Good day, and welcome to the Q3 2020 ONEOK Earnings Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Andrew Viola. Please go ahead, sir.
Thank you, Sarah, and good morning, and welcome to ONEOK's Q3 2020 earnings call. We issued our earnings release and presentation after the markets closed yesterday and those materials are on our website. 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 19331934. 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 is Terry Spencer, President and Chief Executive Officer. Terry?
Thank you, Andrew. Good morning and thank you all for joining us today. As always, we appreciate your continued trust and investment in ONEOK. Joining me on today's call is Walt Hulse, Chief Financial Officer and Executive Vice President, Strategic Planning and Corporate Affairs and Kevin Burdick, Executive Vice President and Chief Operating Officer. Also available to answer your questions are Sheridan Swords, Senior Vice President, Natural Gas Liquids and Chuck Kelley, Senior Vice President, Natural Gas.
Higher third quarter results were driven primarily by curtailed volume returning to our system and increased ethane recovery. The majority of volume across our operations has now exceeded pre pandemic levels and better represents our volume expectations prior to the widespread production curtailments seen last quarter. We're in a much improved position today than we were on our Q2 call. Back in July, we discussed the expectation for curtailed volume to return in the 3rd quarter. Now, just 3 months later, not only has essentially all of the curtailed volume on our system returned, that are returned at a faster rate than expected.
This momentum, especially from September, is expected to continue with the 4th quarter being just as good, if not better than the 3rd quarter, which also sets a good baseline into 2021. Additionally, we've successfully captured more previously flared natural gas in the Williston Basin, leading the effort to reduce flaring even as production has returned in the region. In August, we captured a higher percentage of gas than the statewide average of 92%, an opportunity we've discussed for numerous quarters. Infrastructure put in place earlier this year and the hard work of our employees allowed us to help producers in the region decrease flaring, allowing both our customers and 1UP to benefit from previously uncaptured earnings. This is just one example of our continued focus on customer service, safety and environmental responsibility despite the challenges of operating and conducting business during a global pandemic.
Operating conditions have greatly improved from 2nd quarter lows, but there is still uncertainty around the pandemic and the economic recovery. Despite that uncertainty, we remain focused on continuing to meet the needs of our customers. Our conversations with producers are increasingly positive as commodity prices have shown some stability and demand has shown positive signs. These conversations have now shifted more towards 2021, indicating the potential for an improving pace of drilling and completion activity next year. As curtail volumes have recovered, so have our earnings.
We now expect 2020 earnings to approach the midpoint of our previously provided outlook ranges, which Walt will discuss shortly. On our last call, I shared our outlook for 2021 and today the backdrop is even stronger. Volumes in the Bakken ramped throughout the Q3, setting us up for a strong 4th quarter and 2021. We expect to achieve double digit earnings growth in 2021 compared with our new and updated 2020 outlook. As it relates to our dividend, distributable cash flow this quarter exceeded the dividend by $125,000,000 With earnings strength expected in the Q4 and into 2021, we expect distributable cash flow to cover both the dividend and our 2021 capital expenditures as we continue on our path to deleveraging.
As always has been the case, the dividend remains a potential lever we could pull if our deleveraging expectations are not being met. This quarter demonstrated the reliability of our assets, the unwavering dedication of our employees and the resiliency of our extensive and integrated businesses. While the second quarter was challenging, our employees remained focused on serving customer needs and preparing our assets for the eventual return of curtailed volume. The key infrastructure projects we completed prior to the pandemic create substantial capacity for future growth as markets continue to improve. With that, I will turn the call over to Walt.
Thank you, Terry. ONEOK's Q3 2020 net income totaled $312,000,000
or $0.70 per share.
3rd quarter adjusted EBITDA totaled $747,000,000 a 15% increase year over year and a 40% increase compared with the Q2 of 2020. Distributable cash flow was more than $540,000,000 in the 3rd quarter, a 12% increase year over year with a healthy dividend coverage of 1.3x. We also generated more than $125,000,000 of distributable cash flow and excessive dividends paid during the quarter, an 11% increase compared with the same period last year. Our September 30 net debt to EBITDA on an annualized run rate basis was 4.6 times as we saw a significant step up in EBITDA in the 3rd quarter from the return of curtailed volume across our system. We continue to manage our leverage towards 4x or less and maintain 3.5x as our long term aspirational goal.
We ended the Q3 with no borrowings on our $2,500,000,000 credit facility and nearly $450,000,000 in cash. Last week, the Board of Directors declared a dividend of $0.935 or $3.74 per share on an annualized basis, unchanged from the previous quarter. We took proactive steps earlier this year to provide ample liquidity and protect our investment grade ratings. We've demonstrated our ability to access the capital markets even during challenging market conditions and have enabled to use our balance sheet flexibility to help guide financial decisions throughout this period of uncertainty. We have proactively paid off upcoming debt maturities and have been opportunistic in repurchasing more than $200,000,000 of debt through open market repurchases in the 1st 9 months of the year.
From an upcoming debt maturity standpoint, we have no maturities due before 2022. As Terry mentioned, with yesterday's earnings, we announced that we now expect 2020 net income and adjusted EBITDA results to be higher, approaching the midpoint of our previously provided outlook ranges. Our improved outlook is supported by the volume strength we're seeing across our assets, the pace that curtailed volumes returned and our ability to capture previously flared gas results in an earnings run rate more in line with our original 2020 expectations and providing a clear path to our continued deleveraging. Yesterday, we also announced the early completion of our 2 remaining active projects, the Bakken NGL pipeline extension and Arbuckle II pipeline extension, which were originally scheduled for completion in the Q4 2020 and Q1 2021, respectively. 3rd quarter CapEx included dollars pulled forward from the Q4 and 2021 for these projects and routine growth capital primarily for well connects and maintenance activities.
