Good day and welcome to the EnLink Midstream Partners Second Quarter 2017 Earnings Conference call. [Operator Instructions] I would now like to turn the conference over to Kate Walsh, Vice President of Investor Relations. Please go ahead. .

Thank you and good morning, everyone. Thank you for joining us today to discuss EnLink Midstream second quarter 2017 results.

Participating on the call today are Barry Davis, Chairman and Chief Executive Officer; Mike Garberding, President and Chief Financial Officer; Steve Hoppe, President of the Gas Gathering, Processing and Transportation Business; Mac Hummel, President of the Natural Gas Liquids, Crude & Condensate Business; and Ben Lamb, Executive Vice President of Corporate Development.

As you saw, we issued our earnings release yesterday and filed our Form 10-Q with the SEC earlier this morning. To accompany today's call, we have posted our earnings release and operations report to the Investor Relations portion of our website. Shortly after today's call, we will also make available a webcast replay of this call on our website.

I will remind you that any statements made about the future, including our expectations or predictions, should be considered forward-looking statements within the meaning of the federal securities laws.

Forward-looking statements are subject to a number of assumptions and uncertainties and may cause our actual results to differ materially from those expressed in these statements, and we undertake no obligation to update or revise any forward-looking statements.

We will discuss certain non-GAAP financial measures, and you will find definitions of these measures as well as reconciliations of these non-GAAP measures to comparable GAAP measures in our earnings release.

We encourage you to review the cautionary statements and other disclosures made in our SEC filings, specifically those under the heading Risk Factors. The structure of the call will be to start with prepared remarks by Barry Davis and Mike Garberding, and then leave the remainder of the call open for a question-and-answer period.

With that, I would now like to turn the call over to Barry Davis. .

First, Devon has tested new horizontal refrac designs on a 6 well pilot program and the results are very encouraging. Devon's refrac program increased production per well by 400% with cost as low as $650,000. These results could spur additional investments in the future by Devon and other operators in the basin.

Second, to further define upside in the Barnett, Devon is initiating a new rig line drilling pilot of 6 wells in the third quarter that will leverage improved drilling and completion technology. Results from this pilot are expected by year-end. And lastly, we remain encouraged by Devon's potential divestiture of Johnson County properties.

And we are hopeful that a potential divestiture could attract a counterparty who maintains a more focused development program in the basin. As we continue down our path of execution in 2017, our long-term vision remains unchanged to be the trusted energy company devoted to people, partners and performance.

In summary, by executing on our long-term strategy, we will deliver what we promised, sustainable, long-term growth for the company and its stakeholders. The volume growth we're achieving is driving higher cash flow results, and we expect continued momentum in the second half of the year.

Our near-term vision is to continue to do what we've always done, build and operate great infrastructure in the best places in the country. Over the long-term, we will continue to pursue strategic opportunities and expand across commodities and services.

And in time, achieve vertical integration of our business by connecting our facilities through pipe and contracts to link our assets in top supply basins to premier demand markets. With that, I'll turn the call over to Mike. .

narrowing annual EnLink adjusted EBITDA to $ 840 to $ 880 million for the year based upon results to-date and improved second half visibility, maintaining confidence in meeting our fourth quarter annualized exit rate for ENLK adjusted EBITDA of between $ 925 million and $ 950 million.

Executing on third quarter, EnLink adjusted EBITDA that is expected to be consistent with the performance during the first half of the year, inclusion of the legal settlement proceeds and current year ENLK EBITDA guidance and continued confidence in our Oklahoma and Permian growth.

The business has made tremendous progress this year, especially when you look at it with the backdrop of crude oil price volatility with crude currently trading between $45 and $50 a barrel.

We believe the focus of refining our guidance is our continued confidence in meeting our fourth quarter annualized exit rate for ENLK adjusted EBITDA of between $ 925 million and $ 950 million. To us, this is a key metric to focus on as it shows the capability of our existing business as we exit 2017 and continue to grow further into 2018.

Why do we have the confidence? First, all major construction projects are in operation including Chisholm II, Ascension, Chickadee and Lobo II; Second, key producers like Diamondback in the Midland Basin expect to execute well completions on existing [ decks ] during this year.

