Ladies and gentlemen, thank you for standing by, and welcome to the Q3 2019 earnings conference call. At this time, all participants line are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star zero. I would now like to hand the conference over to your speaker today, Mr. Randy Burkhalter. Sir, you may go ahead.
Thank you, Michelle. Good morning, everyone, and welcome to the Enterprise Products Partners call to discuss third quarter 2019 earnings. Our speakers today will be Jim Teague, Chief Executive Officer, and Randy Fowler, President and Chief Financial Officer of Enterprise's General Partner. 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 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. With that, I'll turn the call over to Jim.
Thank you, Randy. This morning, I'll cover our earnings first and then give you an update on our projects list. Starting with earnings, we had $1.6 billion of distributable cash flow in the third quarter. That provided another 1.7 times coverage of our distributions. Year to date, our DCF was $5 billion, which provided a 1.7 times coverage. We retained $665 million of DCF in the third quarter, bringing our total to $2.1 billion for the first nine months of this year. Adjusted EBITDA for the third quarter was $2 billion. That's up 6% compared to third quarter of last year. For a total adjusted EBITDA of $6.1 billion for the first nine months, which is up 14% compared to the first nine months of last year.
Similar to prior quarters, our results continued to provide healthy free cash flow, giving us the flexibility to fund our growth projects while maintaining a solid balance sheet and not having to issue new equity. During the third quarter, we set six operational records, including total equivalent pipeline volumes, natural gas pipeline volumes, NGL fractionation volumes, crude oil marine terminal volumes, and DIB and propylene production volumes. With our upcoming distribution payment in November, we begin our 22nd year of consecutive distribution growth. We continue to get closer to the 25-year dividend aristocrat benchmark, which is a select group of stocks with over 25 years of consecutive dividend increases, sort of the best of the best of dividend growth stocks. Over this time, we have increased our quarterly distribution rate 71 times through numerous business cycles, including the financial crisis and the last commodity cycle for energy.
We manage Enterprise to provide financial stability and growing distributions. In addition to projects already under construction, we were again successful in terms of underwriting new growth projects during the third quarter. Based on projects sanctioned today, we currently expect our growth capital expenditures in 2020 will be in the range of $3 billion-$4 billion. Given the size and integrated nature of our systems, we're always evaluating our alternatives to reduce the capital intensity of some of these projects while enjoying the benefits of incremental volumes in our system. We are evaluating joint ventures with strategic partners, not financial partners, on certain projects and are always looking for ways to optimize our systems based on market conditions, which could include physically changing the service or direction of our pipes. Sometimes our options are contractual.
This includes using contract provisions to claw back unused natural gas processing capacity from producers under acreage dedication contracts. This would provide us immediate long-term capacity while eliminating the need to build another processing plant. Our ability to keep customers' crude oil neat through segregated storage in Midland and Houston and batch it through our pipelines, coupled with our water access, has been a key differentiator of Enterprise Products Partners for large producers and large trading firms looking to sell crude into international markets that demand quality. We recently sanctioned two expansions of our Midland to ECHO Pipeline System, M2E3 and M2E4. We announced M2E3 in July and M2E4 in October. Our M2E3 expansion will add 450,000 barrels a day of capacity. This pipeline's expected to be completed in the third quarter of 2020.
The M2E4 expansion is our latest expansion of our Midland to ECHO Pipeline System that ties into our Eagle Ford crude oil pipeline and provides up to 450,000 barrels a day of incremental capacity, further expandable up to 540,000 barrels a day. By utilizing our Eagle Ford asset, shippers and producers will have the ability to match their pipeline capacity to their allocations of capital between the Eagle Ford and Permian basins. Simply put, this type of flexibility for our customers is unmatched. These expansions will allow us to optimize costs across our Midland to ECHO system. While DRA has enabled us to maximize the throughput of M2E1 and M2E2, it has come at an increase in variable costs.
Across these pipelines, we see variable costs of the last segment of incremental capacity exceeding $2, which works when the spread is over $2.50, but it doesn't work in the current spread environment. By optimizing volumes across the Midland to ECHO Pipeline System, variable costs should approach the more normalized variable operating costs of $0.10-$0.20 a barrel. In addition to savings from optimizing volumes across the Midland to ECHO Pipeline Systems, these expansions also give us the flexibility to divert crude off of M2E2, our Seminole pipeline, and then convert Seminole back into NGL service. We think we will eventually need this additional NGL capacity. In doing so, M2E4 will only add a small amount of incremental capacity to our Midland to ECHO System. If market supported, M2E4 could add up to 540,000 barrels a day of incremental capacity.
