Welcome everyone. Thank you for joining us. It is my pleasure to introduce our next company, ONEOK, a leading midstream service provider with a premier NGL system that connects critical NGL supply in the Rocky Mountains, Permian, Mid-Continent regions with key market centers. With us, we have Walt Hulse, CFO, and Kevin Burdick, Chief Commercial Officer. Thank you. Thank you. Thanks. Welcome to you both. Okay. At this point, you know, we're two and a half years past the pandemic, or since the pandemic began, rather. Your organization has navigated through tremendous challenges during that time, including, you know, COVID, major and multiple weather events, both this year and last year, and most recently, the Medford Fire. Yet the cash flows and outlook remain remarkably resilient. Again, reflected in your reaffirmation of 2022 guidance. What qualities within ONEOK do you think has allowed for success through these tumultuous times? Well, I think that it comes back to our asset position and, you know, to be really dialed back to even before COVID, at the end of 2019 and the first quarter of 2020, we put into service about $6 billion worth of capital investment, and then COVID hit. It took us a year to get past that and really start to see the ramp up. We had the customer supply that was waiting for those assets to come on, and they have continued to perform as we had expected them to. While our cash flows may have been delayed nine months to a year, we've achieved all those goals that we expected to prior to the pandemic coming. I think it comes down to our asset position, primarily in the Bakken, where we have a meaningful market position in the G&P business and a very significant position in the NGL business. But we also have a very strong footprint in the Mid-Con, and our presence down in the Permian is very focused in our NGL takeaway and our gas takeaway. Good diverse business across the way, assets that meet the customer's needs, and they were really built to satisfy specific customers' needs. Great. It sounds like that latent demand did, you know, ultimately, obviously come to fruition. At this point, I'd love to get an update on how volumes are trending across your G&P assets and how that ties into your outlook for the second half of this year as well as into 2023. I think they're trending well. You know, coming out of the storms in April, the volumes, you know, took a couple months to get back. When you look at starting in the Bakken, you look at some of the state-reported information that came out here very recently. You know, gas production's back up to nearly 3.1 Bcf a day, which is a good, you know, good trend for us. We've seen volumes across our system kind of mirror that. With our well connects, we talked on our third quarter call that we do expect a strong second half of the year for well connects, and again, reiterating the range that we originally put out. On the volumetric side, you know, albeit because of the storms in April, you know, that trended into May, our gathering and processing volumes will be towards the lower end of the range of guidance, but the NGL volumes will reaffirm the midpoint of that guidance as well. All in all, things are progressing nicely. Got 45 rigs in the Bakken. You know, roughly half bounces around a little bit are on our acreage. That's plenty of rigs to grow gas production, as we think about the back half of this year, but also into 2023 and beyond. And through discussions with our customers, there's opportunities, I think, for some additional rigs to show up as well. All those are nice tailwinds. Move down to the Mid-Continent. Similar story there with high NGL and natural gas prices. We've seen activity pick up in the STACK and the SCOOP, and that's really transitioned our thinking. You know, several months ago, we were probably thinking the Mid-Continent was a slightly declining environment. Now we believe it's gonna be a slightly increasing environment as it relates to volumes. Almost all the incremental volume that comes on the system is gonna ultimately come to our NGL system as we're connected to about every plant in that region. Permian, we're getting our fair share. We're not one of the biggest NGL players out there, but we absolutely are getting our fair share, and we're seeing volumes grow. It was nice to print in the third quarter on our third quarter earnings call to see volume growth in all three of our regions from an NGL standpoint. All in all, things trend nicely the rest of this year and into 2023. Perfect. I do wanna touch on some of these, you know, fundamental producer-driven trends that you're seeing both, you know, upstream and into your integrated system. First, I wanna talk about, you know, the growth that is embedded in everything that you just said. There seems to be good visibility for ONEOK to get to that, you know, 3.5x or lower target leverage target. You've also talked about wanting to get below the 100% payout ratio as another governor of capital allocation, right? I guess within that context, what do you think