It's important to note that we don't require any wells to be drilled to meet our guidance expectations as we have around 40 to 60 decks on our system; Third, current rig activity in Oklahoma supports the volume growth we expect for the remainder of the year, for example, Devon has been experiencing tremendous well results in the STACK and is transitioning to full-field development in Q3 2017; Fourth, in Louisiana, Marathon is increasing its utilization of transportation on the Ascension system and associated liquid storage.

And finally, the increased activity in Oklahoma and the Permian support additional volumes on our Cajun-Sibon NGL system. Based on the caliber of our customer portfolio and active dialog we maintain, we have confidence in our key producer and end-market customers executing on their plans this year.

Turning to our current quarter, we continue to see solid volume and margin growth in both Oklahoma and Permian. However, we have seen a decline in margin in our crude and condensate segment in our Louisiana gas business.

The main drivers of the decline in our crude and condensate business are reduced margins in our Permian business, slightly offset by the ramping of the Chickadee system as well as volume and transportation rate decreases at our ORV assets.

The main driver of our decline in our Louisiana gas business was the expiration of a transportation contract in North Louisiana. Overall, we are committed to financial discipline and have strategically focused on lower risk, higher return organic growth projects in our core growth areas.

We continue to prioritize strengthening our leverage ratios, building distribution coverage and building the ability to grow distributions. Resuming distribution growth remains a long-term priority of EnLink. And as we stated before, we do have the opportunity to commence distribution growth at ENLC prior to ENLK.

I will now turn the call back over to Barry for concluding remarks, Barry. .

Thank you, Mike. I'd like to make 1 key point that I think is important to hit home before we wrap up. At this time last year, we had 18 rigs running on our dedicated acreage. Today, we have 57 rigs running on our system.

It's this 215% rig growth year-over-year during a tough commodity cycle that gives us confidence that we're in the right places with the right partners. Our path forward today is to continue to execute with excellence in all our core areas and to continue to do a great job focusing on what's within our control.

And what I know without a doubt is that we have the right people to do it. With that, you may open the lines for questions. .

[Operator Instructions]. And our first question comes from T.J. Schultz with RBC Capital Markets. .

So what were the key benefits with the ONEOK arrangement that made you choose that right on NGL takeaway as opposed to building your own pipeline?.

T.J., good morning, it's Ben. I'm going to start and I'll talk about what it means for our Oklahoma business and then I'll pass to Mac and let him talk about what it means for our NGL business. So the last call , we talked about this and what we said was that we would carefully consider all of the options that we have for our Oklahoma NGLs.

And that would include third-party transportation agreements, it would include joint ventures, it would include our own pipeline. And at the end of the day, the clear best option was to partner with ONEOK and let them provide a transportation service for us more inexpensively than we could provide it for ourselves.

And the benefit of that was an immediately cash flow accretive solution that required no capital whatsoever for us and yet left us complete flexibility downstream to do interesting things in fractionation including fill up the Cajun-Sibon system. So very, very happy with the partnership with ONEOK on this. .

T.J., this is Mac. And just following up Ben's comments there. Very, very clearly, the ONEOK alternative was heads and shoulders above the other alternatives we consider. And like Ben mentioned, we considered a broad swath of potential opportunities there.

Specifically, on the NGL side, in addition to the benefits Ben talked about, we'll have strategic connections directly from ONEOK systems into our Cajun-Sibon facility. So we'll be able to get those barrels literally from our processing plants through ONEOK system directly into Cajun-Sibon.

We will also have the ability to deliver those volumes into the Mont Belvieu area in order to have them fractionated there should we choose that long-term. We've got complete flexibility with regards to how we deal with the fractionation of those barrels.

So like we did on the transportation side, we'll look at all of our alternatives for fractionating those barrels, and we've got the complete flexibility in this agreement to do that. And another one is that it was immediately accretive to our 2017 earnings.

In other words, had we elected some of the other alternatives we were pursuing or considering, we would have paid a significantly higher transmission rate to get those barrels down to Mont Belvieu versus the long-term rate we're paying now. .

So again, very positive for us. And then finally, I think I just reiterate, one of the points Ben made and that is no capital required on our side for us to execute on getting these barrels down into Cajun-Sibon and very, very important in this environment. .

Okay. So just a follow-up.

When do you expect Cajun-Sibon to be full basically just looking for when you have that decision point on either additional frac capacity that you need at Belvieu or expanding Cajun- Sibon?.

Yes, T.J, again, this is Mac. We will continue to see Chisholm II volumes ramp-up and will contribute towards filling Cajun-Sibon. That's happening today. And we expect that happen over the balance of 2017 and 2018.

