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Edited Transcript of EPD earnings conference call or presentation 28-Oct-19 2:00pm GMT

Q3 2019 Enterprise Products Partners LP Earnings Call

HOUSTON Oct 29, 2019 (Thomson StreetEvents) -- Edited Transcript of Enterprise Products Partners LP earnings conference call or presentation Monday, October 28, 2019 at 2:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* A. James Teague

Enterprise Products Partners L.P. - CEO

* Anthony C. Chovanec

Enterprise Products Partners L.P. - SVP of Fundamentals & Commodity Risk Assessment

* Bradley Motal

Enterprise Products Partners L.P. - SVP of Liquid Hydrocarbons

* Brent B. Secrest

Enterprise Products Partners L.P. - EVP & Chief Commercial Officer

* F. Christopher D'Anna

Enterprise Products Partners L.P. - SVP of Petrochemicals

* John R. Burkhalter

Enterprise Products Partners L.P. - VP of Investor Relations

* Michael C. Hanley

Enterprise Products Partners L.P. - SVP of Pipelines & Terminals

* Natalie K. Gayden

Enterprise Products Partners L.P. - SVP of Natural Gas Assets

* Graham W. Bacon

Enterprise Products Partners L.P. - EVP & Chief Operating Officer

* W. Randall Fowler

Enterprise Products Partners L.P. - President & CFO

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Conference Call Participants

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* Christopher Paul Sighinolfi

Jefferies LLC, Research Division - Senior Equity Research Analyst, Master Limited Partnerships

* Colton Westbrooke Bean

Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Midstream Research

* Jean Ann Salisbury

Sanford C. Bernstein & Co., LLC., Research Division - Senior Analyst

* Jeremy Bryan Tonet

JP Morgan Chase & Co, Research Division - Senior Analyst

* Keith T. Stanley

Wolfe Research, LLC - Research Analyst

* Michael Jay Lapides

Goldman Sachs Group Inc., Research Division - VP

* Pearce Wheless Hammond

Simmons & Company International, Research Division - MD & Senior Research Analyst

* Shneur Z. Gershuni

UBS Investment Bank, Research Division - Executive Director in the Energy Group and Analyst

* Spiro Michael Dounis

Crédit Suisse AG, Research Division - Director

* Torrey Joseph Schultz

RBC Capital Markets, LLC, Research Division - Analyst

* Tristan James Richardson

SunTrust Robinson Humphrey, Inc., Research Division - VP

* Ujjwal Pradhan

BofA Merrill Lynch, Research Division - Associate

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Presentation

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Operator [1]

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Ladies and gentlemen, thank you for standing by, and welcome to the Q3 2019 Earnings Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions)

I would now like to hand the conference over to your speaker today, Mr. Randy Burkhalter. Sir, you may go ahead.

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John R. Burkhalter, Enterprise Products Partners L.P. - VP of Investor Relations [2]

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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.

And so with that, I'll turn the call over to Jim.

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A. James Teague, Enterprise Products Partners L.P. - CEO [3]

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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 1.7x coverage of our distributions.

Year-to-date, our DCF was $5 billion, which provided a 1.7x coverage. We retained $665 million of DCF in the third quarter, bringing our total to $2.1 billion for the first 9 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 total adjusted EBITDA of $6.1 billion for the first 9 months, which is up 14% compared to the first 9 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 6 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 began 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 -- in best of the best of dividend growth stocks.

Over this time, we have increased our quarterly distribution rate 71x through numerous business cycles, including the financial crisis in 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 sanctions -- projects sanctioned to date, 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're 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.

Sometime our options are contractual, this includes using contract provisions to clawback 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 sanctioned 2 expansions of our Midland-to-ECHO pipeline system M2E 3 and M2E 4. We announced M2E 3 in July and M2E 4 in October. Our M2E 3 expansion will add 450,000 barrels a day of capacity. This pipeline is expected to be completed in the third quarter of 2020. The M2E 4 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 assets, 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 M2E 1 and M2E 2, it has come at an increase in variable cost. Across these pipelines, we see variable costs of the last segment of incremental capacity exceeding $2, which works when this 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 cost 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 off of M2E 2, our Seminole pipeline, and then convert Seminole back into NGL service. We think we will eventually need this additional NGL capacity.

