Good day and welcome to the third quarter 2020 ONEOK earnings call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Andrew Ziola. Please go ahead, sir.
Thank you, Sarah. Good morning, welcome to ONEOK's third quarter 2020 earnings call. We issued our earnings release and presentation after the markets closed yesterday. 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 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 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 Walter 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 second quarter call.
Back in July, we discussed the expectation for curtailed volume to return in the third quarter. Now, just three months later, not only has essentially all of the curtailed volume on our system returned, but it returned at a faster rate than expected. This momentum, especially from September, is expected to continue with the fourth quarter being just as good, if not better, than the third 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 ONEOK 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 second 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 curtailed 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 third quarter, setting us up for a strong fourth quarter in 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 million. With earnings strength expected in the fourth quarter 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'll turn the call over to Walt.
Thank you, Terry. ONEOK's third quarter 2020 net income totaled $312 million or $0.70 per share. Third quarter adjusted EBITDA totaled $747 million. A 15% increase year-over-year and a 40% increase compared with the second quarter of 2020. Distributable cash flow was more than $540 million in the third quarter, a 12% increase year-over-year, with a healthy dividend coverage of 1.3x . We also generated more than $125 million of distributable cash flow in 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 4.6x , as we saw a significant step up in EBITDA in the third quarter from the return of curtailed volume across our system.
We continue to manage our leverage towards 4x or less and maintain three and a half times as our long-term aspirational goal. We end of the third quarter with no borrowings on our $2.5 billion credit facility and nearly $450 million 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 been able to use our balance sheet flexibility to help guide financial decisions throughout this period of uncertainty.
We've proactively paid off upcoming debt maturities and have been opportunistic in repurchasing more than $200 million of debt through open market repurchases in the first nine 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 clearer path to our continued de-leveraging.
Yesterday, we also announced the early completion of our two remaining active projects, the Bakken NGL Pipeline extension and Arbuckle II Pipeline extension, which were originally scheduled for completion in the fourth quarter 2020 and first quarter 2021, respectively. Third quarter CapEx included dollars pulled forward from the fourth quarter in 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 million-$400 million. This base level of annual capital will be maintained until producer activity levels provide visibility to volume growth warranting expanded capacity. 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, resulting in a potential need to restart Bear Creek II construction if this activity materializes. Even in this scenario, our 2021 capital expenditures would likely be in the $500 million range. We now expect our cost-saving measures to total approximately $130 million this year compared with our 2020 plan. Through September, we've recognized approximately $100 million 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 third quarter, we saw a large step-up in NGL and natural gas volumes across our system compared with the second quarter. NGL volumes across all of our operating areas exceeded pre-pandemic levels in the third quarter, and natural gas volumes processed in the Rocky Mountain region have reached more than 1.2 billion cubic feet per day in October. I'll start with the Natural Gas Liquids segment. Third quarter NGL raw feed throughput volumes across our system increased 7% year-over-year and 15% compared with the second 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 third quarter 2020 average, and a more than 50% increase from the second quarter 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 two other areas as we move into 2021.
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 two 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. 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 Overland 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 Arbuckle 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 third quarter. Our raw feed throughput volumes in the region increased 9% compared with the second quarter 2020, largely due to ethane recovery. Ethane volumes in the Mid-Continent averaged more than 245,000 barrels per day in the third quarter 2020 compared with the second quarter 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 and 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 and Gulf Coast region, third quarter NGL raw feed throughput volumes increased 16% compared with the second quarter 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 second quarter.
As we've mentioned previously, we continue to offload 25,000 barrels per day on third-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 second quarter 2020, and processing volumes in the Rocky Mountain region have reached more than 1.2 billion cubic feet per day in October. A more than 16% increase from our third quarter average. The return of curtailed volumes to our system in the Williston Basin drove the third quarter average fee rate to $0.94 per MMBtu, compared with $0.71 in the second 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 in the Williston Basin, with eight on our dedicated acreage, which is an increase from the past few months. Drilled but uncompleted wells in the basin total more than 850, with approximately 400 on our dedicated acreage. We've said previously that it takes 15-20 well completions per month to maintain our processing volumes around 1.1-1.2 BCF per day. This is a relatively small number of well completions considering we have averaged 28 completions per month through the first nine 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 seven 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 four to five frack crews in the region today, each with the capability to complete five to six 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. GORs have continued to increase and remain well over 2: 1, 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 million cubic feet per day still flaring in the Basin, with approximately 80 million cubic feet per day of that on ONEOK's 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 pipeline 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. Terry, 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. Just recently, we received notable ESG-related recognition, including being recognized by JUST Capital for the second 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. As we always have, we will do our homework to gain knowledge and prepare diligently for the future as our industry continues to meet the world's energy needs in an environmentally responsible way. Whether it's actively evaluating the use of renewable energy at our facilities, developing carbon-capturing projects, or assessing the feasibility of 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. 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. 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.
