歐尼克 (OKE) 2019 Q1 法說會逐字稿

Good day, and welcome to the First Quarter 2019 ONEOK Earnings Call. Today's conference is being recorded.

At this time, I would like to turn the conference over to Andrew Ziola. Please go ahead, sir.

Thank you, Todd. And good morning, and welcome to ONEOK's First Quarter 2019 Earnings Conference Call. This call is being webcast live, and a replay will be made available. After our prepared remarks, we'll be available to take your questions.

A reminder that statements made during this call that might include ONEOK's expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision of the Securities Acts of 1933 and '34. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings.

Our first speaker this morning is Terry Spencer, President and Chief Executive Officer. Terry?

Thanks, Andrew. Good morning, and thank you all for joining us today. As always, we appreciate your continued interest and investment in ONEOK.

Joining me on today's call is Walt Hulse, Chief Financial Officer, Executive Vice President, Strategic Planning and Corporate Affairs; and Kevin Burdick, Executive Vice President and Chief Operating Officer. Also available to answer your questions are Sheridan Swords, Senior Vice President, Natural Gas Liquids; and Chuck Kelley, Senior Vice President, Natural Gas.

I'll make a few brief comments and then turn the call over to Walt to discuss our first quarter financial highlights. To start, we've continued to see an improving industry backdrop since January. Crude prices have strengthened, producers remain active across our operations and our capital growth program remains on track and on budget.

Project construction is progressing very well with our ability to predict expected completion dates improving every week. As it looks today, we now expect the southern section of the Elk Creek pipeline to be complete early in the third quarter of this year and the entire pipeline complete during the fourth quarter. The Arbuckle II pipeline and MB-4 fractionator are expected to be complete in the first quarter of 2020. Keep in mind, the earlier these projects are completed and are placed into service, the earlier ONEOK begins to recognize earnings on them.

Based on producer activity and the progress on our projects and assuming no dramatic market change, ending the year at the low end of our capital guidance range is less likely than it was in February. To the extent that we may be above the guidance midpoint of $3.1 billion, we would be spending construction dollars in 2019 that were previously planned for 2020 and accelerating the in-service dates for some projects.

Last week, we announced an extension of our Bakken NGL Pipeline in North Dakota to connect with a third-party natural gas processing plant. We're not only connecting an additional plant, we're reaching into a new area of the Bakken and providing NGL takeaway in Williams County, which historically has had limited transportation options. And by doing so, we're enhancing our ability to provide potential NGL transportation services to more customers. Additionally, our commercial team continues to evaluate a potential NGL export facility on the Gulf Coast. As this opportunity continues to evolve and develop, we will provide further details as appropriate.

After more than a year of talking about our capital growth projects, we are nearing completion on several of them. Over the coming months, these projects will add critical NGL takeaway, fractionation and natural gas processing capacity for our customers where they need it the most, providing ONEOK with substantial long-term fee-based earnings and cash flow growth.

With that, I will turn the call over to Walt for comments on our first quarter results.

Thank you, Terry. ONEOK's first quarter 2019 net income totaled $337 million or $0.81 per share, a 27% increase year-over-year, and first quarter adjusted EBITDA totaled $638 million, a 12% increase year-over-year. All 3 business segments reported double-digit adjusted EBITDA growth compared with the first quarter 2018.

Distributable cash flow in the first quarter 2019 was more than $500 million, up more than 17% from the first quarter 2018, with a healthy dividend coverage of 1.43x. We continue to reinvest in the business, generating more than $150 million of distributable cash flow in excess of dividends paid in the first quarter of 2019. During the first quarter, we paid a dividend of $0.86 per share, and in April, we announced an increase to $0.865 per share or $3.46 per share on an annualized basis. The dividend is payable on May 15 to shareholders of record on April 29.

Our March 31 debt-to-EBITDA on an annualized run rate basis was 4.0x and 4.1x on a trailing 12-month basis. We ended the first quarter with total available liquidity of $3.25 billion, including borrowing capacity of $2.5 billion available on our credit facility and $750 million available on our 3-year unsecured term loan agreement.

