Good day, and welcome to the 4th 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, and good morning, and welcome to ONEOK's 4th quarter year end earnings 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 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 trust and investment in ONEOK. Joining me on today's call is Walt Hulse, Chief Financial Officer and 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. 2019 was an outstanding year, a year of project execution and record setting safety performance for ONEOK, positioning ourselves for exceptional growth in 2020 2021. Yesterday, we announced 4th quarter and full year 2019 results, announced our 2020 guidance and provided a 2021 outlook. We also announced 3 expansion projects that will further strengthen ONEOK's position in the Williston and Permian Basins and increase the needed natural gas processing and NGL transportation capacity for our customers. It is important to point out that these high return projects build off of our existing assets.
These projects include the Demicks Lake 3 plant in the Williston Basin, the full expansion of the Elk Creek pipeline to 400,000 barrels per day and the 4th expansion of the West Texas LPG pipeline since October 2017. Our growth program is providing critical natural gas and NGL infrastructure to our customers, including assets to help significantly reduce natural gas flaring in the Williston Basin and provide increased connectivity all the way to the Texas Gulf Coast. Upon completion, our announced projects will expand the backbone of our NGL business and will add processing capacity to further strengthen our position as a leading midstream service provider. As for project updates, we announced that Elk Creek was completed in mid December, Demicks Lake 1 and 2 were completed in October 2019 and January 2020 respectively and the first phase of the MB-four fractionator was completed in late December. Kevin will provide more color on the projects that are slated for completion here in the Q1.
Our last earnings call in late October, I made a comment that 2021 is setting up to be another year of double digits growth. With many of our projects being completed this year and into next year, we are confident in our 2020 earnings outlook of adjusted EBITDA increasing approximately 20% compared to our 2020 guidance midpoint. With that, I will turn the call over to Walt.
Thank you, Terry. ONEOK's 2019 net income totaled $1,280,000,000 or $3.07 per share, an 11% increase compared with 2018. In 2019, adjusted EBITDA totaled $2,580,000,000 a 5% increase year over year. Natural gas liquids and natural gas volume growth, higher average fee rates and increased transportation capacity contracted all contributed to a strong 2019 performance. The Natural Gas Gathering and Processing and Natural Gas Pipeline segments ended the year with adjusted EBITDA increases of 11% 12% respectively compared with 2018, exceeding the high end of the 2019 guidance range in both segments.
The Natural Gas Liquids segment adjusted EBITDA increased 2% compared with 2018, about 4% below the low end of the 2019 guidance range due primarily to narrower than expected NGL price differentials. Distributable cash flow for 2019 was $2,020,000,000 up 11% compared to 2018 with a healthy full year dividend coverage of 1.38 times. We also generated nearly $560,000,000 of distributable cash flow in excess of dividends paid in 2019. Our annual dividends paid during 2019 were $3.53 per share, a 9% increase compared with 2018 in line with our previously stated guidance. And in January, the Board of Directors declared a dividend of $0.93 5 or $3.74 per share on an annualized basis, also an increase of 9% compared with the Q1 of 2018.
Our December 31 net debt to EBITDA on an annualized run rate basis was 4.8x. We continue to expect to be at 4x debt to EBITDA run rate in late 2020 or early 2021 with deleveraging continuing thereafter as volumes ramp and additional projects come online. We ended the year having no borrowings outstanding on our 2.5 $1,000,000,000 credit facility and $220,000,000 of commercial paper outstanding. As Terry mentioned, with yesterday's earnings announcement, we provided detailed 2020 financial and volume guidance and a 2021 outlook. Our 2020 guidance includes increases in our earnings per share and adjusted EBITDA midpoints of 16% 25%, respectively, compared with 2019.
We expect double digit year over year earnings growth in our natural gas liquids and our natural gas gathering and processing segments of 15% and 11%, respectively. Our Natural Gas Pipeline segment had a strong 2019 and we expect another solid year of performance for the segment in 2020. Key drivers to achieving our 2020 financial guidance expectations include volume growth expected from the Elk Creek pipeline and the Demicks processing plants and contributions from the Arbuckle II pipeline, the MB-four fractionator and the 2nd West Texas LPG expansion, all projects that we expect to be completed here in the Q1. Our 2020 growth capital guidance range of $2,250,000,000 to $2,730,000,000 is a significant decrease compared with our peak CapEx spend in 2019 and incorporates the projects we announced yesterday. As a reminder, what we call routine growth capital such as well connections and plant connections is included in this number.
Our 2021 outlook of an approximate 20% increase in adjusted EBITDA compared with the 2020 guidance midpoint is driven by continued volume growth on Elk Creek resulting from the increased volumes from plants connected in 2020. The Bakken NGL pipeline expansion and the Bear Creek expansion volume growth in the Permian Basin and the Gulf Coast from the completion of the MB5 fractionator and the 3rd and 4th expansions of West Texas LPG pipeline will also contribute to the 2021 increase. With these project completions this year early next year, total capital expenditures are expected to decrease significantly in 2021 relative to 2020. I'll now turn the call over to Kevin for a closer look at each of our operating segments.
