Ladies and gentlemen, thank you for standing by. Welcome to the EnLink Midstream Third Quarter 2017 Earnings Call. [Operator Instructions] Please note this call is being recorded today, Wednesday, November 1, 2017, at 10 a.m. Eastern Time. I would now like to turn the meeting 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's third 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. Our operations report provides support and detail in line with today's discussion.

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.

Actual results to differ materially from what is described in these forward-looking statements, and we undertake no obligation to update or revise any forward-looking statements. Additional information on factors that could cause actual results to differ from what is described in the forward-looking statements is available in our SEC filings.

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. .

Thank you, Kate, and good morning, everyone. Thank you all for joining us today. At EnLink 2017 is all about focused execution of the right plan in the right places with the right partners. As we look back at the third quarter of this year, EnLink continued strong execution of our plan, which produced solid financial and operational results.

ENLK achieved adjusted EBITDA of around $217 million for the third quarter, which is at the high end of the $198 million to $218 million range we provided last quarter. We are pleased to report that we are realizing the vast majority of the volume and earnings ramp we expected for the back half of 2017.

The event that will cast a shadow over 2017 will be Hurricane Harvey and the destruction the storm caused across Houston and parts of the U.S. Gulf Coast. The impacts were historic for the energy industry as well as for the countless people, homes and communities.

Overall, EnLink was very fortunate to sustain no significant financial or operational impact and there are 3 things that I want to highlight from the hurricane.

First and foremost, our employees stepped up admirably and performed exceptionally to prepare for and respond to the operational demands, challenges and volatility Harvey reaped throughout our industry. Our employees as well as our integrated system allowed us to successfully navigate these disruptions.

As a management team we are thankful and proud of how our team responded, not only to help EnLink, but also surrounding communities and neighbors. Second, the overall impacts of the storm on our system, volumes and throughput were immaterial and thus did not cause significant one-time operational or financial impacts to our third-quarter results.

And third, we were swiftly and safely back to normal business operations following the storm and today are running on plan across our footprint for the fourth quarter and the full year.

Based on our strong results year-to-date and the volumes and producer activity levels we've seen through October, we are reaffirming our 2017 full year adjusted EBITDA guidance of $840 million to $880 million, and we are also reaffirming the fourth quarter annualized adjusted EBITDA exit rate of $925 million to $950 million.

Our fourth quarter exit rate for adjusted EBITDA represents a 20% increase from fourth quarter 2016, which is very attractive growth, particularly in today's range-bound commodity environment. Strong volume growth drives strong cash flow growth for EnLink.

Increasing the strength and stability of cash flows from our high quality assets is a prime objective of ours and underpins the decisions we make. We are in the business of building and returning value to unitholders, and our execution and performance throughout 2017 is achieving this goal today.

As we sit here today we have a very clear path forward in continuing to build and return unitholder value. Our path forward is centered around 7 growth strategies, all within our core areas.

This is our right plan and executing these 7 strategies will enable us to continue generating strong, growing cash flows from our strategically advantaged positions. Our 7 growth strategies start with maximizing our strategic position in Oklahoma.

We believe we have the top strategic position in the core STACK, with all of the biggest producers in the area feeding hydrocarbons into our system. Our facilities are new. Our team is best in class. And we see opportunities for decades. Devon alone has advanced its STACK production by 26% year-to-date and in Q3 tied in 14 impressive Meramec wells.

Devon's multi-zone Showboat Project is well underway and they expect to tie 25 new wells during Q4. There is a lot to be excited about in Oklahoma and a direct result of this momentum is our recent gas processing announcement.

Our next 200 million cubic feet a day plant in the STACK, which is called Thunderbird, is expected to be operational in Q1 2019. Our second strategy is to increase utilization of our Midland Basin assets through our 25 customers and 300,000 dedicated acres.

We have best-in-basin customers like Diamondback, RSP Permian and Chevron, and have recently added Parsley to our top-tier roster. Our producer customers are reliably and consistently investing in their production programs and we are experiencing sustained, steady growth on our platform today.

Our third growth strategy is to continue building scale in the Delaware Basin. The Delaware Basin is a core growth basin for us following our investment 2 short years ago with our acquisition of the initial Lobo footprint.

With the announcement of our 200 million cubic feet a day Lobo III gas plant expansion, we are well underway with building scale in the Delaware. We will exit 2017 with 185 million cubic feet a day of gas processing capacity in the Delaware and, with our Lobo III expansion we will double that capacity by the end of 2018.

The growth from our Oklahoma, Midland and Delaware supply basins directly translates into our fourth growth strategy, expansion of our NGL platform along the demand-driven Gulf Coast. Today we are connecting hydrocarbons from our supply basins in the Permian and Oklahoma to our demand regions in the Gulf Coast.

Our goal is to expand our value chain from the wellhead to the Gulf Coast and expand the scale of multiple feed capture points along the NGL value chain.