We're going to need to make a decision with regards to fractionation and/or what we do with our portfolio supply contracts on Cajun-Sibon some time in 2018. .

Just switching gears, one last one and I'll hand it over. In the Midland Basin, we've seen some commentary from producers on delays in drilling and completions, you guys are expecting utilization to ramp to [ 70% ], I think by the fourth quarter.

What line of sight do you have on some of these tasks getting completed into your system or is that ramp just from the Diamondback decks that you talked about? And then similarly any concerns on the pace of the ramp at Chickadee?.

Yes, T.J., this is Steve. Just to reiterate, we've got a number of decks in the system, it's not just Diamondback but it's other customers as well.

And we are -- we spent a lot of time in discussions with our customers and anticipating and planning for our capacity and we're in real close contact with them and we're very confident that in the second half of the year, that we're going to see continued growth in the Midland Basin and the volumes come online.

So we feel pretty confident about the projections that we have on the go forward and the volume, capacity that we're going to get to fill up that or the volume that we are going to get to fill up that capacity. .

T.J., I just wanted to visit with you to about Chickadee and follow up something there. The Chickadee system has really performed in the second quarter like we expected it to.

When we talked about it in the first quarter, we talked about it ramping into the second quarter and throughout the second quarter and leveling off to where we expected, really consistent operations through second quarter through the balance of the year. And as we look at the second half of the year, we still think, we're right in-line to do that.

We've got some bold on projects that we're currently executing on Chickadee that should come on, the majority of which should come on in 2017. And as our producers drill and complete on the schedules that they're telling us, that will benefit us to be as a dedicated acreage we've got to Chickadee.

So again, feel good about where we're at, feel good that the startup issues are behind us and the growth opportunities are ahead of us. .

Thank you, T.J. Appreciate the questions. .

Our next question comes from Jeremy Tonet with JP Morgan. .

This is [ Rahul ] on for Jeremy. Thanks for the updated guidance and all the other details on projects.

Now that we have more visibility into 4Q exit rate as the year progresses, is it reasonable to think that this run rate could potentially serve as a floor for the first half of '18, especially given the projects coming on at the end of the year?.

Yes, Rahul, This is Mike. So one of the key points we wanted to make with guidance was the point you made which was the confidence we have around the exit rate in 2017. We think if there is one big takeaway from the revision to guidance that is it. And it goes to, the key points we made as far as what has to happen to get to that point.

And we think, that's just a handful of things and we feel well positioned for that today. So as we look into '18, we feel that that run rate is going to be a great starting point for '18. As we talked about, we have additional projects coming on into '18 which would be the next phase of Chisholm.

We talked about the crude gathering ultimately in Oklahoma, the ramp of Chickadee. The potential or the ramp of Lobo. So I think as far as an expectation, that's a good expectation to have for '18. .

Coming to the North Texas, like you guys [ wanted ] the flattening of volume declines there and also gave some good details on Devon's equity.

So how do I think about the trajectory going forward for [ backup ] of the year in terms of volumes and also into '18?.

This is Steve. I am going to just start off first by just kind of reiterating what Barry had said. I think, it's real real important understand that we have been executing on our plan in North Texas. We have had success in offsetting declines, but we've been very focused in pressure reduction.

We see our customers adding some new wells and continuing with the refrac program like Devon and also looking at a new drilling program for the second half of the year. But we've also added some new supplies, like contracted new supplies to the system. So all of that is helping and it's really, really been a great story.

I think and our teams in North Texas are executing well. Specifically, to your question on declines going forward for the rest of the year. I think, that, what I'd say is that our prediction will be from 1.5% to 2% decline quarter-over-quarter for the second half of 2017, is where we're at today. .

Come to Oklahoma, like we have some margin expansion this quarter. And it appears that more volumes are going to be coming in.

Is this like a fair run rate in unit margin in the region as volumes especially from Devon continue to ramp?.

Hi Rahul, it's Ben. I caution you too much about trying back into unit margins because the Oklahoma business is complex and margins vary among customers and they vary according to the services that we provide.

But what I would reiterate though is the pace at which we see that business expanding is consistent with what you saw this past quarter, and I think if you look in the operations report, Page 26, tells that story.

