Ladies and gentlemen, thank you for standing by. Welcome to EnLink Midstream's First Quarter Earnings Call. [Operator Instructions] Please note that this call is being recorded today, Wednesday, May 1, 2019 at 09:00 AM 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 first quarter of 2019 earnings.

Participating on the call today are Barry Davis, Executive Chairman; Mike Garberding, President and Chief Executive Officer; Eric Batchelder, Executive Vice President and Chief Financial Officer; and Ben Lamb, Executive Vice President and Chief Operating Officer.

To accompany today's call, we have posted our earnings press 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 on our website.

I will remind you that statements made during this conference call about the future, including our expectations or predictions, should be considered forward-looking statements within the meaning of the federal security laws. Actual results may differ materially from what is described in these forward-looking statements.

Forward-looking statements speak only as of the date of this call and we undertake no obligation to update or revise any forward-looking statement.

Additional information on factors that could cause actual results to differ from what is described in these forward-looking statements and sources for certain statements we make herein are available in the earnings press release and the operations report accompanying this call located at enlink.com and in our SEC filings.

This call also includes certain non-GAAP financial measures. Definitions of these measures as well as reconciliations of comparable GAAP measures are available in our earnings press release and our operations report on enlink.com.

We encourage you to review the cautionary statements and other disclosures made in our earnings press release and our SEC filings, including those under the heading Risk Factors. As a quick reminder, we modified our segment reporting to better align with how we are running our business.

Any comparisons between 2019 and 2018 at a segment level are done using 2018 segment results recast into the 2019 segment reporting methodology. The structure of the call will be to start with prepared remarks by Barry, Mike and Eric, 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 as we report our first quarter and discuss our outlook as a newly simplified EnLink. As with our corporate structure, we've been very intentional with building EnLink's large integrated asset platform in premier supply basins and key demand centers.

That purposeful approach is paying off with the business generating strong cash flows and our ability to repeatedly bolt-on highly accretive projects. As I stand back and look at the business we have built together, 3 things stand out for me.

First, our differentiated asset platform is performing very well with cash flows from our diversified operations exceeding not only our expectations, but the market's expectations as well. We're on track to achieve our company level 2019 and long-term financial objectives.

Second, we continue to execute with excellence and place highly accretive projects into service. We recently completed our Lobo III natural gas processing plant expansion and with increased producer activity on our footprint, the volume ramp will now exceed original expectations.

We also recently completed our Cajun-Sibon III NGL pipeline expansion, which will be able to transport 185,000 barrels of NGLs from the Mont Belvieu hub to our fractionators in Louisiana.

And the third thing that stands out to me is that the combination of our strong customer relationships and our growing asset platform continues to drive new high return opportunities for us.

We recently announced plants to accelerate our pace of growth in the Permian with a new 200 million a day natural gas processing plant in the Delaware Basin and a project to access additional capacity to our Riptide facility in the Midland Basin. EnLink is operating in an increasingly constructive environment.

And on the supply side, we see some attractive macro-trends emerging. Number one, we have a supportive oil price environment. Number two, we have a producer community even more focused on capital allocation living within free cash flow and ensuring sustainable growth over the long term.

And number three, we have continued drilling advances driving capital efficiencies, enhancing returns and bolstering financial strength. One of the key areas of growing capital efficiencies for producers relates to drilling multi-zone large scale developments.

As producers transitioned from the exploration phase to the full field development phase, drilling cycle times significantly shortened leading to more wells being drilled with fewer rigs. Specifically for EnLink, we've seen strong rig consistency over the past few years across our growth basins.

Looking ahead, we expect to see rig count naturally come down throughout 2019 as rig efficiency ramps. Ben will likely give you more color on this during the Q&A portion.

As producers evolve their development strategies, we believe integrated midstream companies positioned in key areas like us will be the beneficiaries of their optimized well productivity, their increasingly focused capital allocation plans and ultimately their improved development returns.

In terms of attractive macro-trends on the demand side, exports of all commodities are on the rise. And our assets in Louisiana position us perfectly to play a meaningful role in that growth. We've a number of projects that our team is developing, vetting and in the advanced stages of negotiating and all with attractive returns.

At the end of the day, returns are what create value for energy companies and returns are certainly at the heart of the decisions we make every day at EnLink. We're making return based decisions every day to drive value creation and to return value to all stakeholders over the long term. With that, I'll turn it over to Mike..

Thanks, Barry. And good morning, everyone. I think Barry summed up very nicely where we are. The business is performing very well with strong diversified cash flows being generated from our 4 operating segments. We continue to execute with excellence and bolt-on highly accretive projects to a differentiated midstream platform.

And our deep customer relationships are driving incremental high return projects. A great example of deep relationships driving opportunities is the expansion in the Delaware Basin we announced yesterday.

EnLink has a longstanding relationship with XTO, a subsidiary of ExxonMobil, who is one of the most active operators and one of our key customers in the Permian Basin. XTO recently upsized their growth plans in the Permian.

EnLink is honored to be a key service provider developing required infrastructures for XTO's production plants and we will be growing right along with them. Our updated outlook forecast at our Lobo natural gas processing complex will be nearing full capacity in 2020 requiring additional processing capacity to be added up in the next 18 months.

As a result, we plan to construct a new 200 million cubic feet per day gas processing plant in the Delaware Basin. We estimate that to develop the plant and associated compression and gathering infrastructure, we'll invest around $240 million over the project period.

