Q3 2021 ONEOK Inc Earnings Call
Good day and welcome to the one Oak third quarter 2021 earnings call. Today's conference is being recorded at this time I would like to turn the conference over to Andrew Cellular. Please go ahead Sir.
Thank you Todd and welcome to <unk> 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 will be available to take your questions.
Statements made during this call that might include one offs expectations or predictions should be considered forward looking statements and are covered by the safe Harbor provision of the securities acts of $19 33 in 1934.
Actual results could differ materially from those projected in forward looking statements for.
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 peers, Thanks, Andrew and good morning, everyone.
We appreciate your interest and investment in <unk> and thank you for taking your time to.
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 Chuck Kelly Senior Vice President natural gas.
Yesterday, we announced strong third quarter earnings results and increased our 2021 financial guidance expectations are.
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.
Cause World Economics continued 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, one and two emissions by 2030 compared with 2019 levels. We.
We will undertake a number of strategic emission reduction measures to meet this target, including the further electrification of certain natural gas compression assets.
<unk> additional methane mitigation through best management practices.
Some optimizations and 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'll share that information and our progress toward our 2030 target.
I'll turn the call over to Walt Hulse to discuss our financial performance.
Thank you Pearce.
With yesterday's earnings announcement, we once again increased our 2021 financial guidance expectations and narrowed our ranges. We now expect net income of 1.4 dollars 3 billion to $1 five 5 billion and adjusted EBITDA of 332 5 billion.
2342, 5 billion with a midpoint of $3 three southern 5 billion.
This represents a 10% increase in our net income and EPS guidance mid points 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.
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 will 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.
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.
100, <unk> third quarter 2021, net income totaled $392 million or <unk> 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, a 16% increase year over year, and an 8% increase compared with the second quarter 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 sub four 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 due February 2022.
Our next debt maturity is not until October of 2022.
In October the board of directors declared a dividend of <unk> 93, and a half cents or $3 74 per share on an annualized basis unchanged from the previous quarter.
I'll now turn the call over to Kevin for an operational update.
Thank you all.
In our natural gas liquids segment total NGL raw feed throughput volumes increased 5% compared with the second quarter, 2021, and 10% year over year, averaging nearly one 3 million barrels per day, our highest NGL volumes 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.
Raw feed 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 and 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.
These new petrochemical plants coming online before the end of the year could provide more than 160000 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 incentives 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.
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 225000 barrels per day of that total opportunity more than 125000 barrels per day are available in the Rocky Mountain region, and 100000 barrels per day in the mid continent as.
Is NGL volumes continue to grow across our systems. So does the discretionary ethane.
Moving on to the natural gas gathering and processing segment in.
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 2021, and nearly 25% increase year over year.
Scheduled plant maintenance at four 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 one 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 Tim completion crews operating in the basin with 17 rigs and five 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 station is 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 two to three years with Bear Creek Twos 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 two rigs now operating on our acreage and 10 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 dollar in two cents per M. M Btu compared with 94 cents per M and btu in the third quarter 2020.
Changes in our average fee rates continue to be driven by our volume and contract mix each quarter, we still expect the fee rate for 2021 to average between the dollar and a $1.05 per M. M Btu.
Under the natural gas pipeline segment.
This segment stable fee based earnings continued 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 events 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 round, 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 2800 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 nine months of this year has set up well.
At the end of the next year.
And company wide earnings growth in 2021.
The foundation for continued growth next year.
With that operator, we're now ready for questions.
Thank you if he would like to ask a question. Please signal by pressing star one on your telephone keypad. If you were using a speaker phone. Please make sure. Your mute function is turned off to allow your signal and to reach our equipment.
Press Star one to ask a question.
We'll take our first question from.
Shneur <unk> with UBS.
Hi, good morning, everyone.
Maybe to start off I was wondering if we can talk about tailwind into 2022, you gave some pretty good color about well completions in the presentation. There. It sounds like you've got a 100 wells left to complete for the Sheridan 300 with only two months to go you've got Bear Creek Cowen Survey.
