Hello, and welcome to the Energy Transfer Q1 2023 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note today's event is being recorded. And now, I'd like to turn the conference over to your host today, Tom Long. Sir, please go ahead.

Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer first 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 quarter ended March 31, 2023, which we expect to file this Thursday, May 4. 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 measures on our website. I'd like to start today by going over our financial results. We were pleased with our results for the first quarter of 2023, during which we generated adjusted EBITDA of $3.43 billion, which was up from $3.34 billion for the first quarter of 2022. Results for the first quarter benefited from record volumes across our interstate and midstream segments, as well as through our NGL pipelines and NGL and refined products terminals, which included a record amount of LPGs exported out of our Nederland terminal and a record amount of ethane exported out of both Netherlands and Marcus Hook terminals during the quarter. DCF attributable to the partners of Energy Transfer, as adjusted, was $2.01 billion compared to $2.08 billion for the first quarter of 2022. This resulted in excess cash flow after distributions of $1.04 billion. On an incurred basis, we had excess DCF of $640 million after distributions of $967 million and growth capital of $407 million. On April 26, we announced a quarterly cash distribution of $0.3075 per common unit or $1.23 on an annualized basis. This distribution represents an increase from $0.3050 per common unit paid for the fourth quarter of 2022. Although we cannot guarantee future performance, we expect to make ongoing quarterly increases to our common unit distribution of a $0.0025 on a quarterly basis or $0.01 on an annualized basis and we are now targeting 3% to 5% annual distribution growth rate. This targeted growth rate allows us to provide some clarity to our equity holders on future distributions. We continue to balance our leverage reduction and increasing equity returns, all while maintaining sufficient cash flow to invest in our incredible backlog of growth opportunities. Inclusive of the targeted distribution growth rate, we still expect to be at the lower end of our 4 times to 4.5 times leverage ratio target range going forward based on our calculation of the rating agencies' leverage ratios. As of March 31, 2023, the total available liquidity under our revolving credit facility was approximately $3.01 billion. Now turning to results by segment for the first quarter, I'll start with NGL and refined products. Adjusted EBITDA was $939 million compared to $700 million for the same period last year. This change was primarily due to higher margins from transportation, fractionation, storage and terminal services, as well as an increase in northeast blending and optimization. Also included in the increase was approximately $50 million from the recognition of gains on hedged NGL inventory, which is primarily related to the physical loss recorded in the third quarter of last year. NGL transportation volumes on our wholly owned and joint venture pipelines increased 13% to a record 2 million barrels per day compared to 1.8 million barrels per day for the same period last year. This increase was primarily due to higher volumes from the Permian region and our Mariner East Pipeline System, as well as on our NGL pipelines that deliver into our Nederland Terminal. Average fractionated volumes increased 18% to an average 949,000 barrels per day compared to 804,000 barrels per day for the first quarter of 2022. NGL export volumes grew more than 20% over the first quarter of 2022, driven by record ethane and LPG exports out of our Nederland Terminal as well as record ethane exports out of the Marcus Hook Terminal. This was primarily driven by the second tranche of satellite's contract going into effect on July 1, as well as increased international demand for natural gas liquids. In the first quarter, we loaded more than 14 million barrels of ethane out of Nederland. In total, we continue to export more NGL than any other company or country with our percentage of worldwide NGL exports remaining at approximately 20% of the global market. For midstream, adjusted EBITDA was $641 million compared to $807 million for the first quarter 2022. This was primarily due to the lower natural gas and NGL prices, as well as increased operating expenses, which were partially offset by increased throughput in all of our operating regions. In addition, the first quarter of 2023 included a onetime positive adjustment of approximately $40 million. Gathered gas volumes increased 14% to a record 19.8 million MMBtus per day compared to 17.3 million MMBtus