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Enterprise Products Partners LP
Earnings Call Analysis
Q3-2023 Analysis
Enterprise Products Partners LP
The company reported a solid performance for the third quarter with an adjusted EBITDA of $2.3 billion, maintaining a distributable cash flow coverage ratio of 1.7 times and retaining $773 million. This financial strength came alongside record volumes handled across all segments of their midstream system, amounting to 12.2 million barrels per day of crude oil equivalent. Furthermore, the company announced significant expansions in their NGL operations, including the construction of additional processing plants and the conversion of existing pipelines to bolster NGL takeaway capacity.
Net income for common unit holders was $1.3 billion, translating to $0.60 per diluted common unit. Operating cash flow remained stable year-over-year at $2 billion. Distributions to common unit holders increased by 5.3% compared to the previous year's third quarter, reflecting the company's commitment to returning value to investors. They also continued to utilize their capital return programs prudently, with 41% of a $2 billion buyback program executed and about $4.3 billion paid out in distributions over the last twelve months, confirming a strong commitment to shareholder returns.
Capital investments for the third quarter stood at $826 million, signaling an aggressive growth stance with expectations to total $3 billion for the year and a forecast of $3 billion to $3.5 billion for 2024. Notably, this level of capital investment is not expected to impede distribution growth or buyback activities, aligning with the company's dual focus on expansion and shareholder remuneration.
The company has managed its debt strategically with a principal of approximately $29.2 billion. With long-term fixed-rate debt constituting about 96% of the portfolio and only a small percentage maturing over the next few years, they are well-positioned to handle current high interest rate environments without affecting their plans for cash flow growth per unit. Their current consolidated debt ratio stands at a healthy 3.0 times, within their targeted range of 2.75 to 3.25 times, speaking to substantial financial flexibility and a strong foundation for future growth.
Progress in their negotiations for the SPOT project appears promising, with increasingly optimistic outlooks. The eventual decision on construction licenses, expected by the end of the year, will further clarify the project's future contribution to the company's portfolio and its impact on overall cash flow generation.
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Hello, and welcome to Enterprise Products Partners L.P. Q3 2023 Earnings Conference Call. [Operator Instructions]I would now like to hand the conference over to Randy Burkhalter, VP of Investor Relations. Sir, you may begin.
Thank you, Twanda. Good morning, everyone, and welcome to the Enterprise Products conference call as we discuss our third quarter earnings. 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.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 the 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 1.7x 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 handle 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 folks 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 like it comes 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 forecast have been consistently on the money 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 2 more 300 million cubic feet a day processing plants in the Permian, 1 in the Delaware and 1 in Midland. When completed, we'll have 19 processing trains in the Permian and 41 companywide.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 NGLs into our storage system in Chambers County. The beauty of this Seminole pipeline is we can seamlessly switch service to include our NGLs or as an expansion of our new TW refined product system.Finally, we announced today that we would build frac 14 and a related DIB. The frac is similar to frac 12. We'll be able to fractionate approximately 200,000 barrels a day. This will bring Enterprise's company-wide fractionation capacity to 2 million barrels a day across 20 fractionators. We haven't just been announcing new projects. We've also been blocking and tackling, and I could take up this entire hour talking about what our people are doing every day to improve the performance of our existing assets. But one example of what we've been doing is a Permian initiative to improve the quality of the crude we deliver for our customers.We've spent money to develop a system to monitor crude receipts to ensure that those receipts meet our specs, which mirror the Platts dated Brent specs. Since we've adopted this initiative in May, every WTI cargo we've loaded has met the Platts dated Brent specs. That is over 100 cargos of crude. 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 system. 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 assets we have, our folks, Enterprise people, 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 segment items. Net income attributable to common unitholders 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 or -- 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 close of business today. This year marks our 25th consecutive year of distribution growth. I guess you can say you can treat that distribution as a treat today.Our dividend reinvestment plan and enterprise unit 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 9 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 buyback equity in the third quarter. During the third quarter buyback window, our VWAP, 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 6 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 6th largest North American midstream energy companies, those with a market capitalization over $35 billion. Since 2019, EPD is one of only 2 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 start of buybacks for 6 years in a row.We were also 1 of only 3 companies that grew distributable cash flow per unit by 15% or more. In fact, for this group of 6 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 CapEx. Capital investments for the first 9 months of 2023 were $2.3 billion, which includes $2 billion for 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 4 projects, we have $6.8 billion of major growth capital expenditures of projects 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 was approximately 19 years. Our weighted average cost of debt is 4.6%. As of 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 3 years, 2024 through 2026, only 13% of our term debt obligations matured. The combination of this modest maturity ladder, the average life of our debt portfolio and high percentage of fixed rate debt provide the partnership with ample financial flexibility and provides a solid foundation to grow cash flow per unit.In other words, 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, and 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 3.0x 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 3x plus or minus 0.25, so the range of 2.75x to 3.25x.With that, Randy, we can open it up for questions.
