Good morning, and welcome to the ONEOK Q4 2023 earnings conference call and webcast. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing Star then zero on your telephone keypad. 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, Vice President, Investor Relations. Please go ahead. Thank you, Drew, and welcome to ONEOK's Q4 and year-end 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 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, for Q&A, we ask that you limit yourself to one question and a 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, and thank you for joining us this morning. On today's call is Walt Hulse, the Chief Financial Officer, Treasurer and Executive Vice President, Investor Relations and Corporate Development, and Sheridan Swords, who's our Executive Vice President, Commercial Liquids and Natural Gas Gathering and Processing. Also available to answer your questions are Chuck Kelley, our Senior Vice President, Natural Gas Pipelines, and Kevin Burdick, who's the Executive Vice President and Chief Enterprise Services Officer. Record volumes, strong financial performance, and the closing of the Magellan acquisition solidified 2023 as a year of significant growth and transformation for ONEOK. Momentum from our operations in 2023 is setting the stage for additional growth in 2024. With our earnings release yesterday, we reported double-digit NGL and natural gas processing volume growth year-over-year, and continued fee-based earnings growth in all three of our legacy business segments. We also provided 2024 guidance, along with some insight into 2025 and beyond, including an expectation for double-digit Adjusted EBITDA growth in 2024. Walt will provide more detail on our guidance, which is underscored by solid business fundamentals, demand for the products that we deliver, and a full year of earnings contribution from our refined products and crude oil segments, and the initial realization of acquisition-related synergies. Before I turn the call over to Walt, I want to share a few data points that help sum up the exceptional growth ONEOK has experienced in recent years. While our business continues to transform and to look to the future, it's still important to reflect on what has already been accomplished. I'll share just a handful of highlights, but there are many more. First, 2023 marked ONEOK's 10th consecutive year of Adjusted EBITDA growth throughout various commodity cycles. Over the same time period, we've increased dividends paid to $3.82 EPS from $1.48 EPS, a more than 150% increase, and in January, the board approved another increase. Our volumes out of the Rocky Mountain region have set numerous records. Over the last five years alone, NGL volumes from the region have grown at a more than 20% annual growth rate, and natural gas processing volumes have grown at a 10% annual growth rate. We've continued to expand our asset portfolio, increasing our extensive pipeline network to more than 50,000 miles from approximately 30,000 miles in 2013, and adding nearly 2 BCF per day of natural gas processing capacity and 3 fractionators. And finally, through all of this growth, both internally and by acquisition, we've continued to prioritize safety and our sustainability and ESG-related performance, consistently ranking toward the top of our industry peer group, including a triple-A rating from MSCI. We've achieved a great deal in recent years and over the course of our company's history, and now, with a more diversified portfolio of assets, we are even better positioned to make the most of future opportunities. With that, I'll turn the call over to Walt. Thank you, Pierce. Before I get to guidance, I'll start with a brief overview of our Q4 and full year financial performance. ONEOK's Q4 and full year 2023 net income totaled $688 million and $2.7 billion, respectively. Adjusted EBITDA totaled more than $1.5 billion in the Q4 of 2023, and more than $5.2 billion for the full year. ...While there were a number of unique items contributing to the significant year-over-year increase in results, such as the Medford settlement and the Medford, Magellan acquisition, the strong performance from our legacy business segments continued. Even excluding these unique one-time items, ONEOK's Adjusted EBITDA would have increased more than 15% year-over-year. As of December 31, we had no borrowings outstanding under our $2.5 billion credit facility and had more than $335 million of cash on hand. In 2023, ONEOK extinguished $1.3 billion of long-term debt, contributing to a Q4 2023 run rate net debt to EBITDA ratio in line with our previously discussed target of 3.5 times. In January, we increased our quarterly dividend 3.7% to $0.99 EPS, or $3.96 EPS on an annualized basis. Going forward, ONEOK expects to target an annual dividend growth rate ranging between 3%-4%. We also announced a $2 billion share repurchase authorization, which we target to largely use over the next 4 years. This program is complementary to the dividend growth rate when thinking about shareholder return in the future. Over the next 4 years, ONEOK's combination of dividends and share repurchases is expected to trend towards a target of approximately 75%-85% of forecasted cash flow from operations after identified capital expenditures. Our commitment to maintaining our financial flexibility and taking advantage of attractive return capital growth opportunities that complement our now larger and more diverse operating footprint, continues to be the highest priority in our capital allocation strategy. This commitment will continue to create value for our investors and support ONEOK's position as one of the midstream leaders of return on invested capital. Now moving on to 2024 guidance. We provided a net income midpoint of more than $2.8 billion, and EPS midpoint of $4.88 per diluted share, and an Adjusted EBITDA midpoint of $6.1 billion. We also include guidance related to the synergies we expect to realize over the next couple of years. This guidance reflects higher earnings from all business segments, excluding the Medford insurance settlement