Good day, and welcome to the ONEOK Q1 2023 earnings conference call and webcast. All participants will be in a listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press Star, then one on your telephone keypad. To withdraw your question, please press Star, then two. Please note, this event is being recorded. I would now like to turn the conference over to Andrew Ziola, V-VP of Investor Relations. Please go ahead. Thank you, Chad, and welcome to ONEOK's Q1 2023 earnings call. We issued our earnings release and presentation after the markets closed yesterday, and those materials are on our website. After our prepared remarks, management will 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 nineteen thirty-three and nineteen thirty-four. 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 for Q&A, we ask that you limit yourself to one question and one quick 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. Good morning, everyone, and thank you for joining us. On today's call is Walt Hulse, our Chief Financial Officer and Executive Vice President, Investor Relations and Corporate Development, and Kevin Burdick, the Executive Vice President and Chief Commercial Officer. Also available to answer your questions are Sheridan Swords, Senior Vice President, Natural Gas Liquids and Natural Gas Gathering and Processing, and Chuck Kelley, Senior Vice President, Natural Gas Pipelines. Yesterday, we announced Q1 2023 earnings and affirmed our full year 2023 financial guidance. Strong Q1 results were supported by continued earnings growth in each of our businesses, with higher natural gas processed and natural gas liquids volumes providing a solid start to the year. Producer activity continues to drive new volume to our assets, and recent conversations with customers point to additional activity through the remainder of the year. Crude prices well above break-even economics in the basins where we operate and continued strong demand for U.S. energy support, a constructive outlook for 2023. We provide midstream services to some of the largest, most well-capitalized producers in the U.S., helping contribute to our history of earnings stability and growth despite commodity prices. We continue to evaluate infrastructure and the needs of these customers so that we can provide added capacity or services aligned with their growth. The successful completion of our Demicks Lake III natural gas processing plant and MB-5 fractionator projects provide additional system capacity and resiliency and are examples of our continued focus on organic growth aligned with our customers' needs. We remain financially well-positioned with significant balance sheet strength and flexibility to support continued growth. Our capital allocation priorities remain consistent, with ONEOK's unique ability to identify and execute on high-return organic growth opportunities setting us apart. With that, I'll turn the call over to Walt for a discussion of our financial performance. Thank you, Pierce. ONEOK's Q1 2023 net income totaled $1.05 billion, or $2.34 per share, and adjusted EBITDA for the period totaled $1.72 billion. As we discussed on our last call, we booked the gain related to the Medford insurance settlement in the Q1, resulting in a net increase in operating income and adjusted EBITDA of $733 million. This reflects the insurance settlement gain of $779 million, offset partially by $46 million of third-party fractionation costs incurred during the Q1. We expect third-party fractionation costs to remain around this level with the potential to decrease through the remainder of the year as our MB-5 fractionator ramps up. Excluding the Medford impact, net income increased 24% year-over-year, and adjusted EBITDA increased 14% over the same period, benefiting from increased NGL and natural gas processed volumes, higher average fee rates, and higher natural gas storage rates. We ended the Q1 with a higher inventory of unfractionated NGLs primarily due to the timing of the MB-5 fractionator being placed in service and expect to recognize approximately $12 million over the second and Q3s as that inventory is fractionated and sold. In April, Moody's upgraded ONEOK's credit rating to Baa2 from Baa3, recognizing our significant deleveraging, conservative financial policy, and consistent strong operating and financial governance. Our net debt to EBITDA remains below our long-term target of 3.5 times, and we had $680 million of cash and equivalents as of March 31. Our cash balance is primarily made up of highly liquid government and treasury money market funds and deposit fully insured by the FDIC. We've reduced our total debt, net debt by more than $1 billion compared with the Q1 of 2022. In February 2023, we redeemed $425 million of 5% notes due September 2023, and we recently announced a June redemption of $500 million of 7.5% notes due September 2023, both with cash on hand. As Pierce mentioned, we affirmed our financial guidance expectations in yesterday's earnings