Welcome to the EnLink Midstream Fourth Quarter and Full Year 2016 Earnings Call. [Operator Instructions] Please note that this call is being recorded today, Wednesday, February 15, 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 2016 results and 2017 outlook.

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 plan to file our Form 10-K with the SEC later today. To accompany today's call, we have posted the earnings release and the operations report in 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 that 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 brief prepared remarks and then leave the majority of the call open for a question-and-answer period.

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

Strong balance sheet, best basins, right platform, top customers. The strength we built in 2016 positions us well for 2017 and beyond, and we continue to capitalize on growth opportunities and execute on long-term expansions across our platform, creating unitholder value for years to come. With that, I'll turn it over to Mike. .

Thanks, Barry, and good morning, everyone. As Barry highlighted, EnLink delivered strong results this year achieving adjusted EBITDA net to ENLK of $775 million for the year, which represents over 14% growth from 2015.

We exceeded adjusted EBITDA guidance for the third year in a row and continue to build a strong scorecard of executing on the plan we laid out. We are committed to maintaining our strong investment-grade balance sheet, preserving ample liquidity and creating stable cash flows that support and grow our distribution.

We took deliberate steps during 2016 to ensure that we met our goals. First, we executed on nearly $1.2 billion in equity during 2016. This includes our preferred and ENLC units issued for Tall Oak acquisition and our ENLK ATM issuances during the year.

We ended a very tough year with debt-to-EBITDA of 3.7x, a very solid place to be from a balance sheet perspective. Second, we executed on issuing senior notes in July with an all-in interest rate of 4.85%, which was at the lowest point of the 10-year treasury for the year.

This helps position us with consolidated liquidity of $1.6 billion at the end of the year. Third, we executed on a joint venture with NGP to ensure we had a strategic partner with focused capital to quickly grow the business.

We gained access to $400 million in capital commitments that allowed us to finish out our initial Delaware build as well as deepening relationships with a large investment-grade customer. Finally, we announced the sale of noncore assets for $275 million and are reinvesting in our core basins, Central Oklahoma and the Permian.

We did all of this to ensure we maintain the strength of our balance sheet despite very volatile capital markets. This also puts us in a position where we do not have to rely on marketed equity transactions for 2017 equity funding, which provides great financial flexibility.

Our current financing plan has us issuing equity under the ATM consistent with the pace in the second half of 2016 as well as finalizing asset sales we have discussed.

As Barry mentioned, we believe we not only have asset position in the core of the core of the best basins, but we also have the right business model to execute on our growth opportunities. We believe this solidly comes together in 2018.

A couple of items that we highlight in 2017 guidance were the exit rate ENLK adjusted EBITDA and distribution growth. The exit rate adjusted EBITDA should highlight the earnings growth of these assets and the business model.

Our 2017 guidance projects an adjusted EBITDA exit rate of $925 million to $950 million, a 20% increase versus 2016 adjusted EBITDA. We signaled that the majority of growth will be levered towards the second half of 2017, with an expectation that the first quarter will be somewhat flat to the fourth quarter of 2016.

However, we believe this growth gives us the opportunity to consider growing distributions at ENLK during 2018 and potentially growing distributions at ENLC prior to ENLK. I will now turn the call back over to Barry for concluding remarks.

Barry?.

Thank you, Mike. We're excited about the year ahead. We have a lot to execute on and a lot to accomplish. We have superior quality assets in premier U.S. basins and long-term contracts with top-tier producers who are focused on growth. We believe the activity we're seeing today is sufficient to drive the growth we expect.

And we have a team whose hearts and minds are fully engaged, who come to work each day with a strong sense of ownership and purpose, all keys to continuing to pave a successful path ahead. With that, operator, you may open the lines for questions. .

[Operator Instructions] The first question comes from TJ Schultz with RBC Capital Markets. .

I think just first looking beyond Chisholm III.

When you think about that next suite of expansion options, what are the kind of current thoughts on keeping potential processing additions in basin versus the potential for Oklahoma Express? And then just any color on potential expansions or extensions into Cajun-Sibon?.

Good morning, TJ. This is Barry, and I'll ask Ben to respond to that. .

Hello, TJ. It's Ben. So first let's step back and just talk about where we are in Central Oklahoma. As you said, looking beyond Chisholm III, but first just want to remind everyone that Chisholm II is under construction right now, looking to go in service here very shortly. Chisholm III coming right behind that toward the end of the year.

And previously, we had guided you to think about the need for processing expansion every 12 to 18 months, if present trends continue. Right now, present trends are continuing. We don't see anything different today than when we provided that general guidance. Now, as to the next step on processing capacity in Oklahoma, it could take a couple of forms.

