Randy Burkhalter - Vice President, IR Jim Teague - Chief Executive Officer Bryan Bulawa - Chief Financial Officer Anthony Chovanec - Senior Vice President William Ordemann - Executive Vice President Roger (RB) Herrscher - Senior Vice President Albert (Al) Martinez - Senior Vice President

Darren Horowitz - Raymond James Brandon Blossman - Tudor, Pickering, Holt Sunil Sibal - Seaport Global Securities Jeff Birnbaum - Wunderlich Matthew Phillips - Clarkson Kristina Kazarian - Deutsche Bank Ted Durbin - Goldman Sachs Jeremy Tonet - JPMorgan Helen Ryoo - Barclays Poe Fratt - D.A. Davidson Faisel Khan - Citigroup John Edwards - Credit Suisse Chris Sighinolfi - Jefferies Selman Akyol - Stifel Greg Price - Barclays

Thank you, Jinger. Good morning, everyone, and welcome to the Enterprise Products Partners fourth quarter earnings call.

Our speakers today will be Jim Teague, Chief Executive Officer of Enterprise’s general partner and Bryan Bulawa, Chief Financial Officer. Other members of our senior management team are also in attendance for the call today.

During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934 based on the beliefs of the Company as well as assumptions made by, and information currently available to Enterprise’s management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.

Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. And with that, I’ll turn the call over to Jim.

Thank you, Randy. 2015 was another outstanding year for Enterprise with us reporting record gross operating margin of $5.3 billion, supported by contributions from recently acquired and newly constructed assets and increased liquids transportation volumes.

This led to record distributable cash flow of $4 billion, excluding the proceeds from asset sales, which provided 1.3 coverage of the $1.53 per unit distributions declared with respect to 2015. Including $1.6 billion in proceeds from asset sales, we retained $2.6 billion of distributable cash flow to reinvest and reduce our need to access capital markets.

Our businesses continued to perform well despite a challenging commodity environment that included a 60% drop in crude prices since the peak and mid-’14 and lower NGL prices. Given our low cost of capital, no IDRs, support from a strong general partner and our diversified tightly integrated assets, we believe we’re well-positioned to manage, adapt and grow.

We entered 2016 with solid financial flexibility, BBB+ investment grade ratings, and healthy distribution coverage. We have over $6 billion of capital projects that are scheduled to begin operations over the next two years, plus additional ramp up commitments on some of the assets we have recently put into service, all providing support for continued growth in our distributions.

Like the three previous quarters, we also ended 2015 on a strong note with fourth quarter results that included increased gross operating margin contributions from three of our four business segments, and distributable cash flow of $1 billion, excluding proceeds from asset sales, which provided 1.3 coverage of the cash distribution declared with respect to the fourth quarter. Including $71 million in proceeds from asset sales, we retained $302 million of distributable cash flow in the fourth quarter of 2015.

Earlier this month, we also announced an increase in our cash distribution to $0.39 per unit with respect to the fourth quarter of 2015, a 5.4% increase over the distribution for the fourth quarter of 2014. We also announced our plans to recommend to the board of our general partner that Enterprise continue to increase the distributions during 2016 by one half cent per unit, per quarter or each quarter in 2016.

This would result in distribution with respect of 2016 of $1.61 or 5.2% increase over the $1.52 per unit paid with respect to 2015. We’re proud of our results, but we don’t take anything for granted.

It’s not business as usual for anyone in our industry. Crude oil and NGL prices started 2015 at levels that we thought were low and generally had a downward bias all year.

Futures prices fell more or less on lockstep with weakness in the cash markets. Inflation adjusted prices for crude oil, natural gas and most NGLs are at lows that go back as far as 1999.

We don’t think anyone knows how long the depressed prices will last, how low they can go, or how we are going to redefine normal after we finally start to see some stability. We have too much supply partially caused by rapid growth from U.S.

sales. History tells us that this won’t last forever and at some point we’ll come out of this cycle.

History also tells us that everyone will not make it through this cycle, at least not in their current form. For some, the deck has stacked against them for various reasons.

Our experience has taught us that you need to understand your business and be prepared for the lean times, otherwise you’ll find yourself reacting to negative events. For some, the current downturn is also confirming that you better not have built your business plan on ‘me too’.

You should understand both the supply and demand side of your markets and understand your competition and be close to your customer. Tight integration versus just a collection of assets is more important than ever.

As margins shrink, being able to continually reduce your cost per unit handle is critical. History shows that you can count on Enterprise.

Our structure is simple; our credit rating is excellent; and our 2015 performance certainly shows that we understand our business and how to behave during difficult times. In addition to our focus on serving the largest basins in the U.S., we continue to focus on cultivating markets, both domestically and globally.

