Good morning. My name is Bonita and I will be your conference operator today. At this time, I would like to welcome everyone to the Spectra Energy and Spectra Energy Partners earnings call. All lines have been placed on mute prevent any background noise. After the speakers’ remarks, there will be a question and answer session.

If you would like to ask a question during this time, simply press star then the number one on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you. Ms. Dill, you may begin your conference..

Thank you, Bonita, and good morning everyone. I’m Julie Dill, Chief Communications Officer for Spectra Energy. Thank you for joining us today for our review of Spectra Energy and Spectra Energy Partners’ 2014 first quarter results.

With me today are Greg Ebel, CEO of both Spectra Energy and Spectra Energy Partners, and Pat Reddy, Chief Financial Officer of both companies as well. Pat will begin by sharing our financial highlights for the quarter.

Additional information on these results is detailed in both the Spectra Energy and Spectra Energy Partners’ earnings releases as well as the appendix to today’s presentation, all of which are available on the Investor page of our website.

Next, Greg will update you on our strategic plans and priorities and the progress we’re seeing across the enterprise to deliver long-term shareholder value, and as always we’ll leave ample time for your questions following Greg’s remarks.

Before we begin, let me take a moment to remind you that some of what we’ll discuss today concerning future company performance will be forward-looking information within the meaning of the securities laws.

Actual results may materially differ from those discussed in these forward-looking statements and you should refer to the additional information contained in Spectra Energy and Spectra Energy Partners’ Form 10-K and other filings made with the SEC concerning factors that could cause those results to differ from those contemplated in today’s discussion.

As this is a joint presentation, the terms we, our and us refer to Spectra Energy and/or Spectra Energy Partners as appropriate; and in addition, today’s discussion will include certain non-GAAP financial measures as defined under SEC Regulation G.

A reconciliation of those measures to the most directly comparable GAAP measures is available on our website. With that, let me now turn things over to Pat..

Thanks Julie, and good morning all. As you’ve seen from our earnings release, we delivered exceptional first quarter EBITDA results of more than a billion dollars at Spectra Energy and $413 million at Spectra Energy Partners.

Those results are both more than 20% higher than the same quarter last year and we’re extremely pleased with the strong beginning to the year. At Spectra Energy, distributable cash flow was up more than 25% and considerably more than our original expectation for the quarter.

Distributable cash flow was also up significantly at SEP as a result of the 2013 drop down. Both entities generated strong coverage ratios in the quarter, 2.8 times at Spectra Energy and 1.6 times at Spectra Energy Partners.

Given the seasonal nature of earnings and maintenance CAPEX spend, these DCF numbers and coverage ratios are higher than we would expect on an annual basis. Given our strong start to the year, on a full-year basis we now expect Spectra Energy’s coverage to be around 1.5 times and SEP’s to be around 1.2 times.

Both investment-grade balance sheets remain strong and continue to provide the strength and flexibility to efficiently support our ambitious expansion plans, and as you know, we initiated a $400 million at-the-market continuous equity offering, or ATM program at SEP at the end of last year.

To date, SEP has raised approximately $120 million in that program. We know it’s early in the year, but the signs we’re seeing and the value we’re creating are positive indicators of a great year ahead. Let’s turn now to our EBITDA results by segment.

As you can see on the slide, each reporting segment is up year-over-year, so let me focus on the dynamics that drove us to this strong start. Spectra Energy Partners is comprised of our U.S. transmission and liquids businesses. At U.S.

Transmission, quarterly EBITDA results reflect increased earnings from the expansion projects we placed into service last year. The business also benefited from higher revenues from greater short-term firm and interruptible demand on our Texas Eastern system, thanks in part to the unusually cold and prolonged winter.

Our liquids business realized EBITDA of nearly $60 million from the acquisitions of Express-Platte and our one-third interest in the Sand Hills and Southern Hills NGL pipelines. We expect to continue that strong earnings trend throughout the year and are on track to more than double the EBITDA from the liquids business by 2016.