After a few quarters of relatively flat volume, you have begun to see the expansion in volume that we expected and you are now seeing that translate into rapid increases in segment profit, not only in -- not only in the Oklahoma business, but also driving the NGL business going forward as well. .

And one final one for me.

Like how do you think about the total CapEx here for the Black Coyote project as it expense over time? Do you see like potentials for more -- room there like going forward or?.

Yes, yes, certainly. And you said the key words, as we expands over time. So crude gathering is a little bit different in this sense than gas gathering and processing, because you don't have a big processing plant expenditure that you have to make upfront. The system is inherently a bit more scalable to system volumes than perhaps a gas G&P system is.

So the upfront capital for Black Cayote this year will be in the range of $10 million to $15 million and that will be an ongoing capital expenditure year-after-year as our dedicated producer adds receipt points on the system. .

Our next question comes from Gabriel Moreen with Bank of America Merrill Lynch. .

Just couple of questions for me. I think, you had referenced the Mont Belvieu disruptions having a benefit to Louisiana segment in the second quarter.

Can you just talk about maybe what those were -- the degree of the benefit?.

Yes, Gab, this is Mac. And thanks for the question. We did mention that and the -- we had a couple of benefits to our NGL business in the second quarter. One is, just the continued volume ramp that Ben talked about from Oklahoma and then the other was some benefit from Mont Belvieu disruptions.

And simply what that was is -- is there was a party that had some maintenance going on fractionation in Mont Belvieu. And we were able to compete for those barrels and bring them into the Cajun-Sibon system, transport them over our fracs and fractionate that product in Louisiana. .

And I guess in terms of '17 guidance for CapEx, obviously you narrowed a lot of your other guidance ranges, but you didn't really narrow '17 growth CapEx expectations. I know, you've obviously touched a lot on growth CapEx that you are spending, in answers to questions, and your comments.

But can you just talk about the reasons maybe little more specifically, why not to narrow that growth CapEx range?.

Yes, Gab, this is Mike. We are about right on track with where you are expected to be on growth CapEx. The big piece of growth for us was the 4 big projects we've talked about within Oklahoma, Permian and Louisiana, and those all really came in on plan, on time and on schedule in the first half of the year.

That was the big driver of CapEx and got us to about that $ 380 million net to ENLK. Where we project to be for the year is between mid-to high, which would then project to be about an additional [ $200 million to $265 million ] for the remainder of the year. And that does include the Black Coyote within that number.

If we are able to execute on additional projects that could change accordingly but right now, we feel good about the guidance we've given on CapEx. .

And then a last question for me, just broadly speaking on resumption of distribution growth in '18 whether it's [indiscernible].

Any change in your thinking over the last couple of months, I know that you obviously are on track in terms of your plans, financially, but just in terms of philosophically, any thoughts there?.

Gab, this is Mike again. Not at all. I think, I hope, you hear from all of us the confidence we have in our business. I think that we've executed on the projects incredibly well.

That is what ultimately will drive the cash flow and you are seeing that in this quarter and ultimately see that in the exit rate we've talked about with regard to the guidance.

We think that sets us up well for distribution growth and our view is consistent with what we told you before with regard to distribution opportunities in '18 and then potentially at ENLC before ENLK. We keep focus on the balance sheet and we'll continue to build distribution coverage to get there.

But the big thing for us we always watch is the commodity price, the volatility around that. So what we'll do is always maintain our balance sheet coverage and have that capability and then watch that commodity price. Because we got -- we got to have the durability and consistency of that distribution increase. Thank you, Gab. .

Our next question comes from Darren Horowitz with Raymond James. .

Ben and Mac, if I could, I wanted to go back to your discussion around the value chain approach to move those NGLs on [ Chisholm ] and Cajun. Does it still make the most economic sense as you think about it to [ dilute ] Cajun, as it gets closer to full capacity.

And then also to the point that you all mentioned earlier about where you are going to fractionate those barrels either at Belvieu or other options.

Is part of that thought process, maybe the option to fractionate those barrels at [ Unis ] so that way that put you in a position to capture more fee and purity product sales benefit, especially when you think about leveraging the butane and natural gasing capacity that you guys have on Ascension?.

Darren, this is Mac. Yes, one of the options that we will look at to fractionate the barrels is to see what option we've got to move them over to our Louisiana fractionators.

One of the major benefits there obviously would be transportation revenue, another benefit would be the product sales benefit that you talked about to the extent that we can frac those at Unis or frac those at [ Plankamen ]. There are opportunities for us to earn an extra margin on the sales of those.