We brought the last two segments of our Aegis ethane pipeline into service in 2015. That pipe is essentially fully subscribed as the global petrochemical market continues to be attracted to plentiful U.S.

feedstocks. In late December, we put our latest LPG export expansion and serviced, and are pleased as its performance exceeds expectations.

We continue to add new customers meeting long-term capacity including a recent seven-year agreement with a new Asian customer. Our terminal is over 90% subscribed through 2019 and we have contracts extending well into the 20s.

In the fourth quarter, we announced that we saw long-term space in our ethane export facility taking its committed capacity up to around 180,000 barrels a day. This facility is expected to be up and running in the third quarter.

The Aegis pipeline, our LPG export, and our ethane export will be new growth engines within our NGL pipelines and services segment, which reported gross operating margin of $730 million for the fourth quarter and $2.8 billion for the year. Our PDH plant at Mont Belvieu construction continues.

This asset is commercially structured as a large fixed fee arrangement that is 100% backed by long-term contracts with investment grade companies. Our PDH plant is an example of extending our value chain, in this case substantially upgrading the value of propane.

We’re still targeting to begin commissioning activities by year-end. We use this value chain model in other assets including MTBE and high-purity isobutylene facilities.

Both of these facilities upgrade our butane and the much higher value products. Our Petrochemical & Refined Products sector reported gross operating margin of $171 million for the fourth quarter compared to $199 million for the fourth quarter of 2014.

Our fourth quarter results were negatively impacted by unplanned outage and our MTBE plant that began in mid-November. But as a result, we decided to accelerate the planned annual maintenance and expected to be in service sometime shortly after mid-February.

Our Petrochemical & Refined Products segment was our only segment that didn’t show improvement in the fourth quarter. However, in spite of the MTBE outage, this segment still reported $719 million of gross operating margin in 2015 which was a $38 million improvement over 2014.

Our Crude Oil Pipelines & Services segment reported gross operating margin of $250 million for the fourth quarter compared to $228 million for the fourth quarter of 2014. 2015 results for this segment was $962 million which was $200 million increase from 2014.

This segment includes the EFS Midstream assets we added in the third quarter of 2015, our new crude oil distribution system and the new crude oil terminal capacity we have added primarily in Houston and Beaumont. Work continues on the Midland crude oil pipeline.

This project is 60% contracted as we have added a contract in December and discussions continue with other Permian producers. This current environment is tough for producers but the Permian is truly a premier basin which is why even in today’s environment, there are nearly 200 rigs running.

Also in the Permian, we’re constructing two new processing plants for a total of 400 million cubic feet a day, an incremental takeaway. Both of these plants will be completed and in service later this year.

Our Natural Gas Pipelines & Services segment reported gross operating margin of $194 million for the fourth quarter compared to a $185 million in the fourth quarter of 2014. 2015 results for this segment were $783 million, which represents a $21 million decrease from 2014.

This segment includes our Acadian Gas, Texas Intrastate, San Juan, Jonah Natural Gas pipelines. Segment results for the fourth quarter were up slightly compared to fourth quarter 2014, primarily due to lower pipeline operating costs.

Results for the full year 2015 were negatively impacted by lower revenues from our San Juan system or transportation fees of indexed regional energy prices. We see upside in this segment due to projected higher natural gas demand for power generation, exports to Mexico, and LNG and industrial demand, all of which is Gulf Coast centric where our pipes are located.

With our initiative on process condensate, it’s probably not surprise that we’ve been a very strong supporter of lifting the crude oil export ban. Our process condensate ruling was only a first step to ultimately lifting the ban.

We get a lot of questions of what this means for the U.S. oil and gas industry and for Enterprise.

Today’s price environment, spreads do not generally support significant crude oil exports. However, we believe that as we move out of this cycle, world will recognize the abundance of our resources, the benefits of supply diversification, and they know they count on the U.S.

producers. We also believe that global consumers will soon view the U.S.

as a place to invest in reserves. Ultimately, we believe that lifting the ban will be a real positive for the U.S., will be a stabilizing influence for global oil and gas, and will ultimately be very positive for Enterprise.

In closing, we want to recognize our employees. 2015 was very rough for industry and 2016 appears to be even more difficult.

Our results are first and foremost a result of our people’s resolve to excel. None of us take it for granted and we don’t think we can say thank you enough for all that they do.

In this environment, all we can do is make sure we keep our eye on the ball, continue to perform and continue to focus on building our future. That’s what we did during the downturn in the 80s, in 2001 and 2003 and 2009 and it’s what we have done since the current trough cycle started in mid-2014.

Thanks to a strong asset base and then to our extremely dedicated and talented employees. In spite of the volatile markets, Enterprise reported yet another strong quarter and strong full year for 2015.

