.25 billion revolving credit facility at June 30, 2017 and $759 million of available borrowing capacity. During the second quarter of 2017, SMLP amended this revolving credit facility and extended the maturity by 3.5 years from November 2018 to May 2022. SMLP also issued approximately 750,000 units during the quarter raising proceeds of $17.3 million. Total leverage as of June 30, 2017 was 4.35 times. SMLP revised its 2017 financial guidance. Adjusted EBITDA was advised in our previous range of $295 million to $315 million to a new range of $285 million to $300 million. At the midpoint 3017 adjusted EBITDA was reduced by approximately 4.1%. We expect SMLP's average full year 2017 distribution coverage ratio to range from 1.10 to 1.20 times. Now I'll turn the call back over to Steve.

[Steve Newby:]

Thanks, Matt. Consistent with our comments last quarter we're seeing a firming of producer sentiment this year, which is leading to not only an increase in rig deployments but also a strong uptick in commercial discussions and opportunities. I mentioned a few of these opportunities briefly in my asset level discussions but to reiterate, we're evaluating accretive opportunities in the DJ, North east and Western Colorado. It appears that producers are now more comfortable in executing their growth plans in 2.50 to 3.50 gas market and $45 to $55 crude market, which is leading to the highest level of commercial activity that we've seen in the past several years. In early July, we announced the new project to build 60 million cubic foot a day gathering and processing system for XTO Energy in Delaware Basin. We're thrilled to extend our relation with XTO from the Utica to the Permian and our team is working diligently to have that gathering and processing system up and running before the end of the second quarter of next year. Our commercial team continues to work the Delaware area had and we're having a number of fruitful discussions with additional operators in the area. We see a broad opportunity set and another exciting platform for organic growth for Summit. We expect this growth to include both our existing processing facility and also new and ancillary services, such as crude oil and produced water gathering. While they are certainly healthy level of competition in the region, we think we're very well positioned with a premier anchor customer and we expect to win our fair share of new opportunities. I hope to be able to share more details with you in the short-term about how these growth opportunities complement SMLP's existing business. With that, I'll turn it over to the operator and we'll open it up for questions.

[Operator:]

[Operator Instructions] and our first question is from Gabriel Moreen from Bank of America. Your line is open.

[Gabriel Moreen:]

Steve, maybe I can start on the Delaware since you just finished up on that. Can you just talk about kind of how much of the initial $60 million capacity? The expectations are for XTO to be slow and then how much you might be going out to get third parties and then I guess, would the CapEx that you're planning to spend change significantly as you see it today based on your success or lack thereof with getting third parties into the system.

[Steve Newby:]

So I think that, I'll take it backwards forward, I think the CapEx that we've announced is pretty well set for what we believe is Phase I in the project. I would think about in terms of just customer capacities, us having about probably close to half of the facility for third parties initially. And then, that could change obviously as XTO ramps up their activity. I think everybody knows, they're going to hit that pretty hard, I think the last I heard was 19 rigs, is what they're going to, in the Delaware overall. I expect some of those to be up in our area in the Northern Delaware, so that's how I would think about it, Gabe. I don't think our initial CapEx announcement of $110 million really changes based upon you know that's for the base facility, we'll have third-party ability to track third parties into that. Where it will change is if, obviously if we are successful and then have to expand the facility and then the other place it will change is if we beginning to add ancillary services like we talked about in our prepared remarks.

[Gabriel Moreen:]

And on the ancillary services, I mean are you doing everything for XTO out there just or I mean, are someone else doing some of those services for them.

[Steve Newby:]

Yes, so initially, initially it's just gas gathering and processing and we're having I would say though pretty active discussions with lot of parties about other services, right? I mean, we do crude gathering and we do produce water gathering and both of those are services that are going to be needed in this area, most probably know the water situation in the Delaware is pretty intense, I mean you get sort of three to five barrels of water for every barrel of crude, so that's another big area as well, that I think us and a lot of other Midstream guys are trying to get after. So I would say right now Gabe, its long winded answer saying its gas and gathering and processing, but I think there will be other opportunities for XTO and owners.

[Gabriel Moreen:]

Thanks Steve and then, shifting over to the Piceance and Charis [ph]. I mean, since they're obviously an existing customer already can you talk about kind of their plans their newly acquired acreage, any discussion there around sort of the MVCs behind legacy and Encana properties, any color there?

