EnLink Midstream LLC (ENLC) 2016 Q1 法說會逐字稿

Good morning and welcome to the EnLink Midstream first-quarter 2016 earnings conference call.

(Operator Instructions)

Please note this event is being recorded. I would now like to turn the conference over to Ms. Jill McMillan of EnLink Midstream Please go ahead.

Thank you, Chad. And good morning, everyone. Thank you for joining us today to discuss EnLink Midstream's first quarter 2016 results.

Participating on the call today are Barry Davis, President and Chief Executive Officer and Mike Garberding, an Executive Vice President and Chief Financial Officer. Additionally, Steve Hoppe, Executive Vice President and President of the Gas Gathering Processing and Transportation Business; Mac Hummel, Executive Vice President and President of the Natural Gas Liquids Crude and Condensate Business; and Ben Lamb, Senior Vice President of Finance and Corporate Development will be available in the Q&A portion of the call.

We issued our first-quarter 2016 earnings release yesterday. And we will file the 10-Q later today. To accompany today's call, we have posted the earnings release and operations report on the investor relations portion of our website. If you would like to listen to a recording of today's call, you can access a webcast replay 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'll 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.

I will now turn the call over to Barry Davis.

Thank you Jill. Good morning, everyone. Thank you for joining us. EnLink performed well in the first quarter in spite of the continued challenges our industry is experiencing. We are executing on the plan we laid out with a proven business model that has consistently delivered solid results because of our financial strength and the stability of our platform.

We have best-in-class assets positioned in the core of the core across the most attractive producing basins in the country and in the high-growth demand markets in the Louisiana Gulf Coast. We have stable cash flows from contracts with high-quality, investment-grade customers and a team of employees that are focused and committed to delivering results.

Today I'd like to begin by highlighting three main reasons that we are confident in our ability to meet the goals we laid out earlier this year. First, we are focused on the disciplined execution of our plan. Our priority this year is to maximize cash flows from our existing assets by reducing costs, increasing operating efficiencies and ensuring a lean G&A structure. We are focused on executing on projects in our core growth areas which include central Oklahoma, the Permian basin and Louisiana and on delivering best-in-class competitively priced services and serving as a true partner to our customers.

Second, EnLink's strong business model gives us the stability to execute through all market cycles. We benefit from stable cash flows supported by supported by fee-based contracts that have minimal direct commodity exposure. We project approximately 95% of our gross operating margin is fee-based and 75% of cash flows in our Texas and Oklahoma segments are supported by minimum volume commitments or firm contracts in 2016. We also have a high quality and diversified customer base, with approximately 90% of our revenue coming from counterparties with investment-grade credit profiles. These include customers like Chevron, Dow, Devon, Marathon and Williams among others.

Third EnLink is a best-positioned midstream companies. Our strong platform in each of our core growth areas derived in large part from acquisitions we've made over the last two years, allows us to execute on opportunities in the first mile of pipelines aggregating supply in high return basins like the STACK, SCOOP and Permian.

We have assets in six of the top 10 basins by internal rate of return and 14 of the top 16 counties by current horizontal rig count. Today producer customers are seeing excellent well results and reduced drilling costs in areas like Central Oklahoma and the Permian basin. For example, recent IP rates in the STACK range from 1,500 to 3,000 barrels of oil equivalent on our dedicated acreage, and in the Permian, recent IP rates range from 800 to 1,600 barrels of oil equivalent per day. We believe, with a modest sustained commodity recovery of around $50 to $55 per barrel, producers will add rigs in places we operate because they are some of the most economic and highest producing oil and gas regions in the country.

On the demand side, EnLink has the premier natural gas footprint and one of the most extensive NGL footprints in the state of Louisiana. Recent industry forecasts show that natural gas demand could grow from approximately 4 billion cubic feet per day in 2015 to approximately 12 billion cubic feet per day in 2020, a threefold increase, most of which would come from LNG exports and industrial growth. Our competitive advantages in Louisiana are the result of our ownership of the last mile of pipeline providing supply access to our consumer customers.

In summary, we remain confident that the execution of our strategies will position EnLink to be one of the premier midstream companies over the long term. We will continue to deliver value by maintaining our strong investment-grade balance sheet, delivering stable cash flows and providing best-in-basin services for our diverse high-quality customer base. Our commitment to our plan to focus and execute in 2016 will drive near-term results and allow us to succeed in any market cycle.

With that, let me turn the call over to Mike to review the financials.

Thanks, Barry, and good morning, everyone. Our ability to execute is underscored by a solid first-quarter consolidated adjusted EBITDA of approximately $195 million, which is around 16% higher than that of the first quarter 2015 and around 5% higher than that of the fourth quarter 2015. The stable cash flows from our business supported first-quarter distribution coverage of 1.09 times at ENLK and 1.04 times at ENLC.