Going forward, we'll continue to direct greater volumes to our Gulf Coast network, increasing revenues from transportation, fractionation, distribution and storage, along with increasing product sales revenue. We forecast that our Cajun Sibon NGL pipeline, which has capacity of approximately 130,000 barrels per day, will reach full capacity in 2018.

A key part of our NGL growth strategy is to determine the best option to optimize our NGL operations and connectivity in the Gulf Coast once Cajun Sibon is full. And we're actively evaluating our options right now. Our fifth growth strategy is capturing significant incremental gas opportunities with our franchise gas network in Louisiana.

Louisiana's total energy consumption ranks among the highest in the nation, largely because of an industrial sector dominated by their energy-intensive chemical, petroleum and natural gas industries, and our gas network has excellent connectivity into a number of key delivery points across Louisiana's Gulf Coast.

Louisiana is also home to the first large-scale LNG export terminal, and our assets are not only serving current LNG demand, but are also very well positioned to serve the next phase of LNG exports, which could represent a true step change for this growth strategy.

Our sixth growth strategy centers around our opportunity to repurpose our gas pipeline infrastructure in Louisiana into crude or NGL service. This strategy is exciting on 2 fronts. Number one, it's very cost effective. And number two, it has the potential to expand our Louisiana business into crude. We are well underway with evaluating this opportunity.

The repurposed pipelines could have several potential supply access points, one key access point being Cushing, Oklahoma, and the pipeline could connect directly into Louisiana's crude hub in St. James.

There are a lot of moving parts and a lot of work left to be done with evaluating this opportunity, including potentially entering into a strategic joint venture. Our seventh growth strategy is to proactively participate in the redevelopment of our position in the Barnett Shale.

Today we are more excited about the future of the Barnett than we have been since the inception of EnLink. We are definitely seeing potential bright spots emerge. Over the past 2 quarters we've seen 1 to 2 rigs regularly operating on our footprint, and that's activity we haven't seen on our dedicated acreage in the Barnett since mid-2015.

Another bright spot for us here is Devon's activity. Devon recently announced that due to the successful 6-well horizontal refrac pilot last quarter, they are expanding this program by an additional 6 wells in the fourth quarter.

Devon is also drilling 6 new wells in the Barnett to leverage improved drilling and completion technology with results expected in the fourth quarter. Devon is progressing well with the sale of its Johnson County properties and expects initial bids to be submitted during the fourth quarter of 2017.

As you can tell, we are really excited about the compelling potential of our 7 growth strategies, and I would encourage you to refer to our operations report on our website for the recap of our 7 growth strategies. We have a lot to accomplish, but the path is clear. It's straightforward. It's largely in our control.

And it's definitely in our wheelhouse. With that, I'll turn the call over to Mike. .

Thanks, Barry, and good morning, everyone. As Barry highlighted, we are very pleased with our financial and operational results this quarter. Adjusted EBITDA net to ENLK totaled approximately $217 million for the third quarter, representing around 10% growth year-over-year as compared to the third quarter of 2016.

This was at the high end of the range we provided last quarter and around $15 million greater than the second quarter after adjusting for one-time items. Distribution coverage was just under 1x for the quarter, even with the Series B preferred distributions converting the cash paid this quarter and our Series C issuance.

The business has made tremendous progress this year and this progress enables us to have continued confidence in achieving around the midpoint of our full year adjusted EBITDA guidance range of $840 million to $880 million.

We also have confidence in meeting our fourth quarter annualized exit rate for ENLK adjusted EBITDA of between $925 million and $950 million. The volume growth in the business is driving cash flows, as we had expected.

This quarter ENLC achieved cash available for distribution of approximately $55 million, which is in line with our expectations and represents a 7% increase from this time last year. Distribution coverage in ENLC continues to be strong, with the coverage greater than 1.15x for the quarter.

ENLC's cash available for distribution for the third quarter includes $6.9 million related to cash flow contribution from a 16% investment in EnLink's Central Oklahoma STACK assets. This amount has been netted with around $2.6 million in direct and indirect ENLK expenses.

Therefore, on a growth basis the assumed 100% cash flow contribution from EnLink's Central Oklahoma STACK assets is around $45.4 million for this quarter. The strength of the business is driven by being in the right places with the right partners.

This is clearly seen through the quarter-over-quarter and year-over-year volume growth in our core growth areas. And it all starts with Oklahoma. If you look at growth in gas processing volumes, we've experienced 20% sequential growth and more than 50% growth from the third quarter of last year.

We have connected 170 wells year to date in Central Oklahoma, have constructed 270 miles of pipe and have 27 active rigs drilling on acreage dedicated to our systems.

We're also on track and on budget to bring our Chisholm III gas processing plant online in late fourth quarter of this year, which will increase our processing capacity in terms of Oklahoma to 1 Bcf a day, representing 180% growth from 2 years ago. The Permian Basin has also demonstrated consistent growth.

In the Midland Basin we have seen gas gathering volumes increase 20% year over year, with around 14 rigs running in our acreage dedications.