is the optimal payout ratio? Well, we haven't put a specific number out there, but I think that the guidance that we've given to date is that we don't need to get all the way down to a utility 50%-60%. But we definitely want to be below that 100% that we're just crossing through. Somewhere in between there. It's not a bright line that when we get to this specific number, we will then be there. What we wanna do is make sure that we see a trend that is sustainable, and that when we get to a point where we start to allocate capital back to dividends and/or stock buybacks, that if we were doing dividend increases, that they would be within our earnings growth going forward, so that we maintain that payout ratio on a going forward basis. To the extent that we had excess cash flow and didn't have investment opportunities, then we would probably look at share buy-backs. Okay. Let's just tie that all up neatly. Okay. In terms of, you know, let's fast-forward, ONEOK has achieved all these financial goals and metrics. Walk us through how you would balance, you know, organic growth, dividend increases, and share repurchases as each, versus the other in terms of incremental, you know, competition for that. Sure. Free cash flow dollar. Well, I think at the end of the day, you know, where we've been very successful is finding opportunities to invest capital at superior returns to the rest of the industry. The reason we've been able to do that is that the asset position that I mentioned before gives us opportunities to build incrementally off that, so that we can serve a customer's needs, and also achieve above industry returns. To the extent that those opportunities present themselves, we're gonna continue to do those. Cause if we can invest our money at that 25% type of IRR, or even 20%, that's very attractive as it compares to our cost of capital. You know, we do see the opportunity for investments to be slower than it was, say, three or four years ago. We do see on the horizon a good number of investment opportunities ahead of us. We're excited about what we see from an earnings growth perspective. You know, if you dial back to 2015, we were at $1.5 billion of EBITDA. Today, our midpoint is north of $3.6 billion. That's been quite a trajectory over that period of time. While the slope of that may not be at the same steepness, we do see, you know, growth here going into the future. You know, we've been a strong dividend payer over time. I think that, you know, we would probably lean towards that. I think we wanna be disciplined and stay within our growth and not get ahead of our payout ratio. You would probably see stock buybacks come on the latter part of that series, you know, if we had excess cash flow above our investment opportunities and our dividend growth. Fair enough. Going back to the fundamentals and the activity across. Can you talk about your views on the medium to long-term outlook for the Bakken in particular, in terms of the quality of reserves, the depth of inventory there, the types of customers that you have, on your acreage, and how that drives the durability of the volumes that you see flowing across your systems? I think all those things play into we have a very strong point of view on the mid to long term for the Bakken. First of all, our customer base is really the who's who. It's pretty much everybody in the play. We gather and process at least some amount of their natural gas. As we talk to them, they clearly have a long-term outlook for the play, especially those that have large acreage positions. When you think about the Continental Resources and the Marathon Oil and the ExxonMobil and the ConocoPhillips, the Bakken continues to get capital allocated from, you know, for those companies. They look at the trajectory, and they're looking at over 10, 15, 20-year horizons. Like Walt said, do we necessarily see, you know, the 15%-20% growth year-over-year that we saw back in 2013, 2014, 2015? Probably not. At the rig count levels you're seeing today with what they're telling us, I do see growth on the oil side, slight growth on the oil side. If oil production's growing, then with the rising GORs, your gas production's gonna be growing at an even steeper clip. All that, to me, sets up not only with the midterm horizon, but also longer term, as we factor in over time gas to oil ratios rising as well, which is another benefit to us. Got it. Going back to your comment about the rig activity, so 45 rigs currently in the Bakken. Yeah. What are your expectations of what that number can get to? If you can remind us, you know, your expectations for well connects in 2023 versus 2022, even just directionally? We haven't provided guidance for well connects for 2023 at this point. Our midpoint is around 400 well connects for 2022. If you think about, just put some math to it, that a typical rig can drill 21, 22 wells a year, some simple math gets you to slightly less than 20 rigs, gets you to that number. If we're sitting at 22, 23, 24, you know, rigs in the Bakken, or I'm sorry, 45 rigs