As Terry mentioned, the industry environment has strengthened since the fourth quarter and construction on some of our largest projects could be completed early in the quarter as we've specified. We have clear line of sight to the ramp and timing of expected cash flows on these projects, which, combined with our strong balance sheet and financial flexibility, continues to underscore our expectation for no equity financing needs in 2019 or 2020.

I'll now turn the call over to Kevin for a closer look at our operating performance.

Thank you, Walt. I'll walk through each of our operating areas and touch on a few more highlights related to operations in our projects. Starting with the Rockies region.

Raw feed NGL throughput volume on the Bakken NGL Pipeline averaged 167,000 barrels per day in the first quarter with most of the growth attributable to increasing volumes being railed from the basin. Natural gas volumes processed in the Rocky Mountain region increased to more than 1 billion cubic feet per day during the first quarter as we continued to see strong producer activity and record North Dakota natural gas production in January.

We estimate more than 250 million cubic feet per day of natural gas is currently being flared on ONEOK's acreage, providing a clear backlog of volume to fill Demicks Lake I when it begins service in the fourth quarter of this year. We expect additional flared natural gas and continued strong production to provide for a quick volume ramp at Demicks Lake II, which is expected to come online in the first quarter of 2020. Each of these plants when full are expected to provide approximately 25,000 barrels per day of NGLs to our Elk Creek pipeline, not including ethane recovery.

We continue to expect Elk Creek to reach approximately 100,000 barrels per day in the first quarter of 2020 with volumes increasing throughout 2020 and beyond. At volumes of 100,000 barrels per day, Elk Creek will be generating its targeted adjusted EBITDA multiple of 4 to 6x within its first few months of operation. In addition, we now have secured contracts with natural gas processing plants in the Rocky Mountain region that can produce up to 200,000 barrels per day of NGLs, up from 170,000 barrels per day previously reported.

The Williston Basin continues to average more than 60 rigs operating with approximately 25 rigs on our dedicated acreage. If crude prices sustain around $60 to $65 per barrel, we could see additional rigs move into the basin once NGL takeaway capacity and natural gas processing capacity are completed this year. Feedback from producers in the Powder River Basin also remains positive, where we continue to have more than 20 rigs on our dedicated NGL acreage.

Moving on to the Mid-Continent. NGL raw feed throughput volumes increased approximately 4% in the first quarter 2019 compared with the same period last year. Volumes decreased in the first quarter of 2019 relative to the fourth quarter of 2018 primarily due to the impact of winter weather in the first quarter and some short-term volume we only gathered in the second half of 2018. Construction on Arbuckle II pipeline is on track for completion in the first quarter of 2020, and our total contracted capacity on Arbuckle II is now 350,000 barrels per day compared with 320,000 barrels per day previously.

In our gathering and processing segment, winter weather impacts and the delayed timing of several well completions contributed to the decline in natural gas volumes processed in the Mid-Continent in the first quarter 2019 compared with the fourth quarter 2018. Producer activity on our acreage in the STACK and SCOOP areas remains in line with our expectations, and we're on track to be within our volume guidance range.

In our natural gas pipelines segment, contracted pipeline capacity increased 10% compared with the first quarter 2018. This increase was driven by recent pipeline project completions in both the Mid-Continent region and the Permian Basin. These strategic expansions have helped alleviate natural gas pipeline constraints in these areas as we've been able to provide much-needed takeaway for our customers.

Now taking a closer look at our Permian Basin and Gulf Coast operations. NGL raw feed throughput volumes in this region increased 7% compared with the fourth quarter 2018, primarily driven by increased volume on our West Texas LPG pipeline system, including a ramp in volumes from our completed extension into the Delaware Basin.

Additionally, the average NGL fee rate associated with our Gulf Coast Permian volumes increased to an average of $0.05 per gallon in the first quarter 2019.

The higher rate is primarily being driven by increased bundled service volumes or transportation and fractionation volumes on West Texas LPG. Volume on this pipeline has historically been lower-margin transport-only barrels, but as legacy volumes roll off, we're replacing them with higher-margin transportation and fractionation volume, which we expect will cause this average rate to continue trending upward.

