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Enterprise Products Partners LP (NYSE:EPD)
Q3 2019 Earnings Call
Oct 28, 2019, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Ladies and gentlemen, thank you for standing by and welcome to the Q3 2019 Earnings Conference Call. [Operator Instructions] I would now like to hand the conference over to your speaker today, Mr. Randy Burkhalter. Sir, you may go ahead.

Randy Burkhalter -- Vice President, Investor Relations

Thank you, Michel. 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 Enterprises' 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 as 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 the call over to Jim.

A. J. Teague -- Director and Chief Executive Officer

Thank you, Randy. This morning I'll cover our earnings first and then give you an update on our projects list.

Starting with the 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 continue 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 Aristocrats 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 -- in 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 in the last commodity cycle for energy. We manage Enterprise to provide financial stability in 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 sanctions -- project sanction today, we currently expect our growth capital expenditures in 2020 will be in the range of $3 billion to $4 billion.

Given the size and integrated nature of our systems, we are 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 for 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. Sometime our options are contractual; this includes using contract provisions to call 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 for large producers and large trading firms looking to sell crude into international markets that demand quality. We recently sanction 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 is 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. Furthermore, 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 this spread is over 250 [Phonetic], 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 to $0.20 a barrel. In addition to savings from optimizing volumes across the Midland-to-ECHO pipeline system, these expansions also give us the flexibility to divert crude 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. As market supported, M2E4 could add up to 540,000 barrels a day of incremental capacity. In short, look at the map and 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 the zero capital.

The third major project we announced during the quarter is our PDH2 plants. Lyondell is one of the largest petrochemical companies of 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 have negotiated a fixed cost engineering procurement and construction contracts with SMB to build PDH2. We have a long history with the SMB dating back to 1995. They led construction on nine of our NGL fractionation -- fractionator 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 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 quarter. We also announced a successful open season for the expansion of our 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 fractionator 10 and 11 at Mont Belvieu, gas processing plants at [Indecipherable] the Permian and Panola in East Texas and crude oil petrochemical ethane and LPG dock expansions.

With the second PDH, our iBDH 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 US petrochemical industry is significantly advantaged to virtually all of the world because of the low cost feedstocks and significant infrastructure and we 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 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 chain -- the value of that incremental volume brings to our system. We have a long history of optimizing our systems attracting strategic partners, converting assets and churning overpriced acquisitions. We are a Company that prides itself in consistency and distributions, solid balance sheet and 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.

W. Randall Fowler -- Director, President and Chief Financial Officer

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% and 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 Gillis lateral -- 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 links are for 10 years or more. Assuming our historical returns on capital, these assets have the potential to generate up approximately $1 billion to $1.3 billion of incremental gross operating margin for the 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 contribution 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 billion 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 on 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 15, 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 but 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 up for questions.

Randy Burkhalter -- Vice President, Investor Relations

Okay, Michel, we're ready to take questions from the audience. And I would remind our audience that we would limit our questions to one question and one follow-up.

Questions and Answers:

Operator

[Operator Instructions] Your first question comes from the line of Shneur Gershuni. Your line is now open.

Shneur Gershuni -- UBS -- Analyst

Hi, good morning, everyone. Maybe just to start off on the capex front a little bit here, you know, appreciate the color that you gave around Midland-to-ECHO in the prepared remarks. Just wanted A, to clarify that the total net increase in capacity was about 500,000 barrels, and then as part of that in terms of your capex number for this year -- sorry, for 2020, does that also include the spot terminal or is that not part of 2020 number?

A. J. Teague -- Director and Chief Executive Officer

It is a part of the 2020 number.

Shneur Gershuni -- UBS -- Analyst

And the net increase in terms of crude capacity around the Enterprise system as a result of Midland-to-ECHO, that's -- what was the number that you've set on a net basis on the prepared remarks?

A. J. Teague -- Director and Chief Executive Officer

On a net basis, I think what we're saying is we're adding our Midland-to-ECHO 4, which is 450,000 barrels a day, if by optimizing the system, I think what we're taking off reducing is about 370,000 --

W. Randall Fowler -- Director, President and Chief Financial Officer

[Indecipherable].

