Ladies and gentlemen, thank you for your patience in holding. We now have our speakers in conference. Please be aware that each of your lines is in a listen only mode. At the conclusion of our presentation, we will open the floor for questions. Instructions will be given at that time on the procedure to follow if you would like to ask a question.
It is now my pleasure to turn this conference over to Andrew Ziola. You may begin.
Thank you, Chantal, and welcome to ONEOK's 2nd quarter earnings conference call. This call is being webcast live 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 Act of 1933 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.
It's an exciting time for ONEOK as we begin placing some of the largest capital growth projects in our history into service. Our projects remain on or ahead of schedule and on budget. The southern section of Elk Creek pipeline began flowing NGLs on July 15th the Rockies region into the Mid Continent with the northern section still on target to be completed in the Q4. Last week, we announced additional low cost expansion projects across our system, which continue to demonstrate ONEOK's ability to incrementally grow with our customers. These projects will help address NGL transportation and fractionation needs of producers and will further address flaring in North Dakota with added natural gas processing capacity.
All our projects, including these recent expansions, are built to meet the needs of our customers and are backed by long term contracts. We continue to see strong producer activity levels across the basins where we operate with NGL and natural gas volume growth that is in line with our expectations so far this year. Now more than halfway through the year, our confidence in our 2019 financial expectations and 2020 earnings outlook has strengthened significantly. With our projects remaining on or ahead of schedule, we expect accelerated earnings growth leading into 2020 beyond and additional cash flow to reinvest in our business, reduce leverage and continue to return value to shareholders. With that, I will turn the call over to Walt for comments on our Q2 results.
Thank you, Terry. Our Q2 2019 net income totaled $312,000,000 or $0.75 per share, an 11% increase year over year. And 2nd quarter adjusted EBITDA totaled $632,000,000 a 5% increase year over year. Distributable cash flow in the Q2 2019 was $540,000,000 up 19% from the Q2 2018 with a healthy dividend coverage of 1.51 times. We also generated more than $180,000,000 of distributable cash flow in excess of dividends paid in the Q2 2019.
During the Q2, we paid a dividend of $0.865 per share. And last week, we announced a dividend increase to $0.89 per share or 3.56 dollars per share on an annualized basis. This increase further underscores our confidence in the increasing cash flow we expect to generate from projects we have recently completed or will complete in the coming months. The dividend is payable on August 14 to shareholders of record on August 6. Our June 30 net debt to EBITDA on a trailing 12 month basis was 4.2 times.
With the earnings expected from these projects, we expect to be at 4 times debt to EBITDA run rate in the Q4 of 2020 or Q1 of 2021 with deleveraging continuing in the quarters to follow. Our liquidity remains strong as we ended the 2nd quarter with the full $2,500,000,000 available on our credit facility and more than $270,000,000 of cash on hand. We announced additional natural gas and NGL expansion projects last week that we expect to provide attractive returns for minimal capital invested. We do not expect these projects to impact our 2019 growth capital guidance range of $2,500,000,000 to $3,700,000,000 as most of the spending will happen in 2020 2021. Because of the accelerated timing on some of our projects, we anticipate ending the year towards the higher end of our capital guidance range.
As spending on our large pipeline projects winds down early next year, we expect capital expenditures in 2020 to be lower than 2019. Producer activity, project timing and additional committed volumes on our system all add up to an impressive backdrop for ONEOK's growth. As we sit today, we are even more confident in our outlook that our 2020 adjusted EBITDA will increase greater than 20% with an emphasis on the greater than when compared with our 2019 guidance midpoint. I'll now turn the call over to Kevin for a closer look at our operating performance.
Thank you, Walt. We continue to see strong producer activity across our operations, driving increases in both NGL and natural gas volumes in the 2nd quarter. Total NGL raw feed throughput volume increased nearly 110,000 barrels per day or 11% year over year and increased 80,000 barrels per day or 8% compared with the Q1 2019. Natural gas volumes processed increased more than 150,000,000 cubic feet per day or 9% year over year and increased more than 80,000,000 cubic feet per day or 4% compared with the Q1 2019. Let's take a closer look at our volume growth and project timing in each of the basins where we operate, starting with the Rockies region.
Producer results remain strong in the Williston and Powder River basins. North Dakota natural gas and more than 500,000,000 cubic feet per day of natural gas being flared and nearly 1,000 drilled but uncompleted wells in inventory. All of these factors provide an inventory of growth for our natural gas liquids and natural gas segments. As Terry mentioned, we completed the southern section of Elk Creek pipeline from the Powder River Basin to the Mid Continent, and it is currently flowing more than 30,000 barrels per day of NGLs. With the southern section in service, we have moved volumes previously railed onto our pipelines, eliminating higher rail transportation costs.