Thank you, Walt. 2019 was an impressive year with strong producer activity across our operations, driving NGL raw feed throughput and natural gas processed volume increases of 7% compared with 2018. We expect volumes to continue to increase in 2020 and our earnings to remain more than 90% fee based. As Terry said, we completed our Demicks Lake 2 plant in the Williston Basin in January and expect to complete 3 additional NGL projects by the end of the Q1. Overall, our projects are on time and on budget, positioning us well for continued growth as volumes on these projects ramp up.
Let's start with our Rocky Mountain region, which includes the Williston and Powder River basins. Producer activity remains strong in both the Williston and Powder River basins. North Dakota continues to see natural gas production of more than 3,000,000,000 cubic feet per day and the basin wide rig count remains in the 50 to 55 range with approximately 25 rigs on our dedicated acreage. Rig counts have remained consistent in this $50 to $55 WTI crude oil price environment, which we expect to continue. Natural gas volumes processed in the Rocky Mountain region increased 11% in both the Q4 and full year 2019 compared with the same periods in 2018.
Processed volumes averaged 1,050,000,000 cubic feet per day for 2019, above the midpoint of our volume guidance range. We expect processed volumes from this region to increase more than 25% compared with 2019 due to the completion of the Demicks Lake plants as we significantly reduce gas currently being flared. We connected 5 26 wells in the Rocky Mountain region in 2019. Better than expected well performance and higher gas to oil ratios contributed to volume growth even with producers temporarily delaying well completions until our Demicks Lake plants came online. We expect to connect between 575 and 625 wells in 2020.
Our 200,000,000 cubic feet per day Demicks Lake 1 natural gas processing plant that was placed in service in the 4th quarter is expected to be full by the end of the Q1. We expect our Demicks Lake II plant to ramp to full capacity over the next 12 to 18 months. With the latest reported natural gas clearing data of approximately 500,000,000 cubic feet per day in the basin and approximately $300,000,000 of that on ONEOK's dedicated acreage, we now have the capacity available to capture a significant portion of this flared gas. Our Bear Creek plant remains on schedule to be completed early in the Q1 of 2021, which will provide much needed processing capacity to the highly productive, geographically isolated Dunn County area, where we have substantial acreage dedications. The Demicks Lake expansion will provide an additional 200,000,000 cubic feet per day of processing capacity when it is completed in the Q3 of 2021.
With the completion of these two facilities, ONEOK will have approximately 1,900,000,000 cubic feet per day of processing capacity in the Williston Basin. NGL raw feed throughput volumes in the Rocky Mountain region, which consists of Elk Creek and the Bakken NGL pipeline, increased 9% compared with the Q3 2019 and 23% compared with the full year 2018. We expect our Rocky Mountain NGL volumes to continue to increase as approximately 850,000,000 cubic feet per day of processing capacity We recently reached more than 230 We recently reached more than 230,000 barrels per day of raw feed throughput on Elk Creek and the Bakken NGL pipeline combined and continue to expect to exit the Q1 2020 with more than 240,000 barrels per day. Yesterday, we announced an expansion of the Elk Creek pipeline to its full capacity of 400,000 barrels per day. The expansion is supported by well over 240,000 barrels per day of long term dedicated production from ONEOK and 3rd party plants, excluding any incremental ethane.
Of the
160,000 barrel per day expansion, approximately 60,000 barrels per day of the capacity is expected to be available in early 2021 and the remaining 100,000 barrels per day by the Q3 2021. We also see continue to see growth in the Powder River Basin as production results remain strong, benefiting both our natural gas gathering and processing and natural gas liquids segments. Moving on to the Mid Continent. Natural gas volumes processed increased 3% year over year, above the midpoint of our guidance range, connecting 117 wells to our gathering and processing system. Based on recent discussions with our customers, we expect our natural gas volumes processed in the Mid Continent region to decrease approximately 10% this year compared with 2019 and expect to connect 40 to 60 wells.
Total NGL raw feed throughput in the Mid Continent region for the 4th quarter decreased slightly compared with the 3rd quarter, due primarily to spot volumes in the 3rd quarter that did not carry over to the 4th quarter. Outside of ethane rejection, we expect relatively flat midcontinent volumes on our system in 2020 compared with the Q4 2019. During 2019, we connected 5 new third party processing plants to our natural gas liquids system in the region and 2 previously connected third party plants on our system were expanded. Our Abrucco II pipeline remains on schedule for completion by the end of the Q1 of 2020. Arbuckle II will play an important role in transporting incremental supply from the Williston and Powder River Basins, the Mid Continent and the Permian Basin to the Gulf Coast.
