Hello and welcome to the Enterprise Products Partners LP Q3 2023 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. I would now like to hand the conference over to Randy Burkhalter, VP of Investor Relations. Sir, you may begin.

Thank you, Tawanda. Good morning everyone and welcome to the Enterprise Products conference call as we discuss our third quarter earnings. Our speakers today will be Co-Chief Executive Officers of Enterprise’s general partner, Jim Teague and Randy Fowler. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934 based on the beliefs of the company, as well as assumptions made by and information currently available to Enterprise’s management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. And so, with that, I will turn it over to you Jim.

Okay, thank you, Randy. This morning we reported solid results for the third quarter including adjusted EBITDA of $2.3 billion. We had 1.7 times coverage of our distributable cash flow and we retained $773 million. But we had challenges throughout the quarter. Record heat in August and September affected our processing plants throughput and refrigeration at our NGL export facilities and we experienced operational challenges at our PDH plants. We were also challenged by low natural gas and NGL prices, but despite these challenges, we handled record volumes across our midstream system, including our liquids pipelines, natural gas pipelines, NGL fractionators and our marine terminals. In total, our pipelines transported 12.2 million barrels per day of crude oil equivalent. In terms of hydrocarbon exports, we reported 2.1 million barrels a day and while most people focus on crude exports, we focused on hydrocarbon exports. We exported everything from ethylene to crude oil. I think both Randy and I are very optimistic that our teams can do even more with the assets we have. Among some of the highlights so far this year is an unbelievable growing appetite for ethane exports and of course we're expanding our export facility and this demand seems to come from all parts of the world. We're also continuing to see a growing appetite for LPG exports and we're having productive negotiations in anticipation of getting our SPOT license to construct permits soon. Our fundamentals group forecasts have been consistently accurate in the past. We have a lot of confidence in their future outlook. Therefore, this morning we announced an expansion of our NGL franchise. We're going to build two more 300 million cubic feet processing plants in the Permian, one in the Delaware and one in Midland. When completed, we'll have 19 processing trains in the Permian and 41 company-wide. Today, we also announced that we are converting our 210,000 barrel per day Seminole crude oil pipeline back to NGL service to support our needed Permian NGL takeaway. In addition, we announced our Bahia 30-inch NGL pipeline that will originate in the Permian and deliver up to 600,000 barrels a day of NGL into our storage system in Chambers County. The beauty of this Seminole pipeline is we can seamlessly switch service between crude, our NGLs are as an expansion of our new TW refined product system. Our focus on quality is extremely important to the entire producer community in order to ensure that Gulf Coast crude remains highly desirable in global markets. We've also improved the quality of our Eagle Ford crude oil systems. Not only has it made it easier to sell South Texas wheat, it's improved the price that we get for that crude. Whether it's creating new growth projects or improving the performance of the assets we have, our teams at Enterprise continue to deliver strong financial results and we are exceedingly proud of each and every one of them. With that, I'll turn it over to Randy.

