Good day, and welcome to the Fourth Quarter 2021 ONEOK Earnings Call. Today’s conference is being recorded. At this time, I’d like to turn the conference over to Andrew Ziola. Vice President of Investor Relations and Corporate Affairs. Please go ahead, sir.

Thank you, Jennifer. Welcome, everyone, to ONEOK’s fourth quarter and year-end 2021 earnings call. We issued our earnings release and presentation that includes 2022 guidance 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 ONEOK’s expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision of the Securities Acts of 1933 and 1934. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings. 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. Thank you for taking the time to join us. We’ve got a lot to cover today. With me on the call today 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 Kelley, Senior Vice President of Natural Gas. Yesterday, we announced strong fourth quarter and full year 2021 performance, recording our eighth consecutive year of adjusted EBITDA growth. That equates to a 13% annual growth rate during that eight-year period, highlighting the stable and resilient earnings power of our assets despite various economic and commodity cycles. In 2021, during a year of continued economic recovery in lingering pandemic-related challenges, we grew adjusted EBITDA 24% compared with 2020, continued to strengthen our balance sheet and achieved record natural gas and NGL volumes on our Rocky Mountain region assets. 2021 provided other milestones as well, including our announcement of a greenhouse gas emissions reduction target, receiving an upgraded AA ESG rating from MSCI, and once again receiving a perfect score in the latest Human Rights Campaign Corporate Equality Index. These are only a few of the many great things we’re doing as a company to ensure ONEOK remains a great workplace, community partner and service provider. With yesterday’s earnings announcement, we also provided 2022 financial and volume guidance expectations. We expect increasing producer activity and improving market demand to drive strong volume and earnings growth across our operations. As we’ve said before, we are well positioned financially and operationally in 2022 and for many years to come. Before I hand the call over to the team…

Thank you, Pierce. ONEOK’s fourth quarter and full year 2021 net income totaled $379 million and $1.5 billion, respectively. Adjusted EBITDA for the same periods totaled $847 million and $3.38 billion, respectively, representing year-over-year increases of 14% for the fourth quarter and 24% for the full year. Our December 31 net debt-to-EBITDA was just below 4 times, passing through an important marker and our continued deleveraging strategy. We continue to prioritize reducing leverage below 4 times and view 3.5 times or lower as our long-term aspirational debt-to-EBITDA goal. In 2021, we reduced our total outstanding debt more than $600 million by proactively paying off nearly $550 million of maturing debt on November 1st with cash on hand and being opportunistic with open market repurchases earlier in 2021. We currently have no debt maturities due before the fourth quarter of 2022. Fourth quarter results reflect volume growth in our Rocky Mountain region that was offset by higher operating costs. These higher costs were driven by discretionary employee-related benefit costs and expenses related to planned O&M maintenance projects completed in the fourth quarter in our natural gas liquids and our natural gas pipeline segment. As Pierce mentioned, with yesterday’s earnings announcement, we provided 2022 financial guidance, including a net income midpoint of $1.69 billion and EPS of $3.76 per diluted share. We also provided an adjusted EBITDA range of $3.5 billion to $3.8 billion, with $3.62 billion as our midpoint, representing a 7% increase compared with 2021. We expect double-digit earnings growth at the midpoint for both the natural gas liquids and natural gas gathering and processing segments, driven by higher volume expectations across our operations. Kevin will provide more detail on our volume outlook. In our natural gas pipeline segment, we expect earnings to be stable year-over-year when adjusting for Winter…