and a full year contribution of the refined products and crude segment. Sheridan will provide more detail on each of the operating segments in a moment. As for synergies, we've assumed a midpoint of $175 million of total realized annual cost and initial commercial synergies in 2024, followed by an additional $125 million in 2025. We expect additional synergies in 2026 and beyond as capital expenditure projects to connect our NGL to the refined products and crude businesses are completed. As it relates to capital expenditures, we've assumed a total of $1.85 billion, which includes growth and maintenance capital. This guidance reflects the investment necessary to keep up with the expected levels of producer activity and attractive return growth projects, including the MB-6 fractionator and expansions of our West Texas NGL and Elk Creek NGL pipelines, all expected to be completed in the Q1 of 2025. Once these projects are completed in early 2025, we expect to be on a trend of decreasing capital expenditures over the near to medium term. Our expected 2024 capital guidance does not include the Saguaro Connector project or any other projects that have not yet reached financial investment decision. I'll now turn the call over to Sheridan for a commercial update. Thank you, Walt. We saw strong year-over-year volume growth in 2023, with natural gas processing volumes up 14% and NGL volumes up 10% compared with 2022. Rocky Mountain Region volumes were particularly strong, with double-digit growth in both NGL and natural gas processing volumes year-over-year. Higher producer activity levels, increased well connects, and continued strong gas-to-oil ratios drove record Q4 volumes totaling nearly 400,000 barrels per day of NGLs and nearly 1.6 BCF per day of processed volume. Mid-Continent processed volume increased 15% year-over-year, and Permian Basin NGL increased 19% year-over-year, both benefiting from solid producer activity throughout the year in those regions. Well connects across our operations increased more than 50% compared with 2022. We continue to see the benefit of those connections throughout 2024 as volumes ramp. Our natural gas pipeline segment significantly exceeded its 2023 financial guidance range on higher earnings from long-term storage services and higher rates from negotiated fee-based contracts. Our refined products and crude segment Adjusted EBITDA totaled more than $420 million in the segment's first full quarter of operation since the acquisition of Magellan. This segment's performance was driven by mid-year tariff increases, longer-haul refined product shipments, and steady crude oil transportation volumes. Our optimization and marketing activities, which includes liquids blending, also benefited from strong margins and volumes. Turning to 2024. Key drivers for our higher 2024 guidance include stable producer activity and continued production efficiency improvements, providing strong natural gas and NGL volumes across our systems, solid refined products demand, continued strength in fee-based earning and rates, and our first full year of annualized synergies. In our natural gas liquids segment, we expect higher year-over-year Adjusted EBITDA and raw feed throughput volumes to be driven primarily by growth out of the Rocky Mountain Region. Despite lower assumptions for incentivized ethane recovery in 2024 and a low margin contract expiration from Overland Pass Pipeline in November of 2023, we still expect higher year-over-year NGL volumes. The expired contracts volume is being replaced with higher rate barrels ramping through 2024. Healthy demand for ethane from the petrochemical industry and wide gas-to-oil ratios are setting up a positive backdrop for NGL markets in 2024. On our system, we've assumed high levels of ethane recovery continue in the Permian Basin in 2024, and partial recovery in the Mid-Continent. We also expect to see continued opportunities to incentivize ethane recovery in the Rocky Mountain Region. As Walt mentioned, we've officially moving forward with the expanding the Elk Creek Pipeline to 435,000 barrels per day, increasing our total NGL capacity out of the Rocky Mountain region to 575,000 barrels per day. This additional capacity will support future growth and increased ethane recovery. Moving on to the natural gas gathering and processing segment. We expect volume growth in the Rocky Mountain and Mid-Continent regions driven by higher than anticipated well connections in 2023, and consistent producer activity levels expected in 2024. In the Rocky Mountain region, we expect processing volumes to grow 9% at the midpoint compared with 2023, and average more than 1.6 BCF/d in 2024. This outlook includes the impact from the weather we experienced so far this year, including well freeze-offs in mid-January, when the wind chills dropped below -60 degrees. By the end of January, volumes had recovered to levels achieved prior to the extreme cold. Strong producer activity levels in 2023 and the continued trend of high gas-to-oil ratios drove several months of record North Dakota natural gas production, with the latest record of 3.52 BCF per day set in December. Producer activity has carried over into 2024. Even through the winter months as we enter March, there are 36 rigs in the Williston Basin, with 20 on our dedicated acreage. Through detailed planning sessions with our customers, we expect additional rigs to return as we move into spring. Additionally, we continue to see a trend of producers drilling longer laterals in the basin, 3 miles in length or more, as opposed to the historical 2-mile laterals. These longer laterals continue to drive improved production efficiencies and result in fewer well connections needed to grow gathered volumes. As detailed in our earnings presentation, we expect 3-mile laterals to account for approximately 30% of the wells drilled on our acreage in 2024, compared with only 7% two years ago. In the Mid-Continent region, we are currently seeing approximately 45 rigs in Oklahoma, with 6 operating on our acreage. We expect processing volumes to grow approximately 3% at