This has also freed up rail capacity, which can be used to address continued NGL growth in the Williston Basin until Elk Creek is fully in service in the Q4. As further growth is expected, we will add pumps on Elk Creek as needed to increase capacity. These projects are low cost and can be completed incrementally to address additional volume growth, including the need for potential ethane recovery. Approximately 850,000,000 cubic feet per day of new natural gas processing capacity is coming online basin wide between now and the end of the Q1 2020, which translates to approximately 110,000 barrels per day of propane plus NGL production when these plants are full. With all of the NGLs from those plants dedicated to ONEOK and more than 30,000 barrels per day already flowing on the pipeline, we remain confident that throughput on Elk Creek will reach approximately 100,000 barrels per day in the Q1 of 2020.
ONEOK has now announced a total of 600,000,000 cubic feet per day of additional natural gas processing capacity in the Williston Basin expected to come online between now and early 2021. Our latest announcement was the 200,000,000 cubic feet per day expansion of our Bear Creek plant in Dunn County, an area that has recently experienced some of the highest production increases in North Dakota and has a decades long runway of well inventory yet to be drilled. We expect volumes on the Bear Creek expansion ramp up over a 12 to 24 month period once in service. This expansion also increases our NGL volumes contracted from natural gas processing plants in the Rocky Mountain region from 200,000 barrels per day to 225,000 barrels per day. Our Demicks Lake I plant remains on schedule to open full in the Q4 2019 in conjunction with the completion of the northern section of Elk Creek.
Demicks Lake 2 is expected to be complete early in the Q1 2020. Moving on to the Mid Continent. Producer activity in the region remains in line with our expectations for the year. In the Q2, we saw increases in both NGL raw feed throughput volumes and natural gas volumes processed in the Mid Continent compared with the Q1 2019. Large well pad completions early in the quarter drove the increase in natural gas volumes processed and 2 new third party plant connections contributed to the increase in NGL volumes.
Arbuckle II is on schedule for completion in the Q1 of 2020 and its contracted capacity now totals 375,000 barrels per day compared with 350,000 Last week, we announced NGL fractionation facility expansions totaling 65,000 barrels per day in the Mid Continent. These projects will increase our propane plus fractionation capacity to help address the heavier NGL barrels from the Williston Basin. 15,000 barrels per day of capacity is expected to be completed in the Q3 2020, with the remaining 50,000 barrels per day completed in the first quarter of 2021. These types of projects can be efficiently completed at costs substantially lower than new construction. Recently completed expansion projects in our natural gas pipeline segment continued to drive higher firm capacity contracted in the 2nd quarter compared with both Q2 2018 and the Q1 2019.
These projects increased the capacities of our Mid Continent and Permian Basin pipeline systems and will continue to provide increased firm transportation earnings going forward. Now let's take a look at our Permian Basin and Gulf Coast operations. NGL raw feed throughput volumes in this region increased 20% compared with the Q1 2019, primarily driven by volume growth on our West Texas LPG pipeline. We continue to expect our average fee rate in this region to trend higher in future quarters as legacy volumes roll off West Texas LPG and are replaced with market based transportation and fractionation volumes and as expansion of the system come online, which are contracted at market rates. The 80,000 barrel per day expansion of West Texas LPG remains on track to be completed in the Q1 of 2020 with volumes ramping up quickly after it is placed in service.
And last week, we announced a third expansion, which will add 40,000 barrels per day of capacity to the system. The expansion is supported by long term dedicated NGL production from processing plants in the Permian Basin and is expected to be completed in the Q1 2021. Our NGL fractionation capacity, given current product composition, is approximately 820,000 barrels per day and was 90% utilized in the Q2. We now expect to complete our 125,000 barrel per day MB-four fractionator in phases. Phase 1 will provide approximately 75,000 barrels per day of capacity and is expected to be available in the Q4 of this year earlier than originally planned.
Phase 2 will consist of the remaining 50,000 barrels per day and is expected to be completed in the Q1 of 2020 as originally announced. MB5 remains on track for completion in the Q1 of 2021. Terry, that concludes my remarks.
Thank you, Kevin. The progress on our capital growth projects this year is setting us up well for a significant volume and earnings uplift in 2020. As Walt emphasized, we're even more confident in our 2020 adjusted EBITDA growth outlook of greater than 20 percent compared with our 2019 guidance midpoint. The impressive production results across our operations highlight the widespread quality of our operating basins and well capitalized and experienced producers operating there. The volume growth we've discussed today has high visibility.
Both NGL and natural gas volumes are ready and waiting for processing and transportation now. Producers are looking to ONEOK to provide the critical infrastructure they need to connect their products with demand markets and we're well equipped and ready to grow our operations efficiently in order to do so. I'd like to recognize our large project teams and operations personnel located both at our headquarters and at our various field locations for their hard work to keep our growth projects on time and on budget, and specifically to those working on our Elk Creek pipeline who were able to place the southern section in service early, benefiting many of our customers. Thank you to all our employees for your dedication to ONEOK. Your continued focus on safe and responsible operations has led to our continued reliability and operational success.
