Enterprise Products Partners L.P. (EPD) Q4 2018 Earnings Report, Transcript and Summary

Good morning. My name is Tiffany, and I will be your conference operator today. At this time, I would like to welcome everyone to the fourth quarter 2018 earnings call. [Operator Instructions]. Randy Burkhalter, you may begin your conference.

Thank you, Tiffany. Good morning, everyone, and welcome to the Enterprise Products Partners conference call to discuss fourth quarter 2018 earnings. Our speakers today will be Jim Teague, Chief Executive Officer; and Randy Fowler President and Chief Financial Officer of Enterprise's general partner. Other members of our senior management team are also in attendance and available for questions for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 based on the beliefs of the company as well as assumptions made by and information currently available to Enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements. With that, I'll turn it over to Jim.

Thank you, Randy. Business has continued to perform well during the fourth quarter and throughout 2018. The fourth quarter capped off a very strong year on a consistent theme, achieving operational milestones and setting financial records. In total, we reported 8 operational financial records in the fourth quarter. Our liquid pipeline volumes, our natural gas pipeline volumes and propylene production volumes all set records. This operational performance supported our fourth quarter record gross operating margin of $2.1 billion compared to $1.5 billion for the same quarter in 2017 and provided a 1.7x coverage compared to 1.4x for the same quarter last year. That 1.7 normalized was 1.5. The same theme was true for the total year of 2018 where we set a total of 23 operational and financial records. Distributable cash flow increased 33% to $6 billion, giving us a 1.6 coverage for the year. We retained $2.2 billion of DCF, a 155% increase from the $867 million we retained last -- in 2017. As to returning value to our unitholders, we now have increased our distribution for 20 consecutive years. On the heels of this kind of performance and the confidence we have on our future, today, we also announced that our board has authorized a $2 billion multiyear common unit buyback program. In order to position Enterprise to return more capital to the investors, we believe the first step was to stop diluting our equity investors and to strengthen our credit metrics, which we have done. We believe the authorization of the new buyback announced today is a significant tool in our toolbox. We have completed $6.4 billion of new assets since 2017, all of which are connected to several parts of our value chain. We have another $6.7 billion underway. Also, we continue building assets in the Permian. We've already committed more than $6 billion of capital to projects in the Permian. Our Permian asset base now includes natural gas processing and related gathering; NGL, natural gas and crude oil takeaway; and additional crude oil segregation and storage. We're also building two new NGL fractionators in Mont Belvieu and expanding our LPG export capabilities in order to handle significantly more liquids from the Permian Basin and beyond. Our Permian natural gas processing now includes three plants at our Orla complex and our recently announced Mentone gas plant. 2 of the 3 Orla plants were put into service in 2018, with the third scheduled to begin service in the second quarter of '19. The nearby Mentone plant is scheduled to come online in the first quarter of 2020. Upon the completion of these facilities, we will have over 1.5 Bcf a day of natural gas processing capacity and over 250,000 barrels a day of liquids production in the Permian. These NGLs are pointed toward Enterprise Products' collection of west to east NGL pipelines, which will soon include our Shin Oak pipeline, scheduled for completion in the second quarter this year. In addition to NGLs from our plants, Shin Oak is contracted for over 200,000 barrels a day of capacity to Apache, that has committed all