Texas project, as part of EnLink's Delaware joint venture, will share this investment with our partner NGP with the net cost to EnLink of approximately $120 million including around $60 million expected to be spent during 2019.

The project's adjusted EBITDA multiple is expected to be around 5 times to 6 times and demonstrates our commitment to highly accretive expansions. And we're doing all of this with no changes to our net 2019 growth capital expenditure range through effective capital allocation among our growing asset areas. Turning now to Oklahoma.

First and foremost, we've an unwavering belief in the long-term growth in Oklahoma and the STACK's position as a top tier growth play. Not all factors are same, but we believe we have some of the best acreage where the 3 counties come together, Canadian, Blaine and Kingfisher. This area is very consistent with the Midland based on economics.

Second, the Oklahoma segment is still in transition. Devon continues to optimize its drilling completion strategy which it is executing on today. Encana continues to integrate and establish its plans for the new field acquisition and Roan adapts to being a newly public and independent company.

The sequentially lower volumes we saw in the first quarter of 2019 as compared to the fourth quarter of 2018 were primarily driven by these customer transitions as well as other transitory factors such as weather.

While some aspects of this transition have taken a bit longer than we anticipated, we still have a great confidence in Oklahoma being a meaningful contributor to our growth in the quarters and years ahead, and we believe we have one of the best positions in the STACK. Overall, we expect to see volume growth of 10% to 15% in 2019 as compared to 2018.

We're already seeing volume growth in the Oklahoma segment with April gas volumes approximately 5% higher than average first quarter volumes and April crude volumes almost double the average we realized during the first quarter.

In the first quarter, we saw fewer than 20% of the total number of wells we expect for the year to be placed online and many of those came online at the end of the quarter. Of the remaining wells we expect to see online for the balance of the year, approximately 90% are known locations on producer provided schedules.

From a capital expenditures perspective, we expect Oklahoma program to scale up and down with volume growth as the majority of spent is now on gathering and compression infrastructure.

The STACK is undoubtedly a top tier supply play with very competitive economics and it will continue to be a core growth asset for us this year and for many years to come.

Because of the strength and diversity of our business and the growth we're seeing in Oklahoma, we're maintaining our company-wide outlook for 2019 including adjusted EBITDA of $1.13 billion at the midpoint and our long-term financial outlook for 2019 through 2021.

Now turning to North Texas, our Barnett position continues to be a strong contributor through diversified cash flows. Recently we made a relatively small acquisition, less than $25 million, to consolidate a competitor's operations on the southwest side of our footprint.

The acquisition has an adjusted EBITDA multiple of approximately 5 times to 6 times and is a step forward in efficiently growing cash flows. Running out of 4 operational segments is Louisiana. Our Louisiana segment continues to be a steady growth area for us.

We brought Cajun-Sibon III online recently, like Barry mentioned, and we'll able to transport approximately 185,000 barrels of NGLs to our fractionation complex in Louisiana. We continue to closely monitor the evolution of the NGL market, are in a good place right now with the fractionation capacity we have secured.

We continue to see steady natural gas transmission volumes across our Louisiana network and we saw an uptick in processing volumes this quarter due to a positive commodity environment. Louisiana remains a tremendous source of opportunity for us.

As Barry mentioned, there're some very favorable macro-trends around exporting that play right into our asset platform strengths. We are pursuing projects across all commodities and are very encouraged with how a number of these potential projects are developing. Stepping back now and taking a look at the total company, EnLink is right on plan.

I could not be more confident in what our team is striving for in accomplishing. We're exactly where we need to be, executing on exactly what we set out to do and most importantly, we're achieving the returns we set out to achieve. With that, I'll now turn the call over to Eric to give us an update on financial performance and outlook..

Thank you, Mike. And good morning, everyone. As Barry and Mike have highlighted, EnLink delivered strong cash flow results for the first quarter of 2019. We achieved adjusted EBITDA of $268 million for the quarter, which exceeded both company and street expectations.

Our distributable cash flow of $185 million for the quarter also exceeded company and street expectations. Distribution coverage was 1.35 times for the quarter, again exceeding both company and street expectations and in line with our long-term targeted range of 1.3 times to 1.5 times.

Our Permian business achieved over 100% growth in segment profit in the first quarter of 2019 when compared to the first quarter of 2018. Oklahoma segment profit increased over 15% when comparing first quarter 2019 to first quarter 2018. And Louisiana also reported solid segment profit growth.

As expected, segment profit for North Texas decreased by approximately 16%, which was driven by the expiration of our minimum volume commitments with Devon Energy in the Barnett at the end of 2018.

However, as a result of our team's focus on expense management and optimization, we exceeded cash flow expectations from the North Texas segment for the first quarter.

Because of the strength and diversification of our cash flows from the business, EnLink continued to increase its quarterly distributions in the first quarter of 2019 with an annualized increase of approximately 6% when compared to the 2018 declared distributions.

From a leverage perspective, we achieved a solid debt-to-adjusted EBITDA ratio of 3.7 times as calculated per our credit facility, which is consistent with our long-term financial goals. We continue to maintain a flexible liquidity position and exited the quarter with revolver availability of around $1.6 billion.

We also closed a very successful $500 million senior notes offering in April, which significantly reduces our need to access the capital markets.