Thank you, Walt. Fourth quarter volumes continued to show strength, particularly in the Rocky Mountain region, where processed volumes increased 5% and NGL volumes increased 6% compared with the third quarter of 2021. Natural gas processed volumes in the Mid-Continent increased in the fourth quarter compared with the third quarter as we’ve seen -- as we continue to see more activity in the region, while NGL volumes in the Mid-Continent decreased due to some reduced third-party volumes and lower ethane recovery levels. Overall, for 2021, natural gas and NGL volumes saw significant increases from 2020 levels. We saw record natural gas and NGL volumes on our Rocky Mountain region assets with significantly higher activity in rising gas to oil ratios. In the fourth quarter alone, our team connected 130 wells, nearly doubling the amount from the third quarter for a total of more than 320 in 2021, a great accomplishment for our team in meeting the needs of our customers and continuing to provide momentum into 2022. Now, taking a closer look at 2022. At the midpoint, our volume guidance would result in an 8% increase in total NGL volumes and an 11% increase in total natural gas processing volumes compared with 2021. These higher expectations are supported by increasing producer activity, volume growth from recently completed ONEOK and third-party projects, rising gas to oil ratios in the Williston Basin and ethane recovery opportunities across our NGL system. With the recent completion of our Bear Creek plant expansion, we are already seeing increasing volumes from Dunn County, and we expect the plant will continue to ramp up over the next two to three years. However, with activity levels in the area consistently outpacing our expectations, we could be looking at an even quicker ramp. In the natural gas liquids segment,…

Thank you, Kevin, and thank you, Walt. Strong financial and operating results in 2021 have provided momentum for another year of growth. We continue to benefit from our interconnected systems, built in operating leverage and the ability to incrementally grow with our customers. We continue to invest in our core businesses, remaining focused on optimizing our assets and staying dedicated to operating responsibly and reliably. Service is another one of ONEOK’s core values, and it is something that our more than 2,800 employees know very well. Through 2021, they worked tirelessly through severe weather events like Winter Storm Uri to serve our customers and continue delivering the vital energy products necessary for the global economy to run. Our employees’ dedication to meeting customers’ needs while operating safely and responsibly, enabled our strong 2021 performance and has set us up for another year of growth in 2022. With that, operator, we’re ready to answer questions.

[Operator Instructions] And our first question today comes from Michael Blum with Wells Fargo.

I wanted to go back to the comments on incentivized ethane recovery in 2022. Can you just give us a sense of what’s going to drive that? And have you changed the rates directionally that you’re charging on that incentivized ethane?

Michael, this is Sheridan. What we -- as we said before, what drives that is the difference between natural gas prices in the Bakken compared to ethane prices in Mont Belvieu. And so, what’s going to drive that rate higher is if we see that spread continue to wide, we will incentivize more ethane out of the Bakken to capture that spread. So, it’s not -- we’re not putting out a new tariff or reducing TNF fees. We’re actually literally capturing gas price to ethane prices, which today is widened out wider than what we saw in ‘21.

Okay, great. I appreciate that. And then, just maybe a related question, can you give us your latest thoughts on the -- some of the proposed, including your own natural gas pipeline expansion projects out of the Bakken? Do you think we’re getting closer to a place where we’re going to need some more gas capacity? Thanks.

Yes. Michael, this is Chuck. I do, and we do. We believe that the Bakken will need some resolute takeaway, let’s say, in the next, call it, three years either side of that. And as you may have heard on TC Energy’s call, they said don’t be surprised if you see an open season this spring. And frankly, I think all stakeholders, processors, pipelines and producers realize the decision probably needs to be made this year to effectuate that time line. So between Northern Border’s Bison Express pipeline and some underutilized pipelines in the Powder River Basin, I think we’ll be able to go ahead and manage that egress.

And our next question will come from Jeremy Tonet with JP Morgan.

Just wanted to pick up on the Bakken a little bit here, I guess, more thoughts about NBPL in heat content and given kind of the trajectory here, just wondering if you could walk us through, I guess, procedurally next steps if it’s viewed that the heat content would get too high and there would need to be adjustments in the rate or less ethane accepted, or just any thoughts you could share there?

Yes. Jeremy, it’s Kevin. Yes. That phenomenon still exists. If you -- if we rewind a little bit pre-COVID, we were bumping up against those -- some BTU downstream challenges. And there was a lot of discussion in the basin and Northern Border had proposed a new tariff that ultimately got denied and FERC asked the pipe to go back and work with shippers, work with markets to produce a little more information. COVID hit and it really reduced the volumes back to where it wasn’t an issue. If you look at gas production or gas capture in the Bakken today, we are back up to the pre-COVID levels. So the only thing that’s keeping that problem from being persistent is the ethane that we’re recovering on an incentivized basis, which is reducing the heat content. If that market turns around and we don’t incent ethane, then that’s going to raise the BTU content back on border to the levels we were seeing pre-pandemic. So absolutely Northern Border continues to have those conversations. It’s our understanding, they will go back to FERC with a recommendation sometime this year. But in the meantime, we’ve proven if we do end up with a heat content issue, we can always recover ethane to make that okay -- the BTU spec back okay on the pipe. But if that’s a forced ethane recovery because of a BTU limit, that would be at full rates.