of their NGL production from their Alpine High in the Delaware Basin to Enterprise. In natural gas, in combination with Energy Transfer, we recently completed the expansion of our West to East Texas natural gas system, including putting the Old Ocean pipeline back in service in order to move more Permian production toward the Gulf Coast. For Permian crude, our Midland to Houston pipeline moved up to 550,000 barrels a day of crude oil in 2018 and served as the only new and big relief valve for Permian producers. We are in the process of commissioning our Seminole NGL conversion project, which is expected to be complete by April but will be in limited service in February and March. That capacity will be made available to a third party who's contracted for over 200,000 barrels a day under a long-term agreement. In addition, the government is back open, and as we speak, we have a team in Washington submitting our application with the maritime administration to build an offshore port in water deep enough to fully load VLCC crude carriers. Once completed, we expect to be able to load a tanker at 85,000 barrels per hour, giving us the capability to load 2 million barrel VLCC in 24 hours. One component needed for successful terminal is price transparency. In September, CME announced a new WTI Houston crude oil futures contract with not 1 but 3 delivery points on the Enterprise system. Another component key to a terminal success is access to supplies. Enterprise supply position, coupled with our Houston area storage and distribution network, offer unmatched connectivity and supply aggregation. Our terminal will have all the necessary components, supply aggregation, open connectivity and price transparency. Our crude oil business model is not new. It looks like our NGL business model. Our attitude is "If it isn't broken, don't change it." We continue to write the book on midstream services to the petrochemical industry, which is growing faster on the Gulf Coast than any place in the world. Because of what's happening in Shell and the feedstocks provided by it, Texas and Louisiana have moved into the global leadership position in ethylene production, and we believe there's more underway. This ethylene growth is the driver of a significant opportunity in petrochemical midstream services, which Enterprise is situated to fill. Construction is underway on our ethylene distribution and export facilities, which includes construction of a new dock, storage facilities and a 24-mile ethylene pipeline from Mont Belvieu to Bayport, Texas. The new ethylene export terminal, expected to be in limited service in the fourth quarter of '19, will support the growing U.S. ethylene production by providing low-cost ethylene producers the flexibility to access international markets. In addition to the world-scale PDH put into full commercial service last April, which converts propane into polymer-grade propylene, we're working with several parties on an additional PDH in Mont Belvieu. Given our footprint in propylene, we have also opened up our storage and distribution systems to third parties, which has significantly increased volume and liquidity. Construction is on schedule on our IBDH facility, which should be completed in the fourth quarter of this year. This plant will extend our butane value chain and allow full utilization of our octane enhancement and high-purity isobutylene facilities. We expect to continue to develop and grow our petrochemical midstream services. I'll close by saying that, between our supply position, our market connectivity, projects we have underway plus the prospects we have under development, we have never seen this much momentum, energy and opportunity. I'll close by saying thank you to our most valuable asset, our employees. I've been around a long time, and I have never seen an organization that has the creativity, the work ethic and a culture of teamwork than they do. Our employees are what make Enterprise the high-performing organization that we are, and they are truly appreciated. I'll turn it over to Randy.

