Randy Burkhalter – VP, IR Michael Creel – CEO James Teague – COO Randy Fowler – EVP and CFO William Ordemann – Group SVP Anthony Chovanec – SVP Graham Bacon – Group SVP

Brian Zarahn – Barclays Capital Darren Horowitz – Raymond James John Edwards – Credit Suisse Danillo Juvane – BMO Capital Michael Blum – Wells Fargo Axel Styrman – Nordea Faisal Khan – Citigroup

Thank you, Tony. Good morning everyone and welcome to the Enterprise Product Partners conference call to discuss results for the third quarter of 2014.

Our speakers today will be Mike Creel, CEO of Enterprise’s general partner, followed by Jim Teague, Chief Operating Officer and Randy Fowler, CFO. Other members of our senior management team are also in attendance today.

During this call, we will make forward-looking statements within the meaning of Section 21(e) 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 Enterprise’s management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such expectations will prove to be correct.

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

Thanks, Randy. We reported third quarter earnings this morning highlighted by increases in gross operating margin from four of our five business segments.

Gross operating margin increased 16% over the third quarter of 2013, supported by record liquid pipeline volumes and fee based natural gas processing volumes as well as higher NGL fractionation volumes. We also benefited from $4.9 billion of new assets that were placed in service over the last 12 months.

These strong results led to increased distributable cash flow of $975 million compared to $908 million for the third quarter of last year. That’s a 14% increase after excluding proceeds from sales of assets for both periods.

Earlier this month we declared a $.365 per unit cash distribution with respect to the third quarter, which is 5.8% higher than the distribution paid with respect to the third quarter of last year. This is our 41st consecutive quarterly distribution increase and the 50th increase since Enterprise’s initial public offering in July of 1998.

Distributable cash flow provided 1.4 times coverage of the distribution declared for the quarter. We retained $284 million of cash this quarter and just over $1 billion of cash during the first nine months of this year, to reinvest in the growth of the partnership and reduce our reliance on capital markets.

Gross operating margin for the NGL Pipelines and Services segment increased $72 million or 11% to $712 million compared to the $640 million reported in the third quarter of 2013. Our natural gas processing business reported a $45 million increase in gross operating margins, driven by better processing margins at certain plants and record fee based processing volumes of 5 billion cubic feet a day.

This was offset by $48 million decrease in gross operating margin from our NGL marketing business, primarily due to lower margins in volumes resulting from expansion related downtime, associated with our LPG export facility. In the third quarter of this year more volume in the LPG export business was associated with long-term fee based contracts as oppose to higher margin spot business in the third quarter of 2013.

Gross operating margin from our NGL pipelines and storage business increased $47 million or 20% to $278 million for the quarter, primarily related to our ATEX ethane pipeline and our Rocky Mountain pipeline expansion both of which began commercial service in January of this year. Gross operating margin from our NGL fractionation business increased $27 million or 23% to $143 million for the third quarter, compared to $116 million for the third quarter of last year.

Our seventh fractionators at Mont Belvieu begin commercial operations in September of 2013 and our eighth fractionator began operations in the fourth quarter of last year. Total fractionation volumes increased 12% this quarter primarily due to higher volumes from the Eagle Ford and the Rockies.

Gross operating margin from the onshore crude oil pipelines and services segment increased $45 million or 31% to $191 million for the quarter. We had a $14 million increase in gross operating margin from our investment in the Seaway pipeline, which benefited from a tariff increase applicable to long haul volumes effective July 2014, and that was partially offset by lower volumes.

Our West Texas and South Texas crude oil pipeline systems, Eagle Ford joint venture pipeline and ECHO terminal reported an aggregate $25 million increase in gross operating margin in the quarter, compared to the third quarter of 2013 and that’s on a 74,000 barrel per day increase in volume. The Petrochemical and Refined Products Services segment had a $73 million or 63% increase in gross operating margin to $190 million for the third quarter, compared to the third quarter of last year.

