Oneok Inc (OKE) — Q4 2021 Earnings Call Transcript

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 for more details on 2022, I’d like to reiterate what makes ONEOK so uniquely well positioned for the long term. First, our extensive and integrated assets, which are located in some of the most productive U.S. shale basins. Our customers are well capitalized with decades of proven reserves and many have announced plans to sustain and grow production levels in 2022. In the Williston Basin, in particular, steady crude oil production still means NGL and natural gas growth for ONEOK due to rising gas to oil ratios. Second, our dedication to safe, reliable and environmentally responsible operations. Our commitment to safety in the environment is a core value for ONEOK. It’s critical for us to be a safe and reliable service provider, and we strive to be a good partner in the areas where we operate. Our ESG-related performance is a source of pride for ONEOK, and we’re committed to continuing to make progress. Third, our strong balance sheet and investment-grade credit ratings, which provides significant financial flexibility. We’ve reduced our leverage to below 4 times and continue to drive that lower, providing optionality for the future cash flows and investor returns. Fourth, our built-in operating leverage and proven track record of disciplined and intentional growth. After completing more than $5 billion of capital growth projects prior to the pandemic, our systems have significant capacity to grow alongside the needs of our customers. And because our large infrastructure projects are complete, we now have opportunities for short-cycle bolt-on type projects at attractive returns. Fifth, the resilience and increasing demand for natural gas and NGLs. We deliver energy products and services that are vital to an advancing world. And we believe these resources will play an important role in the energy transformation. And finally, the depth and experience of this management team who have a proven track record and extensive experience. This team has been through commodity cycles, adapted business models and adopted significant changes in technology and innovation over the years. This team continues to grow our core business and advance our company forward. It is because of these factors and the segment-specific drivers the team will discuss in a moment that I have such confidence and excitement for ONEOK’s future. With that, I’ll turn the call over to Walt for a discussion of our financial performance.

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 in 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 by 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 Storm Uri in the first quarter of 2021. Our 2022 guidance assumes producer activity associated with WTI crude oil prices in the low $70 range. Sustained higher prices could lead to more activity and a quicker volume ramp, which could drive earnings towards the higher end of our guidance range. We expect total capital expenditures of approximately $975 million, which includes growth and maintenance capital. This midpoint reflects the investments necessary to keep up with the expected increase in producer activity and volume expectations, including investments to complete Demicks Lake III in early 2023 and MB-5 in mid-2023. Our routine growth capital accounts for a higher number of well connects and other high-return routine growth projects such as pump stations, compression expansions and other debottlenecking projects to meet our customer needs. Our guidance also assumes the impact of inflation. As we’ve mentioned previously, we have escalators on many of our natural gas liquids, and gathering and processing contracts. These are typically tied to either CPI or PPI indexes and provide protection from rising costs. We expect these types of escalators to keep pace or exceed inflationary costs as we move forward. I’ll now turn the call over to Kevin for an operational update.