Just in short, look at the math in our crude oil system. Enterprise can transport at optimum cost 1.3 million barrels a day. If the market needs more capacity, Enterprise can ramp that capacity to 1.8 million barrels a day with zero capital. The third major project we announced during the quarter is our PDH2 plant. Lyondell is one of the largest petrochemical companies in the world, and they have been an important customer to Enterprise since the early '80s with our first butane isomerization facility. To build that plant, we've negotiated a fixed cost engineering, procurement, and construction contract with S&B to build PDH2. We have a long history with S&B, dating back to 1995. They led construction on nine of our NGL fractionators plus several other assets at Mont Belvieu and numerous other assets on our system.
Relative to market for natural gas, we also recently announced construction of the Gillis Lateral, which is an LNG-oriented natural gas pipeline extension of our Haynesville pipeline system that allows us to move Haynesville gas and interconnect volumes to the growing Gulf Coast LNG corridor. We also announced a successful open season for the expansion of ATEX ethane pipeline. Similar to other expansions on our system, this incremental capacity is expected to be achieved largely through improvements and modifications to existing infrastructure versus new pipes. Work also continues on our other major projects, with most of them to be in service within the next 18 months. Those projects are a healthy mix of supply and market system additions, including fractionators 10 and 11 at Mont Belvieu, gas processing plants at Mentone in the Permian, and Panola in East Texas, and crude oil petrochemical ethane and LPG dock expansions.
With the second PDH, our EI-PDH plant and our ethylene export project, we continue to grow our fee-based petrochemical midstream services value chain. This model follows our NGL and crude business models, aggregate supplies, transport, upgrade, store, optimize, and then distribute products to end users, including exports. The U.S. petrochemical industry is significantly advantaged to virtually all the world because of low-cost feedstocks and significant infrastructure and will continue to play an increasing role in our value chain for years to come. In summary, today's earnings, capital discussion, our portfolio of assets continue to perform and provide us with opportunities to grow over the long term. We have a strong history of capital discipline and continue to add to our systems with projects that will generate attractive returns on capital and free cash flow for years to come.
We're always evaluating our alternatives to reduce the capital intensity of some of our growth while still enjoying the value that incremental volume brings to our systems. We have a long history of optimizing our systems, attracting strategic partners, converting assets, and shunning overpriced acquisitions. We're a company that prides itself on consistency in distributions, solid balance sheet, an extremely supportive general partner, and what Randy Fowler has emphasized as no surprises, and a company that our stakeholders and shareholders can depend on. Looking ahead, expect more of the same. With that, I'll turn it over to Randy.
Thank you, Jim, and good morning. Starting with the income statement. Net income attributable to limited partners for the third quarter of 2019 was $1 billion, or $0.46 per unit on a fully diluted basis. Net income included a $39 million non-cash loss for asset impairment charges, or $0.02 per unit fully diluted, and $86 million in unrealized non-cash mark-to-market hedging losses, or $0.04 per fully diluted unit. Included in the non-cash mark-to-market losses was a $95 million hedging loss related to financial instruments used to hedge interest rates for anticipated debt offerings in 2020 and 2021, which is reflected in interest expense, and a $9 million hedging gain on financial instruments primarily related to our crude oil and natural gas segments. Adjusting for these non-cash items, EPU increased 2% versus the comparable adjusted earnings per unit for the third quarter of 2018.
Moving on to cash flow. Cash flow from operations was $1.6 billion for both the third quarter of 2019 and 2018. In traditional terms, our cash distribution payout ratio was approximately 59% with respect to the third quarter of 2019, and 58% with respect to the trailing 12 months ended September 30, 2019. Our cash distribution yield is currently 6.4%. In our last 12 months, cash flow from operations yield is approximately 11%. Free cash flow, which we define as cash flow from operations minus net capital investments, was $2.7 billion for the trailing 12 months ended September 30, 2019, which was a 28% increase compared to the trailing months ended September 30, 2018.
To follow what Jim said regarding capital investments, we have approximately $9.1 billion of major capital projects under construction, with $3.6 billion of these major projects added since our last earnings call, including our second PDH, Midland to ECHO 4 pipeline, and the Gillis natural gas lateral in Louisiana. Approximately 77% of the contracted volumes associated with these projects under construction are with investment-grade customers, and 70% of the volume-weighted contract lengths are for 10 years or more. Assuming our historical returns on capital, these assets have the potential to generate approximately $1 billion-$1.3 billion of incremental gross operating margin per year. Our total capital investments in the third quarter of 2019 were $1.1 billion, including $1 billion of growth capital investments and $91 million of sustaining capital expenditures.