We entered 2016 on solid footing and we fully expect to continue to deliver. And with that I’ll turn the call over to Bryan.

Thank you Jim. I will cover a few additional income items for the quarter and the year as well as an overview of our capitalization.

Before doing so, I would like to reiterate comments we’ve made in the past about revenue. The changes in revenue and operating costs and expenses are largely influenced by the changes in commodity prices and are not necessarily good indicators of the performance of our Company.

So, while revenue was down 44% for the year, our associated costs and expenses were also down 46%. We believe gross operating margin is a better performance base metric which was a record $5.3 billion in 2015.

With that said, net income attributable to limited partners was $685 million for the fourth quarter of 2015, or $0.34 per unit on a fully diluted basis. Net income and fully diluted EPU were reduced by non-cash asset impairment charges totaling $24 million or a penny per unit.

General and administrative costs were down $14 million this quarter compared to fourth quarter of 2014, primarily due to $10 million of non-recurring expenses recorded in the fourth quarter of last year related to the Oiltanking acquisition. Total capital spending in the fourth quarter of 2015 was $1.2 billion including $77 million of sustaining capital expenditures.

For the year, capital expenditures were $6.4 billion which included $1.4 billion of equity issuance for the completion of the Oiltanking transaction last February and $1.1 billion of cash in connection with the first installment payment for the EFS Midstream acquisition in July of 2015. Sustaining capital expenditures were $273 million in 2015.

We currently expect growth capital expenditures to be approximately $2.5 billion to $2.8 billion in 2016 and sustaining capital expenditures to be approximately $275 million. Adjusted EBITDA for the 12 months ended December 31, 2015 was $5.3 billion.

Accordingly, our consolidated leverage ratio of net debt to adjusted EBITDA was 4.2 times after adjusting for 50% equity treatments for the hybrid debt securities. At December 31, 2015, the average life of our debt was 14.1 years using the first call date for the hybrids and 17.3 years using the final maturity date for the hybrids.

Our effective average cost of debt was 4.7%. We had consolidated liquidity of $4.4 billion at the end of the year, which included available borrowing capacity under our credit facilities and unrestricted cash.

In 2015, we raised approximately $1.2 billion through a combination of our distribution reinvestment program, employee unit purchase program and our ATM equity program including a $177 million in the fourth quarter. These figures are inclusive of the aggregate $200 million investment in EPD common units made by affiliates of privately-held Enterprise Products Company or collectively EPCO during 2015.

With respect to 2016, EPCO and certain of its affiliates plan to purchase in aggregate of $200 million of EPD common units in the first quarter of which a $100 million was purchased through the ATM program during the first week of January. EPCO and certain of its affiliates plan to purchase the other $100 million through the partnership’s distribution reinvestment plan in February or next week.

Also EPCO has stated its intention to evaluate the purchase of additional common units during 2016 to further support Enterprise growth. The current commodity price cycle has raised the concerns of analysts and investors alike with respect to customer credit risk.

Managing and monitoring credit risk is and has been a top concern for Enterprise. To add in, we have a customer profile with approximately 80% of our top 200 customers by revenue being investment grade rated or secured by letter of credit.

Those top two customers account for approximately -- a little over 99% of our 2014 revenues. Digging deeper into the numbers, Enterprise has exposure to eight sub-investment grade independent E&P customers and this group accounted for only 2.4% of our 2014 revenues.

And with that I’ll turn the call back over to Randy.

Thank you, Bryan. Before taking questions, Jinger, I’d like to mention that the Enterprise and Oiltanking K-1s for 2015 are expected to be available online by noon Central Time on Tuesday, February 23rd.

Of course we’ll announce this with a press release also when they are available. So, Jinger, I think we’re ready to take questions now.

Jim, back to some of your earlier comments about the $6 billion of projects that you expect to place in the service over the next few years. And I realize this is tough to say but when you look at that projects at relative to the returns that you expect to generate on the $2.5 billion to $2.8 billion of growth CapEx you’re going to spend this year, is there that much of a difference?

So, I’m just trying to get a sense for how the return metrics have changed and how much of an influence maybe the changing cost of capital has had relative to market driven margin compression or anything you’re seeing out there from a customer perspective or at least the risk of facilitating those assets?

I don’t think we’ve seen any decline in return Darren. And I think I’ve mentioned that we’ve in December -- was it December Bill?

We signed a new contract on that Permian pipeline and frankly we’re in some discussions with couple of other folks that I think executing those contracts are fairly imminent. So, we’ll just keep going.

And then my follow-up question and you all have had this slide in your slide decks for a long time but specifically in the analyst slide deck that you all had last year, there was some information that was outlining the indicative amount of growth CapEx that was required to support that $0.08 per unit distribution growth based on return on capital assumptions that were out there and there were a couple of different targeted return metrics. I’m just wondering from a financing perspective given that you have obviously a lot of friends to support, you’ve excellent retained cash and a lot of financial flexibility.