per day for the same period last year. For the crude oil segment, adjusted EBITDA was $526 million compared to $593 million for the same period last year. This was primarily due to lower volumes on the Bakken Pipeline and lower optimization gains compared to the first quarter of 2022. The reduction in optimization was entirely attributable to the timing differences between physical and financial settlements. We expect to recognize $25 million gain in the second quarter related to this activity. In addition, the first quarter of 2023 included a onetime negative adjustment of approximately $35 million. These were partially offset by higher throughput on several of our pipeline systems and higher export demand. Crude oil transportation volumes were 4.24 million barrels per day compared to 4.22 million barrel per day for the same period last year. This was a result of higher volumes on our Texas pipeline systems and the Bayou Bridge pipeline, as well as placing the Ted Collins Link pipeline into service in the second quarter of 2022, which were offset by lower volumes on the Bakken Pipeline as a result of weather-related production impacts. In the Interstate segment, adjusted EBITDA was $536 million compared to $453 million for the first quarter of 2022. This was due to increased transportation revenue related to higher contracted volumes and rates on several of our wholly owned and joint venture pipelines, as well as placing the Gulf Run Pipeline into service in December of 2022. Volumes increased 11% 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, Pebble, Trunkline, MEP and SESH. And for our Intrastate segment, adjusted EBITDA was $409 million compared to $444 million in the first quarter of last year. This was due to lower pipeline optimization opportunities and decreased retained fuel revenues related to lower natural gas prices, which were partially offset by increased storage optimization opportunities and higher fees on assets in the Haynesville and Oklahoma. Utilization on our EOIT, HPL and Rig Systems increased due to higher demand from gas takeaway from growing production in a number of our operating basins. Looking briefly at recent developments, we are excited about the closing of our acquisition of Lotus Midstream for approximately $900 million in cash and 44.5 million Energy Transfer common units. Lotus owns and operates [Centurion] (ph) Pipeline, a fully integrated crude pipeline terminal system in the Permian Basin. This acquisition will enhance Energy Transfer's crude pipeline footprint across the Permian Basin with the addition of approximately 3,000 miles of crude gathering and transportation lines that extend from Southeast Mexico to Cushing, Oklahoma. In addition, the assets provide direct access to other major hubs including Midland, Colorado City, Wink and Crane, and will increase our storage capacity at Midland by approximately 2 million barrels per day. Now turning to our growth projects. I'll start with an update on our Lake Charles LNG project. In May 2022, we received an extension from FERC of the deadline for completion of the construction of Lake Charles LNG facility to December of 2028. And in June 2022, we applied to the Department of Energy. As many are now aware, on April 25, the Department of Energy denied our request for this extension. We strongly disagree with this decision and we plan to file an appeal with the DOE within 30 days of the DOE decision. Now turning to Nederland and Marcus Hook export terminals. NGL demand both in the U.S. as well as from international customers continues to increase. We are bullish that there will be significant growth in the international demand for many years to come and we are well positioned to benefit from that demand. In order to address this growth, we have recently FID and expansion to our NGL export capacity at Nederland which we expect to add up to 250,000 barrels per day of export capacity. This expansion which is projected to cost approximately $1.25 billion will give us tremendous flexibility to load different products as well as new products based upon customer demand and market dynamics at the time. The expansion is expected to be in service in mid-2025. We look forward to providing more specifics on this expansion in the near future. We also continue to pursue an optimization project at our Marcus Hook Terminal would add incremental ethane refrigeration and storage capacity. Next at Mont Belvieu, fractionation throughput averaged over 1 million barrels per day for the month of April, which is a new monthly record. And we continue to expect frac eight to be in service in the third quarter of 2023. This addition will bring our total Mont Belvieu fractionation capacity to approximately $1.15 million barrels per day. And in the Delaware Basin, we placed our 200 