Okay, thank you and good morning everyone. Starting with the income statement items, net income attributable to common unit holders for the third quarter of 2023 was $1.3 billion or $0.60 per common unit on a fully diluted basis, compared to $1.4 billion or $0.62 per common unit on a fully diluted basis for the third quarter of last year. Adjusted cash flow from operations, which is cash flow from operating activities before changes in working capital, was $2 billion for the third quarters of both 2023 and 2022. We declared a distribution of $0.50 per common unit for the third quarter of 2023, which is a 5.3% increase over the distribution declared for the third quarter of 2022. The distribution will be paid November 14 to common unitholders of record as of the close of business today. This year marks our 25th consecutive year of distribution growth. You could say you can treat that distribution as a treat today. Our dividend reinvestment plan and employee unit purchase plan purchased approximately 1.4 million common units on the open market for a total purchase price of approximately $37 million during the third quarter of 2023. Our utilization of the authorized $2 billion buyback program is unchanged at 41% with unit purchases for the first nine months of the year totaling approximately 3.6 million common units for a total purchase price of approximately $92 million. For the 12 months ending September 30, Enterprise paid out approximately $4.3 billion in distributions to limited partners. These distributions combined with $213 million in buybacks for the last 12 months result in Enterprise having a payout ratio of adjusted cash flow from operations of 56% and a payout ratio of adjusted free cash flow of 90% for that 12-month period. Our buyback activity has been admittedly lumpy over the last 18 months. EPD elected not to buy back equity in the third quarter. During the third quarter buyback window, our volume weighted average price was 98% of our 52-week unit price and we elected to be patient. We fully expect to be back in the market doing buybacks in the fourth quarter. We have established a track record of opportunistic buybacks over the last six years. We will continue to look for opportunistic windows to reduce unit count as we remain focused on improving our cash flow per unit metrics. We recently did a comparison of the six largest North American midstream energy companies, those with a market capitalization over $35 billion. Since 2019, EPD is one of only two companies to have actually reduced common unit/share count, and we are the only midstream company to reduce unit count over this time period without material asset sales. EPD reduced its common unit count by approximately 1% over this period, as did our peer. While this is a modest start, it is a consistent beginning of buybacks for six years in a row. We were also one of only three companies that grew distributable cash flow per unit by 15% or more. For this group of six midstream energy companies, EPD is the only company to have both reduced unit count and increased DCF per unit. We will include this peer comparison of DCF per unit growth, change in unit count and change in debt in our upcoming investor slide deck after our peers file their third quarter 10-Qs. We believe this will show EPD's balanced approach to increasing the value of the partnership for our limited partners over time. Total capital investments in the third quarter of this year were $826 million which included $722 million for growth projects and $99 million of sustaining capital. Capital investments for the first nine months of 2023 were $2.3 billion, which includes $2 billion organic growth capital projects and $284 million for sustaining capital expenditures. We expect our 2023 growth capital expenditures to total $3 billion. We expect 2023 sustaining capital expenditures will be approximately $400 million. As Jim mentioned earlier, this morning, we also announced $3.1 billion of organic growth projects to expand our core NGL franchise in the most prolific basin in North America. These projects will provide additional natural gas processing and NGL pipeline and fractionation capacity to support continued production growth out of the Permian Basin. These growth projects will also bring additional volumes to our downstream NGL storage, pipeline and marine terminal assets. In addition, facilitating Permian production growth also provides indirect business opportunities for our crude oil and natural gas businesses. With the addition of these four projects, we have $6.8 billion of major growth capital expenditures under construction. We are currently forecasting 2024 growth capital expenditures in the range of $3 billion to $3.5 billion. We do not expect this level of capital investment to impact our distribution growth or our buyback activity in 2024. For 2024, we expect our buyback activity to be consistent with our history of approximately $200 million to $250 million a year. We are confident the returns generated by these organic capital investments in the heart of our NGL value chain will support the continued growth in EPD's cash flow per unit and free cash flow, which will support future returns of capital through both distribution growth and buybacks. Our total debt principal outstanding was approximately $29.2 billion as of September 30, 2023. Assuming the final maturity date for our hybrids, the weighted average life of our debt portfolio is approximately 19 years. Our weighted average cost of debt is 4.6%. At September 30, approximately 96% of our debt was fixed rate. In 2024 only $850 million or approximately 3% of our $28.6 billion in term debt obligations, which excludes commercial paper, actually mature. For the three years 2024 through 2026, only 13% of our term debt obligations mature. The combination of this modest maturity ladder, the average life of our debt portfolio and high percentage of fixed rate debt provides the partnership with ample financial flexibility and gives a solid foundation to grow cash flow per unit. In other words, the incremental cash generated from these new projects will not be materially eroded by having to refinance our existing debt portfolio in the current high interest rate environment and thus will better translate into cash flow per unit growth. I do not believe the value of our debt portfolio and liability management is fully appreciated. Our consolidated liquidity was approximately $3.8 billion at the end of the quarter, this includes availability under our credit facilities and unrestricted cash on hand. Our adjusted EBITDA was $9.2 billion for the trailing 12 months ending September 30, 2023 compared to $9 billion for the trailing 12 months ending September 30, 2022. We ended the quarter with a consolidated leverage ratio of 3.0 times on a net basis after adjusting debt for the partial equity treatment of our hybrid debt and reduced by the partnership's unrestricted cash on hand. Our leverage target remains 3 times plus or minus 0.25, so the range of 2.75 to 3.25 times. With that Randy, we can open it up for questions.

Okay, thank you, Randy. Tawanda, we're ready now to take questions from our participants and I would just remind our participants to please restrict your questions to one question and one follow up. Okay? Thank you. Tawanda, go ahead.