release. With our strong Q1 performance and positive outlook for the remainder of the year, our confidence remains high in achieving our financial guidance. I'll now turn the call over to Kevin for a commercial update. Thank you, Walt. Let's start with our natural gas liquids segment. Q1, 2023 NGL volumes increased both year-over-year and compared with the Q4 of 2022, with higher producer activity levels driving increased C3+ or propane plus volumes on our system. Permian Basin volumes saw the largest increase up 17% compared with the Q1 of 2022, and 14% compared with the Q4 of 2022. We continue to have success contracting additional volumes in the basin and connected one new third-party natural gas processing plant during the Q1. Permian producer activity remains strong and we continue to consider incremental expansions on our West Texas NGL system to accommodate increasing volumes. Volumes in the Rocky Mountain region increased during the Q1 compared with the same period last year, and decreased slightly compared with the Q4 of 2022. The decrease was driven entirely by reduced ethane recovery as our propane plus volumes increased sequentially. We expect volumes to continue to grow in the spring and summer months. In the Midcontinent region, consistent producer activity in the STACK and SCOOP continues to drive NGL volumes on our system. Raw feed throughput volumes increased compared with the Q4 of 2022, driven primarily by higher ethane recovery. Regarding the macroethane environment, we expect domestic petrochemical utilization rates to continue to improve as we move through 2023. With lower sustained natural gas pricing and lower ethane inventory levels driving improved ethane economics and volumes across our system. Through the remainder of the year, we continue to expect that the Permian Basin will stay at high levels of ethane recovery, the Midcontinent will be in partial recovery, and that we will have opportunities for incentivized recovery in the Rocky Mountain region. In April, we completed our 125,000 barrel per day MB-5 fractionator in Mont Belvieu. With MB-5 now fully operational, our system-wide fractionation capacity is nearly 900,000 barrels per day. The added capacity will be used to accommodate volume growth and reduce third-party fractionation needs. We remain on track to complete our MB-6 fractionator in the Q1 of 2025. In the natural gas gathering and processing segment, Q1 processed volumes averaged more than 2.1 billion cubic feet per day, an 11% increase compared with the Q1 of 2022. In the Rocky Mountain region, processed volumes averaged nearly 1.4 billion cubic feet per day during the Q1 and have recently reached more than 1.5 BCF per day. We connected nearly 150 wells in the region during the quarter, compared with approximately 90 connections in the Q1 of 2022, a more than 60% increase. Well connections in the region are currently on pace to exceed our guidance midpoint of 500 for the year. There are currently approximately 40 rigs and 23 completion crews operating in the basin with 20 rigs and approximately half of the completion crews on our dedicated acreage. We continue to expect additional rigs entering the region as we exit winter. In the Midcontinent region, Q1 processed volumes averaged more than 750 million cubic feet per day, a 27% increase year-over-year. We connected 11 wells in the region during the Q1, compared with six in the Q1 of 2022. Are on track to be within our guidance of 45-55 connections. There are currently more than 50 rigs and 11 completion crews operating in the region with 10 rigs on our dedicated acreage. Despite weakness in natural gas prices, we continue to see strong activity in the higher crude and NGL-rich producing areas of the region, where producers are focusing their drilling. In the natural gas pipeline segment, strong Q1 results continue to benefit from firm transportation services and the demand for natural gas storage. We are on track to complete an expansion of our natural gas storage capabilities in Oklahoma in the Q2, allowing us to utilize and subscribe an additional four billion cubic feet of our existing storage capacity. We have subscribed 100% of this incremental capacity through 2027 and 90% through 2029. We continue to evaluate the Saguaro Connector Pipeline, a potential intrastate pipeline project that would provide natural gas transportation to the U.S. and Mexico border for ultimate delivery to an export facility on the west coast of Mexico. There continue to be positive developments related to the potential LNG export project. We still expect to make a final investment decision on that ONEOK pipeline in mid-2023. Pierce, that concludes my remarks. Thank you, Walton, Kevin. As you both have highlighted, ONEOK is well-positioned for another year of strong financial and operational performance. We continue to execute on high return organic growth projects and remain intentional and disciplined in looking for additional opportunities to add value for our business and our stakeholders. Demand for our products and services remains robust. We're continually looking for opportunities to enhance the vital services we provide for our customers. Our employees take pride in our position as a leading midstream operator, maintaining our focus on operational reliability, safety, and environmental responsibility. As part of our core values, a focus on safety and environmental performance is at the core of our business. We're proud of the cultures we built around these key areas. 