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, and 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, 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 and lingering panic, pandemic-related challenges, we grew Adjusted EBITDA 24% compared with 2020, continued to strengthen our balance sheet and achieve 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 and the environment is a core value for ONEOK. It's critical for us to be 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 provide significant financial flexibility. We've reduced our leverage to below 4x 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. Because of our large infrastructure projects are complete, we now have opportunities for short cycle, bolt-on type projects at attractive returns. Fifth, the resilient 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. 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 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 4x, passing through an important marker in our continued deleveraging strategy. We continue to prioritize reducing leverage below 4x and view 3.5x 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 in 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-$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 midpoints 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've continued 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 midpoints, 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 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 bpd 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 incent 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 process volumes to grow 15% at the midpoint compared with 2021 and average nearly 1.5 billion cf/d in 2022. Just five years earlier in 2017, volumes totaled 830 million cf/d. 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 /bbl. 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 five 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 14-15 rigs, which can drill around 300 wells per year, is enough to maintain 1.4 billion cf/d 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 375-425 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 30-50 wells compared with 15 last year. In the natural gas pipeline 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 cu ft, which will increase our total system-wide storage capacity to more than 53 billion cu ft. 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. Thank you. If you'd like to ask a question, please signal by pressing star one on your telephone keypad. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, press star one to ask a question. Our first question today comes from Michael Blum with Wells Fargo. Thanks. Good morning, everybody. I wanted to go back to the comments on incentivized ethane recovery in 2022. Can you just give us a sense of, you know, what's gonna drive that? Have you changed the rates directionally that you're charging on that incentivized ethane? Michael, this is Sheridan. What we said before, what drives that is the difference between natural gas prices in the Bakken compared to ethane prices in Mont Belvieu. What's gonna drive that rate higher is if we see that spread continue to widen, we will incentivize more ethane out of the Bakken to capture that spread. It's not. We're not putting out a new tariff or reducing T&F fees. We're actually literally capturing gas price to ethane prices, which today has widened out wider than what we saw in 2021. Okay, great. Appreciate that. 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 gonna need some more gas capacity? Thanks. Yeah, Michael, this is Chuck. I do, and we do. We believe that the Bakken will need some residue takeaway, let's say in the next, call it three years, either side of that. As you may have heard on TC Energy's call, they said, "Don't be surprised if you see an open season this spring." Frankly, I think all stakeholders, processors, pipelines, and producers realize the decision probably needs to be made this year to effectuate that timeline. Between Northern Border's Bison Xpress Pipeline and some underutilized pipelines in the Powder River Basin, I think we'll be able to go ahead and manage that egress. Our next question will come from Jeremy Tonet with JP Morgan. Hi, good morning. Just wanted to pick up on the Bakken a little bit here. I guess, you know, more thoughts about NBPL and heat content and given kind of the trajectory here. Just wondering if you could walk us through, I guess, procedurally, you know, 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, you know, less ethane accepted or just any thoughts you could share there. Yeah, Jeremy, it's Kevin. Yes, that phenomenon still exists. 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. 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. 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. Absolutely Northern Border continues to have those conversations. It's our understanding, they will go back to FERC with a recommendation sometime this year. 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. 