Good day and welcome to 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.

Thank you, Travis, and welcome 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, 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 nine months have set us up well for another year of companywide earnings growth in 2019 and have laid the foundation for continued growth next year. We also reiterated our outlook for greater than 20% earnings growth in 2020. We 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 five growth projects that will add more than 700,000 barrels per day of NGL transportation capacity, a 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 Williston Basin, will provide immediate earnings and volume up lift in 2020 and stable fee based growth for years to come. With that, I will turn the call over to Walt's 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 nine months of the year was $1.5 billion, up 13% compared with 2018 with a healthy year-to-date dividend coverage of 1.42 times. We have also generated nearly $450 million of distributable cash flow in excess of dividends paid through the first nine months of this year. During the first quarter, we paid the dividend of $0.89 per share and last week we announced the dividend increased to $0.915 or $3.66 per share on an annualized basis. Dividend is payable on November 14th to shareholders of record on November 4th. 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 the funding capital expenditures, proceeds from the offering also were used to proactively manage upcoming debt maturities including repaying $250 million of our $1.5 million term loan to 2021 and redeeming $300 million of senior notes that were due March 2020. On September 30th, net debt to EBITDA on an annualized run rate basis was 4.5 times. We continue to expect to be at four times debt to EBITDA run rate in the fourth quarter of 2020 for the first quarter of 2021 with the 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 remain unchanged at $2.6 billion. The natural gas gathering and processing, and natural gas pipeline segments are trending toward the high-end of the previously announced financial guidance ranges, each with the ability to exceed the high-end of their range. Our performance in these segments reflect stronger-than-expected volume growth in the Williston Basin and STACK and SCOOP areas and gathering in the gathering 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 narrower than expected pricing spread 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 one third as large as the year ago, our base business grew compared with a strong quarter last year. As we mentioned in prior quarters, we expect earnings for this segment to be heavily weighted towards the back half of the year. The Williston Basin continues to be a primary contributor to one-offs 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 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 will 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 nine 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 Williston and Powder River basin. 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 s in service. With natural gas flaring of more than 550 million cubic feet per day in the basin and more than 300 million of that one dedicated anchorage, 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 Mount 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 Mount region this year compared with 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 delay in completion to avoid additional flaring due to lack of processing capacity and NGL takeaway. This has translated into a rising drill but uncompleted well count, which is 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 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 which 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 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 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 volumes 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, benefitting both our natural gas gathering and processing and natural gas liquids segments. Moving onto 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 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 of the new petrochemical facilities on the Gulf coast. Through the first nine months of the year, we've connected 98 wells to our natural gas gathering and processing system and connected five 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 $0.05 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 rates legacy volumes on the system with market-based transportation and fractionation rights. We expect average rates to continue to increase as our 80,000 barrels per day expansion and 40,000 barrels per day expansion are completed in the 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 2021. Terry that concludes my remarks.

Thank you, Kevin. Our operating performance, system-wide volumes strength and execution of our capital growth program with a very strong balance sheet had 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 project is equally important and it is important that we place on sustainable and responsible operations that is the foundation for all of the successes we discussed today. You can find more detailed information related to our environmental, social and government focus 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 prioritize increasing disclosures, content and relevance for one of 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 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 companywide growth and were about to enter an exciting year of new asset operations and additional project completions. With that operator were now ready for questions.

[Operator Instructions] First question comes from Jeremy Tonet, JP Morgan.

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

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 is substantial flaring behind not just our system but other company systems as well. So, you would expect it's going to ramp very quickly 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 you'll continue to see a ramp given the rig counts in the activity levels we're seeing.

That's very helpful, thanks. Just turning to CapEx, you guys have a very deep portfolio 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 [Later changed by the Company] 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 horizon has been announced. There will other growth opportunities that will come, but remember we've built the backbone of the system here with these two pipes. So, we have significant operating leveraging 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 spend over the couple of years. So our 2020 CapEx at this point is something that you can get a pretty good look 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've sort of mentioned in your prepared remarks about the reduction in expectation for Bakken 12 expects for this year, but what's interesting in your commentary indicates that it's the function of the infrastructure delay, 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 what I think about next year, does it now mean that you to have potential for even higher inventory connection? And with the higher cut that you're seeing coming from the liquid side as you would think that 2020 could be even better than what you are originally vision for 2020? Or might not be thinking about that correct?

