Thank you, Drew, and welcome to ONEOK’s fourth quarter 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 will turn the call over to Pierce Norton, President and Chief Executive Officer. Pierce?

Thanks, Andrew, and good morning, everyone. 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 is 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 is the Executive Vice President of Chief Enterprise Services. 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 have increased dividends paid to $3.82 per share from $1.48 per share, 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 5 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 have 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 towards the top of our industry peer group, including a AAA rating from MSCI. We have 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 fourth quarter and full-year financial performance. ONEOK’s fourth quarter and full-year 2023 net income totaled $688 million and $2.7 billion respectively. Adjusted EBITDA totaled more than $1.5 billion in the fourth quarter 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 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 fourth quarter 2023 run rate net debt-to-EBITDA ratio in line with our previously discussed target of 3.5x. In January, we increased our quarterly dividend by 3.7% to $0.99 per share or $3.96 per share on an annualized basis. Going forward, ONEOK expects to target an annual dividend growth rate ranging between 3% to 4%. We also announced a $2 billion share repurchase authorization, which we expect to largely use over the next four years. This program is complementary to the dividend growth rate when thinking about shareholder returns in the future. Over the next four years, ONEOK’s combination of dividends and share repurchases is expected to trend towards a target of approximately 75% to 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, an EPS midpoint of $4.88 per diluted share and an adjusted EBITDA midpoint of $6.1 billion. We also include in 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 first quarter 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 decisions. 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 fourth quarter volumes totaling nearly 400,000 barrels per day of NGLs and nearly 1.6 Bcf per day of processed volume. Mid-Continent process 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 benefits 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 operations since the acquisition of Magellan. This segment’s performance was driven by midyear tariff increases, longer haul refined product shipments, and steady crude oil transportation volumes. Our optimization and marketing activities, which include 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 earnings 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 should 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’re officially moving forward with 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 an average of more than 1.6 Bcf per day 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 negative 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 at 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 Pipelines 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 idled 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 the final investment decision on the pipeline by midyear 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 midyear 2023 increase of 11.5%. 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 segment’s earnings. Pierce, that concludes my remarks.

Thank you, Sheridan and Walt. I started this call by saying that 2023 was a year of significant growth and transformation. None of this would have been possible without our dedicated employees, many of whom are actually listening to this call today. So I want to make sure that I thank them publicly for all that they did in 2023. With us now 5 months post-closing of the acquisition, our employees have continued to focus on our integration efforts and prioritize the reliable operation of our assets with 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. And from a safety perspective, we 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 and the communities that we operate in. 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.

The first question comes from Brian Reynolds with UBS. Please proceed.

Hi. Good morning, everyone. Maybe to start off on synergies on Slide 10. We’ve seen the risk-weighted synergies increase to roughly $400 million from the original expectation of $100 million. So perhaps just a two-part question. First part is, can you provide some concrete commercial examples of what’s driving that upward revision? Just anything specific? And then second, based on that these risk-adjusted synergies are up roughly $300 million, could you perhaps update us on the initial like $200 million to $800 million synergy range that you provided 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 going forward, as we say in the $700 million. And really, a lot of it is going to 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 ‘24 and ‘25, the focus will be on prioritizing which ones we can work on and bring forward. We started 24 wells to be driven by, we’ve reached a substantial amount of our cost-saving synergies already through ‘23, and we’ll see a full year of that in ‘24.

Brian, this is Kevin Burdick. The other thing, just on the – if you think about the cost savings, we have realized the vast majority of those already. So we’ll see the full impact in ‘24. A couple of examples would be our organizational design and restructuring activities are complete, so that will be factored in. Another example, public company costs have been eliminated for the Magellan Company. So that’s another example as well as many others. So the cost savings side will play a big role in 2024 as well.

Great, thanks. Appreciate that. Maybe to switch to just the updated return on capital framework. You outlined a 3% to 4% dividend growth, but kind of updated it with the updated payout ratio of 75% to 80% with buybacks and dividends. So looking at the model, it seems like it’s pretty clear on 2024 that you can kind of come to that conclusion. But when I look at ‘25 and ‘26, leverage trends below 3.5x, you should have some excess cash based on existing projects that are FID at this point with potentially Saguaro going into that bucket. So as we look in ‘25 or ‘26, can you maybe update us on how we should think about the return of capital framework? Could we see maybe an increase in buybacks? Or how should we think about maybe interest in M&A or maybe other projects that may come to fruition in ‘25 and ‘26 while keeping that return on capital framework unchanged?

Sure. I want to 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 are obviously 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 set with the goal of that 3.5x. So we will expect that to ramp over time. But 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 an additional 15% to 25% of unallocated cash flow for high-return capital projects that we have not yet identified.