Total investments year-to-date have been $3.4 billion, including $3.2 billion of growth capital investments, or $2.6 billion if you net contributions from JV partners and $233 million of sustaining capital expenditures. We expect full-year growth capital investments for 2019, net of contributions from JV partners, to be $3.8 billion. Note that the number in the press release was rounded to $4 billion. The largest component of the increase from last quarter was the purchase of 30-inch pipe for Midland to ECHO 4 and the Gillis natural gas pipeline Lateral, which together was $370 million. We expect $350 million for sustaining capital expenditures for 2019. Looking ahead to 2020 and given the projects recently announced, we currently expect growth capital investments to be between $3 and $4 billion.
In terms of capitalization, our consolidated liquidity was approximately $6.2 billion at the end of the third quarter 2019, which included available borrowing capacity at our credit facilities and unrestricted cash of $1.2 billion. As of September 30, 2019, our total debt principal outstanding was $28 billion. Assuming the first call date for our hybrids, the average life of our debt portfolio was 14.7 years. If you assume the maturity date of the hybrids, the average life of our debt portfolio is 19 years. Our effective average cost of debt was 4.5%. The partnership used cash on hand to retire $800 million of debt principal that matured on October 15th, 2019. Adjusted EBITDA for the trailing 12 months ended September 30, 2019, was $8 billion, and our consolidated leverage ratio was 3.2 times.
After adjusting debt for the partial equity treatment of the hybrid debt securities and reducing the debt by the unrestricted cash on hand. If we normalize adjusted EBITDA for the last 12 months to eliminate certain spread-related activities, we estimate that our leverage ratio would have been 3.5 times at September 30, 2019. Moving on to distribution payments. Our distribution with respect to the third quarter of 2019 was $0.4425 and will be paid on November 12th. This distribution represents a 2.3% increase when compared to the same quarter of 2018. As mentioned last quarter, and until further notice, the delivery of common units under our Distribution Reinvestment Program and our Employee Unit Purchase Program is now satisfied through open market purchases instead of the issuance of new units.
Even with our expanded growth capital investments for 2020, we still intend to self-fund the equity component of our growth rather than relying on equity capital markets. With that, Randy, we can open it up for questions.
Okay, Michelle, we're ready to take questions from the audience. I would remind our audience that we would limit our questions to one question and one follow-up.
Ladies and gentlemen, if you have a question at this time, please press the star and the number one on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. We ask that you please limit yourself to two questions. Please press star one again to go back to the queue. Your first question comes from the line of Shneur Gershuni. Your line is now open.
Hi, good morning, everyone. Maybe just to start off on the CapEx front a little bit here. Appreciate the color that you gave around Midland to ECHO in the prepared remarks. Just wanted to, A, clarify that the total net increase in capacity was about 500,000 barrels. As part of that, in terms of your CapEx number for 2020, does that also include the SPOT terminal or is that not part of the 2020 number?
I don't think that is a part of the 2020 number.
Nope.
The net increase in terms of crude capacity around the Enterprise system as a result of Midland to ECHO, what was the number that you had said on a net basis on the prepared remarks?
On a net basis, I think what we're saying is we're adding Midland to ECHO 4, which is 450,000 barrels a day. By optimizing the system, I think what we're taking off or reducing is about 370,000. Yeah.
I believe it's 70.
Yeah. I think the net addition is about 70,000 barrels a day, Brent.
I believe.
You heard in the prepared remarks, we're moving a lot of crude. For example, in Midland ECHO 1, I think we're moving 620,000 barrels a day, the variable cost on that has gone up significantly. We could take that to 450,000 barrels a day and reduce our cost dramatically. We could convert some of it back to NGL service, which we think we'll have to do. Overall, we're adding 70. At an optimum cost, we move about 1.3 million barrels a day. If the market wants it, we can ramp that up to 1.8 million barrels a day. There is an unbelievable amount of flexibility within our system to change what we're moving.
Okay. That makes perfect sense. For my follow-up question, I think it was about two years ago this quarter that you had reset the distribution growth policy. Just wondering, has anything changed in terms of your views on buybacks and distribution growth rates? Are you comfortable with the current distribution growth rate? On the buyback side, is it just for offsetting the drip and the employee purchases, or is there an evolving view on that?
