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Good day, and welcome to the Fourth 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 Fourth Quarter and 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 and '34. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings.
Our first speaker this morning is Terry Spencer, President and Chief Executive Officer. Terry?
Thanks, Andrew. Good morning, and thank you all for joining us today. As always, we appreciate your continued 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 and 2021. Yesterday, we announced fourth 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 III plant in the Williston Basin, the full expansion of the Elk Creek pipeline to 400,000 barrels per day and the fourth 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 I and II were completed in October 2019 and January 2020, respectively, and the first phase of the MB-4 fractionator was completed in late December. Kevin will provide more color on the projects that are slated for completion here in the first quarter. 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 [Later changed by the Company to 2021] 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 $1.28 billion or $3.07 per share, an 11% increase compared with 2018. In 2019, adjusted EBITDA totaled $2.58 billion, 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% and 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 $2.02 billion, up 11% compared to 2018, with a healthy full year dividend coverage of 1.38x. We also generated nearly $560 million 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 $0.935 or $3.74 per share on an annualized basis, also an increase of 9% compared with the first quarter 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 billion credit facility and $220 million 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% and 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 Lake processing plants, and contributions from the Arbuckle II pipeline, the MB-4 fractionator and the second West Texas LPG expansion, all projects that we expect to be completed here in the first quarter. Our 2020 growth capital guidance range of $2.25 billion to $2.73 billion 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 extension and the Bear Creek expansion. Volume growth in the Permian Basin and the Gulf Coast from the completion of the MB-5 fractionator and the third and fourth expansions of West Texas LPG pipeline will also contribute to the 2021 increase.
With these project completions this year and 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 II plant in the Williston Basin in January and expect to complete 3 additional NGL projects by the end of the first quarter. 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 billion 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 fourth quarter and full year 2019 compared with the same periods in 2018. Processed volumes averaged 1.05 billion 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 526 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 million cubic feet per day Demicks Lake I natural gas processing plant that was placed in service in the fourth quarter is expected to be full by the end of the first quarter. 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 flaring data of approximately 500 million cubic feet per day in the basin and approximately 300 million 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 first quarter 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 million cubic feet per day of processing capacity when it is completed in the third quarter of 2021. With the completion of these 2 facilities, ONEOK will have approximately 1.9 billion 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 third quarter 2019 and 23% compared with the full year 2018. We expect our Rocky Mountain NGL volumes to continue to increase as approximately 850 million cubic feet per day of processing capacity from ONEOK and third-party plants has come online since the third quarter 2019. 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 first quarter of 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 third-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 third quarter of 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 fourth quarter decreased slightly compared with the third quarter, due primarily to spot volumes in the third quarter that did not carry over to the fourth quarter. Outside of ethane rejection, we expect relatively flat Mid-Continent volumes on our system in 2020 compared with the fourth quarter 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 Arbuckle II pipeline remains on schedule for completion by the end of the first quarter 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 fifth 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 third quarter 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 fourth 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-4 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 first quarter of 2020. And our MB-5 fractionator remains on track for completion in the first quarter 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-4 fractionator and 80,000 barrel per day West Texas LPG pipeline expansion, all expected in the first quarter 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 II. 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 of 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.
[Operator Instructions]. And our first question comes from Tristan Richardson with SunTrust.
Appreciate all the commentary on the expansions. Could you talk -- just a quick one. The difference on the CapEx side between Demicks III. It seems like you've got a lot of efficiencies versus the first 2 as well as the Bear Creek expansion. Just the difference in costs, should we think of that as an opportunity for enhanced return profile for Demicks III versus the others?
Yes. Tristan, this is Kevin. Yes, that's -- 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 I and Demicks II, 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 then -- 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 III 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. As we continue to ramp volumes with more than 240,000 barrels a day now of 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.
[Operator Instructions]. We'll take our next question from Shneur Gershuni with UBS.
I was just wondering if we can dive into the 2021 plus 20% EBITDA guidance a little bit. Just trying to understand what it assumes, I guess, with -- obviously, it's -- what part of it is a ramp-up of 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 kind of the margin uplift? If you can sort of like walk us through what is the delta between '20 and '21 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 '21. So you've got Bear Creek II, 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 then 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 40,000 barrels per day of ethane that we believe will come out in '21 and that is a result of the BTU heat content issue on Northern border.