We exited the second quarter this year with around 40 to 60 uncompleted wells on our Midland acreage and our producer partners have done a fantastic job completing many of those wells during the third quarter, as well as drilling of new inventory of wells to complete.

The Delaware Basin has continued to provide very attractive volume growth and rig activity. We have newly constructed, cost-efficient assets that serve 6 active strong producer customers who are committed to the Delaware.

We have 16 rigs running in our footprint, and when we look at year-over-year growth and [ the gap ] of earning volumes, we've grown by over 300%. Finally, Louisiana continues to exceed our expectations with gas gathering transmission volumes over 2 Bcf a day during the third quarter.

The downstream markets, including chemical, LNG and power, remained strong during the year and we see a tremendous opportunity to further supply the growing demand market. Throughout 2017 we have focused on building scale in our core growth areas through higher-return organic growth projects.

With lower-risk, higher-return projects underway, like our Black Coyote crude oil gathering system in the STACK as well as our processing expansions in the Delaware in the STACK, we will likely exit the year at the high end of our growth capital expenditures guidance range.

We don't think that these opportunities will decrease in 2018 and therefore we expect growth capital expenditures to have a range similar to 2017. To ensure we maintain a strong balance sheet we have proactively financed our growth with over $1 billion raised this year.

We had a successful offering of $400 million of perpetual preferred units during the quarter which alleviate the need to issue equity and enables us to prefund our last $250 million installment payment related to our 2016 Central Oklahoma asset acquisition.

From a levy standpoint we ended the quarter with debt to adjusted EBITDA of 3.7x, on track with our goal for the business.

Looking ahead to 2018, we are committed to maintaining our financial discipline, which means prioritizing the management of our leverage ratios and building distribution coverage, both of which will strengthen our ability to grow distributions. From a corporate structure perspective we get a lot of questions around our plans.

Today our focus is our 7 growth strategies and the strong returns we strive to achieve by growing in the right places with the right partners. However, we'll keep reviewing alternatives to ensure we have the right long-term structure for our business and ultimately our unitholders.

To ensure we have the right resources leading our focused growth in our core areas, we made some strategic senior management moves to enhance our team's alignment with our 7 growth strategies. We recently announced that Cindy Jaggi will now be our Senior Vice President, leading our Strategic Process Transformation team.

Cindy will focus on core processes within the company and data-driven decision making to ensure we truly are the best company in our basins. We also elevated Dean Mueller to Senior Vice President of Operations for Oklahoma and North Texas.

Dean has been a core resource for us in Oklahoma and is key for us in continuing the pace of growth we are achieving. And with that, I'll turn it back to Barry. .

Thanks, Mike. And before we open the call up for questions, I'll build on what Mike said about Cindy, Dean and the rest of the EnLink team. What sets EnLink apart and what will make us successful with our 7 growth strategies is unquestionably our people.

Our team wakes up each morning thinking about EnLink and how to make the company better and stronger. The team has an ownership mentality, a winning work ethic and a clear path forward. With that, you may open the call up for questions. .

[Operator Instructions] And our first question will come from Jeremy Tonet of JPMorgan. Okay, we'll move on to the next question, from Schneur Gershuni of UBS. .

Just a couple of quick questions. One is kind of more of a modeling-type question. I think I kind of know the answer to the question, but can we re-review the conversion of EBITDA to distributions for Tall Oak? If I remember correctly, the guide is to get up to $300 million in EBITDA. Then you obviously have the 16%.

But you're kind of reporting a cash distribution which is far lower than that pace would imply. I assume part of the delta is that it's a cash distribution and it's probably also lagged a quarter as well, too. But if I remember correctly, it also talked about filling in [ MBCs ] for the Cana plant first.

And so I guess my question is, am I thinking about it correctly.

And then, secondly, can you talk about the conversion of EBITDA to cash distribution once you hit the $300 million run rate? How should that fall to the bottom line?.

Yes, Schneur, this is Mike. So what I would say overall, we are right on track with where we expected to be with that acquisition. One of the comments I made in my call script was where we are ultimately when you look at the 16% of that ownership up in ENLC, which translates to an annual run rate of just south of $200 million from where we are today.

So we feel ultimately that everything's tracking as planned, even though we've seen a lot of different moves to the left and right during the 2 years on executing on this. So we feel good of hitting our goals for Central Oklahoma all the way through 2018. When you think about that going down to -- from EBITDA to DCF, we are seeing that today.

You do see some of the financing for that last piece of the Tall Oak payment that came through, where we prefunded ultimately the last installment payment due in January through the perpetual preferred, which keeps us in a great place from a balance sheet.

So I think you're in a position to where you'll continue to see that come through to the DCF as we move into 2018. [Indiscernible] --.

And so when I think about the -- sorry, go ahead. .

No, go ahead. .

I was going to say, so when I'm thinking about $300 million in EBITDA, what should we expect that translates into on a cash distribution basis once you sort of get that run rate?.

Ultimately when you think about it, the financing has been mainly done for the acquisition itself. You'll have the follow-on capital we'll see in 2018. But think about it in terms of what that cost of capital would be as you move down, very little maintenance costs.