In doing so, M2E 4 will only add a small amount of incremental capacity to our Midland-to-ECHO system. As market supported M2E 4 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 zero capital.

The third major project we announced during the quarter is our PDH 2 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 have negotiated a fixed cost engineering, procurement and construction contract with S&B to build PDH 2. We have a long history with S&B dating back to 1995. They led construction on 9 of our NGL fractionation -- fractionators plus several others assets at Mont Belvieu and numerous other assets on our system.

Relative to market for natural gas, we've 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 integrated volumes to the growing Gulf Coast LNG corridor. We also announced the successful open season for the expansion of ATEX ethane pipeline. Similar to other expansions to our system, this incremental capacity is expected to be achieved largely through improvements and modifications to existing infrastructure versus new pipes.

Work also continues in our other major projects, 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 iBDH plan 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 value -- in our value chain for the years to come.

In summary, today's earnings and 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 chain -- 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 and an extremely supportive general partner.

And what Randy Fowler has emphasized, has no surprises, in 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.

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W. Randall Fowler, Enterprise Products Partners L.P. - President & CFO [4]

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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 the $39 million noncash loss for asset impairment charges or $0.02 per unit fully diluted and $86 million in unrealized noncash mark-to-market hedging losses or $0.04 per fully diluted unit.

Included in the noncash 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 noncash items, EPU increased 2% versus the comparable adjusted earnings per unit for the third quarter of 2018.

Moving onto 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 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 lengths are for 10 years or more.

Assuming our historical returns on capital, these assets have the potential to generate approximately $1 billion to $1.3 billion of incremental gross operating margin for 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 the $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 in 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 3.2x, after adjusting debt for the partial equity treatment of the hybrid debt securities and reducing the debt by unrestricted cash on hand. If we normalize adjusted EBITDA for the last 12 months to eliminate the certain spread related activities, we estimate that our leverage ratio would have been 3.5x 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 12. 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 equity component of our growth rather than relying on equity capital markets.

With that, Randy, we can open it up for questions.

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John R. Burkhalter, Enterprise Products Partners L.P. - VP of Investor Relations [5]

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Okay. Michelle, we're ready to take questions from audience. (Operator Instructions)

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Questions and Answers

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Operator [1]

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(Operator Instructions) Your first question comes from the line of Shneur Gershuni.

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Shneur Z. Gershuni, UBS Investment Bank, Research Division - Executive Director in the Energy Group and Analyst [2]

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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 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 -- I'm sorry, for 2020, does that also include the SPOT terminal? Or is that not part of the 2020 number?

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A. James Teague, Enterprise Products Partners L.P. - CEO [3]

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I don't think that is a part of the 2020 number.

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Shneur Z. Gershuni, UBS Investment Bank, Research Division - Executive Director in the Energy Group and Analyst [4]

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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'd said on a net basis on the prepared remarks?

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A. James Teague, Enterprise Products Partners L.P. - CEO [5]

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On a net basis, I think, what we're saying is we're adding the 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, --

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [6]

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Yes.

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A. James Teague, Enterprise Products Partners L.P. - CEO [7]

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Yes. So I think the net addition is about 70,000 barrels a day, Brent?

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [8]

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I believe.

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A. James Teague, Enterprise Products Partners L.P. - CEO [9]

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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 -- we can take that to 450,000 barrels a day and reduce our cost dramatically. And then we could convert Seminole back to NGL service, which we think we'll have to do. So overall we're adding 70, we could at an optimum cost, we 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.

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Shneur Z. Gershuni, UBS Investment Bank, Research Division - Executive Director in the Energy Group and Analyst [10]

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Okay. That makes perfect sense. And then for my follow-up question. I think it was about 2 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? And then on the buyback side, is it just for offsetting the DRIP and the employee purchases? Or is there an evolving view on that?

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W. Randall Fowler, Enterprise Products Partners L.P. - President & CFO [11]

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Shneur, this is Randy. I think currently on what we've said around the buyback program anyway is we we're 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're 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.

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Operator [12]

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Your next question comes from the line of Jeremy Tonet.

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Jeremy Bryan Tonet, JP Morgan Chase & Co, Research Division - Senior Analyst [13]

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Just want to start off with the CapEx -- and the range that you guys have provided there the $3 billion to $4 billion, was wondering what would drive the lower end versus the higher end there? You mentioned JVs potentially being part of that, but is kind of $3 billion what's 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 me to the higher end? Or any other things driving the moving pieces there?