2023 is not only a year of continued financial progress, but also a year to continue our commitment to responsible operations, emissions reduction projects, and our continued pursuit of a zero-incident culture. With that, operator, we're now ready for questions. Thank you. We will now begin the question-and-answer session. To ask a question, you may press star then one on your touch tone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star then two. We ask that you please limit yourself to one question and one follow-up. If you have additional questions, you may reenter the question queue. At this time, we will pause momentarily to assemble our roster. The first question will be from Brian Reynolds from UBS. Please go ahead. Hi. Good morning, everyone. Maybe to start off on the third-party frac fees. The original guidance stipulates roughly, you know, a quarter billion in costs for all of 2023, but Q1 trended better than expected. Now with MB-5 up and running, you know, kind of curious if you can give us an updated view on how we should see third-party frac fees trending going forward and into next year. Thanks. Brian, as we said in the remarks, we expect that $46 million level to be viewed as kind of a run rate going forward with the potential for us to do better as we bring up MB-5 throughout the balance of the year. Great. Thanks. As a follow-up, maybe just touch on the Bakken activity levels. You know, we're off to a strong start this year with weather helping out in 1Q. You know, given, you know, ONEOK has completed roughly a third of its Rockies Well Connects in 1Q, was wondering if we should expect a slowdown in activity from producers or if we continue to see, you know, similar activity going forward. Thanks. Brian, it's Kevin. I think we see similar activity levels, if not a little bit stronger. Now, if you remember in the Q4, we were a little light on our connections and said that just timing had slipped some of those into the Q1, so that was part. There, the activity levels with 20 to 20-plus rigs on our acreage and that looking to be consistent, if not growing, moving forward, I don't see the activity level slowing down. That's why we think, you know, right now we're with those tailwinds looking that we'd be ahead of our midpoint of the guidance for the Well Connects. Great. Appreciate it. I'll leave it there. Thanks. The next question will be from Jeremy Tonet from JP Morgan. Please go ahead. Hi. Good morning. Morning, Jeremy. Morning, Jeremy. Just want to dial into the Bakken a little bit more, if I could. That was helpful with the 1.5 Bcf per day, volume number that you provided there. Just wondering on the NGL side itself, I think we saw the Bakken NGLs tick down a little bit quarter-over-quarter, but the rates went up a little bit quarter-over-quarter. Just wondering, I guess, you know, where you see that now, how you think about NGL volumes trending and kind of like the ethane extraction economics at this point? Jeremy, this is Sheridan. What I would tell you is that as we said in the remarks, the decrease in volume, quarter-over-quarter was due to less ethane that we incentivized in the Q1 versus the Q4. Actually, our C3+ volume on the NGL system was up quarter-over-quarter. We still see good growth, good trajectory of growth going through 2023. With low gas prices right now, and we think that ethane is really the preferred feedstock in the petrochemicals, we will have plenty of opportunity to incentivize ethane out of the Bakken going forward as well. Got it. That's helpful. Thanks. Just wanted to kind of pivot, you know, with the insurance proceeds, obviously a lot of capacity on the balance sheet and thinking about where that could be deployed going forward between growth or buybacks or what have you. Just any update, thoughts, I guess, as far as incremental West Texas LPG looping or other extensions of the value chain, such as LPG export facility in the Houston Ship Channel. I'll start out with the first part of it and kick it over to the other guys for the West Texas part of it. Jeremy, you're absolutely right. Our balance sheet is in stellar shape at this point. And it does give us quite a bit of flexibility. Our priorities haven't changed at all. Our first priority is to find very high return projects that we can grow our business. You know, our debt reduction is kind of achieved the goals that we were looking for, and that, you know, does create our flexibility for further dividend