million cubic foot per day Grey Wolf processing plant into service in December of 2022. As a reminder, this plant is supported by new commitments and growth from existing customer contracts. And construction continues on the Bear plant, our eighth 200 million cubic foot per day processing plant in the Delaware Basin. This plant remains on schedule to be in service in the second quarter of 2023. In addition, we continue to evaluate the necessity and potential time of adding another processing plant in the Permian Basin. Regarding Permian takeaway, we also completed modernization and debottlenecking work on our Oasis pipeline during the first quarter, which added at least an incremental 60,000 Mcf per day of takeaway capacity out of the Permian Basin. We also placed the Gulf Run pipeline into service in December of 2022. Gulf Run provides natural gas transportation between our upstream pipeline network and from the Haynesville, Shell for delivery to the Gulf Coast connecting some of the most prolific natural gas producing regions in the U.S. with the LNG export market, as well as many markets along the Gulf Coast. We were already utilizing a significant portion of Zone 1 capacity on Gulf Run and we have added additional customer commitments through Zone 2, which is being delivered into our trunk line pipeline. In addition to these ongoing projects, we continue to evaluate a number of other potential growth projects that over the long term could provide strong returns and significant upside to our business. We remain optimistic that we can bring these projects to FID and will share any significant updates on these potential projects at the appropriate time. One the Alternative Energy front, we continue to make progress on our carbon capture and storage project with CapturePoint that is related to our north Louisiana treating plants. A Class 6 permit for this sequestration site was filed by CapturePoint with the EPA in June of 2022. Also we recently executed a letter of intent with Oxy related to Oxy's Magnolia hub in Allen Parish, Louisiana, north of the Lake Charles Industrial Complex. Pursuant to the letter of intent, Energy Transfer and Oxy are working together to obtain long term commitments of CO2 from industrial customers in the Lake Charles, Louisiana area. If this project reaches FID, Energy Transfer would construct a CO2 pipeline to connect the customers in Oxy's sequestration site in Allan Parish, Louisiana. Now looking at our growth capital project for the first quarter ended March 31, 2023, Energy Transfer spent $407 million on organic growth projects, primarily in the midstream and NGL and Refined Products segment, excluding SUN and USA Compression CapEx. For full year 2023, we now expect growth capital expenditures to be approximately $2 billion, which will be spent primarily in the midstream, NGL and refined products and Interstate segments. This capital outlook has been updated to include the NGL export expansion project at Nederland, as well as the expenditures related to the Lotus acquisition. A significant amount of our 2023 growth capital spend is comprised of projects that are expected to be online and contributing cash flow before the end of 2023 at very attractive returns, including frac 8, the Bear processing plant and new treating capacity in the Haynesville. Now for our adjusted EBITDA guidance, we are updating our guidance to include EBITDA associated with the Lotus acquisition. As a result, we now expect our 2023 adjusted EBITDA to be between $13.05 billion and $13.45 billion. As a reminder, with the current forward curve for commodity prices and spreads, our guidance does not assume the same upside benefits from pricing and spreads that we experienced in 2022. Our base business continues to provide stable cash flows and demonstrates our ability to operate through various market cycles and we expect utilization in all of our core segments to increase. In addition, we continue to create opportunities for optimization and expansion driven by sustained domestic and international demand for our products and services. We remain bullish about the future of our industry and the growing worldwide demand for all of our products. As part of our capital allocation strategy, we will continue to look for new ways to address this demand through the pursuit of strategic growth projects that enhance our existing asset base and generate attractive returns. In addition, we will continue to place emphasis on strategically allocating cash flow in a manner that balances our targeted 3% to 5% annual distribution growth rate and our commitment to our 4 times to 4.5 times leverage target, all while maintaining significant free cash flow for growth. This concludes our prepared remarks. Operator, please open the line-up for our first question.