our guidance midpoint compared with 2023, and average approximately 770 million cubic feet per day in 2024. Rig activity across the basin will continue to drive additional NGLs to our system. In the natural gas pipeline segment, we continue to expect strong demand for natural gas storage and transportation services in 2024. At the end of 2023, more than 75% of our natural gas storage capacity was contracted under long-term agreements, and our pipeline transportation capacity was nearly 96% contracted. We expect similar levels in 2024. From a natural gas storage perspective, we continue to focus on expansion projects. We are currently working on a project to reactivate 3 BCF of previously idle storage in Texas and are further expanding our injection capabilities in Oklahoma. In February 2024, the FERC approved the Saguaro Connector Pipeline's Presidential Permit, and we expect a final investment decision on the pipeline by mid-2024. Moving on to the refined products and crude segment. We continue to expect healthy business fundamentals and the segment's more than 85% fee-based earnings to drive consistent performance. We'll see the full year effect of higher refined products tariff rates, driven by the mid-year 2023 increase of eleven and a half percent, and we expect additional mid-single-digit increases in July 2024. We also expect an increase in refined products volumes, including a benefit from the completion of our expansion to El Paso. Additional benefits are expected from higher volumes and margins related to liquids blending in 2024, driven by favorable market conditions and synergy-related opportunities. Walt discussed commercial synergies earlier, which we expect primarily to show up in our refined products and crude segments earnings. Pierce, that concludes my remarks. Thank you, Sheridan and, and Walt. I started this call by saying that 2023 was a year of significant growth and transformation, but none of this would have been possible without our dedicated employees, with many of those employees actually listening to this call today. So I wanna make sure that I thank them publicly for all that they did in 2023. With us now five months post-closing of the acquisition, our employees have continued to focus on our integration efforts and prioritize the reliable operations of our assets and the high quality of service expected at ONEOK. Everything we have accomplished this past year means nothing if we don't do it safely and responsibly. From an environmental perspective, we've made significant progress toward our greenhouse gas emissions reduction target, achieving reductions that equate to approximately 50% of our total 2030 reduction target. From a safety perspective, we've brought together two companies with leading safety cultures and performance, and combined, we will continue to focus on the safety and health of our employees in the communities that we operate. We've created an operational platform that provides increased scale, scope, and diversification. It's a platform which is already providing opportunities and enabling us to generate exceptional value for our stakeholders. Looking ahead, ONEOK is well-positioned in 2024 for another year of significant growth and opportunity. With that, operator, we're now ready for questions. We will now begin the question and answer session. To ask a question, you may press Star, then one on your telephone keypad. If you are 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. At this time, we will pause momentarily to assemble our roster. The first question comes from Brian Reynolds with UBS. Please go ahead. Hi, good morning, everyone. Maybe to start off on synergies in slide 10. You know, we've seen the risk-weighted synergies increase to roughly $400 million from the original expectation of $100 million. So perhaps just, you know, a two-part question. First part is, can you provide some concrete, you know, commercial examples of what's driving that upwards revision? Just anything, you know, specific. And then second, you know, based that these risk-adjusted synergies are up, you know, roughly $300 million, can you perhaps update on, on, us on the initial, like, $200 million-$800 million synergy range that you provided, you know, last quarter? It seems like there's a little bit of upside to that range at this point. Thanks. Well, you're right. We do see some upside to our synergies as we go forward, as we say, in the $700 million, and really a lot of it's gonna be driven by being able to bring our refined product and crude oil and NGL systems together, which we have multiple opportunities in many different areas of our systems. And really, as we continue through 2024 and 2025, it's lots gonna be, as we said before, in prioritization of which ones we're gonna work on, we can bring forward. We start 2024, we'll also be driven by, we've reached a substantial amount of our cost-saving synergies already through 2023, and we'll see a full year of that in 2024. Yeah. Brian, this is Kevin Burdick. The other thing, just on the cost. If you think about the cost savings, we have realized the vast majority of those, already, so we'll see the full impact in 2024. Couple of examples to that would be our organizational design and restructuring activities are complete, so that will be factored in. Another example, you know, public company costs have been eliminated for the Magellan aft- Magellan company, so that's another example, as well as many others. So the cost-saving side will play a big role in 2024 as well. Great, thanks. Appreciate that. And maybe to switch to just the updated return on capital framework. You know, you outlined the 3%-4% dividend growth, but you know, kind of updated it with the updated payout ratio of 75%-80% with buybacks and dividends. So, you know, just looking at the model, it seems like it's pretty clear on 2024, you know, how that you can kinda come to that conclusion. But when I look at 2025 and 2026- ... you know, leverage trends below 3.5 times. You should have some excess cash just based on, you know, existing projects that are FID at this point, you