ONEOK's system-wide NGL fractionation capacity is approximately 810,000 barrels per day given our current product composition, and this capacity remains approximately 90% utilized. We continue to look at several debottlenecking projects that could add 40,000 to 50,000 barrels per day of fractionation capacity in 2019 and early 2020 and be efficiently completed at costs substantially lower than new construction. These debottlenecking projects are expected to provide capacity to help bridge us to the early first quarter 2020 completion of our 125,000 barrels per day MB-4 fractionator, which we expect will exit 2020 at full capacity.

Terry, that concludes my remarks.

Thank you, Kevin. We've had a great start to 2019 and are looking forward to getting a number of these projects to the finish line in the coming months. The credit goes to our employees who remain extremely focused on operating our existing assets and building new ones safely and responsibly.

We'll be putting hundreds of miles of pipeline in several facilities into service later this year and into next, which will dramatically increase the scale of our operations and provide much-needed infrastructure and services for our customers. Our employees work every day to provide solutions for these customers, to enhance our business and to make ONEOK even more sustainable for the long term, all while focusing on safety and reliability, limiting our impact on the environment and providing value to our investors. Again, I want to express my thanks to all of our employees.

With that, operator, we're now ready for questions.

(Operator Instructions) We'll take our first question from Christine Cho of Barclays.

I wanted to start off with the lateral to the Bakken NGL line. I think the processor that you're connecting to, their other processing plants have been connected to different NGL takeaway solutions. Can you provide us some color on what's going on with those other options and why they finally came to you? Also, my guess is the capacity of the pipeline, even though you guys haven't disclosed it, is much more than the contracted. Can you give us an idea of what other opportunities you have along the line?

Christine, this is Sheridan. I think once we get Elk Creek online, that the customers up there are seeing that our alternative for NGL takeaway nets them a greater netback than going their existing route and as they continue to expand up in that area, that their existing outlets are limited and they need that extra capacity. And you are correct, we are putting in a line that could move probably over 200,000 barrels a day, the lateral going over there. We see today other processing plants in the area that this pipeline goes by are producing approximately 10,000 barrels a day. But as we talked to people in the area, that 10,000 barrels a day could grow to as much as 40,000 barrels per day in the near future.

Okay. Great. And then moving over to just sort of the ethane. With all the Permian ethane that's coming out and I think pressuring ethane prices, in the event Conway ethane frac spread remains negative, should we think that third-party processing plants are rejecting the ethane so there's less supply of ethane showing up at Conway for you to optimize? Just some color on how we should think about that.

Well, what -- I think you're right. As long as you keep Conway ethane in rejection, which it is sitting there today, you will have about the same amount of ethane you have today. It may grow a little bit as we bring on a couple of new plants in the second quarter. But remember, not every plant can't reject -- not every plant can reject all the ethane. There is some ethane that has to come out naturally anyway on our system. So I think what we're seeing today is what we think we'll see going forward if we stay in a time when Conway's going to stay in ethane rejection.

And Christine, this is Kevin. I mean you've also got a significant amount of demand for more ethane coming on in the back half of '19 as well. So that's going to be -- that's going to pull more ethane out also.

Okay. And can you give us an idea of like the utilization on Sterling I and II for the quarter?

Well, we just finished the expansion of Sterling III, and we really operate those pipelines all together. They move around, and we're a little bit under 90% for the total system.

Okay. Great. And then last question for me. I just wanted to make sure -- can you remind us on the LPG export project? Any partner that you guys bring on would be someone who would take the volume, yes? Or we might not think of that...

Christine, this is Kevin. Well, I think it could. We're exploring a lot of alternatives, but yes, especially as you think about ethane, that would be a scenario that could play out. LPGs might have a different approach. But we're working with the markets on both sides, and we're working with others as well and still working through the details of what that might look like.

When you say both sides, you mean ethane and LPG? I'm sorry, I just...

Yes.

We'll take our next question from Michael Blum of Wells Fargo.

Two questions for me. One, some of the recent data coming out of the government on Bakken production shows a decline in the last couple of months. So I was just wondering if you could just comment in terms of any trends you're seeing in terms of overall production trends in the Bakken.

