歐尼克 (OKE) 2019 Q3 法說會逐字稿

Good day, and welcome to the Third 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, Travis, and welcome, everyone, to ONEOK's Third Quarter Earnings Conference Call. This call is being webcast live, and a replay will be made available. After our prepared remarks, we'll be available to take your questions.

A reminder that statements made during this call that might include ONEOK's expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision of the Securities Acts of 1933 and 1934. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings.

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

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

Joining me on today's call is Walt Hulse, Chief Financial Officer, Executive Vice President, Strategic Planning and Corporate Affairs; and Kevin Burdick, Chief 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.

Yesterday, we announced third quarter earnings results and updated our 2019 financial guidance expectations. The first 9 months have set us up well for another year of company-wide earnings growth in 2019 and have laid the foundation for a continued growth next year. We also reiterated our outlook for greater than 20% earnings growth in 2020.

We've provided updated timing on several of our capital growth projects, including our Demicks Lake I natural gas processing plant in North Dakota, which was completed earlier this month and our Demicks Lake II plant, which we expect to complete in January 2020. The northern section of our Elk Creek NGL pipeline is expected to begin line fill activities in November, and will provide meaningful volume and earnings growth as we exit the year.

Between now and the end of the first quarter of 2020, we expect to fully complete 5 growth projects that will add more than 700,000 barrels per day of NGL transportation capacity, 125,000 barrels per day of fractionation capacity and an additional 400 million cubic feet of natural gas processing capacity, including Demicks Lake plants. This critical natural gas and NGL infrastructure, including assets to help significantly reduce natural gas flaring in the Williston Basin will provide immediate earnings and volume uplift in 2020 and stable fee-based growth for years to come.

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

Thank you, Terry.

ONEOK's third quarter 2019 net income totaled $309 million or $0.74 per share. And third quarter adjusted EBITDA totaled $650 million. Year-to-date, net income and adjusted EBITDA increased 11% and 5%, respectively, compared with the same period last year.

Distributable cash flow through the first 9 months of the year was $1.5 billion, up 13% compared with 2018 with a healthy year-to-date dividend coverage of 1.42x. We have also generated nearly $450 million of distributable cash flow in excess of dividends paid through the first 9 months of this year.

During the third quarter, we paid a dividend of $0.89 per share and last week, we announced the dividend increase to $0.915 or $3.66 per share on an annualized basis. The dividend is payable on November 14 to shareholders of record on November 4. This latest increase results in a 9% increase in 2019 dividends paid compared with 2018, in line with our previously stated guidance.

In August, we completed a $2 billion senior note offering, providing increased liquidity and balance sheet flexibility. In addition to funding capital expenditures, proceeds from the offering also were used to proactively manage upcoming debt maturities, including repaying $250 million of our $1.5 billion term loan due 2021 and redeeming $300 million of senior notes that were due March in 2020.

On September 30, net debt-to-EBITDA on an annualized run rate basis was 4.5x. We continue to expect to be at 4x debt-to-EBITDA run rate in the fourth quarter of 2020 or the first quarter of 2021 with deleveraging continuing in the quarters to follow that.

We ended the third quarter with the full $2.5 billion available on our credit facility and more than $670 million of cash. With yesterday's earnings announcement, we narrowed our 2019 financial guidance ranges. The midpoint of our net income guidance increased to $1.28 billion, and our adjusted EBITDA midpoint remained unchanged at $2.6 billion.

The natural gas gathering and processing and natural gas pipeline segments are trending towards the high end of the previously announced financial guidance ranges, each with the ability to exceed the high end of their range. Outperformance in these segments reflects stronger-than-expected volume growth in the Williston Basin and STACK and SCOOP areas in the gathering and processing segment, and higher firm transportation capacity contracted on expansion projects in the natural gas pipeline segment.

Our natural gas liquids segment is trending towards the low end of its previously announced financial guidance range, primarily due to lower optimization and marketing earnings from narrowed -- narrower-than-expected pricing spreads between Conway and Mont Belvieu and due to the impact of increased ethane rejection on our system.

Despite a vastly different commodity price environment and spreads that were 1/3 as large as a year ago, our base business grew compared with a strong quarter last year. As we mentioned in prior quarters, we expect earnings from this -- for this segment to be heavily weighted towards the back half of the year.

The Williston Basin continues to be a primary contributor to ONEOK's growth, underscored by the fact that volume growth in the region is at higher margins relative to our other regions.