know, with potentially Saguaro going into that bucket. So as we look in 2025 to 2026, can you maybe update us on how we should think about the return on capital framework? Could we see maybe an increase of buybacks, or how should we think about maybe interest in M&A or maybe other projects that may come to fruition in 2025 and 2026, to maybe keep kind of that return on capital framework, you know, unchanged? Sure. Well, you know, I wanna start out by again continuing to point out that during 2023, we were able to extinguish over $1.3 billion of debt, including paying off maturities as they came due and making some open market repurchases in the debt market. So, we obviously are continuing to produce significant amounts of free cash flow. As we go into 2024, I think you're correct that we expect to begin our share repurchase program. We do expect that to ramp over the four-year period, as we're still getting through our debt to EBITDA metrics, that we've gone out with a goal of that 3.5 times. So, we will expect that to ramp over time. But we do, we do have an intention to begin that program here in 2024. So I think we're set up to make those forward capital returns to our shareholders, while still retaining in that additional 25-50 to 25% of unallocated cash flow, meaningful free cash flow for high return capital projects that we have not yet identified. Great. Makes sense. Super helpful. Enjoy the rest of your morning. Thank you. The next question comes from Neel Mitra with Bank of America. Please go ahead. Hi, good morning. I was wondering, what you're assuming for any third-party frac costs in 2024, and the timing of MB-6 and how that would impact those costs? Well, in MB-6, as we said in, in our prepared remarks and in our earnings release, will come up in the Q1 of 2025, and it's a 125,000 barrel a day frac, so it will have a significant impact to our third-party frac costs. Our third-party frac costs in 2024 will be about $30 million a quarter, as I think of what we've estimated on that piece. So we'll be needing third-party frac costs through the remainder of that, which most of we've already contracted. Got it. And then the second question, specifically on the butane blending synergies. I think legacy Magellan blended about 2% of butane into the gasoline stream. But because you're able to pipe a lot of the butane and the gasoline together, it seems like you can expand that opportunity. Can you give us a sense of the total opportunity there, in terms of how much of the butane you can blend into the gasoline as a percentage basis, or how much you can expand that operations from the legacy Magellan operations? For commercial reasons, we won't get into too much of it, but butane blending is driven by regulations of RVP into the gasoline, so there is a limit. But other than that, we don't wanna get too much into it, due to commercial sensitivities on what we're doing. Okay. Thank you. The next question comes from Sunil Sibal with Seaport Global Securities. Please go ahead. Yeah, hi, good morning, everybody, and thanks for all the clarity. So I wanted to start off on the consolidation team. Seems like, you know, that's kind of picking up even more, both on the upstream side and some on the midstream side. So I was kind of curious, you know, as you think about that as a growth avenue, should we be thinking about any major guardrails in terms of the assets, or corporations that you look at? So, Sunil, this is Pierce. That really question kind of falls in the bucket of mergers and acquisitions, I think. I just want to reemphasize that our primary focus is to continue to be integrating the Magellan acquisition and executing on the synergies and opportunities that we see to create the maximum value for our shareholders. So, we're gonna be—we're gonna continue to be intentional and disciplined in our approach, you know, to M&A. But I'd also say that we have, and we will continue to look at other mergers and acquisitions in the context of how do they strengthen our competitive position. Okay, thanks for that. And then, I think in your prepared comments, you mentioned that the growth CapEx is likely to come down in 2025 and forward years. I was kind of curious if you could, you know, help us think through the, you know, growth CapEx needs at combined ONEOK, now. And, is there a good way to think about the growth CapEx or total CapEx needed to maintain volumes and then to, you know, further on grow volumes? So I'll kind of take a high-level cut at that, and then I'll ask either Walt or Sheridan to chime in on this. But one thing that I don't know if you picked up on, but Walt just mentioned that we actually have some excess cash of about 20%-25%. ... So there is money out there for these high return projects that we either are potentially working on or even not identified at this point. So as far as the specifics go, I'll kind of turn it over to Walt and Sheridan. Well, I think, you know, as we mentioned here, here in 2024, we've identified a midpoint of $1.85 billion. You know, we have some pretty large projects in there, with the MB-6 being the largest, and then the completion of the West Texas LPG expansion, and then the completion of the Bakken expansion, which we wanna make sure is done here in early 2025. You know, once those projects are done, we don't have any other large identified projects that we've FIDed for the market, so you can, you can kind of peel those away as they've come into 2025. Our routine growth type of expenditures will continue, and we will find more opportunities. They're probably just gonna be more bite-sized and ones that we can do out of free cash flow and will be ones that are really facilitating and accelerating the synergies that we're looking to achieve in 2025 and 2026. Thank you. The next question comes from Michael Blum with Wells Fargo. Please go ahead. Thanks. Good morning, everyone. So, question on Saguaro. If you FID Saguaro in mid-2024, first of all, would that change the 2024 CapEx number much, or would most of that fall into the 2025 and 2026? And would that change your expectation that 2025 