Well, Michael, this is Kevin. I mean from a gas perspective, we set a record in January, so that's always a good sign. February, you had quite a bit of weather, not necessarily abnormal but that pulled production back a little bit, which is standard kind of operating procedure this time of year. The feedback we're getting from not only our G&P customers but then there's already been a couple of calls from some of the other processors up there, the results have been incredibly strong. So we don't see any pullback of volumes, of rigs, and the results seem to keep getting stronger. Chuck, do you have anything...

Okay. Thanks for that. The second question I had was on this potential LPG export project. I was wondering if you could just talk through some of the competitive dynamics and return expectations you would have. I'm sure you're well aware that one of the big players in that market is out very publicly talking about basically keeping their rates down to keep competition out of the market. So I was wondering if you could just kind of talk about the competitive dynamics and what returns would look like for a project like this.

Michael, we are seeing it's a very competitive market out there on the LPG side. And if we would get into the LPG and ethane, it would be a very strategic move that we see, that we need to be able to clear our product and be able to incite more ethane to come out. So it's a bigger loop into straight economics. No doubt, the economics would be more compressed than we've seen on some of the recent projects, but we think it's a long-term play if we would go that route that we would do.

Yes. I think -- Michael, this is Kevin. I think we've said and we continue to maintain that the project will stand on its own merits. So as we look at that, obviously, the economics will be key, but Sheridan's right, it's a very competitive landscape out there for the project.

We'll take our next question from Jeremy Tonet of JPMorgan.

Just wanted to touch on Elk Creek and how that was going with the contracting side, if anything was added since the last quarter. And kind of what's enabled you to pull forward the time frame here? It seems like pipeline projects seem to be pulling backwards as opposed to be pulling forward. So I'm wondering what you were able to accomplish.

We'll start with the contracting. We -- I said in my remarks that we're now at 200,000 barrels a day contracted out of the Rockies region that will ultimately, we believe, hit Elk Creek. As for the construction, our teams just -- they've done a great job executing as we've gone through the first stages of the project. As we move forward, we've been very open about starting with the southern section, and the team has made great project even through some tough weather and some very wet weather in the winter and the early spring, but still on track and got comfortable that we now think it's going to be that southern section can be complete early in the third quarter. So just a great job of executing so far by our project team as it relates to right-of-way acquisition and getting the pipe in the ground.

That's helpful. And looking at the Mid-Con. It looks like things stepped down a little bit 1Q versus 4Q for some of the volumes you had. Just wondering how you see that kind of trending over the balance of the year. Has there been any change as far as producer communications for their activity levels? Or are things kind of within the band of what you expect?

Jeremy, this is Chuck. I'd say, in the Mid-Con, we've had a good start to the year with our 32 well connects, and the number of rigs operating on our acreage is consistent with our plan and with guidance. Volumes were within the band of guidance. So we feel good about our numbers balance of the year in Mid-Con. And in talking with some of the producers, we actually see some of the rigs movement -- moving to our acreage on the SCOOP later in the year, end of Q2, end of Q3. So overall, I just think we're on pace with our guidance for the year.

We'll take our next question from Chris Sighinolfi of Jefferies.

Terry, I'm not sure if this is for you or this is for Walt. But just wanting to follow up on the discussion we had on the last quarter call about the pace of your dividend growth. Whereas just -- I've noticed in subsequent presentations following that discussion that the 9% to 11% rate that you previously discussed and featured no longer appears. Obviously, the pace of growth has decelerated over the last 2 quarters below that range, unless there's a subsequent step-up later in the year. So I'm just -- I'm not advocating for a particular range or saying that there's something off. I'm just trying to figure out how to interpret what we've seen and what you guys are thinking at this point.

Well, as far as the omissions, I wouldn't read anything into that. We've been clear on that guidance, and it hasn't changed. We established that guidance shortly after the consolidation transaction, so it's in place. So I wouldn't read anything into that. I think as the Board thinks about as we go into the balance of the year and it thinks about our dividend policy going forward, obviously, we've got the guidance there.

