Summit Midstream Partners LP (SMLP) 2017 Q2 法說會逐字稿

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. (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.

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 that 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.

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 will turn it over to our CFO, Mat Harrison for a 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 1.11x. 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 was down 5.6%, due primarily to the seasonal nature of our maintenance CapEx activities.

Overall for the first half of '17, 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 1.15x. 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 back-end 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 expected, and we currently have 13 rigs running behind our systems, a huge improvement from the trough we experienced in the third quarter of 2016. What really drove us to lower our 2017 guidance is the expected delay in well completion activity by our producers. In most cases, like in the Piceance and Utica segments, this was really just a push to the right of a few months, whereby certain wells originally expected early in the second half are now expected to be commissioned later in the second half of 2017. For our Williston segment, the weaker crude environment that we've seen this summer led to reduction 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 than in any point in the past 3 years leads us to continued optimism about Summit's growth prospects.

Turning to the performance of our operating segments, we had an active quarter, which included a number of accomplishments that I'll highlight. In the Utica, our wholly-owned and operated Summit Midstream Utica system commissioned the TPL-7 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 of 413 million cubic feet a day, an increase of more than 135 million cubic feet over the first quarter of the year.

We currently have 1 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 the Summit Midstream Utica system to accommodate higher volumes than the current 0.5 BCF of capacity the system can handle. We're working on expansion of the systems 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 have 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 via the compression fee on the volumes we're currently gathering.

To the west of our SMU system in our Ohio Gathering JV, we commissioned the Larew Compressor Station in March of 2017. Adding 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 an incremental compression fee, which generates 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 2 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 segment's delivery point, the 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 is 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 lowered by 3% compared to the first quarter. Recall these 2 operating areas in particular have experienced a high-level of upstream M&A over the past 18 to 24 months, which has 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 6 rigs running upstream of our Barnett and Piceance/DJ segments. A level that is significantly higher than what we have seen throughout the current commodity cycle and a factor which we believe will drive cash flow stability in near-term growth for these segments. In the Barnett, 2 of the 3 rigs working in the entire basin are drilling in our service area, which along with the consistent level of work over activity in the area, should provide for volume growth throughput on the system by the end of '17.

In the Piceance, just last week, one of our existing customers, Caerus 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. Caerus is an existing customer of Piceance system has been one of the most active drillers in the area over the last 3 years. We maintain an excellent relationship with Caerus and look forward to expanding our relationship in assisting them and executing their future growth plans in the Piceance and the 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 are 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 liquids gathering business in the Williston basin gathered 68,900 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 natural production declines from existing wells connected to the system, partially offset by 6 new well completions that occurred late in the quarter. 3 to 4 rigs continue to operate upstream of our gathering system, a level which compares favorably to the 1 to 2 rig average we saw in 2016.

Consistent with my opening remarks regarding our financial guidance, the Williston segment is where we are 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 startup of the Dakota Access Pipeline.

So with that, I'll turn it over to Matt to review the quarter in a little bit more detail.

Thanks, Steve. SMLP reported net income of $11.2 million for the 3 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 build 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 a 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 a $17.5 million increase of the deferred purchase price obligation.

In conjunction with the 2016 drop down transaction, we recognize a 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 the 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 of 2017 totaled $72.6 million compared to $72.4 million for the second quarter of 2016. The second quarter of 2017 included $2.8 million of gathering revenue related to a 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. Relative to the second quarter of 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 segments. And by this decreased 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 segments. In most cases, we expect these well completions to occur later in 2017 than originally expected, and in some cases, in the first half of 2018.

Adjusted EBITDA in the second quarter of 2017 included approximately $15.7 million related to MVC mechanisms from a natural gas gathering and crude oil transportation agreement. Additional tabular detail regarding MVCs is included in the second quarter earnings release. Distributable cash flow totaled $50 million in the second quarter of 2017. This implies a distribution coverage ratio of 1.11x relative to the second quarter 2017 distribution of $0.575 per limited partner unit to be paid on August 14. Second quarter of 2017 was impacted by seasonally high maintenance CapEx. SMLP distribution coverage ratio for the 6 months of 2017 was 1.15x.

