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ONEOK (NYSE:OKE)
Q3 2020 Earnings Call
Oct 28, 2020, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Operator

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.

Andrew Ziola -- Vice President, Investor Relations, and Corporate Affairs

Thank you, Sarah, and good morning, and welcome to ONEOK's third-quarter 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 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?

Terry Spencer -- President and Chief Executive Officer

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 during 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 had 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, needing 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 the global pandemic. Operating conditions have greatly improved from second quarter lows, but there are still uncertainties 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 toward 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 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 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 volumes. 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.

Walter Hulse -- Exec Vice President, Strategic Planning and Corporate Affairs, and Chief Financial Officer

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 1.3 times.

We also generated more than $125 million of distributable cash flow in excess of 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 third quarter from the return of curtailed volume across our system. We continue to manage our leverage toward four times or less and maintain three and a half times as our long-term aspirational goal. We ended 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 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 the curtailed volumes returned and our ability to capture previously flared gas, resulting 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 two remaining active projects, the Bakken NGL pipeline extension and Arbuckle 2 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 and 2021 for these projects and retained 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 to $400 million. 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, 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 million range. We now expect our cost saving measures to total approximately $130 million this year compared with our 2020 plan. Both September -- 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.

Kevin Burdick -- Executive Vice President and Chief Operating Office

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 had 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 for 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. 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 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.

Second, 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 2 pipeline extension in August, earlier than our target date of the first-quarter 2021. This extension includes connectivity from our Elk Creek pipeline to the Arbuckle 2 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 had seen some plants in the Mid-Continent return to recovery this month, but expect the ethane volumes on our system to fluctuate for the remainder of 2020 and into 2021.

In the Permian 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 addition of 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 totaled more than 850 with approximately 400 on our dedicated acreage. We've 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 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've had 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 four to five frac 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 two to one, the result of activity concentrated in Dakota 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. The 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.

Terry Spencer -- President and Chief Executive Officer

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 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 on 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 the 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 will do our home works to gain knowledge and prepare diligently for the future and 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, 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 live healthier, safer and more productive lives. With that, operator, we are now ready for questions.

Questions & Answers:


Operator

[Operator instructions] And we'll go ahead and take our first question from Jeremy Tonet with JP Morgan.

James Kirby -- J.P. Morgan -- Analyst

James on for Jeremy. I just wanted to start with the '21 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 300 well -- kind of the ballpark for well completions needed to kind of maintain that volumes there within Bakken?

Kevin Burdick -- Executive Vice President and Chief Operating Office

Well, Jerry, it was real hard to understand you, but let me take the first question about growth into '21. When we talk to producers in this price environment, 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 and the early parts of '21. 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 coming back in a material way in '15 and '16. And I think our conversations with customers today that would still hold.

So as we think about '21, 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, do you want to add there?

Chuck Kelley -- Senior Vice President, Natural Gas

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 the spring. So I think as you look at the strip in '21, that pretty much supports that statement.

James Kirby -- J.P. Morgan -- Analyst

Got it. So if I just understand, do you -- my next question here, I mean, just looking at seeing kind of $50 million in the G&P segment that was kind of captured here from improved commodity prices. I guess at a higher level, can you talk about how much of that is the element of an improved volume and kind of versus the fee component there? Just any color you can provide there. I appreciate the color on the G&P fees going forward, assuming the kind of $0.94.

Any color you could provide there.

Kevin Burdick -- Executive Vice President and Chief Operating Office

Jeremy, we're struggling. Was your question about the fee rate in the G&P business?

James Kirby -- J.P. Morgan -- Analyst

Yeah, sorry. Just basically, what is the kind of breakdown of color you could provider there in terms of the -- how much of that is attributable to improved volumes versus kind of the improved commodity prices?

Terry Spencer -- President and Chief Executive Officer

Jeremy, this transmission is really bad. There 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, Chuck, if you've got any commentary around the fee rate that might be helpful for Jeremy?

Chuck Kelley -- Senior Vice President, Natural Gas

Sure. Yeah, 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 two things: 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 50-50 mix between Mid-Continent and Bakken, with, of course, Mid-Continent being the lower fee margin business. So here in Q3, we saw our Rockies volumes contribute upwards of approximately 60% of that calculation. So a combination of large producers, higher fee, lower POP components, all Williston volume-related and roughly 60% of that basin mix and the average of the basin weigh.

Operator

We'll go ahead and take our next question from Shneur Gershuni with UBS.