Is it still the assumption that you can assume that 10% targeted return and meet that distribution growth, maybe by leaning more on 100% retain DCF or maybe a bit more on more retain DCF and a blended debt financing? And if that ends up being the case, is the applicable number still between $1.5 billion and $1.8 billion of growth CapEx in order to get those returns?

This is Randy. I’ll be honest; we’ve not updated that chart probably here in a couple of months.

We will have it updated for the analyst meeting. The one thing we just have to factor through there, certainly the last three months, if you take a snapshot just as far as where equity yields are and where cost of long-term debt capital is, that’s moved up call it maybe 100 basis points on a weighted average cost of capital basis.

So that would have an impact on the amount of growth CapEx that you’re assuming at all those return levels. So really, we just need to come in and work the math.

And stay tuned in March, we’ll have it for you then.

Let’s start with a fundamentals question. LPG exports, propane, butane, propane in particular doing very well here turning to hit just globally new records on U.S.

throughput through the terminals. Is there a risk, and this is probably 12 to 18 months risk; is there a risk that we don’t have enough supply out of Texas to meet global demand profile?

So, it’s a global supply demand question as it’s focused on kind of the U.S. liquids production?

So, you’re saying is there a risk, we have a high class problem...

Yes, that is exactly right.

I think we’ve got plenty of pipelines that can access other regions to bring supply down to the Gulf Coast.

I mean just base production and what the production profile looks like over the next…

Let’s Tony take a shot at it.

You could make a case, who knows exactly where liquids productions, how it’s going to be impacted for 2016. So, I could run a scenario where supply would get tight.

But you have to realize that the export markets are very dynamic markets, and it response to price. And so that’s what I think is going to happen to that market.

It’s very liquid.

We’d just say the reality is price will solve any supply issue meaning if it reaches that point, the ARB will close and you’ll have -- somebody won’t be exporting.

Okay, fair enough. And then perhaps an easier question, the CapEx range $300 million for ‘16.

What would push it to one end or the other?

It’s really just getting in, as far as on the growth CapEx of $2.5 billion to $2.8 billion that’s just the timing on how the cash would go out the door.

Okay. And any incremental cost savings available out there as demand for new project strengths?

I think in terms of -- you’re talking about on CapEx projects or just in general?

No, no, CapEx projects specifically.

Bryan, do you see any…

Particularly pipelines outside of the greater Houston region, we’re seeing some cost savings on our capital projects inside the greater Houston area where there is a lot of petrochemical competition, for materials and labor, we’re still seeing -- we’re seeing pricing hold steady.

But you’re not seeing them go…

No, we’re not seeing any significant increase, and we’re not seeing any -- labor is readily available to do all the projects that we’re in the process of executing.

Hi, good morning guys and congratulations on a good solid quarter. So, when you look at onshore crude segment, it seems like there was about 7% or 10% decrease in sequential volumes.

Were there any one-time factors that contributed to that or any specific regions which contributed to that?

The issue is less production in some of these basins, and the Eagle Ford is a classic example. So, we’re having -- our lease buyers are having to hustle a lot more to retain, control the volume and that’s probably the area that we are probably putting the most effort in to shore up over the next year; we’d make some changes in that area.

And then in terms of your project pipeline, just a follow-up to previous question. When you’re bidding on projects, are you looking at enhancing your returns to kind of counter the higher cost of capital while you’re bidding on these projects?

Yes, absolutely. We’re going to be very discipline that -- we’re not going to get aggressive just to get a project.

We’re going to get a project, because it fit us; it’s strategic and it’s got a good return. And we’ll walk away from those that aren’t.

I’d add to that also that we really didn’t lower our return expectations over the last three or four years, just because the cost of capital was less.

That’s fair. And then lastly, if you could remind us on that Centennial Pipeline reversal, any progress on those discussions?

Those discussions are ongoing. We are pretty well-aligned now in that with Marathon, MarkWest.

MarkWest has a need to continue to grow up there and Marathon being a 50% partner in Centennial is aligned with us. So, we are aligned; discussions are ongoing; and we’ll see where it develops.

Just kind of follow-up on the growth CapEx. The 2.5 to 2.8 seems a bit lower than what it sounds like you were thinking in October when I think you said that you expect the total CapEx to be around 3.2 to 3.5.

So, just I am curious if there has been anything kind of pushed out there or sort of what’s driving that kind of somewhat lower CapEx or is that entirely from timing changes and/or cost savings?

Yes. Jeff, this is Bryan.