Is it also fair to assume that you potentially have some PPI and flavors on some of your assets like Elk Creek, and so forth and so just kind of wondering how to how to think about one O because as we sort of head into 2022 in the past you've talked about a $3 5 billion to $4 billion upside potential.
Is that the case or this tailwind stronger now.
Just wondering if you can give us sort of some color as to how do you think of the tailwind right now as we head into 2022.
Shneur this is Kevin.
I think there's multiple kind of answers in that question. One when we think about <unk> into 'twenty two I really go more towards the activity levels, we're seeing in the Bakken.
With the rigs with the DUC inventory with the rising G O ours we're.
We're seeing really nice activity and 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 tail winds are but to your you ask a question there about kind of the inflator is on our contracts in our NGL segment in 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.
We're still good with the with the range from before okay.
And then maybe just.
Just sort of given given your leverage trajectory.
Kind of curious about what kind of return of capital options or potentially considering when when you hit your leverage targets mid next year.
We potentially see a dividend increase our buybacks on the table just any color on that as well to your place.
Sure Shneur this as well.
We were.
We're 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 reduction direction, and then improving debt to EBITDA ratio.
Other thing with free cash flow as it gives us the opportunity to invest in our capital growth as we go forward.
Utilizing free cash flow and not having to finance them.
Obviously as we get further and further along into the.
The reduction our options open up but at the moment we're focused on.
The debt reduction and using our free cash flow for high high return projects.
Okay perfect. Thank you very much I appreciate the color today.
But thank you. Thank you we will take our next question from Christine Cho with Barclays.
Good morning.
If I could start with the incentive ethane extraction in the Bakken.
There was.
A little noisy with the 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, you said you continue to Incent.
You know what the magnitude of the increase was on a quarter over quarter basis.
And.
And then belvieu spread all of our venture a casting seem like it would incentivize ethane extraction. So should we assume it's because of your exposure to a call and I know youre not going to tell us what your exposure to any color. So can you give us an idea of what your limitations and constraints would be so that we can try and figure out maybe like air 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 four at the gas plant not adventurous. So 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 and so you can't really use adventure or a co 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 our 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 of how much more but we did incentivize more in the third quarter.
And would it be.
Safe to assume that you know.
You could incentivize them, even more like on a physical basis going forward.
Yeah, especially as volumes grow in the basin and grow on our in our G&P segment, we do have an opportunity to incentivize more ethane, but as I said previously we look at what's going on in the marketplace, where the prices are in all basins 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 slated to ramp up.
How do you guys think about the risk to the operational crackers not running at full utilization of U S gas prices and ethane prices get too high.
But 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 cracked today than it has been because of that wide ethane to ethylene spreads. So we still 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 2000.
'twenty, one, especially as additional crackers come on in China.
Great. Thank you.
Thank you we'll take our next question from Jeremy Tonet with J P. Morgan.
Okay.
I think on prior calls.
You talked about.
A low double digit.
Increase for EBITDA versus the midpoint of $3 2 billion of EBITDA at that point in time with the guidance and I'm. Just wondering if that's kind of 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 'twenty 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 3.5 O.
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 strengthen in our business, whether it would be producer activity commodity prices.
So all of the trends are headed the right direction.
We think that we're going into 'twenty, two with a very good tailwind and we will give you our 'twenty two guidance in February.
Got it that makes sense there.
And maybe just pivoting towards D C 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 oak be higher 45, Q or minimum tax or anything outside that is on your mind at this point.
Well as it relates to the.
Alternative minimum tax and Theres still quite a few moving parts right now.
If it isn't enacted its unclear at this point.
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 $1 billion threshold, maybe increasing making the whole conversation somewhat irrelevant. So we are.
On top of it we've got a team that is 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.
Hey, Good morning, North Dakota statewide flaring increased in recent months as he is shown on page eight.
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 and notably one X acreage flaring Hasnt increase so maybe it's different per yodlee processing capacity, but just wondering.
Wondering about the trends and wider North Dakota versus yours.
Dan This is Kevin.
Chuck can chime in as well, but.
What you saw going on through the summer as you had several outages at facilities.
You know 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 in.