Thank you, Jim, and good morning. Starting with the income statement for the quarter. Net income attributable to limited partners for the fourth quarter of 2018 was $1.3 billion or $0.59 per unit on a fully diluted basis. This included $239 million or $0.11 per unit in noncash mark-to-market gains and $29 million or $0.01 per unit of noncash impairment losses. This represents a 29% increase in adjusted earnings per unit versus the comparable EPU for the fourth quarter of 2017. Distributable cash flow, excluding nonrecurring items for the fourth quarter of 2018, increased 19% to $1.5 billion compared to the fourth quarter last year. We retained $662 million in excess distributable cash flow in the quarter and had distribution coverage of 1.5x. 2018 DCF excluding nonrecurring items was up 31% compared to 2017 and 29% on a per-unit basis. As Jim mentioned, we retained approximately $2.2 billion of DCF for 2018. Cash flow from operations for 2018 increased 31% to $6.1 billion compared to 2017. And in traditional terms, our payout ratios, so if you would, our cash distributions as a percent of cash flow from operations, was approximately 52% with respect to the fourth quarter of 2018 and approximately 62% of cash flow from operations with respect to the full year 2018. Free cash flow was $738 million for the quarter and a record $2 billion for 2018, which is a 50% increase compared to 2017. Capital investments. We placed approximately $600 million of growth CapEx into service during the fourth quarter, including the second processing train at the Orla complex. We have another $6.7 billion of major capital projects under construction. Additional projects added since our last earnings call includes an incremental deisobutanizer and isomerization capacity in Mont Belvieu, which will be placed into service in 2020 and 2022, respectively. Our capital investments in the fourth quarter of 2018 were $1.2 billion, including $106 million in sustaining CapEx. On a full year basis, our capital investments were $4.5 billion, including $321 million of sustaining CapEx. In addition, we spent another $72 million on pipeline integrity and maintenance that was expensed. We currently expect capital investments for 2019 to be in the range of $3.5 billion to $3.9 billion, which includes $3.1 billion to $3.5 billion of growth capital expenditures and $350 million of sustaining capital expenditures. For 2019, we also currently expect to receive approximately $645 million of cash contributions from partners in jointly owned projects, including from the exercise of an option by Apache-backed Altus Midstream to acquire a 33% interest in the Shin Oak NGL pipeline. So in terms of net growth of CapEx in 2019, after subtracting the expected cash contributions from our partners related to Shin Oak and the ethylene export marine terminal, our growth CapEx for 2019 could range between $2.5 billion and $2.9 billion. So in 2019, if we were to only replicate 2018 cash flow from operations of $6.1 billion and assume these net capital investments, this would imply 2019 free cash flow potential in the range of $2.9 billion to $3.2 billion or about a 50% increase compared to the $2 billion of free cash flow we've reported in 2018. Moving to our balance sheet. At December 31, 2018, our debt -- total debt principal outstanding was $26 billion. Assuming the first call date for our hybrids, the average life of our debt portfolio is 14.5 years. Assuming the maturity date of the hybrids, the average life of the debt portfolio is 19 years. Our effective average cost of debt was 4.7%, and 99% of our debt portfolio was fixed-rate debt as of December 31. In a rising rate environment, we think this was a great position to be in. It also reflects that we finance long-term assets with long-term capital. Adjusted EBITDA for 2018 was $7.2 billion, and our consolidated leverage ratio was 3.5x after adjusting debt for the partial equity treatment of the hybrid debt securities by the rating agencies and further reduced by unrestricted cash. If we normalized EBITDA for approximately $400 million of wider spread opportunities than normal in 2018, we estimate our debt-to-normalized-EBITDA ratio was 3.7x. We are targeting normalized leverage in the 3.5x area. Our consolidated liquidity was approximately $6.3 billion at December 31, 2018, which included available borrowing capacity under our credit facilities and unrestricted cash. Moving on to equity issuances and redemptions. Enterprise received approximately $89 million of net proceeds from the distribution reinvestment program and employee unit purchase programs during the fourth quarter of 2018. As mentioned on last quarter's call, the distribution reinvestment plan will not have a discount offered in 2019. When the equity price fell in December, Enterprise bought back just over 1.2 million units at an average price of $24.92, which exhausted an existing buyback program that dated back to December 1998. The indicative DCF per-unit yield was approximately 11% on this buyback. As Jim mentioned, this morning we announced a $2 billion multiyear buyback program to opportunistically return capital to investors. The utilization of this program will be dependent on a number of factors, including our financial performance, our financial flexibility, the amount of organic growth projects and acquisitions that have higher potential returns on capital and complement our existing footprint of assets, also in maintaining our leverage target in the 3.5x area as far as debt-to-normalized-EBITDA with the hybrids receiving partial equity credit. Additionally, we guided this morning that we intend to recommend to the board an increase of $0.0025 per unit per quarter, which is consistent with the rate of increase through 2018. This leads to a full year 2019 expected payment of $1.765 per unit, which is a 2.3% increase over that declared with respect to 2018. And with that, Randy, I think we can open it up for questions