It’s really more just a shifting on timing as obviously we’re just trying to optimize the timing of our spend and that’s where you saw that a little bit of shift.

And I guess Bryan, I think you said that leverage at the end of year was 4.2 times, are you still thinking that that’s likely to peak around 4.25 early this year or there have been sort of any changes to that?

I think Jeff as we continue to move through our spending cycle, we’re kind peaked towards the middle of the year. So, our leverage will probably peak somewhere in that area of 4.25 to 4.5 times, without any adjustments, just straight leverage.

Right. And just sort of one last from me on the balance sheet issues.

I was just curious, you mentioned sort of obviously EPCO stepping up in the first quarter here, and willingness to potentially purchase more through the year. I guess just kind of obviously Enterprise’s cost of capital hasn’t been hit as hard as many of your peers have.

But do you see any changes to sort of how you are planning to finance capital needs this year or is there a way to sort of put any numbers or parameters on how much EPCO might be willing to purchase as you go through the year?

This is Randy. Yes, EPCO is still coming in, as Bryan mentioned earlier, they’ll come in evaluating additional purchases for the remainder of year but has not made any decision at this point.

But I really -- coming into 2016, we’re really looking at the same way we did in 2015 and 2014 that the funding will be a combination of retained distributable cash flow. We’ve shown over the last couple of years that we’re willing to come in and sell non-core assets.

So, we are willing to do that as well. And then equity rise and then a debt component also.

Thanks. And just one quick operational question from me.

The $50 million gross operating margin contribution from EFS Midstream was a nice increase sequentially. I know you’d spoken about or you have spoken about taking costs out of that system.

So, I was just curious if you give us some color on the breakdown in terms of that increase quarter-over-quarter, volumes versus cost savings?

This is Bill. I am really not sure what your question is taking cost out of the EFS system.

We’ve integrated it in with our South Texas operations and probably taken some cost out of it from that perspective. And we continue to look and discuss opportunities with third parties other than the two companies we bought it from.

And we’re having some promising conversations there about hooking up some other to the system.

Yes, I think that basically is kind of what I was getting at. Alright.

A follow-up on EFS assets, Pioneer is a pretty good partner to have in this environment but they are land on rigs and the Eagle Ford. Has this changed at all how you view the transaction in the near-term or you able to kind look through to ‘17?

And with Bill’s comments just now about hooking other customers up, I mean do you think that can offset any other declines?

In the near-term, we have further than just the near-term we have demand fees associated with that system from the anchors. So, we don’t really view it much differently, maybe a little less upside but as far as the economics goes, still sound.

Got you. And shifting over to LPG exports, there has been a pretty clear downward trend in global pricing compared to U.S.

pricing since you and others really ramped up exports 18 months ago or so. But it still seems you are able to add another year on your term contracts.

Could you all discuss kind of the dynamics in that market and are you still seeing demand for U.S. volumes out in early 2020s?

I’ll try to take it. What you have whenever you look at the ARB, you’re looking at spot freight rates.

A lot of these guys have their own ships under time charter. So, that doesn’t necessarily mean a heck of a lot to them.

But we haven’t had a single cargo cancelled. And propane and to some extent butane in the U.S., it’s got a price to export to a point.

And that’s what we’re seeing. So, remember too, a lot of our stuff, over half I think goes to Central and South America.

So, their alternative is from the AG and that’s quite a haul.

Do you expect with the expansion on line now that you’ll maintain that percentage going to Central, South America or more of those going to be long haul to Asia?

I think we’ll continue the percentage. It’s interesting, we’ve had a -- we’ve signed two large contracts with Asian companies, one going to Japan and one South Korean company.

It brings the question and it kind of raises same issue with crude oil, these guys are looking to diversify their supply. So, strategically it’s important to them they have some volume tied to a transparent pricing point like Mont Belvieu in order to have some alternatives to the CP price out of the Middle East.

Randy, I know both you and Bryan touched on this a bit; could you guys just explicitly lay out for me in 2016, both the equity and debt needs? And on the $1 billion final payment, is that already funded; how do I finance that; and when does it hit, is it second quarter or third quarter?

I think you guys said before July but that would be helpful.

Kristina, the second installment is in July as far as on the EFS Midstream deal. And to say, it’s just not our practice to come in and get -- lay out sort of what our financing plans are in specific detail.

How about non-core asset sales? You touched on that in one of the previous answers to your question; how should I be thinking about that in 2016?

On that front, I think you have a lot of private equity money looking at Midstream assets. I think more of your strategic players and frankly that’s probably where you could get some higher value for some of these assets from the strategics, right now some of them are -- and their cost of capital has gone up as a result of where the capital markets are.

So, the strategics maybe less of an opportunity to transact with them but maybe an opportunity with sales private equity.