It could take the form of additional capacity there in-state, it could take the form of Oklahoma Express and doing the processing in North Texas. What we do have is conviction that we will continue to need to add processing capacity.

What we lack today is perfect clarity on the downstream markets that would determine where that processing capacity should be. At times, it has looked like Oklahoma Express was the best answer. At times, it has looked like in-state processing was the best answer.

And right now, we have a very dynamic market on the residue gas side, in particular, and we'll need to see a little bit more clarity before we can make that determination. Fortunately, I think we're going to have that clarity before we need to make a decision, which is probably later this year.

On the Cajun-Sibon question, maybe I'll start, and I'll ask Mac to add. The great news is we're going to fill Cajun-Sibon with Chisholm liquids. The question that we have before us, is exactly how we get those liquids to Cajun-Sibon. We control enough supply to construct an NGL pipeline if that's what we choose to do.

Something that we are working through right now is trying to determine whether that is the best answer, whether the best answer is a partnership with others or whether the best answer is just using third-party infrastructure that's very attractively priced.

And so, we will have to stack up all of our options and make sure that we chose the one that competes the best, both financially and strategically. .

TJ, this is Mac. Ben, I think you did a great job answering that question.

I would just add that I think Central Oklahoma is a great demonstration of the capability that we've built and the capability that we're continuing to build to link our upstream businesses with our downstream businesses, so that we get multiple touches on that molecule and give us additional opportunities to add margin. .

Got it, that's helpful. Just moving to the Delaware JV contemplates $800 million of committed capital. So again just looking ahead, in this case after Lobo II, just any color on the next targets.

Are you looking at more acquisitions, knowing Matador is still holding some midstream? Or is there enough organically to do around your current footprint?.

TJ, it's Ben, again. I'll start and Steve may want to add on. Our priority is focusing on the execution of what we have in the Delaware. So it's organic growth as the first priority. Having said that, there are a lot of assets in the Delaware that could come available for sale. We've seen some transaction activity already this year in that regard.

We are always involved in M&A activity. We are always looking for opportunities to add to the positions that we have and ways that make us better. But we will be disciplined about it. And if we take that step, it will only be because we feel real conviction that an acquisition makes us better. .

TJ, this is Steve. When you look at the opportunities that we've got in front of us right now, the first opportunity is the expansion that we've got of the Lobo II plant. So it's a 60 million a day plant, and we've already started work on expanding that to 120 million a day.

In addition to that, there are a number of pipeline expansions that we're working on off of our gathering system. You recall the gathering system was recently put into service at the end of this year, and that was actually 3 months early. We had planned on the end of the first quarter.

So we are already in a great position to expand off of the gathering system, and we've got an opportunity as volumes grow that the next bolt-on would be a third plant in the area. So we see a lot of opportunity for rapid growth in the area.

We see drilling and prices improving that can give us the market to drive that opportunity, and we're prepared for -- we're preparing for it today. .

Thanks. Just last one for me. Barry, you touched on the GP LP structure. Just if you could expand on some ways you want to leverage the flexibility that the structure gives you.

Is this something you'd want to transact more at the ENLC level to utilize that currency? Or is the comment really that since the GP take is not a big hindrance to your cost of capital right now, you just don't need to address it, or address the structure now, but maybe something to consider later. .

Yes. TJ, consistent with what I've said earlier, we don't think we have a problem, first of all, with the cost of capital burden or tax burden. At the General Partner, we've done some very creative and strategic things to address that. So we like our structure.

We believe that it does in fact offer us some financing flexibility as we look at transactions.

Just to remind you, I mean, we've used it in 2 of the largest transactions, the combination of ENLC and ENLK in 2 of the largest transactions that we've done in the creation of EnLink, first of all, and then in the Central Oklahoma asset acquisition that we did.

So that's an example of where we think it really affords us some flexibility, not predicting, but certainly just acknowledging the optionality that we have. And let me just lastly say, we do believe there is a life cycle to the GP MLP structure, and everyone has to evaluate that in time, and we will stay very much on top of it.

And if there is something there that needs to be done, we certainly will -- we'll certainly be proactive. .

Our next question will come from Jeremy Tonet of JP Morgan. .

This is actually Rahul for Jeremy Tonet. I have a couple of quick questions for you guys. The first one on the Tall Oak EBITDA. So for the ENLC's share of $9 million for 2016, this kind of translates to what looks like $55 million for the year on EBITDA, which falls like slightly below your $75 million to $85 million guidance.