Our propylene business contributed $37 million to this increase, primarily due to higher sales margin and volumes and lower operating expenses. Operating expenses for the third quarter of last year included $16 million of maintenance cost that was not repeated this quarter.

Our refined product pipeline and related services business reported a $45 million increase in gross operating margin, primarily due to lower pipeline integrity cost and other operating expenses as well as higher transportation fees. Gross operating margin for the Offshore Pipelines and Services segment increased $9 million or 24% to $47 million, primarily due to $7 million in equity earnings from the Lucius oil pipeline that began operations in July of this year.

Total offshore crude oil pipeline volumes increased 7% over the third quarter of last year. We expect continued growth from our business as we put new assets into service and increase the utilization of recently completed projects.

Approximately $4 billion of the $4.9 billion new assets put into service during the last 12 months were completed in the first three quarters of this year and we expect another $2.5 billion to be completed in 2015 and about $3.5 billion of new assets to go into service in 2016. This does not include projects that are currently under development, as is our custom we’ll announce the details of projects under development when they are actually sanctioned.

On October the 1st we announced a $4.4 billion acquisition of the General Partner and related incentive distribution rights 15.9 million common units and 38.9 million subordinated units of Oiltanking Partners from Oiltanking Holdings America. The subordinated units will convert into the same number of common units after the next Oiltanking distribution is paid on November the 14th this will result in Enterprise owning 54.8 million Oiltanking common units or 66% of the then outstanding common units.

The $4.4 billion acquisition was comprised of $2.21 billion in cash and 54.8 million Enterprise common units. As part of the transaction we also paid $228 million to assume notes receivable issued and payable by Oiltanking and its subsidiaries.

As previously disclosed we also submitted a merger proposal to the Conflicts committee of General Partner of Oiltanking to merge Oiltanking with a wholly owned subsidiary of ours. Since this proposal is pending we will not take questions regarding the merger proposal today.

And with that I will turn the call over to Jim.

Thanks, Mike. As Mike said we continue to put a sizable amount of assets in service, we also continue announce plans to build others and example as we recently announced that we were going to build a new processing plant at Delaware Basin.

In addition to the plant we are building 80 miles of natural gas gathering that will complement the 1,500 miles we already have in the area. We’re also adding a 75 mile Y-grade NGL pipeline to take the liquids to our fractionation system.

This plant will have initial capacity of 200 million a day and frankly show a lot of interest for expansion. The Delaware Basin is an area where we have a good footprint and an area where we expect to continue to be active.

Last month we also announced our ninth fractionator at Mont Belvieu. With increasing volumes of NGLs around the country and growing domestic and global demand interest has been strong for incremental Gulf Coast fractionation.

At 85,000 barrels a day at nameplate, this plant is similar to others we have recently build brings our Mont Belvieu fractionation capacity to well over 750,000 barrels a day with over 1.2 million barrels a day system wide. With this fractionator and the PDH plant we have under construction plus a couple of other projects underway related to supplying product for export, things are busy at Mont Belvieu where in addition to our operations personnel we have another 2,400 contractors on-site.

U.S. producers are continually getting better at what they do and NGL supply is continue to grow, world understand its potential and all roads for NGL seem to lead to the U.S., whether it would be production from the Eagle Ford, the Rockies, the Permian, Appalachia our market oriented projects, including exports we’ve on a significant building bench, particularly at Mont Belvieu for the last several years and frankly we don’t see that changing any time soon.

As to crude oil our build out of our storage at ECHO continues we are headed to somewhere in the neighborhood of 7 million barrels of capacity, what’s exciting is that capacity is sold out for over five plus years. In addition we completed our 95 mile 30-inch lateral from ECHO to Beaumont Port Arthur and we continue to build out our 30-inch Rancho II crude oil pipeline as the pipe from Sealy into Houston that move growing supplies of crude into ECHO.

Demand for U.S. process condensate is robust as evidenced by the fact that we are sold out through the end of the year.