But I think the most important fact they will take into consideration is just the tremendous cash flow growth that we see for the company. Business is performing extremely well. And particularly with these projects coming online earlier and the growth opportunities we continue to develop, the free cash flow generation really is continuing to exceed our expectations as we look out. So that will be the key thing that they take into consideration as they think about the dividend policy going forward.

But the baseline view is still a view around the 9% to 11% that you had talked about?

Absolutely. That guidance is still there, so...

Okay. Sure. All right. And then, I guess, maybe for Kevin or for Sheridan. We had previously chatted about key content in the Bakken as it pertained to Northern Border and the fact that ethane rejection might not just be an economic decision but maybe an operational one. I'm just wondering where we shake out on that? A lot of processing is set to come up later this year and into next year, but curious how the dynamics look today?

Yes. This is Kevin. And yes, that's still something we watch very closely and stay in touch with, that as you push -- with the basin being in ethane rejection right now, you're pushing more and more high BTU content gas into Northern Border. That trend will continue. And you're right, if you think about Demicks I and Demicks II and the target Hess plant and Crestwood's expansion and you think about those -- all the capacity there and all of that residue making its way to Northern Border, clearly, we're watching the BTU content at the bottom of Border very closely.

As we've said, we have the ability, as does the rest of the processors up there, to recover ethane. Now we need to get Elk Creek in service first before we would have the capacity to do that. But once we have Elk Creek in service, then we've got -- that's a nice option we have as an industry to be able to lower the BTU content on Border if we start seeing downstream market impacts.

Okay. No, that makes sense. And kind of while I have you, just a follow-up on Michael's earlier question about the export dock. I think you said that the project would have to stand on its own. So in terms of returns, you guys have talked for a while about getting into that market. Michael referenced the peer talking about aggressively pricing their capacity. We shouldn't think about there being maybe a suboptimal return on getting access to that space made up for through later expansions or anything like that?

Yes. I mean I wouldn't think about it that way. You're going to see periods of time where competition for spot space or to the extent that there's excess capacity on these docks, you're going to see some dock-on-dock competition that will pressure margins. But as we think about this project, we're thinking about it long-term contracting, solid returns even relative to our other investments that we have. Obviously, the project itself is -- would be a strategic move for us, making sure that we have the ability to clear barrels. We could have the ability to clear barrels even without a dock longer term, but it's better if we have a dock. So -- but as Kevin indicated, we're looking at all our options. And again, it's a project that we're investing a lot of time in, and certainly, it's a capability that would add value to our existing suite of capabilities.

We'll take our next question from Michael Lapides of Goldman Sachs.

Actually, I have a couple of them. First of all, you talked for a while about the expansion capability at either Elk Creek and Arbuckle II just with pumps. How are you thinking about the timeline for when you would potentially implement that? And would you do it kind of staggered or you think the market warrants like bigger leaps?

This is Sheridan. Obviously, as we're starting to get contracting up to 200,000 barrels a day, that is really on our mind when we put it in, and we have the ability to stagger it. You don't have to go all the way on Elk Creek to the 400,000. There's intermediate stay. If you can just put a couple of pumps in here and a couple of pumps in there and hit incremental capacity. So we could do that in stages as we go on, but definitely, as we reach this 200,000 barrel a day mark, we are definitely looking at when we want to expand that pipeline because we want to make sure that we have the capacity to meet the customers' needs up there and don't get into an issue where the pumps are delayed by any way -- by any means.

And the only thing I would add on to that, this is Kevin, is the contracted volumes that we talked about and we report are really C3-plus volumes, and they don't assume any ethane being extracted. So as we also think about our capacity on Elk Creek, we want to make sure we've got the ability and have some capacity available that if we -- back to Chris' question, that if we do need to pull some ethane out because of downstream spec issues or the issues on Border and the BTU content, that we have the capacity to be able to do that. So we factor that into our thoughts on capacity expansions as well.

Got it. And then on the debottlenecking projects for the fracs, can you talk a little bit about how much incremental capacity you think you're adding through that and when you think you get that completed?

That's where we said we've -- we were at 30,000, 40,000 barrels a day of additional we think we can get. You'll see some of that, maybe 10 to 20-ish that we expect we'll get probably in '19, with the balance in early '20.