And then I know you guys mentioned contract terms on some of the projects, the four major projects that you guys have coming on line in 2016. But are you guys feeling pressure at all from people that kind of -- or customers to move away from your historical -- you are looking for your steady fee-based take or pay terms and just what sentiment there?

And I know you guys probably will say you are not moving away but just pressure in the environment would be helpful.

We’re in a lot of discussions with a lot of producers that as contracts roll off, you got to get creative and you got to be willing to develop a product that they’ll buy. So, it’s not necessarily the same sort of a deal that you did initially.

That’s just reality. We’ve been through that cycle, more times than I like to think of and that’s how you behave.

Just quickly what is your view just from a macro perspective, what it’ll take to rebalance the propane market here; is it more exports, is it PDH? Just kind of walk us through that view.

It’s probably both, Ted, as PDH comes -- but each of those plants, doesn’t use just boatload of propane. They use, what, about 35,000 barrels a day per plant.

That’s what I said earlier, it’s got a -- to a point, it’s got a price to export. But also I think there are contracts we have that are not spread sensitive; they’re source sensitive.

So, export mostly, alright. You talked about the ethane recoveries being strong this quarter; you had a big uptick in your equity volumes.

What’s driving that?

What the question is?

I’m sorry, your ethane recoveries are strong and a big uptick in your equity volumes?

The discretionary recovery.

Yes, we have a discretionary recovery, I think I’ve talked about that before. If the producers elect to what we call conditioning mode there, their percentage of the ethane goes down and we have the ability to extract that ethane if the economics work for us.

And typically it’s certain facilities we’re working on variable cost economics and it does work for us, so where we can do that and particularly where we can lock that ethane in going forward and make some money on it, we do it. And I think we’ve done quite a bit of that here recently.

And then just we’ve talked a little bit about on the industry here, the comments up front around not everybody is going to make it. What does that imply for you more specifically, are you -- rather than selling assets, maybe are you willing to come in on a JV basis on maybe some projects where companies are having issues with financing or is it more just buying assets outright, buying entire companies outright?

Just love to hear your thoughts on that.

We have a lot of joint ventures and we’re not afraid of joint ventures. But joint ventures have to be assets that fit what we are and who we are.

So, I don’t think we’re going to go out and do a joint venture that help a competitor with its financing needs, we may very well look to joint venture a pipeline or plant or something with a producer or a consumer that either brings feedstock to the plant or it consumes feedstock off the plant. That’s historically how we’ve approached joint ventures.

I just wanted to follow up a little bit more on that last discussion there. And going back to what was mentioned earlier in the comments as far as this being a challenging cycle and not all of your peers might make it through in their current form and EPD’s appetite to get involved in that process and take advantage there or just the organic growth opportunity set in front of you is sufficient for what you are looking for and there is no need to go out and get involved there?

I’m going to try it and then I’ll give it to Randy and Bryan. We’re not licking our chops to go out and find things we can buy.

It has to -- it’s just like our organic projects and it’s just like how we approach joint ventures. Strategically, it has to fit us and Oiltanking is a classic example.

Oiltanking fit us; it filled a void that we had and we wanted it. But just to go out, because some is cheap with a pipeline, that’s not connected to where we are, we’re really not interested in that.

Randy, do you want to take a shot, what else was it?

Yes. Jeremy, I come back and really echo Jim.

I think our primary goal right now is to execute on the organic growth projects that are currently under construction, but also some of those that are in the discussion development phase as well. I think from an M&A standpoint, it’s I’ve often said, the first rule is do not harm.

And in this market, I think you need to be very deliberate. But we will come in and look at opportunities.

I think the distress caused by this cycle may provide some opportunities, but we’re going to be putting deliberate as we go through and take a look at them.

And if you look at what we’re doing and if you listen to -- read the script of Bryan and mine, almost everything we talked about in there were demand pull projects. The only supply project that we’re doing right now I think, and I’m looking around the table, is our Permian pipeline.

And that’s strategic because we felt like we really needed to be in the Permian that we think so highly of it. But things like export facilities and Aegis pipelines and ethane export facilities and PDH plants, we like those things.

That’s really helpful, thank you for that. And just one last one if I could.

As far as the asset sale, sorry if I missed it this quarter. Could you share any more color on what that was?

We sold our Rocky Mountain crude oil business and then we sold some marine assets offshore crude barges and tugs.

The Rocky Mountain crude oil business was a marketing business.

It was a marketing business, it had few truck unloads and it fit somebody else much better than fit us. It’s classic example, we’re not going to -- we’re not afraid to prune.

I had a question about your CapEx, and you’ve touched upon it a little bit. But Bryan, when you said you are optimizing timing of certain projects, just wondering if any of that -- I mean they are mostly more midstream type of projects that are being pushed out in anticipation of producer CapEx cuts.