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. Maybe just kind of pivoting towards the guidance for a minute here, and thanks for kind of listing some of the, you know, puts and takes, but just was curious, you know, if we think about kind of the formation of the guidance, I imagine this wasn't formed last night and it was formed a little while ago. If you kind of overlay, you know, the world today as we see it, you know, in 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, you know, any other thoughts on, you know, what's happening today and how that colors, I guess, where you could fall in the guidance range? Jeremy, this is Pierce. I think given, you know, 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 volumetric 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. We'll hear next from Brian Reynolds with UBS. Hi, good morning, everyone. Maybe just to follow up on the guidance and talking about, you know, the upper end of the guidance range, which we seem to be pointing towards. Just kind of curious if you can help me reconcile you know, the upper end of the G&P growth versus the NGL, you know, throughput. It seems like, you know, G&P growth is a little bit higher. Just kind of curious if you can give a little bit more, you know, commentary around ethane recovery assumptions. You know, are you assuming a little bit of ethane rejection into 2022, or is that just kind of a conservative estimate with, you know, ethane recovery to the upside? Thanks. Brian, this is Sheridan. I think what they 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 NGL, the increase was across our region. One of the big contributors to that is the Midcontinent is growing less than 8%, so that's bringing down the average for the NGL segment. Also in our guidance, we have less incentivized ethane than we did in 2021. 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, you know, capital allocation. You know, the high end of the guide kind of implies 2022 leverage exiting near 3.5x. Just curious if you could talk about the evolution of the long-term leverage target and, you know, how we should think about, you know, future opportunities around return of capital, you know, as we get into the end of the year and into 2023. Thanks. Well, we're very pleased with you know, how we've progressed on our leverage metrics and that we broke through that 4x and are heading in the direction as you mentioned. You know, 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%. You know, that's trending again also in the right direction. We'd like to see that get some room under that 100%, as we look and think about capital in the future. 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. We'll look at that as the year progresses going into 2023. Great. Appreciate the color. Have a great day, everyone. Our next question comes from Theresa Chen with Barclays. Morning. I was wondering if you wouldn't mind providing some incremental color on your production 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? By your customers. as we see it, or. By- By our customers? Yes. I mean, when we think about crude production in the Bakken, we believe it will grow slightly. We don't think it's gonna 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's gonna grow at the percentages that we've outlined previously. I guess that's how we're thinking about that. STACK, SCOOP, you go down to Midcontinent, you know, this is one that we've been saying flat to slightly declining. However, with the recent activity pickup, 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. Obviously the Permian is gonna 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. We believe we can participate in that growth in the Permian. Got it. 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 2022. As we think about the rest of the commodities, you know, we've driven so much exposure of the commodity exposure out of our business with how we contract, you know, 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've been looking at. Thank you. We'll hear next from Colton Bean with Tudor, Pickering, Holt & Co. Morning. I think you may have just touched on this, but with the 2022 G&P guidance, it looks like EBITDA for MCF is effectively flat year-on-year. I know fee rate is guided to a similar range. 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, you know, that may be skewed a bit by price deck, but it seems like for both hedged and unhedged volumes, you'd have a better outcome there. Colton, are you talking specifically about G&P or are you talking about Just the G&P segment specifically. Oh, I'm not sure we followed exactly what you're asking there. Yeah. Looking at the G&P segment, if I just take the- You're looking. G&P. Yeah, the G&P EBITDA versus volumes, it looks like EBITDA per m, so on a unit basis is kind of flattish. But I would've thought that the fee rate would've seen some escalation with the Bakken growing as quickly as it is. Then on the commodity side, it sounds like that may be, you know, 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, or obviously our volumes are up year-over-year. As part of that, you know, we do have some percentage of proceeds exposure, roughly call it 15%-18%. At these volumes and these prices, you have a larger commodity piece contribution to our EBITDA. The dollar-for-dollar $5 average fee rate is across our segment. Obviously, the Bakken's higher. 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. We're doing our best to give you the average for the year. That fee rate can move around depending on specific producer characteristics. 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. What you're getting there is a blend, but it's gonna bounce around quarter- to- quarter. Yeah. No, understood. Can follow up with that. I think looking at it from a high level, it just looks like the EBITDA per m is relatively flat. With both commodities and Bakken growing, was a bit confused there, but can follow up on that. You know, on the OpEx side of things, I know you mentioned compensation factored into that. 