Shneur, this is Randy. I think currently, on what we've said around buyback program anyway, is we were looking to be opportunistic with that. Given our success in underwriting attractive growth projects, I think that's still where our mindset is. Again, we get asked from time to time about a programmatic buyback. Again, I think we'd rather allocate our capital to good growth projects as opposed to coming in and doing programmatic buyback. Then as far as distribution growth is concerned, really, we take a look at that year by year. We're in the early stages of our planning process for 2020. We'll take a look at that and probably will come in and provide some guidance on 2020 distribution growth in January, really about on the same timeline that we did earlier this year.
All right, perfect. Thank you very much, guys. Appreciate the color.
Your next question comes from the line of Jeremy Tonet. Your line is now open.
Hi, good morning.
Good morning.
Just wanted to start off with the CapEx and the range that you guys had provided there, the $3 billion-$4 billion. I was wondering, what would drive the lower end versus the higher end there? You mentioned JVs potentially being a part of that, but it's kind of $3 billion was secured, and the upper end could be JVs or maybe there's some other project announcements that you could secure over the course of the year that could drive you to the higher end, or any other things driving the moving pieces there?
Three to four this year. Next year's three to four.
You want to take that?
Yeah, Jeremy, honestly, I think we're still in that range of $3-$4. We've got a couple of things that we're working on that, if we are successful in underwriting that, frankly, that would still keep growth CapEx under that $3-$4 range.
Got you.
As Jim mentioned earlier, SPOT is not included in 2020. While we've sanctioned the project, the project is still subject to government approval, so we have elected not to include that in our forecast for growth CapEx for 2020.
Okay, that's helpful. Thanks. One more question. I think you talked about the flexibility between crude oil and NGL pipelines, kind of being able to flex back and forth. Was just wondering if there would ever be a scenario where one of them could be swapped into natural gas service if the market really demanded it in the near term, and then swapped it back to liquid service at a later date, if that could ever make sense, if that's possible.
Well, Jeremy, I wish it was possible, but it's not. It's strictly going to be a liquids pipeline with flexibility between NGLs and natural gas, I mean, crude oil, unless Graham, you think differently.
No, I don't see that happening.
Well, wish it could.
That's all for me. Thanks for taking my question.
Your next question comes from the line of Colton Bean from Tudor, Pickering, Holt & Co. Your line is now open.
Appreciate the detail on the CapEx program. Just with that 2020 midpoint of $three and a half billion, any preliminary thoughts on financing for the year? Should we anticipate debt funding as basically the balance between your retained cash flow and your CapEx, or would you still target something closer to 50% and maybe any excess cash allocated towards some of those opportunistic buybacks?
Yeah. We'll see what we have next year. I think we still think about funding it 50% debt and then, if you would, 50% retained cash flow. That's sort of our going-in position.
Got it. If that resulted in excess cash, would that be where you guys look at doing something beyond the drip offset?
We'll just take a look at market conditions at that point in time.
Understood. Just a quick one on operations. Fairly significant step down in equity NGLs this quarter. I think historically you've all talked about a number in the 130,000 barrel a day range as kind of your C3 plus or propane plus type recovery. It doesn't seem like this quarter's result would be solely attributable to more rejections. Just any incremental context you can provide on that 111,000 equity NGLs?
I think most of that's probably ethane rejection. Where's Natalie or Brad or whomever?
Yeah, this is Brad. Most of that, I'll agree with Jim. Most of that's attributable to, I'd say, rejection across the system, whether it be the Rockies or some of the other places.
Got it. That's helpful.
Your next question comes from the line of Jean Ann Salisbury from Bernstein. Your line is now open.
Good morning. Are you able to comment on whether CapEx costs for the two new Midland ECHO pipelines are expected to be noticeably lower than the first one?
Just really comparable.
Yeah, comparable. Not noticeably lower.
Okay. Thank you. As a follow-up, the ATEX expansion announcement kind of comes as rig count is falling in Appalachia. Can you just give any more color on whether this is like customers are still expecting growth, or if it's more of a backup solution for when or if Mariner East is down?
Yeah. This is Tug here. I can just comment that we had a customer approach us, the valuable, reliable takeaway down to Mont Belvieu, and we closed a successful open season. That's all I can comment on that one.
Okay. Is it possible to comment on if there's been any change or lengthening to the existing ATEX terms?
To the existing ATEX term? There's not been a change, no.
Okay, cool. Thanks. That's all for me.
Your next question comes from the line of Tristan Richardson from SunTrust. Your line is now open.
Hey, good morning, guys. Just following up on some of your comments on identifying strategic partners on projects in some of your markets. Do you see the greater opportunity on new projects that may not be in service yet, or more on existing capacity currently in place?
It's kind of hard to do it on existing capacity. I think probably it's more new projects that we would look at. You never say no to anything. It depends on what a person's bringing to the table. If you got, for example, a petrochemical customer that wants to have a big offtake, then you might do something on existing assets. By and large, it's new assets.