Yes, thank you. At this time, we will begin the question-and-answer session. [Operator Instructions] And the first question comes from Michael Blum with Wells Fargo.

Hey, good afternoon. Thanks, everyone. I'm wondering if you can break down how much of the EBITDA guidance, the increase of $150 million. Is that due to Lotus versus just better performance in the base business?

Yeah. Michael, this is Tom. Majority of it clearly was the Lotus acquisition, but I will say with strong performance you saw in the first quarter, we were able to bump that up a little bit, but it's a smallest piece of the bump. So it's great to be able to continue to increase it and obviously very excited about the contribution of Lotus as we got that one closed in fairly short over. So…

Great. And then just want to get a little more insight into the change in distribution policy. It seems like last quarter or certainly last few quarters you were thinking more once a year and now you're going to this quarterly distribution? And then can you talk a little bit about what would drive the range from between 3% and 5%? Thanks.

Yes, Michael, we clearly have very good discussions with our directors every quarter and you can hopefully translate from this the strength of our business and the ability to be able to continue to grow our distributions. And when we looked at it and had the discussion on it, we decided that we would just continue to bump on a quarterly basis. And the 3% to 5%, when you really kind of look out forecast, we all wish we had the perfect crystal ball. But we thought that was a good sustainable target to put in. But keep in mind, we will always continue to evaluate this distribution level on a quarterly basis. So maybe you'll be asking this question again as we get into the next quarter. But after good dialogue, I will say that it's great to be here and great to be in the position that we can see leverage coming down and all these growth opportunities in funding them at the same time to be able to grow distribution. So it's a great place to be.

Great. Thank you.

Thank you. And the next question comes from Brian Reynolds with UBS.

Hi, good morning, everyone. Maybe as a follow-up to the guidance question, but maybe a focus on spread opportunities. On the last call, you kind of highlighted $400 million to $600 million of spread opportunities across the business. But now with the Lotus acquisition, you have a new market with future opportunities in the future. So kind of curious if you can just update us on just kind of base business spread opportunities for the balance of the year, particularly on the crude side? Thanks.

Yes. This is Mackie. When you say spread opportunities, they're numerous depending on exactly what you're talking about.

I guess, just focus on the base business with nat gas opportunities and then in relation to Lotus as well just given new market opportunities?

Okay. So around nat gas, there is another pipeline being built prior to that. We expect and anticipate the spreads across Texas to widen significantly. They really haven't yet even with Freeport coming back online. However, look at the growth out there, I think we hit 17.6 Bcf. So the growth just continues and we do expect those spreads to widen at least over the next year and a half till next pipeline project comes online. And then around the crude spreads, it's overbuilt -- the industry has overbuilt it. It's going to be that way for a little ways. But Lotus is such a great acquisition for us. We -- Chris Hefty and his team continue to create deals on -- with Enable and with [WEX and then with this project, we're so excited we can buy them to kind of multiples, we're buying and bringing all those barrels into our system will not help the spread, but certainly will help our revenue if we continue to keep our pipelines full across Texas.

And there's one thing to highlight, if you look at the slides that we posted out there, you noticed, we update the piece of the total pie on the sensitivities. It used to be 0% to 2.5% related to the spreads. We did take that up a little bit to 0% to 5%. So we have increased that a little bit. Not material when you compare it to the size of Energy Transfer, but it still is something that we did take up a little bit.

Great. I appreciate the incremental color. Maybe to just touch on growth CapEx. It seems like most of the raise is due to Lotus and then the Nederland NGL expansion announcement. Just given just recent peer announcements with the focus on exports, and just the opportunity set for Energy Transfer at both Marcus Hook and Nederland. Just kind of curious of how we should think about future projects, could Nederland be upsized or how are you thinking about Marcus Hook opportunities as well? Thanks.

Yes, this is Mackie again. Could it be upsized? It's being upsized. And it needs to be upsized quicker than we can do it. The global demand for ethane and propane and butane is incredible. If you look at the PH (ph) facilities that are being built around the world over the next 12 to 18 months and also the growing demand for ethane, we are probably one of the most bullish companies in the industry where we think NGL process and demand will go over the next three years to five years, if not longer. So we have the tremendous capability both at Nederland and at Marcus Hook in expanding this expansion that we've talked about today. We're very excited about, we pretty much maxed out what we can do right now with our facilities. We’re moving as quickly as we can to get these built. They should be service by the middle of 2025. We've already secured a number of contracts -- long-term contracts and we have an enormous base load of customers that we're negotiating with and very excited about that. And as we've always advertised, we're the only company that can export both in the Gulf Coast and also Middle East. And so ultimately, we also anticipate that we will be expanding at Marcus Hook, our ethane capabilities -- exporting more ethane. And so, we have set this up in such a way that we can source ethane out of Nederland. And once we are able to secure enough ethane in the Northeast, we can move those customers up to our Marcus Hook facility and then reload new customers into Nederland. So we feel very blessed, I guess, for having these assets and our ability to meet the world demand for these growing products.