From a capital allocation standpoint, our priorities remain to increasingly fund highly accretive projects with cash flow from the business and create and return value to our stakeholders while maintaining our key financial metrics.

As we evaluate longer dated, larger projects, we continue to view global infrastructure partners as a potential partner to support future opportunities. One other item I would like to briefly address is the topic of asset sales because it comes up a lot in conversations.

As we've discussed on prior calls, we've taken steps over the last few years to high grade our asset base and don't have planned asset sales of any magnitude at this time. There may be a small asset here and there that we monetize, but nothing significant at this time.

Our 2019 growth capital expenditure outlook for EnLink continues to be projected in the range of $565 million to $725 million net to EnLink. During the first quarter of 2019, we spent approximately $220 million on growth capital expenditures as most of our larger projects will be in-service during the first half of the year.

We expect the incremental growth capital expenditures in the Permian related to our new plant expansions to be offset by contributions from our Delaware basin joint venture partner and reduced growth capital expenditures in other segments.

We maintain our 3-year aggregate growth capital outlook of $1.2 billion to $1.5 billion with the expectation that project returns will be on average in the 5 times to 6 times range.

Building on what Mike said earlier about us being on track and on plan for 2019, we have reaffirmed our company level financial 2019 guidance ranges presented in the materials released on February 19 with the exception of net income.

Net income has been revised downward to a range of $18 million to $28 million for 2019 as a result of a goodwill impairment we recorded in connection with the closing of our simplification transaction on January 25. Excluding this noncash goodwill impact, our net income guidance is consistent with original guidance.

From a long-term outlook perspective, our financial tenants remain unchanged and we continue to target distributable cash flow per unit growth of 10% plus from 2019 to 2021, long-term distribution coverage of 1.3 time to 1.5 time, and debt to adjusted EBITDA of 3.5 time to 4 time as calculated by our credit facility.

Our strong financial outlook supports our commitment to sustainably creating and returning value to stakeholders over the long term. With that, I'll now turn it back over to Mike..

Thanks, Eric. To sum it all up, value creation is what we are focused on and executing highly accretive projects is driving tremendous value creation for us.

We have a talented team that wakes up each day thinking about how to make EnLink better and stronger, and we have deep industry and customer relationships that continue to provide robust opportunities for us. 2019 is off to a great start and we're excited for all accomplishments to come. With that, you may open the call up for questions..

[Operator Instructions] Our first question will come from Dennis Coleman of Bank of America Merrill Lynch..

I wonder if we might start with the guidance, some numbers a little bit confusing. It seems like there's a lower volumes in Oklahoma and that should, I guess, likely translate into some hit to EBITDA, but the guidance remains the same for 2019. And so I guess just to put that broad question out there, if you can help us square that..

Dennis, this is Mike. So let me start with this. We have great confidence in the business, in the execution we're seeing and also in our 2019 company-wide outlook. Like you had mentioned, there is concerns or questions around with revisions to Oklahoma and what does that mean to guidance.

I think the first thing you need to take away is again the diversified business is driving our results. And I think that's something that people may be missing. But if you start with the first quarter, you can truly see that. So just look at EBITDA.

EBITDA was around $268 for the quarter which was above company level and market expectation, so great execution if you just break that apart and look what's driving it. North Texas performance, over-performance for the quarter with that bolt-on acquisition which is accretive. Louisiana performance, over-performance for the quarter.

Permian performance, over-performance for the quarter with new contracts added that are accretive and really start up today. And as you mentioned, Oklahoma really relatively flat, but still growing.

And assuming Ben is going to address as part of this too is really the understanding of how you think about volume to margin because that's not a one-for-one or equal relationship on what we're seeing in Oklahoma today. So then how do you take all that in consideration for guidance? So start again with the first quarter.

So first quarter is $10 million ahead of market expectations from a cash-flow standpoint. In the first half of the year, we have four big projects coming on. We have Lobo III, we have Thunderbird, Avenger and Cajun-Sibon III. Of that, Lobo III and Cajun-Sibon III are already up and running. So new big drivers of cash flow.

If you think about those 3 segments I talked about, the strength of those segments voiced on first quarter, I just used 2019 guidance as an example. So if you look at the difference of those 3 segments between mid and high, that's again North Texas, Louisiana and Permian, that's about $40 million.

If you look at the 2 new accretive things we're doing, which is both the bolt-on opportunities in the Permian as well as the acquisition, that also is providing results to 2019. If you look at Oklahoma and you look at Oklahoma between mid and low, that's about $40 million.

When we look at that growth in Oklahoma, we see it somewhere around that low end and Ben will talk further on that. So again when you add all that up and the drivers of that diversified cash flow that are driving the business today and over-performing today, that's what gives us confidence.

We feel great about what we're seeing for the business, but again it's a story of all those assets and Oklahoma is a piece of that story. So, Dennis, again we feel good about the trajectory of the business..

Okay. That's great. Was Ben going to add something there on Oklahoma….

Yes, Dennis. I think what's coming through in the couple of research now that came out last night is people wanting to better understand the change in Oklahoma. And there is really 3 factors there. The first factor is timing and well count as a result of those customer transitions that Mike talked about in his prepared remarks.

So we had fewer than expected well turn to sales in the first quarter, really just delays. We also had some updates from producers for the balance of the year where some of them have paired some activity levels. And we've trued all of that up in the 10% to 15% revision that we came out with this morning.