We've also updated our 2019 growth capital guidance range to $3.5 billion to $3.7 billion, consistent with my remarks last quarter, reflecting the accelerated timing on several of our capital growth projects. The early in service on these projects also accelerates their associated EBITDA contributions and further underscores our confidence in our earnings growth and deleveraging next year.

As Terry already mentioned, we continue to expect adjusted EBITDA growth of greater than 20% in 2020 compared with our 2019 guidance midpoint. And the emphasis remains on greater than 20%.

I'll now turn the call over to Kevin for a closer look at each of our business segments.

Thank you, Walt.

We continue to see strong producer activity across our operations with NGL and natural gas volumes through the first 9 months of the year already surpassing full year 2018 volumes. Overall, our projects remain on time and on budget, positioning us well for continued growth as volumes on these projects ramp-up over the next several months.

Let's take a closer look at our operating regions, starting with the Rockies. Producer activity remained strong in both the Williston and Powder River Basins. North Dakota saw a record natural gas production again in August of more than 3 billion cubic feet per day, and the basin-wide rig count remains at approximately 60.

As Terry mentioned, our 200 million cubic feet per day Demicks Lake I natural gas processing plant is now in service, and we expect it to ramp quickly to full capacity once the entire Elk Creek pipeline is in service. With natural gas flaring at more than 550 million cubic feet per day in the basin and more than 300 million of that on ONEOK's dedicated acreage, the volume growth is immediately available to capture. We also expect to complete our 200 million cubic feet per day Demicks Lake II plant in January of 2020, which will help further alleviate flaring in the basin.

Third quarter natural gas volumes processed in the Rocky Mountain region were nearly 1.1 billion cubic feet per day, an increase of 7% year-over-year and 2% compared with the second quarter 2019. This puts us on track in 2019 for the higher end of our volume guidance range. We now expect to connect between 525 and 550 wells in the Rocky Mountain region this year compared with our prior well-connect guidance of 620 wells. Better-than-expected well performance and higher gas-to-oil ratios have contributed to the growth even with producers temporarily delaying completions to avoid additional flaring due to lack of processing capacity and NGL takeaway. This has translated into a rising drilled but uncompleted well count, which has reached approximately 1,000 basin wide with more than 400 on our acreage. We expect producers to begin working this inventory off once Elk Creek and additional processing capacity come online, providing further support for our expected growth in 2020.

NGL raw feed throughput volumes in the Rocky Mountain region increased approximately 7% compared with the second quarter 2019, due primarily to the southern section of our Elk Creek pipeline coming online in July.

In addition to our Demicks Lake I plant, more than 300 million cubic feet per day of third-party processing capacity was recently completed with an additional 750 million cubic feet per day of capacity expected to be completed in the Rockies region by the first quarter of 2020. At full capacity, these plants are capable of producing a total of approximately 160,000 barrels per day of propane-plus when full.

We are already seeing additional NGL volumes from the region in October with throughput averaging more than 190,000 barrels per day, which includes the already full 140,000 barrel per day Bakken NGL Pipeline. Line fill activities on the northern section of Elk Creek are expected to begin in November, and volumes will continue to ramp-up through the remainder of the year, including approximately 25,000 barrels per day currently being railed that will transition to the pipeline and reduce our rail cost. We expect to exit 2019 with more than 215,000 barrels a day of raw feed throughput for the region and reach more than 240,000 barrels per day in the first quarter of 2020. As a reminder, each 25,000 barrels per day of incremental volume results in nearly $100 million of adjusted EBITDA.

We also continue to see increased producer activity in the Powder River Basin as production results remain strong and some rigs have relocated there from other basins, benefiting both our natural gas gathering and processing and natural gas liquids segments.

Moving on to the Mid-Continent. Natural gas volumes processed increased 8% year-over-year and are tracking above the midpoint of our guidance expectations. Total NGL raw feed throughput in the Mid-Continent region decreased compared with last quarter due to higher Mid-Continent ethane rejection, specifically during July and August. We had approximately 50,000 fewer barrels per day of ethane on our system in the third quarter of 2019 than the second quarter of 2019 but saw an increase of approximately 30,000 barrels per day of propane-plus volumes in the region, which demonstrates strong core supply growth. We've since seen ethane on our system increase in the fourth quarter but continue to expect fluctuation through the remainder of the year as we near the start-up of new petrochemical facilities on the Gulf Coast.