Thank you, Randy. Tiffany, we're ready to take questions now from our listeners. [Operator Instructions]. Tiffany, we're ready.

[Operator Instructions]. Your first question comes from the line of Spiro Dounis with Crédit Suisse.

Just want to start off on CapEx guidance for 2019, if we could. It looks like a step down from prior comments around it being at least $3.5 billion. And so obviously, there's a lot of moving parts there around JV contributions. But just curious if you'd just help us bridge those comments with the current guidance range.

Yes. No, it -- honestly, it's consistent because the $3.5 billion number is a gross number before we apply what we expect will be $645 million of contributions from partners on the Shin Oak pipeline, again assuming that Altus Midstream elects to exercise their option, plus the contributions that we'll get from Navigator around the ethylene export dock. So if you would, all we're doing is just taking it from a gross number to a net number.

Got it. Okay, that's helpful. And then just on the buyback program, great to see that re-upped. But just curious, you talked about it a little bit, but how to think about the catalyst that makes you use it. Is it really just a function of the stock price, assuming your other metrics are kind of where they should be? And more broadly, would you consider maybe a more systematic approach as opposed to opportunistic where maybe you're just buying a certain percentage back every year, every quarter, whatever the case may be?

Systematic maybe doesn't feel real good at this point. We might get to that. I think, really, what our drivers are right now is, one, the financial performance of the company keeping up. And then we're looking to come in and try to capture good returns on capital and some of it were -- what's the implied DCF per yield on our -- that's offered in the market in buying back units compared to organic-growth capital projects where we can come in and get good returns on capital, not only incremental returns on capital but also what would that project be -- bring to additional cash flow to our existing footprint. And then the final thing is also where our leverage is because we do not plan on leveraging up in order to come in and buy back units.

Your next question comes from the line of Jean Salisbury with Bernstein.

It sounds like you are commissioning Seminole as crude now but not Shin Oak just yet. I'm just wondering, if that's the case, where are the old Seminole NGLs going? I thought that you were on allocation so the Seminole couldn't happen until after Shin Oak.

I'll let Tug Hanley answer that, Jean Ann.

This is Tug. We have a diverse system with our MAPL assets that we're able to wrap our NGL barrels around, and there are no impact to our shippers at this time on Seminole. We're able to accommodate everything.

Consequently, Jean Ann, we got a lot of levers to pull, and we pulled the levers that made this happen.

Okay, totally makes sense. And then as a follow-up, we're expecting significant Permian wellhead clearing for rest of this year until Gulf Coast Express comes online in October because we may max out gas takeaway. Are you expecting that to impact your Permian volume growth in the short term?

This is Brad Motal. Not really for us. We've got an integrated value chain. We've got gas takeaway. We've got excellent producers that are good at building out what part of the value chain they need to build out. So it doesn't give me a lot of pause because our customers, at this point in my conversation, don't leave me to think there's a lot of flaring at the moment.

And we do have capacity between -- from west to east that we're not going to be afraid to leverage that into the right gathering and processing deals.

Your next question comes from the line of Shneur Gershuni with UBS.

Maybe I just wanted to start off with the non-FID projects. Specifically, you've talked about the VLCC loader out of Houston. Is the plan, longer term, to be able to repurpose some of your existing export capacity towards LPG exports? And when I think about this project, is it a costly endeavor or is it something that's fairly manageable from a cost perspective?

At the size we are now, it's probably -- we would characterize it as manageable. Personally, it's not a small amount of money but manageable. As we said in our script, we are in the process of expanding our LPG export capability. I think this is really -- you got to look at it as kind of a combination. Putting in an offshore port enhances our ability to more LPG, so it's kind of both.

Okay, fair enough. And then just getting back to the buyback question. When you think about a targeted yield for buybacks, is it the same return hurdle that you would apply towards a new project? Or is it lower because of the time value of immediate accretion of a buyback versus the time lag to build a project? And then secondly, is it also lower because the risk profile of buying all of Enterprise is lower than the risk profile of a discrete project?

Yes, Shneur. I think you hit on a key point. And when we come in and look at returns on new projects, if you would, you do have a negative cost security built in. You're in an 18-month, two year construction cycle, so, I mean, we do take that into consideration when we come in and look at the -- we compare a new project to the DCF yield that's offered by the units.

Okay. And just finally, in your prepared remarks, you're basically netting out the CapEx reimbursements with maintenance and everything, spend for FID projects, which should be around $3 billion. That would put you far in excess of a 50% funding goal. Does -- if you end up in a position where you have a lot of excess DCF, over and above your 50% self-funding target, is that also to potentially just be used towards share buybacks, assuming leverage is in line with where you want it?