overall, if you cut that in half. If we're at 22, 23, 24 rigs. That's gonna put you above the 400 number just from a math perspective. If we see these rigs remain in the basin, if you get a couple more coming in, then you would expect that you'd see a slightly higher well connect number for 2023. Got it. What are your expectations for ethane extraction out of the Bakken? How's the recent low AECO pricing impacted your thinking on recovering and incenting more ethane out of the basin? We've said all along, and we continue to believe it's going to be sporadic. Some months we may recover incentives more than other months. Some weeks we may incentives more than other weeks. We've said we've been very consistent with, say, it's a day- to- day, sometimes week- to- week, month- to- month type decision that we make, and it's all dependent on what's going on to the gas price in basin. What is the alternative can you sell the ethane, I mean, get more value by selling it as residue gas or by extracting it and putting it in the NGL pipe? AECO is a decent marker. There are some other things when you think about Fort Morgan and Empress or other constraints that may be changing what the ultimate gas price that companies can get in the Bakken. It is a pretty good marker. The wider you see that spread between, say, a Henry Hub or a Ventura and AECO, the more opportunity we're gonna have to incent the ethane recovery. The rate will just be determined by whatever again the alternative is to sell it as an MMBtu in the gas stream versus recovering it. We do see it pretty strong. One thing I might add to that is that, you know, one of the things when we talk about incenting, sometimes people think about it as a reduction of fee. You have to think about the tariff that we have available. With a $0.30 tariff, we have a lot of room. If you look at the other basins, if you're getting full tariff, you're somewhere $0.07, $0.08, $0.09, $0.10. If they have the opportunity, that's the maximum they can make. When we have the opportunity to incent, we can still be doing that at a multiple of what we might be doing it in a different basin, just maybe not getting that full $0.30 rate. Sure. That makes sense. If ethane extraction does pick up, how soon do you think you will need that 100,000 barrel per day pump related expansion on Elk Creek? And can you also remind us, you know, how much you would expect it to cost, and how quickly you could bring that online? The way we've talked about that is, first of all, we still got quite a bit of capacity remaining when you combine Elk Creek at 300,000 barrels a day and the original Bakken line at 140,000. So that's a total capacity of 440,000 barrels a day. I think we were at 360-something in the second quarter. So that gives us quite a bit of headroom. As we think about it, we're not gonna be caught short capacity for NGL takeaway out of the basin given the, you know, the rates and the margins we're able to achieve up there. The way we've talked about it is it's adding pump stations is how we would expand the pipe. Those are projects that don't need a 2-year lead time. We're probably already doing some things to prepare and shorten that window, should we need to pull the trigger. As far as capital, it's measured in tens of millions of dollars, not hundreds of millions of dollars. We're not talking about another $500 million just to expand it by 100,000 barrels a day. That's the way we're looking at it. We're watching it close. We're continually talking to our customers about what their growth plans are and the timing of that. As we need that capacity, we'll get on it and get it added. Got it. From the perspective of your downstream customers, with the petchem industry facing demand headwinds, you know, as a result of global recession risks and all that, and you know, seeing economic run cuts, both in Europe, Asia and domestically, how should we think about the outlook for frac spreads? There have definitely been some things here recently that have, you know, pulled the frac spreads in very tight. You know, there's been some logistical issues with getting polyethylene out. There's been some, you know, obviously the gas price run-up has driven up the price of ethane. Those ethane-only crackers, their feedstock costs have gotten pretty high, which has caused some switching. There are things like that that are going on. Typically it's a little cyclical. Stocks will build. As things work off, it'll come back in line. I think the unknown at this point is what's going on with global demand, from a recession type perspective. That's something we'll be watching close. There's still a lot of ethane that's being pulled out, you know, on a day-to-day basis. With our ability in the Bakken especially, we're not comparing to Henry Hub, right? You're comparing to what's going on with the gas price in the basin. Sometimes if even if the rest of the markets, the frac spread's incredibly tight, well, if you look at it in the Bakken with what's going on relative to natural gas, that frac spread's still