increases and potentially even stock buybacks over time. That is our list of priorities. As I said, you know, high return growth projects that they're at the top of the list, that's a good segue into West Texas LPG. Yeah, Jeremy, it's Kevin. As we think about, like we said in the remarks, with, you know, the Permian volumes have been strong for us. We've seen nice growth there. Clearly, we're continuing to evaluate, and we'll stay ahead of any capacity needs we had through our looping of West Texas LPG. We'll stay on top of that and won't get caught short capacity. Got it. That's helpful. Thank you. The next question will be from Michael Blum from Wells Fargo. Please go ahead. Thanks. good morning, everyone. wanted to ask on the Saguaro Pipeline project around contracting. What percent of the pipeline do you need to be contracted to move forward, and what's sort of an average length of contract that you're looking for? Well, Michael, it's Kevin. As we think about Saguaro, we'll look at that project from an integrated perspective. I mean, you've got the contracts with the LNG facility, the potential pipeline in Mexico, and then our potential pipeline. All those are related. At the end of the day, the offtakers are the ones that will be, you know, looking for the transportation out of, out of Waha. That's the way we're thinking about that. Not ready to talk about any contract terms or, you know, rates or anything like that yet. Still early in the process, but we are taking the steps forward and continue to move it forward, hopefully will be in a position to announce something mid-year. Okay, great. Just maybe a follow-up on that since mid-year is fast approaching here. If you do go forward with the project, would that result in some increase in 2023 CapEx? Just generally, when would the CapEx for the project be spent? That'll all depend on when, you know, we would announce something. Again, not ready to talk about, you know, any specific capital that might hit because we're still unsure when it might be FID. All right. Thank you. Our next question is from Tristan Richardson from Scotiabank. Please go ahead. Hey, good morning, guys. Kevin, appreciate your comments on the Permian. Obviously, you've got production growth there as well as adding a new plant, third-party plant. You also talked about contracting additional volumes. Can you kind of talk about that environment, whether these are, you know, medium, long-term deals, just kind of what that environment looks like and how that may have contributed to the Q1? I think a lot of the volumes that we've seen on our system are growing volumes on contracts that may have been put in place several years ago, you know, back when, you know, even pre-COVID. We also have seen opportunities to go contract new volumes. Sheridan, you wanna talk about, you know, some of the things we've seen there? Yeah. I mean, obviously, volume is growing well in the Permian Basin. As we have a lot of relationship with producers out there and processors, that we've been able to get our fair share, if not a little bit more of the volume that's come up. We've had good luck contracting new volume. A lot of that is coming through existing plants on our system or the potential for new plants as we look into the forward. We think we have a compelling story out there to be highly competitive in a very competitive area, and we are seeing some success. I appreciate it, Sheridan. Then maybe just the obligatory high-low question. You know, obviously strong results in the Q1. Just thinking about the full year outlook, some of the conditions necessary to, you know, hit the high end versus what might need to happen to see the low end occur. Tristan, this is Pierce. I think you all have picked up on the fact that, you know, we're coming out of Q1 with some really, really strong tailwinds. That actually, is a very positive, move for us. A lot of times during the Q1, we're trying to explain kind of the different trajectories that we have, but we really, really like, the trajectory that we're on now. We've, affirmed our guidance range and, you know, stay tuned, for the quarters to come. Appreciate it. Thank you, guys. The next question is from Theresa Chen from Barclays. Please go ahead. Hi. Thank you for taking my questions. Within the GNP segment, can you talk about the fee escalation that I think kind of just totally steps up in the Q2 now that we're a month and change through it, how that's trending now, and how that, you know, gets to your guidance within the fee range? Theresa, it's Kevin. On the fee rate, again, that's gonna move around on a couple of factors. One is just various contract mix as new volume comes on the system every quarter. Then the others is the contract escalators that kick in. We've said historically previously that in GNP segment, that's typically occurs in the spring. You're just seeing just the minor moves like that or just contract mix moving around from quarter to quarter. Okay. Then in terms of the