Well, you put a lot of ifs in there. Yes, Shneur. Again, we think we got -- 2019, we're very optimistic about 2019 and the level of free cash flow that we're going to have. And as Jim mentioned, there's a lot of opportunities as far as growth capital projects. We haven't seen this type of momentum in a number of years. And really, we'll come in and see what the market gives us, whether it's our customers, new projects or if it's the units -- where are the units valued. And then also, we want to be mindful. We want to keep our leverage in check, too. Because we won't -- if you would, keeping the leverage in check gives us the flexibility for bigger things down the road.

Your next question comes from the line of Jeremy Tonet with JPMorgan.

Just want to turn to the nat gas pipeline side there. Quite a strong quarter there, and it seems like some of the uplift is just kind of favorable dynamics and also basis being good there. I'm just wondering, is that largely kind of Permian? Is that Waha basis there? Is this kind of a good run rate of what you expect the segment to deliver in the near term? Or any other thoughts on this segment going into 2019?

Tony, you want to answer? You start and I'll...

No, from my perspective, in 2018, yes, a lot of the performance was for the west to east and west to south. I think, near term, that's going to continue. Longer term, as Jim mentioned earlier, we're looking at -- taking a hard look at our capacity, using that -- leveraging that capacity into longer-term gathering and processing arrangements. So saying all that, I think, near term, it's a pretty good run rate.

I'll add a little bit to that. Those spreads come in as you get towards end of '19, anticipating that pipeline, anticipating a second one, but we're not alone. The amount of gas that we expect to come out of Permian Basin, I think the back of that curve might not be exactly right at this point. It won't be the first time that we've seen that the market says, "We don't price it that way until you show us." So a lot of natural gas, associated gas in the Permian that has to move.

That's helpful. And kind of a similar question on the crude oil side as far as results came in a bit better than we expected there. Is this kind of a good run rate at least for the near term? Or are there kind of any onetime items there? And we talked about the $300 million, I think, Midland-to-Sealy. Is that a gross? Or is that a net number there?

Jeremy, could you repeat that question? Okay, net number.

Okay. And as far as for the segment as a whole, is this kind of a similar performance you would expect in the near term? Or are there any kind of onetime benefit that we should be thinking about?

Jeremy, you -- we're benefiting in 2018, if you would, during this ramp-up period, before all the long-term contracts come on, on Midland-to-Sealy. So we'll see that, if you would, probably you won't have that kind of run rate going forward. But at the same token, what will help us in 2019 is we'll get the benefit of the ramp-up with this Seminole conversion.

Your next question comes from the line of Justin Jenkins with Raymond James.

I think we covered most of what I had, but just want to start with a follow-up on the Seminole conversion. Jim, I know you mentioned it's mostly contracted, but is there any open capacity for Enterprise to ship on your own account?

There's a little bit. It's not a hell of a lot, but there's some.

Okay, fair enough. And then thinking about Seaway expansion. What's the latest on that potential here?

The open season ended on the 21st, I believe, and it was successful. So that was an incremental 100,000 barrels a day that was contracted.

Your next question comes from the line of Colton Bean with Tudor, Pickering, Holt.

So just wanted to follow up on the discussion on nat gas marketing. So I think you mentioned Q4 was a decent look, but does the in-service of the North Texas pipeline give you any additional capacity to move volumes kind of across North Texas and then down on Old Ocean with that January in-service?

The short answer is yes, it does. I mean , we've worked with our partner on the 36-inch on Old Ocean to add capacity on both pieces of the pipe. So in short, yes, it does allow us to move additional Permian to the Gulf Coast.

And from a contracting standpoint, do you guys have spread exposure there? Or is that mostly third party?

Right now, we're in some spread exposure. But as said early -- as we said earlier, we're not afraid to leverage that into more long-term deals.

Got it. And then just on -- Q4, we saw fairly dramatic increase in Opal pricing there in Wyoming. I think, historically, you guys may have had some exposure there on the keep-whole side. Can you just frame kind of what that exposure looks like today and maybe any impact it had to processing margins in Q4?