We have now substantially completed all of our active capital growth projects. We continue to expect a run rate of total annual capital expenditures, including maintenance and growth of $300,000,000 to $400,000,000 This base level of annual capital will be maintained until producer activity levels provide visibility to volume growth warranting expanded capacity. But as always, we remain flexible with the ability to restart projects quickly as customer needs change. Recent conversations with producers, particularly those who have substantial positions in the Dunn County area of the Williston Basin are indicating that more rigs will return in 2021, and resulting in a potential need to restart Bear Creek 2 construction if this activity materializes. Even in this scenario, our 2021 capital expenditures would likely be in the $500,000,000 range.
We now expect our cost saving measures to total approximately $130,000,000 this year compared with our 2020 plan. For September through September, we've recognized approximately $100,000,000 in savings and continue to look for additional efficiencies. From a financial perspective, we remain well positioned with ample liquidity and balance sheet strength to withstand additional market uncertainty should it arise and to be opportunistic in the event of a faster paced recovery. I'll now turn the call over to Kevin for a closer look at our operations. Thank you, Walt.
With nearly all curtailed production back online by the end of the Q3, we saw a large step up in NGL and natural gas volumes across our system compared with the 2nd quarter. NGL volumes across all of our operating areas exceeded pre pandemic levels in the 3rd quarter and natural gas volumes processed in the Rocky Mountain region have reached more than 1,200,000,000 cubic feet per day in October. I'll start with the Natural Gas Liquids segment. 3rd quarter NGL raw feed throughput volumes across our system increased 7% year over year and 15% compared with the 2nd quarter. In the Rocky Mountain region, which is our highest margin business, volumes are averaging approximately 245,000 barrels per day in October, a 14% increase over our Q3 2020 average and a more than 50% increase from the Q2 2020.
The return of curtailed production, completion of DUCs and increased flared gas capture have contributed to higher volumes. As the primary NGL takeaway provider from the region, our natural gas liquids segment not only benefits from the gas captured on ONEOK's dedicated acreage, but also from many third party plants across the basin. With more than 130,000 barrels per day of available capacity out of the region and the ability to expand capacity with minimal capital if needed, there's a long runway to grow with our customers. We expect NGL earnings in the region to see additional benefit from 2 other areas as we move into 2021. First, the early completion of our Bakken NGL pipeline extension in August.
This lateral extension connects our system with an area of Williams County, which has historically had limited NGL transportation options. In addition to the original contract with an expanding third party plant in the area, we've also contracted 2 additional third party plants near the pipeline. Volume has already started flowing on the extension and we expect a continued ramp into next year. As a reminder, this project is also supported by a minimum volume commitment. 2nd, we expect to transport all of our Williston and Powder River Basin volumes exclusively on our Elk Creek and Bakken pipelines beginning very early next year once we complete a low cost pump expansion on Elk Creek, which will reduce our transportation costs paid to Overleaf Pass Pipeline.
In the Mid Continent region, we completed the Arbuckle II pipeline extension in August earlier than our target date of the first quarter 2021. This extension improves connectivity from our Elk Creek pipeline to the Elbuckle II pipeline, allowing increasing Rocky Mountain volumes the optionality to be transported to the Mont Belvieu market hub. Increasing petrochemical demand and favorable ethane economics resulted in significant ethane recovery across the Mid Continent region through a good portion of the Q3. Our raw feed throughput volumes in the region increased 9% compared with the Q2 2020, largely due to ethane recovery. Ethane volumes in the Mid Continent averaged more than 245 1,000 barrels per day in the Q3 2020 compared with the Q2 2020 average of 210,000 barrels per day, a more than 17% increase driven by nearly all of our mid continent plant connections recovering ethane in July August.
In September, we saw a reversal back to ethane rejection as pricing and volumes were impacted by decreased petrochemical demand due to Hurricane Laura. We have seen some plants in the Mid Continent return to recovery this month, but expect ethane volumes on our system to fluctuate for the remainder of 2020 and into 2021. In the Permian Gulf Coast region, 3rd quarter NGL raw feed throughput volumes increased 16% compared with the Q2 2020, benefiting from returning volumes and approximately 30,000 barrels per day of short term fractionation only volumes. Even without the additional short term volume, raw feed throughput in the region still increased more than 6% compared with the 2nd quarter. As we've mentioned previously, we continue to offload 25,000 barrels per day on 3rd party NGL pipes.
This firm contract will expire at the end of the year, which will eliminate this expense as we move these barrels to our integrated system. Moving on to the natural gas gathering and processing segment. Total natural gas volumes processed increased 13% compared with the 2nd quarter 2020 and processing volumes in the Rocky Mountain region have reached more than 1,200,000,000 cubic feet per day in October, a more than 16% increase from our 3rd quarter average. The return of curtailed volumes to our system in the Williston Basin drove the 3rd quarter average fee rate to $0.94 per MMBtu compared to $0.71 in the 2nd quarter. As a number of high fee percentage large producers brought production back online, some sooner than expected.