Through the first 9 months of the year, we've connected 98 wells to our natural gas gathering and processing system and connected 5 new third-party processing plants to our natural gas liquid system in the Mid-Continent. Two previously connected third-party plants on our system have also been expanded in the region. NGL volumes from these new connections and expansions, in addition to growing Rockies volumes, will drive the volume growth on our Arbuckle II pipeline, which remains on schedule for completion in the first quarter of 2020.

We continue to stay in contact with our customers in the region about their plans and forecasts, and this information has been incorporated into our growth outlook for 2020.

Now taking a closer look at our Permian Basin and Gulf Coast operations. NGL raw feed throughput volumes in this region increased 26% year-over-year, and the average fee rate increased by approximately $0.005 compared with the second quarter 2019. This was driven primarily by a ramp in volumes on completed West Texas LPG expansion projects and the replacement of lower-rate legacy volumes on the system with market-based transportation and fractionation rates. We expect average rates to continue to increase as our 80,000 barrel per day expansion and 40,000 barrel per day expansion are completed in first quarter of 2020 and the first quarter of 2021, respectively.

System-wide, NGL fractionation capacity remains highly utilized. Phase 1 of our MB-4 fractionator, which will provide approximately 75,000 barrels per day of capacity is expected to be completed by the end of the year. Phase 2 of the project, which will add the remaining 50,000 barrels per day of capacity, remains on schedule for completion in the first quarter of 2020. MB-5 remains on track for completion in the first quarter of 2020.

Terry, that concludes my remarks.

Thank you, Kevin.

Our operating performance, system-wide volume strength and execution of our capital growth program with a very strong balance sheet has clearly exceeded many expectations. But while the operational and earnings growth is important, the way in which we operate, conduct ourselves in business and construct our projects is equally important. And it is the importance that we place on safe, sustainable and responsible operations that is the foundation for all of the successes we've discussed today.

You can find more detailed information related to our "environmental, social and governance" focused priorities and programs in our most recent corporate sustainability report, which can be found on our website. The report is our 11th annual ESG report. And with each version of this report, we've prioritized increasing disclosures, content and relevance for ONEOK's many stakeholders. I encourage you to review the report on our website. We continue to focus on improvements in these areas and welcome your feedback to help us do so because our goal is to build and grow a business that is profitable, safe and environmentally responsible for the long term.

Thank you to all our dedicated employees for your hard work and contributions this quarter. We're only a couple of months away from closing out another year of company-wide growth, and we're about to enter an exciting year of new asset operations and additional project completions.

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

(Operator Instructions) First question comes from Jeremy Tonet, JPMorgan.

Just want to start off with the project ramps. You have a lot of moving pieces here, a lot of projects coming online over the next couple of quarters. And you talked on it in your remarks. But just with Demicks Lake I and II, how should we think about those plants ramping up, especially because you need Elk Creek online to, kind of, perform the way you want to perform there? Just -- how should we expect EBITDA to ramp-up over the next few quarters with all these different projects coming online?

Well, Jeremy, this is Kevin, and then I'll let others jump in. But clearly, Elk Creek is kind of the key project that we need to get done. The basin is short NGL takeaway capacity right now. But as Elk Creek comes in service, then all the processing plants up there, not just Demicks Lake I, but you've got some third-party processing plants that are up now, and you've got another one that's going to come online in the fourth quarter, all those plants will be able to ramp. And clearly, there's substantial flaring behind not just our system but other companies' systems as well. So you would expect it's going to ramp very quickly to -- from the flared gas inventory.

Then as you move through 2020, early 2020, and the flares get put out, you still see the strength in rigs we're seeing up there. And you've also got growth coming out of the Powder as well. So you'll see an immediate step-up as we put out the flares. And then you'll continue to see a ramp, given the rig counts and the activity levels we're seeing.

That's very helpful. And just turning to CapEx, you guys have a very deep portfolio of projects, and it seems like it's kind of peaking right about now. Just wondering what -- how you guys think about the balance of capital -- with great opportunities versus capital discipline that the market seems to be focused on, how do you see capital trending next year? Any color or thoughts you could provide there?

Jeremy, this is Walt. We've got several projects that we've already announced that include Demicks Lake II, MB-5, [Arbuckle II] (corrected by company after the call) and West Texas expansion. All of those will be completed throughout the course of 2020. So you can kind of do the math on what we've already got ticked off. So we'll see a meaningful step down in our CapEx next year from what we have in 2019.