[Steve Newby:]

Yes, so they just closed last week, so it is obviously pretty new to everyone. But we norm well, have been discussing for some time with them about multiple things out there. I think what you're going to see is - so let's be clear of what they bought too, they bought everything in the Piceance from Encana, so that everything means acreage in our area, existing area. And acreage and Midstream assets what we call north of the river, up in the plateau's as you move further up to the northern part of the play. And so I think they're going to be active initially meaning in the near term, I think we'll get some more activity in our area in the near term is my suspicion and I think they'll be real active of north as well too. So that's number one, additional drilling activity. On the MVCs, we had active discussions with our customers all the time, this is a big one from just the size of the contract, we're not the only one out there that they have MVCs with, but we are actively discussing with them how to make it work, better for them and for us, I would say, overall they try to execute their growth plans. So nothing definitive yet, but I think there are lot of different possibilities that could occur.

[Matt Harrison:]

And Gabe just to be clear, Charis [ph] assumed the MVC obligations of Encana. And then also during our kind of consent to agreement process, we've both agreed to remove an annual measurement in payment period to a monthly payment period so from a credit standpoint that enhanced our profit a bit.

[Gabriel Moreen:]

All right, did you have to actually change anything to get that modification? Or give up anything? Or they just, that's the way it went.

[Matt Harrison:]

That's the way it went.

[Gabriel Moreen:]

Okay, cool. That's nice. Then just last question is on the ATM timing and pacing, should we just sort of assume with your liquidity that this is sort of going to be your quarterly pace going forward.

[Steve Newby:]

Yes, I mean I think if you look, as we did what 750,000 units or so, $17.3 million in the second quarter. I think that's a pretty good pace, not very disruptive to the trading. So we're pretty pleased with how it worked for the quarter. We expect to do more of that. That's part of our, part of the pre-funding that's in the plan for the pre-funding of the deferred payment.

[Gabriel Moreen:]

Got it. Thanks guys.

[Operator:]

And our next question comes from Tristan Richardson from SunTrust. Your line is open.

[Tristan Richardson:]

Steve, just wanted to clarify from your prepared comments. Did you guys say you were still assessing the compression investment in Utica or at this point, it's safe to say you already agreed to go forward with that?

[Steve Newby:]

I would say the former not the latter. The way that works Tristan is, it's a decision made by our customer. There to add compression, it's their decision. They have a notice period to us and then we have period of time to put in. I just think we're - this is been pushed out further than we've thought for a while now, that's a good thing because it means it just shows how strong those wells are there. I think we're getting to a point now as, and part of this relates to as more gas comes on in that area and it pressures up the long hauls, that flows all the way back to the field, if you want to think about it that way. So as guys, drill that dry gas area pretty hard overall in the Utica, I think that's causing more discussion around when they add compression. And so we're starting to get some clarity on it, I wouldn't tell you, we know whether it's going to be first half or second half, but we're starting to believe that it definitely could be 2018.

[Tristan Richardson:]

Okay, no that's helpful. Steve. And just curious I mean it does sound like based on your comments, the second half calms down from wells term standpoint from a really active first half, but given where the sequential volume, you guys saw in the Utica. I mean, is it - do you start to run up against capacity constraints? Day after day.

[Steve Newby:]

Yes, so in the Utica specifically I think it becomes important for us to start delineating volumes because we added a service there, which is a hot pressure service on the TPL7 connector. Those are little bit volumes than our gathering volumes. Our gathering volumes or higher margin by fall [indiscernible] because we have more invested capital. And so a lot of the growth, not all –growth from gathering side too, but a lot of it is just commissioned to project, we have pin up volumes. So to answer your question more finally though, we are evaluate that's roughly a half of BCF a day system. We're north of 400, we're evaluating a pretty easy expansion on that system to get to 600 that's really some meter on the discharge side, some meter issues. It's very low capital cost and so we're evaluating that and I think that gives us room to maneuver from what we're seeing here over the next six to 12 months. The important piece to the Utica story that's occurred, it occurred at the beginning of or end of the second quarter, beginning of third is one of our big customers [indiscernible] started drilling in our SMU acreage. This is the first time they started that previously have just been XTO. [Indiscernible] has fairly decent size position and SMU acreage wise and they began drilling and we expect to start completing or then to start completing, to start bringing on production for them in the fourth quarter and throughout the first half of 2018 as well too. So that's why we're starting to look at, how do we make sure we have enough capacity to maneuver, so it's all good news. Some of that on our completion timing, some of both in the Piceance and Utica, as I mentioned in the prepared remarks there is really a matter of couple months. So again I wouldn't put too much into that, it's just a matter of producer specific issue and it's moving from what we thought would be maybe September to November, but when you start talking about the level of volumes they're coming on that matters, from an EBITDA standpoint. So just matters on timing of it.

[Tristan Richardson:]

Thank you. And then I guess just last one from me. Could you talk just a little bit about the customer dynamic in the Northern Delaware? I mean is there, a lot of dedication still to be had, chunky ones or I mean or it seems maybe the last area to be buttoned up, but just kind curious, the landscape there.