Going forward, we expect the average fee rate to remain around this level. There are 13 rigs currently operating basin total more than 850 with approximately 400 on our dedicated acreage. We said previously that it takes 15 to 20 well completions per month to maintain our processing volumes around 1.1 to 1.2 Bcf per day. This is a relatively small number of well completions considering we have averaged 28 completions per month through the 1st 9 months of 2020. When we factor in our current volume levels, a significant DUC inventory that is profitable to complete in this price environment, the rigs currently on the system and some additional flared gas opportunities, we have ample inventory to support current volume levels through 2021, assuming no increase in producer activity during that time frame.
Of course, any additional producer activity in the basin would present upside, resulting in more wells drilled and or completed, driving higher volumes and ultimately earnings for ONEOK. Slide 7 in our earnings presentation has been updated to illustrate the ability to maintain current natural gas processing levels with minimal well completions. This slide is meant to be a representation, not guidance or an indication of our expected future volumes. For reference, there are 4 to 5 frac crews in the region today, each with the capability to complete 5 to 6 wells per month. In addition to the substantial inventory of wells on our system, other volume tailwinds in the basin include rising gas to oil ratios and additional gas capture opportunities.
DORs have continued to increase and remain well over 2:one, the result of activity concentrated in the core of the basin and maturing wells. This level of gas production suggests that even in a flat or slightly declining crude oil production environment, we could still see stable to increasing gas volumes in the region. The latest North Dakota data, which is for the month of August, showed 215,000,000 cubic feet per day still flaring in the basin with approximately 80,000,000 cubic feet per day of that on 1H dedicated acreage. Statewide flaring in August decreased to 8% compared with nearly 20% at the same time last year. As Terry mentioned, flaring on ONEOK's acreage was below the statewide average, a reflection of the infrastructure that our employees have worked hard to construct and operate in the region over the last decade and specifically over the last couple of years.
With 1.5 Bcf of processing capacity, we will continue to push to capture even more of the gas produced as we move through 2021. In the Natural Gas Pipelines segment, we reported another strong quarter of stable fee based earnings with firm capacity remaining nearly 95% contracted. This segment continues to be a stable fee based earnings driver for the company providing essential natural gas to end use customers. Barry, that concludes my remarks. Thanks, Kevin.
That was a great overview of a strong quarter headlined by the expected return of volumes and a solid demonstration of the resiliency of our businesses. This quarter was not only marked with volume related milestones and accomplishments. In August, we issued our 12th annual Sustainability and ESG report. And just recently, we received notable ESG related recognitions, including being recognized by Just Capital for the 2nd year in a row as the industry leader in the energy equipment and services sector and receiving an award for environmental excellence from the Environmental Federation of Oklahoma. We're always evaluating ways to improve our ESG related performance and enhance our long term business sustainability.
This includes planning and preparing for potential changes to our industry, customer needs or the broader demand for energy. There has been much discussion about the future state of the energy industry and we get asked frequently what our role could be in a low carbon world. The answer is simple. ONEOK has always promoted a business culture prioritizing safety, environmental responsibility and profitability in all that we do. And as we always have, we prepare diligently for the future and as our industry continues to meet the world's energy needs in an environmentally responsible way.
Using our extensive assets for hydrogen transportation and storage, our commitment to environmental stewardship remains steadfast. Our assets, their location and our midstream skill set is compatible with many of these types of projects, but they still need to make strategic sense for our business. In many cases, technology or large scale application may be further into the future, but we'll continue to evaluate opportunities that fit within our businesses. Because we absolutely believe that our large and extensive infrastructure has a vital role to play in the long term energy transition. And while we evaluate new and future opportunities, I want to thank our employees for doing what they do best, operating our assets safely and responsibly and transporting the essential NGLs and natural gas that are used to heat your home, generate electricity and create the many end use products that help us lead healthier, safer and more productive lives.
With that, operator, we are now ready for questions.
And we'll go ahead and take our first question from Jeremy Tonet with JPMorgan.
On for Jeremy. I just want to start with the 'twenty one guidance here for double digit growth. Just given where the strip is today, what are the price assumptions built into that guidance? And then just looking at Slide 7 with the well completion guide, is it is Perrigo well kind of the ballpark for well completions needed to kind of maintain flat volumes there in Bakken?
Well, Jerry, it's a little hard to understand you, but let me take the first question about growth into 'twenty one. When we talk to producers in this price environment, they clearly the DUCs are profitable to complete. I mean, I think that's the focus, especially as we look as you move through the rest of this year in the early parts of 'twenty one. You've got that substantial DUC inventory in the Bakken and you've seen some rigs come back. So as we've said before, in a $35 to $40 environment, the DUCs work well as far as the economics.
You get north of 45, that's when we saw rigs come back in a material way in 2015 2016. And I think our conversations with customers today, that would still hold. So as we think about 2021, we're absolutely not thinking about it in the context of a $55 environment. It's more in line with what the Strip would look like today. Chuck, anything to add there?
No, I would agree with those prices. And as far as what you referenced with producers, we've had discussions with our Bakken producers and looking at their 2021 forecast and drill schedules. And what they've provided, they expect the pace of completions in the first half of the year to be DUC driven, as Kevin mentioned. However, they anticipate adding rigs in spring. So I think as you look at the strip in 2021, that pretty much supports that statement.
Got it. Thanks for the color. So I'm hard to understand. And just my next question here, you're just looking at the kind of $15,000,000 in the G and P segment that was kind of captured here from improved commodity prices. I guess, at a high level, can you talk about how much of that is an element of improved volumes and kind of versus the fee component there?