Arbuckle II is the lower end of the NGL backbone and will be our 5th pipeline that can funnel supply from across our entire system to the Gulf Coast markets. Finishing with the Permian Basin and Gulf Coast. NGL raw feed throughput volumes in this region increased 22% year over year, and the average fee rate increased compared with the Q3 2019. We expect average rates to continue to increase as we bring on new volumes with bundled rates from our completed expansion projects. We announced our 4th expansion of the West Texas LPG system, 100,000 barrel per day fully contracted expansion with long term dedicated production from third party processing plants in the region.
We now have announced approximately 260,000 barrels per day of expansions on West Texas LPG to support volume growth in the region. Our system wide NGL fractionation capacity remains highly utilized. Phase 1 of our MB-four fractionator, which was completed in December, has increased our capacity by 75,000 barrels per day. Phase 2 of the project, which will add the remaining 50,000 barrels per day of capacity, remains on schedule for completion by the end of the Q1 of 2020. And our MB-five fractionator remains on track for completion in the Q1 of 2021.
Our
overall NGL segment raw feed throughput volume guidance is expected to increase 15% in 2020, driven by a full year of operations of Elk Creek and the completions of the Arbuckle II pipeline, the MB-four fractionator and the 80,000 barrel per day West Texas LPG pipeline expansion, all expected in the Q1 of 2020. Continued growth from plant connections and expansions completed in 2019 will also contribute to higher volumes in 2020. We expect 6 to 9 new third party plant connections or expansions, including the connection already completed with Demicks Lake 2. Terry, that concludes my remarks.
Thank you, Kevin. 2019 was another successful year for ONEOK, and I'm proud of our employees who continue to focus on safety, reliability and the execution of our growth projects. Operating our integrated network of assets in the manner for which ONEOK has a strong reputation remains our focus and is the foundation for all our successes we've discussed today and will continue to be as we move forward as we transition from this build cycle to a period of significant cash flow generation. Thank you to all our dedicated employees for your hard work and contributions in helping us achieve another year company wide growth in 2019. And 2020 is off to a great start as we are in the middle of many project completions and new asset operations that will position us well in the coming years.
With that, operator, we're now ready for questions.
Thank And our first question comes from Tristan Richardson with SunTrust.
Hey, good morning, guys. Good morning. Pretty much more commentary on the expansions. Could you talk just a quick one on the difference on the CapEx side between Demicks III, it seems like you've got a lot of efficiencies versus the first two,
as well as the
Bear Creek expansion. Just the difference in cost, should we think of that as an opportunity for enhanced return profile for Demicks III versus the others?
Yes, Tristan, this is Kevin. Yes, I mean, that's the way we think about it. The reason for the lower capital is again kind of more expansions when as we've constructed Demicks 1 and Demicks 2, things like power, a lot of the inlet handling for the plant, some of the pipeline infrastructure, We're doing we're expanding existing compressor stations rather than building new compressor stations. So all those things contribute to that capital being lower than the previous projects.
Helpful. And just on the Elk Creek expansion, in terms of the volumes behind that, should we think of that as primarily there to serve Demicks 3 as well as Bear Creek? Or are there could you talk about the quantity of other third party plants that could be behind the latest expansion?
Yes. I mean, that's the way to think about it is we continue to ramp volumes with more than 240,000 barrels a day now contracted on the pipe. We needed to expand it. We also wanted to make sure we had the ability to handle any ethane that needs to come out incrementally. But again, the economics are really based more on just the traditional, the classic C3 plus volume growth that we see.
We still have a lot of opportunities and we're in late stage negotiations with several customers north of the river as we build that lateral that's going to connect over to the Hess plant. So there's still opportunities out there in front of us.
We'll take our next question from Shneur Gershuni with UBS.
Hi, good morning guys. I was just wondering if we can dive into the 2021 plus 20 percent EBITDA guidance a little bit. Just trying to understand what it assumes, I guess, obviously, what part of it is a ramp up from Elk Creek, but how much ethane recovery are you assuming from the Bakken? Is it full ethane recovery? Also, I was wondering if you can talk about the margin uplift.
If you can walk us through what is the delta between 2020 2021 in terms of what's going into your assumptions?
Sure, Shneur. This is Kevin. Clearly, it is a Bakken driven story. I think you start and just kind of go down the list of projects that are coming on either late this year or early, early in 2021. So you've got Bear Creek 2, that expansion, which again, there's going to be some flared gas behind that facility when it's up.
We've got 4 large well capitalized producers that are just dying to go drill down there, but there's just no capacity currently. So there's growth there. We've talked about the north lateral from our on our in our NGL segment that will go connect to the Hess plant that will be completed in Q4 of this year. So we'll have a year of volumes on that. You've got continued just core growth in of our existing plants, the Demicks Lake facilities that will continue to ramp up and we'll have a little opportunity for Demicks III towards the end of the year.