Growth in cash flows in the first quarter were driven primarily by pressure reduction programs in North Texas, increased volumes in the Permian, the addition of the Tall Oak assets, and a reduction in operating expenses. This growth was partially offset by reduced NGL supply and fractionation volumes due to reduced drilling activity.

Additionally, our teams were able to reduce operating expenses by approximately $9 million compared to the fourth quarter of 2015, even after taking into account the addition of the Tall Oak assets. This expense reduction is a combination of successful cost-cutting initiatives as well as timing of spending. Most importantly we have continued to maintain a strong investment-grade balance sheet with ample liquidity.

We ended the first quarter with approximately 3.8 times leverage and approximately $900 million of liquidity on our revolving credit facility at ENLK. During the first quarter, Fitch gave ENLK its first rating and assigned an investment-grade, stand-alone credit rating of BBB Minus. To maintain our strong balance sheet, we continue to have significant optionality to finance our growth which includes a potential sale of non-core assets, issuing additional preferred equity for Tall Oak growth and opportunistic capital market activities. For the sale of non-core assets, we are considering selling our 31% non-operated ownership interest in Howard Energy Partners. We remain very focused and confident in our ability to maintain EnLink's strong balance sheet.

Turning to guidance, we expect lower performance in adjusted EBITDA for the second quarter 2016 compared to that of the first quarter, given the continued uncertainty in the commodity markets, but feel confident in meeting our financial goals for the year. We are very pleased with this solid performance and believe there's tremendous upside when commodity prices improve.

With strong asset platforms in the best oil and gas regions we are exactly where we want to be and see great opportunity for EnLink continue expanding and growing. While we encourage you to review the operations report posted on our website, we want to note a few highlights.

In Oklahoma, we are positioned in the core of a developing play with great customer diversity and significant growth opportunities. Producer activity remains strong around our assets with 10 rigs currently operating on our dedicated acreage. Integration of the Tall Oak midstream assets is going as planned and we expect to see significant growth from these assets this year and in the years to come.

In the first quarter we successfully completed a number of projects that expanded both the capacity and the extent of the system we acquired from Tall Oak which we now refer to as our Central Oklahoma system. We're creating a supersystem in the STACK, SCOOP, Cana-Woodford, and CNOW plays by interconnecting our Cana systems to our recently acquired Tall Oak assets and remain excited about the many opportunities to expand and grow in this area.

In the Permian Basin, we are focused on executing on the opportunities from our strong platform of assets, including leveraging our LPC business to develop new crude oil opportunities. When commodity prices improve, we expect our producer customers like Diamondback, RSP Permian, Matador and Reliance, to add rigs on our dedicated acreage. For example, Diamondback believes it could double its current rigs in the Midland Basin with sustained pricing between $45 to $55 per barrel. With the completion of the construction of the 100 million cubic feet per day Riptide Processing Plant, and additional high-pressure gathering pipelines, we have created a true supersystem within the core of the Midland basin and remain confident in our ability to drive bolt-on opportunities in 2016 and beyond from our strong platform of assets.

In North Texas we have the best platform that has continued to generate great cash flows with minimal capital investment. During the first quarter, we had a robust performance with segment cash flows of approximately $96 million, which is flat year over year, an increase of approximately $2 million from the fourth quarter 2015. This growth was largely driven by the connection of new wells, refracs of existing wells, and our efforts to offset the clients by lowering system pressures to increase deliverability. We previously projected an approximately 10% annual volume decline. However, we are now projecting declines of approximately 7% due to the execution of optimization efforts by our customers [announced] in North Texas.

In Louisiana, we were able to capitalize on significant market opportunities on both the NGL and natural gas side as a result of the size and flexibility of our assets. In fact, we initiated a new NGL project where we exported butane from our Riverside fractionator on the Mississippi River to customers in the Caribbean. We also expect to be able to reach Latin America markets and expert other products such as propane. Additionally, we expect to begin storing natural gas in early May at the Napoleonville Storage Facility we acquired from Chevron in late 2014 which provides additional optionality on our gas system. These two demand-driven projects helped demonstrate our superior position in Louisiana where we operate one of the most extensive gas and natural gas liquids footprints. Furthermore, we have additional growth projects coming online in Louisiana, all of which offer excellent IRRs with relatively low capital costs as a result of exposure to Louisiana's growing demand.

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

Thank you, Mike. We remain focused on the disciplined execution of our plan, putting us in the best possible position when markets rebound. We are delivering solid results with a strong business model that provides stability in all market cycles. We are one of the best positioned midstream companies. Our strong platform allows us to execute on opportunities in the first mile of supply in high return basins like the STACK, SCOOP and Permian, while our premier natural gas and NGL footprint in Louisiana provides us the last mile in a high-demand growth market.

With that, Chad, you may open the lines for questions. And I'll remind that we have a broad group of Management here, as Jill outlined, that are ready to answer your questions.

Thank you, sir.

(Operator Instructions)

T.J. Schultz, RBC Capital Markets.