A. J. Teague -- Director and Chief Executive Officer

So I think the net addition is about 70,000 barrels a day, Brent. And you heard in the prepared remarks, yes, we're moving a lot of crude. For example, in Midland-to-ECHO 1, I think we're moving 620,000 barrels a day and the variable cost on that has gone up significantly. So if you remove -- we could take that to 450,000 barrels a day and reduce our costs dramatically. And then we could convert Seminole back to NGL service, which we think will have to do. So overall, we are adding 70 [Phonetic]. We could at an optimum cost would move about 1.3 million barrels a day, but if the market wants it, we can ramp that up to 1.8 million barrels a day. So there is an unbelievable amount of flexibility within our system to change what we're moving.

Shneur Gershuni -- UBS -- Analyst

Okay. That makes perfect sense. And then for my follow-up question. I think it was about two years ago this quarter that you would 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 and then on the buyback side is just for offsetting the DRIP and the employee purchases or are there -- is there an evolving view on that?

W. Randall Fowler -- Director, President and Chief Financial Officer

Hey, 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, and again, we get asked from time to time about a programmatic buyback, but again, I think we'd rather allocate our capital to good growth projects as opposed to coming in and doing programmatic buyback. And then as far as distribution growth is concerned, really we take a look at that year by year. We are in the early stages of our planning process for 2020 and 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.

Shneur Gershuni -- UBS -- Analyst

All right, perfect. Thank you very much, guys. Appreciate the color.

Operator

Your next question comes from the line of Jeremy Tonet. Your line is now open.

Jeremy Tonet -- JPMorgan -- Analyst

Hi, good morning.

A. J. Teague -- Director and Chief Executive Officer

Good morning.

Jeremy Tonet -- JPMorgan -- Analyst

Just wanted to start off with the capex in the range that you've had provided there, the $3 billion to $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 is kind of $3 billion, what secured and the upper end could be JVs or maybe there is 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?

W. Randall Fowler -- Director, President and Chief Financial Officer

Yes, Jeremy, honestly, I think we're still in that range of $3 billion to $4 billion. We've got a couple of things that we're working on that, if we are successful in underwriting that that frankly that would still key growth capex into that $3 billion to $4 billion range. And then 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.

Jeremy Tonet -- JPMorgan -- Analyst

Okay, that's helpful, thanks. And 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. I was just wondering if there ever be a scenario where one of them could be swapped into natural gas service if the market really demanded 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.

A. J. Teague -- Director and Chief Executive Officer

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 -- and I mean, crude oil unless, Graham you think differently?

Graham W. Bacon -- Executive Vice President and Chief Operating Officer

No, I don't see that happen.

A. J. Teague -- Director and Chief Executive Officer

Wish it could.

Jeremy Tonet -- JPMorgan -- Analyst

That's all from me. Thanks for taking my question.

Operator

Your next question comes from the line of Colton Bean from Tudor, Pickering, Holt & Company. Your line is now open.

Colton Bean -- Tudor, Pickering, Holt & Co. -- Analyst

So I appreciate the detail on the capex program. Just with that 2020 midpoint of $3.5 billion, any preliminary thoughts on financing for the year? Should we anticipate debt funding is 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 toward some of those opportunistic buybacks?

W. Randall Fowler -- Director, President and Chief Financial Officer

Yes. We'll see what we have next year. I think we're still looking -- we still think about funding it 50% debt, and then if you would 50% returning cash flow, that's sort of our going-in position.

Colton Bean -- Tudor, Pickering, Holt & Co. -- Analyst

Got it. And if that resulted in the excess cash, would that be where you guys look at doing something beyond the DRIP offset?

A. J. Teague -- Director and Chief Executive Officer

We'll just take a look at market conditions at that point in time.

Colton Bean -- Tudor, Pickering, Holt & Co. -- Analyst

Understood. And just a quick one on operation, so fairly significant step down equity NGL this quarter. I think historically, you've all talked about a number in the 130,000 barrel a day range is kind of your C3 plus or propane plus type recovery. So it doesn't seem like this quarter's result would be solely attributable to more rejections. So just any incremental context you can provide on that 111,000 barrels per day in equity NGLs?

A. J. Teague -- Director and Chief Executive Officer

I think most of that's probably ethane rejections. Where is Natalie, Brad or whomever?