CapEx would come down? I'm gonna let Walt kind of take the, the CapEx question, but there's a couple of things that I wanna make sure that, that I note on this call that, that pertains to Saguaro, Michael, and one is, I wanna really thank all those employees who worked on getting the permit approved in this process. And as we look at Saguaro, it is the most economical route for LNG to reach the markets, or at least multiple markets. And that's actually been indicated by the strong commercial interest and the backing, you know, by the major players there. And here's where I want to really, kind of make this clear, is that, you know, we said all along that our commitment to this project will involve procuring the Presidential Permit, which as, as we noted in our script, that is complete. The building of the U.S. portion of the pipe, getting across the border with the pipe, and then the operation of the U.S. pipe. As far as our financial involvement, that's gonna be commensurate with the value that it brings to our shareholders, you know, versus the risk we see in the project. I'll kind of let Walt fill in some of the details there. Yeah, Michael, given the timing, there's not... If it gets FID mid-year, the capital associated with that would not be a material change to 2024. And in 2025, and beyond, I don't think you'll see anything that would change my comment before about seeing a reduction over the 2024 level of CapEx as we go forward. You know, projects takes a couple of years to construct and will fit right in within our capital program. Great. Thanks for that. Then just wanted to ask on the Elk Creek expansion you announced. Maybe you could just help us understand a little bit what the ramp in volumes could look like. Should we expect this to be highly, highly utilized at startup, you know, like, maybe, or, will this be kind of more of a gradual ramp? Thanks. Well, Michael, on as we think about the Elk Creek expansion, we've always said that we're not gonna run out of capacity coming out of the Bakken. And that's why we wanna make sure this pipeline comes up in the Q1 of 2025. So we are expecting volume increases, that we'll need that as we move into 2025. And then there's a lot of things affected on the ramp-up. One is how much incentivized ethane we have coming out of there, and the other one is the continuing growth of, in the basin. As we've seen, gas-to-oil ratios continue to grow, and the drilling activity that we're seeing right now is conducive to increased overall volumes in the basin. So I think we will see quite a bit of growth as we move into 2025 on this pipeline with those two backdrops. Thank you. The next question comes from Vrathan Reddy with JP Morgan. Please go ahead. Good morning. Appreciate the color you guys provided on producer efficiency in the slides and even in the prepared remarks. Seems like a pretty significant step up there in the share of three-mile laterals in 2024. So just kind of thinking, if we should be thinking about the increase in three-mile laterals, reducing the required CapEx to maintain current volumes at this point, or any other thoughts you could, you know, frame up there would be greatly appreciated. Yeah, this is Sheridan. Absolutely, with the more efficiency and them drawing three-mile laterals, so each well is gonna have more production on that, so we are gonna see a drop-off from our previous cadence on capital that we need to spend in the area to maintain volume. And also remember that in the Bakken, we are guiding a little bit over 1.6 BCF of throughput, and we have 1.9 BCF of processing capacity up there. So we have a lot of working leverage to grow in that area, so we will see our capital come down. Great. And then, for the second one, I wanted to hit on Northern Border. Just any thoughts you guys could share on how you see dynamics playing out there throughout the year? Mainly, if we could see any relief on the pipeline once volumes start flowing on Coastal GasLink to service LNG Canada. Well, Rathan, this is Chuck. As far as Northern Border goes, the volumes that we see coming down there today, I don't think will be appreciably impacted with the Canadian volumes diverted to LNG Canada. There's a stronghold of about 400 million a day that's held by long-term producers that will continue to flow down Northern Border. So the pipe will remain full headed toward Ventura and Chicago. And you know, there's been some relief in our GMP business. You're working a deal with WBI to move some gas down to Cheyenne Hub, and that's been a nice relief valve. And you've probably seen some information about Bison XPress, which should be coming on in Q2 of 2026. That will offer upwards of another, call it, 400 million a day of relief. So I think, I think the pipe is positioned well for the next couple of years. Great. Thank you. The next question comes from Spiro Dounis with Citi. Please go ahead. Thanks, operator. Morning, everybody. Maybe just to go back to a follow-up to, to Michael's question, but really kind of focus on the, the three major projects you've got coming online in the Q1 of 2025. Adds up to about $1.4 billion of capital kind of starting up that quarter. Just curious if you can give us a sense for what the initial return multiple was on those projects and how to think about the EBITDA ramp for all three over 2025. Well, I'll take the first part of that. On, as we look at each one of those projects and we think about the ramp-up, MB-6 is gonna come up full. Because we're having third-party frack capacity today, so it's gonna be at a very high operating rate, so it's gonna be a very nice multiple we have on that. As we've said with the West Texas expansion, that we are contracting and continue to contract more volume on that to have an acceptable return with a significant amount of upside going forward. So we're continuing to drive that project's multiple down as we grow on that. The Elk Creek expansion is probably gonna be the lowest one on that, as we don't need a whole lot of volume to be able to have a very low multiple. If we would get to the point that we're at a high