So that would be something that would be very attractive to us. I wouldn't say at this point, we've got a leading candidate for what the right answer is. We're going to evaluate all of our alternatives very thoroughly, really follow the process like we did on the transportation side and make sure we understand all of the alternatives.

And so, that's what we're going to do. Louisiana is certainly one of those alternatives, but it's not the only alternative. .

Okay, and then switching gears back to the Permian for a minute.

With regard to that 40% available capacity on the Midland system that you guys referenced, what kind of EBITDA uplift could you see hypothetically, if that system was running closer to full effect of utilization and as you consider the next phase of expansion, when you're looking at the magnitude and timing of supply growth.

Can you give us a sense from a capacity standpoint, what scale and scope, you might be thinking about to handle that volume uplift?.

Darren, this is Mike, on EBITDA uplift. I think, the way to think about that is the trajectory you can triangulate around where we're at on second quarter and use that to think about where we're at at full. I mean, there is some growth in Delaware. You'll see there based on the rig activity. But the big growth you'll see really is the Midland Basin.

And so, I would just use the second quarter run rate to think about what you could see ultimately through the remainder of the year and use that but the game changer continues for us will be the bigger growth we've seen on Delaware and that's probably more into '18. .

And Darren, this is Steve. In response to your kind of planning of capacity expansion, question, start with Midland Basin. We've completed a number of expansion projects in 2016 and in early 2017 on the gathering system. So we've got a lot of good capacity there that is ready and available.

We've always had about $ 400 million since we acquired and completed the Riptide plant in processing capacity. So we're in good shape there. As we move forward with next expansions in midland, it's what we've discussed a lot in prior calls, it's -- the next phase would be adding capacity at [ Riptide ].

We've got a very low cost option there to add another $ 100 million in Riptide plant processing capacity. So we're really well positioned to get Midland Basin into the $ 500 million a day capacity range at a very low incremental capital investment. Thank you, Darren. .

Our next question comes from Brian Brungardt with Stifel. Please go ahead. .

I guess just to expand on the crude gathering question earlier.

Is the larger picture here to get into crude transportation, say into Cushing or is it primarily to focus on the gathering side and help fill in the product offering for customers, especially Devon?.

Yes, Brian, this is Mac. Our crude strategy is very broad. It involves largely getting as much crude in the pipe as we can get.

We think, the first step of that is exactly what you've seen on the Chickadee side as well for the Oklahoma side and looking to ensure that we've got the capability to gather crude via pipe versus the truck where we can and add that kind of capability, not only in Permian but other growth basins like Oklahoma.

So we're doing exactly what our strategy had us layout to do, which is move from truck to pipe. Another phase in our strategy is to look at alternatives then to get our regional-based crude gathering systems better connected to major market outlets and potentially to connect inter basins with pipes.

I'd say that's down the road, but that's certainly part of the strategy that we've got and want and the things that we're looking out. .

And then just to again follow up.

Did I understand it correctly that kind of a run rate we think kind of $ 10 million to $ 15 million in CapEx in fiscal '18 and beyond to meet Devon's needs?.

This is Ben. $ 10 million to $15 million this year, what we know right now for 2018, I would say that's a fair estimate. That may change though in 2018 and it will change according to the producer's activity levels and need for future receipt points. And of course 2019 is far enough out that I wouldn't want to prognosticate on capital in 2019. .

Our next question comes from Mirek Zak with Citigroup. Please go ahead. .

Good morning, everyone. My first question is around Black Coyote.

Can you guys speak about third-party opportunities around that, and if any of that translates into opportunities around your Delaware Lobo assets?.

Well, Mirek, it's Ben. I'll start on Black Coyote system, which will initially serve Devon's need for crude gathering in the STACK. The initial connection point will be the Showboat project that Devon highlighted in their operations report about 25 wells beginning to come on in the first part of next year.

As far as third-party opportunities, there is certainly a third-party opportunity in Oklahoma for crude gathering that could be in the form of an expansion of the Black Coyote system. It could be in the form of other gathering systems because there is a variety of grades of crude they get produced in the STACK.

And so, we will work with our existing customer and our potential other customers to determine the right infrastructure to meet their needs, to segregate qualities that they want to see segregated. Help me again on the Lobo part of your question. .

Just seeing if this translates into opportunities around your Delaware and Lobo assets, possibly through shared customers or anything like that?.

