Enterprise Products Partners LP (EPD) 2014 Q3 法說會逐字稿

Good morning. My name is Toni and I will be your conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners Q3 2014 Earnings Call.

(Operator Instructions)

I would now like to turn the call over to Randy Burkhalter. Sir, you may begin.

Thank you, Toni. Good morning, everyone. Welcome to the Enterprise Products 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.

Now 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 the call. 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 $0.365 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 margin, driven by better processing margins at certain plants and record fee-based processing volumes of five billion cubic feet a day.

This was offset by a $48 million decrease in gross operating margin from our NGL marketing business, primarily due to lower margins and volumes resulting from expansion-related down time associated with our LPG export facility. In the third quarter this year, more volume in the LPG export business was associated with long-term fee-based contracts, as opposed 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 fractionator at Mont Belvieu began 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 margins and volumes and lower operating expenses. Operating expenses for the third quarter of last year included $16 million of maintenance costs 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 costs 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 in 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 will announce the details of projects under development when they are actually sanctioned.

On October 1, 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 14. 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 the 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. With that, I'll turn the call over to Jim.

Thanks, Mike. As Mike said, we continue to put a sizeable amount of assets in service and we also continue to announce plans to build others. An example is we recently announced that we were going to build a new processing plant in the Delaware Basin. In addition to that plant, we're building 80 miles of natural gas gathering that will complement the 1,500 miles we already have in the area and we're also adding a 75-mile Y-grade NGL pipeline to take the liquids to our fractionation system. This plant will have an initial capacity of 200 million a day and frankly, there's 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 of nameplate capacity, this plant is similar to others we've recently built, 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 supplies continue to grow. The world understands this potential and all roads for NGLs seem to lead to the U.S., whether it be production from the Eagle Ford, the Rockies, the Permian, Appalachia, or market-oriented projects, including exports, we've been on a significant building binge particularly at Mont Belvieu for the last several years and frankly, we don't see that changing anytime soon.

As to crude oil, our buildout of our storage at ECHO continues where we're headed to somewhere in the neighborhood of seven million barrels of capacity. But 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 buildout our 30-inch Rancho II crude oil pipeline, that's the pipe from Sealy into Houston, that will move growing supplies of crude into ECHO.

Demand for U.S.-processed 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 waterfront position, that will result in our processed condensate export capabilities being over currently available supplies. Consequently, we're 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 for NGLs and natural gas, we understand that our role is to give producers flow assurance and market choices and to give consumers supply reliability and market flexibility. I'm not sure we talk enough about our focus on markets in order to create new market availabilities for producers. A 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 close to 100 million barrels of LPG and work continues on our two export expansions, where, by 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 on the Houston Ship Channel. A lot of folks didn't think this could be done. I must admit, five years ago, I said 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 simply made too much sense. In April, we announced our ethane export project at Morgan's Point and since that time, we've received key permits and major equipment has been ordered.

We'll begin construction next month, with completion expected 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, it tells them Enterprise is 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 Lake Charles and now onto the Mississippi River corridor. By 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 transportation commitments, Aegis customers are also signing up for other product and services, such as term ethane supplies and storage in Mont Belvieu, in order to support their demand in the sizeable 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're going to take 35,000 barrels a day of natural gas-derived 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 landlocked crude oil production in the Midwest. On the refined products 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 demerge.

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 it then moves on to Cochin or Southern Lights for delivery to Western Canada to be used as a diluent.

Finally, crude oil prices: obviously, we've seen a rapid and meaningful price correction caused by weaker global demand and growing supplies, both here in the U.S. and by some of the OPEC players. While I can't predict oil prices or what OPEC will do or not do, $80 oil prices aren't killing the U.S. shale oil producer. Our analysis shows that most, if not all, of the core drilling areas 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 halt.

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 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 invention. With that, we'll turn it over to Randy.

Thank you, Jim. I'll cover a few additional financial items. As a reminder, when calculating earnings per unit for your model, a reconciling item between our non-GAAP gross operating margin and net income are the non-refundable deferred revenues that are attributable to shipper 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, which includes sustaining capital expenditures -- let me back up. 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 principal to adjusted EBITDA was 3.7 times. This gives 50% equity treatment to the hybrid 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 of 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 30 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 15 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%. With that, Randy, I think we're ready for questions.

Okay, Toni, we're ready to take questions now from our listeners.

(Operator Instructions)

Your first question comes from the line of Brian Zarahn with Barclays.

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 aggregation is always key, Brian, and that's kind of what we're focusing on right now. There are a few things we need to do to up our capabilities, but we're in the process of doing that. Bill?

The middle to early third quarter next year, we'll have a new pipeline in place between Sealy and Houston and that will allow us to bring a lot more volume. We're 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're installing, yes, it would be.

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?

Oh, absolutely. Probably none that we're going to tell you about right now, Brian.

Well, I had to try. That's my job.

We like that area and we're being 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, Jim or Bill, can you comment a bit on the proposed Bakken/Cushing crude pipeline and any impact on the crude price pullback?

Yes, 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.

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

Hi Brian, this is Mike. As I said, we're in the middle of discussions and our lawyers said they'll slap us on the wrist if we mention anything about it.

That was another nice try, Brian.

Tried to slip one in there. Thanks very much.

Your next question comes from the line of Darren Horowitz with Raymond James.

