Oneok Inc (OKE) — Q3 2020 Earnings Call Transcript

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. Third quarter results were driven primarily by curtailed volume returning to the system and increased ethane recovery. The majority of volume across our operations has now exceeded pre-pandemic levels and better represents our volume expectation 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 curtail volume on our system returned, but 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 Wilson 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% and 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 outlook for 2021 and today the backdrop is even stronger. Volumes in the Bakken ranch throughout the third quarter set 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 remain focused on serving customer needs and preparing our assets for the eventual return of curtailed volume. The key infrastructure projects we completed prior to the pandemic create substantial capacity for future growth as markets continue to improve. With that I will turn the call over to Walt.

Thank you, Terry. ONEOK's 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 towards 4 times or less and maintain 3.5 times as our long-term aspirational goal. At the end of the third quarter, we had 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 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 of 2020 and first quarter 2021 respectively. Third quarter CapEx included dollars pulled forward from the fourth quarter and 2021 for these projects and routine growth capital primarily for well connects and maintenance activities. We have now substantially completed all of our active capital growth projects. We continue to expect a run rate of total annual capital expenditures including maintenance and growth of $300 million 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 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. Well, 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'm now turning 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 liquid 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 more than a 50% increase from the second quarter of 2020. The return of curtailed production, completion of ducts, and increased flared gas capture have contributed to higher volumes. As the primary NGL takeaway provider from the region, our natural gas liquid 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 is 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 Williston 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 with 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 other fast pipelines. In the Mid-Continent region, we completed the Arbuckle 2 pipeline extension in August earlier than our target date of the first quarter of 2021. This extension improves 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 have resulted in significant ethane recovery across the Mid-Continent region through a good portion of the third quarter. By raw feed throughput volumes in the region increased 9% compared with the second quarter of 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 that expect 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 of 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 of 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 to $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 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 level and significant duck inventory that is profitable to complete in this price environment, the rigs currently on the system, and some additional flare gas opportunities we have ample inventory to support current volume levels through 2021 assuming no increase in producer activity during that time frame. Of course, any additional producer activity in the basin would present upside resulting in more wells drilled and/or completed driving higher volumes and ultimately earnings for ONEOK. Slide 7 in our earnings presentation has been updated to illustrate the ability to maintain current natural gas processing levels with minimal well completions. This slide is meant to be a representation not guidance or an indication of our expected future volumes. For reference there are 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. Flaring rates have continued to increase and remain well over two to one as a 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. 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.

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 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 valuing ways to improve our ESG-related performance and enhance our long-term business sustainability. This includes planning and preparing for potential changes to our industry, customer needs or the broader demand for energy. There has been much discussion about the future state of the energy industry and we get asked frequently what our role could be in a low carbon world. The answer is simple: ONEOK has always promoted a business culture prioritizing safety, environmental responsibility, and profitability in all that we do and as we always have we 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 accepting 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 are compatible with many of these types of projects, but they still need to make strategic sense for our business. In many cases, technology or large-scale application may be further into the future, but we'll continue to evaluate opportunities that fit within our businesses because we absolutely believe that our large and extensive infrastructure has a vital role to play in the long-term energy transition, and while we evaluate new and future opportunities, I want to thank our employees for doing what they do best: operating our assets safely and responsibly and transporting the essential NGLs and natural gas that are used to heat your home, generate electricity, and create the many end-use products that help us lead healthier, safer and more productive lives. With that operator, we are now ready for questions.

It’s James speaking for Jeremy. I wanted to begin by discussing the 2021 guidance for double-digit growth. Given the current market situation, what price assumptions are included in that guidance? Also, regarding the well completion guidance, what is the estimated number of well completions required to keep Bakken volumes stable?

Well, Jeremy, you were a little hard to understand there. But let me take the first question about growth into ’21. We talked to producers in this price environment, they clearly the ducks are profitable to complete. I mean, I think that's the focus especially as we look as you move through the rest of this year in the early parts of ’21, you've got that substantial duck 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 ducks work well as far as the economics, you get north of 45 that's when we saw rigs come back in material ways in 15 and 16, and I think our conversations with customers today that would still hold. So if 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?