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. With $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 4.35x.

SMLP revised its 2017 financial guidance. Adjusted EBITDA was revised from our previous range of $295 million to $315 million to a new range of $285 million to $300 million. At the midpoint, 2017 adjusted EBITDA was reduced by approximately 4.1%. We expect SMLP's average full year 2017 distribution coverage ratio to range from 1.10x to 1.20x.

Now I'll turn the call back over to Steve.

Thanks, Matt. Consistent with our comments last quarter, we are 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 are evaluating accretive opportunities in the DJ, the Northeast and Western Colorado. It appears that producers are now more comfortable in executing their growth plans in a $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 a 60 million cubic foot a day gathering and processing system for XTO energy in Delaware Basin. We're thrilled to extend our relationship 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 with Delaware area hard, 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 produce water gathering. While there is certainly a healthy level of competition in the region, we think we are very well positioned with a premier anchored 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, who'll open it up for questions.

(Operator Instructions) And our first question is from Gabriel Moreen from Bank of America.

Steve, maybe I can start on the Delaware since you just finished up on that. Could you just talk about kind of how much of the initial 60 million capacity of the expectations are for XTO to be slowed 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 changed significantly as you see it today based on your success or lack thereof with getting third-parties into the system?

Yes. So I think that I'll take it backwards/forwards. I think the CapEx that we've announced is pretty well set for what we believe is Phase 1 of 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 -- last I heard was 19 rigs, it's 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 -- that sort of the base facility. We'll have third-party ability to track third-parties into that. Where it'll change is, if obviously, if we are successful and then have to expand a facility, and in the other places it will change as if we begin to add ancillary services like we talked about in our prepared remarks.

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?

Yes. So initially it's just gas gathering and processing. And we're having, I would say though, pretty active discussions with a lot of parties about other services, right? I mean, we do crude gathering and we do produced water gathering, and both of those are services that are going to be needed in this area. Most probably now that the water situation in the Delaware is pretty intense, I mean, you get sort of 3 to 5 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, it's long winded answer saying, it's gas and gathering and processing, but I think there'll be other opportunities for both XTO and others.

And then shifting over to the Piceance and Caerus, I mean, since they're obviously an existing customer already. Can you talk about kind of their plans for their new acquired acreage? Any discussions there around sort of the MVCs behind the legacy Encana properties? Any color there?

Yes. So they just closed last week. So it is obviously pretty new to everyone. But we know them well. Have been discussing for some time with them about multiple things out there. I think what you're going to see is them be -- so let's be clear of what they bought too. So they bought everything in the Piceance from Encana. So that everything means acreage in our area, existing area, and acreage in midstream assets, what we call north of the river up on the plateaus as you move further up to the northern part of the play. And so I think, they're going to be active in both areas. 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 up north as well too. So that's number one, just additional drilling up 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.

And Gabe, just to be clear. Caerus assume the MVC obligations of Encana. And then also during our kind of consent to agreement process, we have both agreed to remove an annual measurement and payment period to a monthly payment period. So from a credit standpoint that enhanced our profile a bit.

Did you have to actually change anything to get that modification or give up anything? Or it's just -- that's the way it went?

That's the way it went.

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?

Yes, I mean, I think if you look at -- we did it what 17,500 units or so -- I mean 750,000 units or so for $17.3 million in the second quarter. I think that's a pretty good pace, not so -- not very disruptive to the trading. So we're pretty pleased with how it works for the quarter. We expect to do more of that. That's part of our private pre-funding, that's in the plan for the pre-funding of the deferred payment.

And our next question comes from Tristan Richardson from SunTrust.

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

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, we have a -- they have a notice period to us and then we have a fair time to put in. I just think we are -- this has been pushed out further than we've thought for a while now. That's a good thing because it means -- it just shows you 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. And so as guys drill that dry gas area pretty hard, overall in the Utica, I think that's causing more discussions around when to 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 '18.