And then you mentioned the ethane opportunity that, yes, we do have what we would consider a modest level of ethane. If you look at the production growth that just from capturing the flared gas and as these other ours and third party plants ramp up, it's just some math that determines we're going to need to pull some ethane out. So we've got around 25,000 to 40000 barrels per day of ethane that we believe will come out in 2021 and that is a result of the BTU heat content issue on Northern Border. Permian Gulf Coast, we've got the 3 expansions that are coming on between now and the middle of 2021 that will provide additional volume growth and we have a full year of the MB5 fractionator in 2021 as well. So you pull all that together, we see both our NGL and G and P segments volume growth continuing to increase and it's going to be well into double digits.
That was very helpful. Really do appreciate that. Maybe as a follow-up question, kind of a 2 parter, if you don't mind. With your CapEx activity, I mean, despite the fact that you've announced these new projects, it is definitely lower than where it's been. And you sort of see slowing producer activity.
I was just wondering what are the opportunities for ONEOK to pivot and optimize on the cost side? Are there costs that you can now strip out now that you can sort of see where your business is running? And also are you able to potentially pursue an asset light strategy when I sort of think about your Elk Creek expansion as well as the West Texas LPG brings a lot more volumes into on the NGL side, which would suggest you would need a frac, but given there's excess frac capacity out there, are there ways for you to sublease other fracs and sort of take advantage of that and pursue an asset light strategy? Just sort of wondering if you can sort of talk about other ways to optimize for further earnings growth beyond 2021?
Yes, it's Kevin again. I think we I believe we have been doing that already in a lot of ways. The previous question about Demicks Lake, that's a great example of a brownfield expansion to where we put it there. And again, we're able to significantly reduce the capital for that capacity. As we think about the fracs, I think we've done that as well.
We have clear line of sight to MB-four being full and significant volumes, if not MB-five being full. But if you remember, the other thing we've done is we've announced like 65,000 barrels a day of, again, expansions at our existing facilities that our team was able to go find for much less capital than building another greenfield frac. And so that has delayed any discussion of an MB6, because our team has been able to find those types of debottlenecking and expansion opportunities. So I like to think our team, we have already we've done that and we that's part of our DNA is we think about how we provide the capacity for our customers. And I don't you made a comment at the very beginning, I would like to just give you my point of view and I don't think we have seen slowing producer activity on our acreage, especially when you talk about the Bakken and the Permian.
Yes, the Mid Continent's pulled back, but we haven't seen any slowed activity in the Bakken or Permian at all.
No, fair enough. I do appreciate the color. Maybe one final question. When do you guys expect or when is your next projection for Ganoak to be a cash taxpayer?
Well, Shneur,
as we've said in the past, when we did the acquisition of the partnership back in 'seventeen, we said we wouldn't be a taxpayer through 2021. We've built between $6,000,000,000 $7,000,000,000 worth of assets with bonus depreciation that we've been able to take advantage on top of that. So we have a good runway here before we will become a taxpayer at all. And then at some point, there'll be a limitation on the utilization of the NOL that was put in place with the last Tax Act. But that would at that point going forward, we would have kind of a 4% to 5% marginal rate somewhere out there in the future.
So we don't see a full taxpaying situation well into the future.
Our next question comes from Christine Cho with Barclays.
Hi, everyone. If I could actually start as a follow-up to the ethane extraction in the Bakken. Should we think of this the ethane extraction that you'll potentially do next year as a temporary dynamic until another pipeline comes on and more Canadian gas can come back to blend with the Bakken gas? Or do you think it will be more of a permanent thing?
Christine, this is Kevin. I think we believe it's going to be a long term thing because if you think about new capacity, any new capacity that's going to come online in the Bakken, it is highly currently is going on, on Northern Border. So, like currently is going on, on Northern Border. So, at least the various projects that we've looked at and been involved with, all of those contemplate a BTU spec.
Okay.
That's what I thought. Just wanted to confirm. And then could you give us a breakdown of where the 6 to 9 third party plant connections are regionally?
Christina, this is Sheridan. Those are going to come in as you'd expect in the Bakken and in the Permian and the 6 is pretty much half and half on each one of them. The growth is going to be some plants that will be coming on at the end of 2020 that could either be in 2020 or 2020
1. Okay. And is the growth primarily Bakken or that's also split between Permian
and It's split.
Okay. And then, can you give us an idea of the cadence and the magnitude of the 3rd party frac costs and rail costs roll off in 2020?
Yes, Christy, we won't see any third party rail cost in 2020 or we haven't predicted any since Elk Creek coming online that has been reduced to 0. But the 3rd party frac will be about the same level it was in 2019 as in 2020 as we get ready for MB5 coming online.
Okay. So those costs are not going to go down this year?
3rd party frac costs won't go down in 2020 from 2019.
Okay, great.
Thank you.
And that's baked into our guidance.
We'll take our next question from Jeremy Tonet with JPMorgan.
Hi, good morning. Just wanted to follow-up, I guess, with your conversations with producers in this environment and given how the commodity price has declined a bit here. Just wondering if you could roll it with us, I guess, expectations for drilling activity. Has that been moderating? Or it seems like it all be firmly baked into your guidance at this point, but anything that you can share with us, I guess, on this topic?