Bradley Motal -- Senior Vice President

This is Brad. Most of that -- Jim, most of that's attributable to ethane rejection across the system, whether it be the Rockies or some of the other places.

Colton Bean -- Tudor, Pickering, Holt & Co. -- Analyst

Got it. That's helpful.

Operator

Your next question comes from the line of Jean Ann Salisbury from Bernstein. Your line is now open.

Jean Ann Salisbury -- Bernstein -- Analyst

Good morning. Are you able to comment on whether capex cost for the two new Midland-to-ECHO pipelines are expected to be noticeably lower than the first one?

A. J. Teague -- Director and Chief Executive Officer

Just really comparable --

W. Randall Fowler -- Director, President and Chief Financial Officer

Comparable, not noticeably lower.

Jean Ann Salisbury -- Bernstein -- Analyst

Okay, thank you. And as a follow-up the ATEX expansion announcements kind of comes as rig count is falling in Appalachia. And 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 [Indecipherable] down?

Michael C. Hanley -- Senior Vice President

Yeah, I think this is Tug here. I can this comment that you know we had a customer approach us the valuable reliable takeaway down to Mont Belvieu, and we closed the successful open season, that's all I can comment on that one.

Jean Ann Salisbury -- Bernstein -- Analyst

Okay. And is it possible to comment on if there has been any change or lengthening to the existing ATEX terms?

A. J. Teague -- Director and Chief Executive Officer

To the existing ATEX term, there is not going to change now.

Jean Ann Salisbury -- Bernstein -- Analyst

Okay, cool. Thanks. That's all for me.

Operator

Your next question comes from the line of Tristan Richardson from SunTrust. Your line is now open.

Tristan Richardson -- SunTrust -- Analyst

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?

A. J. Teague -- Director and Chief Executive Officer

It's kind of hard to do it on existing capacity. I think probably it's more new projects that we would look at. I mean, you never say no to anything. if it depends on what a person to bring into the table; if you got to, for example, a petrochemical customer that wants to have a big offtake and you might do some on existing assets, but, by and large, it's new assets.

Tristan Richardson -- SunTrust -- Analyst

Helpful. Thank you. And then 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 US production environment shifting or also more just looking at assets that have utilization upside?

A. J. Teague -- Director and Chief Executive Officer

Everybody, there is a big, there is take or pay contracts, which means you're going to get paid, but that mean you're going to get the production. Typically, we have downstream numbers in our economics. So that's an issue. One of the things we have on our acreage dedications, if people aren't performing up to the production profile that the plant was built on, then as a certain point we have the right to reduce their MDQ and use that capacity somewhere else. So it is safeguard that we always have the right to, at a certain point in time, to call back and use -- reduce the MDQ and use it with someone else.

Tristan Richardson -- SunTrust -- Analyst

Helpful. Thank you guys very much.

Operator

Your next question comes from the line of Spiro Dounis from Credit Suisse. Your line is now open.

Spiro Dounis -- Credit Suisse -- Analyst

Hey, good morning, everyone. First question just for with respect to the overall growth strategy. I think we've seen you guys lean in somewhat aggressively year to the next part of the cycle where we're seeing maybe a lot of your peers retrenched a little bit. So you just sort of stand out in that respect. Securities, is it fair to say that you're deploying maybe a similar strategy LPG exports where your major focus at this point is on capturing market share and dissuading competition or is it a little more nuance than that?

A. J. Teague -- Director and Chief Executive Officer

You want to -- a part of that, I mean, [Speech Overlap]

Brent B. Secrest -- Executive Vice President and Chief Commercial Officer

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, very good returns that have upside, either downstream or upstream, and on top of that, it's with very creditworthy customers. So 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.

A. J. Teague -- Director and Chief Executive Officer

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. Our petrochemical midstream services business, we are very focused on that, building the BDH2, but 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, stored, distributed or exported.

Brent B. Secrest -- Executive Vice President and Chief Commercial Officer

But I think you saw Enterprise back out of certain projects, two years ago and three years ago and we were pretty vocal about the projects that we wouldn't go after and I think at the end of the day is served us well. But when we look at where to deploy capital right now, whether it's an acquisition or whether it's still organic growth, is still makes much more sense to do organic growth projects to work for Enterprise.

