Oneok Inc (OKE) — Q3 2019 Earnings Call Transcript

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 company-wide 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 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 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 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 in 2021 and redeeming $300 million of senior notes that were due in 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 remains 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 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 a 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 toward the back half of the year. The Williston Basin continues to be a primary contributor to one-off 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 is 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 on 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 of 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 delaying 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 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 of 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 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 costs. 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 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've since seen ethane on our system increase in the fourth quarter, but continue to expect fluctuations 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 of 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 an emphasis 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 governance 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 our 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 are now ready for questions.

Just want to start off with the project ramp. You have a lot of moving pieces here, a lot of projects 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 plants 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 can expect it's going to ramp very quickly from the flared gas inventory. Then as you move through 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 once we put out the flares, and you'll continue to see a ramp given the rig counts and the activity levels we're seeing.

That's very helpful, thanks. 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, 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, 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 will be 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 leverage going forward. If we had another processing plant or something along those lines, the order of magnitude is significantly less as we go forward, and then also I would point out that anything we would announce in the coming quarters would really get spent over the 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.

I’m 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 have the potential for even higher inventory connection? And with the higher cut that you're seeing coming from the liquid side, would you think that 2020 could be even better than what you originally envisioned for 2020? Or might I not be thinking about that correctly?

This is Kevin. Yes, I believe you're on the right track. Producers have faced significant constraints due to limited processing capacity and full NGL takeaway in the basin. Instead of completing wells that would only result in flaring, they opted to hold back, a situation that's persisted for several months. Therefore, the increase in production was a consequence of that decision. This also gives us a positive outlook as we head into 2020. Additionally, producers continue to show strong performance, and despite connecting fewer wells than expected, we still managed to reach the upper 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 oil ratios have been a big deal for us up there, which in turn has increased our liquids to 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 quick follow-ups, one just the clarification you talked about more ethane recovery in Q4 '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 might make more sense to recover 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 high, 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 Mid-Continent have moved 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, you've talked about it's being materially lower in 2020 versus 2019. So, there should be some sort of free cash inflow. 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 buybacks? Do you change dividend policy? I’m just kind of curious about your thoughts on when the free cash flow starts to materialize next year?

We said that we would 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; 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 and around that 3.5 times on a going forward basis.

The only thing I would add to Walt's comments is that the priority continues to be fund those 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 buybacks 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.

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 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 STACK 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, like well connects, I don't know, maybe adding a compressor pump somewhere here?

Just looking at 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, it raises up a little bit, but that's kind of the range 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 connects make up the bulk of that routine, right.

Absolutely, yes, just connecting wells.

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

Good morning, guys. Appreciate the commentary on the 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, etc. Just talking about just your ability to flex the timing of those either based on volume trajectory or producer plans, etc.?

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. Clearly, if there were a notable decline in producer activity, we have some flexibility regarding our plans, but we don’t anticipate that happening. MB-5 and Arbuckle II are expected to be completed in the first quarter of 2020.

And then just one small follow-up, 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.

Can you provide an update on the status of the potential expansion of Northern Border? Additionally, what is the timeline for when you will need to see new gas pipeline capacity out of the Bakken before it becomes necessary to start recovering ethane due to 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 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 in 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. I think that's more in the '22 timeframe.

First question on the Mid-Con, just wondering 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 connected 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 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.

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

No, just to say that weather can always be a factor, especially if there's an early snowfall or if it could have an impact as well.

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?

If we look back a year or a year and a half ago, flaring levels were down to single digits for several months. With the addition of our processing capacity and once Elk Creek is operational, I believe we will successfully reduce flaring to below the state targets for capture. This outcome is very much expected.

Okay, that's helpful. Can you clarify if you need to transfer volumes between the existing Bakken NGL pipeline and Elk Creek once it begins operations?

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.

Thank you for taking my question. I won't discuss the upcoming LSU game, but I wanted to ask a couple of quick things. First, I'm curious if we should expect a significant increase in 2021 compared to 2020. You've mentioned that the EBITDA for 2020 will be up over 20%, but will there be another notable increase in 2021? Secondly, you've expressed a desire for export capacity. With everything happening in the world, such as the drop in ethane prices and the ongoing China trade war, how are you approaching that opportunity and where does it fit into your future plans 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, it's 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.

Hey, good morning everyone, thanks for 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 the question another way, what would have to happen for you to walk back that outlook?

Elvira, this is Kevin. I'll start again with what we've emphasized over the past several months. Our focus remains on the flared gas in the Bakken, where we have a clear view of the volumes. A similar situation occurred around 2015 or 2016 when we capitalized on flared gas and quickly transformed it into EBITDA. With the current flaring in the basin, the existing dock count, and the productivity and returns producers are experiencing, we are very confident that this will be a major driver of growth in 2020. This perspective doesn't even consider the growth we are witnessing in the Permian, the Powder, and other areas. Our confidence stems from having a clear visibility on these volumes.

Kevin, I would just add that we don't have much included here for ethane recovery. Given that the ore spreads are typically low this time of year, the economics of ethane recovery are only marginal. If the situation improves, there could be more potential for upside in this number than downside.

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 be super compelling and most likely, it would be smaller bolt-on types of acquisitions.

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 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 talking about the upcoming production from the Rockies region, specifically Williston and the Powder River Basin, due to the flexibility we have in moving between pipelines. The 240 represents an increase of over 100,000 barrels a day compared to when we were only using the Bakken pipeline. This increase is a result of the new plants coming online, reduced reliance on rail, and an expected ramp-up in those volumes. We believe we will exceed 240 in 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 had any conversation specifically with investors around that, and they focused on any particular metrics?

We are consistently focused on gathering more information, and we've made remarkable progress in disclosing our emissions and various environmental impact data. We've engaged in extensive discussions from a governance perspective, and our efficiency in governance has received positive recognition. Our commitment to reducing our environmental impact has resonated well with investors. The fact that we've maintained this commitment for 11 consecutive years, with continuous improvements each year, has also appealed to investors. We emphasize the importance of disclosure, and as we advance, we plan to continue providing more information regarding emissions targets and related outlooks, which will be a priority for us in the near future.

Terry, when you highlighted ethane as 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 prime for another year of double-digit growth. When we're looking out two years like that. Are we kind of taking in 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.

What market dynamics do you think are necessary to start realizing more value? Would it be ethane exports, or what do we really need?

We have more petrochemical facilities coming online domestically and internationally. The ongoing development of international exports, whether at the Gulf Coast or in the Northeast, will be key drivers. Ethane economics depend on the price of natural gas, and if natural gas remains weak, the chances of recovering significantly more ethane improve. However, due to the volatility of ethane economics, we've decided not to incorporate a lot of this into our internal forecasts. Sheridan, do you have anything to add?

Well, that continues 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 volatility 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 as 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.

Good morning. I'm considering the future of ethane recovery in the Bakken for next year, whether due to pricing issues or physical constraints related to Northern Border. How do we plan to manage those ethane volumes? Are they seen as additional to what is already contracted on Elk Creek and further south, or could they offset current contracted volume levels that we have established? It seems like you suggested they would be incremental, but I wanted to confirm that.

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.

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 four times, 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 four times or should we be thinking more like between 3 or 3.5 as an excess longer-term target?

We expect to continue to delever past 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 as 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, it seems like you will be in a pretty good spot to get a 35% to 40% reduction in CapEx in 2020 versus where you've end up in 2019. I was just curious, does that number seem 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.

Thank you, Charles. Our quiet period for the fourth quarter begins when we close our books in early January and lasts until we release earnings in late February. We will 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.