Shneur Gershuni -- UBS -- Analyst

Hi. Good morning, guys. Hopefully, my connection is OK. Just to clarify before I ask my questions, you're basically saying that mix shift of where the volumes came from is part of the reason why the rate went up.

Is that fair to maybe characterize your last response?

Kevin Burdick -- Executive Vice President and Chief Operating Office

Yeah. That one -- I mean, again, it's a shift in both the volumes from the Mid-Con kind of decline in the higher percentage of Williston volume and then also the mix of contracts. So we had a lot of our larger, higher fee-based customers brought gas back online in a sizable way in the third quarter.

Shneur Gershuni -- UBS -- Analyst

Perfect. OK. Just moving on to my questions here. First of all, thank you for providing all the incremental data on well connections 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 '21. And to grow, you got the 25, 35, 45 scenarios.

And then, as you mentioned in the call, you got 400 DUCs that are in the mining 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, how should 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 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?

Kevin Burdick -- Executive Vice President and Chief Operating Office

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 we 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.

Shneur Gershuni -- UBS -- Analyst

In the prepared remarks, I believe, Terry mentioned that double-digit growth for '21 versus '20, which one of those scenarios are you assuming? Is it 25, 35, just trying to understand that?

Kevin Burdick -- Executive Vice President and Chief Operating Office

We haven't -- again, we haven't necessarily provided the specific link there. But again, I'd go back to the previous comments from Jeremy -- 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 '21.

Shneur Gershuni -- UBS -- Analyst

OK. And then, maybe as a follow-up question, one of your peers yesterday sort of was talking about the Williston, in general, that the producers are becoming significantly more efficient, more stages per frac, 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?

Chuck Kelley -- Senior Vice President, Natural Gas

Yeah, this is Chuck. We are. We're seeing it from our producers. I think we mentioned on last call, lateral lengths, we're seeing -- pushing out to the three-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.

Terry Spencer -- President and Chief Executive Officer

It's just that -- the bottom line of that is the breakeven costs continue to come down significantly.

Chuck Kelley -- Senior Vice President, Natural Gas

That's correct.

Shneur Gershuni -- UBS -- Analyst

Yeah. That's super helpful. And maybe one final question, if I may, for Walt. When I sort of 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?

Walter Hulse -- Exec Vice President, Strategic Planning and Corporate Affairs, and Chief Financial Officer

Well, 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 '20, early 2021. And that kind of got moved out 12 to 15 months based on the pandemic.

So I think we're still trending that range toward four times. And whether that happens on a run rate basis at the end of '21 or early 2022, we'll be headed in the right direction.

Shneur Gershuni -- UBS -- Analyst

Perfect. Thank you very much today for all the color

Operator

We'll take our next question from Christine Cho with Barclays.

Christine Cho -- Barclays -- Analyst

Good morning, everyone. I'm going to apologize in advance, but I also want to discuss Slide 7. When you talked about the 15 to 20 wells a month in the Bakken to hold volumes flat at the 1.1 or 1.2 Bcf a day level. When I combine that with your comments that you'd expect to be at least $3 billion in EBITDA next year that would to me at least imply Bakken volumes will have to hold at least from current levels.

Is your capex of 300 to $400 million next year indicate that level of well connects of 15 to 20 per month in the Bakken? And how should we think about that?

Kevin Burdick -- Executive Vice President and Chief Operating Office

Yeah, 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 that we would need would be well connect capital.

To go connect wells, we might need to add a compressor or the station or something like that. And that would be within that 300 to $400 million type range, given the environment that we're looking at today.

Christine Cho -- Barclays -- Analyst

OK. 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 cash 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 that pipe was previously full.

So should we think that there's available capacity on that system going forward?

Sheridan Swords -- Senior Vice President, Natural Gas Liquids

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. And part of the run rate you're at today is what you'll see through the fourth quarter. And then, once we get into 2021, we will -- 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.

Christine Cho -- Barclays -- Analyst

OK. Could you -- are you going to have to expand Elk Creek?

Sheridan Swords -- Senior Vice President, Natural Gas Liquids

As Kevin said in the earnings, well, 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 onto Elk Creek.

Christine Cho -- Barclays -- Analyst

Got it. And sorry, one follow-up. Would you have to pay anything to take your volumes off of Overland Pass for the last quarter, this quarter and next quarter?

Sheridan Swords -- Senior Vice President, Natural Gas Liquids

Well, 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.

Operator

We'll take our next question from Tristan Richardson with Truist Securities.

Tristan Richardson -- Truist Securities -- Analyst

Hi. Good morning. Really appreciate all the comments on '21, particularly clarifying some of the assumptions, especially on certain 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 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?