Thank you. Our first question comes from Theresa Chen with Barclays. Your line is open.

Good morning. Thank you for taking my questions. Would you mind providing some more color about what drove the magnitude of the project FIDs at this specific juncture? What changed versus previous expectations, the annual growth CapEx cadence and were some of these projects contemplated earlier in that $2 billion to $2.5 billion CapEx range, but things got more expensive or were they discrete projects that previously weren't in your runway not been brought in?

I guess what changed is the opportunities were there, Theresa, and we thought it was the right time to go. I know there's a lot of questions in the past on Chinook and as we look at what we're doing out in the Permian, we felt like we needed to move on Chinook given that we're going to build two more plants and bring our plants out there to 19, which is quite a lot of WAG, right? Chris?

Yes, Theresa, this is Chris Nelly. You know, I think what we've been talking about on last quarter's earnings call was that, we were looking for what was the most effective way to expand our NGL take away capacity out of the basin. And as Jim alluded to, with some of the commercial successes we've had in expanding and winning contracts on gas processing capacity, we came to the conclusion that we needed to build the full Bahia pipeline and as a result of that downstream of that you need additional frac capacity. So in our minds, these things go very much hand in hand, and it is in the core of our NGL franchise.

And as evidence to that, Theresa, we took Seminole's crude service because we need NGL takeaway right now until the Bahia pipeline gets in service. So Frac #14 will be full and those two processing plants when we bring them on will be full, right Natalie?

Got it. Would you also be able to provide an update on the commercialization progress for SPOT? And would it be possible to maybe move some or all of the ECHO export volumes over to SPOT, maybe supplementing that commercialization effort, if anything? And that would make space, I imagine for incremental NGL exports given that you do see a tremendous amount of NGL growth across your system underlying your project announcement today, which includes expansions nearly along every aspect of your NGL infrastructure value chain except exports?

Yes, we're having some productive negotiations with producers and large trading houses on SPOT, and frankly I'm getting more optimistic by the day. We have that record of decision. We're still waiting on Bob Sanders, the license to construct which we're hoping that we expect to have by the end of the year.

We're continuing to work with Mayor Ed and the Department of Transportation on moving that forward, so timing is relatively short, yes, Sir.

You got anything, Brent?

No, I think overall the momentum on SPOT continues to get better and better and the earlier question, this question to me it's what do we believe as a company. I think Tony Chovanec and his group need to take a victory lap for their ability to forecast production, and SPOT is going to be about what the Permian Basin does from crude oil and all things, and that's what all these projects align toward.

Regarding the inquiry about increasing LPG through the ship channel, I want to emphasize my appreciation for the Houston Ship Channel. One of its advantages is the two-way traffic it accommodates. From what I’ve heard, the daylight restrictions will be lifted on November 1st. Additionally, once the channel is widened, we can expect a significant increase in traffic through that route.

Yes Sir, that's absolutely correct. The wider channel is going to allow us to move more product, whether it's LPGs or crude oil or ethane.

Got it. Thank you.

Thank you. Please stand by for the question. Our next question comes from the line of Jeremy Tonet with JPMorgan Securities. Your line is open.

Hi, good morning.

Good morning.

I just want to come back to capital allocation. I appreciate the deep commentary in the prepared remarks there, but just wanted to kind of come in overlaying once, these projects tend to service the projects announced today, Enterprise appears well-positioned to generate significantly more free cash flow and drop leverage well below three times here it seems. I believe your messaging highlights the ability to return more cash to investors with these projects and maybe could you talk us through how you see Enterprise's capital allocation unfolding and particularly given the potential for lumpiness as you described?

Yes, Jeremy, I believe we've shown that we've been consistent in balancing buybacks while continuing to invest in the partnership and increasing cash flows per unit. To me, the growth of cash flow per unit is a key metric, along with managing leverage. Keeping leverage in check is crucial because as we grow cash flow per unit, it will eventually lead to increased free cash flow. I believe our growth capital expenditures are uneven over time. In 2024, we expect to return to a range of 3 to 3.5 times leverage. This is influenced by several projects we have underway. I hesitate to describe it as uneven, but we have significant projects like our river export facility and the Bahia pipeline, which are quite large. After these, the expenses for natural gas processing plants and NGL fractionators become much more manageable. SPOT will also still be out there, and if we don't complete its commercialization, that will extend over 3 to 3.5 years. Therefore, I see the period where we invest $3 billion to $3.5 billion a year as fairly limited. So moving forward, around 2025, 2026, and 2027, we should generate a substantial amount of free cash flow. Currently, we don't feel the need to reduce leverage from our target of 3.3 times, which will allow for more cash available for distribution growth and buybacks.