Great. Thanks. Good morning, everybody. First on Tall Oak, as we think about Scoop, Stack, to what extent may some of the good well performance we have seen be able to mitigate fewer rigs compared to expectations when you entered that transaction? And further if you can provide any color on outlook you have for investment or cash flow ramp as you look at possible extensions, just the potential investment and view to ultimately get that investment to high single digit EBITDA multiples on the purchase price?

Good morning, T.J., it's Ben. Great question. First of all, I want to say that you're right to say that the wells have gotten better. And you don't have to look beyond Devon's operations report to see that. And two in particular that I'd highlight, their [born free] pilot, which was a two-well downspacing test where the wells came in at an average of 2,200 BOEs a day.

And then further south, really at the end of what we think is the core of the volatile oil window, the [Calspace] well that came on at 2,150 BOEs a day. Those were about 70% above Devon's tight curve and significantly exceed our assumption in the Tall Oak acquisition.

But picking up on part of your question, at this point our activity levels are right where we expected them to be. We've got 11 rigs operating on dedicated acreage from six different producer customers and that's very much in line with what we expected at the time of the acquisition.

Now looking into the end of the year and beyond, of course, it will be a function of price. But to your point, if we do see continued softness in prices, I do think the quality of the well results will help make up for that. At this point, though, we see good activity levels.

In terms of the investment, at the time of the acquisition we told you that we expected to spend about $350 million in follow-on capital this year. On the last call we told you that was down to $180 million because of the benefit of combining the Tall Oak systems with our legacy Cana system and our ability to optimize processing capacity between those assets.

That's still our expectation today. But I would say don't be surprised if we continue to see these well results if we need to accelerate the addition of processing capacity or of our Oklahoma Express project a little bit further or a little bit closer to us in time.

Okay. Good. Thank you. Moving to South Louisiana, a couple questions. First your exporting butane looks like relatively small CapEx project, but if you could expand there on contracts on the butane exports to the Caribbean? And then as we think about the potential for propane exports, where are you on contracts for exports to Latin America?

T.J., this is Mac Hummel. Thank you. That's an exciting development in our Louisiana business to be able to export product out of South Louisiana, something that we've been asked about at times over the last couple years, really, and it's exciting to see it come to fruition.

We did load butane out of Riverside. The first cargo in April that went to the Caribbean. We expect to be able to reach the Caribbean and Latin America countries with exports out of Riverside. I think it's safe to say at this point we're still feeling the market out a little bit in terms of exactly the level of contribution that that's going to create to us.

We do expect over time that we're going to establish relationships with additional carriers that allow us to move additional volumes more ratably through the system than we're seeing in this startup period. But our expectations are for both butane and propane to be exported out of Riverside.

Okay. Great. Lastly, on balance sheet management, you have a lot of different levers that you discuss. Just maybe how should we think about prioritizing those as we get through 2016? You talked about Howard. Is that something that could be a potential 2016 sale? And then as we think about the ATM, if you can tell us to what extent that's been used year to date maybe?

Yes. This is Mike. It all starts with a strong balance sheet and we think we've done a good job really managing that. And that, again, goes to the business and the business structure, but as well as the optionality we entered this year on financing.

As we mentioned on the last call, we have a lot of levers we can look to, whether it's deferring capital, whether it's [tall-up] financing on preferred sale of assets, et cetera. But that optionality is how we think of it, that it's not necessarily any one but is probably a combination of all of the above.

We did say that we are going to look at some non-core assets and one of those we're currently working through is the Howard Energy Partners. We have talked quite a bit about that in the last couple of calls just on what we think; it's a great management team, a great set of assets. It's a process we're going through and we will make ultimately a decision on it this year, so it would be a 2016 item.

To give you sort of a view of that business, for our 31% interest, we have about $200 million on the balance sheet and distributable cash flow for us is expected to be this year somewhere between $20 million to $25 million. But the nice thing for us is that flexibility, that we're not reliant upon any one of those things with regard to financing our capital.

T.J., this is Barry. And just let me just emphasize the word you heard Mike say a number of times was optionality. That is the way we look at all of the ways we can capitalize our business this year and the sale of Howard is something that is an option. We very much feel good about the business, particularly in the long-term, with their big projects that they have announced, the Mexico project, et cetera.

The prospects for that business are great. But because they're great, it probably will give us the ability to execute on a sale at an attractive price. To the extent that it doesn't, then we certainly would use other levers, if you will, for financing this year.

From an ATM standpoint in the first quarter, we actually had very little ATM activity. It was under $5 million. But on the offset of that, we also issued the large preferred for Tall Oak in the first quarter too.

Got it. Thanks, everybody.

Thanks, T.J.

Darren Horowitz, Raymond James

Morning, guys. First question is on the Permian. When we last spoke I think your forecast was to spend somewhere around $120 million or $140 million. And you had outlined the two processing plant completions. And thinking about what was just mentioned with regard to Spraberry economics and the volume uplift now that everybody's expecting, how has your capital allocation model shifted? Is it a situation where you really want to emphasize CapEx with returns in mind around the LPC business on the crude side?