third-party frac fee, understand that you have downside from the $46 million per quarter as you utilize some of the space on MB-5. As some of your competitors are also bringing on additional frac capacity, second half of this year and into next year, would you expect that the spot fee will also weaken to some extent? Is there further downside even in addition to, you being able to use MB-5? I think that is the potential as we look out into 2024. A lot of what we did in 2023, we have contracted it at a certain rate. As we get into 2024 or for some reason we would need a little bit more in 2023, we've definitely seen spot frac rates are a lot lower than they were six months ago, and we predict that will continue into 2024. We could see some additional downside or upside as it would be for us on lower third-party frac fees. Thank you. The next question is from Spiro Dounis from Citi. Please go ahead. Thanks, Operator. Morning, guys. First question, actually wanna talk about Elk Creek. Pierce, you talked about keeping pace with customer needs. I acknowledge this question is probably a bit on the early side, but just given the Well Connect outlook, potential methane recovery, GOR is increasing, you know, over the next year or so, when is it sort of time to start thinking about an Elk Creek expansion? How are you guys thinking about some of the capital needs and timing that will go into that? I think, I'll kind of give a high-level thing, throw it to Kevin here. I can tell you that, we've said before that we're not gonna get short, caught short on capacity. As your question of when does it start time to thinking about it, we're thinking about it. I'll let Kevin kind of fill in the blanks there. Yeah. We are. With the strength we've seen recently, and even going back to last year with the activity levels and the producer, the rigs that were there, but particularly now as we move into Q1 and seeing what we have seen from the producers, we're definitely taking steps. We're already taking steps necessary to ensure that we've got the capacity when we need it. Great. That's helpful color. Second question, kind of outside the quarter as well, but over the last two years or so, even before that, we've sort of seen you lean more into more utility-like businesses, the storage expansions, now the potential Saguaro pipeline, you know, more take-or-pay style. Is that part of kind of a larger plan to introduce even more earnings stability into the platform? How should we think about maybe other avenues where you can continue to grow there? Well, the short answer to that is yes. This is Pierce. You know, those things are really driven by customer demands as well. We definitely are looking for those opportunities as that's part of the intentionality of, you know, the diversification, you know, into those more, you know, stable earnings type areas, in the, in our footprint. The short answer is yes. Understood. Appreciate the color. That's all I had, guys. Thank you. The next question will be from Jean Ann Salisbury from Bernstein. Please go ahead. Hi. Good morning. I just have one, another one on the Saguaro Connector. I guess my understanding is that inside Mexico pipelines have, I don't want to use the word disaster but have generally been very far delayed and not successful. How does ONEOK and how do investors get confidence that if you build another pipeline to the border, that the rest of it will be on time? All right. Jean Ann, this is Kevin. I think the way I would answer that is, I mean, obviously, as we come to a decision to FID or not, that will be we're factoring in what's going on with the full aspect of the pipeline. I think it's safe to say, you know us, we'll be do the things we need to do from our contractual position to mitigate that risk as much as we possibly can. Okay. That makes sense. Thank you for taking my question. Thank you. The next question is from Neal Dingman from Truist. Please go ahead. Hi, morning. Thanks for the time. My first question is just on the contract structure. I'm just wondering, you know, maybe in the type of volatile commodity tape we're in now, could you remind me, I don't think it's changed much, but I just wanna make sure I've got this, what% of this year's earnings you expect to be fee-based? I'm just wondering, do you all have availability, I don't know, in any of these contracts to potentially walk them up the remainder of the year? Just overall, we've said we're 90% fee-based, and 10% commodity exposed. Then you think about the GNP business with our POP contracts, where some of the direct commodity exposure occurs. We're well hedged in 2023. That even reduces that commodity exposure further. Really it's a when you just look at it on an earnings perspective, it's a small percentage that we have in direct commodity exposure. Perfect. Okay. Then my second just on the Rocky Mountain Nat Gas G&P, you did have a nice step up last quarter on the total there. I'm just wondering if you remind me, how should we