With that, operator, we are now ready for questions.
Thank you very much. Our first question will come from Danilo Juvein, BMO Capital.
Thanks and good morning. You mentioned in the press release having significant upside in the second half of the year from the early start of Elk Creek and other projects as well. Where do you see sort of your 2019 EBITDA number residing relative to the midpoint? And to the extent that you reside higher than the midpoint, do you still see a 20% growth rate between 2020 2019?
Well, we haven't changed any of our guidance and don't expect to do that today on this call. Obviously, as we get through the year, we'll continue to evaluate whether we're going to adjust that. But right now, we're giving that outlook on 2020 off of the midpoint to let people have a basis on which to think about it.
Thanks for that Walt. DCF was pretty strong during the quarter and it looked like it potentially came from Northern Border. Anything going on there?
Nothing really out of the ordinary. Northern Border made an off cycle distribution in addition to our normal quarterly distribution in the Q2, but nothing out of the ordinary course of business.
So we shouldn't expect that to continue going forward?
I'm sorry,
can you
say that again?
We shouldn't expect any more off cycle distributions for the balance of the
year? No, it's a distribution in excess of earnings for the quarter and that catches us up. So distributions going forward will track with earnings as they have in the past.
Got you. Last question for me. To the extent that you continue to see strong production out of the Bakken for liquids, any thoughts on a potential residue gas takeaway solution?
I think, I mean, clearly there it's something we're looking at, we're paying attention to. When you look at the capacity that's getting ready to come online across the basin, and we do believe we can continue to in the basin we'll continue to displace gas coming from Canada. But absolutely there are conversations going on a variety of different outlets and we're participating in all those conversations.
Thanks, Kevin. Those are my questions.
Thanks.
Thank you very much. Our next question will come from Chris Sighinovalli, Jefferies.
Hey, guys. Good morning. Nice continued execution. Thanks for taking my questions. Well, I just want to circle back on that question Danilo had asked about Northern Border.
Just for my own notification to understand, is I guess what's the mechanism for that? This cash build at the JV and then you and your partner make the decision to pay that out on a periodic basis?
Yes, to the extent that over time we make a regular quarterly distribution and to the extent that the management committee believes that there is a capacity to do more than that, they have the ability to do it in a one time basis and that's what happened here.
And as it pertains to DCF guidance and things of that nature, this was anticipated to fall this year. Is that also correct?
Well, I think that it's fair to say that as we the plans to do this kind of develops throughout the course of the year. So, I think on a going forward basis, we would expect distributions more in line with where they have been on a quarter by quarter basis.
Okay. All right, great. And then if I could switch and just Kevin, I wanted to touch base, you guys have done a really nice job continuing to contract up Arbuckle 2. Seemingly every quarter, we get another 200,000 or 25,000 barrels a day of commitments there. And I just wanted to better understand or just I guess review and remind myself as to where the volume slate now for that pipeline will be sourced, I guess, between what's fed to it from Elk Creek, what comes from the Mid Con plants and then what comes from 3rd parties.
Is there a rough rule of thumb at this point given all the incremental contract adds you've had?
Well, I mean, it varies as we contract new plants. Obviously, if you're getting a plant in the Mid Continent a new contracted plant that's going to be tied directly to Arbuckle II. As we get a new Bakken plant, if those barrels are going to all go all the way to Bellevue, then that will be included in both Elk Creek and Arbuckle II. So that's how we break it down. I mean, Sharon, do you have any other thoughts on just in general how
Well, I think that's the right. So definitely you could see that on a very macro sense that the difference between what we've contracted for Arbuckle II and what we've contracted for Elk Creek. That difference is definitely coming out of the Mid Continent.
Okay. And is it fair then if I look at just the table that you guys have long provided that looks at the bundled rates on your NGL raw feed service? If I like I guess what I want to be careful of doing is making sure I'm giving you enough credit and appropriate credit for each of these two assets, but not double counting volume that's moving on Elk Creek that then subsequently moves down Arbuckle II. And so is it fair to just credit the Elk Creek volume with the bundled rate on the Bakken portion and then the incremental volume that I would see above that give that midcontinent rate, is that fair way rule of thumb to think about it? Or would you advise me to do something different?
No, I think that's a fair way to think about it.
Okay. All right, great. Thanks for taking my questions guys.
Thanks, Chris. Sure.
Thank you. Our next question will come from Tristan Richardson, SunTrust.
Good morning, guys. Just on the expansion project for Mid Con frac capacity, you talked about that in prepared comments just about the heavier barrel. Is this purely really just optionality for you guys and the customer? Or just kind of curious, could you talk about sort of the need for new capacity there relative to what the projects you have going on at Bellevue?
I think it just came down a lot of it came down to we had the ability as our teams looked at how we provide more fractionation capacity that that was a low cost option for us and would drive the best return. With our other pipes, clearly, we'll have the ability to move those purity products down to Bellevue once our Buckle II is up. So we do get that optionality, but it really came down to where we look at where we could provide the lowest cost, most efficient frac capacity.