I just want to check like if I am missing anything here or am I reading this right?.

Yes. This is Mike. It's a good question. There are other items in there. There is some dollars in there related to the joint venture we have out in the Delaware. So you're generally in the number. I would say that where we guided for the Central Oklahoma acquisition was around $70 million.

Your number, if you just gross it up by the 16% gets you, I think, around the $55 million if you do it just on the net number in there. I would say, we're generally around that, probably more around the $60 million number.

I think where you need to focus is, again, the growth we see moving into '17, and then ultimately '18 because of where the producer is at from a development standpoint. And the key for that is really the conviction we have around the guidance, both for '17 and exit rate into '18. .

Mike, I will add on one thought. I know it's easiest to conceptualize our businesses as all being inside little boxes. And so there is a Central Oklahoma acquisition box that we talked about, we put an EBITDA number out there associated with it.

But the reality is that, that asset has been integrated into our broader Central Oklahoma business where we had our 400 million cubic foot a day Cana plant. And one of the things we did last year was offload volumes from the Central Oklahoma systems we acquired on to our legacy Cana system.

And so when we do that, some of the margin moves out of the acquired entity and into the legacy entity. So just looking at the ENLC financials and doing a gross up doesn't tell the whole story of the acquisition. .

Got you. That's helpful. On -- and one more question following up with MVCs roll-off in the Barnett. Can we like -- see like take Devon out or like someone to step up for the flagged contract renewals on MVC expiration, like few of your peers had like similar kind of support. So any comments there or... .

This is Mike, again. I'll start and then pass it to Steve. So I think if you go to what Barry talked about in the script on the Barnett, that's the key is really is us working hand-in-hand with Devon on the Barnett. And you can see that ultimately through 2 things. One, you can see that from a Devon perspective on bringing money back to the drill bit.

And two, you can see it from a EnLink perspective on the pressure reduction and the optimization working hand-in-hand with Devon from an efficiency standpoint. Steve can walk you through what those ultimately mean both to us and to Devon. .

Yes. So this is Steve. On the MVCs, in 2016, on the Devon-based contracts, this is both North Texas and Oklahoma, they made $37 million in MVC payments. In 2017, we're projecting about a $20 million increase to that.

But keep in mind, one of the things that we see is that the Oklahoma volumes will further be supported by development in the Cana-Woodford. So we don't see that being an issue going forward long term. In North Texas, I want to really stress that we're going to be very determined to find better than a runoff case in Barnett.

We're going to continue working with Devon and other producers to reduce declines. We want to improve well-head net backs that is going to incentivize, encourage and support new development. We're going to continue to pursue consolidation opportunities and connect new supplies to our system.

And we've been very successful in our operations optimizations. In fact, we've reduced O&M cost $20 million in 2017 compared to 2015. So we've got a lot of things that we're working on, and focused on, to continue to have North Texas to be a good and stable cash flow to our business. And I think we've been very successful in that effort. .

Steve, I think that's well said. And this is Barry. I want to add just to that, or emphasize, that is a joint effort between us and Devon. We're working collaboratively to determine a positive future for the Barnett, and I think the $50 million of investment that they're making this year is in that direction.

We have not had a modern-type curve -- a modern well drilled in the Barnett for now 2 or 3 years, and so part of what they're doing is to determine really where it fits in our portfolio as well as hopefully it'll be helpful to other operators in the Barnett Shale to see what can be done.

We've seen some real positive developments in other plays, like the Haynesville, for example, that has really resulted in a resurgence in that area. The expectation is that you would see returns on wells drilled in the Barnett today north of 20%. How far north will be determined by the success of the wells that we're drilling.

So, again, emphasizing what Steve said, we're determined to find a better forecast for the Barnett Shale and beyond the MVCs to really close the gap there. So stay tuned. We'll try to keep you posted on that as it develops. .

The next question will come from Mirek Zak of Citigroup. .

Just a couple of quick ones from me. The first one being on the NGL side. I was just curious what potential opportunities you see on the NGL side out of the Permians.

Is that only on the pricing side or if and where you might see any additional opportunities around NGLs out there?.

Mirek, this is Mac Hummel. Thanks for the question. I think the primary opportunity we see for increased NGLs from the NGL side of the business out of our Permian area is that we can funnel those volumes into our Cajun-Sibon facility.

So like we talked about with Central Oklahoma and the linking opportunity we've got there, we've got the opportunity to link some of that NGL growth that we see out of the Permian into our Cajun-Sibon facilities over time and really touch that molecule again, multiple times and earn margin each time we do. .