Got it. That's very helpful there. Thanks. And then just want to pivot back to the projects announced today a little bit more, if I could. And clearly the growing logistics needs associated with robust Permian production is the focal point for midstream here highlighted by your announcement today. And so diving in a little bit more here on the NGL pipe side specifically with today's announcement and the NGL pipe additions appear to outpace, I guess, the 1.2 million of NGL production growth enterprise 2030, if you look at all the NGL pipes I think talked about in the industry and granted Enterprise has acres dedication and a closed loop system which provides barriers to entry there. But do you see risk to a looser NGL pipeline market down the road and how did Enterprise, I guess, gain comfort in this size of an NGL pipe?

You understand what you're talking about the 30-inch Bahia?

Yes, just give, sorry…

We felt like that was the right size given what we see. What a lot of people, what I had Tony look into at sometimes is a damn Permian is how about 10 stack pays? Huh?

Probably greater than that particularly on the Delaware side, Jim, it's awesome…

I look at what Exxon's CEO said about improving efficiency and recovery rates, and I believe we are only beginning to explore our potential. One thing that Jim Teague and Randy Fowler dislike are unproductive assets, and they won't remain unproductive for long.

Yes. And Jeremy what I'd add also, and I thought the timing was good. Rusted Brazil a note that also highlighted end of last week, end of last week, Tony, you want to hit some of the…

Yes. So look, when we look at our production forecast, the EIA actuals for what those words are worth are supposed to be out today or tomorrow. But if we go through what they have for actuals just through July, they're showing 853,000 barrels of growth in crude oil production for this year so far. Now, they've been a very, their data is very hard to set your watch to admittedly, but we had talked about 1.8 million barrels over a three-year period, 2022 through 2025 okay, and then people said, well, and you know how do you gauge it year-to-year? And I said well, it's hard to tell, but just divide it evenly. I'll definitely take the overall 600 for 2023 without a doubt for crude oil additions.

I would look at Enterprise and Permian assets as a portfolio and I think we've demonstrated what Jim said is that we use those pipes for how the market sees fit and I would expect us to do that going forward.

Got it. I'll leave it there. Thank you.

That was more of an answer than you wanted, wasn't it?

Thank you. Please stand by for our next question. Our next question comes from the line of Tristan Richardson with Scotiabank. Your line is open.

Hi, good morning all. Just in the context of the NGL production outlook you offered and really how critical and unique the export complex is? Can you talk about the competitive landscape for NGL export capacity? I mean particularly now as some of your peers might like to enter this market either be it in M&A or organically?

Hi, Tristan, this is Jim. Yes, we keep hearing that. We, I personally think, and we made a mistake and maybe it was I made a mistake when we were the only game in town in that we went after pretty high fees when I wish we'd have gone after lower fees because we opened the door for competition. That won't happen again. I don't know how a Greenfield project competes with a brownfield project, especially when you have someone like Enterprise that's going to be aggressive in holding market share or even growing it.

Super helpful. I appreciate the context. And then you've talked about all of the folks at Enterprise are very focused and incentivized around Project 9.3. Can you give an update there as we near your end and really, more importantly, any thoughts yet on incentive targets or goals for 2024?

9.3 was never intended to be guidance, although every one of you guys took it as such. It was a goal. It was a goal. And I can't remember the last time we missed meeting a goal.

Thank you. Our next question comes from Jean Ann Salisbury with Bernstein. Your line is open.

Hi, good morning. There's not really any Gulf Coast LPG export capacity being added until, like, mid-2025. Do you see export capacity getting tight over the next year and a half? And could that be a tailwind for you next year?

Going to be very tight, Jean Ann.

All right. As a follow-up, you obviously announced a lot of organic Permian G&P growth today. Can you talk about how you looked at the pros and cons of organic versus inorganic G&P ads in the Permian? There are obviously a lot of options?

With organic, you can build plants where you want them. And you don't have to deal with someone acquiring a company that has a lot of dedications to other companies. So, we just – we can build them where we want them and we control the liquids.