Great. And then just a follow-up on your appreciate your commentary on directionally where 2020 CapEx might stack up relative to 2019 range. Should we think about that as just sort of on the projects you have sanctioned today? Or does that contemplate other projects that you might be looking at that haven't necessarily been greenlit yet?
No, I think that our expectation given everything that we see going forward both what we've been able to announce and we're thinking we'd have lower CapEx in 2020 than it will be in 2019.
Appreciate it. Thank you guys very much.
Thanks.
Thank you. Our next question will come from Christine Cho, Barclays.
Hi, everyone. Great quarter. What is the financial benefit going to be when rail and third party frac costs roll off? I'm assuming it's all off by Q1 next year when all your assets are online, but could you provide the cadence of the roll off between now and then as well?
Well, I guess what we've talked about previously, the way to think about that is the barrels that have already rolled off rail, I think we said we save about $0.20 per gallon of transportation cost. So as we put more barrels on rail through the rest of this year, then the next step will be when the full pipeline is in place and all those rail barrels move to the pipe, then you'll see another uplift at that point, along with other volumes coming from processing plants when the flares start getting put out when the processing capacity comes online. Did that answer your question, Christine?
Yes. I guess, okay. But you've moved 30,000 barrels per day off right now with the southern portion coming on, but you're still continuing to rail. So I guess and I'm guessing the rail is still going to increase, throughout the end of this year. So at what point does that peak?
Like how much are you railing today and how much do you expect to rail at the peak between now and year end?
Well, the rail volume when we brought on the southern section, the rail volume at that point in time went to nearly 0. So we pulled pretty much everything down. And then that rail volume, you have plants coming online between now and when Elk Creek comes in, gets in service. So we will use rail, it will start building back up as volumes from those plants start coming online. So it will build back up and then once the full pipeline is in place, all of it will obviously move back over to the pipe.
Okay, got it.
Christine, this is Sheridan. We think by the time we bring Elk Creek back on, when we get the northern section of Elk Creek completed, we will be railing upwards of 30,000 barrels a day again.
Okay. Super helpful. And then your contracted levels on Elk Creek is approaching capacity. Can you remind us how long it would take to expand the pipeline if you decide to do so? And also discuss at what point you would do that just given it's probably low cost and your numbers is doing minimal ethane extraction and I'm not sure at what point that might change?
We look at it continually. Clearly, those projects aren't 2 year projects like building the pipe. They're measured in terms of months not years. And we also have the ability to do things like order in pumps and lot of the long lead time, long lead equipment and other engineering things we can go ahead and do to prepare for that so that it drives the time required to get that done to again just a matter of months.
Okay. And then last one for me. There was an increase in Bakken processing volumes, but your NGL pipeline volumes remained flat. What was the reason for that?
We just drove our ethane rejection just continued to drive deeper and deeper. So to get more throughput through the plants and remain the pipe the NGL takeaway was at capacity. So we were able to through our plants drive deeper rejection and run more inlet but not produce as much liquids.
So, you are doing MAX rail for the quarter too then?
I mean, towards the end, yes, that we were pretty much at MAX rail.
Okay. Thank you.
Thank you. Our next question will come from Michael Bluhin, Wells Fargo.
Hey, good morning, everyone.
Good morning.
I'm curious if you can just comment a little bit, obviously NGL prices have been pretty volatile. I was curious for your latest views on how you see things trending for the rest of the year and into 2020. And then kind of related to that, if you have any different or updated views on how the Conway Bellevue spread is going to trend here for the rest of the year?
Michael, this is Sheridan. I think as we look at the overall price, if you keep crude at the level it is today, you'll see a little uptick in prices. Obviously, we're seeing more export capacity for propane come online, which should create more demand and you're seeing more crackers come online that you should see some uptick in absolute price here through the end of the year and into 2020. Not a huge spike, but I think you'll see some strength. On the Conway to Bellevue spread right now we think that where it is today is where it's going to be or in this range through the Q3 and start into the Q4.
Then you'll get into some seasonality issues that probably will bring that spread in a little tighter than it is today. Then of course as we've said before once we bring Arbuckle II online that spread will go back to more what we've seen historically, which is much narrower than we have today.
Okay, great. Appreciate that. And then just this recent slate of projects that you just announced, should we just think of the returns on those projects, would you consider those to be kind of within the normal course of your typical return profile or those would be better because some of them are kind of bolt on in nature? How do we think about that? Thanks.
Yes, I think Michael, it's Kevin. I think the plant projects are going to be in our kind of our standard 4 to 6 times, but some of the other just expansions and frac expansions that we've talked about could be done at lower cost and new construction are going to be better than that.
Thank you.
Thank you very much. Our next question will come from Jeremy Tonet, JPMorgan.