Going forward, we think the vast majority of everything that we see on the horizon has been announced. There'll be other growth opportunities that will come. But remember, we've built the backbone of the system here with these 2 pipes, so we have significant operating leverage going forward. So if we had another processing plant or something along those lines, order of magnitude is significantly less as we go forward. And then also, I would point out that anything that we would announce in the coming quarters would really get spent over a couple of years. So our 2020 CapEx at this point is something that you can get a pretty good look at just based on what we've announced today.

Our next question comes from Shneur Gershuni, UBS.

Wondering if we can sort of talk about a couple of things here. Just -- you sort of mentioned in your prepared remarks about the reduction in expectation for Bakken well connects for this year. But it was interesting, your comments seem to indicate that it's a function of the infrastructure delays, which in theory would imply a higher inventory for next year. But at the same time, you also noted that the liquid component is higher so your volume expectations are unchanged. So when I think about next year, does it not mean that you have a potential for an even higher inventory of connection? And with the higher cuts that you're saying is coming from the liquid side, that you would think that 2020 could be even better than what you have originally visioned for 2020? Or am I not thinking about that correctly?

This is Kevin. I mean I think that conceptually, you're on the right path. The -- we were able to -- through fewer -- producers were -- I mean, clearly, they were buttoned-up against some flaring constraints, right? With -- because the basin with short processing capacity and takeaway -- NGL takeaway was full. So rather than going ahead and completing those wells, knowing they're going to flare, they backed off. And that's been going on for several months. So yes, that DUC increase was the result of that. And yes, that gives us some tailwinds as we move into 2020.

And then on the other side of that, there -- they just -- producers continue to deliver strong results, which even though we connected fewer wells than we had anticipated, we were still able to get more towards the higher end of our volume guidance.

Yes. Would you...

Yes. Kevin, it's fair to say that producers have consistently exceeded our expectations, particularly in the Williston. I think, there we benefited from their own capital discipline and certainly finding ways to enhance the productivity of their wells. The gas-to-oil ratios have been a big deal for us up there, which in turn has increased the amount of liquids that would be available to our plants. So I think just all in all, the backdrop is the producers have -- really have done a super job, not only delivering on what we expected them to deliver, but exceeding those expectations.

All right. Great. And then just 2 quick follow-ups. One, just a clarification. You talked about more ethane recovery in 4Q '19. Is that a function of the fact that you've -- that there's a challenge to take takeaway gas out of the basin right now and you just need to make more room on the gas line, so it makes more sense to recover the ethane? Is that kind of the reason? Or is there something different?

Yes. This is Sheridan Swords. I think you're right. You really need to look at the gas issue, especially in the Permian and in the Mid-Continent. And when the Permian gas goes really low, you see a lot more ethane want to come out of the Permian Basin versus the Mid-Continent. We saw that in the third quarter, but now the gas prices, during this first part of the fourth quarter, have moved up in the Permian a little bit. And gas prices in Mid-Continent moved down, which allows more ethane to come out of the Mid-Continent. So you really need to look at the gas price, because the T&F out of the Mid-Continent, the T&F out of the Permian are fairly close together. So it's not on that side of it.

Okay. Great. And one final question. In your conversation with Jeremy about CapEx and we talked about it being materially lower in 2020 versus 2019, so there should be some sort of a free cash flow conversion. And I would expect there'd be an improvement in leverage. Like, when is the right time for us to start discussing a return of capital options for the free cash flow, where you look at options like buybacks? Do you change the dividend of -- I'm just kind of curious, kind of, what your thoughts are once the free cash flow starts to materialize next year?

Sure. We've said that we would get to 4x debt-to-EBITDA by Q4 of 2020 or Q1 of 2021. We expect to continue to delever after that, and we'll proceed down through -- into that 3.5 range, which is kind of aspirationally where we'd like to be.

So we still have some time. We're going to -- that's going to take through 2021, maybe into 2022. We're going to continue that delevering as our primary focus. And then going forward, we always are on the hunt for good growth opportunities. And to the extent that the commercial team finds those growth opportunities, we're going to pursue those. But keeping that leverage in that -- on a going-forward

basis, in and around that 3.5x.

The only thing I would add to Walt's comments are that the priority continues to be fund those -- these attractive growth projects, and we continue to have a runway of growth in front of us, albeit we don't have any of those great, big infrastructure projects or backbone projects like Walt mentioned earlier. But the priority will continue to be around these great-return organic projects. And certainly, we think about it as -- if and as we have cash available, certainly, retire debt. And then share backs could come into the equation, but I don't see it, but it's certainly something that we think about. If we get to a point where we're running out of growth projects, and we're forced to look at other ways to invest our capital, certainly, share buybacks are something that we would consider.