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 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, which is 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, we expect continued volume growth from our existing customers and from new third-party plant connections. In the Williston Basin, volumes are expected to increase compared with 2021, supported by higher activity levels and recently completed and expanded processing plants. The Mid-Continent also continues to pick up, particularly from private producers with very recent activity levels providing potential tailwinds not fully factored into our guidance expectations. Our NGL system is connected to more than 90% of the natural gas processing plants in the Mid-Continent. So, any increased producer activity in the region is likely to provide NGL volume to ONEOK, regardless if the activity is on our gathering and processing dedicated acreage. In the Permian Basin, we expect double-digit NGL volume growth on our West Texas NGL pipeline compared with 2021, driven by increased volumes in the Midland and Delaware basins. The volume growth is primarily from long-term contracts we entered into a few years ago, as well as new contracts we have recently signed. Switching to ethane, demand continues to increase with more than 300,000 barrels per day of incremental demand expected to come online in 2022 from new and expanding petrochemical facilities and from growth in exports. Our NGL volume guidance assumes full ethane recovery in the Permian Basin and partial Mid-Continent recovery throughout the year. We’ve assumed no full rate Rocky Mountain region recovery. However, we do anticipate opportunities to incentivize some recovery. This opportunity will fluctuate throughout the year, but a conservative amount is assumed in our 2022 guidance. Moving on to the natural gas gathering and processing segment. We expect volume growth this year in both the Rocky Mountain and Mid-Continent regions. In the Rocky Mountain region, we expect processed volumes to grow 15% at the midpoint compared with 2021 and average nearly 1.5 billion cubic feet per day in 2022. Just five years earlier, in 2017, volumes totaled 830 million cubic feet per day. That’s an approximately 12% annual growth rate over the last five years, while crude oil production has increased in the low single digits. Accordingly, GORs have increased nearly 70% during that same time period. The Williston Basin remains resilient and highly productive. Producers continue to gain efficiencies as they drill in this proven and highly economic region, and the core of the basin is expanding. The North Dakota Pipeline Authority recently estimated that in the last two years alone, more than 7,000 drilling locations have been added to inventory that are profitable at $60 per barrel. This is consistent with what our customers are telling us, as most of them still have decades of inventory remaining. There are currently 33 rigs and 10 completion crews operating in the basin, with 15 rigs and 5 completion crews on our dedicated acreage. This is more than enough activity to grow gas production on our acreage, and we expect that as DUCs are completed through the spring, rigs across the basin will increase. As we’ve said previously, approximately 14 to 15 rigs, which can drill around 300 wells per year, is enough to maintain 1.4 billion cubic feet per day of production on 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. Additionally, more than 475 DUCs remain basin-wide, with more than 250 on our dedicated acreage. We expect to connect 375 to 425 wells in the region this year. In the Mid-Continent region, activity continues to increase. We expect processing volumes in the region to increase compared with 2021, and we expect to more than double our well connections in 2022 to 30 to 50 wells compared with 15 last year. In the natural gas pipelines segment, we expect transportation capacity to be approximately 95% contracted and earnings to remain nearly fully fee-based in 2022. Following a successful open season in 2021, we’re in the process of expanding our Texas natural gas storage capacity by 1.1 billion cubic feet, which will increase our total system-wide storage capacity to more than 53 billion cubic feet. We continue to work with customers seeking additional long-term transportation and storage capacity on our system, which remains highly valued as these critical services are used year-round. Pierce, that concludes my remarks.

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.

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 drives that is the difference between natural gas prices in the Bakken and ethane prices in Mont Belvieu. Therefore, what will push that rate higher is if we see that spread continue to widen, which will encourage more ethane extraction from the Bakken to take advantage of that spread. We are not implementing a new tariff or lowering TNF fees. Instead, we are effectively capturing the difference between gas prices and ethane prices, which is currently broader than what we observed in 2021.

Okay, great. I appreciate that. And then, just maybe a related question, can you give us your latest thoughts on 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 timeline. 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.

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. That issue still persists. If we look back to pre-COVID, we faced some challenges downstream with BTU levels. There were extensive discussions in the basin, and Northern Border proposed a new tariff that was ultimately rejected. FERC requested that the pipeline collaborate with shippers and markets to gather more information. When COVID hit, it significantly reduced volumes, which alleviated the issue. Currently, gas production and capture in the Bakken have returned to pre-COVID levels. The only factor preventing this problem from reoccurring is the ethane we are incentivizing for recovery, which lowers the heat content. If the market shifts and we stop incentivizing ethane, the BTU content at the border could rise to pre-pandemic levels. Northern Border is continuing those discussions, and we understand they plan to approach FERC with a recommendation later this year. In the meantime, we have demonstrated that if we encounter a heat content issue, we can recover ethane to maintain acceptable BTU specifications on the pipeline. However, if ethane recovery is mandated due to 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.

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. 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.

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.

