Good afternoon. And welcome to the Energy Transfer Fourth Quarter 2023 Earnings Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note that this event is being recorded. I would like to turn the call over to Tom Long. Please go ahead.

Thank you, Operator, and good afternoon, everyone. And welcome to the Energy Transfer's fourth quarter 2023 earnings call. I'm also joined today by Mackie McCrea and other members of the senior management team who are here to help answer your questions after our prepared remarks. Hopefully, you saw the press release we issued earlier this afternoon as well as the slides posted to our website. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These statements are based upon our current beliefs as well as certain assumptions and information currently available to us and are discussed in more detail in our Form 10-Q for the full year ended December 31, 2023, which we expect to file this Friday, February 16. I'll also refer to adjusted EBITDA and distributable cash flow or DCF, both of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP financial measures on our website. Let's start today by going over our financial results. For the full year 2023, we generated adjusted EBITDA of $13.7 billion, which is up 5% over 2022 and is a partnership record. DCF, attributable to the partners of Energy Transfer, as adjusted, was $7.6 billion, which resulted in excess cash flow after distributions of approximately $3.6 billion. Operationally, we moved record volumes across all of our segments for the year ended 2023, which included record volumes on our legacy assets before including contributions from assets acquired in 2023. In addition, we exported a record amount of total NGLs out of our Nederland and Marcus Hook terminals in 2023. For the fourth quarter of 2023, we generated adjusted EBITDA of $3.6 billion compared to $3.4 billion for the fourth quarter of 2022. In our base business, we had strong performances across our operations, which included record volumes through our NGL pipelines and fractionators, as well as record volumes in our crude oil and midstream segments. DCF, attributable to the partners of ET, as adjusted, was $2 billion compared to $1.9 billion for the fourth quarter of 2022. This resulted in excess cash flow after distributions of approximately $970 million. On January 25th, we announced a quarterly cash distribution of $0.315 per common unit or $1.26 on an annualized basis. This distribution represents an increase of 3.3% from $0.305 paid in the fourth quarter of 2022. Last year, Energy Transfer's senior unsecured credit rating was upgraded by Standard & Poor's to BBB with a stable outlook. And last week, we were pleased to see that Fitch also upgraded Energy Transfer's senior unsecured credit rating to BBB with a stable outlook. This continued third-party acknowledgment reiterates the emphasis we have placed on balancing growth while improving our balance sheet and reducing our leverage. And in 2023, we made meaningful progress toward reaching the low end of our leverage range. Based on our calculations of the rating agency's methodologies and pro forma for the full year of acquisitions, our leverage ratios are now in the lower half of our 4 to 4.5 target range. As of December 31, 2023, the total available liquidity under our Revolving Credit Facilities was approximately $3.56 billion. During the fourth quarter of 2023, we spent approximately $380 million on organic growth capital, and for the full year 2023, we spent approximately $1.6 billion on organic growth capital, primarily in the midstream and NGL and refined product segments, excluding SUN and USA Compression CapEx. The reduction in capital relative to our most recent guidance is a result of deferring approximately $300 million from 2023 into 2024 due to project in-service timing needs. In January 2024, we issued $3 billion of aggregate principal amount of senior notes and $800 million of junior subordinated notes and used the proceeds to refinance existing indebtedness and for general partnership purposes. Additionally, proceeds were used to redeem all of our outstanding Series C and Series D preferred units. We completed this redemption on February 9th and we expect to redeem all of our outstanding Series E preferred units by May of 2024. Now turning to our results by segment for the fourth quarter, I'll start with NGL and refined products. Adjusted EBITDA was $1 billion compared to $928 million for the fourth quarter of 2022. This was primarily due to strong performances across our transportation, storage, terminal, and fractionation operations as well as lower operating expenses. NGL transportation volumes increased 10% to 2.2 million barrels per day compared to 2 million barrels per day for the same period last year. This increase was primarily due to higher volumes from the Permian region and on our NGL pipelines that deliver into our Nederland terminal as well as on the Mariner East pipeline system. Average fractionated volumes increased 16% to a partnership