utilization rate, that multiple will be well below one. Okay. That's helpful. Thanks for that, Sheridan. And maybe going back to the synergies. It sounds like for 2026 plus, you're gonna have to develop some new infrastructure to achieve those synergies. Just curious, can you give us a sense for what that looks like? Are these storage tanks? Are these connections within the systems? Just a sense of what you're building out there. Yeah, I think it's gonna be all that kind of stuff. It's gonna be small, relatively small capital. It's gonna be some connections here, some tanks here, depending all up and down our system. So it, some of that will come before 2026, but as we continue to look forward to that, we'll be achieving most of it as we head into the 2026 timeframe. Great. I'll leave it there. Thanks for the time. The next question comes from Jean Ann Salisbury with Bernstein. Please go ahead. Hi, just to follow up on the discussion about Northern Border earlier. My understanding from looking at the scrapes is that Canada is actually already at the sort of 300-400 MMCFD that they have directly contracted. Do you think we've hit a limit here on Bakken gas takeaway, until the rest of Bison comes on in 2026? And how do you think it plays out? Jean Ann, this is Chuck. I stand by what I said. I really think the 400 million a day will continue to come down Northern Border from the legacy Canadian producers. So the growth coming out of the Bakken will be absorbed through Bison XPress and the WBI, the WBI expansion. So Jean Ann, this is Pierce. Based on what I've seen, I mean, I actually look at this as well. There is capacity today, so there's no restrictions today. And if you look at the fact that, you know, there's gonna be some natural gas-fired generation facilities that are gonna be built in the, you know, in the North Dakota area, and you also look at the Bison XPress, and then you also look at WBI, you know, we're not seeing anything in anywhere in the near future that there's gonna be any kind of restrictions on gas takeaway. Yeah, and while we think that there's plenty of takeaway, do remember that we always have the lever if we need to, that we can, we can extract more ethylene and put it on the NGL pipe to create capacity for natural gas. Thank you. That's, that's exactly what I was looking for. And then, kind of a follow-up on some, some of the ethane outlooks that, Sheridan was talking about earlier. I think there's not a ton of new ethane demand domestically or exports for a, a few years from now, but associated gas will likely still grow. In your outlook, does that have the risk of increasing rejection in the Bakken or Mid-Con over the next couple of years? And could that be a drag on, on EBITDA? Potentially. I think as we get out in 2025, we'll see a little bit more of ethane export capability coming online. A lot really depends on how hard the petchems are running on utilization is a big impact as well. And then as we think about we think about ethane rejection and recovery across our footprint, a lot depends on what the natural gas price in that area is. We, we feel that we have a very good opportunity to continue to bring incentivized ethane out of the Bakken, just from our fully integrated NGL system and GNP system as well. Mid-Continent may be where we see a little bit of swing, could be a little bit more swing in ethane recovery, but those are at much lower rates than we see coming out of the Bakken. But I think the big thing is gonna be is how hard the petchems are, their utilization rate, and we're seeing as we move into 2024, they're operating at pretty high levels. That's helpful. Thanks for taking my question. The next question comes from Keith Stanley with Wolfe Research. Please go ahead. Hi, good morning. I wanted to start and follow up on Saguaro. And so if Mexico Pacific declares FID, how are you thinking about DOE risks for that project? I think they need an extension of their in-service deadline for non-FTA exports. How do you, how do you mitigate that risk around that issue as it relates to, to your project and, and your contracts? Keith, this is Chuck. Yeah, as you state, MPL received back in 2019 the first two trains DOE export approval, and they have adequate time to go ahead and start this project post-FID, where that approval is for both FTA and non-FTA countries. So feel pretty good, obviously, about trains one and two. This pause that we're seeing right now impacts their second requested approval, which would be for train three. And, you know, and as you know, we don't know exactly how this is gonna play out balance of the year. So, trains one and two post-FID, we feel good about those volumes as we sit here today. Okay, thank you. And the second question, just any updated thoughts on potential to enter the LPG export business and how you're weighing the potential to use Magellan sites or other facilities, versus I think there's a greenfield option that you're in the early stages of looking at, too, at Sabine Pass. Just any updated thoughts there? This is Sheridan. On the LPG exports, I think we're in the same spot or what we can share publicly, where we have been for a period of time. As you're right, we continue to look at all alternatives that we have. We have a greenfield site, trying to understand if there's a some synergies there from a physical standpoint, from the Magellan assets, if we could put something on their sites. So we continue to do that, but right now, as I've said, we see the LPG export as we think something that could enhance our integration, but it's not something we absolutely need as we continue to be able to to move our barrels through the market today that has the export capabilities at other facilities. Thank you. Was there a follow-up to that, Mr. Stanley? No, that's all. Thank you. Thank you. The next question comes from Theresa Chen with Barclays. Please go ahead. Morning. On the refined product side, with the significant swings in MidCon versus Gulf Coast product prices thus far into the year, MidCon being heavily discounted earlier in the year and then product prices