And the same with some I know third party plants that we're going through some expansions and other maintenance activities.
During the summer.
I don't think that's a trend I think that's going to trend back the other way as we get into what I would consider more normal operational run rates for these facilities.
Conversations, we're having with all our customers up there and I am sure third parties are the same way the target discussion is zero, 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 zero as we possibly can.
As it relates to the timing of our facilities as it relates to how they are bringing on.
Large pads et cetera, So 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 theres been any recent movement on either the bison project or the northern border expansion to get similar gas takeaway kind of on the horizon.
Yeah. Julian this is a this is chuck.
The projects that were discussed prior to the pandemic when we saw the trajectory of the basin requiring additional residue takeaway.
Revisiting those projects as we see increased activity in the basin rising G O ours, there's quite a few <unk>.
Factors that indicate that in the next call. It two to three years. These projects are going to become necessary. So there's there's a lot of work being done on that behind the scenes right now and we will definitely be a 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.
Yeah.
Good morning, everyone.
I wanted to just ask a bit about the mid continent just wanted to.
Here, what youre seeing in terms of producers' plans. There do you think there is a possibility that mid con volumes could be flat in 2022, theres been enough uptick in drilling activity. Thanks.
Michael It's Kevin I think if you look at the total basin, Yeah, it's nice to see the uptick in AR.
In rigs I know theres been a couple of producers that have come out pretty strongly in.
And announced increases in production in the mid continent, especially from our gas and NGL perspective.
The way, we kind of look at it as a we focus on the total rigs because you know 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 Ngls are coming to us.
So that's a tailwind.
We may not have a lot of those rigs running on our dedicated acreage in GNP.
You know we do have a couple we've completed some wells in <unk> and that's a nice again, we we 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, maybe to blend the two questions there on ethane incentive in the mid Con I think we saw a slight recovery in the average bundled mid con rate for Q3 was that really just the result of this spread between OTT and belvieu widening out a bit and if so I guess are at current levels or Q3 levels at least sufficient to.
That.
Historical nine cents per gallon rate.
This is sheridan when I'd say, there's two things that drove the rise in the <unk>.
Average cfe in the mid continent.
You mentioned one of them, which is we saw a wider spread between O G. T N belvieu ethane and factors or one of the months in the quarter. We did incentivize didn't have to incentivize any ethane out it came out naturally.
The other thing we also saw an uptick in our C III plus volume, which gets a higher rate than the ethane volume because we have a lot of our plants have a split tier rate for ethane and see three plus so both of those contributed to the higher rate.
Great and then back on the balance sheet.
You've highlighted the desire to drop below Forex looks like effectively they are on a run rate basis.
There are new kind of leverage target that you guys think about whether it's the ratio or do you think more in terms of an absolute debt target. It really just interested in how youre thinking about the balance sheet philosophically over the next couple of years.
Well I mean, we've said before that aspirational, we'd like to head towards three five and maybe even a little bit lower but I think we're going to see opportunities going forward.
At.
The EBITDA levels that we're at a half a turn as a whole lot of money to invest.
So.
We think we've got a meaningful room, there to continue to invest in great projects and still see our deleveraging trend downwards towards that aspirational.
Target of around three five times.
Okay. Thank you.
Thank you we'll take our next question from Tristan Richardson of Truth Securities.
Hi, Good morning, guys, just a quick one on capital.
Clearly you guys have shown the creek slide before obviously, there is plenty of capital efficient optionality there on the downstream side, but can you frame for us maybe generally capex dynamic in 2022.
Versus 2021, certainly a very modest capital year with Bear Creek, but.
Additional third party plants online in the second half G O or trends and that sort of pent up volumes dynamic you mentioned in anticipation of Bear Creek.
Just frame for us what capital could look like in the G&P or more just broadly in 2022.
Kristen This is Kevin I'll I'm not going to give you a number because that will flow with her as we provide you guidance 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 are talking about processing.
Gathering <unk> processing needs in the Bakken.
Frac capacity needs in.
In Belvieu and.
Other pipeline needs may be on West, Texas, we're evaluating all of the information from our customers about what their plans are as we move into 'twenty two.