Yes, Mirek, this is Mac Hummel. We are looking at other crude opportunities in the Permian both on the Midland side and on the Delaware side.

I wouldn't say that there's a direct tie between the opportunity represented by the Oklahoma crude systems, the Black Coyote system and the opportunities we've got in Permian, but that does not change the fact that we're actively looking at opportunities for crude gathering in the Permian. .

And on growth capital front, where do you see that going in the next few years relative to, say the past couple of years, which saw lot of infrastructure build-out.

And do you see that moderating a little bit in general, lowering your needs for external capital while still seeing top line growth?.

Yes, Mirek. This is Mike. That is going to be exactly what we're focused on. As you can see, the key drivers are going to be the continued growth in processing the associated gathering compression in Oklahoma. We're still on the same track as we've talked about before of every 12 to 18 months on a processing plant.

It's going to be the continued expansion. The Permian system as Steve mentioned, but I think one of the key themes you see is that we're doing very capital efficient projects focusing on building out our core-based systems. And so to your point, those are the, what I'll call, lower capital cost high return projects.

So that is our focus and I do you think you'll see that moderate. However, I will say that, you will find other projects that we're doing that could offset that. But again, we have a high bar to execute on those. And so, we will talk about those when we have that opportunity, but as forward-looking capital, that's a good way to think about it. .

Good to know.

And just lastly, any changes in your philosophy around your IDRs at this point?.

Yes, Mirek, this is Berry. And I would say, no change. We have been consistent in our communication there that we are not burdened at our partnership by the cost of capital associated with the IDRs. We've just begun to enter the 50% distribution. But we're very focused on it. We will continue to monitor it and make sure that we continue to feel that way.

So no change in our thought process. Thank you. .

Our next question comes from Ethan Bellamy with Baird. .

Mike, you've got a -- looks like you got about $ 100 million MVC run rate that I presume is about 80% Devon, and it looks like you've got about $ 90 million accounts receivable balance with them. What's the future of those MVCs? And that seems kind of like a lot of customer financing to me.

How should we think about that that financial relationship? And then -- and kind of more importantly, those contracts with Devon long-term, is there any chance that those get negotiated or is there any risk to that cash flow coming down in some future quarter?.

So this is Mike. Let's first talk about, how to think about the numbers. But what we reported in for the quarter was a run rate of about $ 14 million for the 3 months. And so we're right on track where we talked about, where for North Texas, for example, we think for an annual number, we think it be around $ 50 million.

Cana right now is running at about $ 4 million. We think that's going to change because of the Hobson Row was little slower than we expected, but we do feel over this latter half of the year, we'll be at or above MVCs. So I think the number to think about when you're talking about a run rate, MVC number for 2017 is more in that $ 50 million range.

So that's the starting point. With regard to how we think about the MVCs long-term, I would think about it differently between Oklahoma and North Texas. On Oklahoma, if you look at what Devon's done and consistently talked about the future is these large projects like the Hobson Row. They have another one starting in the fourth quarter of this year.

So what we expect is will be at or around the MVCs in Oklahoma based on their activity.

When you move back to North Texas, it really is exactly consistent with what Steve walked through earlier in the call of all the things we're seeing in North Texas and all the things Devon is doing in North Texas that really can change that trajectory of the decline ultimately.

So we think that's going to be the main solution that we're going to be looking toward is ultimately things where if Devon sells Johnson County of getting more activity there, Devon really looking at the refrac because of the success of those or third parties and refracs as well as looking at the new well results, we'll see over the latter half of the year.

We think all those are a big positive for North Texas. .

And about the the [ AR ] balance?.

For Devon, you are talking about?.

I'm just looking at the Q, and it looks like you guys have significant AR balance [ within ]. .

No, it's a case of timing issues all that is. So nothing more [ than it ]. .

And our next question comes from David Amoss with Heikkinen Energy. .

Just thinking about the earlier question about Midland Basin processing and your forecast to be 70% full by the end of the year, how should we think about the potential to [ FID ] that project to expand Riptide relative to utilization?.

Well, we haven't really worked in to our finalized projections beyond '17. So right now, it's not a big project really to -- from an expansion cases adding some residue compression is making some changes to our inlet facilities, so it's not going to be a long-term project.

It would just be about $ 30 million of capital spend and it wouldn't take us long to put it into service. Is that -- would, kind of the color you were looking for. .