Our next question comes from Christine Cho, Barclays.

So if I'm to back out the Rockies volumes that are feeding into the Arbuckle II contracted capacity, I still estimate that over 100,000 barrels per day is supposed to come from Mid-Continent. And I know the outlook for 2020 and the at least more than 20% growth over 2019 is driven primarily by Bakken, but how should we risk the need for Mid-Con volumes to show up to hit numbers? Do you need it to be flat at a minimum? Or can it sustain a decline, and we can still hit those numbers?

I mean -- Christine, this is Kevin. Just looking kind of holistically at the Mid-Con, clearly, there's been some pullback recently by producers. We've factored all that in. We're probably thinking of the Mid-Continent in a flat to slightly declining type of environment as we factor in that to our 2020 growth outlook. So we don't need significant or really any growth coming out of the STACK and SCOOP to meet the growth outlook we've provided for 2020.

Okay. That's helpful. And then moving over to CapEx. You guys are very transparent in providing the CapEx for each of the individual projects. But how should we think about the range of annual spending you guys do on ancillary CapEx that isn't included in the project CapEx you've disclosed or maintenance CapEx? So like well connects, I don't know, maybe adding a compression -- a compressor or a pump somewhere here?

The -- just looking at kind of what we would consider, kind of, that routine growth, routine CapEx that we're going to see on a year in, year out basis that's probably in the $400 million, $500 million range. You throw some processing plants, like Walt alluded to earlier, on top of that, it raises it up a little bit. But that's kind of the range just for that normal blocking and tackling type growth that we'd see.

Kevin, the only thing that I -- Christine, hang on a sec. The only thing I would add to that is well connects makes up a bulk of that routine growth, right?

Absolutely. Just connecting wells.

Yes. And then probably plant connections and then other miscellaneous gathering infrastructure both on the gatherings, processing side as well as liquids side.

Our next question comes from Tristan Richardson, SunTrust.

Appreciate the commentary on direction of 2020 capital deployment, but just thinking about the flexibility you have for some of your longer-dated projects, the 2021 time frame, the MB-5, Arbuckle expansion, et cetera. Talking about just your ability to flex the timing of those, either based on volume trajectory or producer plans, et cetera?

As we -- I guess, as we think about the big one there with the MB-5, with the volumes we have coming and have line of sight to for MB-4, you're going to fill it up extremely quickly. So any growth at all, MB-5 is going to continue on. So I mean, could you do something if something went south in a hurry? Potentially so. But again, we don't see that, again, just with the line of sight we've got to volumes that are going to hit us in the next few months here.

Yes. Obviously, from the well connect and that sort of routine, if we saw a significant downturn in producer activity, we have some flexibility on our -- but we don't see it as it relates to MB-5, and Arbuckle II will be done in the first quarter of 2020.

And then just one smaller follow-up. Just -- can you talk about the performance of the joint ventures and why you saw the cash distributions from joint ventures expected to be much higher this year than you previously thought? Is that a onetime event? Or is there just general outperformance on northern border, OPPLs old direction...

No. We -- Yes, we had a pretty robust discussion about this on our Q2 call. We had a onetime kind of catch-up $50 million distribution on the northern border and expect it to go back to its normal course in the quarters going forward that's in line with where it's been. So that was the only one. Other than that, the joint ventures are all performing very well.

Our next question comes from Michael Blum, Wells Fargo.

Can you just give us an update on where the -- where things stand in terms of a potential expansion of northern border? And then kind of related to that, what's the timing for when you would need to see a new gas pipeline capacity out of the Bakken before you would need to start effectively -- I would call it, force recovering ethane because of BTU limits?

Michael, this is Chuck. As far as northern border expansion or any other residue takeaway out of the basin, we're actively working with parties on these residue projects. Frankly, we're under nondisclosure agreements, but suffice it to say that there will be expansion opportunities out of there. And we realize that this takeaway is needed to take care of our customers, so we will definitely be part of that solution.

As far as your second question on BTU changes or we're -- could you please repeat your second question for me?

Yes. It's just a more question about timing, like when do you have to have new gas pipeline capacity to avoid basically reaching the limit and having to extract ethane?

Okay. Those are really kind of 2 questions. One is on the BTU limits on northern border. Northern border is currently in discussion with customers and point operators about a potential BTU change in their tariff. And that would be forthcoming, we would believe in 2020, and anything beyond that, we'll defer to our TransCanada operator on the asset.