This is Kevin. I mean yes. I think that conceptually you're on the right path. We were able to --producers were clearly they were button up against unflattering constraints right because the basin with short processing capacity and NGL take away was full. So rather than going ahead and completing those wells knowing they're going flare they backed off and that's been going on for several months. So yes, that 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 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, Kevin, it's fair to say that producers have consistently exceeded our expectations particularly in Williston. I think there we benefited from their own capital discipline and certainly finding ways to enhance the productivity of their well. The gas all ratios have been a big deal for us up there, which in turn has increased in our liquids and be available to our plant. So, I think just all in all, the backdrop is that producers have really done a superb job, not only delivering on what we expect them to deliver, but exceeding those expectations.

And then just two quickly follow-up, one just the clarification you talked about more ethane recovery 4Q 19. Is that a function of the fact that there is a challenge to take away gas out of the basin right now and you just need to make more room on the gas line, so it make more sense to recovery of the ethane. Is that kind of the reason or is there something different?

Yes, this is Sheridan. So, 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, you see a lot more ethane come out of the Permian basin versus the Mid-Continent, we saw that in the third quarter. But now the gas prices during the fourth quarter have moved up in the Permian, a little bit and gas prices in the continent moves down, which allows more ethane to come out of Mid-Continent. So you really need to look at the gas price because the TNF out of the Mid-Continent and the TNF out of the Permian are fairly close together. So, it's not on that side of it.

And one final question. In your conversation with Jeremy about CapEx and you've talked about it's being materially lower in 2020 versus 2019. So, there should be some sort of free cash in fruition. And I would expect there'll be an improvement in leverage, but when is the right time for us to start discussing return of capital options with free cash flow where you look at options like buy backs? Do you change dividend policy? And I’m just kind of curious kind of what your thoughts on when the free cash flow starts to material next year?

We said that we were get to four times 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 to 5 range, which is kind of aspirationally where we like to be. So, we still have some time, we're going to -- that's going to take through 2021, maybe into 2022. So, 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 3.5 times.

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 we have 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.

Hi everyone. 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 be at least more than 20% over 2019 is driven primarily by Bakken. But how should we risk the need 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 have those numbers?

I mean, Christine, this is Kevin. Just looking kind of holistically at the Mid-Con, clearly, there has 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 STAKE and SCOOP to meet the growth outlook we provided for 2020.

And then, moving over to CapEx, you guys are very transparent in providing 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 -- compressor pump somewhere here?

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 and year-out basis, that's probably in the $400 million to $500 million range. You throw some processing plants like Walt alluded to earlier on top of, it raises up a little bit, but that's kind of ranges just for that normal blocking and tackling type growth that we'd see.

Christine, hang on a second. The only thing I would add to that is well connect, makes up the bulk of that routine growth, right.

Absolutely, yes, just connecting wells.

And then probably plant connections and then other miscellaneous gathering infrastructure both on gatherings processing side as well as liquid side.

The next question comes from Tristan Richardson, SunTrust.

Good morning, guys. Appreciate the commentary on direction of 2020 capital deployment, but just thinking about the flexibility you have for some longer dated projects that 2021 timeframe, that MB-5 Arbuckle expansion et cetera. Just talking about just your ability to flex of 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 would be 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 small 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 one-time event or is there just general outperformance on Northern Border or OPPL's old direction there?

Yes, we've pretty robust discussion about this on our Q2 call. We had a one-time, kind of, catch-up $50 million distribution at our 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 the 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 of capacity out of the Bakken before you would need to start effectively, I would call it force recovering ethane, because a 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 non-disclosure agreements. But suffice it to say that there will be expansion opportunities out of there, and we realize that those takeaways needed to take care of our customers. So, we will definitely be part of that solution. As far as your second question on BTUs, BTU changes, could you please repeat your second question for me?

Yes, just one 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 two 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 will 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 kind of real 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, you will see more ethane recovery. 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 timeframe.

Our next question comes from Spiro Dounis, Credit Suisse.

First question on the Mid-Con, just wonder 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 and maybe seems to be a bit of a step-up. So, just curious, if there is 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 is plenty of capacity out there what's to process the gas that's there.

Got it. And second question, just with respect to the narrow bands for 2019 guidance and 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 and we look at the biggest levers we have, that would be number one. We've talked about spreads it 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.

Understood. Thanks, it really helped. I'm sorry.

No just to -- Walt jumped in, weather is always, it could be a factor, if you get earlier or know whether that could be an impact as well.

Our next question comes from Jean Ann Salisbury, Bernstein.

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

Jean Ann, the way I would answer that is, if you go back to few years or actually just with probably 12 to 18 months ago. The basin was down into for several months down into single-digit. 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 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 -- around your connects 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, optimized going into OPPL and going on Elk Creek Pipeline. So we have a lot of flexibility to move product back and forth between the two pipelines to maximize capacity.