Spiro Dounis -- Credit Suisse -- Analyst

Yeah, makes 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 and I think we get a sense of maybe octane is 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 that you can do in that business to capture more of that?

F. Christopher D'Anna -- Senior Vice President

This is Chris. We're seeing -- we expect to see the same sort of spreads next year as we have this year, and in fact, we talk about how we hedge forward and we've done some of that are ready for 2020. And then in terms of expansions, we have our iBDH project that's coming online at the end of this year. And so some of that volume also goes into the alkylation market.

Spiro Dounis -- Credit Suisse -- Analyst

Great. If you look at the Astros.

Operator

Next question comes from the line of Pearce Hammond from Simmons Energy. Your line is now open.

Pearce Hammond -- Simmons Energy -- Analyst

Thank you and good morning. Given the fast declining Baker Hughes rig count and the likelihood, the 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?

A. J. Teague -- Director and Chief Executive Officer

One of the things, if you look at who our customers are, they are 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. But 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. Well, I don't think we have a -- do we have any small cap people at all?

Graham W. Bacon -- Executive Vice President and Chief Operating Officer

Not on -- just contractually, just minimum.

A. J. Teague -- Director and Chief Executive Officer

Tony, you want to fill some in?

Anthony C. Chovanec -- Senior Vice President

When we initially talk to people and we talk to our customers are lot, what we hear time and time again and we read everything that they say, is that our capital is going to be down but their production is going to be up because of the efficiency and in some cases, completion of DUCs. So 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 is actually going to roll over, it's very, very hard in our type curve models in our forecast to make that happen. Brent?

Brent B. Secrest -- Executive Vice President and Chief Commercial Officer

I mean, we've met with numerous producers, customers over the last, call it, the last month and every single one with the exception of one has said the volumes are going to be up and capital is going to be down, and usually it's about a ratio of 10%, 15% down on capital; 10% to 15% up on volumes. There is only one customer who said the crude oil volumes would be flat and they said capital will be down, but our gas production is going to decrease. And so I think anybody that's going after crude oil, there has the associated NGLs with it. I think what we've heard is their volumes are going up, but I think gas centric type volumes will be going down.

Pearce Hammond -- Simmons Energy -- Analyst

Great, that's super helpful. Thank you. And then my follow-up, do you see enough customer interest to consider further LPG dock expansions above and beyond what you've already announced?

Anthony C. Chovanec -- Senior Vice President

I think if you look at what we have on the table and the expansions that we have and the cost associated 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 in the past that will probably go down.

Pearce Hammond -- Simmons Energy -- Analyst

[Indecipherable]

Anthony C. Chovanec -- Senior Vice President

No actually that's a relative question. So in terms of capacity that we have contracted right now, there is a little bit of a gap of opportunity that we have out there and we'll like crude oil or NGLs determine how we use that capacity, but in terms of what we have contracted for the next several years, it's north of 90%.

Keith Stanley -- Wolfe Research -- Analyst

Great, thank you very much.

Operator

Next question comes from the line of TJ Schultz from RBC Capital Markets. Your line is now open.

TJ Schultz -- RBC Capital Markets -- Analyst

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 is something you guys have talked about before with the combo plan of Enterprise North Texas moving gas over into the area?

A. J. Teague -- Director and Chief Executive Officer

I think it is mainly given the market to those Haynesville producers. The market was either the [Indecipherable] our Perryville, help me here, am I right? And this just gives them a market and I'll tell you that lateral, if I'm not mistaken, Brad, it's so completely out our badly. I'll let Natalie answer some.

Natalie K. Gayden -- Senior Vice President

Well, like any other project that we do, it's 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.

TJ Schultz -- RBC Capital Markets -- Analyst

Okay, thanks. So moving out of the Haynesville, do you still expect to move gas in the Beaumont, I think you guys had talked about the Lumberjack pipe before is the primary demand pull into Louisiana here?

A. J. Teague -- Director and Chief Executive Officer

I'll take it, and let Natalie to jump in, if she wants to. We're still working that project, but I will be honest, it's not plan off the shelves right now. Is that fair, Natalie?

Natalie K. Gayden -- Senior Vice President

That's fair.

TJ Schultz -- RBC Capital Markets -- Analyst

Okay, understood. Thank you.