Yes, so, I mean, so I read that -- tell you that you're going to do that [ neat thing ].

Is that a fair assessment?.

Hard to say, because we, again we're well positioned to do it very quickly. So it's not something that we feel like we've got a have a long-term plan for. It's something that we think that we can put together very quickly if we needed it and it's already really been engineered out.

So if the buyers, the volumes continue to increase, we're in a great position to pull the trigger on that and make it happen rapidly. .

And then just a similar question in the Del, it seems like you guys are doing a little bit of just-in-time build-out there.

Is there a point where you've had so much commercial success where you're going to have to move forward with more substantial build-out of processing in that region, possibly in '18?.

Yes, this is Steve again. I'm glad you recognized just-in-time building. We're absolutely trying to manage closely to that, but we are currently working on plans for the next stage of a processing capacity in the Delaware and we're working on developing what the scope and scale of that needs to be right now.

So you're right on track with us making those plans and trying to figure out those next steps. .

And then last question on the Merge play.

Just your thoughts about initial activity there and how quickly that may be become something more substantial?.

Hi David, it's Ben. The Merge has been such a bright spot for us. And honestly one that we didn't recognize had much potential at the time we made our acquisition about 18 months ago.

But we have 2 major dedicated producers down there in addition to a number of smaller producers and those are Citizen Energy who is doing the business combination, now will be called Roan Resources and Jones.

And I think that the market has not fully recognized the potential of the Merge because until recently, there wasn't a public company -- public E&P company to champion that play. And now, we're going to have 2 that are really focused there and they are both dedicated [ the unlike ].

I would encourage you to go back and look at Jones' communication from -- it was late last month about their initial wells featuring a couple of their bottom half wells that we gather, spectacular result. We really, really like what we see in the Merge play and we think the market is just beginning to understand it from the E&P side. Thank you, David.

.

Our next question comes from Craig Shere with Tuohy Brothers. .

I understand that you're really marrying future CapEx that's close as possible with production and EBITDA to be capital efficient that over time, the CapEx requirements might be more modest.

But you've detailed a lot out of potential projects including ongoing Black Coyote spend, potential timing and dollar size of the Delaware expansions, Midland, Riptide expansion, potential to convert [indiscernible] gas pipes and others.

Are you able to kind of get a sense in '18 about the potential growth CapEx range relative to 2017?.

Craig, this is Mike. We haven't given guidance yet, but on an earlier question we talked in and around that where we're saying that all the projects you mentioned are what I would call more capital efficient projects where it's a continuation of building out our core positions in the growth areas. You referenced the crude system in Oklahoma.

An incredibly capital efficient project for us and building right next to our G&P system. Riptide, Steve walked through on $ 30 million for $ 100 million capacity. And as you stated, we're trying to match capital, cash flows as best we can.

So we haven't come out with specific guidance on '18 yet, but I would say that we continue to push more towards what we will call the efficient capital projects.

And you seen that also in big decisions like we talked on our earlier, on the ONEOK, which was the right long-term decision for us with the ultimate business optionality but incredibly capital efficient. .

Well, I just that segue then in my next question, Mike, which is, do you feel like you're getting over the hump of covering attractive growth capital needs in terms of the balance sheet and any equity requirements.

In that, we are just getting close to that [ Nexus ] where you're going to have a very serious sequential EBITDA jump in fourth quarter and then next year is looking very interesting. At the same time, you're -- the major CapEx is a little behind us.

Do you feel like from a balance sheet position, you're getting increasingly comfortable?.

Craig, this is Barry. I want to start with that. I think, you've acknowledge something that really is the headline from the report for this quarter and that is we have done a lot of great work over the last 3 years in the midst of -- really a pretty challenging backdrop.

But we're on the -- right on the edge of really seeing the fruits of that good work, and when you look at the amount of capital that was required to invest on the front end in places like the Midland Basin, the Delaware and the -- and now the Oklahoma. I think, you've just hit the nail on the head.

We are at a point where we are really going to start seeing top line results and bottom line results from the investments that we've made there. And while we don't expect the capital expenditures to go down. It will go down, if you think about it on a relative basis to the size of our overall asset base.

And so, we're really focused on both on very efficient quick return to profits, if you will types of investments and I think that's what you've highlighted for us in your question.

Mike, you want to add to that?.