Thank you. Our next question comes from Brian Reynolds with UBS. Your line is open.

Hi, good morning, everyone. Maybe a question for Tony to follow up on some of the Permian fundamentals. Clearly, a lot of these new project announcements are predicated on Permian crude and NGL forecasts going forward. And Jim, you discussed some significant efficiencies that are expected in the Permian through this timeframe. So kind of curious if you can discuss how many of these efficiencies do we need to show up for these numbers to be realized, in your view? And then second, kind of what does this imply for permitting rig count going forward? Just seeing that we have seen some weakness going forward, but the medium term outlook still seems to be intact. Thanks.

I'll start out when we did our forecast, we projected what activity was going to be. So Permian rig counts, we said, would range between 315 and 320, and they've ranged between 300 and 325, so not hard math there. For frac crews, we estimated between 135 and 150, and they're between 145 and 160. It's producers' behavior. And look, they're our customers. We talk to them. We plan projects and capital hand in hand with them. So we have a significant amount of what I'd call institutional knowledge.

Tony, let me ask, when your forecast did you all build in any growing efficiencies? Or did you no…

That's a great question. We do not put a coefficient in there for growing efficiencies, and they've been growing for 10 years. I don't know what stops them at this point. But, Jim, to your point, there are about 80 producers that have rigs working in the Permian basin today. Out of those 80, only 20 of them have five or greater rigs running. Okay? There is significant upside as far as that 60 producers that have less than five rigs running. There's a lot of metrics you can look at, but that's a simple one. That's the reality.

And I guess, Tony, also the forecast that your team worked on did not assume a higher recovery of reserves.

No, sir, it did not. It assumes historical recoveries, which are in the high single digits, Randy. Now, we all know that at least two majors have said that that is not how they are forecasting going forward.

So using a Louisiana term, it's a little something extra, Brian.

Great, thanks. I appreciate the color on that. Maybe just a quick follow up on the Permian natural gas liquids. Seminal conversion seems to be catered towards the highest margin molecule, whether that's crude and natural gas liquids or I think you kind of referenced refined products in your prepared remarks going forward. So just given the opportunities for SPOT in 2025 plus Petchem 2025 plus, how should we think about maybe opportunities for Shin Oak and Seminole, kind of just go to the highest margin market. Is that kind of just a wait and see for what the market's going to give you in that time frame? Or do you ultimately see Seminole returning back to crude service? If you do want to pursue crude exports in the back half of the decade, I think we're going…

I think we go type flexible, Brian, but I mean, all of the above is possible. If those are full, it's possible we'll just build another one. It's really dependent on SPOT success. And like I said earlier, we're getting a lot more optimistic on being able to get this thing done with good commercialization. We're talking to a lot of people. Brent and I were in Europe, what, three weeks ago, Brent? And our sole purpose was to promote SPOT, and we got some pretty good feedback from people.

Great, thanks. I'll leave it there. Enjoy the rest of your morning.

Thank you. Our next question comes from Spiro Dounis with Citi. Your line is open.

Thanks, operator. Good morning, everybody. A few cleanup questions for me. Randy going to see if I can try and get you to say lumpy one more time, but just going back to SPOT and thinking about capital allocation next year. I think you mentioned that you'd still be able to sort of maintain this level of distribution growth with the current CapEx program and not come off this sort of buyback plan. But I just want to verify, if SPOT does get sanctioned, CapEx presumably goes higher, and I think you guys lean on the balance sheet, maybe for the first time in a while. So, just curious, does all that still hold if SPOT does get sanctioned?

Bob, once we get a license to construct, we're not through, are we?

No, sir, that's just the first of about 2024 that are needed.

It's going to take a while to license to construct. Didn't mean we can go out there and start digging ditches.

No, sir.

Yes, I think, again, with or without SPOT, it doesn't impact 2024. And frankly, I mean, if we're successful with SPOT, most of that's going to be 2025, 2026, 2027, and we're in good shape to continue distribution growth and buybacks during that time period.

Chris, the one thing I would also add to that is I still think even if we get to a point where SPOT is sanctioned, we'll still be within our three times leverage, plus or minus a quarter of a turn.