think about the expected cadence the remainder of the year? I see that I forget what slide I'm looking at here. Obviously the guide you've got for the year still. We're now already at the low side. You've got pretty good range. I'm just wondering how, you know, is there pretty good step-ups we should think about? You're talking about the gathering and processing the volumes. Correct. Correct. From Rocky Mountain region? Yes, sir. Oh, okay. I mean, yeah, we, the Q1 you were at the low end and if you go to the you know, we referenced we had breached here recently 1.5 BCF, so we definitely think there's ramp. That's one of the tailwinds Pierce mentioned is where we sit today, from a Bakken or Rockies volume perspective, we're in really good shape. Great to hear. Thank you all. The next question is from Neel Mitra from Bank of America. Please go ahead. Hi. Good morning. Thanks for taking my question. A lot has been answered. I wanted to go a little bit beyond the quarter and with the Medford proceeds and what seems to be a strong 2023, it seems like your leverage levels are trending well below kind of the 3.5 times target. When you think about that a little bit longer term, do you plan to stay lower like some of your peers, or are you thinking more about dividend increases, repurchases, or possible acquisitions? Just in terms of how you plan to think about the mix. Sure. Neal, this is Walt. Well, if you back out the gain from the Medford settlement, we're around 3.4 times. Yes, we're through 3.5, but we're not meaningfully below it at this point. We are not concerned if that trends lower. You know, if we don't have investment opportunities or the like, it probably would trend lower in the short term. You know, we continue to look at attractive opportunities. You know, we've spoken a little bit about the increases we're seeing in the various basins and some of the expansion plans that we might need to do on some of the pipes and the like. Those are very, very high return types of projects, and that's where we like to be first. We have flexibility for other capital, return, you know, now that we're done and achieve these goals. Got it. Then second question. I know you've seen a lot of stickiness in terms of the rigs on your activity. Now that just we've seen crude fall below $70 twice this year, how do you see the producer activity given that a lot of publics have budgeted around $70 if we stay in this environment over, you know, intermediate to longer term? Well, Neal, this is Kevin, you know, I haven't had a lot of time to talk to our customers over the last couple days, but what I would say, you're right, the rigs have been very sticky. I like that word. As prices, if you rewind, rigs really started coming back to the Bakken in earnest as prices moved through $50-$55. That's when we started seeing the stickiness. Now, when it ran up to $110, you know, rigs didn't necessarily follow, but then as the prices came back down, they didn't go away either. We still feel very good. It's not a matter of that's still well above break evens. Producers are still generating a tremendous amount of cash flow, even at the prices we're seeing on the tape right now. That would give me a lot of confidence that we're gonna continue to see that stickiness even in this type of environment. The only thing I'd add to that, this is Pierce, is, you know, I get the opportunity to go around and, meet with, you know, these heads of many of these, you know, Exploration and Production companies, and they take a really long-term view. It's not just what is the price today. Yes, the price has fallen off crude last couple of days, but they're taking a long-term view of what do they think crude's gonna do over time. Until they get the rigs, drilled out there, drill, wells producing, you know, you don't have the opportunity to capture, you know, whatever price it is out there. They really take a long-term view, and it seems to be a very wide path that they look at now as far as a range of prices that they don't really get emotional and go either up or down. They stay very steady. Okay, great. I appreciate the call. The next question will come from Sunil Sibal from Seaport Global Securities. Please go ahead. Yes. Hi, good morning, everybody, and thanks for the clarity on the call. I wanted to start off on Bakken. I think there has been some chatter in the E&P community about well productivity. I was curious, you know, if you could talk about, you know, in the past, you've talked about close to 400 wells per year to maintain your gas volumes. Just curious, you know, if that number has changed in your view based on, you know, some of the recent results. Also seems like, you know, gas-to-oil ratio have trended down recently. This is Kevin. There was a couple questions in there. One is on well productivity. We really have not seen a degradation at all in the well productivity. There has been a little bit of movement with the strong prices to different areas of the play. We've