If you would like to ask a question, please signal by pressing star one on your telephone keypad. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, that is star one to ask a question. We'll go ahead and take our first question from Jeremy Tonet with J.P. Morgan.
James on for Jeremy. I just want to start with the 2021 guidance here, for double-digit growth. Just given where the strip is today, what are the price assumptions built into that guidance? Then just looking at slide seven with the well completion guide, is [15 to 20] well kind of the ballpark for well completions needed to kind of maintain flat volumes there in Bakken?
Well, Jeremy, you were a little hard to understand you there. Let me take the first question talking about growth into 2021.
When we talk to producers in this price environment, clearly the DUCs are profitable to complete. I think that's the focus, especially as you move through the rest of this year and the early parts of 2021. You've got that substantial DUC inventory in the Bakken, and you've seen some rigs come back. As we've said before, in a $35-$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 and 2016. I think our conversations with customers today, that would still hold. 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 you need 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, the expected pace of completions the first half of the year to be DUC driven, as Kevin mentioned. However, they anticipate adding rigs in the spring. I think as you look at the strip in 2021, that pretty much supports that statement.
Got it. Thank you both. My next question here. You're just looking at the $10.50 million in the G&P segment that was captured here from improved commodity prices. I guess, just higher level, can you talk about how much of that is the element of an improved volume versus the fee component there? Just any color you can provide there. I appreciate the color on the G&P fee going forward, assuming the $0.94. Any color you can provide there.
Jeremy, we're struggling. Is your question about the fee rate in the G&P business?
Yes. Sorry. Just basically what is the breakdown of color you provide there in terms of how much of that is attributable to improved volumes versus the improved commodity prices?
Jeremy, this transmission's really bad. It must be a bad connection. We're having real difficulty understanding and just hearing your question. What we could do is try to get to you offline. I think, Chuck, if 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's really a combination of two things: basin mix and contract mix. 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 have a high fee with a lower percentage of proceeds component. 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 50/50 mix between Mid-Continent and Bakken, with, of course, Mid-Continent being the lower fee margin business. Here in Q3, we saw our Rockies volumes contribute upwards of approximately 60% of that calculation.
A combination of large producers, higher fee, lower POP components, all Williston 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.
We'll go ahead and take our next question from Shneur Gershuni with UBS.
Hi. Good morning, guys. Hopefully my connection's 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?
Yeah. Again, it's a shift in both the volumes from MidCon declining and 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 third quarter.
Perfect. Okay. Thank you for that. Just moving on to my questions here. First of all, thank you for providing all the incremental data on well connections and that slide seven where I feel like I can choose my own adventure. When I think about slide seven, I just want to understand how to utilize it correctly here. It suggests 15 average well completions a month. If it keeps you flatter, I guess that's about 180 completions for the year for 2021. To grow, you've got the 25, 35, 45 scenarios. Then, as you mentioned in the call, you've got 400 DUCs that are in the money right now, but maybe they're not all in the right areas.
When I piece that together, if I assume, let's say, half the DUCs get completed, and you mentioned that you have eight rigs running on your acreage, which gives you, what, two wells per rig per month. It seems like you can be materially above the 28 average well completion that you highlighted that you saw in September. 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. That DUC inventory, that provides you a substantial runway for growth. When you add the rigs on top of that, we do expect to capture a little more gas, that gives you that volume strength that we foresee.
In prepared remarks, I believe Terry mentioned that double-digit growth for 2021 versus 2020. Which one of those scenarios are you assuming? Is it 25%, 35%? Just trying to understand that.
Again, we haven't necessarily provided the specific link there. Again, I'd go back to the previous comments that I made with Jeremy that we're thinking about this in the context of a $40-$45 type environment as we look at 2021.
Okay. Maybe as a follow-up question, one of your peers yesterday was talking about Williston in general, that the producers are becoming significantly more efficient, more stages per frack, longer laterals and so forth, and sort of intimated that 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?