Now that's helpful, Steve. And just curious, I mean it does sound like based on y'all's comments that the second half calms down from a wells-turned standpoint from a really active first half, but given where the volume -- sequential volume you guys saw in the Utica, I mean, is it -- do you start to run up against capacity constraints? (inaudible)

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 high-pressure service on the TPL-7 connector. Those are little bit different volumes than our gathering volumes. Our gathering volumes are higher margin by default because our fee's higher because we have more invested capital. And so a lot of the growth -- not all of it, I mean, we had growth from the gathering side too, but a lot of it was just commissioning a project and we had pin up volumes. So to answer your question more finally though, we are evaluate -- that's roughly a 0.5 Bcf a day system or north of 400, we are 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 well capital cost. And so we are evaluating that and I think that gives us room to maneuver from what we're seeing here over the next 6 to 12 months. The important piece to the Utica story that's occurred -- and it started -- it occurred at the beginning of or end of the second quarter, beginning of the third is one of our big customers, SM started drilling in our SMU acreage, it's first time they started that, previously it had just been in XTO. SM has currently decent size position in -- at SMU acreage-wise, and they began drilling and we expect to start completing -- or them to start completing, us to start bringing on production for them in the fourth quarter and throughout the first half of '18, as well too. So that's why we're starting to look at hey, how do we get -- make sure we have enough capacity to maneuver. So it's all good news. Some of that, on our completion timing, some both in the Piceance and Utica, as I mentioned in the prepared remarks, is really a matter of couple of months. So again, I wouldn't put too much into that, it's just a matter of producer-specific issue and it moving from what we thought would be maybe September to November. But when you start talking about the level of volumes that are coming on, that matters from an EBITDA standpoint. So just matters on timing of it.

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

I thought you were going to say the final frontier there for a minute. As the play moves, the play is moving north. I think we got to be more careful about Northern Delaware and how people define that. We're north to Carlsbad by 20 or 30 miles, right? So as the play moves further up there, it becomes little bit a little bit oilier cut on the benches, and that's probably a 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 a 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. They're obviously one of, if not the largest holder in that area of acreage and it's pretty contiguous acreage. So that helps as well too. So -- and we got a great relationship with those guys. But I think, I would characterize it as our initial, what we call, Phase 1 with a $110 million of organic CapEx, we probably have 3x that amount pretty easily in just things that we're evaluating. We'll see if -- those aren't -- we got to win them, we got to get them. But it's a pretty -- it is a pretty active area to say the least.

And then did you guys disclose the size of the dedication? I don't remember reading that in the release.

We did not. No.

(Operator Instructions) Our next question comes from Jerry (inaudible) from Citi.

Just a few quick ones for me. So of course starting or going 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 kind of deferred by [a few] ones. Would it be fair to assume that a lot of these -- will the 4 wells or so that's guided will be more back end loaded in 2017?

Yes, I think we have, and Mark, you can correct me if I get it wrong from memory. But I think we have line of sight on 3 pads that are going to be coming on in and completed here in the back half. 2 of those -- one of those is definitely going to be in the third quarter, one's going to be either late third, early fourth in that timeframe. And then one of them, a fairly sizable one, is going to be later in the fourth quarter. That fairly sizeable one is one that we probably at the beginning of the year, we initially thought was going to be late third quarter and then move to late fourth quarter. So 2 months -- moved 2 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 -- there's significant volumes coming on. So that's a little bit of the timing issues we've talked about.

And in terms of rig count up 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?

Yes. I think we have one in -- just in SMU. I think we have a couple in OGC's -- 2 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 have 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 1 rig is, you still get a lot of volume growth from that. It's not -- this isn't an associated gas play where -- we talked about it yesterday. One Utica well is 5x the gas of a associated Northern Delaware well, just to give you a order of magnitude on an IP.