seen some changes a little bit in potentially the gas-to-oil ratio, but nothing that would cause us concern to think that wells are getting less productive. If anything, producers, if they're drilling in the same areas, the technology continues to improve, and we've seen strong results. We don't have any concerns at this point on what's going on with well productivity or the GORs. Okay. My follow-up was on your natural gas pipeline segment. Seems like a pretty strong Q1, and, you know, even if the remainder of the year turns out to be similar to last year, I think you would exceed that guidance. I was just curious if there are any one-time items in Q1 which helped the gas pipelines. Sunil, this is Chuck. No, Q1 was a solid quarter for us in all regards. Our storage revenues were higher. Obviously, we had some gas sales that we were able to pick up in the quarter like we typically do, Q1. There wasn't a single outlier that generated that performance. Balance of the year, you know, we expect, to be, you know, at or above our midpoint, and looking forward to see what opportunities come about this summer. Got it. Thanks for that. Thank you. The next question will be from Colton Bean from Tudor, Pickering, Holt & Co. Please go ahead. Just a quick follow-up on Saguaro. It looks like the proposed 48 inch diameter would offer plenty of capacity over and above the proposed LNG export sendout. Can you speak to how you scoped that project and what opportunities you might be tracking downstream, apart from LNG? Colton, this is Kevin. Well, we're just lining up again with what's going on with the possible export facility. As we just back up from there and what they're talking about building in Mexico and what we would need to build for the border crossing, that's what we're looking at right now. Not ready to talk about any other opportunities or so forth. There's, you know, potential plans for the LNG facility for additional trains. We scoped the pipe kind of in what they were looking for. Understood. Thank you. The next question is from Craig Shere from Tuohy Brothers. Please go ahead. Good morning. Just a couple quick ones. The Permian NGL unit rates were shown at about $0.06 versus over $0.06 in the Q4. Wondering if there's any detail or trend there. Could you remind us, you know, roughly on the increments that you can increase Elk Creek with additional pumping and what kind of CapEx that would incrementally run? Craig, I'll take the first or I'll take the last one and let Sheridan talk about the fee rates. On the Elk Creek expansion, as Pierce alluded to, yes, it's adding pumps up and down the pipe. That would be the scope of the project. We haven't talked any specifics on what that would cost. Again, we're not gonna get caught short of capacity and already taking the steps necessary to hopefully bring that forward. Craig, this is Sheridan on here. Sorry. I'm sorry. Could you quickly just elaborate how quickly or soon that can be done? It's pretty efficient stuff, right? Can you do it in well under a year once the decision's made, or how quickly can you roll that out? That, again, we're still working through. That's the steps we're taking, is understand exactly what that would be. You know, working with power companies, working with pump providers, and things like that. Those are the types of steps we're taking to ultimately come up with how long it might take. Yeah, it's not like building a brand-new pipeline start to finish. All right. Thank you. Craig, this is Pierce. The only thing I'd add to that is, you know, the thing to remember on that as it relates to capital is, these are very high return projects. Whatever the number is, you know, when we announce that, "Hey, that we're gonna do this," you know, just be assured that it's a, it's a very high return project. Understood. Those Permian NGL unit rates? Yeah. Craig, this is Sheridan. I mean, we always see a little bit of escalation or changing up and down in our fee rates. It all depends on where the volume's coming from. One of the biggest thing that it drives at is if we're getting a little bit more volume from a transport-only contract versus a TNF contract or as that mixes a little bit, it's gonna play with that rate just slightly and you're just seeing just a little bit of a slight change. I mean, it's just noise. It's really immaterial. It's just kind of contract mix. Got it. No trend going on there. Just, you know, bouncing around. No trends. There's no trends going on. Thanks. Ladies and gentlemen, this concludes our question and answer session. I would like to turn the conference back over to Andrew Ziola for any closing remarks. Well, thank you all for joining us today. Our quiet period for the Q2 starts when we close our books in July and extends until we release earnings in early August. We'll provide details for that conference call at a later date. Thank you all, and have a good day. The conference has now concluded. Thank you for attending today's presentation. You may.