Is there any color you can provide there? I appreciate the color on the GMP fee going forward, assuming the $0.94 But any color you could provide there?
Jeremy, we're struggling. Did you is your question about the fee rate in the G and P business?
Yes. Sorry. Just basically what is the kind of breakdown of coated by the in terms of the how much of that is attributable to improved volumes versus kind of the improved commodity prices?
Jeremy, this transmission is really bad. It must be a bad connection. So we're having real difficulty understanding and just hearing your question. So what we could do is try to get to you offline. But I think, Jeff, you've got any commentary around the fee rate that might be helpful for Jeremy?
Sure. We can talk about pretty much what drove our increase in the fee rate quarter over quarter.
If you think about it, it's really a combination of 2 things. It's basin mix and contract mix. So as
we saw, our Williston basin curtailed volumes returning
to our system, particularly from our large producers, These producers have contracts that
are fee only or high have a high fee with a lower percentage of proceeds component. And as these curtailed volumes came back on, then what happened was the mix of the basin contribution to that average fee changed. In Q2, it was more toward a fifty-fifty mix between Mid Continent and Bakken with, of course, Mid Continent being a lower fee margin business. So here in Q3, we saw our Rockies volumes contribute upwards of approximately 60% of that calculation. So combination of large producers, higher fee, higher fee, lower top components, all lowest in volume related and roughly 60% of that basin mix in the average
or the basin weighting in
the average drove that fee rate to 0.94 dollars
We'll go ahead and take our next question from Shneur Gershuni with UBS.
Hi, good morning guys. Hopefully my connection is okay. Just to clarify before I ask my questions, you were basically saying the mix shift of where the volumes came from is part of the reason why the rate went up. Is that the way to characterize your last response?
Yes. That I mean, again, it's a shift in both the volume of from the Mid Con kind of declining in the higher percentage of Williston volume and then also the mix of contracts that we had a lot of our larger higher fee based customers brought gas back online in a sizable way in the Q3.
Perfect. Okay. Just moving on to my questions here. First of all, thank you for providing all the incremental data on WellConnections and that Slide 7 where I kind of feel like I can choose my own adventure. So when I think about Slide 7, I just want to understand how to utilize it correctly here.
It suggests 15 average well completions a month, sort of keeps you flatter. I guess that's about 180 completions for the year for 'twenty one. And to grow, you've got the 25, 35, 45 scenarios. And then as you mentioned in the call, you've got $400,000,000 that are in the money right now, but maybe they're not all in the right areas. So when I sort of piece that together, if I see, let's say, half the DUCs get completed and you mentioned that you have 8 rigs running on your acreage, which gives you what, 2 wells per rig per month.
It sort of seems like you can be materially above the 28 average well completion that you sort of highlighted in that you saw in September. So when I think about that, all else equal, that you can have a material increase in production year on year, am I being too simplistic in my analysis here? Or is that the way to be thinking about that?
No. Shneur, this is Kevin. I think that's exactly how we're looking at it. I mean that DUC inventory, that provides you a substantial runway for growth. And when you add the rigs on top of that and we do expect to capture a little more gas and that gives you that volume strength that we foresee.
In the prepared remarks, I believe Terry mentioned that double digit growth for 'twenty one versus 'twenty. 'twenty. Which one of those scenarios are you assuming? Is it 25%, 35%? Just trying to understand that.
We haven't again, we haven't necessarily provided the specific link there. But again, I'd go back to the previous comments from Jim that I made with Jeremy that we're not we're thinking about this in the context of a $40 to $45 type environment as we look at 'twenty one.
Okay. And then maybe as a follow-up question, one of your peers yesterday sort of was talking about Robustin in general that the producers are becoming significantly more efficient, more stages per frac, longer laterals and so forth and sort of intimated the GORs are going to continue to go up and maybe even faster than they had previously. Is that something that you're hearing from your customers as well, too? Is that something that you're seeing as well also?
Yes, this is Chuck. We are. We're seeing that from our producers. I think we had mentioned on last call, lateral lengths, we're seeing pushing out to the 3 mile level. We're also seeing increased frac stages.
So we're seeing so you're seeing greater production efficiencies. And of course, the GORs continue to rise in the basin. So when you look at those three components, it's all painting a pretty good picture for these new wells coming online.
And, Jeff, the bottom line of that is the breakeven costs continue to come down significantly.
That's correct.
Yes, that's super helpful. And maybe one final question, if I may, for Walt. When I sort of think about the results for the Q3, if I annualize and then look at your leverage compared to that, you start to get down to the 4.6 zone and so forth. As we move into next year, what's the leverage ratio on an annualized basis that you would like to get to before you would consider buybacks?
Shneur, I would answer that question in a couple of ways. I think that we will continue to see that leverage ratio trend in the right direction. We had when we originally gave 2020 guidance, we gave some expectations of where we thought leverage would get to at the end of 'twenty, early 2021. And that kind of got moved out 12 to 15 months based on the pandemic. So I think there's still trend in that range towards 4 times.
And whether that happens on a run rate basis at the end of 2021 or early 2022, we'll be headed in the right direction.
We'll take our next question from Christine Cho with Barclays.
Good morning, everyone. I'm going to apologize in advance, but I I also want to discuss Slide 7. When you talk about the 15 to 20 wells a month in the Bakken Tahoe volumes flat at the 1.1 or to 1.2 Bcf a day level. When I combine that with your comments that you expect to be at least $3,000,000,000 in EBITDA next year, that would to me at least imply Bakken volumes would have to hold at least from current levels. Does your CapEx of $300,000,000 to $400,000,000 next year indicate that level of well connects of $15,000,000 to $20,000,000 per month in the Bakken?