Great. Makes sense. Super helpful. Enjoy the rest of the 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 our prepared remarks and in our earnings release, come up in the first quarter of 2025, and it’s a 125,000-barrel-a-day frac. So it will have a significant impact on our third-party frac costs. Our third-party frac costs in 2024 will be about $30 million a quarter, so I think that's 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 landed about 2% of butane into the gasoline stream, but because you’re able to blend a lot of the butane into 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 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 detail, but butane blending is driven by regulations of RVP into the gasoline. So there is a limit. But other than that, we don’t want to 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.

Hi, good morning, everybody. And thanks for the clarity. So I wanted to start off on the consolidation theme. It seems like 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, as you think about that as a growth revenue, should we be thinking about any major guardrails in terms of the assets or corporations that you look at?

Sunil, this is Pierce. The question kind of falls into the bucket of mergers and acquisitions. I just want to reemphasize that our primary focus is to continue to integrate the Magellan acquisition and execute on the synergies and opportunities that we see to create the maximum value for our shareholders. So we’re going to continue to be intentional and disciplined in our approach 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 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 help us think through the growth CapEx needs at combined ONEOK now. And is there a good way to think about growth CapEx or total CapEx needed to maintain volumes and then to further on grow volumes?

So I’ll take a high-level look 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% to 25%. So there is money out there for these high-return projects that we are either working on or even not identified at this point. So as far as the specifics go, I’ll turn it over to Walt and Sheridan.

Well, I think as we mentioned here in 2024, we’ve identified a midpoint of $1.85 billion. 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 want to make sure is done here in early 2025. Once those projects are done, we don’t have any other large identified projects that we’ve FID for the market. So you can kind of peel those away as they come into 2025. Our routine growth-type expenditures will continue, and we will find more opportunities that will probably 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 ‘25 and ‘26.

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-’24, first of all, would that change the ‘24 CapEx number much or would most of that fall into the ‘25 and ‘26? And would that change your expectation that ‘25 CapEx would come down?

I’m going to let Walt take the CapEx question, but there’s a couple of things that I want to make sure that I note on this call that pertains to Saguaro, Michael. And one is I want to really thank all those employees who worked on getting the permit approved in this process. As we look at Saguaro, it is the most economic route for LNG to reach the markets or at least multiple markets. That’s actually been indicated by the strong commercial interest and the backing by the major players there. Here’s where I want to make this clear that we said all along that our commitment to this project will involve procuring the presidential permit, which 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 going to be commensurate with the value that it brings to our shareholders versus the risk we see in the project. I’ll let Walt fill in some of the details there.

Yes, Michael. Given the timing, 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 about seeing a reduction over the 2024 level of CapEx as we go forward. Projects take a couple of years to construct, and we’ll fit right into our capital program.

Great, thanks for that. I wanted to ask about the Elk Creek expansion you announced. Can you help us understand what the increase in volumes might look like? Should we expect it to be highly utilized at startup, or will this be more of a gradual increase? Thanks.

Well, Michael, as we think about the Elk Creek expansion, we’ve always said that we’re not going to run out of capacity coming out of the Bakken. And that’s why we want to make sure this pipeline comes up in the first quarter of 2025. So we are expecting volume increases, and we’ll need that as we move into 2025. There are a lot of things that affect the ramp-up. One is how much incentivized ethane we have coming out of there. And the other one is the continued growth 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 increase 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 JPMorgan. Please go ahead.

Good morning. I appreciate the color you guys provided on producer efficiency in the slides and even in the prepared remarks. It seems like a pretty significant step up there in the share of 3-mile laterals in ‘24. So just kind of thinking, should we be thinking about the increase in 3-mile laterals reducing the required CapEx to maintain current volumes at this point? Or any other thoughts you could frame up there would be greatly appreciated.

Yes. This is Sheridan. Absolutely, with more efficiency and growing 3-mile laterals, each well is going to have more production on that. So we are going to 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. And 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 volume starts flowing on Coastal GasLink to service LNG Canada?

Well, Vrathan, 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 by 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 in Chicago. And there’s been some relief in our G&P business, working a deal with WBI to move some gas down to Cheyenne Hub, and that’s been a nice relief. You’ve probably seen some information about Bison Express, 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 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. Good morning, everybody. Maybe just go back to a follow-up to Michael’s question, but really kind of focused on the three major projects you’ve got coming online in the first quarter of ‘25. As 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 ‘25.

Well, I’ll take the first part of that. As we look at each one of those projects, and we think about the ramp-up, MB-6 is going to come up full because we’re having third-party frac capacity today. So it’s going to be at a very high operating rate. So it’s going to 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. We’re continuing to drive that project’s multiple down as we grow on that. The Elk Creek expansion is probably going to 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. And if we would get to the point that we are at a high utilization rate, that multiple will be well below 1.