And then if we jump quickly to the Bakken. Can you just give us some more color around sort of downward shift in crude volume of the Bakken and kind of color for the next few quarters?

Yes. So I'll try, we had 2 to 3 rigs running on our systems through -- and a half throughout the first half of the year and that's pretty much was our expectation. What occurred when we had, I would say some volatility here in the second quarter in crude oil prices is several of our customers, our biggest one, who's publicly announced 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 there's still I think, what guys, 3 rigs running -- 4 rigs running on our systems today. So they will build -- if they hold to that, they will build a pretty significant DUC inventory. It'll 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 that activity, where we sit here today. But it definitely is a downshift from what we thought 3 or 4 months ago on just completion activity. The other thing of note that happened is SM pulled the sale of their acreage. And so SM has a pretty good DUC inventory themselves in that area and we would have expect when and if they do still that's the completion of those DUCs would probably occur by new owner. And then the other big news for us was Halcón selling their acreage to Bruin. A little early to tell on that, I'm not even sure if it's closed yet. If it has, it just has and so -- but we'll see how that pans out as well too in our area. So I would tell you the 2 things in the Bakken that have happened is delayed completions, just pushing to the right and then the sale -- the delayed sale of SM I think is -- was not our expectation. I don't think it was theirs either. So that's probably the 2 things that have occurred.

(Operator Instructions) Our next question comes from Sunil Sibal from Seaport Global Securities.

Couple of questions for me. It seems like Delaware could be a 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 -- seems like CapEx might surprise to the upside?

Yes. I mean, our leverage expectations and the way we operate haven't really changed. Right now, we're kind of running between 4x and 4.5x leverage. We're 4.35x at the end of the quarter. You'll see that work its way down to 4x. Long-term think of us as 4x levered and 1.1x or 1.2x covered. And so as we think about our different levers to pull from financing, whether it be ATM or other ways. We also have a growing EBITDA profile. The drop down assets obviously are high growth assets. So there'll be a lot of natural deleveraging going on as time goes to the right.

I would add too, Sunil. 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 chunky, and we feel like that's needed, we're not going to stress the balance sheet. We're also not going to give up what are pretty attractive organic opportunities. I'll make the point, we entered the Delaware with an existing customers who happens to be Exxon and we entered in an organic way. And we have no shortage of folks who would knocking on 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 that option's always out there too. I don't think we're capital constrained from that standpoint.

And then, I guess, 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 from some other midstream guys too in terms of rig ships et cetera. I was just curious, what are you guys seeing in terms of your operations between dry versus wet?

Yes. Very good question. So I'll try to give you some color and we're across all 3 of the windows. So we definitely saw -- I mean we actually had a decent amount in OGC and the JV had pretty decent amount in the second quarter of completions in wet gas window. So there definitely is 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 wells. So we have to be cognizant of that. So 1 dry gas well is a multiple of 1 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 fill that is through drilling big dry gas wells. And so they've been hitting that pretty hard as well too. And then second, ethane is not economical to recover right now. Ethane's about 40% to 50% of the barrel in the liquids window. And so that hurts your economics on the wet gas side and we're all staying tuned to some of the dynamics on the ethane side with some of the crackers that are coming on into this year and into next year. And see if that -- what that does. But that's, hopefully, that gives you a little bit color on customer, at least my discussions with customers on their thought process. I think the dry gas competes favorably, very favorably even in a normal NGL price environment, even with ethane recoveries, I would say the dry gas competes that favorably. The dry gas window of the Utica competes favorably with just about any play, including Permian in the U.S. from an economic standpoint.

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?

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

I'll just give you 1 data point. I mean, so we have 3 rigs going between OGC right now and SMU. Obviously, SMU, the 1 rig is dry gas, because it is a dry gas system. And then the 2 rigs at OGC, 1 is wet and 1 is dry, right. So we'll see folks coming in and out of the wet window. We had a couple of 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 the like. But we'll still see that window being developed.

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

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

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