However, as far as more ethane recovery being necessary, it really comes down to how quickly the Bakken continues to grow, and we have line of sight in 2020. It's going to grow quickly with these gas plants coming on. So as we continue to displace Canadian volumes, that BTU will rise. And obviously, the way to mitigate that is to recover more ethane. So I think 2020 will see more ethane recovered. I can't give you a number on that. Longer term, we will need some residue takeaway relief, and I think that's more in the '22 time frame.

Next question comes from Spiro Dounis, Crédit Suisse.

First question on the Mid-Con. Just wondered if you could talk a little bit more about your ability to connect more third-party plants. It looks like you guys connected a few more this quarter, maybe seems to be a bit of a step-up. So just curious if there's an enhanced push to do more of that, maybe as a way to kind of bridge you through next year and alleviate some of that pressure we're expecting to come from some of the rig count reduction?

Yes, this is Sheridan. We don't really have that many more plants in the Mid-Continent to connect. We've kind of connect all the ones that are out there. We saw a big push in 2019. A lot of those plants -- we've seen some increase in production from those plants, and we expect to kind of stay at that level through next year, the level we're at today on a C3-plus basis. So -- and I think right now, there's plenty of capacity out there with what's to process the gas that's there.

Got it. And second question, just with respect to the narrower bands for 2019 guidance, I'd imagine you have considerable visibility at this point. So just curious what could maybe flex full year EBITDA results from here towards the high or low end of that range?

It's primarily going to be really just the specific timing of these projects. I mean we look at the biggest levers we have, that will -- that would be number one. We've talked about spreads that can fluctuate up and down, that could be a little bit of a driver, but we've got pretty good line of sight at this point to where we're going to end the year. Just -- Walt jumped in. Weather is always a -- it could be a factor. If you get early or no weather that could be an impact as well.

Our next question comes from Jean Salisbury, Bernstein.

As you referenced a lot of Bakken processing capacity is starting up, in theory, enough to eliminate flaring. Can you share what your estimates for flaring levels, once there's enough processing in Elk Creek, are? Like, down to the 12% state target, something much lower or possibly something a little higher?

Jean, and the way I'd answer that is if you go back to few years or actually just probably 12, 18 months ago, the basin was down into -- for several months, down into single digits. So easily, I think, with this processing capacity once, everybody -- once we get Elk Creek up and once everybody gets kind of everything debottlenecked, I think you're going to see flaring get back down below the state -- the state targets or above the state targets for capture. I think that's going to -- that will happen.

Okay. That's helpful. And then can you just remind us how much flexibility you have to move volumes between the existing Bakken NGL Pipeline and Elk Creek, once it starts up?

This is Sheridan. We'll operate those systems kind of in tandem to make sure that we optimize variable costs, optimize going into OPPL and going on Elk Creek pipeline. So we have a lot of flexibility to move product back and forth between the 2 pipelines to maximize capacity.

Our next question comes from Mike Lapides, Goldman Sachs.

I I won't even get into the upcoming LSU game here. But real quickly -- figured one of you all would like that. Real quick, 2 items. One, I assume there's -- should we think about -- and I know 2021 is a long way off and the world can change 7 times between now and then. But I assume there's still a pretty decent step-up in '21 off of 2020. You've talked about 2020 EBITDA being up 20-plus percent. But there's still another pretty decent-sized step-up coming in 2021. That's the first question.

Second question, you guys have talked about a desire to want to have export capacity. Just given all that's going on in the world, ethane prices down a lot more, China trade war still going on, how are you thinking about that opportunity and where that fits in the landscape of things you're targeting to do over the next year or 2?

So Michael, first of all, I'll take LSU in 14 points. And then and the next question is, yes. As we think about 2021, double-digit growth is certainly in the cards in how this business is continuing to be set up. And we still got, obviously, organic growth projects that will be coming on through '20 and critical projects in 2021. So we're still set up nicely there.

I think as far as the export dock project goes, still a project we're very interested in doing. We continue to work it pretty hard. If the economics make sense, we'll certainly do a project. But if they don't make sense, I think we're in good shape with our business. In terms of clearing barrels, we have arrangements in place that give us some certainty that, of course, over the next handful of years we can clear barrels. So we're not really concerned there. I think the export dock is a great complement to our fee-based activities. So we're going to continue to work it. And when we get to a point where we can announce it, certainly, we'll let you all know.