Spectra Energy received GP and LP distributions from SEP of $168 million in the first quarter. Turning next to distributions, that segment’s EBITDA increase was due mainly to higher customer usage as a result of record cold winter weather, which also drove higher operating fuel costs and earnings sharing under the incentive rate framework.

The business managed its regulatory environment extraordinarily well and received a couple of regulatory rulings from the Ontario Energy Board that in the aggregate provided a benefit of about $10 million to Union Gas.

Western Canada’s EBITDA increase was due primarily to higher earnings at Empress and off-plan results across the west of the western Canada segment. We earned $60 million of EBITDA at Empress in large part due to higher propane prices.

In February, we told you we’re working to stabilize the earnings and cash flow contribution from Empress and that we expected to deliver about $50 million of additional EBITDA beyond our original forecast, which would put us at about $80 million for the year.

With these strong results in the first quarter, we remain positive about our ability to deliver that higher number. This is impressive given that our annual expectation takes into account our planned second quarter plant turnaround at Empress, which started at the end of April and will continue for about 45 days.

All said, a strong start to the year at Empress. While the Canadian dollar brought with it a bit of a headwind that affected the EBITDA at our western Canadian and distribution segments, the effect was considerably mitigated on a net income basis as the result of lower depreciation, interest expense and taxes.

Field services benefited from significantly higher commodity prices, improved NGL marketing and logistics margins, and higher margins and volume growth attributable to new projects placed in service.

Thanks to field services’ strong and steady performance, to date in 2014 we have received $136 million in distributions in BCC midstream, well ahead of our anticipated levels.

So all in all, I’m pleased with how we started the year, and barring any significant unplanned events we fully expect to retain the benefits realized to date and continue to deliver on the commitments we made for the balance of the year. With that, let me turn things over to Greg to talk about our plans, priorities, and the progress we’re making..

the Goliad Plant in the Eagle Ford and the Front Range pipeline were delivered into service in February, and the O’Connor plant expansion in March.

We indicated to you that DCP would drop down at least a billion dollars of assets to DPM, and we accomplished more than that in the first quarter with a March drop down of one-third interest in Sand Hills and Southern Hills, the remaining 20% of the Eagle Ford system, and the Lucerne 1 plant.

The DCP have come up fast in 2014 with this first drop down and more is expected by the year-end.

We’ve been focused on securing permits and beginning construction of two new gathering and processing plants – Lucerne 2 located in the growing Niobrara shale is slated to go into service in mid-2015, and Zia II, a sour gas plant that will serve producers in southeast New Mexico and West Texas regions of the Permian.

In the first half of next year, that will be ready to go. We told you we’re ramp up existing contracts from Sand Hills and Southern Hills, and as mentioned previously, we’re on track there. So we’ve had a busy start to the year and an exceptionally strong first quarter.

Spectra Energy realized EBITDA in excess of a billion dollar, distributable cash flow levels at Spectra Energy and SEP are robust, we have strong distribution coverage ratios exceeding our first quarter expectations, and our investment-grade balance sheets are solid.

Clearly we are executing, not only by running our systems safely and reliably so we meet all of our customer commitments, but by delivering new infrastructure into service, securing new business, pursuing opportunities to continue to expand and enhance our footprint, all the while delivering solid dividend and distribution growth to our investors.

Strong fee-based cash flows continue to underpin that growth. As we’ve said before as we do better, we will look to share that upside with our investors.

We’re really pleased with our first quarter performance as we continue to build on the momentum that carried us into this year We’ve got an impressive list of growth opportunities at attractive returns that we’re executing on and work to complete through the end of the decade - $35 billion worth of expansion projects that cover every single one of our business units.

So with that, let me turn things back to Julie so we can take your questions..

Thank you, Greg. We’d like to hear from you now, so we’ll open up the lines for your questions.

Bonita, would you please provide the instructions on how folks can ask questions?.