pretty strong for us. Sure. I guess just from a supply perspective, given the sheer amount of frac capacity coming online over the next, you know, year and a half or so, is there any concern from your perspective related to the economics of that for the industry? I'm sorry, what capacity is coming up? Frac capacity coming online. Frac capacity coming online? Yeah. We've been focused on, you know, Medford and making sure we've got a home for our barrels, which we do. We've got MB-5 coming up in the, you know, early in the second quarter of next year. So that'll give us 125,000 barrels a day of capacity. You've got another, you know, couple fracs coming up late this year and then some late next year. You know, right now, the market's running really tight. I think all the projections we're looking at says overall NGL production's gonna grow. It's not necessarily good for the industry to be running at incredibly high utilization rates. I mean, it's good 'cause you wanna utilize your assets, but it's bad if you have disruptions. I think it'll be cyclical like it always is, where it might be long for a short period of time, and then as volumes grow, we'll grow into that capacity, and then and it'll tighten up again. I don't necessarily think we're gonna be, as an industry, incredibly long for a period of time. You're right, you're gonna ramp into the volumes for the fracs as they come up. I think that will happen over the next 2-3 years. Okay. On Medford, at this point, nearly two months after the incident, would you be able to provide an update on the facility currently and what's happening there? Well, at the moment, we're still in the assessment phase. You know, we have a team of engineers out there looking at what it's gonna cost to repair the facility. The insurance companies have a team of engineers out there doing the same. The good news is we have a fantastic insurance policy, both on the property side as well as the business interruption insurance. The carriers for those two policies are the exact same, so everybody's aligned. There's no competing agendas whatsoever. Everybody's looking for the quickest solution to get us back the capacity that we had and needed. You know, at this point, we don't have a definition on time yet. or whether we will be reconstructing there at Medford. There is a possibility that we would go ahead and reconstruct down in Mont Belvieu. That's just gonna come down to what it's gonna cost to repair the facility in Medford. Our insurance policy allows us the flexibility to do it in either place, whichever is better for us given the economics of what it would cost to replace or repair. We're gonna make that decision in due time when we have all of the information. In the meantime, we're well insured to pick up the difference between what we would have made but for the event. Right What we're gonna make is entirely covered throughout the system. I think that's another important point because it's not just a Medford-specific insurance policy. It's as it relates to the whole system. If we've adjusted our fracs to maximize capacity and that causes us to avoid upgrades or certain things we might have done from an optimization, we still get recovery for those other pieces to the puzzle. It's a system-wide policy, and expect to hopefully get that started right here in September, so we don't even have any issue in the third quarter. Worst case, there may be a cash flow, it may carry over into October, but it would all be caught up by the end of the year. Got it. If I could clarify, the point made about the optionality between, Building in Mont Belvieu versus repairing Medford. Within the property claim portion of the insurance, I imagine, is it that if it's cheaper to build in Mont Belvieu versus repairing Medford, then you have that option? Or regardless of the price, you can go the other way? I wish it was that straightforward and simple that you could do it, but it's not, because there are a variety of different factors that play into it. You know, if we were to do something in Mont Belvieu, we have all the permits in place. We have done, you know, we're on MB-5, so they're cookie cutters. We know exactly what we're doing. Medford was a facility that had 210,000 barrels of capacity. Its original construction was 20,000 barrels. It was expanded and expanded and expanded over time. In this day and age, it would make no sense to actually reconstruct it as it was. We would be doing a re-engineering of the facility. The time it would take or will take to repair and engineer and go through the whole process will be longer at Medford. We'll have to evaluate what the cost recovery will be at Medford and then think about what the timing difference would be, because during that timing difference, if we were to finish in Mont Belvieu, the business interruption claim would stop. Okay. That's the benefit of having all of the same insurers on both policies, is that we're all aligned in there to make the right decision. That makes sense. I guess commercially, is there any reason to