Okay. Got you. Helpful color there. Just going to M&A from two different perspectives. So, one, I guess on the upstream side, we've seen a lot of your customer base continue to consolidate. So, I guess I'm curious to skip your updated views on the potential impact to EPD into midstream more broadly. And then as we think about M&A for EPD, just given the slate of growth projects in front of you, I imagine you're sort of out of that market for the time being, but don't want to put words in your mouth.

I like what Randy says: price matters. The right deal, the right price. I'm not sure we'd back away from it, but it's got to be the right deal at the right price that fits us strategically.

All right, I'll leave it there. Thanks, guys.

Thank you. Our next question comes from John McKay with Goldman Sachs. Your line is open.

Hey, good morning, everyone. Thanks for the time. I wanted to pick up on something that I think Chris mentioned earlier in the call. Just in terms of we're looking at all these new Permian growth projects on the NGL side. How much of the flow do you think is going to come from your own plants on the EPD side versus third party flows? And if we're thinking about that overall, how do you think your market share trends on NGL pipeline throughput over the next couple of years?

Justin, you got any idea?

I think going back to some of the previous commentary, I mean, our G&P asset base is what the feeder to our NGL pipes will continue to be and will continue growing and on a percentage basis, don't have the exact percent, but I'd bet it's 80% plus Fed from our own G&P. And I would expect that's going to continue to grow as we continue to grow that footprint.

That's fair. I appreciate it. Maybe just shifting gears quickly, have the commentary on the PDH 2 ramp in there. Just if you give us an update now that we're a little bit into the fourth quarter and what we should look for there?

We did have some operational issues in the third quarter with the PDH. We're working some issues with a reactor with the licenser. We should have that resolved later this month and expect this to be a one-off and returning to full operation later in November.

I appreciate the time. Thank you.

Thank you. Our next question comes from the line of Michael Blum.

Thanks. Good morning, everyone.

I'm sorry.

No worries. Thanks. So, a lot of questions, obviously, today on the projects and on supply, but wonder if you can give us an update on what you're seeing on the demand side, particularly in China and India, and how any Panama Canal issues are impacting your exports. And then the second part of that question is really the same question, but longer term, you're obviously very bullish on U.S. supply here for a long time. Where do you see all these products being consumed? Do you see that shifting at all from the current setup? Thanks.

I'll start and I'll probably ask Brent a question. As I said in our script, Michael, it's been a pleasant surprise at the appetite for ethane and that's not in Europe, that's in Asia. And we've got a couple more contracts that I expect that we will sign. So I thought ethane was going to be just a point to point project and I wanted to build the first one, but I didn't really expect it. It looks to me like it's becoming, Brent, much more a traded product?

More so…

Than I expected. And then, Brent, speak to the type of demand we see on LPG.

Yes, Michael, if you just look at in the third quarter where the LPG cargoes went, 55% went to Asia, 18% went to the Americas, 17% Europe and 9% Africa. If you were to trend that and look at the incremental molecule, where it's going, Asia is far and away the leader of where each molecule goes. On the demand side of what that LPG is used for, about one-third is used for petchem use, two-thirds is used for cooking and heating. Tony gave us some numbers. I want to say it was yesterday. I'm going to try to look at these notes, but about the IEA came out and said 1.5 billion people use LPGs for cooking and heating. If you look at the estimates through 2030, there's about 2 billion people who don't have access to it. If you look at the same consumption per capita those billion people would need about 3 million barrels of LPG between now and 2030. And if you look at Tony's forecast, he's a little shy of 600,000 barrels of LPG from the U.S. through 2030. So the Middle East will make up some of that. But at some point, the U.S. producer is going to have to step up and fill that void.

Hey, Chris, what was that organization that said propane and natural gas was transitional?

Yes, Jim. MSCI recently came out and upgraded Enterprise to an A rating for their ESG score. I think that really is a result of the stats that branches throughout. Again, if you think about what LPGs do in improving the quality of life for people in, call it the Southern Hemisphere, that is an absolute game changer. Needing 3 million barrels a day of an additional LPGs between now and the end of the decade is really the reason why MSCI came out and said, okay, LPGs are now a green fuel, if you will.

I'd like to add relative to solar. And let's think about Africa. Okay? It's going to happen. They're going to use it. But solar, no matter how you think about it, is not a good choice to cook and eat with homes. It simply is not. And people in Africa, they're going to get more. And natural gas and electricity are very expensive to move around. That's what we've seen over the last ten or twelve years with LPG. Get a lot of energy, not hard to move around. It's not hard math.