Okay. Thank you, Randy. Twanda, 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. Twanda, go ahead.
[Operator Instructions] Our first question comes from the line of Theresa Chen with Barclays.
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? Were there discrete projects that previously weren't in your one way, now been brought in?
I guess what changes the opportunities were there, Theresa. And we felt like it was the right time to go. I know there's a lot of questions in the past on Shin Oak. And as we look at what we're doing out in the Permian, we felt like we needed to move on Shin Oak, given that we're going to build 2 more plants and bringing our plants out there to '19, which is quite a lot of Y grade. Chris?
Yes. Theresa, this is Chris Nelly. I think what we've been talking about on the last quarter's earnings call was that we were looking for what was the most effective way to expand our NGL takeaway 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 that 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 out of crude service, because we need NGL takeaway right now until the Bahia pipeline gets in service. So frac 14 will be full, and those 2 processing plants when we bring them on will be full, right, Nelly.
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 exports?
Yes. We're going to -- 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 -- we expect to have by the end of the year.
We're continuing to work with MARAD 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 is 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.
To the question of more LPG out of the ship channel, I think everybody knows how much I love the Houston Ship Channel. And the neat thing about the ship channel is you have 2-way traffic. From what I understand, daylight restrictions will be lifted November 1, but then when they widen it, that's even -- we can get a lot more traffic coming down that channel, Bob.
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.
All right. That's fine.
Our next question comes from the line of Jeremy Tonet with JPMorgan Securities.
Just wanted to come back to capital allocation. Appreciate, the deep commentary and the prepared remarks there, but just wanted to kind of come in overlaying, once these projects are to service the projects announced today, Enterprise appears well positioned to generate significantly more free cash flow and drop leverage well below 3x 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 Enterprises capital allocation unfolding and particularly given the potential for lumpiness as you described?
Yes. Jeremy, I think we've demonstrated as far as coming in and consistently. And I'd like to say we balanced the buybacks with continuing to invest in the partnership and grow cash flows per unit. And to me, the cash flow per unit growth is the main metric that in leverage -- and keeping leverage in check is really the main metric. Because the more cash flow per unit you grow, eventually this is going to translate into free cash flow because again, I think our growth CapEx is lumpy over time.We -- in 2024, we said we were going to be back in the range of 3x to 3.5x. And some of that is, we have a number of projects. I keep hating to use the word lumpy. But we have some material projects out there, whether it's our Neches River export, our ethane and propane export facility or whether it's the Bahia pipeline that are fairly large projects. Once you get past those, the natural gas processing plants, NGL fractionators are very manageable growth CapEx.SPOT would be out there, that if we can go ahead and finish commercializing that, but that's something that's going to be spread out over 3 years, 3.5 years. So I really see the period where we're investing to $3 billion, $3.5 billion year is pretty limited. And so as a result, I think once you get out further, call it '25, '26, '27, we ought to be throwing off a good bit of free cash flow as you say. Right now we don't see the need to come in and reduce leverage anymore from where we are today with a target of 3.3x. So again, that provides more cash for distribution growth and buybacks.