Hi, good morning. Appreciate that you guys are not updating guidance at this point. But just curious within the G and P and the Gas Pipelines segment, it seems like you guys are trending quite strong versus the ranges that you put out there. Is there anything in the back half of the year that could kind of temper this trajectory or is kind of like the high end or above the high end seems like could be possible for those segments?
Jeremy, this is Chuck. We can talk first about G and P. I think we could trend higher. It's going to come down to 1, our pipeline infrastructure, some of our field facilities come on. So it's a matter of timing as we get toward the end of the year.
And as you think about our gas pipe business, we've seen very good demand for our not only interruptible volumes, but our balancing services and short term storage services which are kind of driving some incremental earnings that we hadn't necessarily planned on. So both of the segments are doing very well right now, demand is up and we're just taking care of customers at this point.
Great, that's helpful. And then thinking about the balance sheet here, it seems like I think before the leverage is going to peak, I think at the beginning of 2020 with all the projects coming online, You've added some more to the backlog there and or you've FID ed some more brought into what you're going to do. And just wondering how you see leverage, I guess, moving across 2020. Is that still the same peak? Or any color that you could provide on how that all comes together?
Well, Jeremy, our heaviest spending is definitely in the 3rd Q4 of 2019. So when you enter that Q1, we've said that with Elk Creek coming on in the Q4 and the volumetric disclosure, the guidance that we've put out there as it relates to our expectations of how quickly Elk Creek is going to build its volume around that 100,000 barrels, we're going to see a significant uplift in our EBITDA in the Q1 of 2020 throughout 2020 and that's going to delever us right from the get go in 2020. So as we cross over the year that will be our peak. The projects that we've announced to date will be towards the back end of 2020 and into 2021 from a CapEx spend and we'll already be well down our road to delevering. And in my prepared remarks, I gave you some thoughts on where we might end the year.
So we're kind of seeing the same trajectory and still looking for some significant delevering going forward.
Thank you. Our next question will come from Dennis Coleman, Bank of America.
Hi. Good morning, everyone. One for me with regard to the fracs. Just I'm a little interested in sort of phasing of bringing on Frac IV, if I understand it right.
Can you just talk
I don't really sort of have a concept of how you bring on a frac in stages. So maybe if you could just talk a little bit about how that's happening?
Yes, Dennis, it's Kevin. Well, in this case with our complex down there, we had some spare capacity for some what I'd call it kind of utilities, some refrigeration, some heaters are typically long lead equipment, long lead time type equipment items. And so we're able to leverage some existing spare capacity we have to bring up the frac in kind of a partial mode. And then as we've installed the rest of that equipment, that's what will get it up to full capacity in 2020.
Okay. So the vessel itself is there and then just so I guess the follow on question is, if you're using up that capacity, should we expect that to be a model for Frac 5 as well?
We'll evaluate it. We may not have the same type of spare utilities, if you will, for frac 5. But that's something obviously we'll take a look at a variety of different things to do, but I wouldn't expect that happen for the MB5.
Okay. Okay. Thanks for that. And then, I'm sorry about this, but just to go back to this Northern Border Distribution, Danilo and Chris both hit on it. But this one time payment, we should not that wasn't included in the guidance, correct?
And so we should just use the guidance and sort of use this one time payment and think of it that way. So if we add that in, we should think about the guidance you're going to be above the guidance?
It's fair to say that that was not included in the original guidance.
Perfect. That's what I need. Okay, that's it for me. Thanks.
Thank you. Our next question will come from Spiro Dounis, Credit Suisse.
Hey, good morning, everyone. Just maybe going back to the 20% growth expectation for next year. Not sure we've seen you guys highlight that in a while here, maybe not since the original guidance was provided. So getting the sense of that means you're getting pretty confident in that figure. So curious how you're thinking about some of the underlying assumptions to get there, maybe just around commodity differentials and some of the base business growth.
You made some comments earlier just around the differential outlook, but if you could just expand there in the context of that 20% growth next year?
Yes. This is Kevin. I mean, I think obviously, the huge driver there is the backlog of flared gas and the inventory we talked about up in the Bakken. When you think about if you just kind of put the math to the 100,000 barrels a day that we expect on Elk Creek by the Q1. And you put that out over the course of the year and then you've got a full Demicks Lake 1 plant running full for the entire year.
You've got Demicks 2 ramping up. And then you've got growth on the Permian and Mid Continent as well. But when you just go back to the 500,000,000 cubic feet a day that's flaring in the Bakken across the basin and the processing capacity that's coming online between now and the Q1, that just generates a significant amount of NGLs, which is the primary driver for the 2020 number.
Got it. And so if I'm hearing that right, it sounds like there's no real major call being made here on big volume growth outside of that or any sort of commodity or differential move. Is that fair?
Yes, it's fair. In fact, we've been talking very openly as Sheridan mentioned with Arbuckle II, we expect spreads to come back in much narrower than they are today. And that is included in that that assumption is included in that 20% greater than 20%.