Kevin Burdick -- Executive Vice President and Chief Operating Office

I mean, I think there's clearly the potential for that. I mean that's what we talked in our opening remarks that that would be the 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 '22 as well.

Tristan Richardson -- Truist Securities -- Analyst

Very helpful. And then, I guess just -- conversely, can you see outside of a reduction in completion -- or pace of completion activity. Are there headwinds out there that would prevent you to that sort of $3 billion number in 2021?

Kevin Burdick -- Executive Vice President and Chief Operating Office

I mean that's the -- again, just other than you said 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.

Terry Spencer -- President and Chief Executive Officer

Right. Kevin, I think the other thing I would add to your comment is as we talk to the producers, certainly, they're making their decisions based upon a longer-term view of commodity prices. Now certainly, you could have -- 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.

But the fact of the matter is that industry has done some things, not only 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 phenomenon -- 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.

Operator

We'll take our next question from Michael Blum with Wells Fargo.

Michael Blum -- Wells Fargo Securities -- Analyst

Thanks. Good morning, everybody. 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, 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 '21?

Sheridan Swords -- Senior Vice President, Natural Gas Liquids

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. As 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 I think that represents 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 that thing where if volume does not show 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.

Terry Spencer -- President and Chief Executive Officer

And Sheridan, we do see some additional pet chem demand coming as well, right?

Sheridan Swords -- Senior Vice President, Natural Gas Liquids

That's right. There's one cracker that's -- to be completed here in the fourth quarter of 2020. And then, we also have an export dock that is to complete -- 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 ethane recovery for a portion of the year in 2021.

Terry Spencer -- President and Chief Executive Officer

Thank you very much.

Operator

We'll take our next question from Spiro Dounis with Credit Suisse.

Spiro Dounis -- Credit Suisse -- Analyst

Good morning, guys. First question for Walt. Just with respect to leverage and getting to that three and a half times aspirational target. I think I heard in your response to Shneur, that the strategy at this point is maybe steady deleveraging, 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 a lot of opportunity there going forward, any appetite to get more proactive here? And 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. I'm not sure if anything is screening for you on that front?

Walter Hulse -- Exec Vice President, Strategic Planning and Corporate Affairs, and Chief Financial Officer

Well, we think we're going to naturally delever. And I think we're -- we shouldn't be four times first, three and a half aspirational over time. But I think getting to that four 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.

Terry Spencer -- President and Chief Executive Officer

Yeah, Spiro, this is Terry. So while we're -- 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&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 core business.

Operator

We'll take our next question from Jean Salisbury with Bernstein.

Jean Salisbury -- Sanford C. Bernstein -- Analyst

Good morning. What drives the flaring that is still happening on your acreage and on the Bakken more broad-based? And what would need to happen next year to get it even lower? Or is this just kind of a good indication?

Kevin Burdick -- Executive Vice President and Chief Operating Office

OK. Jean, this is 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.

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. 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 a few of these and continue to watch the pressures on our system.

Jean Salisbury -- Sanford C. Bernstein -- Analyst

OK. So maybe a little bit lower, but not -- I shouldn't put on like a tiny number. OK. And then, 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? I think what you're saying that for your -- some of the portion that you market yourself, you could do it at a lower price and make money.

Sheridan Swords -- Senior Vice President, Natural Gas Liquids

Yeah. 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 plant, but that would also be with a lot of third-party volumes. And this is something that times we've done in the Mid-Continent when we think ethane may be coming into rejections. To get them come in earlier, we've reduced our fees at times to four 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 view that thing for ethane to come out.

Operator

We'll take our next question from Gabe Moreen with Mizuho.

Gabe Moreen -- Mizuho Securities -- Analyst

Hi, good morning, everyone. If I could ask maybe a little bit about what you're seeing with the poor curve for gas here being north of $3. Assuming 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 curious if any discussions are happening?

Chuck Kelley -- Senior Vice President, Natural Gas

Gabe, this is Chuck. What was the last question regarding Mid-Continent, producer discussions? I didn't quite hear it.

Gabe Moreen -- Mizuho Securities -- Analyst

Yeah. The gas prices at $3. Just wondering if producers are looking at refracs [inaudible] right now?

Terry Spencer -- President and Chief Executive Officer

Yeah, that's a good question. We have seen some refracs here this year, particularly last quarter, and I understand there's a couple of schedules 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. We're talking about next year for us right now in our acreage, there might be a fourth. And what they're citing is strengthening Mid-Continent gas prices for some of the gas refracs, particularly in the stack. I hope that gives you a little bit of color of what we're hearing in the Mid-Con.