Or is it maybe a bit more balanced between adding more processing capacity maybe or residue gas line or a rich gas line moving east? I'm just wondering how that composition of capital might have shifted a bit?

Yes, Darren, this is Steve Hoppe. Let me just remind you were specifically targeting this area, part of the Midland Basin because of the results you're seeing today and it does look a lot like what we just discussed in the Stack and the Scoop areas. We see this as being a very positive for overall for our results in there.

If you recall, we have just completed the Riptide Plant. That's a $100 million a day plant that we're bringing online. It was actually brought online this month. When you take those out and you take that plant and you combine it with our Bearcat Plant, our Deadwood Plant and the other Coronado Plants that we have in the acquisition, we will have $400 million of processing capacity available today. We think were in a great position with processing capacity right now to ramp up volumes very quickly and that's what we're expecting to see as we see a return of commodity prices in the area.

In addition, with the ability of the producers to drill the better wells and increase their performance, we're in a great position to really add a lot of that capacity. We've got the capacity in place and we'll just need to add additional compression and pipeline facilities. We're planning our capital investment around that right now.

But it is something that we don't think is going to have a significant impact to capital plans for the Midland Basin this year. It may accelerate some of the capital that we had put into 2017 into 2016, but it's all stuff that really is part of the plan and we're right on track with our original plans for our total capital investment with Coronado and right on track with our volumes on Coronado, so we're real pleased with the results in this business plan overall.

With regard to leveraging that further and maybe getting those physical barrels down the supply chain, does it make sense to really want to capitalize on that Y-grade across to the Louisiana NGL platform and backstop some additional fractionation capacity so you have control of the downstream logistics of the purity product? Or how do we think about the volumes coming out of the tailgate of those plants?

Darren, I think you hit the bull's-eye right there. And that is as we continue to grow our Permian gas volumes and therefore our Permian NGL volumes, we will see those volumes end up largely in the Cajun-Sibon system, so as those volumes build, we'll see a corresponding benefit on the NGL side of the business.

And you're right, it gives us an opportunity to get those barrels into Cajun-Sibon where we can realize the full NGL value uplift that we can get on those. It ranges from not only the fractionation fees we can charge, the ethane sales we can make, as well as the sales of the heavy. So very positive benefit, not only to the gas business, but also to the NGL business.

Maybe just to highlight one thing, Darren, we're able to do that without owning the pipes in between.

That's right. We have supply contracts that allow us to get those barrels from the outlet of our plant to the inlet of Cajun-Sibon.

Okay.

And, Darren, to add on to that, let me just say that you've heard us for several years now talk about scale and diversity. I think in this call you got a great picture of what that begins to look like in really kind of really in four of our largest and most focused areas right, that being Central Oklahoma, the Permian. With those two supersystems as we're seeing come together there, the expansive system that we have in Louisiana and in North Texas.

What you see there really is multiple steps in the value chain across the midstream and really optionality as we continue to bolt on services and continue to serve the same customers in different ways. I think you'll continue to see opportunities and results come out of that.

And, Barry, I just might mention one more thing, that the piece of the Permian that we haven't talked about that Darren asked about was LPC and the crude business. We continue to be very active with LPC, continue to provide great service to customers there.

And importantly, LPC is doing one of the things we thought it would, which is increase our opportunity [at deal flow]. We are going to be -- have signed an agreement to build a small gathering system for a customer that we previously have been trucking their barrels for. That's something that we expected to be able to do, so were executing on the plan that we laid out when we entered the basin. We're also hopeful that those kind of opportunities will lever even into more and more pipe opportunities for us as we go forward.

I appreciate that. Thank you very much.

Thank you, Darren.

Brian Gamble, Simmons & Company.

Hello, Brian.

Good morning, everybody. Good morning. A couple things for me. One on the kind of near-term guidance, you mentioned some softness on the fractionation side in Louisiana just based on scheduled maintenance for the quarter.

Obviously Tall Oak benefited the quarter but maybe not a full quarter benefit there as the closing went in. But we're offsetting that and saying second quarter is weaker. I know there's some seasonality in there, but maybe walk us through the benefits that we're seeing in second quarter versus some of the offsets, just things to think about from a kind of macro perspective as we walk into the next couple of months?

Yes. This is Mike. I think the first thing that people ought to hear is our confidence and capability on meeting the targets we set out for the year. That's, I think, one of the key takeaways you should hear from what we're saying. With regard to first quarter, second quarter, really I think it's us being realistic in the sense of the environment we're operating in.

We have seen some strengthening in crude, but is it sustained, is it not? We're trying to be realistic in the sense of what we might see ahead. You saw us talk about that in fourth quarter, and you saw, ultimately, the results in the first quarter.