[Steve Newby:]

I thought you were going to say the Final Frontier there for a minute. But as the play moves, the play is moving north. I think we got to be well careful about Northern Delaware and how people define that, we're north to Carlsbad by 20 or 30 miles, right. As the play moves further up there, it becomes little bit oiler cut on the benches and that's probably good thing for producers and you're right, it's an area that has a lot of potential for infrastructure I would say and an area still to be, I think there's still a fair amount of acreage that's undedicated. I would say as well too. So pretty good opportunity set up there as well for lot of different things. Like I said crude gathering, produced water gathering, gas processing, residues, takeaways, so it's - there's a lot of things that are going to have to occur as that play moves up there. We're not naïve, it's competitive in the Delaware overall for sure. We like our position, with XTO. We're obviously one of - it's not the largest holder in that area of acreage and it's pretty contiguous so that helps as well to, so and we got a great relationship with those guys. But I think, I would characterize it as, our initial, what we called Phase 1 was $110 million of organic CapEx, we probably three times that amount pretty easily and just things that we're evaluating. We'll see if - those are we got to win them, we got to get them. But it's a pretty active area to say the least.

[Tristan Richardson:]

No that's helpful and then did you disclosed the size of the dedication? I don't remember reading that in the release.

[Steve Newby:]

We did not, no.

[Tristan Richardson:]

Fair enough. Thank you guys very much.

[Operator:]

[Operator Instructions] Our next question comes from Jerry Zu [ph], from Citi. Your line is open.

[Unidentified Analyst:]

So starting or coming back to the Utica. What are you guys expecting for well completes in the Utica specifically you guys said that the timing looks like it's going to be kind of deferred by few months, would it be fair to assume that a lot of these, well the four wells or so that's guided will be more back end loaded in 2017?

[Steve Newby:]

Yes, I think we have and Marc you can correct me, if I get it wrong from my memory. But I think we have line of sight on three pads that are going to be coming on and completed here in the back half. Two of those, one of those is definitely going to be in the third quarter. One is going to be either late third, early fourth in that time frame. And then, one of them fairly sizable one is going to be later in the fourth quarter. That fairly sizable one is, is one that we probably at the beginning of the year we initially thought was going to be late third quarter. and it moved to late fourth quarter, so moved two months, but that's what I was sort of relaying, to Tristan that kind of timing when you're talking about the size, pads in the dry gas area of the Utica, those are significant, you know there's significant volumes coming on, so that's a little bit of the timing issues as we've talked about.

[Unidentified Analyst:]

Got it, that's helpful. Thanks. And in terms of rig count there. So you guys have one just right now running, do you guys expect to see any more coming on before the end of the year or no?

[Steve Newby:]

Yes, I think we have one in just in SMU. I think we have a couple in OGC. Two in OGC, so I think we expected SMU probably for that to continue. I don't know that we're going to add any. I will caution everyone that rig count and when you come out of dry gas Utica, we had this discussion internally too a lot. Those wells are big, big wells. You're talking about IPs from $10 million to $20 million per well. So one rig is, you still get a lot of volume growth from that. It's not - this is an associated gas play, we're - we talked about it yesterday, one Utica well is five times the gas of associated Northern Delaware well, just to give you an order of magnitude on an IP.

[Unidentified Analyst:]

Got it, yes no. I hear you loud and clearly. Thank you for that. And then, we jumped quickly to the Bakken. Can you just give us some more color around sort of the downward shift in crude volume in Bakken and kind of color for the next few quarters.

[Steve Newby:]

Yes, so I'll try. We had two to three rigs running on our system and have throughout the first half of the year. And that's pretty much was our expectation. What occurred when we add, I would say some volatility here in the second quarter in crude oil prices is several of our customers, our biggest one, who's probably announce they're going to delay completions, so they're going to build a DUC inventory, that DUC inventory for us in the Bakken today is probably 40 plus wells already. And they're still I think, what guys three rigs running?

[Unidentified Company Representative:]

Four rigs running.

[Steve Newby:]

Four rigs running on our system today. So they will build, if they hold through that, they will build a pretty significant DUC inventory. It will grow pretty significantly. We still expect some completions in the second half, it's not completely shut down. We have very good line of sight I would say in those completions, in activity. Where we sit here today, but it definitely is a down shift from what we thought three or four months ago on just completion activity. The other thing I've note that happens is SM pulled sale of their acreage and so, SM has a pretty good DUC inventory themselves in that area and we expect when and if they do sell that, completion of those DUCs would probably occur by new owner. And then the other big news for us was Hawthorne [ph] selling their acreage to Bruin [ph] morally to tell on that, I'm not sure it's closed yet but it just has and so we'll see how that pans out, as we to in our area. So I would tell you, the two things in Bakken that had happened is delay completions, just pushed in to the right. And the delayed sale of SM I think was not our expectation. I don't think it was their either. So that's probably two things that have occurred.