I'm sorry, can you repeat that?

Just asking on the keep-whole side of the business for processing. I think it's been a couple of years since we've had kind of an update on where that exposure stands, so really just trying to get a sense of how the rally in Rockies gas price may have impacted processing margins in Q4.

I think it impacted it up in Wyoming a little bit more than it impacted it down in Colorado, Randy, I think. Don't you have those numbers?

Yes. It just had more impact up at Pioneer plant than it did down at Meeker primarily.

We were in rejection at Pioneer for quite an amount of time. But we backfilled the pipe with other opportunities so we still made money.

Your next question comes from the line of Danilo Juvane with BMO Capital Markets.

Most of my questions have been hit, but I have a follow-up for Randy. You obviously announced the buyback today. And in your comments, I noticed that there was a lot of focus on free cash flow. Is this a structural shift perhaps in how you sort of see messaging your financial flexibility going forward? Are you sort of shifting away from DCF and having an increasing focus on free cash flow? Is that something we should expect going forward?

Well, we -- I think the transition that we're making is from the MLP-centric model that, if you would, we had our own specialized financial metrics. And as we come in, the incremental valor of investment is from more traditional funds, institutional investors that are not accustomed to our MLP language. And I guess, 2 things. One, with us going more to a self-funding model, we can come in and utilize traditional financial metrics. So a little bit, we're just making that transition from an MLP-centric model, consuming a lot of capital and really trying to appeal to generalist investor. And we need to talk their language, which is GAAP measures, whether it's earnings per unit and price on earnings per unit, whether it's multiple of cash flow from operations or in terms of free cash flow.

I guess as an extension of that, any development with respect to your evaluation of the structure MLP versus C corp? Where are you on that today?

We continue to evaluate it. It's a long-term decision. There's no going back. So we're looking at a number of things as far as relative valuation, relative access to capital. And frankly, one of the things, how many more MLPs are there going to be to convert. One of the things that we also look at, we look at -- when we look at Congressional Budget Office, what CBO forecasts are of the federal deficit, one of the questions we ask is, "How permanent is this 21% corporate rate?" The CBO has federal deficit doubling to almost $1.3 trillion by 2022. There's another election coming up in 2020. So again, how permanent is the 21% rate? And just remember, Brett Kavanaugh got more democratic votes than that 21% corporate rate did. So again, we'll continue to monitor.

Your next question comes from the line of Tristan Richardson with SunTrust.

Just one quick one for me. Randy, you talked a little bit about the concept of normalized EBITDA, and the enhanced spread opportunities maybe generated about $400 million. Could you talk about how you got to the $400 million? Is that removing all spread opportunities or just amounts that you guys deem as kind of outsized or outside the range of normal?

Yes. Tristan, I'll start, and I'll let Jim make some comments. Honestly, I think that's a little bit more art than it is science. We did come in and looked at some -- if you would, it was -- this past year, 2018, it was more about regional price spreads being wider than normal on certain products, whether it was Conway to Belvieu liquids, whether it was Midland to Houston oil, Midland to Houston natural gas. And we were looking at what was wider than normal, but normally, there are a number of spreads in the system.

Yes. It's Jim. When you look at our footprint, invariably, there's opportunity somewhere across that footprint. And this year, Waha to the Gulf Coast or Midland to Houston or Conway to Mont Belvieu were good spreads. But if you think about it, we're probably going to get a question on, "Where do you think pipelines will be overbuilt in the Permian?" Well, more crude that comes into our system on the Gulf Coast enhances our downstream opportunities, so you have spreads in the future Mont Belvieu to Asia. But our attitude is, because of the footprint, we've never seen some kind of an opportunity somewhere across that footprint.

Your next question comes from the line of TJ Schultz with RBC Capital Markets.

First, just a question on ethane exports. What capacity do you have to expand out of Morgan's Point? We've seen a few announcements on potential ethane exports on new terminals on the Gulf Coast that are aimed at China and awaiting permits from China to allow ethane imports. So if you could just comment on your expectations there.