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W. Randall Fowler, Enterprise Products Partners L.P. - President & CFO [14]

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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 would -- frankly, that would still keep growth CapEx under 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.

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Jeremy Bryan Tonet, JP Morgan Chase & Co, Research Division - Senior Analyst [15]

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Okay. That's helpful. And one more question, I think, you talked about flexibility between crude oil and NGL pipelines kind of being able to flex back and forth. I 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 swap it back to liquids service at a later date, if that could ever make sense if that's possible?

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A. James Teague, Enterprise Products Partners L.P. - CEO [16]

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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, thinks differently.

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Graham W. Bacon, Enterprise Products Partners L.P. - EVP & Chief Operating Officer [17]

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No, I don't see that happening.

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A. James Teague, Enterprise Products Partners L.P. - CEO [18]

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Well, wish it could.

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Operator [19]

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Your next question comes from the line of Colton Bean from Tudor, Pickering Holt and Company.

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Colton Westbrooke Bean, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Midstream Research [20]

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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 as basically the balance between your retained cash flow and your CapEx? Or would you still target something closer to 50% and may be any excess cash allocated towards some of those opportunistic buybacks?

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W. Randall Fowler, Enterprise Products Partners L.P. - President & CFO [21]

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

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Colton Westbrooke Bean, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Midstream Research [22]

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

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W. Randall Fowler, Enterprise Products Partners L.P. - President & CFO [23]

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

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Colton Westbrooke Bean, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Midstream Research [24]

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Understood. And just a quick one on operations, so 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 of recovery. So it doesn't seem like this quarter's result would be solely attributable to more rejections and just any incremental context you can provide on that 111,000 equity NGLs?

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A. James Teague, Enterprise Products Partners L.P. - CEO [25]

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I think most of that's probably ethane rejections. Isn't that -- where's Natalie or Brad or whomever?

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Bradley Motal, Enterprise Products Partners L.P. - SVP of Liquid Hydrocarbons [26]

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Yes, this is Brad. Most of that -- I'll agree with Jim, most of that's attributable to ethane rejections across the system, whether it be the Rockies or some of the other places.

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Operator [27]

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

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Jean Ann Salisbury, Sanford C. Bernstein & Co., LLC., Research Division - Senior Analyst [28]

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Are you able to comment on whether CapEx cost for the 2 new Midland-to-ECHO pipelines are expected to be noticeably lower than the first one?

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W. Randall Fowler, Enterprise Products Partners L.P. - President & CFO [29]

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Just really comparable.

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Graham W. Bacon, Enterprise Products Partners L.P. - EVP & Chief Operating Officer [30]

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Yes, comparable. It's not noticeably lower.

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Jean Ann Salisbury, Sanford C. Bernstein & Co., LLC., Research Division - Senior Analyst [31]

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Okay. And 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?

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Michael C. Hanley, Enterprise Products Partners L.P. - SVP of Pipelines & Terminals [32]

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

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Jean Ann Salisbury, Sanford C. Bernstein & Co., LLC., Research Division - Senior Analyst [33]

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Okay. Is it possible to comment on if there has been any change or lengthening to the existing ATEX term?

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Michael C. Hanley, Enterprise Products Partners L.P. - SVP of Pipelines & Terminals [34]

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To the existing Apex term, there has not been a change, no.

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Operator [35]

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

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Tristan James Richardson, SunTrust Robinson Humphrey, Inc., Research Division - VP [36]

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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?

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A. James Teague, Enterprise Products Partners L.P. - CEO [37]

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You know, 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, yes, we never say never no to anything, but it depends upon what a person is 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, but by and large, it's new assets.

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Tristan James Richardson, SunTrust Robinson Humphrey, Inc., Research Division - VP [38]

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Helpful. 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 U.S. production environment shifting, or also -- or just looking at assets that have utilization upside?

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A. James Teague, Enterprise Products Partners L.P. - CEO [39]

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You know, everybody -- there is a big-- there's 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. So that's an issue. One of the things we have on acreage dedications that people aren't performing up to the production profile that the plant was built on. Then, at a certain point, we have the right to reduce their MDQ and use that capacity somewhere else. So it's a safeguard that we always have the right to -- at a certain point in time to clawback and reduce the MDQ and use it with someone else.