Great. I appreciate all the color. I'll leave it there. Enjoy rest of your afternoon. Thanks.

Thank you. And next question comes from Jean Ann Salisbury with Bernstein.

Hi. Putting aside the denial of the Lake Charles' extension, I just wanted to get an update on the contracting and EPC environment, it sounds extremely competitive out there?

Yes, we anticipated a question around LNG. So I'm going to make a little broader statement than your question, if you don't mind, and that may help on some potential other questions. People have asked us how do we feel? What's our thoughts and what happened 10 days ago? And a lot of adjective and things that we said, I can't say on this call, but I can't say things like upset and frustrated and shocked and surprise. But at the end of the day, it was just wrong. It was wrong and it was political. And what also was wrong is what's happened over in Europe and really in the U.S. And that really came to fruition here this past year when Russia attacked Ukraine and everybody now is not denying the need for natural gas, not for five to 10 years, but for 25, 30, 40 years. And everybody knows that and thank goodness for a warm winter [indiscernible] catastrophic both economically and from a human standpoint. So we jumped to Lake Charles, we've been working on Lake Charles for a number of years. We've spent over $200 million. We have worked our tails off to try to get this project online. Then the pandemic hit, that slowed us down significantly. And then, of course, as I just mentioned Russia attacked Ukraine. It flipped to $180 million and all of a sudden everybody woke up and the demand has increased astronomically. And we beefed up our team. We began traveling throughout the world throughout Asia and Europe. We've done that consistently over the last year. We immediately asked for an extension from FERC. They gave us that extension, May of last year. We then asked the DOE in June of last year for an extension. We are in negotiations to your question as we speak with over 20 million tons of additional customers on top of what we've already signed up. We have significant equity players that we're in negotiations with. And for months, we've been given every indication that the DOE would approve our extension. And then low and behold, here recently, they've come out and said that because of a new policy, they are not going to extend our request. And they've cited the lack of progress. So here's the DOE citing the lack of progress. They have not asked us onetime over the last year how we progress it. They don't know if we're out there right now of building facilities. We already have four tanks built. We already have a dock built. It's a brownfield unlike some of our competitors. And so it needless to say a little frustrated. Additionally, we've had one customer come to us after we heard that 10 days ago and said they'll go another direction at least for now. And we think it's extremely important to reverse this decision as quickly as possible so it doesn't harm us more than it already has. And so, we will be asking as Tom mentioned earlier, we will be asking for rehearing and we're hoping that reasonable and rational minds at the DOE will prevail and they'll reverse what was an arbitrary and capricious political decision.

Okay. Yes, you really have put a lot of work into it over the last year and before that as well. So thank you for that. Just with a follow-up on something else. Energy Transfer has not been shy about your belief that the sector needs more integration. Can you speak to how you evaluate these opportunities? Looking at Lotus and Enable, is it fair to say that upstream flow into your is kind of a major filter of what you would be looking for?

Absolutely. We do evaluate a lot of the various opportunities that are good bolt-ons if you will to our system. But even if you look at some of the last ones, as you know, the Enable, the Lotus, the Woodford Express. When you really look at these, they all just further enhance our top asset base of the midstream space. And it's something we're going to continue to pursue on those opportunities that make sense but here's the next piece that we always evaluate very carefully and that is that it's accretive. We always want to look at these things and make sure they're going to bring incremental value to our equity holders. And they have, they've all been very accretive to us. And we're always very conservative in how we run our numbers. So we feel like that every acquisition we've made has exceeded any forecast that we put on there. So that's how you -- we've been able to continue to get the coverage up, get the distributions back up to where they are, while at the same time, the leverage coming down. So we're going to continue to follow that model as we look, meaning looking at the various areas that are good bolt-ons for us. And the more tools we can give the fantastic team we have, the better off we're going to be for the long term.

Great. That's all for me. Thanks.