This is Kevin. Yes, we're looking at the commodity environment very similar to our producers. Really, we focus on the crude side. We don't we have reduced our direct commodity exposure so significantly that really it's not that big a deal just as when you get into the NGL prices or the nat gas prices. Most of the producers, our customers are telling us they're planning for a $50 crude environment.
And therefore, that's the activity levels we're kind of assuming of the activity levels that you're seeing in the Bakken and the Permian in the current landscape. So that's the way we're thinking about it over the next couple of years, which we believe is very consistent with the way our customers are thinking about it.
That's helpful. Thanks. And just a couple of cleanup questions I guess with the NGL Logistics side. How do you guys sit on the storage side at this point? Do you think that there's more expansions that are needed there to kind of do what you want to do in Bellevue?
And then in the 20 21 guide, I guess the Conway Bellevue spread, any thoughts you could share with us on how that lands at that point?
Well, I would just say on the storage side that right now we are in the process of constructing 2 new storage wells, both are 1,500,000 barrels and we're also putting in a 3,500,000 barrel brine pond. So right now we do see the need to expand our storage facilities and we are doing it and those will come up part one
of those will come to
those wells will come up this year, the next one will come up next year. So we think that puts us in a very good position on our storage side to be able to handle our growth. And then on the Conway to Belvieu spread as we said with the Arbuckle II pipeline coming online for sure the spreads are going to be very narrow and in our 2020 2021 guidance we are predicting an historically low spread or very narrow spread between Conway and Bellevue.
Got you. Great. And just to confirm, I think you had said $50 to $55 is kind of the price deck that you guys are employing when you think about this guidance going forward?
Yes. From a crude activity perspective, that's the level we're thinking about it.
We'll take our next question from Michael Lapides with Goldman Sachs.
Hey, guys. A couple of questions. First of all, when thinking about flaring and flaring limits, just curious, do you think there's potential for North Dakota to tighten the flaring limits further? And if so, what would have to happen for that? And second, do you have any read through or read into the recent report put out by the Railroad Commission in Texas jump
in. I jump in. I mean, the flaring the gas capture targets or the flaring targets in North Dakota do step down at the end of this year. They step down from 88% capture or step up from 88% capture to 91% capture. So clearly, that is one step up.
In conversations we have with the state and our producers, obviously, we want to drive that number well below that. We have experienced when you look back at 2015 2016 when we when midstream kind of got caught up, we drove flaring to lower levels in that. So I think that's the goal. As it relates to Texas, yes, we saw the report. I think any just from a regulatory perspective, I do think we'll see continued discussions around flaring as to where that goes from a regulation standpoint.
I don't know that I'd have a point of view at this point. But Chuck, I mean
Yes, I guess what I would add in North Dakota, Michael, is that the kind of the interested stakeholders up there between the state, the producers and the processors have been meeting fairly regularly over the last, let's call it, 2 quarters. Looking at the current flaring rules, flaring exemptions, how the interested parties can work more closely together to mitigate flaring. And there's some discussion of potentially changing some of these rules going forward, but there's nothing concrete as of yet.
Got it. And then Michael,
let me just make one quick comment too, then I'll follow-up. So with the Texas report, I think it's just indicative of the fact that the heat on producers is really going to be stepping up in terms of flaring. And I think for midstream companies, I think that actually creates obviously opportunity. And in particular, we're going to see, I think, a step up in terms of infrastructure getting built or maximized in order to reduce the flaring. And obviously, when we maximize that throughput from that rich gas, we're going to create more NGLs coming out of the basin sooner rather than later.
So I think that's going to I think that's really going to step up. And I think step 1 was the fact that the Texas Railroad Commission acknowledged what was happening. I think they did some really kind of took a unique look at it in terms of intensity of flaring. I think it really showed a picture that it's going to have to be addressed and the regulator is going to have to address it and the midstream is going to be a big part of that solution of course.
Got it. And then one follow-up just on the guidance. The growth CapEx range is a pretty wide range to give in February of the prompt year. Just curious what anchors the low and the high end of that range?
Michael, it's Kevin. Similar to last year when we had an even wider range, it really comes down to timing. You look at the number of projects we have, we're expecting to come online in the Q1. If we're always looking for ways to pull those if those get pulled back and we start realizing the EBITDA sooner, we'd love to do that, but that may pull a little capital that would move you towards the high end. Conversely, if some of these things, if they go the other direction for whatever reason, it could slow down some of the capital spend in '20 that would move you towards the low end.
So it's really just going to come down to timing.
Our next question comes from Colton Bain with Tudor, Pickering, Holt and Company.
So just to follow-up there on the 2020 capital program, can you clarify how much of that is attributable to the $900,000,000 of backlog additions you have slated for 2021?
Yes, about half of the $900,000,000 we announced is 2020 spend.