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Operator [40]

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Your next question comes from the line of Spiro Dounis from Crédit Suisse.

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Spiro Michael Dounis, Crédit Suisse AG, Research Division - Director [41]

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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 the cycle where we're seeing maybe a lot of your peers retrench a little bit, so you just sort of stand out in that respect. So curious, is it fair to say that you are deploying maybe a similar strategy to LPG exports, where your major focus at this point is on capturing market share and dissuading competition? Or is there a little more nuanced than that?

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A. James Teague, Enterprise Products Partners L.P. - CEO [42]

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You want to have a part of that...

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [43]

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This is Brent. And I think you hit it. It's that we've seen people pull back as it relates to midstream competitors. What we've seen is people pull back is probably over the last 6 months to 9 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.

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A. James Teague, Enterprise Products Partners L.P. - CEO [44]

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I think the other thing where we -- you're seeing us and it's along the same lines, but we have a broader product line then we could operate. Our petrochemical midstream services business, we are very focused on that, building our PDH 2, 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, store it, distribute it or export it.

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [45]

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But I think you saw Enterprise back out of certain projects 2 years ago and 3 years ago, and we were pretty vocal about the projects that we wouldn't go after. And I think at the end of day, it 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, it still makes much more sense to do organic growth projects that work for Enterprise.

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Spiro Michael Dounis, Crédit Suisse AG, Research Division - Director [46]

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Yes, that 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, 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 on octane enhancement? And is there any sort of expansion or anything you can do in that business to capture more of that?

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F. Christopher D'Anna, Enterprise Products Partners L.P. - SVP of Petrochemicals [47]

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This is Chris. We're seeing -- 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. 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.

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Operator [48]

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Next question comes from the line of Pearce Hammond from Simmons Energy.

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Pearce Wheless Hammond, Simmons & Company International, Research Division - MD & Senior Research Analyst [49]

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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're hearing from some of your customers?

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A. James Teague, Enterprise Products Partners L.P. - CEO [50]

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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. 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. I don't think we have any small cap people at all?

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [51]

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Not -- not on -- or actually...

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A. James Teague, Enterprise Products Partners L.P. - CEO [52]

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It's minimum. Tony, you want to throw some in.

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Anthony C. Chovanec, Enterprise Products Partners L.P. - SVP of Fundamentals & Commodity Risk Assessment [53]

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When we sit down and talk to people, 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 is going to be down, but their production is going to be up because of efficiency and in some cases completion aducts. 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 the production is actually going to rollover. It's very, very hard in our type of curve models and our forecast to make that happen.

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [54]

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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 that volumes are going to be up, capital is going to be down. And usually it's about a ratio of 10% to 15% down on capital, 10% to 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. So 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, but I think, gas-centric type volumes will be going down.

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Pearce Wheless Hammond, Simmons & Company International, Research Division - MD & Senior Research Analyst [55]

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

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [56]

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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 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.

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Pearce Wheless Hammond, Simmons & Company International, Research Division - MD & Senior Research Analyst [57]

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Are you..

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [58]

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That's a relative question. So 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. But in terms of what we have contracted for next several years, it's north of 90%.

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Operator [59]

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Next question comes from the line of TJ Schultz from RBC Capital Markets.

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Torrey Joseph Schultz, RBC Capital Markets, LLC, Research Division - Analyst [60]

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Just a question on the Acadian expansion. Is that driven more by growth in Haynesville production you're expecting? Or are you're bringing 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?

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A. James Teague, Enterprise Products Partners L.P. - CEO [61]

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I think it's mainly given the market to those Haynesville producers. Their market was either the river corridor or Perryville. Help me here, is -- am I right? And this just gives them more market. I'll tell you that lateral, if I'm not mistaken, Brent, it's so completely out. I'll let Natalie answer some.

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Natalie K. Gayden, Enterprise Products Partners L.P. - SVP of Natural Gas Assets [62]

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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. It's a promising an exciting project for us.

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Torrey Joseph Schultz, RBC Capital Markets, LLC, Research Division - Analyst [63]

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

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A. James Teague, Enterprise Products Partners L.P. - CEO [64]

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I'll take it, 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?