Okay. That’s helpful. Thanks very much, Sheridan. And maybe going back to the synergies, it sounds like for 2026 plus, you’re going to 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.

Yes. I think it’s going to be all that kind of stuff. It’s going to be relatively small capital. There’s going to be some connections here, some tanks there, depending all up and down our system. Some of that will come before ‘26. But as we continue to look forward to that, we’ll achieve most of it as we head into the ‘26 timeframe.

Great. I will leave it there. Thanks for the time.

The next question comes from Jean Ann Salisbury with Bernstein. Please go ahead.

Hi. Just a 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 MMcfd to 400 MMcfd that they have directly contracted. Do you think we have had 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, this is Chuck. I stand by what I have 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 Express and the WBI expansion.

So, Jean Ann, this is Pierce. Based on what I have seen, I mean, I actually look at this as well. There is capacity today. So, there are no restrictions today. And if you look at the fact that there are going to be some natural gas-fired generation facilities that are going to be built in the North Dakota area, and you also look at the Bison Express and then you also look at WBI, we are not seeing anything in – anywhere in the near future that there is going to be any kind of restrictions on gas takeaway.

Yes. And while we think there is plenty of takeaway, do remember that we always have the lever if we need to, that we can extract more ethane and put it on the NGL pipe to create capacity for natural gas.

Thank you. That’s exactly what I was looking for. And then kind of a follow-up on 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 few years from now, but associated gas will likely still grow. And 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 EBITDA?

Potentially, I think when we get out in 2025, we will see a little bit more of ethane export capability coming online. A lot really depends on how hard the pet chems are running on utilization, which is a big impact. And then as we think about ethane rejection and recovery across our footprint, a lot depends on what the natural gas prices are in that area. 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 G&P system as well. The Mid-Continent maybe where we see a little bit of swing, could be a little bit more swing in ethane recovery, but those were at much lower rates than we see coming out of the Bakken. But I think the big thing is going to be how hard the pet chems are, the utilization rate. We are seeing as we move into 2024, they are operating at pretty high levels.

That’s helpful. Thanks for taking my questions.

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. 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 mitigate that risk around that issue as it relates to your project and your contracts?

Keith, this is Chuck. Yes, as you state, MPL received back in 2019 for the first two trains, the OE 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, I feel pretty good, obviously, about trains one and two; this pause that we are seeing right now impacts their second requested approval, which would be for train three. As you know, we don’t know exactly how this is going to play out in the 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 are weighing the potential to use Magellan sites or other facilities versus I think there's a greenfield option that you are in the early stages of looking at to at Sabine Pass. Just any updated thoughts there?

This is Sheridan. On the LPG exports, I think we are in the same spot we’ve been for a period of time, as you are right. We continue to look at all alternatives that we have. We have a greenfield site, trying to understand if there are 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 something that could enhance our integration, but it’s not something we absolutely need as we continue to be able 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.

Good morning. On the refined products side, with the significant swings in Mid-Con versus Gulf Coast product prices thus far into the year, Mid-Con being heavily discounted earlier in the year, then product prices certainly rising after the widening outage. Has this created opportunities for you to use the Sterling system to ship product to software when the ARPA was there towards the beginning of the first quarter and also opportunities for more long-haul movements of refined products from the Gulf Coast to Mid-Con on the legacy Magellan assets and incremental earnings as a result?

What I would say is, right now, we are not going to comment specifically on refined products, movements on any specific pipeline. What I can tell is NGL pipelines have moved refined products here in the fourth quarter and the first quarter. We do see, with that movement in the two pricing mechanisms between the Gulf and the group, we have seen an opportunity for longer haul tariffs on our refined products system.

Okay. And Sheridan, going back to the butane blending synergies and your comment about the RVP requirements, so butane blending getting to come out of the gasoline pool in that mid-April timeframe. And just given the comments from some of the downstream customers that have 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 create some uplift for the even heavier components of your NGL barrels?

Yes. There could be some potential as we look at for the natural gasoline component of the barrel, some blending into the unleaded pool that we have looked at. As in terms of isobutane specifically going into alkylate, we have been servicing those alkylate units for quite a long time in the legacy NGL business. Typically, as you know, alkylate is a very high-priced, and usually, they run those pretty strong. The big difference in those alkylate units is whether or not they are going to run some refinery-grade propylene through that unit or are they going to stay, or how their RGBs, refiner grade butane runs through that as well. So, if we see more propylene run through an alkylate 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.