Or how should we think about that?
Yes. Christine, this is Kevin. Yes, I think we would expect to be able to do that. Again, we've got available processing capacity. So all we're talking about in that we would need would be well connect capital to go connect well.
We might need to add a compressor to station or something like that, and that would be within that $300,000,000 to $400,000,000 type range given the environment that we're looking at today.
Okay. And then if I could actually move over to Overland Pass, and I appreciate the comments that you made in prepared remarks about taking your Powder River Basin over to Arbuckle. But overall and tax earnings were down in 2Q and that level continued into 3Q. Did you guys move volumes from the Bakken NGL and Overland Pass to Elk Creek or did a large customer get off the system? And I thought the pipe was previously full.
So should we think that there's available capacity on that system going forward?
Christine, this is Sheridan. We did move some volume off of OPPL on to the Elk Creek Baughton system in both the second and third quarter. And probably the run rate you're at today is what you'll see through the Q4. And then once we get into 2021, we will our plan right now is to remove all the volume off that system. And once we get into 2021, by moving that volume off the system and moving on our own system, we think due to cost savings that we will see, we should see approximately a $40,000,000 or $50,000,000 uplift in earnings.
Okay. To do that, are you going to have to expand Elk Creek?
As Kevin said in the earnings call, we have a low cost expansion that we will complete by the end of the year and that will allow us to move all the volume off of OPPL on Elk Creek.
Got it. And sorry, one follow-up. Did you have to pay anything to take your volumes off of over loan costs for the last quarter, this quarter and next quarter?
Well, we have some contracts or obligations that we can't get into at this time, but any obligations or any contracts we have will not extend into 2021.
Got it. Thank you.
We'll take our next question from Tristan Richardson with Truist Securities.
Hi, good morning. Really appreciate all the comments on 2021, particularly clarifying some of the assumptions and especially uncertain environment. I mean, you guys noted that customer conversations are encouraging and rigs could potentially return in the spring, which would presumably accelerate that completion activity. So to the extent of return of a rig occurs, as you noted, any of that return would be upside to the general assumptions driving the $3,000,000,000 plus 2021 expectation?
I mean, I think there's clearly the potential for that. I mean, that's what we talked in our opening remarks that, that that would be upside. I think that it just will boil down to how the producers and our customers determine to deploy that capital as far as completing DUCs and rigs coming back. The other thing that rigs coming back, if you think about the lag of those rigs coming back, that also then would start supporting growth into 'twenty two as well.
Really helpful. And then I guess just conversely, do you see outside of a reduction in completion or pace of completion activities, are there headwinds out there that would prevent you to that sort of $3,000,000,000 number in 2021? I
mean, that's the again, just other than you said that the activity levels and we all know the risk that would come with that might drive that. But other than that, the thing I think we just keep coming back to is we've got plenty of processing capacity. We've put a lot of compression and field infrastructure in place to get the gas to the plant. We've got an NGL system that's got available capacity. So we're sitting in a good spot to be able to grow with our customers with very little capital.
Kevin, I think the only thing I would add to your comments is that as we talk to the producers, certainly they're making their decisions based on a longer term view of commodity prices. Now certainly you could have you've got OPEC risk out there, you've got COVID-nineteen risk out there in the universe that certainly could impact these numbers as we think about 2021. But the fact of the matter is the industry has done some things not only in the way they operate, but also in the way they manage their markets. And we've got new pricing indices in the Gulf Coast that could mitigate and ensure that the phenomenon we saw in the springtime in terms of negative crude prices does not happen again. So we're pretty certain we're not going to see that type of scenario materialize.
But certainly, we'll see month to month or quarter to quarter volatility in commodity prices like we always do. But we don't anticipate even if we see some of these other phenomena other things happen like OPEC or the COVID, we don't think we're going to get back in a scenario like we saw in the springtime, which was a huge impact to what transpired in the Q2 seeing those negative crude prices.
We'll take our next question from Michael Blum with Wells Fargo.
Thanks. Good morning, everybody. I wanted to ask about ethane for next year really. Do you I guess what ethane price do you think you need to see recoveries in the Bakken? And would you consider or are you considering a lower tariff to incentivize some of those ethane recoveries next year?
And then I apologize for the multipart question here, but is any of that is any ethane recovery assumed in your forecast or expectation for double digit growth in 2021?
Michael, this is Sheridan. What I would say on your first question, the ethane price that we would need in the Bakken obviously depends on what the gas price is in the Bakken. But it'd be fair to say that we would need to be in the $0.40 per gallon range at current fee structure that we have today. We always have the ability to flex our fees or change our fees to incent ethane to come out if we think that's the best thing to do. But a lot of it depends on obviously we have to get still have the price with fees to be higher than the gas price in the area.
If we look into 2021, we are not assuming any ethane recovery out of the Bakken in our double digit growth. We are only assuming a partial ethane recovery through the year in the Mid Continent for the double digit growth as well, which is where we could see some upside as we go into next year based on the volume happens. But ethane does represent kind of a call option that we have If volume doesn't show up, that would force people to go into different areas to extract ethane, where if volume does not show up like we think it is next year, you could see ethane be economic coming out of the Bakken, which would support our growth rate for next year.
And Sheridan, we do see some additional petchem demand coming as well, right?