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Natalie K. Gayden, Enterprise Products Partners L.P. - SVP of Natural Gas Assets [65]

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That's fair.

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Operator [66]

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Next question comes from the line of Keith Stanley from Wolfe Research.

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Keith T. Stanley, Wolfe Research, LLC - Research Analyst [67]

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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, but are there any other chunkier additions? I wasn't thinking that those 2 alone would be really near the $3.6 billion. I'm not sure if ATEX or the Gillis lateral are meaningful capital?

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W. Randall Fowler, Enterprise Products Partners L.P. - President & CFO [68]

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You know, 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.

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Keith T. Stanley, Wolfe Research, LLC - Research Analyst [69]

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

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W. Randall Fowler, Enterprise Products Partners L.P. - President & CFO [70]

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

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Keith T. Stanley, Wolfe Research, LLC - Research Analyst [71]

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Okay. So mainly those 2 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 time line to the third quarter of 2020. I'm just wondering how much is new pipe versus expansion of infrastructure or repurposing on that line?

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A. James Teague, Enterprise Products Partners L.P. - CEO [72]

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It's all new pipe and we started working -- you're talking about how quick we're doing it. We were working on that project long before we announced it. So we had running head start. Is it fair, Graham?

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Graham W. Bacon, Enterprise Products Partners L.P. - EVP & Chief Operating Officer [73]

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

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Operator [74]

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Next question comes from the line of Michael Lapides of Goldman Sachs.

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Michael Jay Lapides, Goldman Sachs Group Inc., Research Division - VP [75]

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Real quick, can you just talk about the returns on capital or the build multiple or the operating margin, however, you wanted to discuss it? For Midland-to-ECHO 3 and 4 versus kind of what you got when you first built some of the Permian crude pipes, meaning maybe Midland-to-ECHO 1 and 2, for example?

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W. Randall Fowler, Enterprise Products Partners L.P. - President & CFO [76]

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Michael, this is Randy. I would take first shot at it. Again, I won't get into talking returns on any specific project, but I mean, if you come back in and I just say that they are comparable 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 costs that Jim spoke to earlier. We could come in and that provides us a good base level return on Midland-to-ECHO 4 that really wasn't available in some of the other pipes.

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Michael Jay Lapides, Goldman Sachs Group Inc., Research Division - VP [77]

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Got it. I'm just kind of 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?

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A. James Teague, Enterprise Products Partners L.P. - CEO [78]

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Brent, why don't you -- perhaps you try to take a shot at it.

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [79]

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It's a good question. And if you look at -- 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 whether there is excess capacity. So I think you're seeing it on the pipelines that have come up recently and the pipelines that will come up over the next 6 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 we have to look to see where those barrels are going. And 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, and they want to go to Houston.

If you look at Midland-to-ECHO 4, there is 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. It does not have a daily supply source. So 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. 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 where people that have Permian acreage and people that 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 that support that capacity.

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Michael Jay Lapides, Goldman Sachs Group Inc., Research Division - VP [80]

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Got it. That's super helpful. And then one follow-up. You all 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 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. So what's driving the open capacity on your processing and if your biggest customers, the bulk of your customers, aren't really cutting production growth rates?

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [81]

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This is Brent again. So in terms of the majors, they are majors for a reason. They are probably majors because they have a lot of acreage. So when you look at processing plants, that is specific acreage to an area. If you look at crude oil in our total portfolio, they are achieving what they signed up for; in most cases, exceeding what they signed up for. But when you look at -- so their issue is some areas are better than other areas. 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 #4 or #5 in the list and are focused on probably a more crude-centric play. So it benefits us on the crude oil side. But on a processing side, they are underperforming. And so we have provisions in their contracts to allow us, if you are underperforming, to go back and reclaim that capacity and that's what we look to doing.

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A. James Teague, Enterprise Products Partners L.P. - CEO [82]

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

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Operator [83]

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Next question comes from the line of Ujjwal Pradhan from Bank of America.

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Ujjwal Pradhan, BofA Merrill Lynch, Research Division - Associate [84]

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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?

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A. James Teague, Enterprise Products Partners L.P. - CEO [85]

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Well, Brent, I think you're dominating this. Go for it.