Hi, good morning, guys. Just maybe a question on the WesTex expansion. You have talked a while now about the optionality that you have once the final team is complete. And just maybe just a little bit about timing and progress on the decision of what service to put the legacy pipe into your 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 on the NGL side. So, there is a good possibility we want to keep it in NGL service to continue to be able to service our downstream assets in the Mont Belvieu area. If we decide to shift it to some other product, the big thing is going to have to be determined on which way we run it. Obviously, if we want to 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 going that direction. But as of this moment right now, we are probably leaning more towards the natural gas liquids 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, you 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% to 85%?

Well, clearly, with what we have identified today from a CapEx standpoint, as I’ve said before, we would expect that capital return to ramp throughout that period. I think we will be producing a meaningful amount of free cash flow. Obviously, it will increase when our CapEx number goes down. So, we will still stay in that 75% to 85% availability after capex; it’s just going to be a bigger number. So, it will 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 our EBITDA to the higher end versus the lower end. I think that’s probably worth mentioning. But filling more of our existing capacity across these assets is going to clearly make that movement up. We have already mentioned that we want to make sure that we get this pipe in by the first quarter of 2025 out of the Bakken. We also want to continue to prioritize and execute on those additional connectivities between our NGL, refined products, and crude oil systems across our footprint. And then third, it’s those quicker than forecasted recognition of synergies. And of course, the downside would be things that might impact the volume, which is the weather and the user activity. All of those kind of go into 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.

Good morning. Thanks for the time. My first question is on NGL specifically, just wondering where you all seeing notable demand pure NGL from the Permian NGL service. Is it mostly in key Midland or Delaware areas? I am 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 basic expansion?

Yes. 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 are seeing, and we have some that are more Midland-specific, some that are more Delaware-specific. So, that really depends on who is kind of drilling more or bringing volume to us at that time. We have seen a little bit of that in terms of contracts rolling off. What we have seen a little bit is some taking kind rides coming to us from different customers as we go forward. Overall, we see an opportunity in both of those basins to be able to source NGLs into our system going forward. A lot depends – really, a lot depends on the customer.

Yes, that makes sense. Okay. And then just a quick follow-up on, like that Slide 10 that shows the synergy opportunities. I am just wondering on the batching upside that you laid out here on this slide, just wondered timing-wise, how quickly, I am just wondering are you thinking, and are there key areas that you would anticipate seeing the majority of that batching upside?

Well, on that batching, I think we are going to 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 systems, and that will continue to grow through ‘25 and ‘26 as we continue to bring these assets together. We see that opportunity in the central system, on the Gulf Coast, and even on the lines out of West Texas.

Thank you for 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 meeting 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. Yes, I don’t think the MMP affects what we have at Medford at all. As we think about increased frac capacity and our needs there, really what we are looking at right now is bottlenecks throughout our system where we can get very low-cost expansions through our existing fracs. 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 portions of that back up. The whole facility wasn’t as damaged by the fire in 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 growth in fractionation capacity coming from, and we really don’t see the MMP acquisition having a big impact on that.

Great. And the 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 might be being conservative on the commercial side. Is that a fair assessment?

Craig, it’s Kevin. Like we said, I mean we feel – obviously, we feel really good about our progress we have made on the cost savings side. I think just kind of naturally, many of those synergies come quicker than the commercial. We continue to prioritize those. We did add about 100 plus to the upside for the cost savings side. So, we will continue to work those. But we are just trying to send the message that, particularly in ‘24, there is a good chunk of the synergies that are going to be cost savings.

Okay. Thank you.

And the last question comes from Zack 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 from the contract rolls on Overland, or are you expecting just less overall ethane recovery? Just trying to kind of put those two numbers together.

Yes. 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 high-volume contract that has an impact. We haven’t been expecting that contract, and we knew we were not going to 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. That’s what’s driving a little bit of the difference when you look at growth on G&P versus the growth on NGLs.

Got it. 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 higher market-based adjustments. Curious if you had any pushback from the customers on that or just how that conversation's going overall?

We haven’t decided what we are going to do on market-based rate adjustments, but we do look at it very extensively at each one of our locations and do an extensive look at the market and what’s appropriate in those locations. That’s why we have kind of just given a mid-single-digit rate is what we think it will be. But we have not yet determined exactly what we are going to do. We do have varied conversations with customers, understand the marketplace, and extend the dynamics that are there before we make those adjustments.

Okay, perfect. Thanks guys.

This concludes our question-and-answer session. I would like to turn the conference back over to Andrew Ziola for any closing remarks.

Alright. Well, perfect timing, everybody. Our quiet period for the first quarter starts when we close our books in April and extends until we release earnings in late April. We will 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.