That's right. There's a 1 cracker that's to be completed here in the Q4 of 2020. And then we also have an export dock that is to complete and that has been completed and will start exporting full capacity into next year. So we see good demand coming on for next year and that's why we think we could see some methane recovery for a portion of the year in 2021.
Got it. Thank you very much.
We'll take our next question from Spire Dounis with Credit Suisse.
Hey, good morning guys. First question for Walt, just with respect to leverage and getting to that 3.5 times aspirational target. I think I heard in your response to Shneur that the strategy at this point is maybe steady deleveraging the cash flow over time, which sounds like obviously that's been pushed out a little bit. Just curious beyond some of the repurchases you guys have done in the open market, where maybe there's less opportunity there going forward. Any appetite to get more proactive here?
And specifically, what I'm thinking about is just on the M and A side and using M and A as a tool to maybe both delever as well as do something strategic. I'm not sure if anything screams for you on that front.
Well, we think we're going to naturally delever. And I think we're shooting to 4x first, 3.5x aspirational over time. But I think getting to that 4 times goal is the near term target. We obviously are going to look at opportunities that come along the way. And if something was attractive from a delevering standpoint, that would be a positive.
But I don't think that would be a driver for us to do a transaction for sure. Yes, Spiro, this is Terry. So while we always think about acquisitions and opportunities to add assets or businesses to our business, that's just an ongoing process. It's really not our top priority right now. And managing the core business, managing the balance sheet is our priority.
And we're just going to stay focused on that. We'll stay focused on our operations. We're going to stay focused on serving our customer needs and optimizing our business where we can. The fact of the matter is, as I've said before, M and A opportunities are kind of few and far between and particularly those that are actionable. So we don't spend a whole lot of time worrying about that.
So right now in this environment, stay focused on the core business.
We'll take our next question from Jeanine Falzberg with Bernstein.
Hi, good morning. What drives the flaring that is still happening on your acreage and in the Bakken more broadly? And what would need to happen next year to get it even lower? Or is this just kind of a good at a dip?
Okay. Jean, it's Kevin. I think you look at the flaring that's left. We still have some isolated pockets of wells and or pads that haven't been connected and or we have some maybe pressure limitations. We're working to continue to put in some infrastructure.
Obviously, we've taken out a lot of that flared gas as productions come back online. As we said before, you're always going to have some level of flaring, especially when you look at IP rates and if a producer brings on a very large pad and we're not building for the peak 30 days or things like that. So those are the types that you've got operational disruptions that could cause some flaring from time to time. So we'll continue to work to obviously look for ways to capture all the gas that's out there, connect to a few of these and continue to watch the pressures on our system.
Okay. So maybe a little bit lower, but it's not I guess I didn't put it on like a tiny number. Okay. And then I just wanted to follow-up on a question that was asked previously. Ethane price does not have to get all the way to $0.40 for you to start sort of recovering and getting some benefit from the packing, right?
I think it's what you're saying that for the person that you market yourself, you could do it at a lower price and make money?
Yes, we could always this
is Sheridan. We could always lower our fees to make it economical to recover ethane. We always have that option and that's not only with our own volume coming off of our plants, but that would also be with a lot of third party volumes. And this is something at times we've done in the Mid Continent when we think ethane may be coming into rejection to get them to come in earlier, we've reduced our fees at times to 4 months to allow them to come in. So we have that option.
And if we see the opportunity to do that and we think that it makes sense, that is definitely within our wheelhouse to do that $0.10 ethane to come out.
We'll take our next question from Gabe Moreen with Mizuho.
If I could ask maybe a little bit about what you're seeing with the pull curve for gas here being north of $3 with some of your legacy areas like the Mid Con, you're seeing maybe some refracs or producer interest and some stuff like that. I'm just wondering if you could tell discussions are happening.
Gabe, this is Chuck. Last question regarding Mid Continent producer discussions, I didn't quite hear it.
Yes, that's a good question. We have seen some refracs here this year, particularly last quarter. And from what I understand, there's a couple scheduled here in our Q4. Other than that, Mid Continent producers we've spoken with have shared their preliminary plans for 2021. And they're indicating a restart in activity in
both the STACK and the SCOOP.
We're seeing 2 to 3 rigs they're talking about next year for us right now on our acreage. There might be a 4th. And what they're citing is strengthening midcontinent gas prices for some of the gas supplies, particularly in the STACK. I hope that gives you a little bit of color of what we're hearing in the Mid Continent.
That was helpful. Thank you. And then, two quick clarification housekeeping questions from me. One is kind of what the expectations now are for total second half twenty twenty CapEx given Q2 spending, I think some of that pull forward. And then the other is the guidance on double digit growth for 'twenty one.
I think last quarter you sort of sensitized to DAPL being on or off. Are there any sensitivities with GAAPL being on or off?
Gabe, this is Kevin. I'll start and then Walt can chime in. As we think about CapEx yet, clearly with what we spent in the Q3 with the acceleration of some of these projects and the activity levels we saw, we are at the high end and capital usually tapers off in the 4th quarter, especially with weather and other things. But we'll definitely trend towards the upper, if not slightly above the top end of the range there, just given what we spent year to date. But when we think going forward about capital, the notion that we can continue to spend the kind of a run rate to continue to grow with the customers in that $300,000,000 to $400,000,000 range, Absolutely, we're thinking about DAPL and continue to think about it.