Next question comes from Elvira Scotto, RBC Capital Markets.

Thanks for all the commentary around the 2020 EBITDA growth, and it sounds like the confidence level in hitting that greater than 20% growth is pretty high, especially given the comments that you made about your view on the Mid-Con. But if I can ask a question another way, what would have to happen for you to walk back that outlook?

Elvira, this is Kevin. I'll start. Again, we -- the thing we have stressed for the last several months, we continue to focus on this is with the flared gas in the Bakken, we've got incredible line of sight to these volumes. A similar situation occurred back in the '16 -- '15 or '16 time frame, where we saw the flared gas, we had projects and we immediately captured it and turned it into EBITDA. So with the flaring that's occurring in the basin, with the DUC count that's out there, with the productivity and the returns that producers are seeing, we've just got a lot of confidence that, that's going to be the substantial driver to that growth in 2020. And that's not even getting into the growth we're seeing out of the Permian, the Powder and other places. So we just have a confidence because we have that line of sight, I mean, we can reach out and touch these volumes.

Kevin, probably the only thing else I'd add to that is, we don't have a whole lot here baked in for ethane recovery...

Or spreads.

Or spreads. So we're at seasonally low spreads, which are typically low this time of the year. Ethane economics are marginal for recovery. If those things turn, there's actually more upside probably to this number than downside.

Great. And just very quickly though, how does commodity or crude oil price factor in to this view? I mean are you looking at anything -- as long as we're above $50? Or do you think -- even you get to somewhere below $50, you're still fine with this outlook?

Well, we go back to when rigs really came back to the Bakken, they really started coming back in and earnest it at around $45 a barrel. From the conversations we have with our customers, most are planning for a $50 environment, more from a cash flow perspective. But the improvements they've seen in the productivity of the wells, again, the returns on the well aren't the challenge, it's solely just living within their cash flow, which has been the consistent theme we've gotten from our customers. So I think easily, if you stay north of $50, probably even if you go down to the $45 range, we're still -- this thing is good to go.

Great. That's perfect. And then just one quick follow-up on the capital allocation discussion. Where does M&A fit in all of this? I mean are you guys -- are you open to looking at various assets? Or are you kind of set on just your organic growth and M&A just has to be super compelling?

You just answered it. We're focused on the organic growth and M&A has to be uber compelling. And most likely, it would be smaller bolt-on types of acquisitions.

Our next question comes from Derek Walker, Bank of America Securities.

Just a quick clarification. I think you said in your formal remarks, but I just want to make sure I heard it right. I think even in the Rockies, the NGL volumes were expected to be 240 in 1Q '20. Is that assuming 140 for Bakken NGL and then 100 on Elk Creek, that assumes no rails, is that correct? For the 25 that rail that you're seeing today that should just transfer over to the pipe? Is that how I'm hearing it?

This is Sheridan. Yes, you are correct. And we're starting to transition to -- away from specifically talking about what's on Elk Creek to what's coming out of both the Rockies region, which is Williston, the Powder River Basin because of the flexibility we have between -- moving between pipes. So that 240 is basically over 100,000 barrels a day increase from where we were when we just had the Bakken pipeline coming in. So that's a new plant that we talked about coming online, rails coming off and then ramp-up on those volumes. And actually, we said we think we'll be above 240 coming out of the first quarter.

Got it. That's helpful. And then maybe I'll just get one in on ESG. I think you guys announced in September that you got added to the Dow Jones Sustainability Index. Can you just talk a little bit about some of your ESG initiatives? And have you had any conversations specifically with investors around that? Are they focused on any particular metrics?

Well, they're always focused on getting more information. And certainly -- probably what we've done, where we've made incredible progress is certainly in the disclosure of our emissions and various environmental impact data that has -- we had a lot of discussion. Obviously, from a governance perspective, I think we've been lauded for the -- for our efficiency from a governance standpoint.

When you really think about our broad thoughts around reducing our impact to the environment, that's certainly an area where I think it's resonated with investors. I think the fact that we've done this now for 11 years in a row and that this -- and this work product continues to improve each and every year, I think, certainly, that has resonated with investors as well. So I -- disclosure, disclosure, disclosure and as we continue to move forward, we'll continue to disclose more information, and certainly around emissions targets, and that type of outlook is certainly something that's top of mind and that we'll hopefully be in a position where we can do and provide those types of disclosures in the not-too-distant future.

Our next question comes from Craig Shere, Tuohy Brothers.