Got it. That's helpful. And then with Dimock's Lake 3 now slated for 2021, how are you evaluating absolute residue gas take away? Understanding the comments earlier on heat content, but just in terms of absolute dry gas capacity?
Yes, Colton, this is Chuck. What I could say, I mean, obviously, you're going to need residue gas takeaway. We said before sometime in 'twenty two, perhaps 2023. We're currently in late stage negotiations, negotiating a proceeding agreement with a project coming out of the Bakken. We're under an NDA, so we can't go into that any further.
However, we believe sometime in the next month or 2, you should see some information come out publicly.
Understood. And just a final one for me. On the Elk Creek expansion, is that effectively an all or nothing type process or could you horsepower more ratably as it's needed?
Well, Colton, this is Sheridan. As you said, we said in our remarks that we will get some of it early in 2021 and then the later will come in later 2021. So we are ramping up that capacity as we go through the year and if some reason we could slow down if we needed to. We don't see that happening, but we could we will get some as we go through the 2021. So we are ramping up the capacity.
Understood. Appreciate that.
We'll take our next question from Derek Walker with Bank of America.
Hi, good morning guys. Just a couple of ones for me. Maybe a follow-up on the growth CapEx. I think you've talked to sort of the routine CapEx before, it's around well connects and plant connects. How much of the 2020 growth CapEx is considered routine CapEx?
And then similarly kind of going into 2021, you mentioned the step down in growth CapEx again. So we kind of think of a similar run rate for routine CapEx in 'twenty one or should we think of that directionally up or down?
Over the years, we've said that our routine growth CapEx is somewhere between $250,000,000 to $400,000,000 or so. It varies depending on where the plants are that we have to connect or the wells we're connecting, but it always is in that range. It's included in our guidance for 2020. From a growth CapEx standpoint, it wouldn't be significantly different in 2021, But we expect a meaningful step down in CapEx from 2020 to 2021, is in the range of $1,000,000,000 less in 2021 than we will have
in 2020.
Got it. And then maybe I'll just ask a quick one on the dividend policy. You hit 9% last year. Should we think about 9% again in 2021? Or should we think about kind of a normalized sort of rate relative to either the dividend or risk risk in S and P or perhaps some of the larger more history names in the space?
Well, we've guided pretty regularly since 2017 that through 2021, we would pay in that 9% to 11% range. We've been at 9% throughout, and we don't see anything at this point that will change that view through 2021 and we're not going to give a view past that.
Got it. Thank you.
We'll take our next question from Chris Sighinolfi with Jefferies.
Hey, good morning, everybody. Thanks for the
Hey, Chris.
All the colors. Kevin, I just wanted to go back maybe to something Michael was asking, but ask it slightly differently. And that's on flared volumes on the Rockies footprint today, I believe in your January update, you'd noted for November, it was about 300,000,000 cubic feet a day, net to your acreage. I'm just curious, I guess, as a starting measure, where that is today? And then if we look at the growth in gathered volumes you've modeled or anticipate for 2020 versus what you did in Q4, how much of that is like basin growth versus how much of that is flared capture?
And I ask just to better understand the walk, but also where that sort of as a setup for where that leaves us on 2021?
Yes. Chris, clearly, the I mean, the latest number, we have another month. It was basically flat maybe a little bit. Our flaring on ours was a little bit less, but we're still in that 300 range. Okay.
As we look going forward, we sorry, there's an echo here that's kind of messing with me. But as we look going forward, the volumes of the flared gas capture will drive, especially as we move through the early parts of the year, we'll drive that flaring down significantly. But again, with the DUCs, with the rig count that's still running as we kind of get towards the back half of 'twenty and go into 'twenty one, you still got just straight production growth at the rig counts we're currently seeing and the productivity of the wells being drilled. And then the other again, I mentioned earlier, another key volume dynamic for the growth is Bear Creek 2, that there's going to be some flared gas behind that system because it's geographically isolated. And we fully anticipate as we get capacity down there, you're going to see some rig movements into that region to drill that area.
Okay. Thanks for that. That's very helpful. I guess as a related point, Kevin, for those watching, I guess, inlet volumes at great plants, are we likely to see volume sort of wheel to your newer facilities for processing before the aggregate footprint more broadly fills up? Are there efficiencies in having, I guess, an expanded plant portfolio where you're not where certain plants maybe are not isolated but connected?
Or I guess a longer dated question, when you start to recover ethane on the plan for 'twenty one, are we likely to see that sort of disproportionately affecting certain plants and not others? I'm just asking because I know some people track individual facilities.
Yes. We look at our system in total, again, with the exception of Bear Creek, that area. The rest of our system, we look at it in total. And absolutely, we'll see some gas move from, say, Garden Creek to Demicks Lake and from Lonesome Creek to Garden Creek as we optimize our system. We'll push the gas to the plant in the facility that we believe we can get do it for the least cost and take advantage of our assets.