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 mismatch, in terms of being constrained, is you only have 50,000 or 100,000 barrels more of incremental capacity? 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.

We've got a partial solution, anyway, that I mentioned before, when we get this, what we're calling our Rancho II pipeline, in place kind of around the City of Houston here mid-third quarter of next year. It's going to open up a lot more capacity. We think we have some dock capacity available to handle that. How much we can handle, we'll see. As Jim mentioned, it's going to be around the supply aggregation, how much supply we can aggregate.

Now others do have some ways to get that processed condensate to other locations where it could potentially be exported as well, so I'm not going to speak to them, but I think we're in the process, in the Eagle Ford anyway, looking ahead at getting that taken care of. It's pretty much substantially increasing our volume of exports come maybe around 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?

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. I think the only way we can answer that is we feel pretty good about our position. As Bill mentioned, we're doing things at Texas City and over in Beaumont. With the Enterprise facilities, we know what we have to do to add capacity. We can do that very reasonably and I mean, it's pretty obvious where we're headed.

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 says that and I mean within three months of announcing it, says a lot, Darren. Believe me, we're focused over there.

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

Your next question comes from the line of John Edwards with Credit Suisse.

Yes, good morning, everybody. Just following on Darren's question, in terms of capital allocation then, are you guys seeing more, or a bias toward more fulfilling export opportunities versus other opportunities? Maybe if you could enlighten us a little bit more on that?

John, I think export opportunities is one where we're giving producers market choices. But the real key to any market choices we give them, whether it's a distribution system to all the refineries, whether it's an export capability for processed condensate, it really starts with supply aggregation, which is what Bill talked about. So, and this may be a little bit of an answer for Darren, 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, we build a stabilizer ourselves. I don't think it's any secret, Bill, that we've got some pipeline projects out there that are being driven by wanting to aggregate more supplies. 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. Our Eagle Ford pipeline has three segregations.

Our other pipeline projects have multiple segregations. We think that's going to be important in the future. So we keep focused on what do you guys got to spend to export? What we've got to spend is to aggregate, because the export capability isn't going to be that big of a deal, I don't think.

Right.

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 to be able to segregate the volumes and bring them in so they can be exported.

Okay, that's really helpful. 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.

Yes, if it's impacted anything we're doing, it may have -- its 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 in what we're doing out in the Permian. We haven't seen any impact at what we're doing in the Eagle Ford.

But John, the Bakken pipeline is not one that we've included in CapEx numbers and so when we talk about $3.5 billion, $4 billion in 2015 and 2016, 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.

Your next question comes from the line of Danillo Juvane with BMO Capital.

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 of its success. People are recognizing that rail's 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 away as I thought we'd be from that threshold.

No we're not. It's going to depend on if the producers are willing to believe that and step up. We're in conversations with a very large number of them right now and frankly, got the indication they needed some 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 the dialogue.

We've got people here pretty excited about it. I worry about it, but I worry about everything.

Okay, great. That's it for me, guys, thank you.

Your next question comes from the line of Michael Blum with Wells Fargo.

Hi, good morning, everyone. 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've seen right now, I don't see any constraints on the market side. You're right, the arb has 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, kind of like service companies with E&P companies, they get their piece of the pie. Things close a little bit and they sit there and hold on and see what's going to happen and ultimately, they lower their freight rates.

They have long-term contracts.

The difference in us and some of these others, we're sold out for the next three, four years. Really, my point is that 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 day, I always planned on it being $25 a ton and either the price is going up in Europe or it's coming down here, one or the other. You have a normal winter, it'll probably be the latter.

Great, thanks. Appreciate that.

(Operator Instructions)

Your next question comes from the line of Axel Styrman with Nordea.

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, I don't know that 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 past the core areas into the non-core areas to broaden their footprint, but it varies from play to play. But the core areas are solidly in the money on the major oil plays at prices we have today and below. So there is a point where your producers quit and 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, 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.

Your next question comes from the line of Faisel Khan with Citigroup.

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 that 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'd have to look back, but I'd be willing to bet you we had some very high price spot cargoes last year and this year, we're full up with contract cargoes. Graham, how long were we down, because part of it was a down time?

We had both trains down at different times, but it was around seven days.

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

More of it was with respect to the lower margins, 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 had these high price spot cargoes that we had last year, Faisel.

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 margins from just a certain plant, so trying to understand that movement, too.

Yes, Faisel, 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 costs in the analysis. This year, we're doing less of that and so we're having more ethane rejection, so as a result, you're seeing better margins at the processing plants, but you're seeing lower volumes like for instance, Mid-America and Seminole, we're down 60,000 barrels a day. That's more ethane rejection flowing through downstream pipelines.

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

That is basically all elective ethane on our part and so we recovered that ethane on variable costs last year. This year, we've elected to reject it, so conditioning where they reduced their recoveries per their contracts, we have the right to continue to extract that ethane. Last year, we elected to do that and this year, with margins where they're 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, yes.

Okay, okay. Understood, guys. Thanks, appreciate the time.

There seem to be no further questions at this time.

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

Okay. To dial into the replay, please dial 855-859-2056 or 404-537-3406 and enter the conference ID 21364843.

Okay. Thank you, Toni. Thank you for listening to our call today and have a good day. Goodbye now.

Thank you for your participation. You may now disconnect.