record 1.1 million barrels per day compared to 982,000 barrels per day for the same period last year. Total NGL export volumes grew 13% over the fourth quarter of 2022 and 18% over full year 2022. This was primarily driven by increased international demand for natural gas liquids. For 2023, we loaded more than 61 million barrels of ethane out of Nederland and nearly 27 million barrels of ethane out of Marcus Hook. For 2023, we continued to export more NGLs than any other company and maintained approximately 20% market share of worldwide NGL exports. For Midstream, adjusted EBITDA was $674 million compared to $632 million for the fourth quarter of 2022. We saw record throughput this quarter, which was primarily the result of the addition of the Crestwood assets, as well as higher volumes from existing customers in the Permian, South Texas, and Mid-Continent regions. The strong volume growth was partially offset by lower natural gas and NGL prices. Gathered gas volumes increased 5% to 20.3 million MMBTUs per day, compared to 19.4 million MMBTUs per day for the same period last year. For the crude oil segment, adjusted EBITDA was $775 million, compared to $571 million for the fourth quarter of 2022. This was primarily due to higher volumes on several of our pipelines, higher terminal throughput, as well as the acquisitions of the Lotus and Crestwood assets in May and November of last year. Crude oil transportation volumes increased 39% to a record 5.9 million barrels per day, compared to 4.3 million barrels per day for the same period last year. This was a result of higher volumes on our Texas pipeline systems and the Bakken and Bayou Bridge Pipeline, increased crude oil gathering volumes, as well as the acquisitions of Lotus and Crestwood. Without the additions of Lotus and Crestwood, adjusted EBITDA and crude oil transportation volumes would still have increased 16% and 8%, respectively, compared to the fourth quarter of 2022. In our interstate segment, adjusted EBITDA was $541 million compared to $494 million for the fourth quarter of 2022. This increase was primarily due to placing the Gulf Run Pipeline into service in December of 2022, as well as higher contracted volumes on several of our wholly owned and joint venture pipelines. Volumes increased 5% over the same period last year, due to the Gulf Run Pipeline being placed into service, as well as higher utilization on many of our interstate pipelines, including Transwestern, Rover, and Trunkline. We continue to fully utilize Zone 1 capacity on Gulf Run, and we are also maximizing deliveries into our Trunkline pipeline from Zone 2. Our team continues to work on the next phase of a potential capacity expansion to facilitate the transportation of natural gas from northern Louisiana to the Gulf Coast based upon customer demand. And for our intrastate segment, adjusted EBITDA was $242 million compared to $433 million for the fourth quarter of last year. Benefits from new contracts on several of our Texas pipelines, as well as lower operating expenses, were more than offset by decreases from lower optimization opportunities. Now turning to our acquisition of Crestwood Equity Partners, which we completed in November of 2023, integration of the combined operations has been going very well. The combination of these complementary assets will allow us to continue to provide flexibility, reliable, and competitive services for our customers as we pursue additional commercial opportunities utilizing our improved connectivity and expanded footprint. We now expect to generate approximately $80 million of annual cost synergies by 2026, with $65 million in 2024. This is before any additional anticipated benefits from financial or commercial synergies. We are in the process of identifying and evaluating a number of commercial and operational synergies that are expected to enhance the operational capabilities of our systems by improving efficiencies and increasing the utilization and profitability of our combined assets. These synergies include optimizing our West Texas processing capacity given the newly acquired Crestwood plants, as well as utilizing spare NGL pipeline capacity out of the Delaware Basin and working with producers in West Texas and New Mexico to provide additional water gathering solutions. We're also looking at opportunities to move more barrels into our Bakken Pipeline system for transport to the Gulf Coast. And in the Northeast, we're evaluating options to transition LPG products previously transported by truck into our Mariner East pipeline system. Now turning to our growth projects, starting with our Nederland and Marcus Hook export terminals, our NGL terminals continue to benefit from increased demand from both in the U.S. as well as from international customers. To address this demand, construction is underway on our expansion to the NGL export capacity at Nederland and we expect to be finished driving piles by the end of the month. This expansion is expected to give us the flexibility to load various products based