I'm going to let Mac address NGLs, but you can see in areas like North Texas, for example, what that team has been able to do both from a margin standpoint and an expense standpoint because of the position they have. So it's continued to be a great cash flow generator for this business.

Brian, you also mentioned the Louisiana piece. And we did have a relatively weaker Q1 than we expected to have, mostly on the volume side of the business. There is the maintenance that you mentioned in January which was a contributor to that. We've also seen some weakness generally in upstream volumes as gas volumes in the areas that we get NGL supply has come down; NGL supply has come down also.

Steve mentioned that the benefits we see in the Permian business and clearly, as we talked about, that will roll through to the NGL side of the business. We also have in the back half of 2016 a number of projects that we have executed on or are executing on now in our NGL business which really don't contribute at all to Q1 performance, but will contribute to Q2, Q3 and Q4 performance.

We remain expectant that will be able to hit the guidance we talked about on the NGL side of the business too, despite the fact that we're in a challenging supply environment.

Great answers on both fronts. Obviously appreciate the realism in this market. You never know when the crude market's going to give you a head fake and then dive the other direction, so appreciate that.

On the North Texas piece specifically, taking the decline rate down to (inaudible) that 7% from the 10% previous (inaudible) on working through that and the market there to be more beneficial than you thought? Any potential to get even underneath that 7%? What are we seeing from the optimization piece? Are there other levers that you guys are trying to pull now that may be able to get that even flatter as we move forward?

Yes, Brian, this is Steve. So I think North Texas is just a great story. Really what's driving that is the work that we're doing, that our team's doing and that we're during with our customers. It's just a combined effort that is really driving those results. And overall, it's just like you said, it's pulling a lot of levers is what's making that happen.

We've seen excellent refrac results from Devon. I think in their latest report they've even reported their 30 horizontal refracs, and it's just been -- the results are much better up than those than we expected. The pressure reductions are offsetting declines; we're seeing benefits from that.

We're driving our operating costs lower and we're looking at consolidation opportunities. We're even got new well connects that we added in this quarter. We probably added about 16 new wells of supply for this quarter, so you wouldn't expect it but we're seeing some drilling and some activity. Really it's just the team's focus and our execution on all of those that is driving these results.

We're very focused on executing on our business plan in North Texas. We see this as a great asset for us, not just now but well into the future to generate some really sensational cash flows.

Good color. Appreciate it.

Thank you, Brian.

John Edwards, Credit Suisse

Good morning, everybody. And thanks for taking my question. In light of the guidance of the second quarter you're expecting to be a little bit softer just for modeling. Can you help us here? Do you expect then -- because first quarter here was pretty strong, do you expect the first half to be about the same as the second half or a little bit lighter? Maybe help us out for that granularity.

Yes, John, this is Barry. Let me comment and then I'm going to pass it to Mike. I was tempted to throw this in, in the answer to Brian, but here's one of the good things that's happened. In an organization that has great people and great continuity, the tenure of our people who are executing these assets is really exceptional. I don't know the number, but I'm going to say 15 years probably on average that we've been operating these assets and executing.

And so what you see in a downturn like this is they continue to find opportunities and pull levers and be creative and always finding the next thing. So when we go through a quarter like the first quarter, which in January and February looked like it was as critical as anything we've seen in a long time, I think people do extraordinary things.

When you then ask people what they're going to do going forward, they're fairly humble and I would say would be very conservative in their ability to continue to deliver that. I think you see that. But I would also say don't overlook the extraordinary efforts in what we're seeing people do in a challenging time.

So, Mike, if you can speak to the numbers.

Yes. So, John, I think you can look at the key drivers (inaudible) from a business standpoint like Ben walked through at the beginning of the call, that is going to be a key to the back end of the year, is going to be continued growth in Tall Oak or Steve's continued growth in Midland or Mac continued growth, hopefully, in the projects they're doing in the liquids business.

So when you think about it, one is we're very confident in meeting the projections we've put out there. You can start saying that you have an expectation to ramp on the back half of the year.

Okay. So just to make sure I understand, so basically you're saying you think it's going to be slightly weighted to the back half? Is that a fair understanding?

Yes. If we were given the growth we project in these assets and all we're trying to make sure is be realistic with regard to the second quarter, given where we see the crude market today.

Yes. Okay. Great; appreciate that. And then following on Brian's question on North Texas. It looks like you did a great job there. I think you indicated you were able to cut operating expenses and that was one reason why you were able to have cash flows up year on year.

I mean, is your outlook there continuing to run at these levels? Or do you expect maybe a slight decline here just given the inherent volumetric issues? Maybe if you could talk a little bit about that?

Yes, John, this is Steve. As Barry kind of alluded, we really did a lot in the first quarter to focus on costs and cost management. Not only absolute reduction of costs, but timing of costs as well.