The second thing is really around production strategy. We've seen some of the producers more aggressively choke the wells early in their lives. We understand they are doing that because they think that that will improve the EUR over time by resulting in lower decline rates.

What we've done in our new estimate for Oklahoma growth is we've reflected lower IP rates, but at this point we have not reflected lower decline rates. And the third thing was weather. We had 3 fairly significant freezing events in the mid-continent that all hit in the late winter. And so when you look at those, that was 20,000 to 25,000 MMBtu's a day.

So the quarter really came together differently than we expected. We saw our highest volumes in January, lower volumes in February, lower volumes still in March, and that's how we got the first quarter result. But as Mike said, April was looking great. We're already 5% above our Q1 result on gas volumes in the month of April.

So again the important thing to remember, the 10% to 15% range that we've given you accounts for all 3 of those factors that we've talked about. We're seeing the results come to fruition in April.

And as Mike said, about 90% of the wells we expect for the year, the remainder of the year are already on producer provided schedules with a handful of exceptions being some of the smaller guys who maybe don't give us data out to the end of the year.

And on the margin point, Mike said that the volume change doesn't necessarily translate one-to-one into a margin change and that's because the quality of our team in Oklahoma, we've been able to capture little bit higher margins per unit than we expected to and that's through better recoveries at the plants.

It's through optimizing our fuel burn and other factors like that. So it would be maybe not their best assumption to assume that because volume is down by x%, that margin is necessarily down by that same percentage..

Okay. That's super helpful. Thanks for all of that detail. I guess just to make sure I'm hearing it correctly, so Oklahoma may be towards the low end of the range.

Do you still think you will hit the low end of the range or could it be a little bit below?.

Dennis, this is Mike. I think as far as where we sit today, again as we're in early innings, we sit around the low end of the range. As Ben said, there's just -- there's a lot of things that we can do to continue to optimize that business. And as we said, we're really in a transition period for a lot of our key producer customers, Devon and Encana.

Encana had a call yesterday and talked again about their initial successes of what they are doing there, but they disclosed their transaction in the first quarter. And so look, we have a strong belief in the long-term productivity of what we're seeing in Oklahoma and love what we're seeing, but again this quarter really represents a transition.

So when you get back to how do we think about it for the year, we sit around the low side of guidance. But the statement you need to hear is from a company standpoint, that diversification of business is driving the cash flow of the business that you closed in the first quarter..

Our next question will come from TJ Schultz of RBC Capital Markets..

The $1.2 billion to $1.5 billion of growth CapEx through 2021, so the bulk of that's still for well connects and I understand just placing some of that in 2019 with the plants just given the producer plants in the STACK.

But are you changing any assumptions on well connect capital in the STACK in 2020 and 2021 or do you expect activity to kind of return to levels that were previously in the guidance?.

TJ, it's Eric. We have not changed the $1.2 billion to $1.5 billion. Like you said, the mix changes a little bit because of the processing plant and as you note as well, this year's mix and guidance hasn't changed which represents some of the flags that Mike referred to in his prepared remarks in terms of going up and down with activity.

But I think as Ben outlined and as Mike mentioned, we still have strong confidence in the STACK and what's going to happen over the few years and that's all incorporated into that $1.2 billion to $1.5 billion as we continue to build out the quick to cash, laterals, compression and things like that will continue to be part of that overall spend..

TJ, this is Mike. And I think a lot like you're alluding to is it's really some level of timing like we talked about and for us it's optimization of our platform, which was truly done in the first quarter and we will continue to do.

And then because of the quick to cash and the timing of capital, we have the capability to do that and still be flat capital for 2019. I think that's incredibly important for people to hear is our capability to shift between that but still have accretive projects filling it around and still have that growth platform in Oklahoma too..

Okay. Thanks.

And then just lastly, the trajectory out of Oklahoma now, what does just mean for utilization downstream and your needs for frac capacity over the next couple of years?.

TJ, it's Ben. It doesn't really mean anything for frac volumes in 2019 because we have multiple ways of filling those fractionators. We fill them not only with the Oklahoma business, but also with our West Texas volumes and now a portion of our North Texas volumes in addition to the NGLs from the opportunity processing that we do in Louisiana.

So I don't see any change to our outlook for the fractionators being full in the second half of the year. As far as the longer term frac outlook, that really hasn't changed either.

When you combine our equity fractionators with the capacity at GCF that we expect to have in 2020, and the third party frac deal that we talked about in the last quarterly call that also comes on at the beginning of 2020, we think we are well positioned on frac capacity through late 2021 and that gives us the luxury of seeing how the frac market develop since we have so many projects that are already in flight in Mont Belvieu..

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

I just want to maybe start with Louisiana. I think you noted there was incremental opportunity processing events that helped on the quarter.

Just wondering if you could explain that a little bit more and do you see those kind of recurring over the balance of the year?.

Yes, Jeremy, it's Ben. It's a couple of things. One is we were successful in being able to direct to the processing plants some streams of gas that was processible. It's lean gas, but it's processible, coming off of interstate pipelines. Sometimes that happens because you see ethane rejection in the Northeast.

And so the ethane ends up coming to Louisiana in the pipeline and that accrues to our benefit. We've also seen some of our neighboring facilities in Louisiana unable to handle their volumes because they've had operational issues. And so we've been able to capitalize on that as well.