So it would be more the interests costs related to the acquisition, which you're seeing in our DCF today. .

Okay, fair enough. And just sort of moving on a little bit, in your prepared remarks you talked about moving to a full scale development. When I sort of think about a pad development, typically the E&P has to run with much higher DUC levels.

Has that been achieved? And does that explain sort of the tail-off in the rigs that was seen?.

It's Ben. I'll start and talk about Oklahoma and then Steve may want to comment for our Permian businesses. We have seen the transition in some of our producer customers to full field development. And so if you take a look at the Oklahoma system today, we have 27 rigs running on dedicated acreage. Five of those rigs are on Devon's Showboat Project.

And so there is an element of delayed gratification that comes with full field development, because first 25 wells have to get drilled on the Showboat Project. Then 25 wells have to get completed on the Showboat Project. And then we're likely to see the volume mainly in the second quarter of 2018. We have had some of this earlier in the year, too.

So similarly, Newfield's Velta June Project that they talk a lot about in their earnings release is on our footprint. That's an 11-well in-field project. And so about this time last quarter all the rigs were there. And that gas still isn't flowing yet, because they're still in the process of completing those wells.

We expect those to come later this quarter. So that really gets to the sort of sawtooth growth expectations that we have as the producers roll over into full-field development. The last part of your question, though, we really haven't seen a tailing off in the rig level.

If anything, in Oklahoma we've seen it increase quarter over quarter over quarter as the results drive the producers to want to do more on our dedicated acreage. .

Yes, Schneur, this is Steve. I would say for the Midland Basin what you are seeing is that good consistent development plan. I would expect that our volumes will continue to grow as you've seen in the past. It will be stable, consistent growth in the fourth quarter and into 2018.

But when you start to look at the Delaware Basin, it's going to look a little steeper. We've had some great growth in the last year and a half and we're going to continue to expect to see some of that growth. We've announced the third plant. So that's in anticipation of being full on our system by midyear.

We'll have the third plant online by midyear of 2018. And we're going to see I think a more rapid development in the Delaware than in the Midland in the near term because it is going from that exploration to that development phase and the producers are just starting to get their ramp-up built.

And you'll start to see it stabilize I think at a higher level than we have seen in the past. But I'm really impressed with where we're at with our team and how we've built our position in the Delaware. .

Great. One final question. You sort of discussed in the prepared remarks about a CapEx plan for next year similar to this past year.

Given where coverage ratio is, which is still on the tighter side, what are the plans to finance for next year? Do you consider potentially doing a KC conversion at some point, either going up or going down? I was just kind of wondering what's the thought process on how to put that forward. .

Schneur, this is Mike. We feel we're in a great position today with the balance sheet. We're exiting the quarter with about a 3.7x leverage. We executed on the perpetual preferred to prefund that Tall Oak installment payment coming in January.

And I mentioned ultimately that we expect a capital program net to ENLK consistent with our guidance in 2017, which translates to about $500 million to $650 million for the year.

We talked about some of the key drivers here, which were the new plant ultimately in Oklahoma, the new plant in the Delaware, the Black Coyote system or crude system in Oklahoma. So I think the key thing you see is all of these are core projects, high-return, organic projects in our core growth areas. And you'll continue to see that.

And that's driven by being in the right places with the producers having great success. From a funding standpoint, we think there's two keys, right.

With having already funded the installment payment it's going to be the cash flow received from these projects, as well as utilization of the ATM in and around about the same amount we'd projected for this year which, again, we think is not a large number. So we feel very good about the financing in 2018 for this capital plan. .

Schneur, this is Barry. Let me comment a little bit on your conversion. I think you might have been talking about a consolidation of K and C in your comment there.

First, let me say that what you've seen us do from an execution standpoint over the last 3 years -- I mean, I hope you see the tone and ready the body language, if you will, in our comments today. We are extremely encouraged by what we see in the business today.

What we've done over the last 3 years through a very difficult cycle that is really 36 months in duration at this point -- we have strategically enhanced the position of the company I think second to none in terms of where we are, what we're doing and the results that we are driving.

I really liked Ben's comment earlier about the delayed gratification. I think it is right now that you see the trajectory change in the results to the bottom line from the investments that we've made over the last 3 years. So that's first of all how we feel about it.

Secondly, what we're focused on today is executing the strategies that we laid out in the prepared remarks. Today our issue is not structure, in our opinion. We think that executing on the strategies will increase optionality and create a better outcome, regardless of what structure or what we do in the future.

That being said, we'll continue to evaluate structure and we'll respond to what the market is telling us needs to be done. But today we think we're in the right place. .

And our next question will come from Darren Horowitz of Raymond James. .

First question regarding the NGL value chain approach that you talked about and the integration into the Gulf Coast.

With the announcement of Thunderbird and the results in the liquids output that you're seeing out of Central Oklahoma, has your thought process shifted a little with regard to the solutions that you're assessing to handle those Y-grade barrels? More specifically, has it put you more firmly in the bias towards looping Cajun Sibon and then looking at fractionating those barrels at either Eunice or Plaquemine?.