sharply rising after the Whiting outage, has this created opportunities for you to use the Sterling system to ship products southwards, when the arb was there towards the beginning of the Q1? And also opportunities for more long-haul movements, of refined products from the Gulf Coast to MidCon on the legacy Magellan assets and incremental earnings as a result? What I would say is, right now, we're not gonna comment specifically on refined products movements on any specific pipeline. What I can say is NGL pipelines have moved refined products here in the Q4 and Q1. We do see with that movement and the two pricing mechanisms between the Gulf and the group, we have seen opportunity for longer haul tariffs on our refined product system. Okay. And Sheridan, going back, to the butane blending synergies and your comment about the RVP requirements. So, butane blending needing to come out of the gasoline pool in that mid-April timeframe. And, just given the comments from some of the downstream customers about the lack of octane in the gasoline pool after that switch happens, does this lend to some opportunities for your isobutane volumes as a feedstock for alkylate? Or said differently, does the acquired Magellan refined products assets and your exposure to gasoline flows now more than before, can that create some uplift for the even heavier components of your NGL barrels? Yeah, there could be some potential as we look at, you know, for the natural gasoline component of the barrel, some blending into the unleaded pool that we've looked at. As in terms of isobutane, specifically going into alkylate, we've been servicing those alkylation units for quite a long time in the legacy NGL business. And typically, as you know, alkylate is a very high priced, and usually they run those pretty strong. The big difference in those alkylation units is whether or not they're gonna run some refinery-grade propylene through that unit, or they're gonna stay or, or how their RGBs, refinery-grade butane runs through that as well. So if we see more propylene run through an alkylation unit, we will see a little bit more isobutane being used, but typically, they run pretty steady. Thank you. The next question comes from Tristan Richardson with Scotiabank. Please go ahead. Hey, good morning, guys. Just maybe a question on the West Texas expansion. You've talked a while now about the optionality that you have once the final looping is complete, and just maybe just a little bit about timing and progress on decision of what service to put the legacy pipe into, whether that be crude refined product or NGLs, and then how readily and quickly you can make that transition. Well, right now, it is an option. We haven't decided to exercise that option. We continue to see good growth on the NGL side, so there is a good possibility we wanna keep it in NGL service to continue to be able to service our downstream assets in the Mont Belvieu area. If we would decide to shift it to some other product, the big thing is gonna have to be determined on which way we run it. Obviously, if we wanna run it from Mont Belvieu out to West Texas, it will take us a little bit more time because we'll have to do a little bit of work on header systems on that side. If we want another product moving from West Texas into Mont Belvieu, into the Houston area, it would be quicker because the pumps are already set up with that set up going that direction. But as of this moment, right now, we're probably leaning more towards the natural gas liquid side of it or the raw feed side of it as we continue to see good growth coming out of the Permian. Appreciate it, Sheridan. And then maybe for Walt, just curious, so you've talked about this in a couple of questions here, but as thinking about the three major projects coming off in 25, and what that implies for future CapEx, and certainly what that implies for future free cash flow. Can you talk about, as we think about 25 and 26, what gets you to maybe the higher end or the lower end of that capital return as a percent, that 75%-85%? Well, clearly, with what we have identified today from a CapEx standpoint, as I said before, that we would expect that capital return to ramp throughout that period. I think that we will be producing a meaningful amount of free cash flow. Obviously, it will increase when our CapEx number goes down. So we'll still stay in that 75%-85% availability after CapEx. It's just gonna be a bigger number, so it'll give us more opportunity for shareholder return. Tristan, this is Pierce. Kind of embedded in your question there is the implication of kind of what drives, you know, our EBITDA, you know, to the higher end, you know, versus the lower end. I think that's probably worth mentioning there. But, you know, filling more of our existing capacity across these assets is gonna clearly make that movement up. And we've already mentioned that we wanna make sure that we get this pipe in by Q1 of 2025 out of the Bakken. And then also to continue to prioritize and execute on those additional—those connectivities, you know, between our NGL refined products and crude oil systems across our footprint. And then third, it's those, you know, quicker than forecasted recognition of synergies. And then, of course, the downside, you know, would be, you know, things that might impact the volume, which is the weather and the producer activity. All of those kind of go into, you know, how far above or below the midpoint that we might be, that impacts what you and Walt just talked about. Pierce, appreciate it. Thank you all very much. The next question comes from Neal Dingmann with Truist Securities. Please go ahead. Hi, good morning. Thanks for the time. My first question is on NGLs. Specifically, just wondering where have you all seen notable demand to your NGL, the Permian NGL service? Is it mostly in key Midland or Delaware areas? I'm just wondering if there are specific areas that we should be looking at there. And then are you all taking market share from Permian contracts rolling off other pipes, or is this more basin expansion? Yeah. When we look at the