Yeah, 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 three-mile level. We're also seeing increased frack stages. You're seeing greater production efficiency. Of course, the GORs continue to rise in the basin. When you look at those three components, it's all painting a pretty good picture for these new wells coming online.
Chuck, the bottom line to that is that breakeven costs continue to come down significantly.
That's correct.
Yeah, that's super helpful. Maybe one final question, if I may, for Walt. When I think about the results for the third quarter, 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. When we originally gave 2020 guidance, we gave some expectations of where we thought leverage would get to at the end of early 2021, that kind of got moved out 12-15 months based on the pandemic. I think we'll still trend in that range towards 4 x. Whether that happens on a run rate basis at the end of 2021 or early 2022, we'll be headed the right direction.
Perfect. Thank you very much today for all the color.
We'll take our next question from Christine Cho with Barclays.
Good morning, everyone. I'm going to apologize in advance. I also want to discuss slide seven. When you talk about the 15- 20 wells a month in the Bakken to hold volume flat at the 1.1- 1.2 BCF a day level. When I combine that with your comments that you expect to be at least $3 billion 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 million-$400 million next year indicate that level of well connects of 15- 20 per month in the Bakken? How should we think about that?
Sure, Christine, this is Kevin. Yeah, 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 wells. We might need to add a compressor at a station or something like that. That would be within that $300 million-$400 million type range, given the environment that we're looking at today.
Okay. Then if I could actually move over to Overland Pass, I appreciate the comments that you made in prepared remarks about taking your Powder River Basin over to Arbuckle. Overland Pass earnings were down in Q2, and that level continued into Q3. Did you guys move volumes from the Bakken NGL and Overland Pass to Elk Creek, or did a large customer get off the system? I saw some 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 onto the Elk Creek Bakken system in both the second and third quarter. Probably the run rate you're at today is what you'll see through the fourth quarter and then once we get into 2021.
Our plan right now is to remove all the volume off that system. 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 or $50 million uplift in earnings.
Okay. To do that, are you going to have to expand to 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. That will allow us to move all the volume off of OPPL onto Elk Creek.
Got it. Sorry, one follow-up. Did you have to pay anything to take your volumes off of Overland Pass for the last quarter, this quarter and next quarter?
We have some contractual 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 on uncertain environment. You guys noted that customer conversations are encouraging and rigs could potentially return in the spring, which would presumably accelerate that completion activity. To the extent a return of the rigs occurs, as you noted, any of that return would be upside to the general assumptions driving the $3 billion plus 2021 expectation?
T here's clearly the potential for that. That's what we talked in our opening remarks 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 2022 as well.
Really helpful. I guess just conversely, do you see outside of a reduction in pace of completion activities, are there headwinds out there that would prevent you to that sort of $3 billion number in 2021?
Just other than you said, the activity levels, and we all know the risk that would come with that might drive that. 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. 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 upon a longer-term view of commodity prices. Certainly, you've got OPEC risk out there. You've got COVID-19 risk out there in the universe that certainly could impact these numbers as we think about 2021. 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. You'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. We're pretty certain we're not going to see that type of scenario materialize.
Certainly, we'll see month-to-month or quarter-to-quarter volatility in commodity prices like we always do. We don't anticipate, even if we see some of these 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 second quarter, seeing those negative crude prices.
We'll take our next question from Michael Blum of Wells Fargo.
Thanks. Good morning, everybody. Wanted to ask about ethane for next year, really. I guess, what ethane price do you think you need to see recoveries in the Bakken? Are you considering a lower tariff to incentivize some of those ethane recoveries next year? Apologize for the multi-part question here, 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. It would 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. A lot of it depends on, obviously, we have to still have the price with fees 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. Ethane does represent kind of a call option that we have, that 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.
Sheridan, we do see some additional petchem demand coming as well, right?
That's right. There's one cracker that's to be completed here in the fourth quarter of 2020. We also have an export dock that is to complete, and that has been completed, and we'll start exporting full capacity into next year. We see good demand coming on for next year, That's why we think we could see some ethane recovery for portion of the year in 2021 out of the Bakken.
Got it. Thank you very much.
We'll take our next question from Spiro Dounis with Credit Suisse.
Hey, morning, guys. First question for Walt, just with respect to leverage and getting to that 3.5x aspirational target. I think I heard in your response to Shneur that the strategy at this point is maybe steady de-leveraging with 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? Specifically what I'm thinking about is just on the M&A side and using M&A as a tool to maybe both delever as well as do something strategic. Not sure if anything screens for you on that front.