We will see some of the savings that we realized in the first quarter move into subsequent quarters in the year, so we'll give a little bit of that back. I do mean a little bit because I'm kind of like Barry in the belief that we're going to continue to see our people perform and execute.

I'm very positive on that they're setting new standards and that we're going to see our costs in North Texas continue to track down relative to the volumes. We're working on that. It is a focus of us in our business plan and in our execution plan. Right now we're probably looking at a total savings this year of about $6 million to $7 million in North Texas and we're going to continue to push that in into the future.

Okay. And then just on the Howard Energy investment, just switching gears here to that. What was the expected growth trajectory you're expecting there? I think you said you're expecting that to the annualized deliveries around $25 million of cash distributions and it's got a good future. Just give us an idea of what was the ramp, the growth ramp you're expecting on that?

Yes, John, this is Mike. When you think about Howard, there's a [$25 million] of our distributable cash flow represents the business as it is today. And as Barry mentioned, the exciting thing for Howard is what they're doing and really developing, I'll say, additional businesses namely into Mexico, a large-scale natural gas opportunity and then some other products also.

Those are projects that will come to fruition over that 2017, 2018 timeframe and are very large-scale. The big issue there is really positioning that business with a lot more capital to grow with the opportunities that it has today. We see it run by a wonderful Management team that has created some great opportunities. We feel very good about how it's going to be received in the marketplace.

Okay. And then can give us an idea, when you say large-scale, the kind of -- your share of investment, should you hold on to that opportunity?

It all depends on how the projects are financed. Some of these assets have a capability to do project financing on them because of the contracts really from the Mexican counter-party. And that's what Howard is looking to do.

What we've said this year is that we have around $100 million in our capital plan that would be our portion for the Howard assets. And ultimately there would be optionality around that if we did sell the asset.

Okay. And then just anything that's surprised you in this downturn? And do you view second quarter as the likely bottom of activity?

John, this is Barry. What I would say is there probably have been a lot of things that we didn't predict, but we prepared for. So we really haven't been surprised by anything. We think the business model that we've got is showing exactly why it is designed the way it is and it's resiliency through this cycle. It's hard to predict where the bottom is in the cycle.

I would say, just based on our expectation of what activity levels are going to be, we would expect activity levels to pick up in the second half of this year. That being said, we still have solid activity across all of the growth areas that we are focused on. Anything from here is upside.

And here's the thing, and we want to remind folks all the time. We don't need $80 in order to see a pick up in activity. We believe in the $50 to $55 range, we will see significant increase in activity because we're in the best basins with the highest return and that's the first place the rigs are going to come back to.

Okay. Fair enough. I'll leave it there; thank you.

Thank you, John.

Jeremy Tonet, JPMorgan.

Hey, this is Neal BasuMullick on for Jeremy. How's it going? We very much appreciate the coverage this quarter. But I guess as Class C units that are currently [taking] switch to cash and but also a strong back half of the year that you've been talking about, how are you thinking about coverage for the balance of the year?

Yes. Good question. You are correct, the next quarter the C units, and those were a part of the Coronado acquisition that picked from basically a five-quarter period. You could see a little less coverage in Q2 as compared to Q1 because of that, but ultimately we feel confident in the guidance we gave at the beginning of the year with regard to one times our rate of coverage with regard to ENLK for the year.

Great. That's really helpful. And then I guess in terms of the optionality $500 million of convertible preferred. You've had a lot of success in deferring CapEx so far, so I guess how are you thinking about a decision there?

I guess it goes back to what you said is the optionality. We know we have that option and we'll continue to look at all the sources, but in all likelihood it is going to be a combination of all those sources with regard to financing. And then that's what we like is having that capability to do that.

And as we mentioned when we talk about how much equity we thought we needed with regard to the capital plan we laid out, we said it was less than $200 million. So from an execution standpoint, we feel we're in a great position to execute on that plan.

Great. That's helpful. Just one more question. On the crude and condensate segment, as of now you're delivering to two barge loading dock at the Port of Victoria, but are there any other market outlooks you're looking at?

Yes, Neil, this is Mac. We are looking at ways to expand our market reach there. Probably not ready to talk about the kind of markets we're looking at, but we do recognize that one of our opportunities there is not only to get additional supply reach or barrels into the pipeline, but to create market options on the downstream side. And so, yes, we are looking at those.

Great. That's helpful.

Mirek Zac, Citigroup

Hello, guys, just one quick one from me. Good morning. Related to CapEx, with the rig counts where they are, costs coming down and how you see the development progressing on your acreage, where do you see growth CapEx possibly coming out for the rest of the year relative to your prior guidance? Is there a possibility of shifting more CapEx out of 2016 and possibly even going below your guidance? And how material could a potential reduction be?

Yes. This is Mike. It's a good question and, again, it goes back in to the optionality. So if you look in the first quarter, we spent about $120 million, and that was with a capital plan we came out with of $400 million to $550 million -- or $450 million to $550 million. Where we sit today, we still believe we're on that same trajectory for plan.