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 and the timing on some of our expense projects. If you think about 2022 relative to 2021 and look at a run rate, you know, you're gonna have a full year of Bear Creek II and you'll see increased costs just with increased volumes, which we'll see. And then lastly, you will see some level of. Sorry, I just lost my train of thought here. Those are the two big drivers we'll see. 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. Yeah. Thank you. You bet. Our next question comes from Jean Ann Salisbury with Bernstein. Hi, good morning. I had a question about Mid-Continent guidance. It looks like you're projecting basically flattish gathering and processing volumes in 2022 versus 2021 in the Mid-Continent, 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, this is Chuck. No, we see an increase. I think our volume guidance came out roughly 2%. We actually think that might be a little light; it might be more like 3%-5%. We did guide on volume slightly higher than our actuals from last year. We do have good line of sight to the 30-50 well count that we put out in guidance right now. We've got four rigs operating on our acreage. Well-capitalized publics behind that with a couple of privates coming in Q2 and early Q3. I would say that our Midcontinent volumes will be up obviously relative to 2021. Okay, that's helpful. Thanks. 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, this is Sheridan. When we think about Elk Creek expansion, really we do look at them both together. We both look at Elk Creek and the Bakken pipeline to understand when we need to expand. 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, and as we optimize that, we may decide to increase the pumps on that east-west section so that we can move more back off OPPL to optimize our earnings. That's kind of what we look at when we are going forward. Right now we feel with the Bakken OPPL connection and Elk Creek, we have plenty capacity to meet our customers' needs, and it's just gonna be an optimization when we expand. Great. Thanks. That's all for me. Our next question comes from Michael Lapides with Goldman Sachs. Hey, guys. Thank you for taking my question. Just curious, cost of everything in the world's up, meaning Michael, we could barely hear you. Hey guys, can you hear me now? There you go. Hey guys. Perfect. Okay. There you go. Real quick, cost of everything's 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? If we look at your CapEx forecast, are you seeing changes at all in which 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. 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, you know, 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, you know, 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. So far nothing that would be outside of what we would consider norms, that and the philosophies 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. Again, all that's baked into what we've got from our growth and maintenance capital budget. Got it. 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'll be your heavier spend this year and early next year. You know, we do believe both MB-5 and Demicks Lake III will be completed early in the quarters that we've provided out there, and we're doing everything we can to accelerate them even more, 'cause we'd like to have that capacity available. And some of that's factored into the guidance expectation as well. Got it. Thank you, guys. Much appreciated. You bet. 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 seemed like the Rockies was just $0.01 lower sequentially. I was wondering to what degree that's just random fluctuation or it reflects you know the level of incentivized ethane, or does it impact maybe some volumes actually starting to increase out of 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 pulled that down slightly from Q3, I think is what you're referring to. 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- I was talking about the $0.25 versus the $0.24. Oh, on the Elk Creek or the Rockies rate? Yes. Yeah. That is a function of the incentivized ethane. That drop in a penny has nothing to do with anything contractually that's going on. It's purely the incentivized ethane. Gotcha. Y'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. You've kind of been saying that over a couple of quarters. The volumes have been increasing. At the same time, you know, GORs, GPMs, and overall well productivity keeps improving. If we're thinking about, you know, over a 1.5 billion cf/d 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, say, in the third quarter? Yeah. 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 gonna need fewer wells to hold production flat. Now we'd like to see, obviously, the same capital deployed and grow production. At the pace we're going on right now, that's been a trend over the last several years, is each year it seems like the same number of wells will allow us to stay flat even though the baseline keeps getting larger. You know, that trend could absolutely continue. Great. Thank you. Next question comes from Tristan Richardson with Truist Securities. Hi. Good morning, guys. 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. 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. You know, that really comes back to the operating leverage that we're seeing growth, and we don't have to put capital, you know, meaningful capital into our pipeline assets that we built. You know, 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. We have enjoyed and expect to continue to enjoy increasing return on invested capital going forward. Helpful, Walt. Appreciate it. Thank you. 