upon customer demand. We continue to expect the project to be in service in mid-2025. In addition, we are building new refrigerated storage at Nederland, which will increase our butane storage capacity by 33% and will double our propane storage capacity. This will further increase our ability to keep customers’ ships loaded on time. Also, we recently closed on the acquisition of two pipelines, one from Mont Belvieu at our Nederland Terminal and one from Mont Belvieu to the Ship Channel. We expect to have term transportation commitments on the Mont Belvieu to Nederland Pipeline in the near future, which will have the ability to flow at least 70,000 barrels per day. This will provide much-needed capacity for several products in high demand, both international and domestically. And we are in discussions to provide transportation for potentially multiple products on the pipeline that extends from Mont Belvieu to Houston. And at our Marcus Hook Terminal, we have commenced construction on the first phase of an optimization project that would add incremental ethane refrigeration and storage capacity. In addition, we have begun expanding our processing capacity at several of our existing 200 million cubic feet per day cryogenic processing plants. In total, we see opportunities to add approximately 100 to 150 million cubic feet per day of processing capacity in our west and south Texas regions at favorable capital costs when compared to building a new processing plant. In November 2023, we announced a Heads of Agreement, or HOA, with TotalEnergies for crude offtake from our proposed Blue Marlin Offshore project. Additional customers remain very engaged and interested in our project, recognizing the value of fully loading VLCCs and the reduced execution risk that comes with repurposing existing underutilized assets. Next on an update for our Lake Charles LNG project, as most of you are aware, the Biden administration recently imposed a moratorium on the approval of LNG exports by the Department of Energy, while the DOE conducts studies to determine whether LNG exports are in the public interest. The Biden administration stated that these studies would focus on the cumulative impact of LNG exports on climate change, U.S. natural gas prices, and the impact of LNG facilities on local communities. The DOE most recently conducted similar studies in 2019 and based on the results of these studies, the DOE subsequently approved several LNG export projects. In light of the extremely low natural gas prices in the U.S. currently and the beneficial climate impacts from the use of natural gas compared to coal for power generation, it would be difficult to believe that these new studies won't continue to conclude that LNG exports are in the U.S. public interest. Lake Charles LNG applied for a new LNG export authorization in August of 2023 and requested approval by February of 2024. The recently announced moratorium on approvals of LNG export creates uncertainty as to when the DOE studies will be completed and whether the criteria for approving LNG export projects will be changed. Despite these uncertainties, Lake Charles LNG continues to pursue the development of the project and is extremely thankful for the continued support of its LNG customers. And now for an update on other projects. On the blue ammonia front, we are working with several companies to evaluate the feasibility of ammonia projects. That would include the opportunity to supply and transport natural gas to the ammonia facility and to transport CO2 to third-party sequestration sites. We're also looking at opportunities to provide other infrastructure services, including transport and sequestration, ammonia storage, and deep water marine loading on property near our Lake Charles and Nederland facilities. Additionally, we're working on carbon capture and sequestration projects for our processing plants and treating facilities in North Louisiana, South Texas, and West Texas. And we are evaluating other CO2 pipeline projects that would connect CO2 emitters to CO2 sequestration sites. Before moving to discuss our 2024 guidance, we wanted to quickly address another topic. Our practice is not to comment on pending litigation. However, given that we have received a number of questions about the Louisiana Pipeline matter, we would like to provide some important context. Recently, several third parties approached Energy Transfer about crossing various pipes we own and operate in Louisiana, including three of our common carrier pipelines, gathering systems, and other lines. These three parties proposed between 140 and 160 crossings, as well as seeking to secure long segments of proposed parallel pipe within our existing rights of way and workspaces. As a consequence, we requested certain technical information from these parties regarding these crossings to allow us to evaluate their technical feasibility and potential issues between these new proposed pipes and our existing operations. The parties making these requests largely rejected or