Well, we think we're going to naturally delever. I think we're shooting to 4x first. 3.5x is aspirational over time. I think getting to that 4x 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. 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. Managing the core business, managing the balance sheet is our priority. 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&A opportunities are kind of few and far between, and particularly those that are actionable, we don't spend a whole lot of time worrying about that. Right now, in this environment, stay focused on core business.
We'll take our next question from Jean Ann Salisbury 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? Is this just kind of a good of a guess?
Okay. Jean Ann, it's Kevin. I think you look at the flaring that's left, we'll still have some isolated pockets of wells and/or pads that haven't been connected, and/or we have some maybe pressure limitations. Where 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've 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. Those are the types of. You've got operational disruptions that could cause some flaring from time to time.
We'll continue to work to obviously look for ways to capture all the gas that's out there, connect a few of these, and continue to watch the pressures on our system.
Okay. Maybe a little bit lower, but I shouldn't say that like a tiny number. Okay. I just wanted to follow up on a question that was asked previously. Ethane price would not have to get all the way to $0.40 for you to start sort of recovering and getting some benefit from the Bakken. Right? I think is what you're saying. That for the portion that you market yourselves, that you could do it at a lower price and make money.
Yes, 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. 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 for a month to allow them to come in. 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 to incent ethane to come out.
We'll take our next question from Gabe Moreen with Mizuho.
Hi, good morning, everyone. If I could ask maybe a little bit about what you're seeing with the forward curve for gas here being north of $3, if you knew some of your legacy areas like the MidCon, we're seeing maybe some refracs or producer interest in some stuff like that, and if those discussions are happening?
Gabe, this is Chuck. Was that last question regarding Mid-Continent producer discussions? I didn't quite hear it.
Just with gas prices above $3, just wondering if producers are looking at refracs or more of your core areas right now?
Yeah, that's a good question. We have seen some refracs here this year, particularly last quarter. 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 two to three rigs they're talking about next year for us right now on our acreage. There might be a fourth. What they're citing is strengthening Mid-Continent gas prices for some of the gas surplus, particularly in the STACK. I hope that gives you a little bit of color on what we're hearing in the MidCon.
That is helpful. Thank you. Then two quick clarification housekeeping questions from me. One is what the expectations now are for total second half 2020 CapEx, given Q2 spending, I think some of that pull forward. Then the other is just the guidance on double-digit growth for 2021. I think last quarter you sort of sensitized it to DAPL being on or off. Are there any sensitivities with DAPL being on or off?
Gabe, this is Kevin. I'll start, Walt can chime in. As we think about CapEx, clearly with what we've spent in the third quarter, with the acceleration of some of these projects and the activity levels we saw, we are at the high end. Capital usually tapers off in the fourth quarter, especially with weather and other things. We'll definitely trend towards the upper, if not slightly above the top end of the range there, just given what we've spent year to date. 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 million-$400 million range would be solid. 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. We do feel we'd be able to support volume growth even in a DAPL shutdown scenario.
Sheridan, do you have anything to say in the event a DAPL shutdown could happen? You got the potential to be a crude transporter out of here with some of the pipe you currently operate?
Yeah, we still continue to look at whether or not we would take the Bakken, the 12-inch pipeline into crude service. As Kevin said, the producers out there have really looked at alternatives. There's a lot of alternatives beyond ours as well, rail being one of them, and obviously other pipes that may be in a better position to start up quicker than our Bakken pipe could be to convert. We still continue to investigate that to make sure it's ready to move if we need to do that based on a DAPL shutdown.
We'll take our next question from Elvira Scotto with RBC Capital Markets.
Hey, good morning, everyone. Recently we've seen an acceleration of upstream M&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 impacts of contracting? Do you think that the larger, more integrated midstream companies like ONEOK that can offer services across the value chain benefit here?
Elvira, this is Kevin. 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 play, especially as we think about the Bakken. They're looking at the reservoir over the next 10 to 20 years, not over the next three to four. That can help from the standpoint of just good, strong ratable growth over time. I don't know that we see it as a significant pro or con either way.
Got it. Thanks. A quick follow-up to that M&A question. I appreciate the comments that you made on ONEOK M&A, but I'm interested in your thoughts on overall trend that you think we could see in midstream M&A potential.