Helpful. Thank you. The follow-up, you also talked about opportunities to optimize existing processing capacity. Could you talk about to the extent this is EPD reacting to the U.S. production environment shifting or just looking at assets that have utilization upside?
Take or pay contracts, which means you're going to get paid, but it doesn't mean you're going to get the production. Typically, we have downstream numbers in our economics. That's an issue. One of the things we have on acreage dedications, if people aren't performing up to the production profile that the plant was built on, at a certain point, we have the right to reduce their MDQ and use that capacity somewhere else. It's a safeguard that we always have the right to, at a certain point in time, to claw back and reduce the MDQ and use it with someone else.
Helpful. Thank you guys very much.
Your next question comes from the line of Spiro Dounis from Credit Suisse. Your line is now open.
Hey, good morning, everyone. First question, just with respect to the overall growth strategy. I think we've seen you guys lean in somewhat aggressively here to the next part of this cycle, where we're seeing maybe a lot of your peers retrench a little bit. You just sort of stand out in that respect. Curious, is it fair to say that you're deploying maybe a similar strategy to LPG exports, where your major focus at this point is on capturing market share and dissuading competition? Is it a little more nuanced than that?
You want to take a part of that and then throw it back to me?
This is Brent, and I think you hit it, is that we've seen people pull back as it relates to midstream competitors. What we've seen as people pull back is probably over the last six months to nine months, we've seen some incredible opportunities in front of us that have very good returns, that have upside either downstream or upstream. On top of that, it's with very credit-worthy customers. At some point, when we're seeing the returns that we're seeing on these projects, it's just a very good project for Enterprise.
I think the other thing where you're seeing us, and it's along the same lines, but we have a broader product line than we can offer. In our petrochemical midstream services business, we are very focused on that, building up PDH2. Also what we're doing is opening up our storage and distribution systems such that petrochemicals, it's the same model we have in crude and NGLs. Store it, distribute it, or export it.
I think you saw Enterprise back out of certain projects two years ago and three years ago. We were pretty vocal about the projects that we wouldn't go after. I think at the end of the day, it served us well. When we look at where to deploy capital right now, whether it's an acquisition or whether it's still organic growth, it still makes much more sense to do organic growth projects that work for Enterprise.
Yeah. Makes a lot of sense. On the petrochemical comment, seeing octane enhancement really strong again this quarter. I'm guessing that's just a continuation of kind of what we're seeing along tier 3 shortages of octane. I think we get the sense that maybe octane's going to be tight again or even tighter next year in 2020. Just curious, do you think about margins the same way going into next year on octane enhancement, and is there any sort of expansion or anything you can do in that business to capture more of that?
This is Chris. We expect to see the same sort of spreads next year as we have this year. In fact, we talk about how we hedge forward, and we've done some of that already for 2020. Then in terms of expansions, we have our iBDH project that's coming online at the end of this year, some of that volume also goes into the alkylation market.
Great. Good luck to the Astros.
Next question comes from the line of Pearce Hammond from Simmons Energy. Your line is now open.
Thank you, and good morning. Given the fast declining Baker Hughes rig count and the likelihood that 2020 E&P capital spending activity and production will be lower than current consensus estimates, how do you see that impacting EPD's 2020 outlook, and what are you hearing from some of your customers?
One of the things, if you look at who our customers are, they're large producers. I don't see someone like Exxon or Chevron slowing down. I don't know about EOG. I'll throw it to Tony. Yeah, we see what you're talking about, but the people that we have that are really the anchors to our system are the very large guys. Do we have any small count people at all?
Not on contracts.
Just minimum. Tony, you want to throw something in?
When we sit down and talk to people, and we talk to our customers a lot, what we hear time and time again, and we read everything that they say, is that their capital's going to be down, but their production's going to be up.
Because of efficiency and in some cases, completion of DUCs. While the industry probably will never repeat what it did in 2018 relative to growth, when, and I'm speaking for Enterprise, when we read people project that production's actually going to roll over, it's very hard in our type curve models and our forecast to make that happen. Brent?
No, we've met with numerous producers, customers over the last month, and every single one, with the exception of one, has said that volumes are going to be up, capital's going to be down. Usually it's about a ratio of 10%-15% down on capital, 10%-15% up on volumes. There's only one customer who said that crude oil volumes would be flat, and they said capital will be down, but our gas production is going to decrease. I think anybody that's going after crude oil, that has the associated NGLs with it, I think what we've heard is that their volumes are going up. I think gas-centric type volumes will be going down.