So certainly wouldn't expect necessarily for those neighboring operational issues to continue throughout the year. But for the opportunity gas coming off of the interstate pipelines, yes, that is a possibility. And really what will control that through the balance of the year is whether we have a home for the NGLs.

And with the fractionators now expanded where capacity is about 193,000, it's obviously composition dependent. But we expect to be able to handle some of that opportunity gas for the balance of the year. Yes..

Yes. I think, Jeremy, when you look at it too and you look at the history of Louisiana, it's exactly that. And you can see that over the last 12-18 months is the capability of that system, really for opportunities because you have so much product moving into that market.

And opportunity processing is one of those you saw in the gas side to continue growth in the gas market. So we feel really good about what we're seeing in Louisiana as far as those additional opportunities..

Maybe just peeling a little bit more, how much would you say is the frac spread from the straddle plants versus kind of the new projects coming online, versus maybe some of those onetime events or possibly onetime events because Louisiana results this quarter were kind of the strongest that we've seen in a very long time.

And so just trying to figure out what kind of a ratable number to think about going forward..

Yes, I'd hesitate to give you a ratable number, Jeremy. I mean, in either case, whichever way the opportunity gas gets to us, it's lean gas, right? It's not like field gas from the Permian or the mid-continent. It's primarily ethane and propane.

And we've all seen that the ethane and the propane market are in a fairly low spot right now, probably $0.24 to $0.25 on ethane. And so the frac spread is thin. But since we own the fractionators and all it cost us to fractionate the marginal barrel is some operating costs, it's great, great business for us when we get it..

But Ben alluded to, it is lower margin business as compared to the other..

Got you.

And one -- just last one on Louisiana if I could, was there any uplift as far as Perryville, any kind of basis spreads around there that helped out in the quarter or is everything Louisiana gas really just going to fee based there?.

No, that's not really a factor for us. A factor that as you're trying to understand the great performance that we've seen in Louisiana gas. One factor is, we saw good load in our kind of urban markets that we normally see more in the summer when it's hot outside and everyone has their air conditioners on.

We've actually seen it last through the winter and in the spring, which was stronger than what we expected to see..

Great. And just last one if I could, with the goodwill impairment, could you explain that a little bit more what was happening there? Just wanted to make sure we're clear off the top there..

Yes, sure. Thanks Jeremy. Look, when EnLink was formed in 2014, there was a goodwill that was created and it gets allocated to the IDRs that were owned by ENLC. So when we close the simplification in January, those IDRs were cancelled and GAAP requires that that previously corporate level goodwill gets allocated out to the operating segments.

And so, first, you have to calculate the relative value of each of the segments. And then the overall market value of the business is effectively the ceiling. And then the goodwill gets allocated out to that to each segment and then compared to the book value of each segment.

And so that led to a difference between the book and the fair market value for the Louisiana segment. It's really a GAAP-driven analysis that it's part of, like I said, sort of the IDRs going away and corporate level goodwill that they require you to push down and move around across the segments..

The next question will come from Shneur Gershuni of UBS..

Just starting off with the guidance again, sorry to have 11 questions on it today. But in some of your responses, you talked about the fact that there's a margin pick up in crude that we may be under-appreciating.

I was wondering if you can give us a little bit more color around the margin on the crude side with respect to margins as well as contract mix, and at the same time if you can contrast that against the theoretical EBITDA impact of the reduced volumes that you had on guidance.

So if we can sort of get the pieces of what's taking it up, what's the offset versus what the negative impact of taking the Oklahoma volumes down..

the 2 in Oklahoma and then a venture in the Delaware come in really over the past 6 months or so. So for us, it's been more of a game of volume growth that you'll continue to see over time. So for crude on margins, I think margins have been decently stable. We've seen some good stability in ORV, for example, as far as volumes too.

So stable plus growing there. And then I'll turn it over to Ben..

Shneur, and maybe I need to clarify some of what I said. On the margin side in Oklahoma, I was not speaking solely to crude. I was talking about the entire segment. So when you think about the fact that we had been forecasting a certain volume level in Oklahoma, now we're forecasting a lower volume level.

All I'm trying to say is, we're seeing stronger margin performance across the Oklahoma business than we expected to see.

And while we're not providing an updated segment profit range for Oklahoma today, we're saying that you shouldn't just assume that if growth is downshifted in volumes by x percentage, that you should necessarily shift out a segment profit by the same percentage because we are making up a piece of that on margin.

And again, that's driven by things like better recoveries. It's driven by things like lower fuel burn. It's driven by things like product marketing. It's all of the things that our team does so well, day in and day out..

No, I think we get that and we know that you've been adding projects and so forth.

It just sort of, I guess, what we -- the collective we I guess, the real question is, are we overestimating the gas side and underestimating the crude side? And so kind of my question about what was the theoretical impact of EBITDA on guidance for taking down the volumes may help us better understand that there's more value on one side versus the other so that we can square away the fact that the guidance, they effectively stays the same.

And I understand your point about margin across the board being better. But I guess trying to better understand the impact of the gas side versus the crude side. And maybe we're overestimating the impact on the gas side. And that's why you've had so many surprising questions about surprising and trying to understand it today.