And also on that CapEx guidance for the year, just wondering how much of the Midland to Sealy spending is included roughly speaking like half or less than half…?

Well, we’re not going to give you specifics around that, but you’re hunting in the right blind.

Okay. You mean related to the first question, the optimizing timing of certain projects that’s mostly midstream related to sort of producer activity, is that what it is?

No, with respect to what you think about, if there is a shift, look at the projects that are scheduled to be completed post 2016 and that gives you a sense of which projects we might have a shift and spending. And its’ just a timing matter.

And we’re not going to shift it beyond what our obligations are. So, we may -- when he says optimizing, we’re still going to bring it on when we’re obligated to bring it on.

We just may not bring it on early.

Yes. And Helen, with respect to Midland and Sealy, really the bulk of the CapEx around Midland and Sealy is more in ‘17 than what it was in ‘16 and -- I mean pipe has been ordered on that but again the bulk of the costs are in ‘17.

Okay, that’s very helpful. And then just on petchem businesses, you mentioned the outage, the MTBE outage and that’s coming back on line in February.

So, is that -- are you able to quantify the effect and maybe would the first quarter be somewhat similar to fourth quarter given this dynamic?

This is RB. Yes, first quarter will be similar because we’ll have a little over a full month of operation in the first quarter, like we did in the fourth quarter.

But our outage was going to extend longer. So initially, we would have had more in 2015 and less in ‘16.

So, its’ starting to turnaround early, a bit more into 2016.

You might mention why we are turning it around, what we gained from that?

In addition to our turnaround, we are also doing a pretty substantial capital improvement project out there at the MTBE plant. And what that will do is -- historically we’ve taken an annual turnaround and this project will allow us to run anywhere from three to four, potentially more but we’re counting on -- we are seeing three for now, years between turnaround.

So that will be producing more margin, every year going forward.

And just if this particular segment, it’s not -- could you remind me how sensitive it is to commodity price? It’s probably not as sensitive as of course your processing business?

It has some sensitivity but the need for octane is still very strong right now, even in this environment. And so, MTBE is still very good business.

Not only that, it gets less sensitive, Helen, as we bring on the PDH plant.

Great, thanks for taking my question, I have two. One, in the commentary on the crude oil pipeline side, you highlighted that marine loading and unloading volumes were down more than 200,000 barrels a day.

And I was just wondering what’s going on here competitively? I hear a lot of other companies investing in marine storage and terminaling, and just wondering if the landscape is changing at all or whether that’s just pricing stress.

Did we say loading or did we say marine? It could be that it’s less imports as productions has more adequate coming out of the U.S.

Yes, Poe. What we -- from a marine volume standpoint, I think year-over-year we were about flat at 1.2 million barrels per day but to Jim’s point, it has shifted where you have -- we had less barrel on the unloading side and more barrels on the loading side.

So, more barrels on the export side.

We make more money on exports than imports, it is a fact.

And then to quantify was it 10 million on the MTBE or was it less than that?

Yes. Poe, ballpark for as far as fourth quarter impact from the facility going down is call it right around $20 million.

Just a couple of questions, one is just on the NGL Pipelines & Services segment. The $12 million increase in gross margin which you talked about as being benefited from the LPG exports and then the $58 million increase in NGL pipeline and storage which you also sort of attribute to higher loading and unloading volumes at the NGL marine terminals.

How much of that is sort of I guess attributable to the expansion that came on line in the fourth quarter?

Really none, because the expansion really came on at the end of the year. And so, really the benefit from that you will start seeing in the first quarter of 2016.

We did our smaller expansion; it did come on earlier in the year. So, that’s probably attributed some to that.

This is Al. We also continue -- as we said last year, we did month after month continue to expand and grow our butane export business.

So in addition to the propane expansion, we still have capacity to load normal butane, isobutene or mixed butanes. And again, we have pursued contracts here, both on a spot and term bases.

And how much was sort of I guess through, you said you received term contracts on spot and term basis, but how much of that was -- I guess the spot volumes would be through your marketing arm and then the term contracts would be through the pipeline and storage business. Is that right?

The way the gross operating margin from LPG export activity show up, it really shows up principally on two assets that are in that petrochemical or in the NGL Pipeline & Services segment, it shows up at the dock and then it shows up at the pipeline and services at the dock and then the other piece of it shows up through NGL marketing. So, it’s really in three assets.

Okay. And then in the last quarterly call you guys gave an update and what shipping costs sort of done over the course of last year.

Do you have any update to that, where are we with sort of the cost to get LPG out of the U.S.?

It’s gone down dramatically. Al, have you got the numbers?