Got it. That’s a helpful context there. And maybe just kind of pivoting towards the guide for a minute here, and thanks for kind of listing some of the puts and takes. But just was curious if we think about kind of the formation of the guidance, I imagine this was informed last night, and it was formed a little while ago. And if you kind of overweigh the world today as we see it within how that applies to the guidance range. Could you provide any color there? Would that put you guys kind of at the high end, or any other thoughts on what’s happening today? And how that covers, I guess, where you could fall in the guidance range?

Jeremy, this is Pierce. I think, given our asset capacity that we have today and then given kind of the backdrop that you described, which is improved demand and improved commodity prices, is really what’s kind of driving this volume metric growth, and we all know that volume impacts us. I’d probably say that our outlook today is as good or better than our guidance midpoint.

And we’ll hear next from Brian Reynolds with UBS.

Maybe just a follow-up on the guidance and talking about the upper end of the guidance range, which we seem to be pointing towards. Just kind of curious if you can help me reconcile the upper end of the G&P growth versus the NGL throughput. It seems like G&P growth is a little bit higher. Just kind of curious if you can give a little bit more commentary around ethane recovery assumptions. Are you assuming a little bit of ethane rejection into ‘22, or is that just kind of a conservative estimate with ethane recovery to the upside? Thanks.

Brian, this is Sheridan. I think what you need to look at is on the G&P side, what we noted in our release was that an increase in the Rocky Mountain region. On the NGLs, the increase was across our regions. And one of the big contributors to that is the Mid-Continent is growing less than 8%. So, that’s bringing down the average for our NGL segment. And also in our guidance, we have less incentivized ethane than we did in 2021. So that’s another reason that you brought it down a little bit as well.

Great. Really appreciate that color. And as a follow-up just on capital allocation. The high end of the guide kind of implies ‘22 leverage exiting there 3.5 [ph]. Just curious if you could talk about the evolution of the long-term leverage target and how we should think about future opportunities around return of capital as we get into the end of the year and into ‘23? Thanks.

Well, we’re very pleased with how we’ve progressed on our leverage metrics and that we broke through that 4 times in our head and direction, as you mentioned. I think that as I said on the last call, we’re trying to triangulate between a couple of different metrics and just not entirely focused on the debt-to-EBITDA metric. We’re also focusing on a dividend payout ratio. As you see at the guidance, we’re starting to break under 100%. And that’s trending again and also in the right direction. And we’d like to see that get some room under that 100% as we look and think about capital in the future. But there’s no doubt that our flexibility as we move forward and these metrics get in line continues to broaden and be a little bit more flexible. And we’ll look at that as the year and going into ‘23 progress.

And our next question comes from Theresa Chen with Barclays.

I was wondering if you wouldn’t mind providing some incremental color on your production outlook, on the projection outlook in your areas of service into 2022 and maybe beyond as well as the GOR outlook.

When you say production, Theresa, are you talking about the crude production as we see it? Or...

By our customers.

By our customers?

Yes.

I mean when we think about crude -- yes, we think about crude production in the flat -- excuse me, in the Bakken, it’s going to be -- we believe it will grow slightly. I mean, we don’t think it’s going to grow at 10%, but we do believe there will be some level of growth based on what our customers are telling us. And the completions that we see on schedules, et cetera. With that crude production growth, we obviously then believe our gas production is going to grow at the percentages that we’ve outlined previously. So, I guess, that’s how we’re thinking about that STACK/SCOOP going down the Mid-Continent. This is one that we’ve been saying flat to slightly declining. However, with the recent activity pick up, we’re probably looking at it in a slight increase type environment. I think that’s consistent with what some others have said on their calls as well with some of the recent information. And obviously, the Permian is going to grow and has shown growth, and we believe we’ll continue to get our fair share with both, our West Texas LPG asset and our OWT system out there. So we believe we can participate in that growth in the Permian.