Thank you. And the next question comes from Keith Stanley of Wolfe Research.

Hi, thank you. Quick follow-up on the guidance, so just the math behind it. So the Q1 obviously had a really strong quarter. If you annualize that, you're at $137 billion of EBITDA and the updated guide is $13.25 billion at the midpoint. So I know Tom you listed some of the inventory swings and things like that, but are there any other unique items in Q1 you just outperformed on spread, marketing type items that you're assuming don't repeat over the balance of the year or how should we think about that updated guidance?

Yes, that's actually a very good question. Keith, glad you asked it. When you really kind of look at our earnings by quarter throughout the year. The first quarter is generally the strongest. I think you can go back and look at that. And so, when we forecast out at the remainder of the year, we will generally bake in what we see from -- everything from a volume, pricing, et cetera. So what you're looking at once again is that first quarter and that's not the way that it plays out as far as just annualizing that first quarter. And it's going to be a lot of the things you mentioned in there, whether it be some of the spreads we see, pricing, et cetera. So if you just take the forward curve on the pricing and you look at it, I think you'll kind of see what -- how we look at it when we look at the forecast going up a year. But once again, this is guidance. It's our numbers that we're currently seeing and currently targeting. And as you know, those can move around. But as of right now, we feel good about it every quarter when we come out with updated guidance, we feel good about the numbers that we're providing.

Great. That's helpful. Second question just on the leverage target, the 4% to 4.5%. Some of your peers have moved lower over time. And Tom, when you talk, you still talk to reducing leverage. So do you see the company ever aspiring to go below 4 times eventually or is the goal to get the BBB flat credit rating and less of a focus on a number?

Yeah. Our goal is to get to that BBB flat. If it goes below four, we're okay with that. We won't be upset with that, but I will tell you that's still the target. But here's where I'd like to expand on that a bit. Not all these leverage metrics when they come out of the same. As you know, leverage is only one metric. You have to also look at the makeup of the earnings stream, you have to look at the scale of the company and the size. And when you start looking through all those various components like what a rating agency uses, we clearly are strong in all those areas. So our leverage metric, when we put it out, we think it's what fits for us. We think that BBB is a good place to be and that's what we're going to continue to target.

Thank you.

Thank you. And the next question comes from Jeremy Tonet with J.P. Morgan.

Hi. Good afternoon.

Good afternoon. Jeremy.

I just want to pick up with Permian egress on the natural gas side if I could. And I want to see the latest thoughts on Warrior and outlook for that project and how you see I guess Waha spreads ebbing and flowing, we've seen volatility there and it seems like takeaway tightness could be back again. So just wondering what thoughts you could provide us on the basin as a whole and the outlook for Warrior at this point?

Jeremy this is Mackie again. Yes, Warrior, we made announcements on the last earnings call that we signed about 25% to 30% of our target, we're still at that level. However, we are in negotiations with over 2 Bcf of additional interest. This is primarily interest on market pull along the Gulf Coast and in the southeast and other parts of South Texas. As I think most know on this call, there's other projects that are being built and other projects being looked at, but nothing compares to our project. We don't have to lay as much pipe to provide the services that others are trying to provide. Our 42 inches pipe would be built if that's where it ends up getting to an FID would be able to [TFW] (ph) and it would enter into our significant Intrastate system that would feed a Katie [indiscernible] and ultimately into our Louisiana interstates to get to the Gulf Coast. So we have -- because the other project is being built, people aren't quite as panicked. Also we're not seeing the blowout we thought we would see by now across Texas. It's been kind of as you said ebb and flow between $0.40 and $0.80. We do think that's going to blow out and we were firm believers that in the next 2.5 to 3 years there's been a significant need for more capacity and we do believe that will be our pipeline. So our team is diligently working on that. It's going to be one of those projects we have sufficient commitments from great customers that give us a guaranteed rates of return and at that time we'll announce it, but we're still very excited and working hard to get to the finish line.

Got it. That is helpful there. And I was just wondering if you could touch a little bit more on Lotus and what those assets mean in your hands as opposed to a standalone and what ET's balance sheet could bring to bear as far as marketing or other opportunities with those assets?