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 forecasts and drill schedules and what they've provided the expected pace of completion the first half of the year to be duct-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.

Thank you for the information. Regarding my next question, I understand that there is approximately 15 million in the G&P segment attributable to improved commodity prices. Can you clarify how much of that is due to increased volume and what portion is related to fees? Any insights you can offer on the GPC going forward, assuming it remains at $0.94, would be appreciated.

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

Yes. Sorry. Just basically what is the kind of breakdown of color provided in terms of how much that is attributable to improved volumes versus kind of the improved commodity prices?

Jeremy, this transmission is really bad. It must be a bad connection. So we're having real difficulty understanding and just hearing the 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.

Sure. We can discuss what led to our quarter-over-quarter increase in the fee rate. It's really a combination of two factors: basin mix and contract mix. As we noticed our curtailed volumes returning from the Williston basin, especially from our large producers, these producers have contracts that include either a fee only or a high fee with a lower percentage of proceeds. When those curtailed volumes resumed, the mix of the basin contributions to the average fee changed. In the second quarter, there was a nearly equal mix between Mid-Continent and Bakken, with Mid-Continent representing the lower fee margin business. In the third quarter, we observed that our Rockies volumes contributed about 60% to that calculation. Therefore, the combination of large producers, higher fee levels, and the basin mix—where roughly 60% of that average was determined by the basin weighting—resulted in the fee rate increasing to $0.94.

Hi, good morning guys. Hopefully my connection is okay. Just to clarify before I ask my questions, you were basically saying the makeshift of where the volumes came from is part of the reason why the rate went up is that a way to characterize your last response?

Yes, it's a change in both the volume from the Mid-Continent, which is decreasing, and the increasing percentage of volume from the Williston. Additionally, a significant number of our larger, higher fee-based customers resumed gas operations in a notable way during the third quarter.

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 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, suggest 15 average well completions in months sort of keeps you flatter I guess that's about 180 completions for the year for 21. And to grow you've got the 25, 35, 45 scenarios and then as you mentioned in the call you've got 400 ducks that are in the money right now but maybe they're not all in the right areas. So when I sort of piece that together if I see let's say half the ducks get completed and you mentioned that you have eight rigs running on your acreage which gives you what two wells per week per month. It sort of seems like you can be materially above the 28 average well completion that you sort of highlighted and that you saw in September. So when I think about that all else equal that you can have a material increase in production year-on-year. Am I being too simplistic in my analysis here or is that the way to be thinking about that?

No. Shneur, this is Kevin. I think that's exactly how we're looking at it. I mean that duck inventory provides you a substantial runway for growth and when you add the rigs on top of that, we do expect to capture a little more gas and that gives you that volume strength that we foresee.

In prepared marks 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.

We're thinking about this in the context of a $40 to $45 type environment as we look at ‘21.

Okay. And then maybe it's a follow-up question: one of your peers yesterday sort of was talking about 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 these efficiencies are going to continue to go up and maybe even faster than they had previously. Is that something that you're hearing from your customers as well too? Is that something that you're seeing as well also?

Yes, this is Chuck. We are seeing that from our producers; I think we mentioned on the 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 greater production efficiencies and of course, the GORs continue to rise in the basin so when you look at those three components it's all painting a pretty good picture for these new wells coming online.

And Chuck that the bottom line to that is that break-even costs continue to come down significantly.

Yes that's super helpful and maybe one final question if I made for Walt and I sort of think about the results for the third quarter by annualizing and 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 and 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 what 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'll still trend in that range towards 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.

Perfect. Thank you very much today for all the color.

Good morning everyone. I'm going to apologize in advance, but I also want to discuss slide 7. When you talk about the 15 to 20 wells a month in the Bakken volume being flat at the 11 or 12 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 to 400 million next year indicate that level of well connects of 15 to 20 per month in the Bakken or how should we think about that?