And would you mind just sharing what kind of commodity price assumptions underlie your 2022 guidance?

Well, that’s where Walt mentioned, as we look at activity levels and things like that, we were using a low 70s type number for crude for ‘22. As we think about the rest of the commodities, we’ve driven so much exposure of the commodity exposure out of our business and with how we contract, we really -- that doesn’t have a huge impact to us. I mean, it is a little bit of a tailwind right now at these prices. But it was definitely back if you think of crude in that $70 environment, that would be the associated NGLs and gas prices that we would have been looking at.

And we’ll hear next from Colton Bean with Tudor, Pickering, Holt & Company.

So I think you may have just touched on this. But with the 2022 G&P guidance, it looks like EBITDA per Mcf is effectively flat year-on-year. Fee rate is guided to a similar range. So it sounds like part of that -- well, I guess, just broadly, could you walk us through why unit margins would be flat if the Bakken is comprising a greater share of volumes? And then, it sounds like commodity margin that may be skewed a bit by a price deck, but it seems like for both hedged and unhedged volumes, you’d have a better outcome there.

Colton, are you talking about specifically about G&P, or are you talking about overall? I’m not sure we followed exactly what you’re asking there.

Just the G&P segment specifically. Yes, looking at the G&P segment, if I just -- yes, the G&P EBITDA versus volumes, it looks like EBITDA per M, so on a unit basis is kind of flattish. But I would have thought that the fee rate would have seen some escalation with the Bakken growing as quickly as it is. And then, on the commodity side, it sounds like that may be partially attributable to a difference in price deck.

One thing -- excuse me, Colton, this is Chuck. One thing I would add is you’ve seen our volume guidance. So, obviously, our volumes are up year-over-year. And as part of that, we do have some percentage of proceeds exposures, roughly, call it, 15%, 18%. And at these volumes and these prices, you have a larger commodity piece contribution to our EBITDA. So the $1 to $1.05 average fee rate is across our segment. Obviously, the Bakken is higher. So I’m not necessarily following your question.

Colton, I think another thing that’s factored in there is just we’ve seen that fee rate bounce around periodically quarter-to-quarter. So, we’re giving you -- we’re doing our best to give you the average for the year. That fee rate can move around depending on specific producer characteristics. So, if a producer that has a more of a POP contract with a lower fee, all of a sudden completes a bunch of wells in one given quarter, that can actually move that fee rate down. So, what you’re getting there is a blend, but it’s going to bounce around quarter-to-quarter.

Yes. No, I understood. You can follow up for that. I think looking at it from a high level, it just looks like the EBITDA per M is relatively flat. So with both commodities and Bakken growing was a bit confused there, but can follow up on that. And then just on the OpEx side of things, I know you mentioned compensation factored into that. So, can you give us an idea of how you’d expect that to progress relative to Q4 levels?

Well, I think Q4, obviously, as Walt mentioned, had a couple of anomalies with the higher employee costs that were discretionary in the -- and the timing on some of our expense projects. If you think about ‘22 relative to ‘21 and look at a run rate, you’re going to have a full year of Bear Creek II from a -- and you’ll see increased costs just with increased volumes, which we’ll see. And then lastly, you will see some level of -- I’m sorry, I just lost my train of thought here. Those are the two big drivers we’ll see. And then -- but from a timing perspective, historically, our expenses, you’ll see that kind of grow over the year just related to the timing of a lot of the expense projects we’ll do in the summer fall and then trying to get them done by the end of the year. That help you?

It does, yes. Thank you.

And our next question comes from Jean Ann Salisbury with Bernstein.

I had a question about Mid-Con guidance. It looks like you’re projecting basically flattish gathering and processing volumes in 2022 versus 2021, in the Mid-Con, but you’re connecting many more wells than you did in 2021. Are you expecting much more oil-directed drilling, or is it a timing thing, or am I totally missing something else?