ignored our very reasonable request. Instead, on at least two occasions, they told us they would begin construction on these new pipes, whether we agreed to the crossings or not. At that point, we had no choice but to enforce our property rights by filing legal actions to prevent these crossings, pending our ability to evaluate the technical details of the crossing. In the process of enforcing our property rights, one of the requesting parties has alleged that Energy Transfer is using unfair or anti-competitive practices to block all pipeline crossings requests in Louisiana in an effort to stifle competition and monopolize the pipeline capacity, moving gas from the Haynesville, and these practices are threatening the expansion of pipeline infrastructure in Louisiana. These statements are unfounded and false. In our opinion, these parties are skirting state and federal regulations and regulatory oversight by seeking to quickly build large diameter pipe, high-pressure pipelines across state lines and calling them gathering. To this end, we encourage you to read the submission we filed in docket number 84356 in the 42nd Judicial District Court in DeSoto Parish, Louisiana, which sets forth our positions on the facts and on the law. We do not want to litigate the matter on this earnings call. However, we want to underscore that Energy Transfer takes very seriously its obligations to operate its assets safely and reliably. Energy Transfer is simply seeking to protect its legal property rights under Louisiana law. Indeed, not a single court has found that ET somehow acted in bad faith in defending its lawful property rights. Nonetheless, any pipeline that is unable to agree to terms on a pipeline crossing is free to exercise rights of condemnation or expropriation as applicable. To accomplish the crossings as it seeks to do so under state or federal law, Energy Transfer has never taken the position that others cannot cross us ever, just that they must assure us that they will not adversely affect our existing lines, create additional costs for us, put us at risk under existing FERC certificates, and unjustifiably piggyback off of our efforts to build pipelines in compliance with state and federal rules, including in some cases significant environmental reviews. We appreciate that long-distance transmission lines have become increasingly difficult to build, particularly given entrenched environmental opposition. No one knows that better than Energy Transfer. As we have been clear, Energy Transfer embraces markets and vigorous competition, but this also means respecting property rights and playing by the rules. And looking ahead at our 2024 organic growth capital guidance, we expect growth capital expenditures to be between $2.4 billion and $2.6 billion for 2024, inclusive of the $300 million deferral from 2023, which will be spent primarily in the NGL and refined products and midstream segments. This capital is made up of expansions to our export facilities and storage tanks at Nederland optimization work at Marcus Hook and new pumping stations to increase our NGL takeaway capacity from the Permian, new crude oil pipeline connections, and new treating capacity in the Haynesville. In addition, this capital includes a large number of blocking and tackling projects, including processing plant capacity additions, compression and laterals to existing pipeline systems, additional gathering and compression build-out, as well as improved efficiencies and emissions reductions work. We also continue to evaluate a number of other potential growth projects that we hope to bring to FID. However, as we look at our potential backlog of high-returning growth projects, we continue to expect our long-term annual growth capital run rate to be approximately $2 billion to $3 billion. Now turning to our 2024 adjusted EBITDA guidance, giving the ability of our business to provide stable cash flows and operate through various market cycles, as well as our market outlook, we expect our adjusted EBITDA to be between $14.5 billion and $14.8 billion. In 2024, we expect utilization of assets within our core segments to remain strong and that recently acquired assets will provide growth and synergy opportunities. Worldwide demand for crude oil, natural gas, natural gas liquids, and refined products continues to grow and we will continue to position ourselves to meet this demand by strategically targeting optimization and expansion projects that enhance our existing asset base, generate attractive returns, and meet this growing demand for our product and services. As a result of our continued emphasis on strengthening our balance sheet, we're in the strongest financial position in Energy Transfer's history, and this will allow us the flexibility to balance pursuing new growth opportunities with further leverage reduction, maintaining our targeted distribution growth rate, and increasing equity returns to our unitholders. This concludes our prepared remarks. Operator, please open the lineup for the first question.