However, if you see prices increase, you have opportunities like Ben talked about, how we'll continue to look at opportunities within Tall Oak on additional processing. We have opportunities like Steve talked about as far as connecting additional volumes through mainly compression and pipe. We feel good about the plan we've laid out, that it's a good realistic plan on executing that's really driven by what we're seeing from our customers today. But really on plan.

Okay. Thank you; that's all for me.

Thank you.

Helen Raiu, Barclays.

Thank you. Good morning. On the comment about the frac volume, some of that is driven by NGL price, some scheduled maintenance. What are the magnitude, which one was the bigger sort of contributor?

And did the scheduled maintenance, is that finished? Is that something you expect to pick up second quarter in terms of cash flow?

Helen, this is Mac Hummel. The scheduled maintenance that we talked about was in the month of January. That maintenance is behind us but as just an ongoing part of the integrity of our business, we will have scheduled maintenance that is appropriate to do and we will conduct that maintenance as we see the need to. Over for January on the fracs but going forward, just an ongoing part of our business that we need to do.

With regards to the proportion of impact, I don't have that in precise terms but the majority of the impact was related to supply and NGL volumes upstream of Cajun-Sibon more so than the impact of the scheduled maintenance in January.

Got it. So just less supply showing up given weak NGL volume?

Yes. If you take a look at drilling activity and gas volumes, you see that they're down a little bit. You see that NGL volumes will correspondingly be down because of that.

And as an industry, we continue to reject a significant amount of ethane. Some reports have it around 500,000 barrels a day of ethane being rejected. We're still seeing significant rejection on suppliers or from suppliers that supply Cajun-Sibon. So it's the price impact, plus it's just this issue around ethane and how quickly that strengthens and, therefore, how quickly that volume comes back into the market.

Actually, that was my next question, so thanks for bringing that up. Wondering -- so everybody believes that with the crackers coming online we're going to have to recover, a lot of the ethane is being rejected today. And just trying to understand how you're going to benefit? I guess on the GMP side you're like 95% fee-based, so you'll get some benefit on some POP margins, but is it fair to assume that you will see more benefit in terms of dollar terms in the NGL side of the business, your Louisiana business?

And if so, how should we think about maybe the magnitude? If you could maybe mention what kind of access capacity you have on your NGL system today? So that if all that ethane shows up, how much of an upside you would see without having to spend CapEx? Is that something you could maybe talk about?

Yes, I can, Helen. And, again, this is Mac. In our Louisiana processing business, so let's talk about first the gas and then the NGLs. In the Louisiana gas processing business, most of our opportunity there is to capture the value of the liquids ourselves as opposed to being a fee-based business.

So we're constantly on the look for additional supplies that we can process through those plants. As ethane becomes more and more economic, then it gives us the opportunity to more economically extract ethane, so it would help us from a margin standpoint and it would help us from a volume standpoint.

I'll move into the NGL side of the business. There's a clear positive impact to us with regards to additional ethane extraction and additional ethane barrels coming in to the NGL system. It's relatively spread in terms of benefit throughout the NGL business. Number one, is will get more volumes into the Cajun-Sibon pipeline and fractionation facilities.

Number two, we will lighten the barrel. In other words, a typical barrel will be made up -- once we get into significant recovery in the industry, will be made up of more and more ethane. As that happens, that increases the efficiency of our fractionators. So that's a second benefit.

A third benefit will be as we have more additional ethane in our feedstock to our fractionators, it means we will have more purity ethane on the backstream of those fractionators to sell to Dow and Williams, our ethane customers. So it's a pretty impactful in terms of our Louisiana business, both on the gas side and the NGL side.

Okay. That is very helpful. Appreciate the color.

Yes.

Thank you, Helen.

Jeff Birnbaum, Wunderlich.

Good morning, everyone. Most of my questions have already been asked and answered, so just one question and sort of a couple housekeeping items. Ben, you mentioned earlier the Oklahoma Express Project and I guess I was curious if there was an update you could give on that or when we might expect either sort of news or things you are working through on that.

Certainly leverages ticked down a bit here. You've talked about the financial flexibility you have. Obviously there's a volume need there too, but just some color on that would be helpful.

Yes, Jeff. There's no doubt in our minds that the right answer for the industry and for our Company is to connect our Central Oklahoma assets with our North Texas assets. The question that we're working through is whether this is the right time for that.

Given the state of uncertainty in the industry, I think it is questionable whether we will find the right level of producer support to go forward with Oklahoma Express at this time. That's what we're working through. If that answer is no, then instead we will be adding processing capacity in Oklahoma. And looking to Oklahoma Express as the step beyond that as opposed to doing it in the other order.

I would just leave you with the thought that we're working on that every day and the state of our capacity planning and our producer customers' plans is very dynamic.

Okay. Thanks. That's helpful. Can you actually give any color on what the actual volumes on the Tall Oak assets themselves were in the first quarter?