Operator

Next question comes from the line of Keith Stanley from Wolfe Research. Your line is now open.

Keith Stanley -- Wolfe Research -- Analyst

Hi, good morning. Randy, you mentioned how the backlog, I guess, you added $3.6 billion of new projects to it and I assume PDH2 and Midland-to-ECHO 4 are the larger parts, but are there any other chunkier additions I wasn't thinking in those two alone would be really near the $3.6 billion? I'm not sure if ATEX or the Gillis lateral are meaningful capital.

W. Randall Fowler -- Director, President and Chief Financial Officer

Yes, it's -- what may have also been included in that was also Midland-to-ECHO 3 could have potentially been in there as well; and PDH, Midland-to-ECHO 4 and Gillis.

Keith Stanley -- Wolfe Research -- Analyst

Okay, sorry, to clarify Midland-to-ECHO 3 is not part of that?

W. Randall Fowler -- Director, President and Chief Financial Officer

I think it was included when we announced earnings in the second quarter.

Keith Stanley -- Wolfe Research -- Analyst

Okay. So mainly, those two projects and Gillis. Follow-up question, just can you give any more color on Midland-to-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?

A. J. Teague -- Director and Chief Executive Officer

It's on the pipe, and we started to work -- you're talking about how quick we are doing it, we will work in that project, but long before we announced it. So, we had a running head start is that fair to you, Graham?

Graham W. Bacon -- Executive Vice President and Chief Operating Officer

I think that's fair. We were doing a lot of work upfront and make sure we're ready to hit the ground running. So, yes, that's fair.

Keith Stanley -- Wolfe Research -- Analyst

Got it. Thank you.

Operator

The next question comes from the line of Michael Lapides from Goldman Sachs. Your line is now open.

Michael Lapides -- Goldman Sachs -- Analyst

Hey, guys, thanks for taking my question. Real quick, can you just talk about the returns on capital or the build multiple or the operating margin, how you want to discuss it; from Midland-to-ECHO 3 and 4 versus kind of what you've got when you first built some of the Permian crude pipes meaning maybe Midland-to-ECHO 1 and 2, for example.

W. Randall Fowler -- Director, President and Chief Financial Officer

Yes, Michael, this is Randy. I'll take a first shot at it. Again, we won't get into talking returns on any specific project. But I mean, if you come back in and I'd just say that they are comparable to our historical returns and most midstream projects fall in that range of 10% to 15%. I think what we have said is the flexibility that Midland-to-ECHO 4 does provide us is just by coming in and being able to save on those variable operating cost that Jim spoke to earlier. We can come in and that provides us a good base level return on Midland-to-ECHO 4 that really weren't available and some of the other pipes.

Michael Lapides -- Goldman Sachs -- Analyst

Got it. Yes, I'm just kind of ask in that given, I mean, a lot of people expect 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?

A. J. Teague -- Director and Chief Executive Officer

Brent, why don't you try to --

Brent B. Secrest -- Executive Vice President and Chief Commercial Officer

Let me give a shot there. So I mean, it's a good question and I -- if you looked at and we've talked about this before, but if you look at total capacity that's come out of the basin, I know you can run the numbers and say, well there is excess capacity and so I think you're seeing it on the pipeline, so that's 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. And 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. And then the, you have to look to see where those barrels are going. And the reason we're getting contracts and the people are typically signing these contracts are people that are going to continue to drill that, they are reupping for increased volumes with Enterprise, and 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. So 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. And so what you're dealing with as you have barrels that are trucked in, you have small gathering lines that go into the Eagle Ford pipeline system and ultimately it's underperforming on a much greater scale than any other pipeline we have in our portfolio.

So what we did is, went back to Midland and brought a daily supply source into that pipeline. And we also have the opportunity to do dual contracts for people to have Permian acreage and people to have Eagle Ford acreage. So going forward, our expectation is that pipeline is going to be full, no different than the rest of our crude pipelines. So that was the thought behind that, and recognize the fact that we have contracts to support that capacity.

Michael Lapides -- Goldman Sachs -- Analyst

Got it, that's super helpful. And then one follow-up. You talked in your opening remarks about potentially reclaiming some of the capacity on the gas processing plants, and I don't know whether those were the new ones built or whether those with legacy ones in the Permian. But just curious you then later in the Q&A talked about how most of your customer base or the majors and that they haven't really been reducing production. So 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.