Jean Ann, this is Chuck. No, we see an increase of -- I think our volume guidance came up roughly 2%. We actually, I think that might be a little light, it might be more like 3% to 5%. So, we did guide on volume slightly higher than our actuals from last year. And we do have good line of sight to the 30 to 50 well count that we put out in guidance right now. We’ve got 4 rigs operating on our acreage, well capitalized publics behind that with a couple of private coming in Q2 and early Q3. So, I would say that our Mid-Continent volumes will be up, obviously, relative to 2021.

Okay. That’s helpful. Thanks. And then how are you thinking about the timing of Elk Creek expansion? Would you need both Bakken pipes to be approaching full or just Elk Creek to be basically full and Bakken doesn’t have to be full to pursue it?

Jean Ann, this is Sheridan. When we think about Elk Creek expansion, really, we do look at them both together. So we both look at Elk Creek and the Bakken pipeline to understand when we need to expand. And really, the next expansion on Elk Creek will come on what we call the east-west portion as we see sustainable volume that has to be delivered to OPPL as we optimize that, and we may decide to increase the pumps on that east-west section so that we can move on back off OPPL to optimize our earnings. So, that’s kind of what we look at when we are going forward. So, right now, we feel with the Bakken OPPL connection and Elk Creek, we have plenty of capacity to meet our customers’ needs. And it’s just going to be an option when we expand.

And our next question comes from Michael Lapides with Goldman Sachs.

Just curious, cost of everything in the world’s up, meaning commodity...

Michael, we could barely hear you.

Hey, guys. Can you hear me now?

There you go. Perfect.

Real quick. Cost of everything is up. Inflation’s rough out there, steel, labor, et cetera. Can you talk about that trend that’s impacting kind of all industries? And whether that’s had an impact on your capital budget? So, if we look at your CapEx forecast, are you seeing changes at all in which your original expectations for either MB-5 or Demicks were, or the average cost for every new well connect relative to what it cost in maybe 2021 or 2020?

Michael, it’s Kevin. Not significantly, and those numbers are baked into the guidance as we think about it. Related to Bear Creek II and Demicks Lake III, we were so far down the road on those projects that when you think about steel and a lot of the materials, a lot of that stuff was already purchased, bought on site, in many cases, installed at the site. Since that time, we’ve gone out and recontracted everything, rebid everything and we’re not seeing anything that would cause us to deviate from where we’re -- what we articulated from a cost standpoint. We are seeing probably a little tick up, as everybody else is, on just kind of your general materials and services. But so far, nothing that would be outside of what we would consider norms that -- and the philosophy is developed when we put the guidance together.

Got it. Meaning you’re not seeing a lot of pressure in the cost to do new well connects relative to what you’ve seen over the last couple of years.

No. I mean, there may be a minor uptick in some of the prices, again, of the materials. But again, all that’s baked into what we’ve got from our growth and maintenance capital budget.

Got it. And then, when we think about the capital budget for this year, really the impact of MB-5, is the bulk of the spend on that frac in this year and there’s just a little trickle in the next year, or is it more evenly weighted across the years?

Well, I think it will be -- your heavier spend will be this year and early next year. We do believe both, MB-5 and Demicks Lake III will be completed early in the quarters that we provided out there. And we’re doing everything we can to accelerate them even more because we’d like to have that capacity available. And some of that’s factored into the guidance expectation as well.

And we’ll go next to Craig Shere with Tuohy Brothers.

Hi. Congratulations on the ongoing progress here. With regards to the realized NGL pricing, I’m sorry if I missed it, but it seems like the Rockies was just $0.01 lower sequentially. And I was wondering to what degree that’s just random fluctuation or it reflects the level of incentivized ethane, or does it impact maybe some volumes actually starting to increase all the PRB?

No. Craig, this is Kevin. That realized NGL pricing, I think you’re referring to on the G&P side. That’s just a function. It does include our hedges in there, which is what is -- what pulled that down slightly from Q3, I think, is what you’re referring to. So, it’s just a function of all our hedges getting lumped in with what’s going on, on the prices. It’s got nothing to do with the NGL...

I was talking about the $0.25 versus the $0.24.

On the Elk Creek or the Rockies rate, yes, that is a function of the incentivized ethane. So, that drop in a penny has nothing to do with anything contractually that’s going on. It’s purely the incentivized ethane.