Great. That's super helpful. Thank you. My follow-up, do you see enough customer interest to consider further LPG dock expansions above and beyond what you've already announced?
I think if you look at what we have on the table and the expansions that we have and the cost associated with it, with the returns that we get, at the fees we're getting, I certainly, as our expansion comes up in the fourth quarter of 2020, we've evaluated further expansion opportunities, and that's obviously the path that we'll probably go down.
Are you full?
That's a relative question. In terms of capacity that we have contracted right now, there's a little bit of a gap of opportunity that we have out there, and we'll let crude oil or NGLs determine how we use that capacity. In terms of what we have contracted for the next several years, it's north of 90%.
Great. Thank you very much.
Next question comes from the line of T.J. Schultz from RBC Capital Markets. Your line is now open.
Great. Thanks. Just a question on the Acadian expansion. Is that driven more by growth in Haynesville production you are expecting or are you bringing more Permian gas ultimately through that system, something you guys have talked about before with the combo plan of Enterprise North Texas, moving gas over into the area?
I think it's mainly giving a market to those Haynesville producers. Their market was either the River Corridor or Perryville. Help me here. Am I right?
Yes.
This just gives them a market. I'll tell you, that lateral, if I'm not mistaken, Brent, it's sold completely out. Natalie?
Sold out.
I'll let Natalie answer some.
Well, like any other project that we do, it is definitely sold out with creditworthy producers behind it. It will get producers to the LNG export facilities in South Louisiana and Southeast Texas. A promising and exciting project for us.
Okay, thanks. Moving out of the Haynesville, do you still expect to move gas into Beaumont? I think you guys have talked about the Lumberjack pipe before. Is the primary demand pull into Louisiana here?
Yeah. I'll take it and then let Natalie jump in if she wants to. We're still working that project, but I will be honest, it's not flying off the shelves right now. Is that fair, Natalie?
That's fair.
Okay. Understood. Thank you.
Next question comes from the line of Keith Stanley from Wolfe Research. Your line is now open.
Hi. Good morning. Randy, you mentioned how the backlog, I guess you added $3.6 billion of new projects to it, and I assume PDH 2 and Midland to ECHO 4 are the larger parts. Are there any other chunkier additions? I wasn't thinking those two alone would be really near the $3.6 billion. I'm not sure if ATEX or the Gillis Lateral are meaningful capital.
Yeah. What may have also been included in that was also Midland to ECHO 3 could have potentially been in there as well. PDH, Midland to ECHO 4, and Gillis.
Okay. Sorry to clarify, Midland to ECHO 3 is not part of that?
I think it was included when we announced earnings in the second quarter.
Okay. Mainly those two projects and Gillis.
Follow-up question. Can you give any more color on Midland Echo 3 in terms of, I guess, what's involved in the project? You guys announced it just this past summer. It's a pretty tight timeline to the third quarter of 2020. I'm just wondering how much is new pipe versus expansion of infrastructure or repurposing on that line.
It's all new pipe. You're talking about how quick we're doing it. We were working that project long before we announced it.
We had a running head start. Is that fair, Joe Graham?
I think that's it. We were doing a lot of work upfront to make sure we were ready to hit the ground running. Yes, that's fair.
Got it. Thank you.
This is just it. Yeah. This is it.
Next question comes from the line of Michael Lapides from Goldman Sachs. Your line is now open.
Hey, guys. Thanks for taking my question. Real quick, can you just talk about the returns on capital or the EBITDA multiple or the operating margin, however you wanted to discuss it, for Midland Echo 3 and 4 versus what you got when you first built some of the Permian crude pipes, meaning maybe Midland Echo 1 and 2, for example?
Yeah, Michael, this is Randy. I'll take the first shot at it. Again, we won't get into talking returns on any specific project, but if you come back in, and I just say that they're comparable to our historical returns.
Most midstream projects fall in that range of 10%-15%. I think what we have said is the flexibility that Midland Echo four does provide us is just by coming in and being able to save on those variable operating costs that Jim spoke to earlier. We could come in, and that provides us a good base-level return on Midland Echo four that really wasn't available on some of the other pipes.
Got it. I'm just asking that given a lot of people expect a sizable Permian overbuild in the next year or so, actually really starting now, and just trying to think about how that impacts you differently than how it may impact some of the other players, the midstream operators in the business.
Brent, why don't you try to take this?