Your next question comes from Michael Lapides, Goldman Sachs.

Hey guys, thanks for taking my question. I won't even get into the upcoming LSU game here. But real quickly figured and one you all would like that. Real quick good items; one, I assume there is -- should we think about, and I know 2021 is a long way off in the world can change seven 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, but is there still another pretty decent size step up coming in 2021, that's 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 that do over the next year or two?

So Michael, first of all, I'll take LSU and 14 points. And then the next question is yes, as we think about 2021 double-digit growth is certainly in the cards and 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 gives 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.

The next question comes from Elvira Scotto, RBC Capital Markets.

Hey, good morning everyone, thanks for the commentary around the 2020 EBITDA growth, and it sounds like the confidence level and 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 the question another way, what would have to happen for you to walk back that outlook?

Elvira, this is Kevin. And 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 timeframe 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 dock count that's out there, with the productivity and the returns, the producers are seeing we've just got a lot of confidence if 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, 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 in here baked in for ethane recovery. So with the ore spreads, so we're at seasonally low spreads with -- you're typically low this time of the year. Ethane economics are marginal for recovery, if those things turn, there is actually more upside probably did this number than downside.

Great. And just very quickly though, how does commodity or crude oil price factor into this view. I mean, are you looking at anything as long as we're about $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 start coming back in earnest it at around $45 per 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 be challenged, 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, you're still -- this things good to go.

Great. That's perfect. Thanks on that. 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 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 had a quick clarification, I think you said in your formal remarks, but I just want to make sure I heard it right. I think believe 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 seems no rail, is that correct for the 25, that rail that you're seeing today that should you just transfer over to the pipe that 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 and 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 the new plants that we talked about coming online, rail coming off and then ramp up on to those volumes and actually we said we think will be above 240 coming out of the first quarter.

And then, maybe I'll just get one in on ESG, I mean, 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 any conversation specifically with investors around that, and they focused on any particular metrics?

Well, there are 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 at this -- and this work product continues to improve each and every year. I think certainly that has resonated with investors as well. So disclosure, disclosure, disclosure and as we continue to move forward, we will continue to disclose more information and certainly around emissions targets and that type of outlook will certainly something that's top of mind and that will 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.

Terry 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 of that 2021 is prime for another year of double-digit growth. When we're looking out two years like that. Are we kind of taking it some of the ethane eventually? Or does that kind of remain an opportunity?

Yes. No we're really, over the course of the next handful of years not expecting or at least we've not got in our base forecast internally much ethane baked into it at least for the next two or three years.

And what kind of market dynamics do you expect would be necessary to kind of, it start to realize -- I mean, 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 be key drivers. And obviously ethane economics and dependent upon net gas to -- where net gases and if net gas and we continue to have some sort of a conservative view on that gas going forward. I think if you see net gas remain relatively weak. The likelihood if you're recovering significantly more ethane certainly improves. But as we think ethane economics are so volatile that we've really -- we felt it appropriate not to bake a whole lot in -- into our internal forecasts. Sheridan you've got anything add to that?

Well, that continue to say what's going to drive ethane. Also, 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 export 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 and out of economics. So you'd have somewhat certainty about pulling through the system?

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 the sales standpoint, which certainly underwrite the dock a fee-based type arrangement, if you will, or perhaps the sale with a fee-based component built into it.

Great, thank you.

The macro ethane economics are going to be what they're going to be, broadly speaking. But as we think about the dock, if the dock and as it relates to ethane fee-based, it's a fee-based business.

Our next question comes from Alex Kania, Wolfe Research.

Hey, good morning. 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 respect to Northern Border. How do we really think about those ethane volumes getting handle. Does that -- do you think of that is like incremental to what is it 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 our established right now, just again, kind of, it sounds like you've suggested it was incremental, but I just wanted to confirm?

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

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

Hi, good morning, guys and thanks for all the color on the call. I just wanted to understand a little bit about the balance sheet management. So it seems like you will hit the ForEx, kind of, leverage metrics in early 2021. I was kind of curious how should we think about that on a more kind of longer-term basis. Do you want to be closer to ForEx or should we be thinking more like between 3 or 3.5 excess longer-term target?

Well, we expect to continue to the left to delever past to 4 times and aspirationally we 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. So we use 3.5 is an aspirational target and just 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 bake all that into my numbers etc, it seems like you will be in a pretty good spot to get 35% to 40% reduction in CapEx in 2020 versus where you've end up in 2019. I was just curious, is that number seems reasonable or if I may be off somewhere?

No 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 will come up with your expectation is readily available, we'll leave that to you.

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

All right. Thank you, Charles -- excuse me, 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.