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 five to restart that pause project. We've already 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 to 18 months to finish out the frac.
And you know that.
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.
Alright, great.
So.
We're talking about the 25 a month.
It connects in the Bakken.
Obviously, it's increasing I think you said 30 in October and if I did the math right. It may be at 38 or more for November December.
So I had a couple of questions one.
If these trends continue does it seem inevitable that that by year end next year are we hit over one half via day and.
This is all just all your activity right on your acreage, where the kind of ignores activity with third party processing plant connections into your NGL system right. So.
How much more upside could there be there.
Well, Craig that's I mean, you've hit on the tailwind as 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 125000 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 that EBITDA.
Yeah.
Hum.
Okay.
It sounds like there is a great tailwind everything's looking wonderful I understand we'll wait until February to get in next year's guidance, but it seems like updated full year midpoint EBITDA guidance kind of suggests.
And all are decent but kind of silver fourth quarter.
Nothing like a more recent outperformance versus expectation could you maybe talk about the gives and takes going into the fourth quarter.
Well I think the gives and takes are as you are probably going to predict will say is we always know there's.
There is whether we have to deal with in North Dakota, and so if you get if you get a call early winter then yeah, I think that could provide some upside we.
We do have a lot of well connects forecasted in the.
The last couple of months of the year, that's what producers are telling us, but if you get if you get some weather could those be delayed I think the key potentially so but I think the key is.
We have kind of this arbitrary cut off at December 31, well the well connects are going to get done rather it's in on December 15th of 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 that would be a positive.
Upside for us in the fourth quarter.
Great. Thank you.
Thank you we'll take our next question from Alex Kania with Wolfe Research.
Hey, good morning.
Two questions first is just thinking about the ethane recovery opportunity going into next year, and maybe putting into context with your view of kind of a widening spread between.
Any natural gas next year, just with increased demand so would it be fair to think that there's a kind of double opportunity there between both volumes and maybe an ability to kind of reduce the incentive pricing that you have on ethane.
Yeah. This is sheridan it youre exactly right.
There is an opportunity both in obviously, if we had the wider the ethane and natural gas spread.
The more we can capture of that spreads and so the incentive is less and also as volume continues to increase in the Bakken in and potentially in the mid continent. We also have the opportunity to bring even more ethane out so youre exactly youre thinking about it right, there's a double benefit going.
Going into 2022.
Great. Thanks, and then just maybe a follow up on thinking about the.
I guess the maintenance at the gas level or at the very least in the 300 wells a year.
The 14 to 15 rigs does that also.
<unk> kind of assume any continued you work down of the DUC inventory or is that 14 to 15 rigs say enough to kind of keep volumes, where they are and then whatever else, depending what the GR, but not having to really dive into the inventory of the of.
The ducks anymore.
I think youll see the DUC.
Inventory continue to work down a little bit those will occur I.
I guess call it simultaneously youll look at the completion crews and and at 10 completion crews I think you will and the number of rigs running I think you'll work.
Inventory down it'll be a little slower.
But the more rigs you have the more kind of a working you'll get down to our 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 on a well to complete so I think youll see it stabilize but I do think youre going to have a period of time here for the next several months.
Where youre 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'll 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.
You get close to a point, where you're going to think about capital allocation again, 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 kind of had a return of capital back to equity holders, meaning do you think it's embedded primarily in the dividend growth. How are you thinking it's embedded more so than buybacks and very limited dividend growth.
Special dividends play a role just 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.
So Michael all of this is pierce.
I think the what our first priority would be to grow our earnings per share and return that value that way in the in the equity price.
I mean, <unk> said this before as we go down through the floor and get to the three five and maybe lower it does open up are 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 door to look at some of those other other opportunities Walter you got anything to add to that.
I think thats exactly right.
As we see this earnings growth.
The board will continue to evaluate all those opportunities.
It comes back to if we have.
More attractive returns and.
Multiple projects, then we're going to focus our capital.
Isn't the 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 appreciate it.
Well thank you.
Thank you that concludes our questions for today I'll turn it back to Andrew's Iola 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.
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 paints you may now disconnect.
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