I'll start, and I'll turn it over to Brent. We went to China not too long ago. And I guess I thought we went over to hustle business, and what I found is we were being hustled because every petrochemical wanted an LOI for ethane exports. I think, as I understand it, they're going to grant 3 or 4 new crackers, and we're in discussions with them. As far as what we can do at Morgan's Point, we got some capacity left and we can add capacity. Brent?

Yes. This is Brent Secrest. To answer your question specifically, we probably have about 60,000 barrels a day of excess capacity. Obviously, there's opportunities for us to invest additional capital to expand that. But regardless of the hydrocarbons, Jim hit on this, access to supply is paramount. Whether it's ethane or LPGs or crude oil, we've seen a lot of announcements talking about docks. But at the end of the day, if you don't have access to supply, all you have is a dock.

Yes, makes sense. Just one quick follow-up. You went through a turnaround at the Seminole fractionator in 4Q. Any frac turnarounds we need to expect in 2019?

Zach, would you get that one? Zach or Angie.

It's for Zach.

I will say that we are looking at -- as fractionation space has some seasonality to it, we have a little bit more capacity in the winter. So we're looking at pulling forward any turnarounds that we can. So we believe 2019 fractionation space will remain tight.

Your next question comes from the line of Michael Blum with Wells Fargo.

Maybe just stay on that topic. So obviously, it seems like that extreme tightness we saw late third, fourth quarter of '18 in the frac market has dissipated somewhat, but now you're saying you think it's still going to be tight. So I was wondering if you could just walk through kind of what changed that created some more slack in that market. And for the balance of '19, how tight do you think you'll get? Do you think we'll see additional periods of extreme tightness where you get these blowouts in frac rates? Just wanted to get your thoughts on that.

This is Brent. It's hard for me to speak for others, but I can look at our system and what we project in terms of volumes. And a lot of this, obviously, is dependent upon Permian volumes, but we see '19 staying tight, just as Zach had said. In terms of the blowout that happened in the fourth quarter, that was real. I will say that we've seen some seasonality on production in the Permian, and I don't know if that has to do with the cold weather out in Midland or what, but we have seen some volume go down. But if you look at what's coming on, if you look at the producers we're talking to, all of them are projecting significant growth in the volumes that are coming. So in terms of our fractionation space, it will remain tight in '19.

But we won't pass on new deals, Michael.

Okay. And then second question, kind of a global question on the LPG export market. Just wanted to know if you're seeing anything as it relates to the trade spat between the U.S. and China. Is that having any impact on flows or any aspect of your LPG export business, including potentially negotiating with new customers or re-upping existing contracts?

Yes. I mean, in terms of -- if you look at the ethane demand from China, there's a healthy, healthy appetite for ethane. In terms of all these hydrocarbons and how tariffs affect it, it affects routes, it doesn't affect what we actually export. So if you look at crude oil, the fourth quarter crude exports for us were the highest we've ever had. If you look at January, that exceeds December. If you look at February, that exceeds January. If you look at March -- you can see where this trend is going. At the end of the day, as Tony has alluded to in the past, these barrels will all price to export, just sometimes the routes get inefficient. That's probably a benefit to shipowners. But at the end of the day, these barrels will move.

Your next question comes from the line of Keith Stanley with Wolfe Research.

With the crude conversion project, can you give some updated thoughts on how quickly Shin Oak ramps up? I mean, could that pipeline be pretty full on the 550,000 a day within a year or 2?

Yes. As Jim said earlier as well, there's over 200,000 barrels from Alpine High and then our own equity production and on top of some additional volumes displaced by the crude oil projects. So we do expect some healthy volumes even on Shin Oak.

Okay. So you would have -- sorry, go ahead.

The most reliable supply is from your own processing plants. And Brad Motal dread seeing me because I'm telling him I want 3 more processing plants in the Permian.