It'd probably be a better question for the guys that report or to me on -- in late, report to me on the crude side, we are so excited. Those assets adds, we believe, so much value it does a lot of things for us. One, we've always wanted to be able to get to Cushing. All we have to do is ride 30 miles and we can move fairly significant volumes to Cushion when those blow out or when our customers want to go that direction. We'll have access to Wink, which is a growing area hub for oil that we don't have access to date, which benefits us in many ways. We also have access to Crane, which is kind of one of the main receipt points for the pipelines heading to Corpus. There's a lot of opportunity to blend and create value there off our system and there will be. And then we also have the ability to move more barrels over to our Colorado City area where we have significant takeaway to our Permian Express systems. In addition to that, there's numerous blending opportunities at Midland, we're adding several million barrels more of storage. So it's hard to kind of, I guess, relate how excited we are and the multiple that we paid for those we think will improve on significantly within a year or two and look forward seeing all those barrels enter our system and also help support our cross sell capacity opportunities.

Got it. That's very helpful. I'll leave it there. Thanks.

Thank you. And the next question comes from Chase Mulvehill with Bank of America.

Hey, good afternoon. I guess if we could talk about the NGL and Refined Products segment, for the second quarter in a row, you generated more than $900 million of EBITDA for this segment. And I realize that there's a lot of marketing and optimization benefits that are included in the results over the last couple of quarters. I don't know if you could kind of hold our hand a little bit and bridge kind of 1Q and 2Q kind of how you're thinking about puts and takes for 2Q? And then obviously in the back half, you got frac 8 coming online. But just trying to understand kind of how we should think about this segment in 2Q and through the back half of the year?

Yes. How to -- encourage you to think about it is excited. We -- as we stated earlier, we've set some records in our NGL business. In fact, we were talking about before this call toward the end of April, we actually hit all-time daily records out of Midland for our NGL transport. We hit all-time U.S. NGL transport and we also hit a one day half for frac. So we're hitting records along our NGL systems and with the -- like as we mentioned, the growing demand we just couldn't be more excited about the assets that we have. As we mentioned in our statements earlier, we hit some records for ethane both at Nederland in the first quarter as well as Marcus Hook. And so we sit in such a great position in both areas. One, our [American] (ph) franchise is locked and loaded. I mean, we've got a tremendous capability that all we have to do is add pumps and can double our capacity up there as we can bring on more volumes upstream. We already have permits to expand our ethane capabilities up to 140,000 barrels a day and we'll continue to pursue that project and get that FID. And then of course, we have Nederland, which is such a gem for us in so many different ways, but certainly on the NGL perspective, it's ironic in kind of humorous inside our partnership. We kind of have a battle going on it Nederland between the usage of our docks between crude and NGL and likely NGL has been kicking the tail of crude and we'll continue to do that. And the benefits of that are, we're now starting to move a lot more of our barrels over to Houston. Those assets are starting to really pay off for us. We're hitting kind of record export levels for crude out of Houston. So that's been a good move to kind of ship those volumes. But anyway, we're so well positioned with our four pipelines moving ethane, propane, butane and natural gasoline from Mont Belvieu. And we're very excited about the expansion project that we've just got approved and look forward to getting that online in the next couple of years.

Okay, perfect. Unrelated follow-up on the midstream segment. EBITDA was basically flat sequentially despite lower natural gas prices. So I guess maybe two questions here related to that. Number one, have you mostly hit the fee floors on your natural gas side for your pops? And then number two, if today's lower NGL prices hold, how should we think about potential further downside for the midstream segment in kind of 2Q and 3Q?

Yes, downside on midstream, the way I describe that is, lower commodity prices. I mean certainly one of the biggest impacts quarter-to-quarter this year on our midstream business was lower commodity prices compared to where they were a year ago. It kind of hard to believe we'll see natural gas go lower than two. We remain pretty bullish on where oil prices are as well as NGL and the growing demand for NGL. So we remain very bullish. I didn't mention this a moment ago, but another record we also set three or four days ago is that we were now processing more gas in the Permian Basin than we've ever processed. So we are very optimistic about our volumes, about our spreads in the midstream. And so the only challenge to those are commodity prices and we feel like they've kind of bottomed out. We feel like with anything we're more optimistic on commodity price improvements as we go deeper into 2023 than what we've seen the first quarter.