And if you can clarify that like that gas volumes would have cost us $20 million, but the margin gives us $20 million, some details around that I think would really be helpful for your listeners today..

Yes, Shneur. This is Mike again. It's a good question. I think that's exactly what's happening. Again I think you can't hear enough from us, again the confidence we have and what we're seeing in Oklahoma, and again we're talking about a transition here, not a longer term point of view.

And so when you say how do you think about the margin, Ben walked through in the gas side and I commented for the Oklahoma segment that we'd be around the low end when you think about the atoma.

And so what I think what people have been doing again is using basically the change in volume to do a absolute change in margin for Oklahoma on a percentage basis. And there's 2 pieces to that which I think that people are overestimating the impact.

One is, as Ben walked through, is the gas margin is our capability to continue to provide margin opportunities and get a greater overall gas margin. And the second is what you're saying is really the crude piece and we talked in our script of prepared comments about crude volumes and the growth we're seeing in crude volumes.

It's starting from a smaller point, but it is a very growing piece of our business. And so I think that all combined gets to the point you're making and helps give us confidence in what we're seeing. But most importantly, it is a diversified business.

We have a lot of good things happening across our platform that are driving opportunities that give us confidence of where we are in guidance..

Okay, fair enough. In just sort of digging in on the volume guidance for Oklahoma and Ben, you gave some great color to some of the prior questions in terms of well counts and so forth.

You and I actually had a back and forth during the fourth quarter call specifically about this and you talked about why we couldn't look at Devon's guidance because of net revenue interests and so forth, and that they're really 2 different numbers and so forth. But now we've guided volumes down, it sort of seems to be following Devon's trend.

Can we look to what the EMPs are doing or are you still thinking about it as it's 2 different numbers? And how should we think about this volume trend as we sort of think about 2020?.

Yes, Shneur. So it's certainly 2 different numbers because of all those things that you and I talked about in the last call, which is that really the gross versus net.

We -- what matters to us from Devon or any producer is their gross production and what matters to them is their net production and so in their numbers they're taking into account their net revenue interests and they're taking into account their percentage interest in other producers' operated production that accounts for their working interest.

Certainly you can look to our producers as a group and you can look to what Devon is saying about the play, you can look to what in Encana is saying about the play, Marathon, Roan and the others.

But I would still caution you against tying too closely anyone's comments about their net production to what we see, which is the gross -- the gross production.

With Devon in this particular quarter, as I outlined the 3 factors that we saw in the quarter, the timing, the production strategy and the weather, we had a little bit of timing impact around Devon, but really the production strategy is a big part of what we saw in the first quarter.

We just saw the wells come on with lower IPs than we previously expected and we think that's because they're doing something different managing the reservoir. In the fullness of time, we think that that should result in higher EURs. What we've done today though is we've lowered our IP expectations in resetting our guidance for 10% to 15% growth.

We have not yet accounted for any benefit from lower decline rates over time. That's what we expect to see, but since we don't actually have data on it yet or enough data to make a judgment, we haven't factored that into our thinking yet..

Okay. Fair enough. Just leaving the whole guidance discussion for a little bit here, I was wondering if you can talk about the Exxon opportunity for potential growth in CapEx.

Do they have takeaway capacity for gas and NGLs or will you be handling that, will Exxon be handling that? I was just wondering if you can give us a little bit more color on that..

Yes, Shneur, happy to talk about that. I think a lot of people followed Exxon's Investor Day given how big a part they play in our industry. But just in case anyone didn't, their 2018 communication was that they were going to grow to 600,000 BOEs a day by 2025. What they said in 2019 was now that 1 million BOEs a day by 2024.

So close to doubling within a shorter time period. And we're fortunate that we're going to be beneficiaries of that because XTO is one of our longest standing customers in the basin. And so that increase in XTOs Exxon's focus includes our acreage.

As far as the downstream arrangements, they handle all of that for themselves and as you know, they have a number of infrastructure projects that they've invested in themselves to make sure that they have takeaway for their gas and their crude.

So we're focused on gathering compression and processing of that volume, and that's what underpins our announcement today of the new cryogenic facility in the Delaware..

The next question will come from Colton Bean of Tudor, Pickering, Holt..

Just to come back to TJ's question there on the CapEx spend. I think you guys provided the reconciliation of your prior 2019 look and updated I think the CapEx flex bucket was around $60 million and included in that was the North Texas acquisition and the Riptide expense.

So is the implication from that that Oklahoma came down by $90-ish million and if so, how do we think about that again in context of that $1.2 billion to $1.5 billion? Because it seems like the 5% reduction for Oklahoma over that 3-year time frame is effectively all accounted for or maybe even modestly over accounted for just in 2019.

So any thoughts there would be helpful..

Yes, I would say, first of all I wouldn't go directly to say that it's all Oklahoma, right. There's segments and other things going on. There's a lot of diversification across the platform that has ebbs and flows.

And as we sit here today 1 quarter into the next 3 years, there's a lot of things that whether it's direct adjustments related to activity or things that come in at a different cost as we move further along looking at certain things, that has an impact on some of that flex.

And so that's why when we look out over the broad period, we think we're going to have an ebb and flow across various time periods in the short term, which get backs to some of the solitude nature of the business as a whole that I think Ben has referenced in the past.

But when we look over the entirety of the 3-year period, that we still expect to be in that $1.2 billion to $1.5 billion range overall..