Our outlook remains consistent with what we said before that if you would experience or the industry would experience a DAPL shutdown, we still believe it would be a mid single digit type growth for DAPL even in that scenario. Our customers, as we talk to them, they definitely have been exploring alternatives. Some of them have been securing some rail. Some of them have been moving some volumes to other pipes and getting allocation there. So
we do
feel we'd be able to support volume growth even in ADAPL shutdown scenario. And Sheridan, do you have anything to say at any event ADAPL shutdown could happen? You've got the potential to be a crude transporter out of here with some pipe you currently operate?
Yes. We still continue to look at whether or not we would take the Bakken, the 12 inches pipeline into crude service. As Kevin said, the producers out there have really looked at alternatives, and there's a lot of alternatives beyond ours as well, rail being one of them and obviously other types that may be in a better position to start up quicker than our Bakken pipe could be to convert. But we still continue to investigate that to make sure it's ready to move if we need to do that based on if that gap will shut down.
We'll take our next question from Elvira Scotto with RBC Capital Markets.
Hey, good morning, everyone. So recently we've seen an acceleration of upstream M and A. What are your thoughts on this trend? Clearly, having larger, better capitalized shippers on your system would be a positive, but do you see any potential impact to contracting? And do you think that the larger more integrated midstream companies like ONEOK that can offer services across the value chain benefit here?
Elvato, this is Kevin. I don't know that we see I don't think we definitely don't see that as a negative. We've got a lot of very large customers. I don't see it as a contract issue at all. We've got the vast majority of our contracts are long term, they're locked in, and we like those contract structures.
The companies typically, the larger companies we deal with, many of them have a long term view of this clay, especially as we think about the Bakken and they're looking at the reservoir over the next 10 to 20 years, not over the next 3 to 4. So that can help from the standpoint of just good strong ratable growth over time. But I don't know that we see it as a significant pro or con either way.
Got it. Thanks. And then a quick follow-up to that M and A question. I appreciate the comments that you made on one open M and A, but I'm interested in your thoughts on overall trends that you think you can see in midstream M and A potential?
Well, I don't know if still, Elar, certainly there is some potential in the midstream space for consolidation, gathering process. And I've been saying for better part of 15 years that there's going to be significant consolidation this year and I've been wrong every time. But we do see some potential for private equity to potentially look at placing assets into the market. The fact of the matter is that most of those assets don't really make a whole lot of sense for us, don't fit with the bigger picture. We've done a lot of work in trying to manage our risk as it relates to wellhead risk.
And so we've done a real good job there contractually as well as how we operate our businesses. So really, to the extent we do see some things in midstream space, specifically in gathering processing, Most of those, as I see the landscape today, don't really fit that well and certainly carry with it some risk that we don't like. But broadly speaking, on a large scale for midstream, there is some you see some assets that are being spun out from other companies and utility companies. And some of those assets are assets that look pretty good, that could make some sense. But certainly, we're going to look at the landscape and be diligent and disciplined in the way we consider acquisitions, just as we always have.
We'll take our next question from Suneel Sibal with Seaport Global Securities.
Yes, hi. Good morning, guys. Hopefully, you
can hear me all right.
I just had a quick question. If you could remind us in terms of your volumes or the cash flows exposure to the drilling on federalIndian lines?
I am sorry. I couldn't make out your question. The connection is kind of garbled. So maybe try the next question, if we can hear that and understand that one. The connection is really the audio is really poor.
Yes. Hi. So my question, same question was related to your capital allocation strategy. I was wondering if you have had any recent discussions with our rating agencies, and how does that figure in terms of your capital efficient strategy? Thanks.
We have regular conversations with rating agencies. We have throughout the pandemic. We would have regular conversations even before the pandemic. I think they've been supportive. You can talk to them directly.
We have been pretty clear about our view on the dividend that it's part of the capital allocation process that our Board thinks about every quarter. And but we really see the strength of the business and the dividend coverage that we saw in this quarter and what we think about moving forward is supportive of the delevering that we're seeing and that the rating agencies have been looking at as well. So I can't speak for them, but we have a very regular dialogue with them.
Okay. Thanks for that. And I'll take my other questions offline.
We'll take our next question. We'll take our next question from Michael Lapides with Goldman Sachs.
Hey, guys. Thank you for taking my question and congrats on a great quarter. Real quick, we've had lots of M and A questions and they've all been asset acquisition or company acquisition driven. I kind of want to take it on the other side. Is there anything within the ONEOK portfolio that might not necessarily be core to ONEOK?
You have a pretty integrated system, but just curious how you're thinking about that as a potential path to accelerating the deleveraging process?
Yes, Michael, we always think about that. We're constantly thinking about asset rationalization. The fact of the matter is that you really don't materially have any assets that we don't consider to be core to our business. But we may have assets that certainly don't generate quite as higher rate of return as others. So we'll always think about those and we'll look at the landscape and the market opportunity and to determine if ownership of the whole value for somebody else is greater.
So we're always thinking about those kinds of things. But as we sit today, our asset collection all fits together pretty well.
Got it.
And then 2 Canadian collections just on the Q3. First of all, in the Bakken, what were the well connects in September? Like what was the cadence? I know you did 55 during the quarter, but what was the cadence of that through the quarter? Was it significantly higher in September as an exit run rate relative to what it was at the beginning of the quarter?
Michael, this is Chuck. I know our quarterly number was 55%. Frankly, I don't have the monthly breakdown in front of me. So, really can't speak to how it broke out over the quarter. We do have line of sight here in Q4 with a similar type number.
We'll take our next question from Craig Shere with Tuohy Brothers.