Yes, Christine, this is Kevin. I believe we should be able to achieve that. We have sufficient processing capacity, so what we would need is to connect additional capital. We might have to add a compressor or a station, but that would be manageable.

I would like to address the situation regarding the pass. I appreciate the comments made in the prepared remarks about moving your Powder River Basin to Arbuckle. However, pass earnings declined in the second quarter and this trend has continued into the third quarter. Did you transfer volumes from the Bakken NGL and the other path to Elk Creek, or did a major customer exit the system? I was under the impression that the pipeline was previously at capacity, so should we expect there to be available capacity on that system moving forward?

Christine this is Sheridan. We did move some volume off of OPPO onto the Elk Creek Bakken system in both the second and third quarter and 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 it on our own system, we think due to cost savings that we will see approximately a $40 million or $50 million uplift in earnings.

Okay. To do that is you going to have to expand Elk Creek?

As Kevin says in the earnings call, we have a low-cost expansion that we will complete by the end of the year and that will allow us to move all the volume off of OPPO onto Elk Creek.

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

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.

Hi good morning. I really appreciate all the comments on ’21 particularly clarifying some of the assumptions in an especially uncertain environment. I mean you've noted that customer conversations are encouraging and rigs could potentially return in the spring which would presumably accelerate that completion activity. So to the extent of return of rigs occurs as you noted any of that return would be upside to the general assumptions driving the 3 billion plus 2021 expectation?

I mean I think there's clearly the potential for that. I mean that's what we talked in our opening remarks that 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 ducks 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.

Really helpful and then I guess just conversely, do you see outside of a reduction in completion or pace of completion activities? Are there headwinds out there that would prevent you to that sort of $3 billion number in 2021?

I mean that's the, again just other than you said that the activity levels and we all know the risk that would come with that might drive that but other than that the thing I think we just keep coming back to is, we've got plenty of processing capacity. We 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.

Right. 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. Now certainly you could have, you've got OPEC risk out there and 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 the industry has done some things not only the way they operate but also in the way they manage their markets and 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. But 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 and commodity prices like we always do but we don't anticipate even if we see some of these other phenomena, other things happen like OPEC or the COVID. We don't think we're going to get back in a scenario like we saw in the springtime which was a huge impact to what transpired in the second quarter seeing those negative crude prices.

Thanks good morning everybody. I wanted to ask about ethane for next year really. Do you I guess what ethane price do you think you need to see recoveries in the Bakken and would you consider, are you considering a lower tariff to incentivize some of those ethane recoveries next year and then apologize for the multi-part question here. But did any of that in any ethane recovery assumed in your forecast or expectation for double-digit growth in ‘21?

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 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 incentivize that ethane to come out if we think that's the best thing to do. But a lot as it depends on obviously we have to get still half 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. But nothing does represent kind of a call option that we have that volume doesn't show up that would force people to go into different areas to extract that thing where if volume does not show effect like we think it is next year you could see I think the economic coming out of the Bakken which would support our growth rate for next year.

And Sheridan, we do see some additional demand coming as well right.

There is one cracker that will be completed in the fourth quarter of 2020, and we also have an export dock that has been completed, allowing us to start exporting at full capacity into next year. We anticipate good demand for next year, which leads us to believe we could see some recovery in ethane for part of 2021.

Got it. Thank you very much.

Good morning guys. First question for Walt, just with respect to leverage and getting to that 3.5x aspirational targets. I think I heard your response to the scenario that the strategy at this point is maybe steady deleveraging with cash 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 well maybe there's less opportunity there going forward and the 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 not sure if anything screens for you on that front?

Well, we think we're going to naturally delever and I think we're shooting for four times first 3.5 aspirational over time, but I think getting to that four-time 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. This is Terry. So while we always think about acquisitions and opportunities to add assets or businesses to a 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.

Hi, good morning. What drives the flaring that is so happening on your acreage and in the Bakken more broadly and what would need to happen next year to get it even lower or is it just kind of a bit of a depth?

Okay, Jean it's Kevin. I think you look at the flaring that's left there, 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 production has 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 of 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.