When you highlighted ethane was only further upside as a catalyst over and above the 20% year-over-year 2020 EBITDA growth guidance, but then you all comment that 2021 is primed for another year of double-digit growth. When we're looking out 3 years like that, are we kind of baking in some of that ethane eventually? Or does that kind of remain an untapped opportunity?

No. We're really -- over the course of the next handful of years, not expecting or at least we've not gotten our base forecast internally, much ethane baked into it at least for the next 2 or 3 years.

And what kind of market dynamics do you expect would be necessary to kind of start to realize -- I mean what would be ethane exports? Or what do we really need to start to get more value there?

Well, obviously, we've got more petrochemical facilities coming on domestically. And then you've got additional petrochemical facilities coming on internationally. So I think the continued development of international exports, whether that's at the Gulf Coast or in the northeast, I think, continues to -- or continue to be key drivers and obviously, ethane economics. It's dependent upon nat gas to where nat gas is, and if nat gas -- and we continue to have somewhat of a conservative view on nat gas going forward. I think if you see nat gas remain relatively weak, the likelihood of you recovering significantly more ethane certainly improves.

But as we think ethane economics are so volatile that we really -- we felt it's appropriate not to bake a whole lot in into our internal forecasts.

Sheridan, you got anything else add to that?

One thing I continue to say what's going to drive ethane also is as we talked earlier about the relative gas price in the Mid-Continent versus the Permian to see which one moves ahead of the other one to pull the ethane out for the demand that is there.

Sure. Are you still considering ethane when you're looking at these [work] project opportunities?

Absolutely.

And I presume that if you did that, it would be something, kind of, semi long-term contracted and take out some of that volatile in/out economics, so you'd have somewhat certainty about pulling through the systems.

That's correct. I mean the way we're thinking about it is the contracts that you would enter into with respect to ethane on a sales standpoint would certainly underwrite the DUC, a fee-based type arrangement, if you will, or perhaps a sale with a fee-based component built into it. The ethane -- the macro ethane economics are going to be what they're going to be, broadly speaking. But as we think about the DUC, it's the DUC and as it relates to ethane, fee-based, it's a fee-based business.

The next question comes from Alexis Kania, Wolfe Research.

Just thinking a little bit more about the prospects for ethane recovery in the Bakken, just next year, either for price reasons or, I guess, physical constraint reasons, just with the [spin within] border, how do we really think about those ethane volumes getting handled? Does that -- do you think of that as like incremental to what ends up being contracted on Elk Creek and further south already? Or does it -- could it cover like existing contracted volume levels that you've kind of established right now? Just again, kind of -- it sounds like you suggested it was incremental, but I just wanted to confirm.

Yes. This is Sheridan. When we look at -- and as quoted volumes coming out of the Rockies, we do not consider ethane in any of those lines. It's all C3-plus. So any ethane that we would get due to being forced out because of constraints or the very unlikely that it becomes economical, will be upside to our volume numbers that we've given.

Our final question comes from Sunil Sibal, Seaport Global Securities.

I just wanted to understand a little bit about the balance sheet management. So it seems like you will hit the 4x kind of leverage metrics in early 2021. I was kind of curious, how should we think about that on a more, kind of, a longer-term basis? Do you want to be closer to 4x? Or should we be thinking more like between 3 or 3.5x as a longer-term target?

Well, we expect to continue to delever past the 4x. And aspirationally, we'd like to be around that 3.5. That gives us a lot of borrowing flexibility going forward for these smaller type of CapEx that would come out in the future. But yes, so we use 3.5 as an aspirational target. And that's what you should think about going forward.

Okay. Got it. And then just one clarity on the CapEx side. So obviously, you guys have given a pretty good kind of breakdown of CapEx for various projects. When I baked all that into my numbers, et cetera, seems like you will be in a pretty good spot to get 35% to 40% reduction in CapEx in 2020 versus where you end up in 2019. I was just curious, is that number seems reasonable? Or if I may be off somewhere?

Well, we're not going to guide to our 2020 CapEx. But I think you can just take the projects we put in service and kind of subtract out what we still have to do and build up to a pretty good number. So the base to come up with a -- your expectation is readily available, we'll leave that to you.

At this time, I would like to turn the call back over to Andrew Ziola.

All right. Thank you, Travis. Our quiet period for the fourth quarter starts when we close our books in early January and extends until we release earnings in late February. We'll provide details for that conference call at a later date. Thank you for joining us this morning, and the IR team will be available throughout the day. Have a good week.

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