Darren, it's Ben. I want to start and just give a little bit of context around the Thunderbird announcement and then let Mac address your questions that are specific to NGLs. I want to make sure everyone understands that the right way to think about Thunderbird is the same way that you would have thought about a Chisholm expansion.

We chose not to build a Chisholm IV plant for a variety of reasons having to do with enhanced operational flexibility on the system, among other things. But the Thunderbird plant will function just like an expansion of Chisholm.

Its liquids will be directly linked to Cajun Sibon as part of a strategic arrangement that we announced with ONEOK in the last quarter. It will be jointly owned by ENLK and ENLC, just as the Chisholm plant is. And then Mac can address your specific question on the liquids. .

Darren, this is Mac. Really the growth in our Oklahoma business is just exactly what we anticipated. It does not change the direction that we're pursuing right now with regards to NGL solutions. We'll continue to do the same thing we did with regards to the transportation question out of Oklahoma.

And that is, we'll evaluate all alternatives that are available to us. And I won't name all the alternatives, but there are a large number of them ahead of us, and that we will look at executing on those that meet the strategic needs that we've got as well as provide the best economic solution for us.

You might even see us select a combination of those alternatives that, again, take advantage of the unique position we've got with Cajun Sibon, with Louisiana fractionation and with capabilities or opportunities we might see in the Mont Belvieu area. .

Okay. Ben, if I could just for a minute as my follow-up go back to your comments around the volume uplift from the Showboat Project and when you expect to realize those lines as it takes shape in the middle of next year.

Is the expectation still on those wells about 5 million to 7 million cubic foot? And if that's the case, or even if it's slightly better from what we've heard, what do you think that means with regard to more downstream liquids capacity that you might have to handle exiting next year into '19, and possibly even the opportunity to further scale up Black Coyote?.

Darren, great question and I'm going to try to take it apart a little bit. And I think Mac will want to talk about the downstream piece as well. You touch on something really important, which is the momentum that our producer customers have and the quality of the well results.

And I'd encourage you and everyone to go take a close look at Devon's operations report. They talk about 14 Meramac wells that average 2,300 BOEs a day, about half of which was rich gas. All of those are on our system. Go look at Newfield's report that they published this morning.

They talk about the Stark infill project which is trending above their type curve and also has been remarkably flat in terms of its production profile. That's in our footprint. They talk about the [Hoyle] well, which per foot of stimulated lateral by one measure is the biggest oil well ever drilled in the STACK. That's on our footprint. So you're right.

The results continue to get better and better. And that is what drives the need for the Thunderbird processing expansion in the first quarter of 2019 and certainly has the potential to deliver outsized results in terms of our Black Coyote crude project. .

Yes, Darren, I would just follow up on that by acknowledging that we just talked about the fractionation side of the NGL question. We feel like we're positioned very, very well with the transportation agreement we did with ONEOK to handle the transport of those barrels from Oklahoma down to the Gulf Coast.

We will be in an increasingly better position as we get additional physical connections from the ONEOK facilities in the Cajon Sibon, but we feel like we're positioned very, very well to take advantage of that. .

The next question today comes from Barrett Blaschke of MUFG Securities. .

Little more on Thunderbird, just to have some clarification. This is sort of an alternative to Chisholm IV from the sound of it.

What's the difference between this and what you -- why the change from the Chisholm system and just what drives that?.

Barrett, it's Ben. First of all, there is no change. The only change from what we've been doing with Chisholm II and Chisholm III is we're going to build it at a separate plant site. And that's going to be located over in Blaine County, whereas the Chisholm plant site is in Kingfisher County.

And there will be a 24-inch rich-gas high-pressure line between those 2 plants. And so one benefit you get is you effectively increase the capacity of your rich-gas high-pressure system by having 2 plants, 1 on each end of the pipeline. The pipeline can flow in both directions.

You also get the benefit of not having all of your eggs in one basket, operationally, particularly at a state that sees its share of severe weather. We like to have things spread around. But functionally, it's just like Chisholm IV would have been. It serves the same gathering system. It serves the same gas. It has the same residue and NGL outlets.

It has the same direct connectivity to our Cajun Sibon system. .

Does the start of sort of the Thunderbird Project, does this stop you from ever expanding to them again? Or does that still stay on the table and then -- but just does it give you 2 sites going forward basically?.

Well, really it gives us 3 sites going forward there in the STACK, between our Cana facility, the Chisholm facility and the Thunderbird facility, and then our Battle Ridge facility over in Payne County, which is also connected to our STACK system. In terms of closing off options, it doesn't close off options.

But my expectation is when we announce the next plant it is most likely to be Thunderbird II, not Chisholm IV. .

Okay. And then just one housekeeping question.

Any update to maintenance CapEx guidance for full year 2017?.

Yes, Barrett, this is Mike. Where we expect to run probably is consistent with what you saw in the third quarter, which would put us in the low side of guidance. .