Okay. So I would think of it as you have your own supply which is available to ship on Shin Oak, you have the Apache commitments and then you have some displacement from Seminole, you get pretty full?

Right.

Okay. Follow-up question. Just, Randy, you alluded to $6.7 billion of projects under construction and had identified a couple of incremental ones since the last earnings call. Can you give some more color on that please?

Yes. The two projects that have -- that were announced were included in the stack. Since then, we're really two. We're adding some deisobutanizer capacity at Mont Belvieu and also another isomerization facility. And those are long-dated. I think we're looking at 2020 and 2022 on those two.

Your next question comes from the line of Barrett Blaschke with MUFG Securities.

I want to swing back to the buybacks versus distribution growth just so I have a better understanding of the thought process. You guys have seen coverage sort of bleeding higher over time, and I noticed a lot of that is to support the self-funding program. But how do you think of distribution increases now versus being opportunistic on the buybacks?

Yes, Barrett. We'll come in and evaluate it. But the feedback that we've gotten from investors clearly has been a preference right now for buyback over distribution growth. And so again, we'll continue to come in, take a look at it, but that's -- I would say, over the last 3 or 4 months, that has been the clear preference from investors. And look, I mean, we're going to keep our financial flexibility, so again, keeping the leverage in check is important to us. And then after that, I mean, we're going to get capital back to investors, whether it's by a buyback or by incremental distributions.

Okay. And then just kind of switching gears. The government's open, but we're not sure for how long necessarily. Can you give us any indications -- any projects that would be materially affected if we saw another month of shutdown, if it came back to that?

Angie, Kevin, you got anything?

Well, actually, we think we're in pretty good shape. We recently got some of the permits we're waiting for. So -- and this being open now, let's get our spot permit application submitted. And even so -- even if the government shuts down shortly thereafter, that permit time line continues to tick.

Yes. It was pretty important for -- we were ready to go with that application a couple of weeks ago and couldn't. So the minute they opened, we got on the docket and submitted it this morning.

Okay. So the good news is that while it is open, even if it closes again, you guys are able to get a lot done in a short space of time with these kind of things.

Yes.

Yes. That application is only 10,000 pages long, so...

Your next question comes from the line of Dennis Coleman with Bank of America Merrill Lynch.

I guess just one more detailed one. I think you said this -- the customer on Seminole, is it a single customer?

Yes.

And it's a 10-year contract, you said?

It's 10.75 years.

Your last question comes from the line of Michael Lapides with Goldman Sachs.

A question for you. With the buyback authorization but also the re-upping of your distribution growth plans and the improvement in free cash flow coming in 2019 and potentially beyond, why not a little more aggressive on the distribution plan -- distribution growth level? Is this a thought that if there is incremental capital allocation, it will predominantly come through buybacks versus incremental distribution growth just to give you the flexibility? Or is an uptick in the distribution growth plan kind of out there but it's not really a 2019 event?

Again, Michael, I come back that the market has not been rewarding distribution growth, and it's important to us to continue to provide distribution growth for our limited partners. There are many that rely on that income, so we want to go ahead and continue to provide it. And again, what we've heard more recently is buyback over distribution growth. And eventually -- again, I come back. When we have increases in free cash flow, once we get our leverage where we want our leverage to be, by definition, we're going to be returning capital back to investors. It could come back in the form of buybacks, it could come back in the form of additional distributions, but we'll cross the bridge when we get there. One, I keep going back that -- with where Jim talked about. We've got a lot of momentum on the commercial front as far as new projects, so we just need to digest all that. We didn't want to get too far out in front of ourselves.

Okay, Tiffany. This is Randy. That ends our call today. So if you don't mind, would you give our listeners the replay information. And then, that's it from this end. Thank you, guys, for joining us today.

Thank you for participating in today's fourth quarter 2018 earnings conference call. This call will be available for replay beginning at 3:00 p.m. Eastern time today through 11:59 p.m. Eastern time on March 6, 2019. The conference ID number for the replay is 2798148. The number to dial for the replay is 1-800-585-8367. This concludes today's conference call. You may now disconnect.