Yes, I would just say, Craig, we've been incredibly focused on our balance sheet during this time. We ended the quarter again this time with a debt-to-EBITDA of 3.9x and that's a big thing for us. And as you mentioned, as we see the cash come on from that, that continues to benefit the balance sheet. So we do feel we are in good position there. .

And, last question.

As we think about targeting distribution growth into '18, is there any kind of longer term coverage range you want to kind of share?.

Craig, this is Mike. What we've talked about publicly on coverage at ENLK is [ 1.1 ] or greater. Ultimately that -- we always look at the risk of the business and try to determine what coverage that should be. And as we've said to the market, we have very little direct commodity exposure.

So we feel good at starting to look at distribution increases post that 1.1. I will say though that we are focused on the underlying commodity price that's driving that, and that's a big factor and how we think about this.

I did mention earlier that we have to have consistent and durable distribution increases that to the market can look to and that's a big thing we're focused on. So -- but using that coverage is a good starting point. .

Just a quick follow up on that. We are seeing some midstream peers not being uncomfortable with even higher coverage to the degree that they still have robust growth CapEx and they don't want to rely on external funding as much.

To the degree your opportunity set remain strong, could we expect you to kind of allow that distribution coverage as EBITDA consent to be comfortably above the 1.1?.

Yes, that's a factor we will look at. So to your point if we continue to see robust capital and look at the capital markets and see what those capital markets really allow us to do, we will balance that with distribution coverage.

But we do think under all circumstances, distribution -- our growth in distribution coverage is a good thing and is a quick pressure to distribution growth. So that could be an option we would look at. .

Our next question comes from Matthew Phillips with Guggenheim. .

Thanks for taking my question. Going back to Oklahoma a bit here. Your volume seem to ramp pretty significantly in the second half of the year to hit the guidance you've laid out, I mean, I'm getting to around 1.3 Bcf a day for the second half on the gathering side. I mean, do you think you can hit those based on current rig count in the basin.

I mean, what should we be looking for there?.

This is Ben, I want to distinguish a little bit between the guidance that Mike reiterated in the script, which is for the whole company versus all the moving pieces that lie under that in the various segments. So very much on track to meet the adjusted EBITDA guidance as Mike described.

Now within the segments, things have moved around some and not surprisingly. In the case of Oklahoma, we have had a little bit slower start to the first half and so I don't necessarily expect the second half is going to be robust enough to hit the projection that we gave at the beginning of the year.

But the bigger picture is how has the resource played out? And the resource looks better today than it did even last quarter and massively better than it did the time we made the acquisition 1 year ago. And so, if I look into '18, I see continued robust growth in Oklahoma going forward from where we are today. .

This is Mike ,and I do want to reiterate the confidence we have on that exit rate. So that to me is that 1 point with the revision in guidance, we want to keep pointing toward is the belief we have and the confidence we have and executing through that. And Oklahoma, as you said, is a big piece of that. .

Anecdotally, we've heard instances of frac hits in the basin that's reducing IP rates on some of the newer wells.

I mean, is this something that you are all starting to see at all or concerned in terms of expect volume growth over the next year or so?.

This is Ben again, not at all. Not at all. I think, that what we have seen over the past quarter, I feel like the market is constantly looking in this environment for bad news. And I think that the normal course of producers understanding what they have in the best way to develop it inevitably involve some trial and error.

And I think the market has seized on some that feel more like the error side than the successful trial side. If you look at some of the positives that have happened over the last quarter, I would focus on for example Devon's Privott result, single well, 6,000 BOE, [ IP-24 ]. Best well ever drilled in the STACK.

Look at Newfield's report from last night, the Stark 9 well test trending above their type curve. Those wells come to us. Now we are very, very confident in the quality of the resource in the STACK and we think, we're only going to see it get better from here.

We acknowledge that it's going to take our producer some time to understand exactly the best way to develop the resource. .

Got it.

So you think it's more of a kind of a man by the [ Dog store ] and that the negative news is getting more play than the higher volume or positive results?.

Absolutely. Thank you, Matthew. .

This concludes our question-and-answer session. I'd like to turn the conference back over to management for any closing remarks. .

Thank you, Stephen for facilitating our call today. And for everybody only call, I just want to thank you for participation and thank you for your support, and hope you have a great rest of the day and the rest of your summer. Talk to you soon. .

The conference has now concluded. Thank you for attending today's presentation and you may now disconnect..