We saw it go as high going into the Asian markets over $200 a ton; Europe I think got as high as 125, 130 and it’s come down significantly. Quite a few ships have been added and will continue to be added.

So, what is it now to Europe $40?

Yes, roughly.

So $40 a ton right now to go to Europe.

About 40 to 50.

Okay.

But that’s from 125, and it will go down further, because there is a lot more shifts coming on the market.

And last question, it looks like maintenance CapEx was trending down in the quarter. Just trying to understand what’s going on there or just a right level of that when you look at going into rest of 2016?

In terms of maintenance capital, nothing significant, just we evaluate projects as we go through the year and we think we’ve got to right level and we’re going to be right about that level in 2017, nothing or 2016 no substantial changes in our plan.

Okay. It was down, it look like it was down roughly 5% from where you were trending during the year.

I’m just wondering if that was related to the sale of the offshore business or -- and then just also your projects coming on line, so that would be a bouncing sort of number?

The way the sustaining capital or maintenance capital is just not that consistent, some timing issues, particularly a lot of -- it’s a number of smaller projects and it will vary -- 5% variability quarter-to-quarter, it’s nothing out of the ordinary.

Could you talk a little bit about the customer credit exposure? I know you said a lot of things are downstream oriented, obviously with the pressure on commodity prices.

Maybe give us a run down and how you see that exposure this year?

Sounds like a Bulawa question.

Yes. John, in my comments actually I went over that.

We have 8 sub-investment grade independent E&P producers in our portfolio as measured against, and that represents about below over 2%, the 2.4% is what I said as far as measured against 2014 revenues. Otherwise, the other proportion which you might have missed in the call was about 80% of our overall customer profile is investment grade.

And then if on the -- as far as going the outlook here, volumes generally -- comment on declines you’re seeing in the Eagle Ford in particular that would be helpful?

I mean we are seeing some declines, they are not dramatic at this point in time. But we’re seeing some declines on our system.

But we do have largely on that system, it’s take or pay arrangements with efficiencies due to the producers if they drop to low certain levels.

Okay. And then how are you seeing things in the Eagle Ford?

That was the Eagle Ford.

That is the Eagle Ford.

Is that matched generally across the system, not seeing a whole a lot of declines?

We’re seeing the Permian is going up where we’re gaining volumes in the Permian and rest of the system I think is fairly flat, and Eagle Ford is a replace we’re seeing some decline.

Bryan, I just want to follow up with you. Thinking about the financing side of the equation for 2016, just wondering if there are some things that maybe are less obvious to us that might be benefits thinking about your storage position for example and the reduction in commodity prices.

Are there working capital benefits of any meaningful degree that you are anticipating that we should be aware of or things of that nature that we could maybe pay attention to in terms of addressing some of the opening exposure on the financing side?

Well just on the working capital side, we actually probably will see -- and that will probably add to some of the comments we made early around leverage. As you actually would see probably an increase because I think we’re seeing -- we expect to see in this sort of environment opportunities that would consume capital with respect to short-term opportunities in around back-to-back type marketing activities and across the commodities.

I think some of the things that we’re -- we’re seeing some opportunities. If you go back to 2009, we saw a good bit of opportunity from contango standpoint and to the extent that we have storage capacity, we’ll take advantage of that.

We did some of that in 2015. And so again seasonally that would affect you upon on working capital standpoint.

Okay. And then final question for me is just with regard to any known planned maintenance outages or turnarounds likely you experienced here in the fourth quarter; anything you should or could highlight for us, so we should make sure we have in there on a quarterly basis throughout the balance of ‘16?

The only real planned outage that we have this year is in the third quarter for our -- one of our isom [ph] units, we’re doing some -- taking it down for some inspection work that’s about it.

Thank you. All my questions have been answered.

I appreciate it.

This is Greg sitting in for Harry. Just a quick question on the debt side of things.

I was wondering if you can give us your updated thoughts around your hybrids that one of them is callable in the next six months, just looking for your updated thoughts there.

It’s interesting that we are coming up on the first call date on the hybrids that are outstanding and if you would were in another period, I guess similar to when we issued the hybrids a while back as far as in a stress related period, you have some companies coming out now with hybrid type securities. It would be counter to the trend, if we call the hybrids when everyone else is issuing hybrids.

So, the purpose of those securities were to give us some flexibility in difficult times. And right now we’re in one of those times.

So again, we’ll evaluate it when we hit that first call date; we’re not on the first call date now. But I mean, if we see market conditions the way they are now, our expectation is we just leave them out.

Jinger, this is Randy. We have time for one more question.

If you don’t mind, Jinger, would you give our listeners the replay information for the call?

And this is Randy again. I would like to thank everyone for listening in on our call today.

And that ends the call. Thank you and have a nice day.