Keith Stanley: 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 is a greenfield option that you are in the early stages of looking at to at Sabine Pass. Just any updated thoughts there?
Sheridan Swords: This is Sheridan. On the LPG exports, I think we are the same spotter what we can share publicly, where we have 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 is 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 have 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 move our barrels through the market today that has the export capabilities at other facilities.
Keith Stanley: Thank you.
Operator: Was there a follow-up to that Mr. Stanley?
Keith Stanley: No, that’s all. Thank you.
Operator: Thank you. The next question comes from Theresa Chen with Barclays. Please go ahead.
Theresa Chen: 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 price is certainly rising after the widening outage. Has this created opportunities for you to use the Sterling system to ship product 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?
Sheridan Swords: 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 opportunity for longer haul tariffs on our refined products system.
Theresa Chen: 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, can that create some uplift for the even heavier components of your NGL barrels.
Sheridan Swords: 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. And typically, as you know, alkylate is a very high priced and usually, they run those pretty strong. The big difference in those alkylate unit 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.
Theresa Chen: Thank you.
Operator: The next question comes from Tristan Richardson with Scotiabank. Please go ahead.
Tristan Richardson: 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?
Sheridan Swords: Well, right now, we – 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 would 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 will have to do a little bit of work on header systems on that side. If we want another product moving from West Texas in to 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.
Tristan Richardson: 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%?
Walt Hulse: Well, clearly, with what we have identified today from a CapEx standpoint, as I have 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 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.
Pierce Norton: 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 there. But filling more of our existing capacity across these assets is going to clearly make that movement up. And we have already mentioned that we want to make sure that we get this pipe in by first quarter 2025 out of the Bakken. And then also to continue to prioritize and execute on those additional – those 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.
Tristan Richardson: Peirce, appreciate it. Thank you all very much.
Operator: The next question comes from Neal Dingmann with Truist Securities. Please go ahead.
Neal Dingmann: Good morning. Thanks for the time. My first question is on NGL specifically, just wondering where are 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 this is more basic expansion?
Sheridan Swords: 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 the ones we have aligned, 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 – in terms of contracts roll off, we have seen a little bit of that. What we have seen a little bit is some taking kind rides 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 – really, a lot depends on the customer.
Neal Dingmann: 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?
Sheridan Swords: Well, on that batching, I think we are really 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 system and then that will continue to grow through ‘25 and ‘26 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 of West Texas.
Neal Dingmann: Thank you for the upside.
Operator: The next question comes from Craig Shere with Tuohy Brothers. Please go ahead.
Craig Shere: 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 legacy Medford frac site?
Sheridan Swords: This is Sheridan. Yes, I don’t think the MMP effects, really affects Medford at all what we have there. 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. 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 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 really growth in fractionation capacity coming from, and we really don’t see the MMP acquisition have a big impact to that.
Craig Shere: Great. And 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?
Kevin Burdick: 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 kind of 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.
Craig Shere: Okay. Thank you.
Operator: And the last question comes from Zack Van Everen with TPH. Please go ahead.
Zack Van Everen: 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.
Sheridan Swords: Yes. The – 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. We haven’t been expecting that contract or 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. So, that’s what’s kind of driving a little bit of the difference when you look at growth on G&P versus the growth on NGLs.
Zack Van Everen: 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 that higher-market based adjustments. Curious if you had any pushback from the customers on that or just how that conversations going overall?
Sheridan Swords: We haven’t decided what we are going to 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. And 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. But we do have varied conversation with customers, understand the marketplace, and extend the dynamics that are there before we make those adjustments.
Zack Van Everen: Okay. Perfect. Thanks guys.
Operator: This concludes our question-and-answer session. I would like to turn the conference back over to Andrew Ziola for any closing remarks.
Andrew Ziola: 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.
Operator: The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.