Let me take a shot at that. It's a good question, and we've talked about this before, but if you look at total capacity that's coming out of the basin, you can run the numbers and say, well, there's excess capacity. I think you're seeing it on the pipelines that have come up recently and the pipelines that will come up over the next six months is you really have to go back to what is their supply source. The beauty of our system is the fact that we have that Midland pricing point and that we have supply to fill up our pipes. You have to look to see where those barrels are going.
The reason we're getting contracts and the people that are typically signing these contracts are people that are going to continue to drill, that are re-upping for increased volumes with Enterprise. They want to go to Houston. If you look at Midland to ECHO 4, there's one crude pipeline that we have that's not full. We have one crude pipeline that's not full, and that's the Eagle Ford pipeline system. The issue with it is probably not a whole lot different than some of the new pipelines that have come up in the Permian Basin recently, is it does not have a daily supply source. What you're dealing with is you have barrels that are trucked in, you have small gathering lines that go into that Eagle Ford pipeline system.
Ultimately, it's underperforming on a much greater scale than any other pipeline we have in our portfolio. What we did is went back to Midland and brought a daily supply source into that pipeline. We also have the opportunity to do dual contracts for people that have Permian acreage and people that have Eagle Ford acreage. Going forward, our expectation is that pipeline is going to be full, no different than the rest of our crude pipelines. That was the thought behind that. Recognize the fact that we have contracts that support that capacity.
Got it. That's super helpful. Then one follow-up. You all talked in your opening remarks about potentially reclaiming some of the capacity on the gas processing plants. I don't know whether those were the new ones built or whether those were legacy ones in the Permian, but just curious. You then later in the Q&A talked about how most of your customer base are the majors and that they haven't really been reducing production. What's driving the open capacity on your processing if your biggest customers, the bulk of your customers aren't really cutting production growth rates?
This is Brent again. In terms of the majors, they're majors for a reason. They're probably majors because they have a lot of acreage. When you look at processing plants, that is specific acreage to an area. If you look at crude oil in their total portfolio, they are achieving what they signed up for, in most cases exceeding what they signed up for. Their issue is some areas are better than other areas. There may be an instance where we have a plant that has certain acreage that probably when they go tier up their acreage, it's number 4 or number 5 on the list, and they're focused on probably a more crude-centric play. It benefits us on the crude oil side, but on the processing side, they're underperforming.
We have provisions in our contracts to allow us, if you're underperforming, to go back and reclaim that capacity, and that's what we'll look at doing.
We have people we're working with that we know that we could fill that capacity with.
Got it. Thank you, guys. Much appreciate you all taking all three of my questions.
Next question comes from the line of Uche Oputa from Bank of America. Sir, your line is now open.
Good morning, everyone. A couple of questions from me. First I wanted to touch on the recent increase in VLCC freight rates globally, and how that has affected your export volumes. Although the spike has subsided recently, I think the rates still are elevated. Can you share what you're seeing on your end?
Well, Brent, you're dominating this. Go for it.
I think, we saw the spike like you all did. I'm going to put a plug in here on this. There was a spike, and we saw record freight rates on VLCCs, and that's an issue. That's an issue for producers who go to markets that are forced to export. In Houston, what we saw is people basically backed off. They backed off from exporting, and the market was trying to fill itself out, and things got to reset, but that takes time. In this case, it took probably a couple of weeks, and we saw it kind of settle into a number. The luxury we have and why people choose to go to Houston is because you have that luxury.
You have the ability to store barrels, and you have the ability to move barrels to refiners, and you have the ability to move barrels downstream. What you're seeing in other markets that are a forced export is either they are severely discounted to Houston or the barrels aren't flowing to the water. You saw big players that are going to terminals outside of Houston being forced to sell back in the field in the Permian Basin. When stuff like that happens, to me, going to Houston is an opportunity for Enterprise and an opportunity for our customers. It's been reset and volumes are increasing. You'll see volumes probably when we come out with our earnings. You'll see volumes for October are very strong.
There was a period in time there where I think it caused the market to pause and say, "Is this the right idea to go to this terminal?" To me, it's probably a selling point for us going forward.
Got it. Maybe a follow-up to your comment on ethane rejection earlier. Can you discuss what the dynamics is right now across your system in terms of pipeline volumes and also downstream, how that has impacted the frac spreads that you're seeing?
I think the rule of thumb in general is the further away you are from Mont Belvieu, the more pipeline capacity that is available based on ethane rejection. In terms of frac use.
We talk about full.
We're full. I mean, when you look at fractionation, the closer you are to the pricing point, the more likely you are to be full. When you look at tertiary fractionators, and we've got some in Louisiana, there's also a bunch in the Mid-Continent, but the closer you are to the pricing point where all these NGLs are leaving, we'll call that the water, the more full you are.