So you will see some of that go on, but it really doesn't impact ethane recovery. Again, it will be a similar argument or discussion if we start recovering or need to recover a little ethane that will ultimately come down to what the how the tariff is worded from a northern border standpoint, if there's a change there, and how we want to operate our facilities.
Okay, great. And if I could ask one final question totally different. Could you just remind me some of the drivers of outperformance for the natgas segment, Pipe segment in 2019? I noted it as a modest EBITDA reduction, I think, you're guiding for 2020. It looks like you remain very well contracted on the capacity there.
So I'm just I guess wondering if it's a rate or a cost issue or if it's something entirely different?
Chris, this is Chuck. So our 2019 outperformance is really driven by the capturing or the interruptible volumes that we flow. There was great demand particularly in Texas and Oklahoma on our interruptible capacities, but within the Permian Basin there being less takeaway capacity alternatives. And certainly we had a real strong Q3 with very, very good cooling and relative generation load for the heat generating cooling. So that was 2019, the uplift.
As you compare it year over year, what we did in looking at 2020 guidance, we typically will normalize our spring and summer electric generation loads. So as you look at our mid point in 2020, we do have some upside in there should there be a repeat of a good strong summer. So our interruptible volumes can help us to the upside. And I might add that recently Permian Highway has indicated that they will be delayed until Q1 of 2021. So that potentially presents another opportunity for our Texas intrastates to capture some more interruptible transport services.
We'll take
our next question from Michael Blum with Wells Fargo.
Hey, thanks. Good morning, everyone.
Hi, Mike.
Question on the 100,000 barrels a day West Texas LPG expansion. Is that are those new plants that are sort of fueling those commitments or are you taking market share from others?
Michael, this is Sheridan. We're doing both. We're getting plants, new plants that are being connected and we are getting volume off of existing plants that are going to other pipelines.
Okay. And then just turning to the 2021 guidance, how much of the growth coming out of the Rocky Mountain region is contingent on Powder River Basin development versus just continued growth in the Bakken? Thanks.
Michael, both segments, it would be a very modest level of increase. It's not a driver. The driver is the Bakken and the Permian.
But Michael, don't let that be an indication of how we feel about the powder, okay? We think the powder has got a lot of unrealized potential. It could be it could and it just needs a little bit of price help. And we're certainly well positioned to be able to exploit that if in fact the powder does get a little bit of price help.
Great. Thank you.
Thank you.
We'll take our next question from Alex Kania with Wolfe Research.
Thanks. I guess just a follow-up question with respect to the West Texas LPG. With the expansion more or less set, how do you think about the timetable with respect to your options related to conversion or repurposing of that the legacy pipe?
Alex, this is Sheridan. With this latest expansion that we announced, we still have a little bit more expansion to do before we can free up one of the pipes go into an alternative service. We did contemplate making a full expansion of the pipeline to open up the legacy pipe into a different service, but we want to have better clarity and better line of sight into additional volume that we predict will be coming on later before we would go ahead and do the full loop, complete the full loop of the West Texas pipeline freeing up the legacy system for a different service.
Got it. Great. Thanks.
And our next question comes from Sunil Sibal with Seaport Global Securities.
Yes, hi, good morning guys and thanks for all the clarity. I got on the call late, just a couple of clarifications and then if you might have touched it. On the leverage side, I think you mentioned that you expect to get to close to 4x leverage sometime in 2020. Is that correct? And if so, any if you can talk anything about funding assumptions that go into that?
Well, what we said in the prepared remarks was that the expectation that we've said before remains the same that we expect to be at 4 times debt to EBITDA on a run rate basis either in the Q4 of 2020 or in early 2021. So that doesn't change and then we expect to continue to delever further as we go beyond that period in 2021 as these projects come on CapEx goes down and cash flows increase. So nothing's changed.
Okay, got it. And then one kind of broader question. I think in the past, you've talked about corporate M and A and the industry environment not being that conducive to that. I was wondering if it's seeing anything different in the industry environment right now?
No, no difference. Still tough environment from an M and A perspective. We're going to stay focused on this organic growth strategy. If we do take advantage of some M and A opportunity, it will more be in the area of the strategic bolt on an asset type acquisition. So our thinking really hasn't changed.
Okay, got it. Thanks.
You bet.
Our next question comes from Harry Mateer with Barclays.
Hi, good morning. So first just a follow-up on the last question. But you guys previously have talked about a 3.5 times aspirational leverage target. And just want to confirm if that's still the case? And have you given any consideration to making that less of an aspirational target, more of an actual target, potentially with some firmer time guidelines, just given how shaky the macro backdrop feels?
Well, if you just do the projections out based on the guidance that we've given you, you'll see that we go towards and through that 3.5 times pretty quickly. What we said is that we thought aspirationally on a going forward basis that we would be around that 3.5% as we saw continued growth going forward. If we don't see additional growth from where we are today, we will be well below 3.5%.