Got it. Okay. Appreciate that. And then maybe just more broadly in how you're thinking about your Mid Con footprint longer term. Clearly, the most of your growth is really focused outside that area.
And I guess lately, producer commentary there has been somewhat lukewarm. So just curious, what sort of optionality do you have around that footprint to maybe offset some potential volume headwinds sort of past 2019, or if you think that's even fair to be cautious on the Mid Con at this point?
I think just in general, the Mid Continent, like we remarked in our prepared remarks, the volumes have been in line with our expectations. Yes, there may have been a couple producers that you've seen some things written that were off a little bit, but then you've been we've had some that have outperformed our expectations. And I think one of the things we continue to remind people is we kind of have our own expectations given the footprint and the size of our system both in the G and P and the NGL side. So as we set our forecasts out there, we're factoring in all that information. So we feel good about it and we do expect growth out of the Mid Continent as we move forward.
I mean guys?
One thing I would say is that we're still planning on hooking up another 2 more plants in the Mid Continent, the second half of this year. So we're still seeing some need for capacity.
And what I would add from a mono GMP standpoint would be, I think our WellConnect guidance that we gave were trending as though we're going to exceed it and I think we probably will this year.
Got it. I appreciate that. Just one last quick one if I could and sorry if you guys touched on it. Just around LPG exports, obviously been considerable amount of new capacity announcements made recently. I imagine that factors into your market outlook.
So just how are you thinking about that now?
I think when we think about LPG exports, we're going to continue to engage the market to understand what the market is and what's going on there. But what we're not going to do is go out there and do an uneconomic project or just build something to say we have an export terminal. So we're continue to use our capital discipline as we evaluate that. But we'll always be involved in engaging the market on exports. And when we get to the time that we see that we have an economic project that we want to go forward, then we will go forward at that time.
Got it. Appreciate all the color. Thanks guys.
Thank you very much. Our next question will come from J. R. Weston, Raymond James.
Hey, good morning. Just wanted to ask real quick on Bakken G and P volumes. So far this year kind of relative to guidance, it looks like you're tracking pretty well, but it looks like you've got almost 60% of the well connects still expected in the second half of the year. So just kind of curious if there are other moving pieces in that guidance or if it seems like maybe you're tracking above expectations there?
Well, I think we did lag early in Q1 due to weather and there was, let's face it, not only cold, but there was a lot of snow. So it was difficult to get out there and connect wells. 2nd quarter, we obviously strengthened and connected quite a few. I think the remainder of the year will hit our guidance on our well connects. And some of that is just waiting on some capacities at certain compressor stations.
So think we're in good shape to hit our guidance numbers for the year on our well connects and volume guidance.
That's it for me. Thanks.
Thank you. Our next question will come from Shneur Gershuni, UBS.
Hi, good morning guys. Good morning. Maybe just a couple of quick follow ups here. Just with respect to the guidance, you sort of maintaining this 20%, but in your prepared remarks, you kind of emphasized greater than 20% was the comment. Until a few days ago, ethane has been under severe pressure.
And if I remember correctly, you had a big ethane rejection reversal tailwind in the last 2 years. Did your guidance when you originally set it out and saying the plus 20%, did that include some reversal of the ethane rejection? And is that being offset by some better Elk Creek expectations? Just kind of wondering what the moving parts have been positive and negative from the time you said it versus where you sit today?
What I would say in when we look at the NGL volume growth in 2019 that has exceeded our expectations. Part of that is, we probably have not seen quite as much ethane come out of rejection as we thought, but we're seeing more ethane on our system than we thought from the growth in other areas. So we are seeing that offset a little bit, but I think the big thing is we are seeing more volume growth than we thought we would see at this time.
Okay. And then secondly, with respect to announcing a third plant in the Williston, I was just wondering what your flexibility was around the spend and the in service date. When I sort of look at the flaring numbers that you have out there in your slides for 300 millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeterscf a day on your acreage, just not moving around and that trend continues, do you have some flexibility around the spend to sort of push out the in service date of this third plant?
Shneur, this is Kevin. I mean, yes, technically you would have that flexibility, but we see nothing right now that would cause us to do that. In fact, it's just the opposite. Our customers are they need more capacity in Dunn County area. The results they've seen and these are some large well capitalized producers with large acreage blocks.
They want to drill this area out and the plants full. And the only reason they're not deploying more capital down there right now is because of capacity. So we clearly see this as a growth area for us. And we started off looking at a smaller expansion and the more color we got from producers about their immediate plans, we continue to push it up and decided to put a $200,000,000 a day expansion in.
All right. That sounds great. Thank you very much. Appreciate the color, guys.
Thank you. Our next question will come from Jean Salisbury, Bernstein.
Hi, good morning. Could you give us an estimate of how much ethane is being rejected into Northern Border today and what the maximum you think it can handle is?