Hi, guys. Thanks for taking the question. Congratulations on a terrific quarter. First, based on conversations with producers, any color around the magnitude of potential Wilson rig count recovery that you could see on your dedicated acreage from the spring? And kind of dovetailing with Terry's comments about breakeven costs falling, Are you getting body language that $40 is the new $45 like what we saw in 2015, 2016 as far as spurring material rig count recoveries?
Hey, Craig, it's Kevin. Yes, the conversations with producers have gone great. They continue to get better and better. Chuck referenced lateral lengths and the frac, the completion technologies, etcetera. In addition to that, they have figured out spacing and they know exactly what they're going to get.
I think one of the charts we provide, not in our quarterly materials, but I think in our investor deck, shows year over year how the type curves have improved every year. And as we talk to producers, they don't expect that to change as they continue to get better. So does that take the does that take 45 to a new 40 or vice versa? I don't know. But all I can tell you is in this price environment, all the conversations we're having with customers right now are about increasing activity, not about shutting activity down.
Great. Thank you.
And last question.
Terry, I just want to dig deeper into your CleanTech and environmental comments. I mean, some things we kind of vaguely heard of is lithium extracted from oilfield brine, hydrogen perhaps cheaply derived from old oilfields and in field liquefaction perhaps assisting with flaring in certain basins. Acknowledging
there's a
lot of uncertainty over the next 5 to 10 years. Are there any areas of transition that really stand out more for you where you could potentially participate?
Well, let me just hopefully this will
answer your question. When we think about our participation in a low carbon environment, it comes in basically 3 buckets. The first is reducing the impact from our existing assets and reducing our emissions. We've got opportunities to do that in terms of enhanced pipeline integrity and leak protection or leak prevention. We also have opportunity with electrification of existing natural gas fired equipment and in particular compressors.
And so we've got it we've done some of that work. We've got a lot of electric drive machines in service and that's growing. And we're looking at continuing to do that as we go out over a 10 year timeframe that can and will have a significant impact in lowering our emissions. It also gives us the opportunity to consume solar and wind derived electricity, which obviously is a good thing to do. The other bucket is the transportation and storage and logistics for hydrogen.
As you mentioned, CO2, carbon capture, we have got some projects that we are looking at that's pretty low hanging fruit to reduce the amount of CO2 emissions. And then we're thinking about renewable fuels and other inert types of commodities or substances. So that fits very well with our existing capability and assets. And then we're thinking about other low carbon projects that just make strategic sense for our business And that could be investing in some new technologies, potentially hydrogen fuel cell technologies. We could have investments in those types of projects, direct investments in some of those.
So, profitability, business strategy, all these things have to make sense with that broader objective to be a profitable company and to make us better and to reduce our impact on the environment. So that's kind of how we think about it. We're probably not going to invest in projects that absolutely don't have a fit or don't connect in some form or fashion strategically with our core business and our core capability as a midstream company. So, that's, I think, a long winded answer to your question. Hopefully, that helps.
We'll take our next question from Derek Walker with Bank of America.
Thanks, everyone. I know we're over the hour and I appreciate you squeezing me in here. Maybe I'll just ask one and ask other question offline. But if I heard you right during
the formal remarks, I believe you said
you captured $100,000,000 of cost reductions this year up to this point. And I know there's some commentary around cost savings with shifting volumes around, it was kind of $40,000,000 to 50,000,000 dollars Does that $40,000,000 to $50,000,000 is that incremental to that $100,000,000 or have you achieved some of that already? And I guess is there any general sort of cost reduction target that you have going into next year? I think you had $120,000,000 last year, but just wanted to make sure that that's incremental to what you've already talked about.
No. This is Kevin. The $40,000,000 to $50,000,000 I believe you're talking about that Sheridan referenced, that's related to kind of margin in our NGL business. And so that would not be included in the $130,000,000 we expect save from the cost savings. So those are 2 separate things.
Got it. Thank you.
We'll take our next question from Ganesh Jhwaaz with Goldman Sachs.
Hi, thank you for taking my question. Just following up on Derek's question on
the costs, we saw a
meaningful step down in the OpEx in the G and P segment. Just wanted to understand if there was something unique happening in this particular quarter or if this is a decent run rate to think of from a total OpEx perspective going forward?
The step down you're referring to compared to the Q2 or you compared to last year?
Both actually, because I guess you have many more plants that are online this year than last year and yet your numbers were meaningfully lower. So just curious if there's something happening unique to this quarter or if this is the new normal in terms of cost structure?
No. I don't know that I'd say it's a new normal. But clearly, when we have worked really hard over the last several months, really since the beginning of the pandemic, to cut costs out wherever possible. So we are doing things like there's we have compressor stations that we can reroute gas and shut down compressor stations and there's a couple of plants in the Mid Continent we have temporarily idled that pulls costs out. You don't need as much materials and services.
And probably the biggest driver is our contract labor. We are doing most everything ourselves at this point with our employees as volumes have left. So with some process improvements and other things we found, we expect that some of that will be sustainable. But you would also expect that as our volumes pick back up, the cost will go up a little bit just from that additional volume.
That concludes today's question and answer session. Mr. Ziola, at this time, I'd like to turn the conference over back to you.
All right. Thank you, Sarah. Our quiet period for the Q4 starts when we close our books in January and extends until we release earnings in late February. We'll provide details for the conference call at a later date. Thank you for joining us and have a good week.
Thank you, everybody.
Thanks, Andrew.
This concludes today's call. Thank you for your participation. You may now disconnect.