When we consider crude production in the Bakken, we expect it to grow slightly. We don't anticipate a growth rate of 10%, but there will be some increase based on feedback from our customers and the completion schedules we are observing. With that growth in crude production, we also expect our gas production to increase at the previously stated percentages. Regarding the STACK/SCOOP in the Mid-Continent, we had previously indicated that it would remain flat to slightly declining. However, due to recent activity, we are now anticipating a slight increase. This sentiment seems to align with what others have mentioned in their earnings calls as well. Furthermore, the Permian is expected to continue its growth, and we believe we will capture our fair share through both our West Texas LPG asset and our OWT system. Hence, we are confident in our ability to engage in that growth within the Permian.

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

Walt mentioned that as we analyze activity levels, we used a number in the low 70s for crude for 2022. In terms of other commodities, we've reduced our exposure significantly through our contracting practices, so it doesn't greatly affect us. Currently, it serves as a slight benefit with prices at these levels. However, in a $70 crude environment, we would also consider the associated prices for NGLs and gas.

I believe you might have mentioned this earlier. With the 2022 G&P guidance, it appears that EBITDA per Mcf is expected to remain flat compared to last year. The fee rate is also projected to stay within a similar range. Can you explain why unit margins are expected to be flat despite an increase in Bakken volumes? Additionally, it seems that commodity margins might be affected by pricing, but it looks like both hedged and unhedged volumes could yield a better result.

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.

Focusing specifically on the G&P segment, the EBITDA per unit appears to be relatively steady despite the increase in volumes. I expected to see an increase in the fee rate given the rapid growth in the Bakken region. Additionally, on the commodity side, it seems that a discrepancy in price might be a partial reason for this.

One thing I would add is you’ve seen our volume guidance. Our volumes are up year-over-year, and as part of that, we do have some percentage of proceeds exposures, roughly 15% to 18%. With these volumes and these prices, there’s a larger commodity contribution to our EBITDA. The average fee rate is between $1 and $1.05 across our segment, with the Bakken being higher. So I’m not necessarily following your question.

Colton, I think another thing to consider is that we’ve observed fluctuations in the fee rate from quarter to quarter. We’re trying our best to provide you with the average for the year. The fee rate may change based on specific producer characteristics. For instance, if a producer with a lower fee under a POP contract completes several wells in a particular quarter, that could lower the fee rate. What you’re receiving is a blend, but it will vary from 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?

I believe Q4 had some unusual aspects, including higher discretionary employee costs and the timing of certain expense projects. Comparing 2022 to 2021, you'll notice a full year of Bear Creek II, which will come with increased costs due to higher volumes. Additionally, I lost my train of thought for a moment, but those are the two main factors to consider. Historically, our expenses tend to increase over the year because of the timing of various expense projects we aim to complete by year-end. Does that clarify things for you?

It does, yes. Thank you.

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?

Chuck here. We anticipate an increase in volume guidance of approximately 2%. However, I believe it could actually be higher, potentially ranging from 3% to 5%. We have set our volume guidance slightly above last year's actuals. Additionally, we are well-positioned to meet our guidance of 30 to 50 wells, with 4 rigs currently operating on our acreage and solid backing from publicly traded companies, along with a couple of private firms expected to join in Q2 and early Q3. Therefore, our Mid-Continent volumes are projected to rise compared to 2021.

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.

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 included in the guidance as we consider it. Regarding Bear Creek II and Demicks Lake III, we were well advanced in those projects, so when it comes to steel and many materials, most of that was already purchased, delivered to the site, and in many cases, installed. Since then, we’ve renegotiated and rebid everything, and we’re not encountering anything that would lead us to change our cost projections. We are noticing a slight increase, like others are, in general materials and services. However, nothing so far falls outside of what we consider standard, which aligns with the guidelines we established.

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?

I believe your major expenditures will occur this year and early next year. We expect both MB-5 and Demicks Lake III to be completed early in the quarters we've mentioned. We're making every effort to speed up their completion because we want that capacity available. Some of this has also been included in our guidance expectations.