And then just wanted to pivot back to the projects announced today a little bit more if I could. 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, the NGL pipe additions appear to outpace, I guess, the $1.2 million of NGL production growth. Enterprise sees 2030, if you look at all the NGL pipes I think talked about in the industry. And granted Enterprise has acreage dedications and a closed loop system which provides barriers to entry there. But do you see a risk to a looser NGL pipeline market down the road? How did Enterprise gain comfort in this size of an NGL pipe?
You're talking about the 30-inch Bahia?
Yes. Just given -- sorry.
We felt like that was the right size, given what we see. A lot of people -- what I have Tony looking at sometimes is down Permian is probably like 10 stack pays.
Greater than that, particularly on the Delaware side, Jim.
Yes.
10 plus on the middle.
I mean, and then I look at what somebody like Exxon CEO said about getting more efficient and getting better recoveries, and I think we're just scratching the surface. And I think we'll -- one thing Jim Teague hates and Randy Fowler hates are empty assets, and they won't stay empty for long.
Yes. And Jeremy, what I'd add also, and I thought the timing was good, rest of Brazil had a note that also highlighted.
End of last week.
Yes. End of last week. Tony, you want to hit some of the…
Yes. So when we look at our production forecast, 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 3-year period, 2023 through 2025, okay? And people said, well, how do you gauge it year-to-year? And I said, well, it's hard to tell, but just divide it evenly.I'd definitely take the over on 600 for 2023 without a doubt, for crude oil additions. And I have to tell you, when I look at what's going on relative to activity and profitability for the produce, I have to ask myself, what's going to change this trajectory in 2024? Or for that matter, what's going to change in 2025? Brent and thank you for the commentary. I mean, we spend a lot of time and a lot of effort. We have sources that are significant relative to things we buy and then that we amalgamate with I would call it data science and data engineering. But last but not least, we have a significant amount of institutional knowledge from the army of people that we have.
On top of that, remember, we're taking Chaparral out of NGL service -- and then we took Seminole out of NGL service. Now we're putting it back into NGL service, which says, hey, you guys need more takeaway right now, which is true. And then we will have the option once Bahia comes on as to what we do with Seminole and we can do one of 3 things with it and we're pretty damn good at repurposing.
I would look at enterprises and permanent 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.
That was more of an answer than you wanted, wasn't it?
Our next question comes from the line of Tristan Richardson with Scotiabank.
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 an M&A or organically?
Hi, Tristan. This is Jim. Yes, we keep hearing that. 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. I wish we'd have gone after lower fees because we opened the door for a 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 damn aggressive in holding market share or even growing it.
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.
Our next question comes from the line of Jean Ann Salisbury with Bernstein.
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 1.5 year, and could that be a tailwind for you next year?
It will be very tight, Jean Ann.
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's obviously a lot of options.
With organic, you can build plants where you want them. And you don't have to deal with some acquiring a company that has a hell of a lot of dedications to other companies. So we just -- we can build them where we want them and when we control the liquids.
Our next question comes from the line of Brian Reynolds with UBS.
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 with these numbers to be realized in your view?And then second, kind of what does this imply for the Permian Rig Count going forward, just seeing that we have seen some weakness going forward, but the medium term outlook still seems to be intact?
Well, 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 something. In your forecast, did you all build in any growing efficiencies?
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. 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 5 or greater rigs running. Okay. There is significant upside as far as that's 60 producers that have less than 5 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-digit range. Now we all know that at least 2 majors have said that that is not how they are forecasting going forward.
So, Jean Ann all that would be using a Louisiana term, lagniappe, a little something extra. Brian, sorry.
Great. Appreciate the color on that. Maybe just a quick follow-up on the Permian natural gas liquids. Seminole 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 of what the market's going to give you in that timeframe or do you ultimately see Seminole returning back to crude service if you do want to pursue crude exports in the back half of that period?
I think we're going to stay 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, 3 weeks ago, Brent?
3 weeks ago.
And our sole purpose was to promote SPOT and we got some pretty good feedback from people.
Our next question comes from the line of Spiro Dounis with Citi.