Yes. Here is how I would think about it generally. If you look on page 10 of the operations report, you'll see our gathered volumes are up by about 185,000 in MMBtus a day, Q1 of 2015 to Q1 of 2016. In rough terms, about two-thirds of that is Tall Oak and one-third is on the legacy Cana system driven mainly by Devon's completions in the Gordon Row.

Great. Thanks. And then last kind of housekeeping question for me, quarter over quarter, the crude volumes, crude handling volumes, were down about 11%. Can you drill down about what the drivers were there?

Yes. Jeff, this is Mac Hummel. As we continue to see relatively low prices and relatively muted activity on the drilling side, we have seen some pressure on volumes quarter to quarter from fourth quarter 2015 into first quarter of 2016.

We've seen that in our [ORV] business. Actually we've seen some of that weakness across our ORV, our West Texas and our South Texas businesses. I'd say in general what we're seeing is just kind of a continuation of the general industry environment we're in where activity is down a little bit and volumes are showing that in the basins that we've got our crude and condensate footprint.

But on the flip side -- this is Mike -- that team has done a fabulous job of resetting costs just like Steve talked about for North Texas. They've really managed their costs down, so from an overall margin standpoint, they've done a good job of trying to sustain that margin even in the declining volume timeframe.

Yes. And, Mike, our guidance is unchanged relative to our crude business. Just to pile on a little bit with what Mike said, and really what Steve has said, and that is on the operations side of the business, they've done an absolutely phenomenal job turning over stones and finding opportunities for us to save money. And as we've seen some of that weakness that I talked about quarter to quarter, we are taking the steps on the operation side of the business to make sure that we keep our costs in alignment with that and add value where we can, even in that difficult market.

All makes sense. Thanks a lot, guys.

Thank you.

David Amos, Heinemann Energy.

Good morning, guys. I wanted to go back to the Stack for a second, which I think great results there. So when you consider volumes well ahead of your fiscal year plan, appreciate the comments on what 2Q might look like versus 1Q, but Devon's results coming out 70% above the type curve. Can you just kind of frame that in terms of what did 1Q look like versus your original internal thoughts on volumes?

And then follow-up question is from a volumetric perspective, when do you think you need to add new processing capacity in that play?

David, to take those two pieces in terms of their performance in the first quarter, what I would say is, it's early days. We're only four months into our ownership of these assets. Even if individual well results are 70% above the type curve, while it may auger well for the future, it doesn't necessarily translate into blowing out our expectations on the first quarter. Where we are today in terms of our expectation for the year is generally unchanged from where we were at the time of the acquisition.

And remind me of the second part of your question? When we need to up the processing capacity. What we were doing, you heard Mike use the term supersystem a couple times in his prepared remarks, and I think Barry said it again, answering one of the questions. What we're in the process of doing is combining the legacy Tall Oak systems, Battle Ridge and Chisholm, with our legacy Cana system and then optimizing processing capacity across all of those.

So today with the Union pipeline, we can move gas from Chisholm over to Battle Ridge and we have been doing that in the first quarter. By the end of the second quarter, we expect to be able to do the same thing with our Cana system and be able to use processing capacity at Cana that we expect will be available.

What we are working through is working with our producer customers to understand their volume profiles to know when we run out of capacity across those three systems. When we last spoke to you in the last call, we thought that we were not going to need to add processing capacity until later in 2017. All signs are indicating that we may need to accelerate those plans as a result of these better well results, but we're not at this point ready to make that determination.

Okay. Go ahead; sorry.

Sorry, Dave, this is Steve. Something else I think that it's important to note is that with the Tall Oak acquisition, we actually have a plant as part of our inventory, so we've got a plant that we already own that would be the next step in that capacity expansion for processing.

Okay. That's helpful. Thank you. And then on the NGL side, again, trying to wrap our heads around what the potential for EBITDA plus might be in a better commodity environment. Can you frame what the historical contribution from that business has been, and maybe in context of what commodity prices were doing at the time?

Yes, so if you look at the big piece of the NGL business, it is really Cajun-Sibon. And there was two pieces to Cajun-Sibon that came in really over a year to 18-month period. So we told the market ultimately we thought Cajun-Sibon was an asset that could be $100 million to $110 million asset run rate cash flows when we thought it was full.

It's not necessarily dependent upon commodity prices. There is some uptick like Mac talked about, but the base amount of that really is driven by the fee-based margin you get on both the supply side and the demand side.

Okay. Thanks. Appreciate it.

Thank you, David.

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

Thank you, Chad. In closing, we are focused on the key strategies we will execute on this year. We remain committed to maintaining our financial strength and we remain confident we can create value for our unitholders and customers with stable fee-based contracts, strong customer relationships, diversity of basins and services, and strong partnerships with our producer customers. Thank you for joining us on the call today.

Thank you, sir. The conference is now concluded. Thank you for attending. You may now disconnect.