Permian and Gulf Coast, we've got the 3 expansions that are coming on between now and the middle of '21 that will provide additional volume growth, and we have a full year of the MB-5 fractionator in '21 as well. So you pull all that together, we see, both our NGL and G&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 two 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 their excess frac capacity out there, are there ways for you to sublease others -- other fracs and sort of take advantage of that in pursuing 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. 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-4 being full and significant volumes, if not MB-5 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 MB-6 because our team has been able to find those types of debottlenecking and expansion opportunities.
So I'd like to thank our team. We've done that. And we -- that's part of our DNA as we think about how we provide the capacity for our customers. And I know 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 has 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 -- when is your next projection for ONEOK to be a cash taxpayer?
Shneur, as we've said in the past, when we did the acquisition of the partnership back in '17, we said we wouldn't be a taxpayer through 2021. We've built between $6 billion and $7 billion 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 will 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 tax paying situation well into the future.
Our next question comes from Christine Cho with Barclays.
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 likely it's going to have a BTU spec on it also because it's not going to have other gas to blend down with like currently is going 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?
Christine, 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 2021.
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 third-party frac costs and rail cost roll off in 2020?
Yes. Christine, we won't see any third-party rail costs in 2020 or we haven't predicted any since Elk Creek coming online, that has been reduced to 0. But the third-party frac will be about the same level it was in 2019 as in 2020 as we get ready for MB-5 coming online.
Okay. So those costs are not going to go down this year?
Third-party frac costs won't go down in 2020 from 2019. And that's baked into our guidance.
We'll take our next question from Jeremy Tonet with JPMorgan.
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 relate with us, I guess, expectations for drilling activity. Has that been moderating? Or it seems like it'd 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 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. 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 Belvieu? And then in the 2021 guide, I guess, the Conway-Belvieu spread, any thoughts you could share with us on how that lands at that point?
Well, I'd just say on the storage side that right now, we are in the process of constructing two new storage wells, both are 1.5 million barrels. And we're also putting in a 3.5 million 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 -- one of those will come -- one of 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 and 2021 guidance, we are predicting a historically low spread or very narrow spread between Conway and Belvieu.
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.
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 regarding flaring there?
Michael, it's Kevin. I'll start and then let Chuck 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 experience. When you look back at '15 and '16, when we -- when midstream kind of got caught up, we drove flaring to lower levels than 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, anything?
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 to -- 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 it's really going to step up. And I think the 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 regulators are going to have to address it and midstream's 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 here. 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 first quarter. If we're always looking for ways to pull those back, 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 Bean with Tudor, Pickering, Holt & Company.
So just to follow-up there on the 2020 capital program. Can you clarify how much of that is attributable to the $900 million of backlog additions you slated for 2021?
Yes. About half of the $900 million we announced is 2020 spend.
Got it. That's helpful. And then with Demicks Lake III announced slated for '21, how are you evaluating absolute residue gas takeaway, 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've said before some time in '22, perhaps 2023. We're currently in late-stage negotiations, negotiating a proceeding agreement with the project coming out of the Bakken. We're under an NDA, so we can't go into that any further. However, we believe some time in the next month or two, you should see some information come out publicly.
Understood. And just a final one from me. On the Elk Creek expansion, is that effectively an all or nothing type process? Or could you add 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 that 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 it 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.
We'll take our next question from Derek Walker with Bank of America.
Just a couple of ones for me. Maybe I'll follow-up on the growth CapEx. I think you've talked to sort of the routine CapEx before around well connects and plant connects. How much of the 2020 growth CapEx is considered routine CapEx? And then similarly, kind of going into '21, you mentioned a step down in growth CapEx again. Should we kind of think of a similar run rate for routine CapEx in '21? Or should we think of that directionally up or down?
Yes. Over the years, we've said that our growth -- our routine growth CapEx is somewhere between $250 million to $400 million 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 in the range of $1 billion 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 '21? Or should we think about kind of a normalized sort of rate relative to either the dividend [indiscernible] or perhaps some of the larger midstream 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 pass that.