Gabe Moreen -- Mizuho Securities -- Analyst

That was helpful. And then, two quick clarification housekeeping questions for me. One is kind of what the expectations now are for total second-half 2020 capex, given 2Q spending, I think, some of that pull forward. And then, the other is just the guidance on double-digit growth for '21.

I think last quarter, you sort of sensitized with DAPL being on or off. Are there any sensitivities with DAPL being on or off?

Kevin Burdick -- Executive Vice President and Chief Operating Office

Gabe, this is Kevin. I'll start and then Walt can chime in. As we think about capex, yes, 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 and the capital usually tapers off in the fourth quarter, especially with weather and other things. But we'll definitely trend toward the upper, if not slightly above the top end of the range there, just given what we've spent year to date.

But I think going forward about capital, the notion that we can continue to stay in the kind of a run rate to continue to grow with the customers in that 300 to $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. So we do feel we could -- we'd be able to support volume growth even in the DAPL shutdown scenario.

Gabe Moreen -- Mizuho Securities -- Analyst

And Sheridan, do you have anything to say in the event a DAPL shutdown could happen, you have the potential to be accrued transporter out of here with some pipe you currently operate?

Sheridan Swords -- Senior Vice President, Natural Gas Liquids

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, and there's a lot of alternatives beyond ours as well. Rail being one of them.

Obviously the other pipes that may be in a better position to start up quicker than our Bakken pipe could be the convert. But we still continue to investigate that to make sure it's ready to move if we need to do that based on the DAPL shutdown.

Operator

We'll take our next question from Elvira Scotto with RBC Capital Markets.

Elvira Scotto -- RBC Capital Markets -- Analyst

So recently, we've seen an acceleration of upstream M&A. What are your thoughts on this trend? I mean, 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 the ONEOK that can offer services across the value chain benefit here?

Kevin Burdick -- Executive Vice President and Chief Operating Office

Elvira, 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. And 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 display, 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 three to four. So that can help from a standpoint of just good, strong ratable growth over time.

But I don't know that we'd see it as a significant pro or con either way.

Elvira Scotto -- RBC Capital Markets -- Analyst

Got it. And then, as a quick follow-up to that M&A question, I appreciate the comments that you made on ONEOK and M&A, but I'm interested in your thoughts on overall trend that you think we can see in midstream M&A potential?

Kevin Burdick -- Executive Vice President and Chief Operating Office

So Elvira, certainly, there is some potential in the midstream space for consolidation in gathering and processing. And I've been saying for a 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 the midstream space, specifically in gathering processing, most of those, as I see the landscape today, don't really shift that well, and certainly, carry with it some risks that we don't like. But broadly speaking, on a large scale for midstream, there's some -- you see some assets that have been 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.

Operator

We'll take our next question from Sunil Sibal with Seaport Global Securities.

Sunil Sibal -- Seaport Global Securities -- Analyst

Yeah. Hi, good morning. 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 lines.

Kevin Burdick -- Executive Vice President and Chief Operating Office

I'm sorry. I couldn't make out your question. Your 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.

Sunil Sibal -- Seaport Global Securities -- Analyst

So my question -- second question was related to the capital allocation strategy. I was wondering if you've had any recent discussions with the rating agencies? And how does that figure in terms of your capital allocation strategy?

Kevin Burdick -- Executive Vice President and Chief Operating Office

We have regular conversations with the rating agencies. We have throughout this -- throughout the pandemic. We had 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, but it's part of the capital allocation process that our board thinks about every quarter. 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. It's a part of the delevering that we're seeing and 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.

Sunil Sibal -- Seaport Global Securities -- Analyst

Great. Thanks for that. I'll take my other questions offline.

Operator

We'll take our next question from Michael Lapides with Goldman Sachs.

Michael Lapides -- Goldman Sachs -- Analyst

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 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?

Terry Spencer -- President and Chief Executive Officer

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, 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 look at the landscape and the market opportunity and -- to determine if ownership of the hold 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.

Michael Lapides -- Goldman Sachs -- Analyst

Got it. And then, two related questions just on the third quarter. 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 well -- 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 in the quarter?

Chuck Kelley -- Senior Vice President, Natural Gas

Michael, this is Chuck. I know our quarterly number was 55. Frankly, I don't have the monthly breakdown in front of me. So we 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.

Operator

We will take our next question from Craig Shere with Tuohy Brothers.