Thank you. [Operator instructions] Your first question is from the line of Darren Horowitz with Raymond James..

Hey, a couple questions, and I appreciate the color on the Texas Eastern system, but with regard to the projects that you outlined to move gas south and the potential for capacity expansions beyond what you’ve announced, if I’m thinking about TEAM South, in February you talked about bids during the open season being four times that 300 million cubic feet of capacity, and just looking at where differentials are now and seemingly more supply building behind infrastructure, how do you think about expanding TEAM South and possibly even that Uniontown to Gas City further?.

Yeah, we’re a little bit limited on what we can do with the current infrastructure, so as I said, this is the same case we’ve got further in the northeast and with over-capacity requests, if you will, in the northeast.

We’re looking at can you do even a bigger expansion all the way down to the Gulf, and the challenge with that, of course, is being able to do it on an economic basis, and as you point out, some of the basis challenges that exist there. But yeah, look – we’re putting two projects into service this year to move gas south.

We’re putting two more in next year, so I hear a lot of discussion about people looking at projects but I think we’re 18 months ahead of others, and that really gives us another opportunity to look at even larger expansions.

But that’s going to be more capital and bigger capacities as opposed to just reconfiguring compressor stations and pipe yards, if you will..

If you had to kind of rank order the opportunities to invest discretionary dollars into the ability to move gas south, whether or not it’s on TEAM South or OPEN or the Uniontown to—that expansion, in terms of unlevered rates of returns, where do you think you’d get the most accretive bang for the buck?.

Well you know, interesting enough given the demand, I actually think all of them. I mean, we’re targeting those 10%-type returns and I think all of them can achieve that. Again, the challenge is not so much what we think they can achieve; it’s what producers are willing to pay in that regard.

But I would say the opportunities l like the most, mainly because it produces the most amount of capital and obviously going to a huge market, is getting down to the Gulf Coast.

All that being said, I think the important part is we are right at the nexus – no pun intended – of the Utica and Marcellus, so while folks are talking about moving gas west and then you’ve got some others talking about moving east, we can move gas to the northeast, we’re going to move it west – we’re already doing that.

We’re going to move it north and we’re going to move it south, so I actually don’t—at this point in time, given the opportunities we see before us, given the capital structure we have, I don’t feel restricted by pursuing any of the opportunities that we have out there, and I think we can do that earning those 10%-type returns..

Okay, and then last question for me, if I can switch to field services, just curious with what’s gone on with composite NGL barrel pricing, if that’s changed the way that you’ve thought about your guidance.

I know that you were building in at the DCP level a weighted barrel price of about $0.94 a gallon, and you had about 25,000 barrels a day of ethane built into the guidance being rejected.

Obviously the demand pull from C3-plus has been a lot different over the past couple months, and where the relationship between composite barrel pricing is versus crude, you’ve got a bit better producer net-back.

So I’m wondering if anything has changed in terms of where you’re expecting realized pricing or possibly ethane rejection, and how that alters what Sand Hills and Southern Hills could do in terms of cash flow into the back end of the year..

You know, obviously it’s going to be helpful to ramp up the volumes, but we have pretty good ramps that we expect and we’re seeing that.

I would say what we’ve seen in results today, and it excludes some of the weather impacts on propane, have been very consistent – you know, the $0.93, $0.94, kind of the 38, 39% relationship with WTI, and I think we’re going to see that for some period of time. You know, you’ve got a bunch of dynamics going on.

The more I hear about propane exports and ethane exports, the happier I get about setting a floor on NGLs, and obviously as by far the largest producer of NGLs in North America, that makes me happy every day. The only thing I wish is that we had some export capability, but we don’t have that directly today..

Okay, I appreciate it. Thank you..

Thank you..

Your next question is from the line of Bradley Olsen with TPH..

Hey, good morning Greg. First question is a little bit more macro focused. We’ve seen a tremendous pace of pipeline reversals out of the northeast.