Midland and Delaware, it's more as we look about growth to our system, it's more based on the customers out there and who we're seeing and the ones we've lined, and we have some that are more, more Midland specific, some that are more Delaware specific. So that really depends on who's kind of drilling more or bringing volume to us at the time. We, in terms of contracts roll-off, we've seen a little bit of that. What we've seen a little bit is some take-in-kind rights coming to us from different customers as we go forward. But overall, we see an opportunity in both of those basins to be able to source NGLs into our system, going forward. A lot depends. It really a lot depends on the customer. Yeah, that makes sense. Okay, and then just quick follow-up on, like, that slide, Tim, that shows the synergy opportunities. I'm just wondering on batch and the batching upside that you laid out here on this slide, just wondering timing-wise, how quickly I'm just wondering, are you thinking, and are there key areas that you'd anticipate seeing the majority of that batching upside? Well, on that batching, I think we're really gonna see a lot of it throughout our system. Some of it is already happening today. Some of it will happen throughout 2024. Those are opportunities that we see where we already have some connectivity between the system, and then that will continue to grow through 2025 and 2026 as we continue to bring these assets together. But we see that opportunity in the Central System, we see that opportunity on the Gulf Coast, we see that opportunity, even as much as on the lines out to West Texas. Thank you. Look forward to the upside. The next question comes from Craig Shere with Tuohy Brothers. Please go ahead. Good morning. Thanks for taking the question. On CapEx opportunities, could you opine on the possibility of needing another frac by 2026? And does the MMP acquisition increase prospects for accretively rebuilding and/or repurposing the legacy Medford frac site? This is Sheridan. Yeah, I don't think the MMP affects, really affects Medford at all, what we have there. As we think about increased frac capacity and our needs there, really what we're looking at right now is bottlenecks throughout our system, where we can get very low-cost expansions through our existing fracs. And we continue to look at Medford and what type of capacity we could get out of Medford at a very low cost by only bringing parts of it, portions of it back up. The whole facility wasn't as damaged by the fire as certain parts, so we think there is an opportunity to have a little bit less capacity there at a very low dollar per barrel of capacity. So that's where we see our next really growth in fractionation capacity coming from, and we really don't see the MMP acquisition have a big impact to that. Great. Last question, on synergies. It sounds like you expect almost the full $100 million or so in G&A benefits in 2024, which would suggest that, you know, you might be being conservative on the commercial side. Is that a fair assessment? Craig, it's Kevin. Like, like we said, I mean, we feel, obviously, we feel really good about our progress we've made on the cost savings side. I think just kind of naturally, many, many of those synergies come quicker than the commercial. We continue to prioritize those. You know, we did add kind of 100+, to the, to the upside for the cost savings side, so we'll continue to work those. But we're just trying to send the message that, particularly in 2024, there is a good chunk of the synergies that are gonna be cost savings. Okay, thank you. The last question comes from Zach Van Everen with TPH. Please go ahead. Hey, guys. Thanks for squeezing me in. Just going back up to the Rockies growth, you noted 9% year-over-year in 2024, but it looks like NGL growth is a bit lower than that for the year. Is the majority of that the contract rolls on Overland, or are you expecting just less overall ethane recovery? Just trying to kind of put those two numbers together. Yeah, on the NGL growth, we are expecting less, or we have put in our guidance, less incentivized ethane coming out of the Bakken. We definitely think there could be some upside there, so that has an impact. And then the contract that we will no longer be getting volume off of Overland Pass is a very low margin, very kind of high volume contract that has an impact, that we've even been expecting that contract or we knew we were not gonna be moving forward to renewing that contract when it came up. So this is something that's been in our plan for a period of time. So that's what's kind of driving a little bit of the difference when you look at the growth on G&P versus the growth on NGLs. Gotcha, that makes sense. And then shifting over to the rate adjustments in July, you noted mid-single digits. Just looking at the FERC-regulated calculation trending towards 1.5%, kind of hints at, you know, higher market-based adjustments. Curious if you're getting any pushback from customers on that or just how that conversation is going overall. We haven't decided what we're gonna do on market-based rate adjustments, but we do look at it very extensive at each one of our locations and do extensive look at the market and what's appropriate in those locations. That's why we've kind of just given a mid, you know, a single digit, mid-single digit rate is what we think it will be. But we have not yet determined exactly what we're gonna do. But we do have very conversation with customers, understand the marketplace, understand the dynamics that are there before we make those adjustments. Okay, perfect. Thanks, guys. That's all I had. This concludes our question and answer session. I would like to turn the conference back over to Andrew Ziola for any closing remarks. All right. Well, perfect timing, everybody. Our quiet period for the Q1 starts when we close our books in April and extends until we release earnings in late April. We'll provide details for that conference call at a later date. Thank you all very much, and have a great day. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.