Got you. And you all have been talking about for some time, 25 rig connections -- or well connections among 300 a year in the Williston pretty much holding volumes flat, but you’ve kind of been saying that over a couple of quarters, the volumes have been increasing. And at the same time, GORs, GPMs and overall well productivity keeps improving. If we’re thinking about over 1.5 year-end run rate, do you think -- what are the prospects that an even more subdued rate of well connects, say, 300 versus the 422 guidance, could keep that higher level of production flat versus what we had seen in the third quarter.

Yes. Craig, this is Kevin. I do think that’s possible. We continue to be surprised. I think as I said in my remarks, producers continue to get better and better. So, as each well gets more prolific and as the gas to oil ratios continue to increase, that just means you’re going to need fewer wells to hold production flat. Now, we’d like to see obviously the same capital deployed and grow production. But at the pace we’re going on right now, that’s been a trend over the last several years as each year, it seems like the same number of wells will allow us to stay flat, even though the baseline keeps getting larger. So, that trend could absolutely continue.

And next question comes from Tristan Richardson with Truist Securities.

Just one from me. Just thinking about 2023 and beyond and your large projects, clearly, there’s a lot of cost advantages in resuming these projects. And if you think about the volume ramp on projects once online, can you talk about maybe the return on capital advantages or incremental return on capital for this year’s budget maybe relative to previous returns on capital or historical returns on capital?

Tristan, there’s no doubt that we continue to see an upward trend in our return on invested capital, and that really comes back to the operating leverage, that we’re seeing growth and we don’t have to put capital -- meaningful capital into our pipeline assets that we built. Obviously, a pump station here or there as volume grows, but that operating leverage has -- year-over-year continues to fall to the bottom line, and we have enjoyed and expect to continue to enjoy increasing return on invested capital going forward.

And our next question comes from Sunil Sibal with Seaport Global Securities.

Yes. Hi. Good morning, folks. And thanks for all the clarity. Just a couple of follow-ups. First of all, it seems like the well completion activity in Rocky Mountain, it was very strong in Q4. I was curious if you can talk about what kind of cadence we should see in volume growth in that region, especially considering that typically, Q1 also sees some weather events? So, should we be thinking of a little bit of a subdued growth in Q1, despite this strong well completions and then a ramp up, or should we be expecting some other trends?

Sunil, this is Chuck. What I’d say about our well connect cadence for 2022, in some ways, it resembles 2021. We had, as you said, a lot of momentum, 130-plus well connects coming out of Q4. 2022 is more back-weighted to Q2 and Q3, just as it was in 2021. We did have some momentum, obviously, carry into here into Q1 this year. Q2, typically, it’s a little dip every year because of frost laws and the weather spring. But -- so the cadence would be more back weighted to Q3 and Q4. Volumes associated with that would probably resemble the well connect activity.

Got it. And then, one follow-up on the cost issue. I realize that Q4 seems like, sequentially, the costs were up about $25 million or so versus Q3. What’s a good way to kind of think about that breakdown in onetime costs versus kind of ongoing costs?

Well, like I said, if we just -- I guess, the way to think about it, if we look at kind of the full year 2021, I do think our costs will be up a little bit in 2022 just overall. I mentioned before, you’ll see a full year of Bear Creek too. The other item I forgot to mention earlier was taxes. You’ll see we’ll have an increase in our ad valorem taxes in ‘22 versus ‘21, so those type of things. And then just the ongoing volumetric costs that are associated with the volumetric growth, which we’ll see with the growth we’re seeing across our system.

Our next question comes from Michael Cusimano with Pickering Energy Partners.

Most of my questions have been answered. But, if you can just talk about the progress that you’ve made in adding plant connections in the Permian? And then, maybe what you view as your competitive advantage there? And if that’s a growth area from here? And then, lastly, just if you’ve looked at any acquisitions in order to, I guess, inorganically grow your footprint there?

