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 1934. 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 are 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 taking 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 three business segments recorded double-digit adjusted EBITDA growth compared with the first quarter 2018. Distributable cash flow in the first quarter 2019 was more than $500 million, but more than 17% from the first quarter 2018 with a healthy dividend coverage of 1.43 times. We continued to reinvest in the business, generating more than $150 million of distributable cash flow in excess of dividends paid in the first quarter 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 4.0 times and 4.1 times 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 three-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 this 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 of 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 four to six times 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 onto 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 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 are 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 de-bottlenecking projects are expected to provide capacity to help bridge us to the early first quarter 2020 completion of our 125,000 barrel 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 and 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, it's much more than the contract is. 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 in line that the customers up there are seeing that our alternative for NGL takeaway nets them a greater net back than going the 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 talk 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.

And then moving over to just sort of the ethane with also 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 and how we should think about that?

I think you're right. As long as you keep Conway ethane in rejection which 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 couple new plants in the second quarter. But remember, not every plants can't reject – not every plant can reject all the ethane. There 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 going to stand in ethane rejection.

And Christine it's Kevin. I mean you've also got the significant amount of demand for more ethane coming on in the back half of 2019 as well. So that's going to be, that's going to pull more ethane out also.

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

We just finished the expansion of Sterling III and we really operate those pipelines altogether they move around and we're a little bit under 90% for the total system.

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 volumes, yes or might think about it?

Yes Christine this is Kevin. Well, I think it could we're exploring a lot of alternatives but yeah, 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, what that might look like.

When you say both sides do you mean ethane and LPG I'm sorry ethane?

Yes.

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

Two questions from me one, some of the recent data coming out of the government and Bakken production shows a decline in the last couple of months. So I wondering if you 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. There is the feedback we're getting from not only our G&P customers, but then there’s already been a couple 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.

The second question I had was on this potential LPG export project. I was wondering if you just talk to 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 markets. 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. Thanks.

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 look and just 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.

So I think, Michael, this is Kevin. I think we've said and we continue to maintain that the project will - the project will stand on its own merits. So as we look at that obviously, the economics will be key but Sheridan is 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 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 enabled you to pull forward the timeframe here. It seems like pipeline project seem to be pulling backwards as opposed to be pulling forward so I’m wondering what we were able to accomplish?

We'll start with the contracting. As I said in my remarks that we were now 200,000 barrels a day contracted out of the Rockies region that will ultimately we believe hit Elk Creek. As for the construction and our teams just jumped, 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 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 write away acquisition and getting the pipe in the ground.

And looking at the Mid-Con looks things have step 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 are things kind of within the band of what you expect?

Jeremy, this is Chuck. I'd say Mid-Con we got a good start to the year with our 32 well connects and the number of rigs operating. On our acreage are 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 one on pace with our guidance for the year.

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

Thanks for your time today. Terry I am not sure this for you or if this Walt, but just wanted to follow up on the discussion we had on the last quarter call about the pace of your dividend growth. Was just, I've noticed in subsequent presentations following that discussion that the 9% to 11% rate that you previously discussed and featured. You no longer peers obviously, the pace of growth has decelerated over the last two quarters below that range unless there is 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 optimal 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 omission I wouldn't read anything into that. We've been clear on that guidance and it hadn'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 got the guidance there. But I think the most important fact they will take into consideration is just a 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 its continuing to exceed our expectations as we look out, so that will be the key thing that they take into consideration as I think about the dividend policy going forward.

The baseline view is still a view around the 9% to 11% that you're talking about?

Absolutely that guidance is still there, so.

And then I guess maybe for Kevin or for Sheridan. We had previously chatted about heat content in the Bakken as it pertains to Northern Border and the fact that, ethane rejection might not just be a economic decision, but maybe an operational one. I'm just wondering where we shake out on that a lot of processing 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 - 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 them Demicks 1 and Demicks 2 and the target has plant and Crestwood's expansion and you think about those that all the capacity there and all 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 out Creek and 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.

And kind of why 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 that you are talking about aggressively pricing their capacity, we shouldn't think about there being maybe a sub-optimal return on getting access to that space made up or through later expansions or anything like that.