Craig Shere -- Tuohy Brothers -- Analyst

Thanks for taking the question. Congratulations on a terrific quarter. First, based on conversations with producers, any color around the magnitude of potential in Williston recoveries 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 the $40 to the new $35, like what we saw in 2015, 2016 as far as spring material rig count recoveries?

Kevin Burdick -- Executive Vice President and Chief Operating Office

Craig, it's Kevin. Yes, the conversations with producers is going great. They continue to get better and better. Chuck referenced lateral lengths and the frac, the completion technologies, etc.

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 $45 to the 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.

Craig Shere -- Tuohy Brothers -- Analyst

Great. And last question. Kevin, I just want to dig deeper into your clean tech and environmental comments. I mean some things we kind of maybe heard of is lithium extracted from oilfield brine, hydrogen perhaps cheaper to derive from the old oilfields and on field liquefaction perhaps assisting with flaring in certain basins.

Acknowledging there's a lot of uncertainty over the next five to ten years, are there any areas of transition that will stand out more for you or you could potentially participate?

Kevin Burdick -- Executive Vice President and Chief Operating Office

Well, let me just -- hopefully, this will answer your question. I think when we think about our participation in a low-carbon environment, it comes in basically three buckets. First is reducing the impacts on the -- 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. And so, we've got -- 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 time frame 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.

This is a 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 fit 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 the thing -- so profitability, business strategy, all of 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 -- thanks for your question. Hopefully, that helped.

Operator

We'll take our next question from Derek Walker with Bank of America.

Derek Walker -- Bank of America Merrill Lynch -- Analyst

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 the other questions offline. But 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.

And I know there's some commentary around cost savings with shifting volumes around, it was kind of 40 to $50 million. Does that 40 to 50, is that incremental to that $100 million? Or have you achieved some of that already? And I guess is there a general sort of cost reduction target that you have going into next year. I think you had $120 million last year, but I just wanted to make sure that's incremental to what you've already talked about?

Kevin Burdick -- Executive Vice President and Chief Operating Office

This is Kevin. The 40 to $50 million, 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 million we expect to save from our cost savings.

So those are two separate things.

Derek Walker -- Bank of America Merrill Lynch -- Analyst

Got it. Thank you.

Operator

We'll take our next question from Ganesh Jois with Goldman Sachs.

Ganesh Jois -- Goldman Sachs -- Analyst

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 in this particular quarter, or if this is a decent run rate to think of from a total opex perspective going forward?

Kevin Burdick -- Executive Vice President and Chief Operating Office

The step down you're referring to is that compared to the second-quarter or you compared to last year?

Ganesh Jois -- Goldman Sachs -- Analyst

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?

Kevin Burdick -- Executive Vice President and Chief Operating Office

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 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 cost 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 costs will go up a little bit just from that additional volume.

Ganesh Jois -- Goldman Sachs -- Analyst

Got it. Thank you.

Operator

That concludes today's question-and-answer session. Mr. Ziola, at this time, I'd like to turn the conference over back to you.

Andrew Ziola -- Vice President, Investor Relations, and Corporate Affairs

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 day.

Thank you for joining us, and have a good week. Thank you, everybody.

Terry Spencer -- President and Chief Executive Officer

Thanks, Andrew.

Operator

[Operator signoff]

Duration: 81 minutes

Call participants:

Andrew Ziola -- Vice President, Investor Relations, and Corporate Affairs

Terry Spencer -- President and Chief Executive Officer

Walter Hulse -- Exec Vice President, Strategic Planning and Corporate Affairs, and Chief Financial Officer

Kevin Burdick -- Executive Vice President and Chief Operating Office

James Kirby -- J.P. Morgan -- Analyst

Chuck Kelley -- Senior Vice President, Natural Gas

Shneur Gershuni -- UBS -- Analyst

Christine Cho -- Barclays -- Analyst

Sheridan Swords -- Senior Vice President, Natural Gas Liquids

Tristan Richardson -- Truist Securities -- Analyst

Michael Blum -- Wells Fargo Securities -- Analyst

Spiro Dounis -- Credit Suisse -- Analyst

Jean Salisbury -- Sanford C. Bernstein -- Analyst

Gabe Moreen -- Mizuho Securities -- Analyst

Elvira Scotto -- RBC Capital Markets -- Analyst

Sunil Sibal -- Seaport Global Securities -- Analyst

Michael Lapides -- Goldman Sachs -- Analyst

Craig Shere -- Tuohy Brothers -- Analyst

Derek Walker -- Bank of America Merrill Lynch -- Analyst

Ganesh Jois -- Goldman Sachs -- Analyst

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