We'll take our next question from Chris Sighinolfi with Jefferies.
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 Rocky's footprint today, I believe, in your January update, you'd noted, for November, it was about 300 million 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 the fourth quarter, how much of that is like phasing growth versus how much of that is flared capture? And I ask just to better understand the walk, but also where is that -- sort of as a set up to where that leaves us in '21?
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. 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 '20 and going to '21, 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 that another key volume dynamic for the growth is Bear creek II, 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 up.
Okay. That's very helpful. I guess, as a related point, Kevin, for those watching, I guess, inlet volumes at this creek plants, are we likely to see volumes 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 as staying on the plan for '21, 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 and 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 is a change there and how we want to operate our facilities.
Okay. Great. And if I could ask one final question, totally different. Can you just remind me some of the drivers of outperformance for the nat gas segment -- pipe segment in '19? I noted a modest EBITDA reduction that I think you're guiding for '20. 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 was really driven by the capturing -- or the -- excuse me, the interruptible volumes that we flow. There was great demand particularly in Texas and Oklahoma on our interruptible capacities. But within the Permian Basin, they're being less takeaway capacity alternatives. And certainly, we had a real strong Q3 with very, very good cooling and relative generational 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 midpoint 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.
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 the existing plants that are going to other pipelines.
Okay. And then just turning to the '21 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?
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, it -- the Powder does get a little bit of price help.
We'll take our next question from Alex Kania with Wolfe Research.
I guess, just a follow-up question with respect to 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 the legacy pipe?
Alex, this is Sheridan. We -- 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 to 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 with -- 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.
And our next question comes from Sunil Sibal with Seaport Global Securities.
I got on the call late, just a couple of clarifications. I know you might have touched it. On the leverage side, I think you mentioned that you expect to get to close to 4x leverage some time 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 4x debt-to-EBITDA on a run rate basis either in the fourth quarter 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&A and the industry environment not being that conducive to that. I was wondering if you're seeing anything different in the industry environment right now?
No. No difference. Still a tough environment from an M&A perspective. We're going to stay focused on this organic growth strategy. If we do take advantage of some M&A opportunity, it'll more be in the area of the strategic bolt-on asset type acquisition. So our thinking really hasn't changed.
Our next question comes from Harry Mateer with Barclays.
Sorry, first, just a follow-up on the last question. But you guys previously have talked about a 3.5x 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 and 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 3.5x pretty quickly. What we said is that we thought aspirationally, on a going-forward basis, that we would be around that 3.5x as we saw continued growth going forward. If we don't see additional growth from where we are today, we will be well below 3.5x.
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 dividend. So just curious how you're thinking about possible debt capital needs, especially given that 10 years almost at 1.3% right now?
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 thoughts.
Got it. Okay. And then last one for me, just putting different parts together in terms of your EBITDA growth for '21 and then the indication you gave about $1 billion of less CapEx in '21 versus '20. 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 Danilo Juvane with BMO Capital Markets.
A quick question for me. Did you guys outline what price assumptions you have for the gathering and processing business for NGLs and natural gas included?
Yes. Danilo, this is Kevin. Yes, we're -- like we mentioned, we're looking at the crude environment in that $50, $55 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.
I guess, so your guidance is premised 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.
We'll take our final question from Craig Shere with Tuohy Brothers.
Congratulations on the new project announcements. Apologies, 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&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 docks...
Like, are you willing to go under 3x?
I'm sorry.
Are you just willing to go under 3x?
Craig, we'll cross that bridge when we get there and see what the market 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.
And 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 that -- 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, we have a lot of conversations around the globe with them, at the same time having conversations with people in the Gulf Coast about what are the 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'll just [indiscernible]. Craig, let me just make one follow-up comment to Walt's comment, 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 hat on. That 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 LPG's, 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?
Yes.
Okay. Yes. It would be -- LPGs is where the significant focus is right now. And 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.
Ladies and gentlemen, this concludes today's question-and-answer session. I will now turn it back to Andrew Ziola for closing remarks.
Our quiet period for the first quarter 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.