Yes, I mean I wouldn't think about it that way that you're going to see periods of time where competition for spot space or it to the extent that there is excess capacity on these docs, 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, it 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 of dock, longer term, but it's better if we have dock. So, but as Kevin indicated, we're looking at all our options and again it's a project that we are investing a lot of time in and certainly it's a capability that would add value to our existing suite of capabilities.

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

Actually I have a couple of them. First of all, your thought 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 is we're starting to get contract up to 200,000 barrels a day. That is really on our mind when we put it in. 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 steps you can just put a couple of pumps in here in a couple of pumps and there and get incremental capacity, so we can do that in stages 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 anyway by any means.

And the only thing I would add on to that. This is Kevin, the contracted volumes that we talk about and we report 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 board in 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.

And then on with debottlenecking projects for the fracs. Can you talk a little bit about how much incremental capacity you think you're adding to that and when you think you get that completed?

That's what we said, we were at 30,000 to 40,000 barrels a day of additional, we think we can get. You will see some of that maybe 10 to 20-ish and that we expect will get probably in 2019 with the balance in early 2020.

And then last thing, the rates of the margin, on West Texas, meaning the Permian in the Gulf Coast, you've talked about going from $0.04 to $0.05, and more importantly you made the comment about it kind of continuing to creep higher. How should we think about that? How do you want investors to think about how much higher that could creep? 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?

It’s 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 West Texas pipeline that is contracted and 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 two big leaps we will see in that rate going up. One is, when we complete the second expansion of the West Texas and the other one will be when their pipelines are completed out of there and volume comes off and we were able to replace it without 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, if I wonder if I might ask a little bit more strategic question. You talk about the export docks and how you enter that market. M&A has been the topic that's come up quite a bit in recent weeks with some of the M&A and 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?

Yes, well, as far as the M&A market goes, we think about it quite a bit. The effect of the meant is the challenge there course is transact ability, 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 that we think about, we'll look, we'll look we have investment bankers coming to us with their own ideas and what makes sense, but you know whenever seems to have a deal ready to do, so we stay focused on what we do and that’s build in 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 on DCF per unit accretion, these organic projects blow away any M&A transaction. So that's why we stay focused and you continue to execute heavily on the organic side. Does it help you?

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

Couple of questions from me, starting out on the Permian side of things, 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 2, 3 years?

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

Actually I was kind of trying to get some color on the legacy contracts that you have on that pipeline, how should those contracts been rolling over in the next one, two, three years?

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

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

Yes we, I mean think about our projects, especially the big four we are in the heavy construction as we went through the first quarter. 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 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 just be a shift from $20 into 2019 or vice versa. It's just literally the timing of how that would play out at the end of the year.

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 three years or so, just to kind of manage your CapEx spend, or should we just think about 9% to 11% every year through 2021?

So the Board is 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, given 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 Salisbury of Bernstein.

What a Basin turnaround from the Bakken, if it is pursued the overall good or bad for what else I can kind of see both sides that would be interested in your view of the impact?

Well, I think, this is Kevin. I think clearly anytime 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, and what type of volume commitments that 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.

And then there's 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 and that the market in these last couple rounds as built as not supported take or pay economics. But what I would say is that Mont Belvieu fractionation position and we anticipated the four and five being full, but under the scenario that they wouldn't we're not full we always have the option to take barrels that were fracking in the Mid-Continent moving 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 beaten 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 its production that's coming on. Now that we do not have enough frac capacity to today.

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

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

Yes, you’re pretty close.

And on the 200,000 a day ultimate capacity that's been contracted in the Rockies, two 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 anything comes on your reset a lot quicker, so I think it take a little bit of time. I think the last piece will come in the delay on the last piece would be. We got to get the lateral over which will be completed the end of 2020.And then it would you repeat your last part of the question?

I wanted 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% coming out of the Bakken.

Right. And one last versus…

Craig, just before you, before you move on, really a lot of those volumes are coming out of the powder not as DJ.

Yes, 80% of the Bakken and almost the almost the rest of it's all out of the Powder River.

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

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

Thank you, this concludes our questions for today. I'll turn it back to 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 will 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.