[Unidentified Analyst:]

Got it. That was very helpful. Thank you.

[Operator:]

[Operator Instructions] our next question comes from Sunil Sibal from Seaport Global Securities.

[Sunil Sibal:]

Couple of questions from me. It seems like, you know Delaware could be, pretty sizable opportunity for you guys and I was just kind of wondering, how do you think about leverage in this environment you know when your seems like CapEx might still priced for the upside?

[Matt Harrison:]

Our leverage expectations and the way we operate haven't really change. Right now we're kind of running between four and 4.5 times leverage or 4.35 at the end of the quarter. You'll see that work its way down to four, long-term. Think of us as four times levered, 1.1 to 1.2 covered. And so as we think about our different levers to pull from financing, whether be ATM or other ways, we also have a growing EBITDA profile, the Drop Down assets obviously are high growth assets. So there will be a lot of natural deleveraging going on as time goes to the right.

[Steve Newby:]

Yes I would add to Sunil that, I would say we have no shortage of people who would love to do things with us in the Delaware. If we have something that's very large and chunking, we feel like that's needing we're not going to stress the balance sheet, we're also not going to give up what a pretty attractive organic opportunities. I'll make the point, we entered the Delaware with existing customer who happens to be Exxon and we entered in organic way and we had no shortage of folks who would knocking our door, who would love to do stuff with us. So if we needed to do that, we would. I hope we don't because these are great opportunities. I think they're very accretive long-term opportunities. But options always out there too, right? I don't think we're capital constraint from that standpoint.

[Sunil Sibal:]

Got it and then I guess, and if you guys can talk about the dynamic going on in Utica, in terms of dry versus wet. How are the producers kind of reacting, I mean we're hearing some other [indiscernible] guys in terms of rec shift etc. I was experiencing, what are you guys seeing in terms of year operations between dry versus wet.

[Steve Newby:]

Yes, very good question. So I'll try to give you some color and we're across all three of the windows. So we definitely saw, I mean we actually had a decent amount of, I know as you see in the JV had a pretty decent amount in the second quarter of completions in the wet gas window. So there is definitely drilling going on there as well too. But I would say overall you're definitely seeing more weight towards the dry gas window. They also as I mentioned, they also are just bigger whales. So we have to cognizant of that. So one dry gas well is a multiple of one wet gas well, when you start talking about molecules that we transport. But you're definitely seeing a move to that. Now part of that is, we have some customers one in particular, who has a very large commitment to Rover and I think a very good way to fuel that through drilling big dry gas well. And so they've been hitting that pretty hard as well too. And then second, ethane is not economical to recover right now. Ethane is about 40% to 50% of the barrel in the liquids window. And so that hurts your economics on the wet gas side. We're all staying tuned to some of the dynamics on the ethane side with some of the crackers that are coming on, end of this year and into next year and see, what that does. But that's hopefully that gives you a little bit color on customer, at my discussions with customers on their thought process. I think the dry gas competes very favorably even inning normal NGL price environment. Even with ethane recoveries I would tell you, that dry gas competes that favorably. The dry gas window of the Utica, can reach favourably with just about any play including Permian in the US from an economic standpoint.

[Sunil Sibal:]

Got it. And I think you guys might have talked about this earlier. Could you remind me, if you had any commitments on Mariner East NGL pipelines?

[Steve Newby:]

We've not, no. we're watching it, but I wouldn't say we're the best one to comment on it.

[Marc Stratton:]

I'll just give you a one point. We have three rigs going between OGC right now and SMU. SMU, the one right is dry gas because is a dry gas system. Then the two rigs at OGC. One is wet, one is dry. Right, so we'll see folks coming in out wet window, we had a couple rigs in the wet during the second quarter as well. we'll see people coming in and out, whether it's for commodity price reasons, acreage reasons, development reasons and alike. But we'll still see that window being developed.

[Sunil Sibal:]

Okay, got it. Thanks for the color guys.

[Operator:]

We have no further questions at this time. I would like to turn the call back over to Steve for final remarks.

[Steve Newby:]

Thanks everybody for joining us and appreciate the questions. If you have anything please follow-up with us and be happy to answer it. If not, have a great weekend.

[Operator:]

Thank you, ladies and gentlemen. And this concludes today's conference. Thank you for participating. You may now disconnect.