rebuild in Medford, regardless of the timeline? Where it seems like every incremental NGL barrel is, you know, optimally frac'd at Mont Belvieu. Going back to, I'll let him talk about the commercial, but going back to the math on the claim, I mean, like I said, we're still evaluating. There's a good portion of the facility that's perfectly fine. Okay. We have to evaluate what it's gonna cost to rebuild it, to that capacity. If that number is large enough, plus the benefit from the, lower business interruption, We would have the latitude to make that decision to go to Mont Belvieu. If we can repair and replace at a lower cost in Medford, then we'll likely do that in Medford. Commercially. Yeah. I mean, commercially, there are. I mean, if Sheridan were up here, I say, there's a lot of moving parts. There really are. When you think about the customers, there's products that are needed in the Mid-Continent, there's products that are needed in the Gulf Coast. The beauty of our situation is we do have a lot of flexibility and optionality in where we would put that capacity. We've got storage in the Mid-Continent. We've got pipelines that would connect the Medford facility up to storage, our storage assets, back and forth. From that standpoint, we've got our Sterling pipelines that can transport purities to the Gulf Coast. We've got our Arbuckle pipelines that can take raw feed to the Gulf Coast. We'll go through the analysis if there's questions or if it's close, and just think through all the situations of where do we want the raw- feed barrels frac'd? What does that do to our pipeline system? What does that do to our frac system, and what's it do to our storage? We'll have to factor all those three in to ultimately determine where we would want that capacity. Okay, great. Maybe turning to the cost side. Clearly, we're seeing a lot of expense inflation up and down the value chain. How are you managing through these cost increases? On the flip side, can you also talk about the inflation-linked, you know, fee escalators within your contracts? Yeah, the way we've talked about that is, and it remains consistent, is we still believe at this point that the fee escalations we're seeing on the revenue side of things are gonna more than outweigh the cost increases we're seeing from an inflationary standpoint. In the gathering and processing business and the NGL business, both virtually all of our contracts have some sort of fee escalation tied to a PPI or CPI type indicator. In our gathering and processing business, the vast majority of those contracts escalate at the same time. That's typically in the spring, and that's why you saw a pretty good pop in our fee as we went through our second quarter call. In the NGL business, those contracts escalate periodically, just kind of as the contracts were signed throughout the year. They're escalated on an annual type basis, and you'll see that continue as we move through the year. On the cost side, we're seeing some of the same pressures everybody else is seeing. Probably more, we probably have more discussions about lead times than we have about cost. Just making sure critical spares and other critical materials we need to run our business, we're absolutely staying ahead of that given some of the supply chain constraints. Are costs creeping up a little bit? Yes. Do we still think those are gonna be well within the escalations we're seeing on our contracts? Yes. Excellent. Last question, I do wanna touch on the Inflation Reduction Act. Both in terms of its tax implications on your business, as well as support for potential renewables investments, over time. Love to hear your views on that. Well, on the tax side, we're in kind of an interesting situation in that the change that was made at the eleventh hour to allow us to use our tax depreciation in the calculation was a big positive for us. 'Cause if you think about it, in 2020, we put the Arbuckle II pipeline in service. We put Demicks Lake II in service, I'm sorry, and MB-4 in service. You know, billions of dollars of assets went into service, and we get the benefit of that depreciation as we do the initial calculation. You know, we will be hovering around that billion-dollar mark and may not even be subject to the tax for a couple of years going forward, given the tax depreciation that we have. The ultimate benefit of that is that as we switch over, we would switch over to that 15% rate going forward and probably never jump up to the 21% statutory rate that we would have had we let the NOL just run its course, because we will still have an NOL at that point in time that we switch over to the 15% minimum. The NOL then just continues to tag on to the back end and would keep us at the 15% for the foreseeable future going forward. The net impact to us in our situation, just where we sit, given the assets we put in place, is gonna be negligible to possibly even a very minor positive, on a going forward basis. Wonderful. Thank you so much. Thank you. for your time and insights. You bet. Thank you. Thank you very much.