Okay. Perfect. I'll turn it over. Thanks.

Thank you. And our next question comes from Gabe Moreen with Mizuho.

Hey, good afternoon everyone. Just sticking on gas prices a little bit. I'm curious whether $2 gas has had any impact in terms of producer outlook for supporting expansions in the Haynesville or the Marcellus at the moment? And particularly as it relates to Gulf Run and your potential to expand that pipe there?

Yes, you did hone in on probably the area where we are starting to see some rigs set down and also completions being delayed really both in Haynesville and also in Marcelles to a certain degree. So $2 dry gas prices is not great for those areas. In regards to how it impact, people are looking long term, producers aren't that and the price we're going to stay at $2 for the next four or five years. So discussions that we've had, the deals that we've done and deals that we're negotiating to extend, to expand our capacity to the Gulf Coast through our network of pipelines that are ongoing and that demand will increase. We are in a little bit of a low here. As we've been in the second quarter of 2023, we're probably possibly sat in that for the next quarter or so, but we'll come out of this and a lot of gas in North Louisiana and even more market growth along the Gulf Coast and in the Southeast. So love those assets. In fact, that kind of opens up one comment I want to make. We are now selling our space across North Louisiana on Tiger on MEP and then on [indiscernible] sashed all the way down to Florida. We're selling at tariff rates. And in some of this we're also selling at tariff rates that we think will be able to get up to 10 year contract. So it's funny. Hang on the pipe and it gets valuable sooner or later across all capacity, across Louisiana and all the way to Florida is becoming very bad.

Thanks, Mackie. And then maybe if I can also ask about the $2 billion growth CapEx figure now for 2023 to the extent that you're looking at additional stuff, would you characterize it as a good chance that other projects get FID in that $2 billion CapEx figure potentially goes higher for this year?

Yes. Gosh. I guess I'd be a little disappointed if we don't get some projects approved. How much of those dollars spend in 2023 remains to be seen. Of course, some of these bigger dollar projects that we're talking about, we don't anticipate any significant dollars contributing to capital needs in 2023, even if they get to FID in the next three to six months. But we've got a very aggressive team of commercial folks in all of segments and we're chasing deals everywhere. And so, we -- don't see anything overly material from the standpoint of huge capital needs, but we'll continue to have gathering needs and adding compression and things like that that will add of revenue for our assets.

Thanks, Mac.

Thank you. And the next question comes from Marc Solecitto with Barclays.

Hi, good afternoon. As we think about OpEx in the NGL segment and particularly on the frac side, can you just remind us how we should think about the impact from lower nat gas prices in that segment and how that flows through to your gas and utility costs?

Yes, it's kind of twofold. One, we are able to gain some upside on the energy that we keep based on the Houston [indiscernible] price versus what we charge for. So we're harmed a little bit there from the standpoint of revenue. However, with lower prices, we also benefit from the operation side of that. So we kind of have both sides of the cost there. But, yes, with the lower gas prices, we aren't benefiting as much on the excess energy that we keep compared to what we charge back to our customers.

Got it. That's helpful. And then maybe just to circle back on Lake Charles and not to put the carriers before the horse, but just to touch on the progress that you have made. Wondering if there's been any update on the EPC side?

As I think everybody knows, we're working with two different companies and we expect to get one of those [indiscernible] here soon and the next within next 10 or 12 days. And we are very pleased with what we're seeing and where we think the costs will come in, but we will be seeing some of those kind of final numbers in the very near future.

Got it. Appreciate the time.

Thank you. This concludes the question and answer session. I would like to turn the floor to Tom Long for any closing comments.

Well once again, we thank all of you for joining us today. As you can see, we're very excited about all the great stuff we have going on. So we look forward to talking with you soon and thank all of you for your support.

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