The first question comes from Jeremy Tonet with J.P. Morgan.

Hi, good afternoon. I just want to start off if I could, maybe some of the drivers that feed into the guidance here. We have seen a bit of volatility in commodity prices and the environment overall. Just wondering, I guess, latest expectation for producer activity in the Haynesville, what have you, how that factored in, or any other key drivers you call out for the upside versus the low side of the guidance?

Hey Jeremy, this is Mackie here to start. Yes, with the lower gas prices in North Louisiana, certainly if they get any lower, we probably will see a slowdown, but right now we haven't seen it. Out in the Permian Basin, where we have a tremendous amount of assets, we see growth even in the lower gas price environment. With the higher oil prices, we continue to see growth and we are projecting modest, if not fairly significant, growth out of the Permian Basin. Other areas, it varies, midcontinent, relatively flat, and other areas where our assets are pretty stable.

Jeremy, this is Tom. I think in addition, the pricing that you brought up in your question just then. We've used the forward curve in this. So this is the kind of latest forecast we have; we always stay kind of down the middle of the road with the range that we put out at the beginning of the year. So anything that we've seen, even here in the first quarter, et cetera, this would be our latest forecast, everything included. So feel good about it and look forward to another great year.

Got it. Okay. So, it sounds like kind of a conservative outlook on producer activity given where this trip is there. Maybe pivoting a little bit towards capital allocation, even with the capital program that you guys laid out as it is, it seems like there's going to be a significant amount of surplus cash flow. And now you've kind of hit stronger credit metrics, getting to BBB. Just wondering how you think about this surplus cash flow, what's the, I guess, priority ranking for the capital allocation at that point?

Well, it's probably pretty consistent to where we've been. The main difference is that we have gotten to the lower side of our 4 to 4.5. And like we said before, it wouldn't even hurt to go a little bit lower if it gave us a little bit more dry powder to be able to continue to look at growth opportunities, et cetera. So if you kind of move through that, you go into the growth capital that we've talked about. We're obviously very disciplined on our projects and how we approve them and get them to FIDs. We're going to continue to focus on that likewise. And then we're going to look at the, of course, the distribution growth also that we put out there, 3% to 5%, which is the equity side of the equation. Based upon the CapEx spend and what we're seeing out there, remember we're always looking at this long term. We're not just looking at numbers that we're reporting for the quarter. But where we will continue to evaluate is of course unit buybacks, along with the distribution growth. So let's see how everything continues to play out. We couldn't agree with you more there; a lot of free cash flow is when you do the math on the guidance we've given out there. And with the other capital allocation topics that we've talked about here. So very good question. Thank you.

Got it. So buybacks are not off the table at this point. Is this how to think about it?

Oh, no, that's exactly right. Absolutely. They definitely are on the table.

Our next question comes from Jean Ann Salisbury with Bernstein.

Hi. Would it be possible to get a dash more detail on the projects in the CapEx budget for this year? I think I'm good on the NGL export projects. But could you talk a little more about the new NGL pumping capacity that you described, the processing plants, like how many and where? Apologies, if I missed it during the prepared remarks.

Hey, Jean, this is Mackie. I think I can cover that question. If you're looking at, if you're talking about our upgrade on some of our 200, 000 day cryos out in West Texas into the Delaware, we can very optimally and at a low cost compared to adding a new processing plant at 20, 000 to 40, 000 UCF per cryo. So we are looking at that. We can move quicker on that. It's just adding compression in some cases, treating, or dehas. We also have already done that in the Eagle Ford. We've already added about 50, 000 or 60, 000 a day at very low cost. And then if you're on some of the other CapEx, if you're looking at our expansion at Nederland, we're looking at the ability, as Tom said, in his opening remarks, of doubling our propane capacity and increasing our butane capacity by 33%. So even though the market's going to be really tight for the next 18 months, we have a tremendous amount of capability of increasing our export volumes starting about mid-2025. And not only are we excited about that, but the international market is very excited about that. And a lot of that that we've already, that we're in the process of expanding has already been sold out for three to five years once those projects come online. So we're doing the best we can to improve or have within our capital and meet the needs of our customers and obligations that we have.

Great, thank you for that. And as a follow-up, I believe that some of the original DAPL contracts roll this year. Can you discuss if you're blending and extending those or anything you can share about that re-contracting process?

You bet. This is Mackie again. As you can imagine, that's a very sensitive question from the standpoint of competition. But as far as when contracts fall off and kind of what our approach is, I will answer it this way. We are very confident that we will keep our pipeline full and increase the volumes through time, certainly if the volumes grow in the Bakken. For the best outlet out of there, we can, at the best cost, we can feed all the refineries, or many of the refineries in the Midwest. We come down to the Gulf Coast, of course, and feed all the refineries in the Port Arthur area. Through our Bayou Bridge Pipeline, we can move volumes all the way to St. James. So there's no other pipeline that's even close, no other options than ours; we feel really good about as contracts roll off, we'll do very well on re-contracting or selling on a spot basis.

Our next question comes from Steve Stanley with Wolfe Research.

Hi, it's Keith. First question, you made some progress on repaying some of the preferred equity and you mentioned another series to take out in May. How are you viewing the preferred stock right now over the next few years and how do you kind of weigh using excess cash to repay that versus other uses?