Got it. And then last thing. The rates of the margin on West Texas, meaning Permian and the Gulf Coast, you've talked about going from $0.04 to $0.05, and more importantly, you made the comment about it continuing to creep higher. How should we think about that? How do you want investors to think about how much higher that could creep? I don't mean -- are you talking about just kind of slow and gradual? Are you talking about moving closer to the rates you're getting in the Mid-Con? I just want to kind of frame that a little bit.

This is Sheridan again. What I would say is that it's -- I wouldn't say it's going to be slow and gradual. Obviously, we have the next expansion coming on, on West Texas pipeline that is contracted. So when those volumes come up, they will almost be contracted at a rate twice as our average when that volume comes on. And then, obviously, we know that we will be losing some legacy volume as other pipelines come on, and we have contracted that space as well.

So I think there's 2 big leaps we will see in that rate going up. One is when we complete the second expansion of West Texas. And the other one would be when other pipelines are completed out of there and volume comes off and we are able to replace it with volumes that we've contracted at the market rate and not at below market rate.

We'll take our next question from Dennis Coleman of Bank of America.

I guess -- I wonder if I might ask a little bit more strategic question. You talked about the export docks and how you enter that market. M&A has been a topic that's come up quite a bit in recent weeks with some of the M&A on the producer side and just some producer activity. How do you think about the M&A market particularly with your currency being attractive as it is for that?

Well, as far as the M&A market goes, we think about it quite a bit. The fact of the matter is that the challenge there, of course, is transactability when you think about the opportunity set that this company has, heavy organic, tremendous returns, low-risk projects relative to, say, much more strategic or exotic M&A. So we remain focused on this organic growth opportunity set that we have.

So it's difficult for us to rationalize the risk associated with some of these transactions that we think about. We'll look -- we have investment bankers coming to us all the time with their own ideas and what might make sense, but no one ever seems to have a deal ready to do. So we just stay focused on what we do and that's building this infrastructure in these basins where we have these great positions. I mean candidly, when you look at it just purely on an accretion basis, just look at it on a DCF per unit accretion, these organic projects blow away any M&A transaction. So that's why we stay focused and continue to execute heavily on the organic side. Did that help you?

Yes, it does.

We'll take our next question from Sunil Sibal of Seaport Capital.

A couple of questions for me, starting out on the Permian side of things. It seems like -- how should we think about 150,000 to 200,000 kind of barrels per day of NGL volumes on that pipeline contracted rolling over the next 1 to 3 years?

I think you will be over 200,000 -- yes, I think you'll be close to 300,000 barrels a day over the next couple of years on that pipeline moving. You're already today approaching 250,000 barrels that's moving on the pipeline. So I think we will be over 300,000 the next couple of years easily.

Got it. Actually, I was -- wanted to get some color on the legacy contracts that you have on that pipeline. How should those contracts be rolling over in the next 1 to 3 years?

I think most of them will come off -- that we see coming off will come off in 2019.

Okay. Got it. And then on the CapEx side of things. It seems like on the growth CapEx side, you spent close to $850 million this quarter. How should we think about cadence of that over the remainder of the year?

Yes. We -- I mean as you think about our projects, especially the big 4, we're in the heavy construction as we went through the first quarter, and we'll continue heavy construction as we go through the second and third quarter. Every project kind of has a natural flow as far as when the capital's spent, and as you get towards the end, it tapers off a little bit. So as you see that -- but what could change that is, again, we're doing everything we can to accelerate these projects that purely from a timing perspective, you might see some dollars. If we're above the guidance we would be -- it would be just a shift from 2020 dollars into 2019 or vice versa. It's just literally the timing of how that would play out at the end of the year.

Okay. Got it. And then just a clarification on the dividend growth policy. I think previously, the policy has been 9% to 11% annual rate. Is there any thought on kind of thinking about that rate on an average basis over the next 3 years or so just to kind of manage your CapEx spend? Or should we just think about 9% to 11% every year through 2021?

Well, the Board's going to continue to take it up on a quarter-by-quarter basis. But what I would tell you is that the fundamental of our business continues to strengthen, giving us plenty of earnings to support our dividend growth. And we have not adjusted our dividend growth guidance, and we'll let the Board look at it, but we have strong earnings to support our guidance.