Okay. Great.

And secondly, in Oklahoma, at what point do you think crude production there could be substantial enough to warrant any additional infrastructure investment on your part? Or what type of opportunity set that might look like?.

Yes, Mirek, it's Ben. Let me start. I think it's later this year. The economics of crude oil gathering are such that it's hard to make it work for single wells being drilled by themselves in delineation mode. It is much easier to make it work and competitive with trucking when you have multiwell pads being developed.

Something that we have seen late last year, and certainly so far in the first quarter, is the transition to pad drilling by more of our customers sooner than we expected.

And so, Devon, for instance, in their operations report highlights their Showboat development later this year, which is 15 to 20 wells in a single drilling unit, developing 3 Meramec horizons.

If you go and look at what Newfield said 2 days ago at the Crédit Suisse conference, they talked about up to 30 wells per drilling unit and have a gun barrel diagram showing 12 Meramec wells in the same section.

Just today, I know we have 1 producer who is operating 4 rigs in the same drilling unit, 4 rigs all lined up on the north side of the same road. It's that kind of development that makes it possible to go and make a crude gathering system work.

And it's something we're working on with multiple producers, and I expect we'll have some progress on that later this year. .

And is any of that in your guidance at this point?.

Mirek, this is Mike. It is not. .

The next question will come from Robert Balsamo with FBR. .

Just some clarification. In the Crude and Condensate segment, showing some good volume growth year-over-year, but obviously the segment profit per barrel is kind of falling off.

Is it just the newer assets generating a lower margin? Can you talk a little bit about that dynamic?.

Yes, Robert, this is Mac. What you see in the growth in the Crude and Condensate business is primarily oriented toward West Texas. Growth around our Chickadee system as well as growth on the supply and marketing side.

And so the -- if you're taking the barrel count and trying to do just an easy margin calculation, I think that's really somewhat misleading in terms of what the business is doing there.

The way the Chickadee barrel -- or the way the Chickadee business is structured is that those barrels are purchased by us and then sold by -- into Chickadee and then sold by us out of Chickadee. And so from a Crude and Condensate segment perspective, we're touching those barrels twice if you will.

We're touching them on the supply and marketing side, and then we are touching them on the pipeline tariff side. .

That's good clarification. And I wondered if you could address the -- in Louisiana, just the gas gathering and processing, obviously some headwinds there moving into '17, you've continually declines.

Is there anything you are seeing there, any potential flattening of those declines or any activity that's worth addressing at this point?.

Yes, Robert, this is Mac, again. On the gas side of the business in Louisiana, we continue to talk about the fact that we have what is the premier asset footprint in the state. When you look at what we've been able to do in terms of integrating those systems together and utilizing stories and the capability that brings, it's been significant.

You might have seen as you look through the operations report, we had a record year for volumes in Louisiana in 2016. That record year was greatly benefited by a significant volume of interruptible business. That interruptible business was largely pointed at the power market and through our Sabine pipeline Henry Hub facilities.

When it came time to provide guidance for 2017, we just didn't feel comfortable including all of those volumes in our number for 2017. I feel really good about our ability to compete for those. I feel real good about our ability to win those.

And what I'm happy to say is that if you look at a short window into 2017 we already have, our volume performance to date in 2017 looks very much like our volume performance on average in 2016. .

That's great.

So that upside is not included in the guidance?.

That's correct. .

And then just a follow-up on the previous question. Just -- you mentioned the reduced O&M cost in 2017 by $20 million kind of offsetting some potential headwinds from MVCs rolling off.

Could you just elaborate on those O&M costs like where -- what kind of savings they are, if that's sustainable, obviously, I assume it is, but just where it's coming from?.

Those are the cost reductions -- those are -- this is Steven. Those are the cost reductions that we've seen over the last 2 years. So 2017 is coming in $20 million lower than our 2015 numbers and it's just general O&M costs for the system wide, things like compression rental expenses and items like that. .

But it is $20 million versus 2015. .

Yes, it is the same. .

[Operator Instructions] The next question will come from Matt Niblack with HITE. .

Congratulations on the great performance here. Just wanted to clarify the Barnett refrac and development program, because I was looking through Devon's operations report and it seemed a little hazy in that report, sort of the timing and whether or not that was something that was approved versus being explored.

But your remark at the beginning suggests that maybe that had been approved. So forgive me if I missed something there.

But what is -- what's the status on the timing on that kind of redevelopment program in the Barnett?.