And the next question will come from Mirek Zak of Citigroup. .

So my question touches on some commentary you had previously.

So with Devon seeing the stronger growth in the STACK and seeing higher oil cuts on their latest wells, can you sort of walk us through the interplay there between the impacts of more oilier wells with the offsetting opportunities such as Black Coyote and how that nets out regarding your prior views and expectations for future performance?.

Mirek, it's Ben. You're right. We have seen some higher oil cuts but we have also seen much, much larger wells than we expected to see.

So in absolute terms, the volume of gas that we are seeing on a well-by-well basis significantly exceeds our expectations, certainly our expectations that we had 2 years ago when we made the acquisition, but really even our expectations earlier this year. And for some wells, we only benefit from that on the gas side.

But it is a benefit, because the wells themselves are so much larger than we expected them to be. In some cases, though, we will benefit not only from the gas production, but from the oil production.

And the first example of that will be that Showboat 25-well development in the first half of next year, that will be the initial connection point for the Black Coyote system. .

Okay.

And I guess tied with that, your 1 Bcf a day of processing capacity you expect in Oklahoma by the end of the year, how do you see that utilization or the tightness in 2018 before Thunderbird comes online, considering your processing volumes have been ramping up pretty quickly recently?.

That's a great question, Mirek. And I think there was an email that we received that said, "Why are you announcing Thunderbird now? If it's November 1 of 2017 and you're telling us you're going to build a processing plant to be in service in the first quarter of 2019, it doesn't take 17 or 18 months to build a processing plant." Well, that's true.

But we are announcing it now because we have line of sight to needing it by the first quarter of 2019. And we're not ready to say today whether that's January 1 or whether it's March 31.

But taking the step of acquiring the cryogenic unit, ordering the long-lead equipment, finding a site, beginning the work will put us in a position to have some flexibility as to when we bring that plant on. .

Mirek, let me just add to that. I think if you were to look at all of the details of our projection of these plans, what we're doing is basically bringing plants on when our volume ramp is projected to exceed the existing capacity and a build through that next plant until it gets full.

And so that's why we have pointed to the 12 to 18 months, and I think 12 to 18 months between the 200-million-a-day plants. And I think we're consistent with that schedule, but on the shorter end, closer to the 12 months between plants. So that's effectively what we're doing.

We would point out the sawtooth nature of that, which is a word that we've used to describe the way the volume is going to increase when you bring on the big multiwell pads. And so it won't be a consistent growth to fill the plants, but more of a sawtooth projection. .

And our next question comes from Tom Abrams of Morgan Stanley. .

I've got three questions. One is on this NGL options along the Gulf Coast. And I'm just guessing that ideally you'll get either an interest in a frac or a frac of your own probably close to Mont Belvieu.

So I was wondering if that is in your kind of soft guidance for '18 spending yet or, if you did go that route, it would be an increase to '18 spending. .

Yes, Tom, this is Mike. We tried to give a range of guidance. And as Mac stated earlier, we have a range of options on the NGL, which could be one or a combination of. And you could see it just as consistent as you did on the NGL transportation to where we worked with a partner to do something that was financially advantageous and capital light.

So that could be the same case. And so ultimately we have some capital for the continued development of that project. But as Mac said, we'll develop that into '18 and that will be more of a '19 spend than '18. .

Okay, good. And then I was wondering about the Tall Oak assets still up at ENLC, how that might make its way down to ENLK.

And if it's dropped, if you will, would C take units back? Or how should we think about that in relationship to the spending that you've outlined?.

Yes, Tom, this is Mike. The assets are continuing to perform well. We think we're in a good position from receiving the benefits at ENLC we expected to receive. So we'll start looking ultimately to drop down of that 16% in 2018. With regard to the consideration or how we'll think about it, we're looking at a lot of different options right now.

And the end-state goal would be what is the best option for both entities. A portion of it would likely be units, but we'll look at a lot of different options with regard to consideration. .

Fair enough.

Then lastly, on the Devon refracs, the 6-well packages, are those on the Johnson County acreage that's -- they're looking for bids on?.

This is Steve. No, they're not. They're on the lean gas systems and the rich gas systems that they're retaining as part of their assets in the Barnett. .

And the next question comes from Praneeth Satish of Wells Fargo. .

Quick question from me. Just on the Midland side and the processing capacity that's available there, when do you think that that could fill up? Is that a 2018 event? Or could that spill over into '19? Just curious on the ramp there. .

So we've been really pleased with the activity that we've seen in Midland. And volumes have grown about 20% over the last year. Customers are maintaining a strong rig count. And in addition to that, we've added about 23,000 acres to our dedications this year. So the teams have done a good job.

As our volumes continue to increase our plans, as we have said, is take advantage of the interconnectivity of our mega system to optimize the capacity we have in place, the 5 plants that give us 400 million a day. And then our next phase of capacity addition is the Riptide plant expansion, which would add 100 million.