Furthermore work is underway in combination with our water front position, that will result in our process condensate export capabilities being over currently available supplies. Consequently we are working closely with condensate producers in the Eagle Ford, the Permian and North and West of Cushing to close that gap.

For crude oil just like to NGLs or natural gas we understand their roles to give producers flow assurance and market choices and to give consumers supply reliability and market flexibility. I am not sure we talk enough about our focus on markets in order to create new market availabilities for producers.

The good example of that is our initiative thanks to Bill Ordemann to classify processed condensate as a product that is excluded from the ban on exports of crude. That’s a way of creating more market choices for our producers.

Another example is our LPG exports, this year we will be knocking on the door of exporting of close to 100 million barrels of LPG and work continues on our two export expansions. Whereby the end of next year we will nearly double our capability.

Another example of creating more market choices is our ethane export facility at Morgan’s Point of Houston Ship Channel. A lot of folks didn’t think this could be done.

Must admit five years ago it wouldn’t be done however there were others both producers and consumers alike who told us not to give up and to keep trying because it’s simply made too much sense. In April, we announced our ethane export project at Morgan’s Point and since that time we have received key permits and major equipment has been ordered.

We’ll begin construction next month with completion expect in the third quarter of 2016 and frankly customer interest remains strong. While 200,000 barrels a day of ethane exports doesn’t clear the ethane excess developing significant and viable export avenues is an important signal to U.S.

producers thousand enterprises on their side. An example of supply reliability and flexibility for consumers is our Aegis ethane pipeline, where we recently put the first leg of the pipeline between Mont Belvieu and Beaumont into service.

And work continues to extend this new pipeline into the Lake Charles now on to the Mississippi river corridor by mid next year, third quarter of next year. When complete we will have a 500 mile dedicated ethane pipeline that stretches from Corpus Christi to the Mississippi River, supporting both the existing and new ethylene plants all along the Gulf Coast.

This pipe is backed by over 200,000 barrels a day of firm commitments and we continue working with several potential customers, who have an interest in both new Greenfield ethylene plants and expansions. In addition to the transportation commitments, Aegis customers are also signing up for other product and services such as term ethane suppliers and storage in Mont Belvieu, in order to support their demand and the sizable investments they are making.

Another example for producers, another example of both flow assurance for producers and reliability for consumers is the PDH plant where we are going to take 35,000 barrels a day of natural gas derive propane and convert it into a higher value product polymer grade propylene. The Seaway pipeline is another example, where we reversed it and looped it unlocking the land lock crude production in the Midwest.

On the refined product side repurposing and upgrading of our southern complex to be able to export refined products, which incidentally sold out now gives our Gulf Coast refining customers, more market choices and less demurrage and the same can be said about our recent project to use existing pipe to be able to deliver natural gasoline from Mont Belvieu to the Midwest where then move zone to Cochin or southern lights for delivery to Western Canada to be used as a daily one. And finally crude oil prices, obviously we’ve seen a rapid meaningful price correction caused by weaker global demand and growing supplier both here in the U.S.

and by some of the OPEC players. While I can’t predict the oil prices or what OPEC will do or not do, $80 oil prices aren’t killing the shale oil producer.

Our analysis shows that most if not all of the core drilling area in key oil plays such as the Eagle Ford, Permian and Bakken are profitable at numbers below where we are today and U.S. drilling is certainly not grinding to a haul.

The U.S. is in the middle of a production revolution because U.S.

producers and the service companies that support them are pretty creative people, that’s what brought us the shale revolution and it’s what will drive this industry to work harder and a lot smarter to produce these resources at lower prices. You don’t have to look at any further than our recent experiences in shale gas as a gauge of the resourcefulness of U.S.

producers this is an industry that continues to prove that necessity is the mother of inventions. With that we turn it over to Randy.

Thank you, Jim. I will cover a few additional items.