Brent B. Secrest -- Executive Vice President and Chief Commercial Officer

So I mean, this is Brent again. So in terms of the majors, the majors for a reason are probably majors because they have a lot of acreage and so when we 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 with those signed up for. But when we look at -- and so their issue is some areas are better than other areas. And so 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 four, number five on the list and are focused on probably a more crude centric play. And so, it benefits us on the crude oil side, but on the processing side there underperforming. And so we have provisions in our contracts to allow us if you underperforming to go back and reclaim that capacity and that's what we'll look at doing.

A. J. Teague -- Director and Chief Executive Officer

And we have people, we're working with that -- we could fill that capacity with.

Michael Lapides -- Goldman Sachs -- Analyst

Got it. Thank you, guys. Much appreciate you all taking all three of my questions.

Operator

Next question comes from the line of Ujjwal Pradhan from Bank of America. Sir, your line is now open.

Ujjwal Pradhan -- Bank of America -- Analyst

Good morning, everyone. Couple of questions from me. First, I wanted to touch on the recent increase in VLCC freight rates globally and how that has exported -- 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?

A. J. Teague -- Director and Chief Executive Officer

Brent. You dominating this, go for it.

Brent B. Secrest -- Executive Vice President and Chief Commercial Officer

So I think, we saw the spike like you all did and I'm not put a plug in here on this. So there is a spike. We saw record freight rates on VLCCs and that's an issue and that's an issue for producers who go to markets that are forced to export. So in Houston what we saw is people basically backed off and they backed off from exporting and the market was trying to fill itself out and things got to reset, but that takes time. And in this case, it took probably a couple of weeks and we saw it kind of settle into a number.

But the luxury we have and why people choose to go to Houston is because you have that luxury and 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 forced export is either they are severely discounted to Houston or the barrels aren't flow into the water. And you saw big players that are going to terminals outside of Houston being forced to sell back in the field in the Permian Basin.

So when stuff like that happens, to me, going to Houston is an opportunity for Enterprise and 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, very, very strong, but there was a period in time there. Well, I think it caused the market to pause and say, is this the right idea to go to this terminal, and to me, it's probably a selling point for us going forward.

Ujjwal Pradhan -- Bank of America -- Analyst

Got it. And 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?

Brent B. Secrest -- Executive Vice President and Chief Commercial Officer

So 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, people were full. And so, I mean, when you look at fractionation, the closer you are the pricing point, the more likely you are to be full. So when you look at tertiary fractionators and we got some in Louisiana, there's also a bunch in the Mid-Continent, but the closer you are to the pricing point, all these NGLs or leave and we called out the water, the more full you are.

A. J. Teague -- Director and Chief Executive Officer

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?

Brent B. Secrest -- Executive Vice President and Chief Commercial Officer

It's --

A. J. Teague -- Director and Chief Executive Officer

Another 1 million?

Brent B. Secrest -- Executive Vice President and Chief Commercial Officer

That will probably set a record.

Ujjwal Pradhan -- Bank of America -- Analyst

Got it. That's helpful. Thank you, guys.

Operator

Our last question comes from the line of Chris Sighinolfi from Jefferies. Your line is now open.

Chris Sighinolfi -- Jefferies -- Analyst

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. I'm just -- you had noted this is a function of contract terms and something that's always been available to you. So 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 isn't exist before and because investors are more focus maybe on capex avoidance? I guess, is it change in strategy or are you simply flagging it so that we're all aware of the contract optionality?

A. J. Teague -- Director and Chief Executive Officer

Yes, I think, Chris, to make you aware that we get so many questions on capital discipline, we have ways to increase our business in 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 -- and we're going to start doing it well, I mean we're going to do it, like we always have.

W. Randall Fowler -- Director, President and Chief Financial Officer

I'll just -- so if you look to producers, when they go ranked our acreage, there is certain acreage that we have in that area that ranks number one for one producer, and ranks number five for another producer. And so at end of the day what 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.

A. J. Teague -- Director and Chief Executive Officer

And it's really not a -- it's not a change -- it's Natalie or Brad, I think it's an every acreage dedication deal we have in it?