Got it.
In October, I think we set a record on ethane and LPG exports of over 21 million barrels. I don't know what we're doing in crude, do you?
It's
Another million?
It'll probably set a record.
Got it. No, that's helpful. Thank you, guys.
Our last question comes from the line of Chris Sighinolfi from Jefferies. Your line is now open.
Hey, good morning, guys. Thanks for all the added color. I have two. First question, just to circle back on the NGL side of your business. Tristan and Michael asked about the idea of pulling back the gas processing capacity from your acreage dedicated producers. You had noted this is a function of contract terms and something that's always been available to you. I'm just curious, in mentioning it now, are you signaling you're going to be more aggressive in pulling back this capacity because you see mismatches now that didn't exist before and because investors are more focused maybe on CapEx avoidance? I guess, is it a change in strategy or are you simply flagging it so that we're all aware of the contract optionality?
Yeah, I think it's to make you aware of it. We get so many questions on capital discipline. We have ways to increase our business and our throughput without spending money, and I think what we're saying is that's one way, and I don't think it's not a change in strategy. It's just we're going to start doing it. Well, I mean, we're going to do it like we always have.
If you look at producers, when they go rank their acreage, there's certain acreage that we have in that area that ranks number 1 for one producer and it ranks number 5 for another producer. At the end of the day, if it works for producer A, that capacity should probably go to producer A because producer B is not going to produce it for some period of time. That's what we're doing.
I mean, it's really not a change. It's not a change. Natalie or Brad, I think it's in every acreage dedication deal we have, isn't it?
I agree. It's just an optimization technique that we're highlighting here. It's not saying we're something new. We've done this the whole time we've contracted these plants.
Okay. That's helpful. That I suspected. I just wanted to clarify. Final question from me, and this might be for Randy, but I'm not sure. It's probably a collaborative answer. Earlier questions on buybacks, and you noted EPD's preference to invest in projects that exceed the hurdle rate versus a ratable buyback program. I'm just curious, we get a lot of questions about terminal states and how you weigh sort of the terminal state consideration of that analysis. For example, another crude pipeline project, realizing that Brent talks about not every landed location is equal and there are contracts in place that justify the expansions. There's also downstream considerations. I'm just curious, when you get to beyond the contract term market, how do you view that investment versus the permanent retirement of a unit and all future distributions tethered to a contract?
Yeah. Chris, a little bit what you're talking about is really how do we feel about recontracting when the base contracts are up. I'm going to toss it to Jim or Brent on that.
Yeah, I think a good example would probably be the ECHO, wouldn't it? Where when we put that pipeline in service, I think we were getting $0.25. Huh? Yeah. Between $0.25 and $0.35 is what we were getting. Now what we're getting on that spread is what Ian's done in here, $0.12 to $0.15. You would look at that and say, "Boy, that's a recontracting issue." What we're getting in our gathering is probably $0.20 to $0.30. If I look at it all in, we're getting the same revenues, just shifted as to where we're getting it. The Eagle Ford pipeline that Brent talked about, one of the things that tying it back to Midland does, it really mitigates our recontracting risk because we've tied it back to a daily market that we can move crude out of.
I don't know what the spreads are going to be, but we have contracts that support that. I think if I look at all of our crude contracts out of the Permian, Brent, you're 90% contracted on those, and those terms don't end for seven or eight years, is what I remember.
I've taught 10 years, nine years.
Yeah. Damn near every one of those contracts, I think with the exception of one, have an associated dock deal. We got nine to 10 years left at pretty decent fees on the transport, every one of them have a dock deal, and some of them may have storage deals to go along with that.
Great. Appreciate that color.
Yeah. Chris, a little bit, when you think about it, as far as recontracting and the underlying cash flow assumptions, that enters into your buyback consideration too, because it's all embedded in the cash flow stream of, if you think about it, cash flow per unit.
Oh, yeah. For sure. I think what I was just noting is, Jim's talking about the dividend aristocrats. You guys have had a really phenomenal schedule of quarterly raises here through some pretty tumultuous periods. I think if we look at it, we look at this growth and the payout, that feels fairly secured. Obviously, everybody's susceptible to risks on the business longer term. I was just kind of trying to frame up, Randy, how you guys think about that uncertainty versus sort of the certainty of cash distribution growth, when you think about buybacks and the retirement of that stream, how it all factors together. Anyway, appreciate the call.
Michelle, this is Randy. With that being our last question, the company's going to go ahead and sign off here. We'd like to thank everybody for joining us today. If you would give our listeners the replay information for the call. Thank you very much. Have a nice day.
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