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, you know, seems like the well completion activity in Rocky Mountain was very strong in Q4. I was curious, you know, if you kind of can talk about what kind of cadence we should see in volume growth in that region, especially considering that, you know, typically Q1 also sees some weather events. So should we be thinking of, you know, 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. You know, we had, as you said, a lot of momentum, 130+ 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 Q1 of this year. Q2 typically it's a little dip every year because of frost laws and the weather, spring. The cadence would be more back weighted to Q3 and Q4. Volumes associated with that would probably resemble the well connect activity. Got it. One follow-up on the cost issue. I realize that, you know, Q4 seems like, you know, sequentially your costs were up about $25 million or so versus Q3. What's a good way to kind of think about that, you know, breakdown in one-time costs versus kind of ongoing costs? Well, like I said, 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, you know, before you'll see a full year of Bear Creek II. The other item I forgot to mention earlier was taxes. You'll see, you know, we'll have an increase in our ad valorem taxes in 2022 versus 2021. Those types 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. Got it. Thanks a lot, color folks. Our next question comes from Michael Cusimano with Pickering Energy Partners. Hey, good morning, everyone. 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, you know, what you view as your competitive advantage there, and if that's a growth area from here. Lastly, just if you've looked at any acquisitions in order to 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 advantage is we have a pipe in place there today. We're connected to a lot of unintegrated players that want an alternative source. We also have cheap expansions on our system that we can continue to grow. We can continue to provide a competitive alternative to other people out in the basin, and we see that because our volumes continue to grow. 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. We have long-term contracts in place as we do in every other place. The M&A question. Michael, I'll weigh in 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, you know, 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, you know, the G&P opportunities that feed the NGL business, then we just don't see that as being, you know, maybe a place where we would deploy our capital, when you look at it as the, you know, the benefit to our shareholders. Yes, we look at them, but so far we hadn't found anything that we think is attractive there. Great. Thank you. Our next question comes from Alex Kania with Wolfe Research. Hi. Good morning. Maybe two questions. The first is, just I was thinking about the headroom on the kind of your pipeline infrastructure out of the Rockies. Could you remind us, maybe you said it, I might have missed it on the call, but you're at 335,000 bpd in Q4. So what's the expectation of that going, you know, as you're assuming for 2022? 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, you're talking about kind of the outlook for the G&P business for this year. Thanks. Alex, this is Sheridan. As we think about the capacity on Elk Creek and the Bakken, as I said, we think about them together. We currently have 440,000 bpd capacity. As you said, we're running in the mid 330,000-350,000 bpd 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 as well, so we're pulling that into that. We think we have plenty capacity on that system going forward for a period of time, and we can take it up another 100,000 bpd pretty easily, just adding some additional pumps in a very short period of time. We feel very comfortable with our capacity coming out of the Rockies. Alex, on the question about the POPs, we provided that earlier. We're again thinking about it in a say low $70 type crude environment. If you go back and look at, you know, what NGL prices were doing when crude was kind of in that range, that gets you in the ballpark. And then gas, you know, 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, you know, about 75% hedged when you look at it, in 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. Got it. Thanks for that. 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. North Dakota being only one One of two states that has Class VI primacy that allows CO2 wells to be developed at the pace the state sets there, you know, kind of sets them apart from others. Also you have the Summit pipeline pointing towards North Dakota in progress. They're just wondering any updated thoughts that you have, that ONEOK has on carbon capture, and could this be something, that realistically enters the fold at some point? Do you have any visibility here? Yeah, Jeremy, it's Kevin. Yes, this is something we are actively involved in conversations with state officials, with other, you know, 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's some opportunities when you look at that's what we do, right? We know how to process things, we know how to build pipelines, and we know how to store things. I think there's opportunities. It's just finding the right, you know, the right partners up there and getting the right opportunities before we'd pull the trigger on something. It's definitely something we're actively working on. Got it. That's helpful. I'll leave it there. Thank you. 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. This concludes today's conference. Thank you all for your participation. You may now disconnect.