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [86]

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So I think we saw the spike like you all did, and I'm going to plug in here on this. So there is a spike. And 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 feel itself out and things get a reset, but that takes time. And in this case, it took probably 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 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 to export is either they are severely discounted to Houston or the barrels aren't flowing to 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 will see volumes probably -- when we come out with our earnings, you will see volumes for October very, very strong, but there was a period in time of there where, I think, it caused the market to pause and say "is this the right idea to go to this is terminal." And to me, it's probably so important for us going forward.

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Ujjwal Pradhan, BofA Merrill Lynch, Research Division - Associate [87]

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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?

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [88]

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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're full. So when you look at fractionation, the closer you are to 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 is also a bunch in the Mid-Continent, but the closer you are to the pricing point where all these NGLs are leaving, we will call that the water, the more full you are.

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A. James Teague, Enterprise Products Partners L.P. - CEO [89]

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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?

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [90]

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It's -- it will probably set a record.

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Operator [91]

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Our last question comes from the line of Chris Sighinolfi from Jefferies.

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Christopher Paul Sighinolfi, Jefferies LLC, Research Division - Senior Equity Research Analyst, Master Limited Partnerships [92]

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I have 2. The 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 dedicate producers. I'm just -- you have 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're seeing mismatches now that didn't exist before and because investors are more focused maybe on CapEx avoidance? I guess, is there a change in strategy? Or are you simply flagging it so that we're all aware of the contract optionality?

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A. James Teague, Enterprise Products Partners L.P. - CEO [93]

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I think it's to make you aware that we get so many questions on capital discipline. We have ways to increase our business with our throughput without spending money. And I think what we're saying is that's one way, and I don't think we're -- it's not a change in strategy. It's just we're going to start doing it, we're going to do it, like we always have.

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [94]

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So if you look at producers, when they go to rank their acreage, there are certain acres that we have in that area that ranks #1 for one producer and it ranks #5 for another producer. And so 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.

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A. James Teague, Enterprise Products Partners L.P. - CEO [95]

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

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Bradley Motal, Enterprise Products Partners L.P. - SVP of Liquid Hydrocarbons [96]

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

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Christopher Paul Sighinolfi, Jefferies LLC, Research Division - Senior Equity Research Analyst, Master Limited Partnerships [97]

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Okay. That's what I suspected. 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 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 land and location is equal and there are contracts in place to justify the expansion, there is also 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 the unit and all future distributions tethered to it?

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W. Randall Fowler, Enterprise Products Partners L.P. - President & CFO [98]

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Yes. Chris, a little bit what you're talking about is really, how do we feel about recontracting when the base contracts are up. So I'll pass it to Jim or Brent on that.

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A. James Teague, Enterprise Products Partners L.P. - CEO [99]

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I think a good example would probably be the Haynesville, wouldn't it? When we put that pipeline in service, I think, we were getting $0.25 -- between $0.25 and $0.35 what we were getting. And now what we're getting on that spread is $0.12 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 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. 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 don't end for 7 or 8 years is what I would...

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Brent B. Secrest, Enterprise Products Partners L.P. - EVP & Chief Commercial Officer [100]

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I'd call it 10 years, 9 years.

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A. James Teague, Enterprise Products Partners L.P. - CEO [101]

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So -- damn near every one of those contracts, I think, with the exception of one have an associated dock deal. So we got 9 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.

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W. Randall Fowler, Enterprise Products Partners L.P. - President & CFO [102]

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Chris, a little bit, I mean, 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, a cash flow per unit.

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Christopher Paul Sighinolfi, Jefferies LLC, Research Division - Senior Equity Research Analyst, Master Limited Partnerships [103]

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I think what I was just noting is Jim talking about the Dividend Aristocrats, you guys have had a really phenomenal schedule of quarterly raises here through some pretty tumultuous periods. So I think when we look at it we look at this growth and the payout and that feels fairly secured. And obviously everybody is susceptible to risk 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, and how it all factors together. Anyway, appreciate the color.

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John R. Burkhalter, Enterprise Products Partners L.P. - VP of Investor Relations [104]

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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 of the call? Thank you very much. Have a nice day.

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Operator [105]

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Your on call or replay will be available 2 hours after the call presented until 4th of November midnight. Please have your participant dial in (800) 585-8367 or (855) 859-2056 or internationally on (404) 537-3406 and enter the conference ID to listen.