Okay. So maybe a little bit lower, but not I shouldn't put in like a tiny number. Okay 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 recovering and getting some benefit from the Bakken right? I think that for your sort of portion that you market yourselves you could do it at a lower price and make money.

Yes. We could always assure it and we could always lower our fees to make it economical to recover ethane. We always have that option and that's not only with our own volume coming off of our plants, but that would also be with a lot of third-party volumes and this is something that times we've done in the Mid-Continent when we think ethane may be coming into rejection to get it to 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 it's definitely within our wheelhouse to do that ethane to come out.

Good morning everyone. I would like to ask about your observations regarding the gas situation in the northeast through the Bakken. In the legacy areas like the Mid-Con, are you experiencing any refracts or interest from producers, and how are those discussions progressing?

Gabe, this is Chuck. With that last question regarding Mid-Continent producer discussions I didn't quite hear.

I didn't quite hear that last question regarding Mid-Continent producer discussions.

Yes. That's a good question. We have seen some refracts here this year particularly last quarter and I understand there's a couple scheduled here in our Q4. Other than that Mid-Continent producers we've spoken with and 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 maybe there might be a fourth and what they're citing is strengthening Mid-Continent gas prices for some of the gas your place particularly in the STACK. I hope that gives you a little bit of color of what we're hearing in the Mid-Con.

That was helpful. Thank you. I have two quick clarification questions for you. First, what are the expectations for total capital expenditures in the second half of 2020 considering future spending, as it seems some of that has been pulled forward? The second question is regarding the guidance for double-digit growth in 2021. Last quarter, you mentioned some uncertainties—are there any sensitivities associated with being on or off in that regard?

Gabe this is Kevin. I'll start and Walt can chime in. If you think about CapEx, yet clearly with what we 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 capital usually tapers off in the fourth quarter especially with weather and other things. But we'll definitely trend towards the upper if not slightly above the top end of the range there just given what we've spent year-to-date. But when we think going forward about capital, the notion that we can continue to spend the kind of run rate to continue to grow with the customers in that $300 million 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 because our customers as we talked 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 DAPL shutdown scenario.

And Sheridan, do you have anything to say in the event of 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?

Yes. We still continue to look at whether or not we would take the Bakken 12-inch pipeline into crude service. As Kevin said, producers out there have really looked at alternatives and there are a lot of alternatives beyond ours as well. Rail being one of them and all the other pipes that may be in a better position to start up quicker than our Bakken pipe could be to convert. But we still continue to investigate that to make sure it's ready to move if we need to do that based on that DAPL shutdown.

Hey good morning everyone. 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 if you see any potential impacts of contracting, and do you think that the larger more integrated midstream companies like 10 that can offer services across the value chain benefit here?

Elvira, it's Kevin. I don't know that we see, I don't think we definitely don't see that as a negative. We've got a lot of very large customers. I don't see it as a contract issue at all. We've got the vast majority of our contracts are long term. They are 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 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 the standpoint of just good strong weighable growth over time. But I don't know that we see it as a significant pro or con either way.

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

There is likely to be considerable consolidation this year, although I may have been mistaken in the past regarding this. We do see some opportunities for private equity to consider entering the market with certain assets. However, most of these assets do not align with our strategic focus. We have made substantial efforts to manage our risks associated with well head operations and have successfully navigated this both contractually and operationally. In terms of midstream assets, particularly in gathering and processing, many of them do not seem to be a good fit for us and present risks that we prefer to avoid. Generally, there are some attractive assets being divested by various companies that might be worth exploring. Nonetheless, we will carefully evaluate the landscape and continue to be disciplined and thorough in our approach to potential acquisitions, as we have always done.

Yes, hi, good morning. I just had a question, and if you could remind us in terms of your volumes or the cash flows explorer with drilling on federal/Indian lands?

I'm sorry I couldn't make out your question; the connection's kind of garbled so maybe try the next question. If we can hear that and understand that one the connections really, the audio is really poor.

Yes. Hi. So my question, second question was related to the capital allocation strategy. I was wondering if you have had any recent questions with the rating agencies and how does that trigger in terms of your temporary allocation strategy? Thanks.

We have regular conversations with the rating agencies. We have 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 that 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 given the coverage we saw in this quarter and what we think about moving forward is supportive of the delevering that we're seeing and that the rating agencies have been looking at as well. So I can't speak for them, but we have a very regular dialogue with them.

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

Yes. 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 at that 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 quarter ONEOK, you have a pretty integrated system but just curious how you're thinking about that as a potential path to accelerating the deleveraging process.

Yes Michael, we always think about that. We're kind of 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 high a rate of return as others. So we'll always think about those and we'll look at the landscape and the market opportunity and to determine if ownership of the whole value for somebody else is greater. So we're always thinking about those kinds of things that as we sit today our asset collection all fit together pretty well.

Got it. And then two data 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 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.

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 wells and recovery that you can see on your dedicated acreage from the spring and kind of dovetailing with Terry's comments about break-even costs falling are you getting body language that $40 is the new $45 that like what we saw in 2015/2016 as far as spurring material rig count recoveries?

Hi Craig, this is Kevin. Yes, the conversations with producers has gone great they continue to get better and better. Chuck referenced lateral lengths and the frac 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 I think in our investor decks shows year-over-year how the type curves have improved every year and numbers right now are about increasing activity not about shutting activity down.

Great. Thank you. And last question sorry I just saw a dig deeper into your insights and environmental comments. I mean some things we kind of vaguely heard of is lithium extracted from oilfield brine hydrogen perhaps cheaply derived from old oilfields and in-field liquefaction perhaps assisting with flaring in certain basins acknowledging there is a lot of uncertainty over the next five to ten years are there any areas of transition that really stand out more for you or you could potentially participate?

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. The first is reducing the impact from our existing assets and reducing our emissions. We've got opportunities to do that in terms of enhanced pipeline integrity and leak protection or leak prevention. We also have our opportunity with electrification of existing natural gas-fired equipment and in particular compressors and so we've got it. We've done some of that work. We've got a lot of electric drive machines in service and that's growing and we're looking at continuing to do that as we go out over a 10-year 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 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 these things have to make sense with that broader objective to be a profitable company and to make us better and to reduce our impact on the environment. So that's kind of how we think about it. We're probably not going to invest in projects that absolutely don't have a fit or don't connect in some form or fashion strategically with our core business and our core capability as a midstream company. So that's, I think a long-winded answer to your question. Hopefully that helped.

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. But if I heard you right during the formal remark, I believe you said captured 100 million cost reductions this year up to this point and I know there is some commentary around costings with shifting volumes around it was kind of 40 million to 50 million. Does that 40 to 50 is that incremental to that 100 or have you excused some of that already and I guess a very general sort of cost reduction target that you have going into next year. I think you had 120 last year, but I just wanted to make sure that's not incremental to what you've already talked about?

Now this is Kevin. The $40 million 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 a cost savings. So those are two separate things.

Hi, thank you for taking my question. Just following up on Derek's question on the cost. 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?

With the step down you're referring to the compared to the second quarter or you compared to last year?

Both actually because I guess you have many more plants that are online this year than last year and yet your numbers were meaningfully lower. So just curious if there is something happening unique to this quarter if this is the new normal in terms of cost structure?

No. I don't know that I'd say it's a new normal, but clearly when we have worked really hard over the last several months really since the beginning of the pandemic to cut costs out wherever possible. So we are doing things like there are, we have compressor stations that we can reroute gas and shut down compressor stations and there are a couple of plants in the Mid-Con that we have temporarily idled that pulls costs out. You don't need as much materials and services and probably the biggest driver is our contract labor. We are doing most everything ourselves at this point with our employees as volumes have left. So with some process improvements and other things we found, we expect that some of that will be sustainable but you would also expect that as our volumes pick back up the cost will go up a little bit just from that additional volume.

Got it. Thank you. That's all I had.