And just as it relates Oklahoma, it sounds like based on that and the prior commentary that the expectations are flat or even potential for those to move slightly higher for 2020 and 2021?.

Yes. So this is, Mike. Yes, and so when you think about what we're doing in Oklahoma, in other areas, it's really a shifting of capital to the highest term project and how we think about things. And so we again have that capability to do that.

So when you think about Oklahoma, Ben mentioned that we're seeing 5% growth in volumes starting in April and we'll continue to see that volume growth over the year. That volume growth will continue and we'll continue to have capital. So I think the right way for you to think about it again is some shifting of capital between the periods.

But you also have to go to what Eric said is that capital also changed. I used the Riptide expansion as example.

Over that 3-year period when we talked Riptide in the past, we talked about it at a number about 3 times of what we're executing on, little bit smaller volume than we thought, but to take things like that in consideration on how we're spending capital more efficient in the broader whole. So I think it's those couple of pieces are driving it..

And just briefly on Louisiana, I think on the Q4 call, you all noted you had had a contract roll off there in the gathering division.

Given the Q1 result, are we effectively through that re-contracting phase or anything still to watch out for over the course of the year?.

Yes. What you're talking about is transportation contracts in north leg and we've had some roll-off. We do still have a little bit of that business that will roll-off over the course of this year, but all of that was already accounted for in the Louisiana segment guidance that we gave you earlier in the year.

So there's certainly no surprises coming up in that regard..

Your next question will come from Mirek Zak of Citi..

Can you provide some more color on the customer and contract mix around the reduction in the Oklahoma volumes? And also what are your expectations of, if those specific rigs or producer activity are expected to come back as the producers rework the play or have you seen those producers more permanently move elsewhere, perhaps to the SCOOP or STACK acreage not dedicated to EnLink? Any color you can provide around that would be helpful..

Yes, Mirek, happy to talk a little bit about that. So let me go through the 3 factors. We actually saw a number of producers have impacts in that first bucket of timing and well count. That was not isolated to any one producer. And as Mike said in his prepared remarks, we have a number of producers that are going through one or other form of transition.

With Devon, it's their strategy around the play with Encana, it's integrating the new field acquisition with Roan, it's their transition into a public company and we could add others on that list. So it was certainly not any one producer. In terms of long-term expectations, no, there's no one who has picked up their toys and gone home.

That's not the case at all. For all of our big, significant producers, the STACK is either their number 1 or their number 2 funded asset in the portfolio and we don't see that changing. So while it's way too early to speculate about 2020 activity, we won't know about that until we get into the fall and the producer budget cycle.

What we do know is that we have a lot of confidence around this asset growing in the future and while the 10% to 15% guidance that we've given you today is lower than what we'd hope for, for 2019, it's still a very large number against an asset that today is gathering north of $1.2 million MMBtu's a day..

Yes, Mirek, this is Mike again. I think you can use Devon as a great example on the transition. They have a slide in their ops report which talks about the continued development around the 4 to 6 wells and what they're seeing on those wells. And that transition has really been happening over the last 3 to 6 months.

And so it's not necessarily to your point of rigs picking up, it's them continuing to work through the transition to that new development which they're having success on. You can look to Encana, the same thing and Roan the same thing. So for us, again it's a transition.

We still have great confidence on what we're seeing in the STACK and that long-term growth of what we're going to see in the STACK. But 10% to 15% this year is what we're seeing today. It is going to continue to lead to that longer term growth..

Okay. Got it. And thoughts around your Delaware processing outlook maybe and how XTO volumes are involved there.

Meaning, is the new plant fully committed to XTO or were there additional third party commitments here and would this plant suffice for the growth plans you expect to see out of XTO over the next few years? And also if you can give us an idea of how many rigs XTO actually has on your Permian acreage at this point..

Yes, so Mirek, in terms of whether it's fully committed to XTO, it is not. It will be just like the Lobo complex; it will serve all of our producers. But the increase in activity from XTO relative to our expectation at the first of the year is what led us to make this announcement now.

So now we have near-term line of sight, the Lobo complex being full in 2020 and the change from our original expectation today is largely driven by the increase in activity with XTO. As far as activity on the footprint today, off the top of my head I don't know that answer. They've had some activity honest this year.

I don't know the rig count at this red hot minute. But since we're looking at a 2020, 2021, 2022 plan from XTO, it's too early to say there's been a significant ramp in drilling activity.

That's a company they plan, as we all know, very far ahead and they are relatively insensitive to market changes which is another thing we like about having them as a customer..

The next question will come from Praneeth Satish with Wells Fargo..

On the potential LPG export project, can you may be just talking about the competitive advantages EnLink would have versus other incumbents in the area? It seems like competition is picking up there..

Yes, Praneeth.

So the big picture and it's not just on LPG export, it's broader than that, is that we have a commanding position on the Louisiana Gulf Coast and just like our fractionation business was really built in being an alternative to Mont Belvieu, a nice diversification for producers who previously had all their rigs in one basket in Mont Belvieu and now they can have the rigs in 2 baskets, Belvieu and in Louisiana.

We think that Louisiana offers the same thing for LPG and for that matter for crude exports.

And so the strategic advantage potentially is offering some diversification away from the Houston Ship Channel and the fact that today most of our North American export capacity for LPG is in that one spot and there obviously are some logistical and operational challenges that come with that..