Do you think that we’re approaching a point now where we’re getting close to saturated on capacity additions, specifically out of the southwest Marcellus and Utica shales, especially for capacity headed to the south and to the west?.

You know, I think maybe the way I would articulate it, Brad, is that these things come in waves, two or three-year waves. I’m glad that we’ve got the projects we have, because I think the next big round is for stuff in ’17 and ’18.

I think you also are looking—don’t forget that a need hasn’t been met yet in the mid-Atlantic region, and I think that opportunity is out there and obviously that could be a pretty big opportunity which we’re going to pursue pretty forcefully with the various folks that are looking for that.

So I think you might be right – if you haven’t got stuff now, it’s going to be hard to realize the benefits of that in ’15 and ’16. The next round of plays are for ’17, ’18 and ’19 and that’s what we’re focused on..

And in terms of ’17, ’18 and ’19 projects, you’re referring to those mid-Atlantic projects, or you believe that there is more work to be done in plumbing the northeast?.

Both.

As I indicated, given the demand that we saw for things like Atlantic Bridge, given the demand we’ve seen for AIM, I think there’s another round of projects that have to occur, at least brownfield-type projects probably but maybe even some big greenfield projects into the northeast; and of course, you know, that ’17, ’18 time frame is exactly where NEXUS will come in.

So I think to the west is a little bit tougher, but that’s not a big focus for us. Remember, we built TEAM X, TEAM 2012, and our OPEN, New Jersey-New York to take gas from the back end to REX, and now given where our assets are, we’re the front end of REX. Lebanon and Clarington are not big producing areas – they’re not producing areas.

You want to be coming through Spectra’s Texas Eastern and stuff to feed that west, but I don’t see a huge need for a ton more pipe into Chicago..

Great, thanks for the color. This question is related more to the Canadian market and the role it has to play absorbing some of this northeast supply.

You know, you’re looking now with the REX reversal at close to four B’s a day moving into the midwest over the next few years and probably closer to 10 B’s a day moving down to the Gulf Coast, yet we’ve only seen really about a B of committed export projects to Canada, and NEXUS, which seems like it’s on the doorstep of being fully contracted but still has taken a while to get signed up, especially in light of the fact that the economics shipping gas to Canada seem like a no-brainer, is there another kind of economic factor at play here? Is there something related to TransCanada’s import tariffs out of the northeast that’s making what would be a very economic proposition maybe a little bit less economic?.

No, I don’t think so, Brad. I think as usual, things can take some time from a regulatory perspective, A.

B, remember the way (indiscernible) always gets done is at first producers say, we’ve got spectacular results in whatever region that we’re in, and that filters through the market and then the pipeliners come along and say, well, if you’ve got spectacular results, surely you don’t want to be stuck in the ground.

But until they’re 100% confident they’ve got what they think they’ve got in the ground, they’re not going to sign up for long-term commitments. And then you get on the demand side of things – okay, we see that the Utica and the Marcellus are humming along great.

We can see that we’ve got some challenges in western Canada, so we in the Michigan-Ontario area are now ready to take supply, and you need all three of those things to line up to be able to get a project, in particular a greenfield project of this size, to shake out. Exact same thing with New Jersey-New York, even with Sabal Trail.

Remember – the Sabal Trail project was probably three years in the works between getting exactly what you needed on the demand side, comfort on the supply side, and then actually going through the process. So I just think we’re in the world of what used to be 18 to 24 months from development to construction to in-service, to now 24 to 36 months.

That’s just the reality of the world with some of the really changing dynamics on the supply side and the demand side, as well as the overlying, let’s face, a tougher sighting environment that we’re in..

Great, and just one last question related more to the modeling side of things. As we think about DCP, historically DCP had pretty significant deliveries into Conway, and now with Sand Hills, Southern Hills, Front Range, Texas Express, there are obviously a lot of ways for DCP to kind of move its NGL barrels to the Gulf Coast.