A few cleanup questions for me. Randy is going to see if I can try to 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 sanctions, CapEx presumably goes higher. And I think you guys lean on the balance sheet maybe for the first time in a while. So I'm just curious, does all that still hold if SPOT does get sanctions?
Cool. Cool. Cool. Hi, Rob. Bob, how many – 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.
So it's going to take a while. The license to construct didn't mean we can go out there and start digging ditches.
No, sir.
That was a ramp up on cash flow.
Yes. So I think, again, with or without SPOT, it doesn't impact 2024. And frankly, most -- I mean, if we're successful with SPOT, most of that's going to be 25%, 26%, 27%. And we're in good shape to continue distribution growth and buybacks during that time period.
And Spiro its 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 3x leverage plus or minus a quarter of a turn.
So I'm just going to M&A from 2 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 get 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 mark for the time being, but don't 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.
Our next question comes from the line of John Mackay with Goldman Sachs.
I wanted to pick up on something that I think Chris mentioned earlier on the call. Just in terms of 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 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 bet it's 80-plus percent fed from our own G&P, and I would expect that's going to continue to grow as we continue to grow that footprint.
Maybe just shifting gears quickly. Have the commentary on the PDH 2 ramp in there. Just maybe 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 the reactor with the licensure. We should have that resolved later this month and expect this to be a one-off and returning to full operation later in November.
Our next question comes from the line of Michael Blum.
So a lot of questions, obviously, today on the projects and on supply. But I 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?
I'll start and then 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 -- it's 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 people -- the type of demand we see on LPG.
Yes Michael, if you just look at in the third quarter where the LPG cargos went, 55% went to Asia, 18% went to the Americas, 17% Europe and 9% Africa. If you were to go 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 1/3 is used for petchem use, 2/3 is used for call it human needs, 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 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.
Chris, was there an organization that said propane and natural gas was a transitional?
Yes, Jim, MSCI recently came out and upgraded Enterprise to an A rating for their ESG score. And I think that really is a result of the staffs 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. In 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 homes with. 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 10 or 12 years with LPG. You get a lot of energy and it's not hard to move around. It's not hard math.
You just fill up a little tank and carry it home.
Absolutely.
And I go back to paraphrase Daniel Yergin, this world has never done energy transition. It has only done energy addition. And I think we're going to see more of that.
Our next question comes from the line of Keith Stanley with Wolfe Research.
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?
Yes, I'll start with the frac. So this quarter we had 2 turnarounds on 2 of our fracs that increased our cost. Obviously, 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.
And NGL marketing, Keith, I think most of it just has to do with structure in the market on a storage. So if you look back when COVID happened, we put on obviously a lot of contango. Some of that was extended further long 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.
And then sorry I have one on the NGL pipe. So I 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 a day? That 130,000 barrels a day, we've got to move on other pipe. We're getting -- I guess in Shin Oak, 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.
Twanda, this is Randy. We have time for one more question.
Our next question comes from the line of Neel Mitra with the Bank of America.
I had a question about the conversion and where you'll be offloading some of the crude volumes. 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?
Again Midland-to-ECHO 1, we can get that up to 500,000, 600,000 barrels a day. There is a marginal difference in cost, but more than made up for what we do with Seminole and NGL service.
And then not to beat a dead horse, but the 700,000 barrels 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 kind of September through December ramp? Because it seems like most of the growth that's come here today has been the first quarter, if I'm not mistaken?
Yes. 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, very, 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 until 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, that we had a tremendous build in rigs in 2022 to just make up for what happened during COVID. You 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, 000and I don't know what it takes us from that path -- off of that path next year. End of story. Well, one quarter have freeze-offs and one be hotter than the other? Yes, sir. But it doesn't matter. The cap was just so big because as Jim's pointing out, the basin is so large. There you have it.
Ladies and gentlemen, at this time, I would like to turn the call back over to Randy for closing remarks.
Thank you, Twanda. We'd like to thank everybody for joining us today. That concludes our call. A replay of the call is available to our website via the webcast. And again, have a good day, and I'll turn it back to you for any closing comments, Twanda.
Thank you. Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.