As a reminder, when calculating earnings per unit through your model or reconciling item between our non-GAAP gross operating margin and net income are the non-refundable deferred revenues that are attributable to ship or makeup rights on some of these new pipeline projects. This quarter the deferred revenues that are excluded from net income and earnings per unit totaled $22 million and year-to-date that was $67 million.

Interest expense increased to $230 million for the third quarter of 2014, compared to $208 million last year. This increase was primarily due to higher average debt balances and a decrease in capitalized interest.

Growth capital expenditures were $772 million in the third quarter of 2014, capital expenditures were $772 million which includes sustaining capital expenditures of $107 million. Through the first nine months of this year we invested $2.2 billion in growth capital projects and we now expect total growth capital expenditures this year will be approximately $3.1 billion as some growth CapEx has slipped into 2015.

We currently expect growth CapEx for 2015 to be in the range of $3.7 billion to $4.2 billion. We had $262 million of sustaining capital expenditures for the first nine months of 2014 and we still expect to have a total of $350 million of sustaining CapEx for the full year.

Adjusted EBITDA for the 12 months ended September 30, 2014 was approximately $5.1 billion our consolidated leverage ratio of debt principle to adjusted EBITDA was 3.7 times, this gives 50% equity treatment to the hyper debt securities after adjusting debt for the $1.1 billion of cash on hand at the end of the third quarter our net debt to adjusted EBITDA was 3.5 times. At September 30, 2014 we had consolidated liquidity of approximately $4.8 billion, which included $1.1 billion of unrestricted cash and approximately $3.7 billion of available borrowing capacity under our credit facilities.

Earlier this month we issued $2.75 billion of senior unsecured notes in a transaction that was strongly supported by our debt investors. The offering included $800 million of five year notes, $1.15 billion 10 year notes, $400 million of 30 year notes and another $400 million of 40 year notes.

This offering generated almost $12 billion of investor demand, including $1.5 billion of demand for the 40 year notes. Enterprise was the first MLP to issue 40 year notes.

We are very grateful to our debt investors for this level of support. After adjusting our debt portfolio with September 30th for the sources of the $2.4 billion of cash consideration that we paid in the Oiltanking transaction, the $2.75 billion note issuance and the October 15th maturity of $650 million of notes, the average life of our debt portfolio is 14.7 years using the first call date for the hybrid securities and our average effective cost of debt is 5%.

I think with that Randy I think we are ready for questions.

Okay. Tony we are going to take questions now from our listeners.

Good morning.

Good morning, Brian.

I was wondering if Jim could elaborate a bit more on the condensate export opportunity and any additional infrastructure and investments required or is it more just getting the barrels to your system?

Supply obligation is always key Brian and it’s kind of what we are focusing on right now, there are few things we need to do to up our capabilities, but we are in the process of doing that Bill.

Well the middle to early third quarter next we’ll have a new pipeline in place between Sealy and Houston and that will allow us to bring a lot more volume, we are currently very, very close to being constrained in moving those Eagle Ford barrels into Houston.

So it sounds like your existing pipeline infrastructure and waterfront is sufficient to handle the growth?

Yes with the new pipe we are installing yes.

Okay. On the heels of your NGL and gas project announcements in the Delaware Basin, do you see any other opportunities out in the Delaware?

Well absolutely probably not that we are going to tell you about right now Brian.

I had a try. That’s my job.

We like that area and we’re pretty proactive.

Anything on the crude side?

In what respect?

Gathering or any other infrastructure that you could see for growth opportunities in the Delaware?

Yes.

Okay. I guess sticking on crude, I guess Jim or Bill, can you comment a bit on the proposed Bakken/Cushing crude pipeline and any impact on the crude price pullback?

I think that project is going to be we extended the open season frankly Brian crude prices aren’t going to help that project.

Okay. Are there any other, besides the crude pullback, any other sort of competitive dynamics for that project or what’s your general view on it?

I don’t know what you’re asking Brian.

I guess how confident you are on a successful outcome for the open season.