But in a period like the first quarter where there were extended periods of time where keeping those NGLs in the midwest, does DCP still have the option to keep those barrels in the midwest if the price dictates that that’s the right thing to do? It just seemed like the realized price that DCP reported, while much stronger than guidance, was still maybe not as high as the spike in prices that we saw in the Conway—that Conway spot price would have indicated..

Yeah, I think that’s a fair comment. We have very little capability to keep the stuff at Conway. It’s got to get to Belvieu, and as you know, Brad—I mean, this is a long-term game. There is no doubt about it – the best market to take NGLs, perhaps in the world but definitely North America, is into Mont Belvieu, and that’s what we’re playing.

But in the near term, yeah, when you have some impact like you saw this winter and Conway spiked up, we can play a little bit of that on our market, being a logistics site.

Now Spectra, of course, does really well when Conway spikes because that’s obviously a close connection to Empress, and to the extent we may not have hedged—and obviously as we just worked into a hedging program in the first quarter, that really helped Empress from that perspective as well.

But at DCP, you would be correct – the bulk of our focus now will be Mont Belvieu, and that’s where we want to be..

Great, and I guess just any parting thoughts on the potential to increase payout, just given the fact that full-year coverage is already setting up to be very strong?.

Well you know, it’s the first quarter, but you know what I love? I love the firepower we have to have a discussion towards the end of the year, and obviously with a really nice running, leaping start to the start of the year and the budget looking the way it is and our forecast for the rest of the year, I don’t see why we should see any change from that, things within our control.

I’m looking forward to the discussion later in the year about what we do for next year. We’ve said before – if the type of results we’ve seen in the first quarter keep playing through and we see better coverages, we definitely want to look at sharing those with investors.

So I think that’s a discussion we typically have towards the end of the year as we put our three-year plans together..

Great. Thanks for all the color..

Okay, thanks Brad..

Your next question is from the line of Craig Shere with Tuohy Partners..

Morning. Congratulations on the good quarter. Greg, let me pick on the NGL commodity question that Darren started off with.

I think you highlighted exports of, if I heard correctly, both propane and ethane contributing to floors for NGLs, so my question is do you see ethane seaborne exports, such as Enterprise’s terminal plan for third quarter ’16, as a reality, and do you see stair steps and pet chem.

demand, including I think this summer we’ve got Williams’ Geismar online and Lyondell’s La Porte expansion coming online, and then a couple more expansions next year for Lyondell as well as others.

Do you see those pet chem expansions just keeping pace with the growing NGL production, or how do you see things in the next 18 months?.

Well, I don’t see a big change in the next 18 months. I think most people have looked to ’17, ’18, ’19 before the big demand kicks in, and my comments—so there will be Geismar and some other things that will come back online, and they were pretty big outages.

But in terms of big incremental demand and given the growth in NGL, this is really looking in that ’17, ’18 time period.

My comments about ethane – you know, the Enterprise guys always do a good job, and if they can get on the water, I just think, just like propane, that sets a floor because they're going to get more global prices for those products, if you will, ethane and propane, and that’s just a positive from North America NGL pricing, particularly as we leg into the demand growth closer to the end of the decade than the beginning of the decade..

Yeah, there has been a lot of discussion in the last year since you guys have been—you know, with the acquisition of Express-Platte and the drop downs really kind of turbocharging some of your game plan here, and people are like, well, what’s next and what can we do with DCP? I guess my question is apart from financial engineering, the problem at DCP LLC has been its very low cost basis and also that part of the business versus the MLP is very commodity sensitive.

If we can in a couple years start, as you say, set a floor for ethane, which I know DCP is very exposed to, couldn’t we see a material uplift in the multiple valuation that could be ascribed to that business, and maybe that’s a better time frame to start thinking about what to do with it?.

Well first of all, I don’t know why we have to wait a couple years for that. My view is that the writing is on the wall and as you see things like Southern Hills, Sand Hills, Texas Express all adding a fee-based nature to DCP’s earnings, then in fact we should start realizing some of that uplift. I think it’s begun to start, but in my view not enough.