That's a very low cost incremental expansion that we have available to us. And we're going to do it based on -- as Barry said earlier, we're following those volume forecasts. We're watching where their progression goes. And we're setting up the timing of those spends to match that forecast. So that's what we're going to follow right now.

We think we're in a really good place for that to be very cost efficient for us as the next step in the Midland Basin development. .

And then just I guess housekeeping unless I missed it, but what's the cost of the Thunderbird plant?.

We didn't say but I can give you an indication. This year it will be about $15 million to acquire the cryogenic unit, some of the long-lead equipment. Overall the plant itself will be in a range of $110 million or so. And then there will be some additional costs to make some residue and NGL connections. But that gives you a rough sense of it. .

And next we have a question from Bernie Colson of Seaport. .

Quick question. So spending a lot of time on the important topic of crude oil volumes out of the STACK. I'm hoping that you can turn maybe and discuss the natural gas volumes there at some point.

So the first question is are there any opportunities for additional takeaway capacity for natural gas, given you've got the big Midship Pipeline coming on at the end of '18.

But are there additional opportunities that may present themselves there, number one? And then, number two, at some point you discussed a project called Oklahoma Express, which was a project, as I understand it, to connect the Oklahoma assets to the North Texas system.

And so, given that we're seeing a resurgence of activity in the Barnett, where does it leave that strategy of kind of hooking everything together there?.

Bernie, it's Ben. To take the first part of your question about additional gas takeaway, you're right. The big development in the basin this year is Cheniere's announcement of the Midship Pipeline. And that pipeline will be coming to both of our big complexes, the Cana complex and the Chisholm complex.

And our current expectation is that, combined with the existing interstate capacity out of Oklahoma and the Oklahoma intrastate pipelines, the basin will be fairly well set for takeaway capacity for the foreseeable future.

And the benefit that the producers have of being on our system is access to all of those options, access to the Oklahoma intrastates, access to the existing interstates that mainly serve Upper-Midwest-type markets, also access to Cheniere that will take then to Bennington and then onward to the Gulf Coast and Transco and all the places that you can get to in that infrastructure.

In terms of Oklahoma Express, we did consider for a period of time whether to connect the Oklahoma assets to our Texas in order to take advantage of the processing capacity we have in North Texas.

Where we sit right now, given the capital efficiency of adding capacity in Oklahoma and the pace at which we need to make that capacity addition, we're focused on expanding the infrastructure in Oklahoma to handle those Oklahoma volumes. .

All right, so that's kind of off the table at least for now, the connection to Texas. .

That's correct. .

All right. And then last one is a bigger picture question about the distribution, distribution growth and strategy there, given that you've added some nice projects and projects that will entail CapEx obviously. And I didn't hear any commentary really about the plan or timing for resumption of distribution growth.

And just wondering, given that the investors in the industry seem to be focused a lot more on internally generating cash flow and lower payouts, how you guys think about that. Has your view changed? Has your stance changed? And that's it for me. Thanks. .

This is Barry. I like the way you asked the question. It's a great lead in to really what I think is important, and that is the investments that we've made over the last 3 years and the performance of those investments, you've heard consistently throughout this call that we're very pleased with that.

We have definitely seen a trajectory change of the results falling to the bottom line and the return on these assets. So that's important.

As it relates to converting that into distribution coverage and distribution growth, we've consistently said that the 3 metrics that we would look at would be first of all distribution coverage at 1.1x or better, secondly leverage at 3.5x to 4x or better and then also the sustainability or the projection of the business going forward to continue to increase the distribution of once we restart the growth of the distribution.

So we continue to monitor those metrics. And what we would tell you is that we're confident that we will continue to grow the distribution coverage through 2018 that will give us the opportunity to evaluate the distribution growth in 2018. So looking at the ENLK, I think you can look at a little differently.

We're in a position today if we chose to do so we could increase the distribution at ENLC with a 1.17x coverage. And we get questions often about whether we would do that, separate the commencement, if you will, with the distribution growth.

And the answer is that in the right situation we would, and we are evaluating that basically with each quarter that we address the distribution going forward. .

And our next question will come from Jeremy Tonet, a follow-up from JPMorgan. .

This is Robert on for Jeremy. I've just a couple of questions here. On the first one, in Louisiana you guys mentioned about the [indiscernible] gas pipes into liquids cost [indiscernible]. I just want to check with you guys like what's your view on the Mont Belvieu and the Louisiana spreads today.

I remember you said early on the call that this would be more of a 2019 kind of thing.

So are the spreads one of the drivers which guided you for this view?.

This is Mac Hummel.

First of all, when we talk about conversion I want to step back just a little bit and acknowledge the great job that our LA gas team, Louisiana gas team, has done in taking advantage of the opportunities on the gas side of the business and growing that business and really creating in a much more robust platform than we had when we first made the acquisition of the Chevron Pipelines in late 2014.

They've been also very effective facilitators of helping the teams understand where we had redundant capability and therefore have the ability to look at conversions that did not impact our ability to serve the market. And we've really talked about these conversion opportunities since Day 1.