We are $100 that have been a lot more confident than I am at $80. I mean we have a high quality producer, that’s made a sizable commitment, we have a threshold that if we reach that threshold we’ll build and at this point we haven’t reached the threshold that we do have one sizable producer that’s made a pretty sizable commitment.

Okay, last one for me. Can you elaborate a bit more on what you see the long-term growth opportunities with the Oiltanking assets?

Hey Brian this is Mike, as I said we’re in a middle of discussions and our largest hit they will slap us on the wrist if we mentioned anything about it.

That was another nice trap.

Tried to slip one in there. Thanks very much.

Morning guys. Just a couple quick questions for me Jim, going back to that condensate discussion and maybe this is a better question for Ordemann, but I’m just curious if we can put some numbers around as you said, the mismatch between processed condensate export capabilities and supply growth.

Last time we talked we were discussing about 500,000 barrels a day of condensate coming out of the Eagle Ford and I’m wondering do you think that that mismatch in terms of being constrained is you only have 50,000 or 100,000 barrels more of incremental capacity? Or I’m just wondering if we can put some numbers around it to get a sense for how quickly we need a solution and what it could do for producer netback economics?

Well it’s going to help producer netback economics.

Well we’ve got a partial solution anyway that I mentioned before when we get this we’re calling our Rancho II pipeline in place kind of around the city Houston here mid third quarter of next year it’s going to open up a lot more capacity and we think we have some dock capacity available to handle that how much we can handle we’ll see and as Jim mentioned it’s going to be around the supplier aggregate how much supply we can aggregate. Now others do have some ways to get that process condensate to other locations where potential be export as well.

So not going to speak to them, but I think we are in the process of in the Eagle Ford anyway looking ahead at getting that taking care of and pretty much substantial increase in our volume of exports come maybe around the August of next year.

Bill, besides that Rancho II line, how much more incremental CapEx do you think you need to spend on dock and handling capacity to actually get that product on the water?

So very, very little.

Okay. Last question for me just thinking big picture when we’re looking at the refined product movements and the petchem exports and Jim you alluded a lot to this, but over, let’s just say the next two years from a capital standpoint, how much do you think you’re going to need to invest in terminals with water access at areas like Morgan’s Point and Texas City and Freeport and even east of Beaumont just to keep pace with supply growth and the need to get a lot of those refined products on the water?

Whether or not it’s gas, oil, or light naphtha to Latin America or what have you or maybe even isobutylene or PGP it seems like that’s the next, when you think about demand pull from a capital investment perspective that’s the next big wave of infrastructure that needs to be done because of the supply push infrastructure has a bit of a head start. Am I thinking about that the right way?

Probably and I think the only way we can answer that is we feel pretty good about our position where as Bill mentioned we’re doing things at Texas City, over in Beaumont with the Enterprise facilities we know what we to do to add capacity, we can do that very reasonably. And I mean it’s pretty obvious where we are heading.

Yes, I was just wondering if we could put some numbers around it in terms of capital. Maybe the bigger question Jim for you is, as you look out call it three to four years from now, how critical of a market from an export capability or a lease out perspective do you think Beaumont is going to be?

We think it’s going to be big, it’s going to be sizeable it could even create some pricing dislocations that provide you guys specifically with more margin capture opportunity, but I’d love your perspective on Beaumont.

I think it’s going to be big I think the fact that we’re already sold out at our terminal and I mean within three months of announcing it, says a lot Darren and believe me we’re focused over there.

Okay, well I appreciate it, Jim. And obviously, the Oiltanking acquisition speaks to that, so I think they have a little bit of acreage over there.

Thank you.

Thank you, Darren.

Yes good morning, everybody. Just following on Darren’s question, in terms of capital allocation then are you guys seeing I guess more or a bias toward more fulfilling export opportunities versus other opportunities?

Maybe if you could enlighten us a little bit more on that?