Yes, this is Chuck. Today, there's roughly about 150,000 barrels a day of ethane going into Northern Border. We actually looked at this just the other day and the North Dakota Pipeline Authority has some information out at their website about it. With forecasts over time depending on the mix between Bakken gas and Canadian gas filling that pipe, you could see it as much as 180,000 to 200,000 barrels of ethane.
Great. That's really helpful. Thank you. And then obviously there's a lot of crude pipelines that are running open seasons out of the Bakken. Just as a general question, do you usually find the E and Ps when they sign up for crude takeaway tend to pair it with other takeaway?
Like for example, if they signed a new 10 year contract for crude, would you expect them to be looking for NGL takeaway to match with that?
Typically, we don't see that. Where we see people come up need NGL takeaway capacity is when you're looking at building a new plant. So when they build the new plants, when they'll secure the NGL takeaway capacity for that complete new plant and then they'll grow into it as they on the crude on that side of it. So just because they signed up for a long crude term deal doesn't necessarily mean they're going to sign up for NGLs and vice versa. But you really got to look at when you start seeing more plants being announced, they have either are going to sign up for NGLs or have already signed up for the NGL takeaway.
Really helpful. Thank you. That's all for me.
Thank you. Our next question will come from Ethan Bellamy, Baird.
Hey, good morning, y'all. There's some concern by investors that the Bakken may decline in the next 3 to 5 years. What's your expectation for North Dakota volumes on your acreage longer term?
Again, Ethan, this is We continue to see growth. When you just look at the track record of even with rigs in that 55 to 60 range for the basin, we have seen significant gas production growth. And just remember that gas production is growing at a faster clip than crude production because of the GOR and the increases there. So there's a lot of positives about gas production. You look at some of the forecasts out there, we believe there's definitely growth beyond that horizon you mentioned.
Okay. That's a good segue to my next question.
Well beyond that.
Sorry, go ahead.
No, I just said well beyond that.
Okay. Thank you. I was just going to ask, it looks like we might need a new gas export pipe to handle that volume. Do you agree with that? And is that a project you're vetting?
Yes. I think we definitely agree with that. And there again as we discussed earlier there are a variety of projects being discussed in different avenues to get more residue out. But clearly, if we stay on a growth trend, you were the basin is going to need some additional takeaway capacity over the next 2, 3, 4 years.
Okay. Moving down south, how has the decline in NGL prices impacted, if at all the rates and negotiations with customers for frac capacity?
It has not impacted them at all. We go in to reprice our services off of alternatives, off of what the marketplace is and remember that NGLs are a byproduct. It needs to be taken away in areas people if they can't get the capacity, they're flaring what they say. So the absolute price of the NGLs does not have an impact on what we can charge for our services.
And market is still fairly tight?
Market fractionation capacity is still pretty tight. There's a lot coming on and pipeline capacity obviously is tight because we're building new ones as we come on as well. So yes, the market is still fairly tight in all areas.
Okay.
And then last question. There are a lot of assets on the market and even a few whole partnership. What's your appetite for M and A here?
Ethan, this is Terry. Not very high. Candidly, when you look at the gross slate of opportunities that we have going forward, when you think about it from an accretion standpoint, we're talking dollars a share in additional earnings to come to the company over the next several years. We can't really get that from strategic M and A. Now there may be some assets from time to time that we can buy with cash that could make some sense.
But right now, we really don't see anything out there that's that compelling or valuations in particular that makes sense, particularly when you think about the alternative we have to invest organically.
Thank you. Our next question will come from Craig Shere, Tuohy Brothers.
Good morning. Congratulations on another great quarter.
Thanks, Greg.
On the G and P unit fee based margins, that looked to be a record in the Q2. Is that sustainable
and what's driving that?
Craig, this is Chuck. We guided to $0.90 to $0.95 We're at $0.93 today. Obviously, with more Bakken gas coming on, it's higher margin relative to our Mid Con business. So that's part of the driver. In addition to that, you get into contract mix, different producers, we have different fees.
And so is it sustainable? I think we're solid in that range.
Okay, great. And I just want to understand all the system integration gives and takes as it relates to Arbuckle II and possible kind of modularity of your system, if I could describe it that way. Currently, you're coming on at $400,000 and then you have an increase of $500,000 a day. Your contract at 3.75 but if you switch Sterling 3 purity products, any excess Y grade that has been fractionated would have to go to Arbuckle 2. And then you may wind up putting all the growth that you're seeing in West Texas LPG into the southern leg of Arbuckle II.
So I'm just trying to think through how quickly the entire system can fill up?
Well, that is a good question. We continue to look at how fast can it fill up and we're as we said, we can add pumps fairly quickly as we go forward. But you are right. If I go back to the original start of your question, the modularity and the optionality we have through our system gives us a lot of flexibility. And the first one is, it's actually Sterling 3 is on raw feed today.