Yes, listen, we're actually very excited at the fact that we're able to start bringing some of that back in as far as the perpetual preferreds. I think you're going to see us continue to look at those and as we look at even cash flow and where our cost of that is, it makes a lot of sense for us to continue to bring those back in. So I think that's how you'll see us kind of prioritize when you look at our deck, told you that, you'll see us working on those first going forward. It's probably worth mentioning that even with the Crestwood acquisition, as you know, we had some more come in with that. We're going to continue to be opportunistic on those. When they make economic sense, we will look at calling those, but we always are very diligent in looking at the math on those, and as soon as they make economic sense, we will jump.

Great, thanks. Second question, one of your peers recently said they think one to two new Permian gas takeaway projects move forward this year. I might have missed it, but I don't think you mentioned Warrior today. So my question is, do you agree with the view that one to two pipelines probably move forward and any updates on Warrior and how optimistic you are on moving that forward kind of with or without Lake Charles?

Yes, this is Mackie. I'll answer that. I guess an update on Warrior is we love to say we're at FID; we're sold out for 10 years, demand charge, and ready to go, but that's not where we're at. We have sold about 25% of our goal. We're in negotiations with about 1.6, 1.7 BCF of additional customers. All of them are looking for, or a lot of them are looking for different places to take the gas. There's no project that's even contemplated that's anywhere close to Warrior where it provides access to almost every major city gate in the state of Texas. It goes to all the major hubs, Carthage, KD, et cetera. It also goes to a lot of the power plants either directly or indirectly; we're connected to the majority of power plants. So it's by far the best project that's out there. With the pause from the DOE, there is a customer that was looking at that. That's going to pause a little bit. However, we continue to push forward. We're not saying that FID is imminent. We do think there will be another pipeline needed in the next two and a half years, and if that were to happen, we do believe it will be ours.

Our next question comes from Brian Reynolds with UBS.

Good afternoon, everyone. Maybe to follow up on some of the guidance on the EBITDA side relative to the S4 guide. I assume if you could just talk about maybe some of the differences between today's guidance and the S4. I assume a lot of it's related to some underlying growth CapEx assumptions that were in the S4, along with maybe some marketing that was included there. So it would be great if you could just provide us an update on and maybe your expectations for marketing, which I believe you need to typically exclude from the guide. Thanks.

Yes, I'll start here, and if Mackie wants to add anything, he can. The main factor contributing to the difference from the S4 is the commodity prices. When we compare it to what we used when that was filed, our commodity prices are now significantly lower. Additionally, deferring some capital expenditures is another factor influencing the difference between the S4 and our current position. Those are likely the two biggest reasons.

Great, makes sense. And as a follow-up, just touching on M&A, Sonoco made a large acquisition over the past month. So kind of just curious from an ET value perspective, are there other opportunities to optimize ET system with additional access to different types of assets, whether it's crude, NGLs, or refined products? Thanks.

Obviously, a great acquisition by Sonoco. It's a very, very good fit for them. And I will say there's not been discussion about Sonoco; this was a Sonoco transaction and they are doing a great job of proceeding through getting all the approvals and even moving a little bit into the integrations. But I wouldn't say there's been any discussions on that.

Our next question comes from Jackie with Goldman Sachs.

Hi. Good afternoon. First, I just want to start off on exports. It looks like for NGL exports continue to be strong, though slightly down a little bit quarter-over-quarter. How do you view exports going into ‘24? And do you see any upward pressure on margins as that dock capacity remains tight until you see those expansions online in mid-25?

Yes. Jackie, this is Mackie. What a great business we have with our export at Nederland and at Marcus. We're very excited about what we've built and what we're building out. However, there are a lot of issues that are involved, especially with shipping. And so there's issues with the Panama Canal or through the Red Sea, the timing of ships. Some months we may see direct basis and some months less. So every month, every quarter kind of have its ups and downs. But overall, we see our steady where we've been and our slight growth pretty much completely fill up our entire export capacity in the short term. Over the next 18 months, we believe we're going to see some very, very good margins for that business. For the spot business that we have available today, there's a significant overload in the international market compared to what the U.S. is capable of exporting, and we are positioned very well in the next 18 months to capture that upside. And then, as I mentioned earlier, we're very excited about bringing old projects that will bring in significant revenue for our export business.