Michael, this is Sheridan. When we look at the Permian, we still continue to be very competitive because we continue to sign up more people. A lot of our competitive advantages, we have a pipe in place there today. We’re connected to a lot of the unintegrated players that want an alternative source. We also have cheap expansions on our system that we can continue to grow. So, we can continue to provide a competitive alternative to other people out the basin, and we see that because our volumes continue to grow. We’re seeing -- as we mentioned, we’re seeing double-digit growth. We’re also seeing growth from people we’ve already contracted. As the volume out there grows on their system, it comes to our system. And we have long-term contracts in place, as we do in every other place. The M&A question...

So, Michael, I’ll weigh on that. This is Pierce. I mean, yes, we do look at M&A opportunities in all of these basins. We kind of drop them into kind of two categories, a defensive kind of play versus a proactive look at it. As it relates to looking at these, when you look at -- especially in our NGL business, when you look at the length of our contracts in a lot of these places and you look at maybe the prices that you have to pay to get the G&P opportunities that feed the NGL business, then we just don’t see that as being maybe a place where we would deploy our capital when you look at it as the benefit to our shareholders. So, yes, we look at them, but so far, we haven’t found anything that we think is attractive there.

And our next question comes from Alex Kania with Wolfe Research.

Maybe two questions. First is, just I was thinking about the headroom on the kind of your pipeline infrastructure out of the Rockies. And could you remind us, maybe you said it, I might have missed it on the call, but you were at 335,000 in Q4. Sort of what’s the expectation of that going as you’re assuming for 2022? And the second question would be, if you could maybe talk a little bit just about the kind of commodity components of the POPs, kind of what price deck were you assuming when you were talking about kind of the outlook for the G&P business for this year?

Alex, this is Sheridan. As we think about capacity on Elk Creek in the Bakken, as I said, if we think about them together, we currently have a 440,000 barrels a day of capacity. As you said, we’re running in the in the 330,000 to 350,000 range today. We see that -- we’re having plenty of capacity for the period of time now. A lot of that we had incentivized ethane on there. We also we’re pulling that into that. So, we think we have completing capacity on that system going forward for a period of time, and we can take it up another 100,000 barrels a day pretty easily, just adding some additional pumps in a very short period of time. So, we feel very comfortable with our capacity coming out of the Rockies.

And Alex, on the question about the POPs, we provided that earlier. We’re -- again, we’re thinking about it in a low $70 type crude environment. If you go back and look at what NGL prices were doing when crude was kind of in that range, that gets you in the ballpark. And then, gas, kind of that same one. It’d be in the upper 3s, upper $3 type number. The other thing to remember when you’re thinking about the POP is we are about 75% hedged when you look at it in the -- for those POP contracts in 2022. So, there’s really just not a lot of commodity exposure left when you factor in the impact of the hedges as well.

And our last question today will come from Jeremy Tonet with JP Morgan.

Hi. Thanks for squeezing me back in here. Just a real quick question. Our conversations with regulators in North Dakota leads us to see a lot of emphasis on the potential for carbon capture and state policy as well as really kind of support this development. And North Dakota being only one of two states that has Class 6 primacy that allows CO2 wells to be developed at the pace the state sets there, kind of sets them apart from others. And also, you have the Summit pipeline pointing towards North Dakota in progress there. Just wondering, any updated thoughts that you have -- that ONEOK has case on carbon capture. And could this be something that realistically enters the fold at some point? Do you have any visibility here?

Yes. Jeremy, it’s Kevin. Yes, this is something we are actively involved in conversations with state officials with other private entities, et cetera, for opportunities. We’ve had a few conversations with them so far, and we’ve got conversations scheduled with them in the very near future to have discussions around that. I do think there are some opportunities when you look at -- that’s what we do, right? We’ve got a lot of -- we know how to process things. We know how to build pipelines, and we know how to store things. And so, I think there’s opportunities. It’s just finding the right partners up there and getting the right opportunities before we pull the trigger on something, but it’s definitely something we’re actively working on.

And this concludes our question-and-answer session. Mr. Ziola, I’d like to turn the conference back to you for any additional or closing remarks.

All right. Thank you, Jennifer. Our quiet period for the first quarter starts when we close our books in April and extends until we release earnings in early May. We’ll provide you details for that conference call at a later date. Thank you for joining us. And the IR team will be available throughout the day. Thank you all.

And this concludes today’s conference. Thank you all for your participation. You may now disconnect.