Okay, thanks.

And then I guess just sticking to Louisiana, can you just talk about maybe how much available capacity you have on the gas system there? I guess in the event that one of the new LNG export projects gets FID'ed, how much capacity there do you have that could support one of those projects?.

So there's a couple of layers there. First, the capacity of the Louisiana system is not easy to put into a pity bullet. We have, I think it's over 60 receipt points over 50 market deliveries, not counting deliveries into other pipelines. The fellow who runs that business for us likes to refer to it as a reticulated system.

It has a lot of capacity from a lot of points to a lot of other points. And so it's hard to say we just have extra capacity available. But we do have capacity available with very little capital to serve some of that LNG load. We've done some of that on uninterruptible basis and we are looking at opportunities to affirm some of that up.

But the bigger picture than that is we have the ability to add capacity to that system in a very capital efficient way by adding compression or a little bit of line looping or a little bit of line extension. That's the benefit of having a couple thousand miles of pipeline already in the ground and much of it large diameter pipe..

Got it. And then just last question from me.

I guess with the Encana moving to cube development in the STACK, can you just touch on how that impacts you guys? Meaning, are there any efficiencies there on either the operating cost or well connect CapEx side?.

Yes, and I won't even limit it just to Encana. Certainly Encana is a market leader in efficiency and I talked a lot about that yesterday in their call. I'd encourage everybody to go look back at what they said. But it's really across the basin.

And Encana specifically made a comment yesterday saying that they intend to run a 4-rig level loaded program and they expect to be able to drill and complete almost as many wells as new field was doing with an 11-rig program. Not quite, but almost.

And similarly in the last call we talked about Devon and the comparison of their rig efficiency between the Delaware Basin and the STACK.

But really what you're getting at is as the STACK matures, it take fewer rigs and for that matter fewer producer capital dollars to drill and complete the same number of wells as they realize efficiencies from drilling the wells on multi-well pads and generally in smaller focus areas than they were at the time when they were delineating the play and they were moving all around their acreage..

Our next question will come from Spiro Dounis from Credit Suisse..

You mentioned earlier in the call just increasingly seeing GIP as a partner on growth projects.

And so I was wondering if you brought a little more color there, specifically is that I guess what's making you say that now that you're sort of increasingly seeing that as a partner and then more broadly what form does that take? Is it a JV on a project or is it directly through the [indiscernible] equity?.

Spiro, it's Mike. So this is something we've been very focused on. It all starts with our platform. We think we have a perfect platform and business to grow from. We also think that you've seen a shift in the overall market that represent opportunities for us. One of the big things that really differentiate parties in this market is access to capital.

And what we've seen with GIP is a capability to do and willingness to do based on the past history of what they've done in their investments. And so for us, what we see is a capability to be very thoughtful, selective to continue to build out our platforms in and around the basins with them as a partner. And so we think it's a great position to be in.

We think it's quite different than others. It's not structured financing coming in, it's a partner that owns a large position that's building up the platform with you. So for us, again we couldn't be at a better position because it again starts with our great platform and then we think the market is going to give us capabilities to build around that..

Okay. I appreciate the color.

And then just to clarify, would that be on incremental projects from here or could we see them come in and partner up on current projects in your CapEx budget now?.

I think you could see any of the above because again for us it's, as Ben alluded to in Louisiana, Louisiana is something that had a small allocation of capital and are $1.3 billion to $1.5 billion. Yet we have a lot of opportunities among all of the commodities in Louisiana. So we see some things there that can be pretty interesting.

So it could be at that level, it could be straight away M&A, it can be all of those. And again, but we're going to be very disciplined on how we do things and it's going to be around our core platform..

Got it. One last one from me, I believe it's quick. Ben, I think it was your comment just around expecting rigs to naturally come down in Oklahoma, but that obviously being offset by some of the well efficiencies.

I guess I was curious, has that been proven out or do you risk yet on either a smaller or larger scale by the producer or customers, and have you risked your guidance from your customers beyond just not accounting for the slower decline rates?.

Yes, so first part of your question, has it been de-risked as to the efficiency gains? That answer is yes. You can just look at what Devon's doing in terms of their well count this year versus last year. This year it's 85 to 95 wells turn to sales, I think there's about 80 spuds. That's down a little bit from last year.

But this year they're running 4 to 5 rigs whereas last year they ran 8 for most of the year. So I think we can say that that is happening in the real world. And I'd also point you to again to what Newfield said yesterday in their call and for the second time I won't repeat it all.

As far as risking Oklahoma volumes the rest of the year, I'd just reiterate that when we build up our volume for Oklahoma, that informs our 10% to 15% growth guidance '19 over 2018. 90% of those wells are on schedule as the producer has given us generally with the rig name and lat-long on it. So that's as real as it gets.

I mean we're not in the business of writing guarantees because the world can always change, but it's hard to see how we could be any more sure of that activity at this point than we are with the communication that we've been provided..

Ladies and gentlemen, this will conclude our question and answer session. At this time, I'd like to turn the conference back over to Mike Garberding for any closing remarks..

Thank you, Allison, for still doing our call this morning and for everyone on the call today. Thank you for your participation and for your support. We look forward to updating you with our second quarter results in August..

Thank you. The conference is now concluded. We thank everyone for attending today's presentation. You may now disconnect your lines..