Got it. Okay. And then financing needs this year, if you could just talk about what your plans might be. Your next bond maturity is until 2022, but you do have a 2021 term loan that's prepayable and you guys will outspend cash flow this year again after all the CapEx and dividends. So just curious how you're thinking about possible debt capital needs especially given that 10 years almost at 1.3% right now?
Well, we'll obviously build some short term debt as we finish up this construction program. And you're right, we do have the term loan out there coming due in 2021. So we'll keep our eye on the market and when we think it's appropriate, we may access the debt market. Obviously, we have no equity financing whatsoever in our thought.
Got it. Okay. And then last one for me, just putting different parts together in terms of your EBITDA growth for 2021 and then then the indication you gave about $1,000,000,000 of less CapEx in 2021 versus 2020. It seems like things are aligning for you to be at least free cash flow neutral after growth CapEx and the dividend. So and there are a number of other of your large cap midstream companies that are trying to get there next year as well.
So is that something like true free cash flow generation that you're thinking of targeting as a matter of policy? Or is it really at this point still just dependent on what other projects you might find?
Well, we're not going to give forward guidance out there. Again, if you do the math on what we've had out there, it will be a reality that that's where we'll be going forward and we'll see what the future brings. But we're in a position where on a going forward basis, the company is going to generate a very significant amount of cash well above dividends.
And our next question comes from Deneo Giovanni with BMO Capital Markets.
Thank you and good morning everyone. A quick question for me. Did you guys outline what price assumptions you have for the gathering processing business for NGLs and natural gas and crude?
Yes. Bunnell,
this is Kevin. Yes, we're like we mentioned, we're looking at the crude environment in that fifty-fifty 5 type environment. Again, we're not that the direct commodity exposure we have is very limited. But we're thinking about nat gas prices and NGL prices not out of the not significantly different than like we look at the strip over the next year or so.
Okay. So your guidance is premise on this basically strip budget for the entirety of the year?
Yes. When you look at our guidance, that's the way we're thinking about those prices.
That's it for me. Thank you.
We'll take our final question from Craig Shere with Tuohy Brothers.
Hi. Congratulations on the new project announcements.
Thanks. Thanks, Craig.
I was on the call a little late. So if you already addressed, we can skip it. But any comments on the export opportunities? And Walt, as you kind of have answered 2 or 3 questions about leverage, is there a downside limit where it just doesn't make sense to let that ratio fall any further if you don't have sufficient growth CapEx and M and A available a point where you have to think about new dividend or share buyback policy?
Well, as it relates to the second part of your question, obviously, as our debt gets paid down to the levels that I was just discussing, it opens up a lot of alternatives for us, whether it be share buybacks or dividends or whatever. But I think the key is that it will be we'll have the flexibility to do what we think is appropriate at that time.
And as
for the
dollar Are you just willing to go under
3 times? I'm sorry? Are you
just willing to go under 3 times?
Craig, we'll cross that bridge when we get there and see what the market and the environment is. But we're not there today. And so we're not going to speculate as to what the market is going to be at that point going forward.
Craig, this is Kevin. On the dock, similar as we have been communicating, it's still part of the business we would love to have. It's not something that we think we have to have, but we have a team working it very hard. Again, we're very confident that our barrels will continue to clear. We're not directly we don't have the price exposure to determine what the relative value or what that real value of the prices are on the Gulf Coast, but we'll keep working that opportunity when we get the markets when I say the markets on the customers that we would be selling to, have a lot of conversations around the globe with them.
At the same time, having conversations with people in the Gulf Coast about where a dock and partnership opportunities there. So we'll keep working those and when we get it all lined up, that's when we might make an announcement.
Craig, I just let me just make one follow-up comment to Walt's comment. As the company has historically always managed the balance sheet in a very prudent way with an emphasis toward being investment grade. I mean, that's if you want to look for some hard line somewhere, that will be a hard line for us. And so, as we think longer term, the company is always going to do what makes sense and is prudent. Okay.
And we've shown a long history of doing that. So that's what you can hang your head on. Appreciate that, Terry. There's my speech.
Okay. Just as my last follow-up, I was just wondering, I don't know if Kevin wants to come back, but if LPGs, ethane or anything else was looking like the strongest horse in the race in terms of your ideal opportunities?
In regards to export facility, Craig? Okay. Yes, it would be LPGs is where the significant focus is right now. We're not ignoring the ethane opportunities that may come our way, but I think LPGs are the ones driving the majority of the conversations at this point.
Great. Thank you very much.
Thanks, Craig.
Ladies and gentlemen, this concludes today's question and answer
Our quiet period for the Q1 starts when we close our books in early April and extends until we release earnings in late April. We'll provide details for that conference call at a later date. Again, thank you all for joining us and the IR team will be available throughout the day for your questions. Have a good rest of your day. Thank you.
Ladies and gentlemen, this concludes today's teleconference. Thank you for your participation and you may now disconnect your phone lines.