Bradley Motal -- Senior Vice President

I agree. It's just an optimization techniques that we're highlighting here. It is not saying we are something new. We've done this the whole time we've contracted these plants.

Chris Sighinolfi -- Jefferies -- Analyst

Okay, that's helpful. I suspect I just wanted to clarify. And then final question from me, and this might be for Randy, but I'm not sure it's probably collaborative answer. But 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 and we did 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 is also a downstream considerations. But 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 it contracting?

W. Randall Fowler -- Director, President and Chief Financial Officer

Yes. Because Chris a little bit what you're talking about is really how do we feel about recontracting when based contracts are up, so I'll pass it Jim or Brent or Natalie.

A. J. Teague -- Director and Chief Executive Officer

I think of a good example would be the Haynesville where -- when we put that pipeline in service, I think we were getting $0.25 -- between $0.25 and $0.30 was what we're getting. And now this -- now what we're getting on that spread is what $012 to $0.15. But what we did, so you would look at that and say that's a recontracting issue. But what we're getting in our gathering is probably $0.20 to $0.30. And so I look at it all in, we get the same revenue, it is just shifted as to where we're getting. The Eagle Ford pipeline that Brent talked about, one of the things that tied 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. Now, 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 going in for 7 or 8 years, is what I remember?

Brent B. Secrest -- Executive Vice President and Chief Commercial Officer

[Indecipherable] 10 years, 9 years.

A. J. Teague -- Director and Chief Executive Officer

Yes so. Remember every one of those contracts, I think with the exception of one having associated dock deal. So we've got 9 years to 10 years left at pretty decent fees on the transport, but every one of them have a dock deal and some of them may have storage deals to go along with that.

Chris Sighinolfi -- Jefferies -- Analyst

Great. I appreciate that color.

W. Randall Fowler -- Director, President and Chief Financial Officer

Yes, Chris, a little bit, I mean, when you think about it as far as recontracting in 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 our cash flow per unit.

Chris Sighinolfi -- Jefferies -- Analyst

Yes, for sure. I think what I was just noting is, Jim was talking about the Dividend Aristocrats and you guys have had a really phenomenal schedule quarterly raises here through some pretty tumultuous period. So I think we look at it, we look at this growth in the payout and that feels fairly secured. Obviously, everybody 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 and when you think about buybacks and the retirement of that stream how it all factors together. So, anyway, I appreciate the color.

W. Randall Fowler -- Director, President and Chief Financial Officer

Michelle, this is Randy. With that being our last question, the Company is going to go ahead and sign off here. We would like to thank everybody for joining us today. If you would give our listeners replay information for the call. Thank you very much, ad have a mass day.

Operator

Your con call or replay will be available two hours after the call, ended until 4th November midnight. Please have your participant dialed in 800-585-8367 or 855-859-2056 or internationally on 404-537-3404 and enter conference ID to listen.

Duration: 59 minutes

Call participants:

Randy Burkhalter -- Vice President, Investor Relations

A. J. Teague -- Director and Chief Executive Officer

W. Randall Fowler -- Director, President and Chief Financial Officer

Graham W. Bacon -- Executive Vice President and Chief Operating Officer

Bradley Motal -- Senior Vice President

Michael C. Hanley -- Senior Vice President

Brent B. Secrest -- Executive Vice President and Chief Commercial Officer

F. Christopher D'Anna -- Senior Vice President

Anthony C. Chovanec -- Senior Vice President

Natalie K. Gayden -- Senior Vice President

Shneur Gershuni -- UBS -- Analyst

Jeremy Tonet -- JPMorgan -- Analyst

Colton Bean -- Tudor, Pickering, Holt & Co. -- Analyst

Jean Ann Salisbury -- Bernstein -- Analyst

Tristan Richardson -- SunTrust -- Analyst

Spiro Dounis -- Credit Suisse -- Analyst

Pearce Hammond -- Simmons Energy -- Analyst

Keith Stanley -- Wolfe Research -- Analyst

TJ Schultz -- RBC Capital Markets -- Analyst

Michael Lapides -- Goldman Sachs -- Analyst

Ujjwal Pradhan -- Bank of America -- Analyst

Chris Sighinolfi -- Jefferies -- Analyst

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