Hey John. I think export opportunities is one way we’ve given producers market choices, but the real key to any market choices we give them whether it’s a distribution system of all the refineries, whether it’s an export capability for process condensate, it really starts with supply aggregation which is what Bill talked about.

So and this maybe little bit of an answer for Darren, so as we look at the Eagle Ford for example you can bet we’ve got one heck of an initiative to identify processed condensate opportunities if necessary what the heck, build to stabilize ourselves and I don’t think it’s any secret build that we’ve got some pipeline projects out there that are being driven by wanting aggregate more suppliers. We think what’s going to be important in the future regardless of what the market choice is, is that you have more segregation in your crude oil pipelines, every pipeline – our Eagle Ford pipeline has three segregations, our other pipeline projects have multiple aggregations, we think that’s going to be important in the future.

So we keep focus on what you guys got to spend export what we’ve got to spend is to aggregate because the export capability isn’t going to be that bigger deal I don’t think.

I think that’s what I said before the export capability is not going to need a lot of investment at this time we don’t believe, but the key is going to be is to be able to segregate volumes and bring them in so they can be exported.

Okay, that’s really helpful. And then maybe if you could just speak, I mean you alluded to this Jim in your opening remarks, but as far as the volatility of crude on your project opportunity backlog, maybe if you could speak to that?

Are you seeing things start to get pushed back at all or are things still continuing? Just a comment on how that’s impacted your opportunity backlog would be great.

If it’s impacted anything we’re doing it’s probably that Bakken project, because I mean it’s kind of simple it’s the furthest from the market. We haven’t seen any impact and what we’re doing out in the Permian we haven’t seen any impact what we are doing in Eagle Ford.

John Bakken pipeline is not one that we’ve included in CapEx numbers and so when we’re talking about $3 billion and $4 billion in 2015 and ‘16 that’s without the Bakken pipeline.

Okay, so as far as what you’re actually committing to, you’re on the same trajectory that you were prior to the volatility here?

Absolutely.

Okay, great. That’s very helpful.

That’s all I have, thank you.

Thank you. If I could go back to the Bakken pipeline for a second, with the recent dynamic of rail being squeezed both on the East Coast and West Coast in terms of the differentials relative to WTI, are you seeing that as a potential opportunity to maybe capture some producer commitments even though oil prices obviously, are not that attractive right now?

Absolutely if this thing is successful that’s going to be a major part its success people are recognizing that, rail is going to be difficult.

Okay, to that end, is that something that maybe moves you over the hump from a commitment threshold standpoint, relatively soon or how do you sort of think about that?

We’re not as far as away as I thought we would be from that threshold, no we are not it’s going to depend on the producers are willing to believe that step up we are in conversations with very large number of them right now and Frank will get the indication he needs more time so we extended the open season here through November ‘14 I believe and we’ll see what we can pull together by then we certainly continue dial up with it.

We got people who are pretty excited about it, I am worry about it, but I worry about everything.

Okay, great. That’s it from me guys, thank you.

Hi, good morning, everyone. Most of my questions I think have been addressed but just one question on your thoughts on the LPG export markets, you’re seeing some of the global or the global arbitrages narrow here a bit.

You’ve got a lot of incremental capacity including your own export capacity, coming online here over the next three to six months. Just curious how you think that all plays out and do you think if you assume that the U.S.

continues to export greater quantities of LPGs is the global market kind of deep enough to absorb all that or does that end up kind of saturating that market and pushing that product back into the U.S.?

From what I have seen right now I don’t see anything that will keep it from – I don’t see any constraints on the market side, you are right the arb is closed a little bit, the way it works the arb will open because it has to, ship owners they try to get their piece of the pie they’re kind of like service companies with E&P companies they get their piece of the pie they things close a little bit, they sit there and hold on and see what’s going to happen and ultimately they lower their freight rates. The difference in us and some of these others we’re sold out for the next three, four years I think so my point is you’re going to see the arb open back up because it has to, it’s going to open up in two ways probably freight, which is what $100 a ton to Europe which is in my date I always plan on it be in $25 a ton and either the price gone up in Europe or it’s coming down here one or the other.