We will take all Sterling 3's raw feed, put it on Arbuckle and open that up for purities. That's why we believe the spreads between Conway and Belvieu will come together. And then we will take we think hopefully very quickly we'll take our buckle up to 1,000,000 barrels if all the capacity comes online as we think it's going to come online, we see it to the future. But we still think above we'll put the pumps in to go to 1,000,000 barrels. We still have some headroom to reach that 1,000,000 barrels that we have not contracted for today.
But we should be in the upper end of Arbuckle II and full pipelines are a good thing. And if we need to build another pipeline because we see that kind of volume come out, we'll build another pipeline.
So Sheridan, a couple of questions. The northern section of Arbuckle 2 isn't the same capacity as the southern section, right? So if you do take West Texas volumes, you can go to 1,000,000 barrels, but you can't in the Northern section, right?
The Northern section can do 600,000 barrels and the Southern section can do a 1,000,000 barrels. So that leaves in West Texas pipeline is going to come in right where Arbuckle II transitions from a 24 inches or 600,000 barrels to a 30 inches or 1,000,000 barrels. So that leaves 400,000 barrels a day that's open for West Texas to fill. That does not impact the volume coming down from the north. And that's how the system was designed.
That was our plan in the beginning. So you could we're anticipating we could see upwards of 400,000 barrels come off West Texas and go on to Orbital
2. And then if I understand that that would free the southern section of West Texas for potential crude service?
That's correct. Or as we continue to just get to 400,000 barrels a day on West Texas, we are going to have a complete new line out of the Permian to Arbuckle II, which would free up West Texas from the Permian, the legacy West Texas system from the Permian to the Gulf Coast to use for some other service, which would include crude.
I see. And moving the Y grade from Sterling 3 to West Tek I'm sorry, to Arbuckle II that's got nothing to do with the $375 a day of contract. The $375 is all incremental to what you have today, right? And then moving capacity over to take advantage of the purity product is just extra.
That is correct. The $375,000,000 is a does not include the volume that's moving on Sterling 3 today.
Great. Thank you very much.
Thank you. Our next question will come from Sunil Sibal with Seaport Global Securities.
Yes. Hi, good morning, guys, and thanks for all the clarity on the call. Just one quick question on the G and P segment. Obviously, the results were fairly strong and I noticed that your OpEx in that segment actually fell sequentially as well as versus last year despite a decent pickup in volumes. I was just curious, is there anything going on there?
Or I know sometimes commodity especially the gas prices kind of impact that OpEx too. So I just was trying to get a little bit clarity on that.
Yes, this is Chuck. No, sequentially, we're about $6,000,000 lower and it's pretty much just due to timing between the quarters. So if you average those two quarters together, run rate might be a little bit higher as we progress toward Demicks 1 and 2 bringing on more employees and more field costs. But it's pretty much those are good numbers for the year.
Okay. And gas is more like a pass through cost, that natural gas prices don't really impact that number, correct?
No, it does not impact that number.
Okay. Thanks for that. And then just trying to understand a little bit better on the LPG export side of things. From what I've been hearing, obviously, there have been a number of DOG expansions coming online, which seems like there's maybe some constraints in moving those LPG volumes to the end customers ultimately. I was curious if you have a view on that.
And also, is there some way that when you're talking to customers on the LPG side, so there's some way for you guys to take in get an opportunity out of that?
I mean, again, as Sheridan kind of alluded to on the dock question, yes, there have been announcements out there. There is more capacity that's going to be announced. We do see some of the short term rates or spot rates have been pushed down. But like Sharon mentioned, I think the key is as we talk to customers, we're looking longer term, we're looking for rates that are going to economically justify a project and that's the way we'll approach it.
Okay. Got it. Thanks, guys.
Thank you. Our last question will come from Michael Lapides, Goldman Sachs.
Hey, guys. How are you guys thinking about what a 2021 step up looks like versus 2020? I mean, you've got a lot of projects that come online in 2020 and trying to think about how much that 20% plus captures that for 2020 versus what drives a 2021 step up?
Michael, I think that we're definitely not going to give you 2021 guidance and we're stepping out a little further than we usually do and give you an outlook on 2020. So you're going to have to do your own work here. But if you just take the capital that we're investing and recognize that we're in the same multiple and in some of these incremental projects or even at better multiples, 2021 is looking pretty good too.
Got it. Do you still assume a 4 to 6 times multiple on most of these projects? Or do you think some can even be better than once you get them at full run rate?
Well, I think that the frac is a perfect example of adding capacity at about half the price of build is definitely better than a 4 to 6 multiple.
Got it. Okay, guys. Thank you. Much appreciated.
Sure.
Thank you very much. Speakers, at this time, we have no further questions in the queue.
Well, thank you, everyone. Our quiet period for the Q3 starts when we close our books in early October and extends until we release earnings in late October. We'll provide details for that conference call at a later date. Thank you for joining us and the IR team will be available throughout the day for your questions. Have a good week.
Thank you very much. Ladies and gentlemen, at this time, this now concludes our conference. You may disconnect your phone lines and have a great rest of the week. Thank you.