But the one that we're currently considering is a conversion to crude. We are evaluating it really because of a number of reasons. And the reasons are oriented around the supply and demand fundamentals associated with Louisiana.

We've got a market there that consumes about 3 million barrels a day, plus or minus crude, mostly oriented toward the Mississippi River corridor. We've got North American supply that's really not accessible to that market via pipeline in a large scale basis. And that supply could be Northern Tier U.S. barrels. It could be Cushing barrels.

It could be Canadian barrels. And Barry and others have talked about us being in the right places. And clearly this is an example of us being in the right place. We've got the pipeline footprint to bridge that supply and that market.

Our footprint lays all over the Mississippi River corridor, all over the refinery demand that exists on the river corridor. So we think it's a very compelling and interesting option for us to be considering. The timing of it is likely not 2018, 2019 but probably more like 2020 in terms of when we could get that project completed and producing.

But some of it also depends upon the timing of commercial discussions and the success of those. .

Just one last question here. [Indiscernible] earlier this quarter. So I'm just wondering on what other avenues are you focused on for financing the broad CapEx going forward.

And, like, this being such a good deal, can we expect something similar in 2018 subject to market [ reception ]?.

This is Mike. We're going to continue to focus on what we've stated on this call, which is managing the balance sheet, building coverage and really thinking about effective returns to the shareholder. And this offering we think did a great job on all of those, especially the last one with regard to potential dilution of a unit offering.

The other big key piece for this is that it allowed us to pre-finance the Tall Oak payment that's coming due in January. So we've already started financing the 2018 growth plans today and feel good about that.

Our 2 avenues for financing growth in 2018 are going to be the growth in cash flows from the projects we see, as well as an ATM program in and around the same size we've expected for this year, which is not a big program. So feel very good about the execution of that. .

And the next question comes from T. J. Schultz of RBC Capital Markets. .

[Indiscernible] just a couple quick follow-ups. Maybe Mac on the conversion opportunities first. You indicated I think in the slide deck potentially entering a strategic JV. Just any color on how that process may have accelerated at all here recently.

How important is it there to find a partner to back that type of conversion who are the likely types of JV partners?.

Well, I'll try to take those in order. We have considered the opportunities associated with taking on a partner with regards to the conversion. I don't think there's been anything in the market that has necessarily increased our interest in that or changed our timing on that.

We would continue to look at partners to the extent we thought they added value from maybe perhaps a strategic perspective or from a value perspective. And I think the list of potential partners is potentially quite long.

But just to maybe reiterate, we're only going to take one on to the extent we think it adds value and it's not something we have to do in order to move forward with that project, at least as we've currently got it conceived. .

Okay, understood. And then a follow-up on the Midland. You just added some acreage from Parsley.

Is there other acreage that may be up for grabs there or any dedications away from you all that may be coming due anytime soon? Or is it, when you think about the ramp in utilization or expanding Riptide that with your current dedications you see the potential to fill up and expand over the next couple of years?.

T.J., this is Steve. It's actually a little bit of both, with the larger portion of it coming from the dedication of existing acreage. We continue to see opportunities for adding new business and in expiring contracts that we're chasing all the time. And we've had a really good year, a lot of success this year in capturing some of that business.

So the team's been very aggressive looking for bolt-ons and step-outs around our existing infrastructure. But the bigger portion of the growth that we're going to see is from that dedicated acreage and those key customers that have core positions in that basin that are in their development mode now. .

T.J., this is Barry. Let me broaden that to also say that that when we look across our 7 growth strategies we require very little additional acreage, additional customers, et cetera, to meet our plan. We have what we need to do, what we have set out to execute across those plans. So I think that's a really important point.

We're not out there trying to win battles right now. Although we're going to keep fighting for acreage, we don't necessarily have to to achieve the growth objectives that we have set forth for the next 3 years. .

Got it. Appreciate that. And, Mike, you mentioned for funding next year the ramping cash flow and ATM. Is there still -- are you considering any asset sales? Would you add that to the mix? Or just any thoughts there. .

Yes, this is Mike. You clearly -- you laid out exactly how we think about it. As Barry mentioned, we're very focused on our core growth areas, which are Louisiana, Oklahoma, North Texas and the Permian. So anything really outside of those core areas we would consider, but don't need to.

So if it makes sense financially for us to do, it's something we could do but don't have to. .

Yes, and T.J. I'd just add that the interest in those 4 areas where we are is where everybody is interested. And that's where we're seeing high valuations that might lead one to want to monetize something.

So outside of those areas you don't see those type of valuations and therefore it's less attractive to actually execute on a divestiture to help finance something. .

Funny how that works. I got it. Thanks. .

And this concludes our question-and-answer session. I would like to turn the conference back over to Barry Davis for any closing remarks. .

Thank you, Laura, for facilitating the call today. And to everyone on the call, thank you for your participation and, as always, for your support. I hope you have a great rest of the day and a great holiday season. We'll be in touch with many of you soon. Thank you. .

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect..