Good day and welcome to the ONEOK Third Quarter 2021 Earnings Call. Today's conference is being recorded. At this time. I would like to turn the conference over to Andrew Ziola. Please go ahead sir.

Thank you, Todd, and welcome to ONEOK third quarter 2021 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. Statements made during this call that might include one of expectations or predictions should be considered forward-looking statements and are covered by the Safe Harbor provision of the Securities Acts of 1933-1934. 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. Just a reminder, before we turn it over to the conference coordinator for Q&A, we ask you that you limit yourself to one question and one follow-up in order to fit in as many of you as we can. With that, I'll turn the call over to Pierce Norton, President and Chief Executive Officer. Pierce?

Thanks, Andrew. And good morning, everyone. We appreciate your interest and investment in ONEOK. And thank you for taking your time to join us today. With me on today's call is Walt Hulse, Chief Financial Officer and Executive Vice President, Strategy 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 Charles Kelly, Senior Vice President, Natural Gas. Yesterday we announced strong third quarter earnings results and increased our 2021 financial guidance expectations. Our Third Quarter results were driven by NGL and Natural Gas volume growth on our system. The result of increasing producer activity and improving market demand. As world economics continue to recover from the pandemic, we're seeing demand continue to recover for natural gas and NGLs. And we're focused on helping to meet that increasing demand for these critical energy products, particularly as we head into the winter months. As we look forward, we continue to coordinate with our customers on future growth expectations and are focused on innovation throughout the Company. In September, we announced a greenhouse gas emissions reduction target, marking another major environmental milestone for our Company. Our goal is to achieve an absolute 30% reduction or 2.2 million metric tons of our combined Scope 1 and 2 emissions by 2030, compared with 2019 levels. We will undertake a number of strategic emission reduction measures to meet this target, including the further electrification of certain natural gas compression assets, implementing additional methane mitigation through best management practices, system optimization in collaborating with our utility providers to increase the use of low carbon energy for our operations, just to name a few. As we continue to evaluate low carbon opportunities, we remain focused on those that will complement our operations and capabilities while providing long-term stakeholder value. As we have additional detail on specific projects or future emission reduction activities, we will share that information and our progress toward our 2030 target. I will turn the call over to Walt Hulse to discuss our financial performance.

Thank you, Pierce. With yesterday's earnings announcement, we once again increased our 2021 financial guidance expectations and narrowed our ranges. We now expect net Income of $1.43 billion to $1.55 billion and adjusted EBITDA of $3.325 billion to $3.425 billion with a midpoint of $3.375 billion. This represents a 10% increase in our net income and EPS guidance midpoints and a 5% increase in our adjusted EBITDA midpoint compared with our previous guidance. Our higher expectations are driven by continued volume strength in the Rocky Mountain region and Permian Basin, increased demand for natural gas storage and transportation, and higher commodity prices. Our 2021 capital expenditures are expected to be closer to the higher-end of our guidance range of $525 million to $675 million as a result of increased producer activity and project timing. We continually work with our customers to evaluate their future capacity needs and supply expectations, and we'll align our projects and capital investment with those needs. Our outlook for growth in 2022 continues to strengthen, driven by increasing producer activity and rising gas to oil ratio in the Williston Basin, along with the recent completion of our Bear Creek plant expansion. Additionally, new ethane demand from new and expanding petrochemical facilities is expected to come online before the end of the year. Kevin will provide more detail on each of these shortly. Now for a brief overview of our third quarter performance. One of third quarter 2021 net income totaled $392 million or $0.88 per share. A 26% increase compared with the third quarter 2020, and a 15% increase compared with the prior quarter. Third-quarter adjusted EBITDA totaled $865 million dollars, a 16% increase year-over-year and an 8% increase compared with the second quarter of 2021. Our September 30 net debt to EBITDA on an annualized run-rate basis was 4.0 times, and we have line of sight to be in sub 4 times in the near future. We ended the third quarter with no borrowings outstanding on our $2.5 billion credit facility, and nearly $225 million of cash on the Balance Sheet. We continue to proactively manage our Balance Sheet and upcoming debt maturities. Earlier this week, we redeemed the remaining $536 million of senior notes to February 2022. Our next debt maturity is not until October of 2022. In October, the Board of Directors declared a dividend of C/93.5 or $3.74 per share on an annualized basis, unchanged from the previous quarter. I will now turn the call over to Kevin for an operational update.

Thank you, Walt. In our Natural Gas Liquids segment, total NGL raw feed throughput volumes increased 5% compared with the second quarter of 2021, and 10% year-over-year, averaging nearly 1.3 million barrels per day. Our highest NGL volume to-date. Third quarter raw feed throughput from the Rocky Mountain region increased 5% with the second -- compared with the second quarter, 2021, and nearly 50% compared with the third quarter, 2020. Volume growth was driven by increased producer activity in the region, ethane recovery and increasing volumes from recently connected third-party plants, including a 250 million cubic feet per day third-party plant that came online in July. Roughly throughput volumes from the Mid-Continent and the Permian Basin also increased. Permian volumes increased 12% compared with the second quarter 2021, driven by higher ethane recovery and producer activity levels. We also connected an additional third-party plant in the Basin during the quarter. The segment was also able to utilize our integrated assets to capture the benefit of location and commodity price differentials during the third quarter, providing additional earnings on top of our primarily fee-based results. Petrochemical demand continues to strengthen as facilities have returned to normal operations following Hurricane Ida and as the pandemic recovery continues. Who new petrochemical plants coming online before the end of the year could provide more than 160,000 barrels per day of additional ethane demand once fully operational. This additional capacity combined with strong ethane exports, should support a wider ethane to natural gas differential in 2022. Ethane volumes on our system in the Rocky Mountain region increased compared with the second quarter 2021, as we incented additional ethane recovery during the third quarter. Recovery continued in October, and is also expected throughout November, given current regional natural gas and ethane prices. In other regions, we continue to forecast partial ethane recovery in the Mid-Continent and near full recovery in the Permian for the remainder of the year. All of these assumptions are included in our increased financial guidance for 2021. Any additional ethane recovered would provide upside to our 2021 expectations. Discretionary ethane on our system is now more than 225 thousand barrels per day. Of that total opportunity, more than a 125 thousand barrels per day are available in the Rocky Mountain region and a 100 thousand barrels per day in the Mid-Continent. As NGL volumes continued to grow across our systems, so does the discretionary ethane. Moving on to the Natural Gas Gathering and Processing segment. In the Rocky Mountain region, third quarter processed volumes averaged nearly 1.3 billion cubic feet per day. A 2% increase compared with the second quarter of 2021, and a nearly 25% increase year-over-year. Scheduled plant maintenance at 4 of our processing facilities, which have since come back online, decreased third quarter volumes by approximately 30 million cubic feet per day for the quarter. We estimate that approximately 14 to 15 rigs, which can drill approximately 300 wells per year, is enough to maintain 1.4 billion cubic feet per day of production behind our system. Any additional rigs combined with the rising gas-to-oil ratios of wells already connected to our system, would provide additional volume growth. Conversations with our producers in the region continue to point to higher activity levels through the end of the year and into 2022. There are currently 32 rigs and 10 completion crews operating in the basin with 17 rigs and 5 completion crews on our dedicated acreage. This is more than enough activity to grow gas production on our acreage. In addition to the rigs currently operating in the Basin, there remains a large inventory of drilled but uncompleted wells with more than 520 basin-wide and approximately 300 on our dedicated acreage, compared with about 400 ducks on our dedicated acreage at this time last year. In the third quarter, we connected 72 wells in the Rocky Mountain region. And in October, we connected more than 30 additional wells. Based on the most recent producer completion schedules, we still expect to connect more than 300 wells this year. With our Bear Creek plant expansion and related compressor stations now complete and in-service, we should see a significant number of well completions in the fourth quarter in Dunn County as producers had time their completions with the startup of our expansion to avoid flaring. The new plant will accommodate increasing volumes as it ramps to full capacity over the next 2 to 3 years. With Bear Creek 2s completion, we now have approximately 1.7 billion cubic feet per day of processing capacity in the Basin. We continue to see increased activity in the Mid-Continent region with 2 rigs now operating on our acreage and ten wells connected during the third quarter. Sustained higher natural gas and NGL prices to drive a continued increase in activity next year. During the third quarter, the gathering and processing segments fee rate averaged a $1.02 per MMBtu compared with $0.94 per MMBtu in the third quarter of 2020. Changes in our average fee rates continued to be driven by our volume and contract mix, each quarter. We still expect the fee rate for 2021 to average between $1 and $1.05 per MMBtu. Under the natural gas pipeline segment. This segment is stable, fee-based earnings continue to drive solid results with adjusted EBITDA, increasing 8% compared with the prior quarter. As we entered the winter heating season, we continue to see increased interest from customers for additional long-term transportation and storage capacity on our system following the extreme winter weather event earlier this year. The segment's market connected pipelines and more than 52 billion cubic feet of natural gas storage provide critical services to customers year around but especially during the winter. As always, we're working with our customers to understand their needs and to help meet increasing demand in the coming months. Pierce, that concludes my remarks.

Thank you, Kevin. The strong results for this quarter underscore the quality of our assets and the hard work and dedication of our more than 2,800 employees. I'm very proud of the fact that our employees remain disciplined and focused on the importance of safety, reliability, and the responsible operations of our assets. The first 9 months of this year has set up well for the end of the next year, the Company-wide earnings growth in 2021, and have laid the foundation for continued growth next year. With that Operator, we're now ready for questions.

Thank you. [Operator Instructions]. We'll take our first question from Shneur Gershuni with UBS.

Hi, good morning, everyone. Maybe to start off, I was wondering if we can talk about tailwinds into 2022. You gave some pretty good color about well completions in the presentation there. It sounds like you've got 100 wells left to complete for this year out of 300 with only 2 months to go. You've got Bear Creek now in service. Is it also fair to assume that you've potentially have some PPI inflators on some of your assets like Bear Creek and so forth? And so just wondering how to think about ONEOK as we head into 2022. In the past, you've talked about a $3.5 billion to $4 billion upside potential. Is that the case? Are these tailwinds stronger now? Just wondering if you can give us some color as to how do you think of the tailwinds right now, as we head into 2022.

Sure. This is Kevin. I think there's multiple answers in that question. 1. When we think about tailwinds into '22, I really go more towards the activity levels we're seeing in the Bakken with the rigs, with the DUC Inventory, with the rising GORs. We're seeing really nice activity in volume growth in the Permian. So I kind of point to that core volume growth. In addition to that, you've got, like I said in the remarks, ethane demand coming on the system, which could drive additional ethane recovery as we think about 2022. So that's where I think the tailwinds are. But to your -- you ask a question there about inflators on our contracts. In our NGO segment and our G&P segment, the vast majority of our contracts do have escalators on the fee rates. So we're covered as we think about inflation and other things like that, so those contracts are covered.

Okay. You're still good with the range from before? Okay. And maybe just given their leverage trajectory curious about what kind of return of capital auctions or potentially considering when you hit your leverage targets mid next year. Could we potentially see a dividend increase or buybacks on the table? Just need color on that as well too, please.

Sure, Shneur. This is Walt. We are very pleased to have achieved that. 4.0 here in the third quarter. We want to continue to see that trend lower and so we're not going to stop looking for that debt rejects section and then improving debt to EBITDA ratio. The other thing with free cash flow is it gives us the opportunity to invest in our capital growth as we go forward, utilizing free cash flow and not having to finance. Obviously as we get further and further along into the reduction, our options open up. But at the moment we're focused on debt reduction and using our free cash flow for high return projects.

Great, perfect. Thank you very much. Appreciate the comment today.

Great

Thank you.

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

Morning. If I could start with the incent ethane extraction in the back -?end. The? quarter was, I mean, a little noisy with a number of plants being offline. So it's kind of hard to tell on a sequential basis, but can you just give us an idea of -- I think in your prepared remarks that you said, you continue to incent ethane, what the magnitude of the increase was on a quarter-over-quarter basis. And the Bellevue spread over Ventura Gas didn't seem like it would incentivize ethane extraction. So should we assume it's because of your exposure to ACO? And I know you're not going to tell us what your exposure to ACO is but can you give us an idea of what your limitations and constraints would be so that we can try and figure out, maybe what your max exposure could be?

Christine, this is Sheridan. What I would tell you is, when we look at the opportunity to incentivize ethane, we look at what we could sell gas at for at the gas plant, not at been juror. We look at what's going on in the marketplace, what the market is offering us for gas price at the plant, and then we buy it. If we choose to incentivize that, we buy the ethane at that price or slightly better than that price to go in. So you can't really use Ventura or ACO. You have to look and see what is happening at the gas plant at the time. In terms of volume, we -- as we said in remarks, we did incentivize more ethane in the third quarter than we did in the second quarter. At this time, we're not going to give you an idea how much more, but we did incentivize more in the third quarter.

And would it be safe to assume that you could incentivize even more like on a fiscal basis, going forward?

Yes. Especially as volumes grow in the basin and grow on our -- in our G and P segment, we do have an opportunity to incentivize more ethane. But as I said in previous, we look at what's going on in the marketplace, whether the prices are an all basis, to see how much we think is the right amount of ethane to bring out. So we don't push other basins that we have operations into rejection.

Okay. And then I guess when we think about the ethane demand that is ready to ramp up, how do you guys think about the risk to the operational crackers not running at full utilization if gas prices and I think prices get too high?

What I would say there is still a very strong spread between ethane and ethylene. And so it looks like the crackers have plenty of room to continue to run. Now with the new crackers run at full rate, we think they will, but they need to run it more. Ethane needs to be crack today than has been because of that wide ethane to ethylene spreads. So we see good volume going forward. And then you couple that with the exports that are coming online, we expect stronger export demand in 2022 than we've seen. in 2021, specially as additional crackers come on in China.

Great. Thank you.

Thank you. We'll take our next question from Jeremy Tonet with JPMorgan.

I think on prior calls, you talked about a low double-digit increase for EBITDA versus what a midpoint of 3.2 billion of EBITDA at that point in time with the guidance. And I'm just wondering if that's a fair way to think about it? Commodity prices look like they're higher than what was quoted in the first call there. But just trying to update, I guess how you guys are thinking about 2022 now versus what you had laid out in the first quarter.

Jeremy, this is Walt. I think when we laid it out in the first quarter, our guidance at that point was 3.050. Obviously, with the strength that we've seen build throughout the year, we already achieved what was out there at that point in time. What I would comment on is that quarter-to-quarter, we have seen everything strengthened in our business, whether it'd be producer activity, commodity prices. So all of the trends are headed the right direction. We think that we're going into '22 with very good tailwind, and we will give you our '22 guidance in February.

Got it. That makes sense there. And maybe just pivoting towards DC for a minute and granted it's a pretty uncertain outlook there, we have a very cloudy crystal ball. But just wondering if you could offer any thoughts on what you might be looking for out there and how that could impact one of the higher 45Q, or a minimum tax, or anything else that is on your mind at this point?

Well, the rest of the alternative minimum tax and there's still quite a few moving parts right now. If it is enacted, it's unclear at this point how it will interplay with bonus depreciation, which is in place for the next several years and has been in place. It's unclear how it will interplay with the interest limitations that are already in place on the NOL utilization. And also the a billion-dollar threshold maybe increasing making the whole conversation somewhat irrelevant. So we're on top of it. We've got a team that as watching the developments there and we will continue to do that. But at the end of the day, even in its worst case, we wouldn't see it changing our progress on deleveraging or being able to fund our capex going forward.

Got it. Thank you for that. That's a very helpful answer.

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

Hi. Good morning. North Dakota state wide clearing increased in recent months as you show on page 8. Can you talk about the reasons for that? And if it's an indicator that it might be tough to get all of the expected gas production growth going forward. Notably ONEOK 's acreage glaring hasn't increased, so maybe it's different for you all look processing capacity, but just wondering about the trends in wider North Dakota versus your.

Jean Ann, this is Kevin, I'll chuck and chime in as well but I think what you saw going on through the summer is you had several outages at facilities. We've talked about some of the facilities we had down and while the majority of the cases producers are then curtailing that volume, sometimes you'll see a little tick up in flaring. And the same with some I know third-party plants that were going through some expansions and other maintenance activities during the summer. I don't think that's a trend. I think it's going to trend back the other way as we get into what I'd consider more normal operational run rates for these facilities. The conversations we're having with all our customers up there and I'm sure third-parties are the same way. The target discussion is 0. It's not the state targets anymore. So we are working with our customers for sure on how we drive that number as close to 0 as we possibly can, as it relates to the timing of our facilities, as it relates to how they're bringing on large pads, etc. I would expect that to turn around as we get these facilities up and going.

That's really helpful. Thank you. And then just wondering if there's been any recent movement on either the [Indiscernible] or the Northern Border Expansion to get some more gas take away on the horizon.

Yes Jean. And this is Chuck. The projects that were discussed prior to the pandemic when we saw the trajectory of the basin requiring additional residue takeaway, we are revisiting those projects as we see increased activity in the Basin, rising GORs. There's quite a few factors that indicate that in the next, call it two to three years, these projects are going to become necessary. So there's a lot of work being done on that behind the scenes right now and we will definitely be part of that solution.

Great. Thanks. That's all for me.

Thank you. We'll take our next question from Michael Blum of Wells Fargo.

Thanks. Good morning everyone. I wanted to just ask a bit about the Mid-Continent. I just want to hear what you're seeing in terms of producers plans there. Do you think there's a possibility that Mid-Con volumes could be flat in 2022, if there's been enough uptick in drilling activity. Thanks.

Michael, it's Kevin I think if you look at the total Basin, yes, it's nice to see the uptick in rigs. I know there's been a couple of producers that have come out pretty strongly and announced increases in production in the Mid-Continent, especially from a gas and NGL perspective. The way we kind of look at it is A, we focus on the total rigs because with our NGL position across that basin where we're connected to about every plant, chances are if a rig shows up in the mid-continent, the NGL s are coming to us. So that's a tailwind. While we may not have a lot of those rigs running on our dedicated acreage in G&P, we do have a couple. We've completed some wells and that's a nice -- again, we continue to talk to our customers and if we see these types of prices sustain, I think you could see some more activity in the mid-continent.

Great. Thank you very much.

Thank you. We'll take our next question from Colton Bean with Tudor Pickering, Holt and Company.

Good morning, sir. Maybe, then I point the 2 questions there on ethane incentive and then the Mid-Con, I think we saw a slight recovery in the average bundled Mid-Con rate for Q3. Was that really just a result of this spread between OTT and Bellevue widening out a bit? And if so, I guess, our current levels or Q3 levels at least can sufficient to get that historical $0.09 per gallon rate.

This is Sheridan. What I'd say, there's two things that drove the rise in the average CNF fee in the Mid-Continent. You mentioned one of them, which as we saw a wider spread between OG2 and Bellevue ethane and factors. And one of the months in the quarter, we didn't incentivize -- didn't have to incentivize any ethane. Now that came out naturally. The other thing, we also saw an uptick in our C3 plus volume, which gets a higher rate than the ethane volume through it. A lot of our plants have split tier rate for ethane and C3 plus. so it -- both of those contributed to the higher rate.

Great. And then back on the balance sheet, you've highlighted the desire to drop below 4X, looks like effectively there on a run-rate basis. Is there a new leverage target that you guys think about whether it's a ratio or do you think more in terms of an absolute debt target? I'm really just interested in how you're thinking about the balance sheet over the next couple of years.

Well, I mean, we've said before that aspirationally we'd like to head towards 3,5 and maybe even a little bit lower, but I think we're going to see opportunities going forward. The EBITDA levels that we're at, a [Indiscernible] there's a whole lot of money to invest. So we think we've got meaningful room there to continue to invest in great projects and still see our deleveraging trend downwards towards that aspirational target of around 3.5 times.

Thank you.

Thank you. We'll take our next question from Tristan Richardson of Truist Securities.

Hi, good morning, guys. Just a quick one on capital. Clearly, you guys you've shown the Elk Creek Slide before. Obviously there's plenty of capital efficient optionality there on the downstream side. But can you frame for us maybe generally the capex dynamic in 2022 versus 2021? Certainly a very modest capital year with Bear Creek, but with additional third-party plant online in the second half, GOR trends and that pent-up volumes dynamic you mentioned in anticipation of Bear Creek. Can you just frame for us what capital could look like in G&P or more just broadly in 2022?

Tristan, this is Kevin. I'm not going to give you a number because that will flow with or as we provide you guidance on early next year. But the way we think about capital, we're constantly evaluating what our customers needs are and what our capacities are. So rather we're talking about processing, gathering, and/or processing need and the Bakken frac capacity needs in Bellevue. Other pipeline needs maybe on West Texas, we're evaluating all of the information from our customers about what they're plans are as we move into '22 and then factoring that in. So the great position we're in, as you mentioned, Elk Creek, but even should we need additional frac capacity, like an MB-5 to restart that paused project, we've already spent a significant amount of that money. So both the additional capital we would need to provide that capacity, as well as the time we would need to deliver the capacity, we're in really good shape because we might only need say, 12 months to 18 months to finish out a frac. And pipeline we've already got pipe ordered and bought, so we don't have that exposure. So these projects that could come back or are in really good shape to -- we don't have to spend a lot of money and we can do them relatively quickly.

Thank you. We'll take our next question from Craig Shere with Tuohy Brothers.

Good morning. So we're talking about 25 a month in well connects in the Bakken. Obviously, it's increasing. I think you said 30 in October and if I did the math right, we may be at 38 or more for November, December. So I had a couple of questions. 1. If these trends continue is the same inevitable that by year-end, next year, we hit over one-half fee a day. And this is all just off your activity, right? On your acreage. But ignores activity with third-party processing plant connections into your NGL system, right? How much more upside could there be there?

Craig, that's -- I mean, you've hit on the tailwinds we've talked about. I mean, if you're north of 30 rigs in the Basin, absolutely, we believe that's enough to grow gas production across the entire Basin. And so that's not only going to benefit us from a G&P perspective, but all the third-party connections that Sheridan has on the NGL side, we're going to benefit from growth there as well. We're in great shape because we've still got, I think like 125,000 barrels a day of capacity on Elk Creek or on our NGL systems coming out of the Basin. So again, we don't have to spend a lot of capital to capture that EBITDA.

Okay. And it sounds like this is great tailwinds, everything is looking wonderful. I understand we'll wait till February to get next year's guidance, but it seems like updated full-year midpoint EBITDA guidance kind of suggests decent but kind of silver fourth quarter, nothing like more recent outperformance versus expectations. Could you maybe talk about the gives and takes going into the fourth quarter?

Well, I think the gives and takes or as you're probably going to predict will say, is we always know there's weather we have to deal with in North Dakota. And so if you get a calm early winter then yeah, I think that could provide some upside. We do have a lot of well connects forecasted in the last couple of months of the year. And that's what producers are telling us. But if you get some weather, could those be delayed? Potentially saw, but I think the key is we have this arbitrary cutoffs at December 31. Well, the well connects are going to get done rather it's in on December 15th or January 15th. So as we think if we back up and look at the trends over the next several months, clearly we've got optimism of where we're going to be. But I think, yes, you've hit on there. I think there's some upside as well with both volumes, if these wells come online like we think, and as well as the ethane recovery option that would be a positive upside for us in the fourth quarter.

Thank you.

Thank you. We'll take our next question from Alex Kania with Wolfe Research.

Hey, good morning. 2 questions, first is just thinking about the ethane recovery opportunity and going into next year and maybe putting into context with your view of a widening spread between ethane and natural gas next year just with increased demand. So it'd be fair to think that there is a double opportunity there between both volumes and maybe an ability to reduce the incentive pricing that you have on ethane?

Yes, this is Sheridan. You're exactly right. We think there's an opportunity both. And obviously, if we had the wider the ethane to natural grass spread gets, the more we can capture of that spreads. And so the incentive is less. And also as volume continues to increase in the Bakken and potentially in the mid-continent, we also have the opportunity to bring even more ethane out. So you're exactly -- you're thinking about it right. There's a double benefit going into 2022.

Great, thanks. And then just maybe a follow-up on thinking about I guess, the maintenance gas level at the very least on 300 wells a year, and the 14 or 15 rigs. Does that also imply or assume any continued work-down of the DUC Inventory or is that 14 to 15 rigs enough to keep volumes where they are? And then whatever else agreeing with the GOR but not have to really dive into the inventory of the DUC's anymore.

I think you'll see the DUC Inventory continue to work down a little bit. Those will occur, I guess call it simultaneously. You'll look at the completion crews and at 10 completion crews I think you will -- and the number of rigs running, I think you'll work the inventory down. It'll be a little slower. But the more rigs you have, the more working -- you'll get down to a working inventory level at some point where the producer likes to keep a certain level so that they don't ever want a completion crew to be waiting on a well to complete. So I think you'll see it stabilize, but I do think you're going to have a period of time here for the next several months, where you're going to have both the DUC Inventory getting worked down, as well as these new rigs churning out new wells.

Great. Thanks very much.

Thank you. We will take our next our last question from Michael Lapides with Goldman Sachs.

Hey guys, thanks for taking my question. Mine's a little bit more long-term in nature. When you get close to a point where you're going to think about capital allocation again and given just what the industry has been through over the last couple of years, if not longer, how do you think about from an equity standpoint what you and the board would view as an appropriate -- how to return capital back to equity holders. Meaning, do you think it's embedded primarily in the dividend growth or are you thinking it's embedded more so in buybacks in very limited dividend growth? Do special dividends play a role? I'm trying to just think about how you're thinking and how the board's thinking about capital allocation as you see improving fundamentals ahead.

[Indiscernible] This is Pierce. I think what our first priority would be to grow our earnings per share and return that value that way in the equity price. Walt said this before, is as we go down through the 4 and get to the 3,5 and maybe lower it does open up our opportunities. But we also are looking at what are those growth opportunities to reinvest in the business, to continue to grow our earnings per share. And then it opens up the board to look at some of those other opportunities. Walt, you got anything to add to that?

No, I think that's exactly right. We -- as we see these earnings grow, the Board will continue to evaluate all those opportunities and [Indiscernible] getting back to it. We have more attractive returns and high multiple projects then we are going to want to focus our capital. And if that isn't the big case, then obviously looking at other forms of capital return to shareholders is something we'll have to evaluate.

Got it. Thank you guys. I'll follow-up offline, much appreciated.

Welcome. Thank you.

Thank you. That concludes our questions for today. I will turn it back to Andrew Ziola for closing remarks.

Our quiet period for the fourth quarter and year-end starts when we close our books in January of 2022 and extends until we release earnings in late February. We'll provide details for that conference call at a later date. Thank you all for joining us and the IR team will be available throughout the day. Thank you.

This concludes today's call. Thank you for your participation. You may now disconnect.