We'll take our next question from Jean Ann Salisbury of Bernstein.

Would a Bison turnaround from the Bakken, if it is pursued, be overall good or bad for ONEOK? I can kind of see both sides, so would be interested in your view of impact.

Well, I think -- this is Kevin. I think clearly, any time there's addition -- we don't want to be takeaway-constrained, right? And so we're always looking for ways to ensure that we have the takeaway for our customers up there. And so that will involve -- you look at residue in a couple of different ways, and so I think it would come down to what type of rate, what type of term, what type of volume commitments it would be required to make a project like that work versus alternatives that the basin might have of other ways to handle the residue, which would also include handling some of the residue by recovering ethane. So I think that's still under -- as we look through it and we'll be thinking through that, but clearly, having -- we don't want the basin to be takeaway-constrained from the producer standpoint. We want them to be able to continue to drill.

Yes. That's helpful. And then there is some concern by investors of a fractionation overbuild over the next couple of years. How much of your Mont Belvieu fractionation is take-or-pay or perhaps otherwise protected?

Most of our new stuff coming on has very limited take-or-pay in that the market in these last couple of rounds of build has not supported take-or-pay economics. But what I would say is that from our Belvieu fractionation position -- and we anticipated 4 and 5 being full, but under the scenario that they wouldn't -- we're not full, we always have the option to take barrels that we're fracking in the Mid-Continent, move them down to the Gulf Coast and collect the additional Conway-to-Belvieu spread on that piece.

But I don't think -- what I'm seeing today with what's coming on now, there may be a little bit of short-term overcapacity in the fractionation market but I think long term will be eaten up pretty quickly. And also remember that a lot of the players that are building these fracs today are storing raw feed and they will have to frac that off once they come on. So it's not just new production, it's production that's coming on now that we do not have enough frac capacity today.

We'll take our next question from Craig Shere of Tuohy Brothers.

Three quick questions around Elk Creek. So the growth that we're seeing out of the Bakken or out of the Rockies is being railed, and the railed volumes have, if I understand it, de minimis margins currently. So when the southern leg of Elk Creek opens up and we have more capacity upstream on the Bakken NGL line, those volumes kind of immediately get, what, a $0.20 plus bump in margin?

Yes. You're pretty close.

And on the 200,000 a day ultimate capacity that's been contracted in the Rockies, 2 questions on that. One, how long do you think that, that could take to reach full capacity on those contracts? And two, can you break it down between Bakken and DJ?

I think we will ramp up to that 200,000 fairly quickly. I would say probably as we get into 2021, we will see that volume be at that rate, up to 200,000 barrels. And once again, as Kevin said, that is assuming no ethane. If ethane comes on, you'll reach that a lot quicker. So I think it takes a little bit of time. And I think the last piece will come in -- the delay on the last piece will be -- we got to get the lateral over, which will be completed at the end of 2020. And then would you repeat your last part of the question?

I want to get a sense where it's all sourcing from in terms of proportion from the Bakken or DJ?

I would say about 70% to 80% is coming out of the Bakken.

Great. And one last question. I ...

Craig, just before you move on. Really, a lot of those volumes are coming out of the Powder, not the DJ.

Yes. 80% from the Bakken, and almost -- the rest of it is all out of the Powder River.

Right.

Great. And last question. I noticed DCF coverage in the quarter was aided by lower sequential maintenance CapEx and higher sequential other income. Can you touch on the repeatability of that?

I think that the maintenance is just normal timing that comes and goes quarter-to-quarter and when a project gets done or not. The other was a small nonstrategic asset that we sold for a very small amount of money. So that was just kind of ordinary course, cleaning up some assets.

This concludes our questions for today. I'll turn it back Andrew Ziola for closing remarks.

Thank you, Todd. Our quiet period for the second quarter starts when we close our books in early July and extends until we release earnings in later July. We'll provide details for the conference call at a later date.

Thank you for joining us. And the IR team will be available throughout the day. Have a good week.

Thank you, ladies and gentlemen. This concludes today's conference. You may now disconnect.