If you have a normal winter it will probably be the ladder.

Great, thanks. Appreciate that.

Hi, good morning. I have a couple of questions regarding the LPG exports, your export capacity.

You briefly touched on the oil price hovering around $80 per barrel and I’m wondering if, you probably answered that current oil price, you don’t expect the volumes to be impacted, i.e., your plans regarding expansion for LPG exports next year will continue as scheduled. So then, next question is what level of the oil price do you think will influence the volumes?

Your first question we’re not worried about next year’s LPG exports. We think that will, I don’t know what oil price changes that situation.

This is Tony, when we look at the core areas in each of the major plays, and of course producers are always trying to extend after core areas into the non-core areas to broaden our footprint. It varies from play to play, but core areas are solidly in the money on the major oil plays, at prices we have today and below.

There is a point where producers quit, start to throttle back on the fringes but the fringes aren’t where the bulk of the production is projected to come.

Yes, so again, then you expect the volumes to, your plans for 2015, your budgets, you expect these volumes to regarding your expansion and you solid your capacity to go ahead as scheduled?

Absolutely.

As Jim said the export facilities are sold out. So we’ve got long-term fixed price deals there.

Okay, thank you.

Hi, guys, thanks for the time. I have a couple of dumb questions.

First one, just in terms of the condensate exports is that showing up in the refined products pipeline and related services business or is that showing up in the LPG business?

It’s actually showing up in the crude oil business.

The crude oil business? Okay, so, there you go, I got that wrong.

I thought it was a refined product right that’s what we’re exporting, but we’re exporting crude oil. On the LPG side, you guys talk about sort of having the impact of downtime.

I just want to understand a little bit better. So the $48 million decrease in operating margin, is that mostly associated with the downtime with the facility or is there something else going on with margins that we didn’t know about?

I would have to look back, but I would be willing to bet you that we had some very high priced spot cargos last year, and this year we are full up with contract cargos and Graham how long we’ll be down because part of it was a downtime.

We have both things down different times of around seven days.

So we had seven days of downtime doing tie-ins related to the expansion. So it’s combination of those two things.

Yes and more of it was with respect to the lower margins with instead of the downtime.

Okay, so I mean if you didn’t have the downtime, would there be any sort of lost economic opportunity?

Yes we wouldn’t have these high price spot cargos that we had last year.

Okay, I’ve got it. On the operating margin increase for the natural gas processing plants, the $45 million increase, so what you said I guess in your commentary, you talked about sort of higher processing margins at certain plants.

It seems like a very large number to sort of move in one year-over-year from this margin from certain plants so just trying to understand that movement too?

Yes Faisal this is Randy, I think some of it last year if you would we were extracting more ethane at de minimus economics at the processing plant, sort of again coming in and using our entire system and using our variable cost in the analysis. This year we are doing less of that and so we’re having more ethane rejection, so as a result you are seeing better margins at the processing plant, but you are seeing lower volumes like for instance Mid-America and Seminole were 60,000 barrels a day that’s more ethane rejection flow into downstream pipelines.

Okay, because it looked like the equity NGL production decreased quite a bit sequentially.

That’s basically all elective ethane on our part. So we recovered that ethane on variable cost last year and this year we’ve elected to reject it, so conditioning where they reduce their recoveries further contracts we the right to continue to extract that ethane, last year we elected to do that, this year margins where they are at we’ve elected to reject it, so that’s why the loss you see in that volume.

Okay. And that, also, is the same reason for the sequential decrease, as well, from second quarter to third quarter?

Yes.

Okay, okay. Understood, guys.

Thanks, appreciate the time.

Okay, Tony thank you. If you wouldn’t mind would you give our listeners the replay information before we close the call.

Okay, thank you Tony. And thank you for listening to our call today and have a good day.

good bye.