You just fill up a little tank.

Yes, sir. Absolutely.

I go back to paraphrase Daniel Juergen, this world has never done energy transition, it has only done energy addition. And I think we're going to see more of that.

Great. Thank you for all the color. I appreciate it.

Thank you. Our next question comes from Keith Stanley with Wolfe Research. Your line is open.

Hi, good morning. I had a question on the quarter and then a follow up on the NGL pipe. So on the quarter, just NGL marketing has been softer this year than last year. Any drivers you'd highlight? And the frac margin too. You had a huge step up in volumes with the new frac, but the per unit margin was down a lot. Anything you'd call out there?

You want to talk to frac? Zach?

I'll start with the frac. So this quarter we had two turnarounds on two of our fracs, so that increased our cost. Obviously there, there is some uplift that we get from blend margins, which were down year-over-year, and then ERCOT pricing. So just the hot summer hit us this year relative to last year.

NGL marketing, Keith? I think most of it just has to do with the structure in the market on storage. So if you look back when COVID happened, we put on, obviously a lot of contango. Some of that was extended further along, dated. And then we had some backwardation opportunities last year that, frankly, we just didn't see those opportunities this year. It's been less volatile in general this year. There just really hasn't been a lot of spreads.

Got it. That's helpful. And then sorry, I have one on the NGL pipe. So just want to confirm. It's a brand new pipe. So it's a greenfield new build. And if there's any way to give more color on what you see as the disadvantages of some of the other alternatives, like a cheaper looping of Shin Oak or even leveraging some of the third-party capacity that's getting added just because it's a lot of capacity, I think that the market's seeing getting added all at one time.

We looked at partial loops, and we didn't think that served what we needed. We decided to just build the entire pipe. And I'll remind you what was Chaparral's capacity? 130,000 barrels per day. We've got to move on other pipe. We get Shin Oak, you're around 600,000 barrels a day right now.

600.

And we need Seminole. And frankly, we don't leverage third party pipes; we put it in our own.

This is Randy. We have time for one more question.

Thank you. Our next question comes from Neel Mitra with Bank of America. Your line is open.

Hi, good morning. Thanks for taking my question. I had a question about the conversion and where you'll be offloading some of the crude volumes. So from what I understand, Midland-to-ECHO 2 is moving some volumes, and the whole Midland-to-ECHO system is relatively full. So when you move this to NGL service, where do the crude barrels go?

Midland-to-ECHO 1. And we can get that up to 600,000 barrels a day. There's a marginal difference in cost, but more than we can make up for what we do with Seminole and NGL service.

Okay, perfect. And then, not to beat a dead horse, but the 700,000 barrel per day crude oil increase in 2023. Just wondering, Tony, from your perspective, for 2Q and 3Q, it seemed like we had flat hydrocarbon growth in general out of the Permian, just with all the infrastructure constraints and the heat compression, et cetera. So are you expecting a big September through December ramp? Because it seems like most of the growth that's come year-to-date has been in the first quarter, if I'm not mistaken.

Yeah. I will tell you, it's very hard to count production quarter-by-quarter. What people are looking at is the EIA numbers, which by their own admission, have been very erratic, sporadic, both of the above. But through the second quarter and through the third quarter, if you sat in our management meeting every Tuesday morning, you would hear about the amount of rich gas that wants to come to our plants and can't wait till our plants get built. So we really didn't see a massive lull. I understand that that's what the EIA reported. The facts are the other thing people worried about is the rig drop because the rigs kept dropping. But you have to remember that we had a tremendous build in rigs in 2022 to just make up for what happened during COVID. We couldn't stay like that at those levels forever. You had to replenish inventories, and you did. So it's very hard to look and say per quarter, but look, we're on a path to exceed 600, and I don't know what takes us from that path off of that path next year, end of story. Will one quarter have freeze-offs and one be hotter than the other? Yes, sir. But it doesn't matter. The calculus is so big because, as Jim's pointing out, the basin is so large. There you have it.

Right? Okay. Thank you very much.

Thank you. Ladies and gentlemen, at this time, I would like to turn the call back over to Randy for closing remarks.

Thank you. Tawanda, we'd like to thank everybody for joining us today. That concludes our call. A replay of the call is available through our website via the webcast. And again, have a good day, and I'll turn it back to you for any closing comments, Tawanda.

Thank you. Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.