This is Steve, Matt. And as of now, we don't have a specific schedule that Devon's got in their plans. I know that they've got a number of things that they're working on in trying to establish that schedule. And it's refracs, it's work-overs on wells and it's possibly drilling 5 to 10 new wells.

So we're going to continue to work with them through the year and help support that program, but we don't have a specific schedule as of today. .

Okay, but the expectation is that, that's something that will get started this year or we're still waiting for a certain commodity environment that's not yet realized or... .

I think we are expecting to see that this year. I don't think it's necessarily driven by pricing. .

Matt, I think it was clear that it was in -- it is in their 2017 capital plan. They have allocated that capital. .

Got it. And so is the goal here to slow declines, or is the goal here to get to flat or to grow.

What's their operating objective?.

I think their operating objective is the same as ours, is to revitalize that basin and to apply, as Barry said, new drilling techniques and learn how those new techniques and new programs can help support the basin and where it falls in their portfolio. .

Okay.

So in terms of the degree to which declines are arrested or reversed, that's to be determined?.

That is correct, Matt. We've not seen a statement out of Devon of a specific target as far as flat or growing volumes out of the Barnett at this point. I think they're very much in a exploring opportunities mode at this time. .

Yes. It's Ben. Let's not lose sight of the big picture and Barry touched on it earlier. There really isn't an instance where a truly modern drilling and completion technique has been applied to the best acreage in the Barnett. And when you think of resource redevelopment, Barry gave the example of the Haynesville.

The Haynesville, like the Barnett was developed with frac 1.0. Well, now we're on frac 5.0. And I think it's an open question what happens when you apply frac 5.0 to the Barnett. That's what we're going to find out. It's going to be exciting to see. .

Well the other piece to that real quick is the refrac of getting that cost down to $700,000 per well. That's a very cost-effective way for them to go back in and recomplete all their older wells. Their portfolio is large. So 2 ways we're coming about at that. .

[Operator Instructions] The next question is from Sharon Lui with Wells Fargo. .

Just if you could provide some more details on the recent contract for the Lobo II.

Whether there's a step up in those volume commitments? And if you can potentially see a potential expansion of Lobo?.

Yes. Sharon, this is Steve. There was a step up in volume commitments with the recent contract. And where we are at today, as we alluded to earlier, we just put in Lobo II in service, that added 60 million a day. That plant came online in December.

We're already working on the expansion of that Lobo II, which is another 60 million a day that would will take Lobo II plant up to 120 million. When you combine that with our Lobo I plant, that gets us to 155 million.

You look at our current forecast, towards the end of this year, we would expect that we'd hit those volumes and be at that full capacity. So we are in, now and in the next few months, looking at what we're going to need to do as far as planning and timing for our third plant.

And we definitely see a lot of additional opportunity out there beyond just the contract that we signed today. We've got a number of deals that we're on the verge of completing and a number of new opportunities that are coming up as prices improve. So we're very encouraged by what we're seeing in the Delaware.

In fact, I'll mention that in January, we saw volumes through our Delaware system approaching 60 million a day. So we're definitely starting to see a lot of gas start to accumulate up there. And it's a very positive outcome that we're expecting this year. .

Great. And also, I guess, there is a potential to expand Riptide, I believe.

Can you maybe talk about the potential timing and capital requirements for that expansion?.

Yes. Riptide. This is Steve, again. And Riptide, we just completed last year, that was the expansion in the Midland Basin. With that expansion, it takes our Midland Basin processing capacity to 400 million a day.

As you look at the growth that we're projecting in the Midland Basin, it's going to run between 20% and 30% a year over the next few years, a good, stable, consistently growing asset. We really like the position we have in the basin in the core.

In fact, I'll note that when you saw the low prices, Barry in his comments had stated a year ago, we saw $26 oil. Well, we still had rigs operating in the Midland Basin at $26 oil. And we've got even more operating at $50 today. So we've seen a lot of good slow development in that area that is consistent with our plan.

When you look at the timing of that, we think we're well positioned for the next few years with our existing processing capacity. We don't anticipate needing an expansion within the next 2 years. But we are chasing some opportunities that could be very large that may see us -- that may drive an expansion.

Our next expansion phase for Riptide would add 100 million of capacity, and it would cost us in the neighborhood of about $30 million. So very economical when you look at what you see for processing plants and processing capacity. .

Ladies and gentlemen, this concludes our question-and-answer session. I would like to return the conference back over to Barry Davis for any closing remarks. .

Thank you, Chad. And thank you, again, to all of you who joined in today's call. We look forward to updating you on our first quarter results in May, and just hope you have a great day. And again, thank you for your support. Goodbye. .

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