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 has 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. You have mentioned for some time that there are 25 rig connections among 300 a year in the Williston, which is keeping volumes flat. However, you’ve also noted that over the past few quarters, volumes have been increasing. Additionally, gas-to-oil ratios, gas production multipliers, and overall well productivity continue to improve. If we're considering a year-end run rate of over 1.5 years, what are the chances that a reduced rate of well connections, such as 300 instead of the 422 guidance, could maintain that higher level of production compared to what we observed 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.

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?

We continue to see a positive trend in our return on invested capital, which is largely due to the operating leverage. We're experiencing growth without needing to invest significant capital into our established pipeline assets. While we may need to add a pump station occasionally as volume increases, this operating leverage consistently contributes to our bottom line year after year. We have benefited from this trend and anticipate that our return on invested capital will keep increasing in the future.

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. Regarding our well connect cadence for 2022, it is somewhat similar to 2021. As you noted, we had significant momentum with over 130 well connections coming out of Q4. The activity in 2022 is expected to be more concentrated in Q2 and Q3, just like in 2021. We had some momentum carry into Q1 this year. Typically, there is a slight dip in Q2 due to frost laws and spring weather. Therefore, the cadence will be more weighted towards Q3 and Q4, and the volumes related to that will likely mirror 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 one-time costs versus kind of ongoing costs?

As I mentioned earlier, if we consider the entire year of 2021, I believe our costs will increase slightly in 2022 overall. You'll see a complete year of Bear Creek II. Additionally, I forgot to mention that we will see an increase in our ad valorem taxes in 2022 compared to 2021. There are also ongoing volumetric costs related to the growth we are experiencing throughout our system.

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?

When we examine the Permian, we remain highly competitive as we continue to attract new customers. We possess significant advantages, including existing pipeline infrastructure and connections to various unintegrated players seeking alternative sources. Additionally, we have cost-effective expansion options within our system that allow for ongoing growth. This enables us to offer a competitive alternative to others in the basin, which is reflected in our increasing volumes. We are experiencing double-digit growth, as well as additional growth from our existing contracts. As their volume increases, it contributes to our system due to our long-term contracts, which we have established in all our regions.

So, Michael, I can provide some insights on that. This is Pierce. Yes, we do consider M&A opportunities in all of these basins, categorizing them into defensive plays versus proactive assessments. Specifically regarding our NGL business, when we examine the duration of our contracts in many locations and the prices required to acquire the gathering and processing opportunities that support the NGL sector, we don't view these as suitable investments for our capital in terms of shareholder value. While we explore these opportunities, we haven't identified any that we find appealing so far.

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. Regarding our capacity at Elk Creek in the Bakken, we currently have a capacity of 440,000 barrels per day. Right now, we are operating in the range of 330,000 to 350,000 barrels. We have sufficient capacity for the foreseeable future, especially since we have incentivized ethane and are incorporating that into our operation. We believe we can handle additional capacity moving forward and could easily increase our output by another 100,000 barrels per day by adding some additional pumps in a short timeframe. Therefore, we are quite confident in our capacity from the Rockies.

And Alex, regarding the POPs, we addressed that earlier. We're considering it in a low $70 crude environment. If you look back at NGL prices within that range, that should give you a rough idea. For gas, it would be in the upper $3 range as well. It's also important to note that we are about 75% hedged for those POP contracts in 2022, so there isn't much commodity exposure left when you account for the impacts of the hedges.

Hi, thanks for bringing me back for another question. Our discussions with regulators in North Dakota highlight a strong focus on the potential for carbon capture and supportive state policies for its development. North Dakota stands out as one of only two states with Class 6 primacy, which permits the development of CO2 wells at the state's chosen pace. Additionally, the Summit pipeline is progressing toward North Dakota. I’m curious if you have any updated insights regarding ONEOK's stance on carbon capture and whether it might realistically become part of the initiative at some point. Do you have any visibility on this?

Yes, Jeremy, it’s Kevin. We are currently engaged in discussions with state officials and other private entities regarding opportunities. We have had several conversations with them already and have more scheduled soon to explore this further. I believe there are several opportunities available. Our expertise lies in processing, building pipelines, and storage. The challenge is finding the right partners and opportunities before we proceed, but we are actively pursuing this.

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.