Got it. Great. Thanks. It makes sense. And then, just as a follow-up, we saw some partial contributions from the Crestwood acquisition this quarter. Wondering if you would be able to quantify what synergies you were able to capture for the remainder of ‘23, and if you see any additional opportunities at this point beyond that $80 million annual cost synergies disclosed and the potential timing of when you expect to see that downstream gain from the acquisition.

Yes. After you get a chance to start going through all the various costs in an organization, we always try to be fairly conservative. We're doing it with what information we have at the time, meaning public information. But after you get really further into these things and start looking at organizations, et cetera, I think you'll find that a lot of times you're always hopeful that you can't find more. So the $80 million run rate that we've talked about from a call standpoint is something that we feel very comfortable with and putting that number out there. And, of course, $65 million is what we put out for 2025. But when you start looking across its systems and all the other type of costs that are buried sometimes that, once again, you can't see when you're in the middle of these things or early in the process of them, it's always good to be able to find those, and I want to make sure we stop for a moment and give a huge compliment to our team, who I know we've said before, no one is better out there at integrating these companies than we are. We've had a lot of experience at it, and we move quickly, efficiently, and effectively as we go through it. But as mentioned in the prepared remarks up front, we've remained on multiple fronts very excited about some of the commercial opportunities. I don't know, Mackie, you want to add anything more to that, what we said?

Other than what you've done in the opening script, we're still digging in. Every acquisition that we do, we discover more and more under the rocks that we turn over to elaborate a little bit more on his opening remarks. We are seeing significant logistics and maybe even deferred on some costs, fully utilizing all of the assets when combined with the new Crestwood assets in the Delaware Basin. There are also some things we can do in the DJ Basin that we're looking at. Up in the Bakken, a lot of those barrels haven't found their way to our pipeline. We think now they will. So we think that will also bring more business to our total pipeline out of North Dakota and then the Northeast. We see some or starting to see some real commercial advantages to working together with that team and doing two things. One, helping that business grow distribution with propane and butane that Crestwood built. And then on the other side where they can bring in volumes with their contracts and with their relationship into our Mariner franchise for deliveries to Marcus Hook. So as Tom said, we're just getting started but pretty excited about the things that we're already seeing.

Our next question comes from Michael Blum with Wells Fargo.

Thanks, good afternoon, everyone. So I know you have a growth CapEx target of $2 billion to $3 billion but you also discussed quite a few potential projects in your prepared remarks today, some of which could be quite large. So I'm wondering if that $3 billion is hard cap or would you consider going above that range if the returns make sense?

Yes, listen, I'll start and then you go with Mackie. No, there's not a hard cap as we look at these. Once again, we'll evaluate projects that make economic sense, and when we pull it all together, as recently gave the range of the 2.4 to 2.6 and keep in mind that that did include $300 million of rollover from 2023. That didn't make it into service at the time, so those got rolled into 2024. So make sure you bake that in there. But is there any more details on that with Michael, as far as your question here?

No, that covers it. I appreciate it. Maybe my second question, I just wanted to ask, obviously, you were very active in 2023 on the M&A front. So I wanted to just get your thoughts on what the landscape looks like in 2024 for you, and are you still kind of in digestion mode, or are you kind of ready to roll with the next deal present itself? Thanks.

Ready to roll. Michael, no, that is a good question. I think we've been saying for some time we've been very consistent on our M&A discussions with everyone that we felt like it made a lot of sense in the midstream space, and you're seeing it. You're seeing it now. And we're going to continue to evaluate opportunities, but the other thing that's worth highlighting here is that we are staying very disciplined with these acquisitions to even doing someone with no premium, just doing it at the market. And you can see the results. They're accretive, they're deleveraging, and it's the reason why we've ended up with the continued growth in our distributions at the same time that our balance sheet is strengthening, and it's showing in our ratings, etc. So it's one of those where it makes sense and where it's FID. And remember, as large as we are, there's a lot on the FID side. So we'll continue to evaluate and we'll continue to look at opportunities.

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

Well, once again, I want to express a lot of appreciation to all of you for joining us today. We always thank you for a lot of really good questions, good dialogue, and as you can see, we've got a lot of really good things to talk about. And therefore, we look forward to continuing dialogue even after this call with anyone. So thank you, everyone. You all have a great day.

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.