Well, look, Elvira, certainly there is some potential in the midstream space for consolidation and gathering processing. I've been saying for the better part of 15 years that there's going to be significant consolidation this year, and I've been wrong every time. 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, we've done a real good job there contractually as well as how we operate our businesses.
Really, if to the extent we do see some things in midstream, 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 risks that we don't like. Broadly speaking, on a large scale for midstream, you see some assets that are being spun out from other companies and utility companies. Some of those assets are assets that look pretty good, that could make some sense. 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 Sunil Sibal with Seaport Global Securities.
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 federal/Indian lands?
I'm sorry, I couldn't make out your question very. Your connection's kind of garbled. Maybe try the next question. We'll see if we can hear that or understand that one. The audio is really poor.
Yes. Hi. My second question was related to your capital allocation strategy. I was wondering if you have had any recent discussions with the rating agencies, and how does that figure in terms of your capital allocation strategy? Thanks.
We have regular conversations with the 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. 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. I can't speak for them, but we have a very regular dialogue with them.
Okay. Thanks for that. I'll take my other questions offline.
Thank you.
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&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 de-leveraging process.
Yeah. Michael, we always think about that. We're constantly thinking about asset rationalization. The fact of the matter is that we really don't materially have any assets that we don't consider to be core to our business. We may have assets that certainly don't generate quite as high a rate of return as others. 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. We're always thinking about those kinds of things. As we sit today, our asset collection all fits together pretty well.
Got it. Two data questions, just on the third quarter. First of all, in the Bakken, what were the well connects in September? What was the cadence? I know you did 55 during the quarter, 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 to 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 Williston rig count recovery that you could see on your dedicated acreage from the spring? Kind of dovetailing with Terry's comments about break-even 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. Yeah, the conversations with producers have gone great. They continue to get better and better. Chuck referenced lateral lengths and the frack, the completion technologies, et cetera. 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. As we talk to producers, they don't expect that to change as they continue to get better. Does that take $45 to a new $40 or vice versa? I don't know. 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. Last question. Terry, I just want to dig deeper into your clean tech and environmental comments. Some things we've kind of vaguely heard of is lithium extracted from oil field brine, hydrogen perhaps cheaply derived from old oil fields, and infield liquefaction perhaps assisting with flaring in certain basins. Acknowledging there's a lot of uncertainty over the next five to 10 years, are there any areas of transition that really stand out more for you where you could potentially participate?
Well, let me see. Hopefully, this will answer your question. When we think about our participation in a low-carbon environment, it comes in basically 3 buckets. 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 the opportunity with electrification of existing natural gas-fired equipment, and in particular, compressors. We've done some of that work. We've got a lot of electric drive machines in service, and that's growing. 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've got some projects that we're looking at that's pretty low-hanging fruit to reduce the amount of CO2 emissions. We're thinking about renewable fuels and other inert types of commodities or substances. That fit very well with our existing capability and assets. 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. 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. 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. That's, I think, a long-winded answer to your question. Hopefully, that helped.
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. I'll maybe ask one and ask the other questions offline. If I heard you right during the formal remarks, I believe you said you captured $100 million of cost reductions this year up to this point. I know there's some commentary around cost saving with shifting volumes around. I think it was $40 million-$50 million. Does that $40 to $50, is that incremental to that $100, or have you achieved some of that already? I guess a very general sort of cost reduction target that you have going into next year. I think you had $120 million last year, but just wanted to make sure that's incremental to what you've already talked about.
No, this is Kevin. The $40 million-$50 million, I believe you are talking about the Sheridan reference. That is related to kind of margin in our NGL business. That would not be included in the $130 million we expect to save from a cost savings. Those are two separate things.
Got it. Thank you.
Got it. Thank you.
We'll take our next question from Ganesh Jois 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&P segment. Just wanted to understand if there was something unique happening this particular quarter or if this is a decent runway to think of from a total OpEx perspective going forward.
The step down, you're referring to compared to the second quarter, or are 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. 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 we have worked really hard over the last several months, really since the beginning of the pandemic, to cut costs out wherever possible. We are doing things like 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. Probably the biggest driver is our contract labor. We are doing most everything ourselves at this point with our employees as volumes have left. With some process improvements and other things we found, we expect that some of that will be sustainable. You would also expect that as our volumes pick back up, the cost will go up a little bit just from that additional volume.
Got it. Thank you. That's all I had.
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 fourth quarter 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.