I think one interesting thing to think about, Craig as you know, we’ve always paid our dividend out of our fee-based earnings out of the non-DCP piece.

As things get more—as you say, a floor gets set and maybe some more fee-based earnings from things like the pipeline, I think then the opportunity is, well, do we start to pay out some of those DCP earnings that aren’t volatile to Spectra investors. So that’s the kind of thing I’m thinking through..

That’s a good point.

My last question, just to clarify – this $35 billion by the end of the decade, that’s a gross figure, right? That’s not proportional for, say, DCP or Sabal Trail or things like that?.

Yeah, that’s got 100% of DCP in it..

Okay, great. Thanks a lot..

Your final question is from the line of John Edwards with Credit Suisse..

Good morning, everybody. Greg, just following on some of the other questions here regarding—you know, you were talking about the additional volumes in 2017 to ’19 time frame, I guess for north to south.

You’re thinking, I guess, kind of aggregate, what do you think those volumes are and what do you think Spectra can capture – you know, just kind of ballparking it?.

Well, I guess if I look at what we’re doing right now, so between ’14 and ’17 and starting in ’14 and ’15, we’re talking about 2Bcf, so I don’t see why we wouldn’t be able to replicate a similar type of situation.

In fact, it may be a much bigger volume only because the next set of growth projects will probably take more capital, more greenfield or brownfield-type capital as opposed to utilizing systems and maybe various parts that may not be fully utilized today.

So I think the restraint will solely be on can we have a meeting of the minds, if you will, between producers and consumers to actually get those 10%-type returns. But yeah, I don’t see why another 2Bcf at least couldn’t come on between ’17 and ’19, and that’s excluding what we do on NEXUS.

I think NEXUS represents a really great opportunity, and I think as producers look at that—you know, we’ve kind of talked about that as a 1Bcf a day pipeline, and maybe that’s going to be substantially bigger. And obviously if that’s the case, the economics of that both for producers and on the demand side get better..

Okay, that’s helpful.

I’m just curious, though, this bi-directional flow, what kind of tariffs do you apply to that, and how does that impact the tariffs that you put on that project?.

Well, here’s the way we look at it. Look – on a net-net basis, all the capital we put to work is earning about a 10% return, so it’s a competitive world out there, we’re negotiating on these rates, and so think about it in terms of 10% types return on capital employed.

That’s the way I would get into it, as opposed to getting into specific commercial returns..

All right, so just have us sort of back into it, would be the way to think about it..

Yes..

Okay, great. All right, thank you very much..

Okay, thank you..

This question is from the line of Christine Cho with Barclays..

Hi. So just regarding the NEXUS pipeline, it looks like many producers have already signed up with an existing pipe to go to the same market sooner than the 2000 time frame that I think you guys have proposed.

Do you think there’s risk to this project getting pushed out, or is there still not enough capacity to go to those markets without NEXUS? Just trying to gauge when do we—like, when do we see producers sign up with your project?.

Well as I mentioned, I’d expect we’d see producers in the next couple of quarters sign up; and no, I think a lot of what you seen from a capacity perspective at this point in time isn’t giving people direct access to Dawn. That’s what we’re proposing.

There are some—I guess you could go to Chicago and up and around the bend and get a lot of rate stacking that goes on, so we still don’t see anybody with the type of volumes we’re talking about getting to Dawn or with as competitive a rate from that perspective.

Again, a lot of what you’re seeing is people using parts of pipes or pipes that aren’t utilized in relatively small volumes, and a lot of that stuff is also going towards the Gulf as opposed to into Dawn.

So yes, there’s always risk to projects until you get them built and in the ground, but as I said, with three LDCs signed up, the focus is on the producer, and over the next couple of quarters that’s the real focus, Christine..

Even with the stacking up of the tariff that you just described, is NEXUS still competitive, because yeah, it’s stacking but it’s also old pipe so I would think that the tariff is not that high versus—you guys probably have to do a little more new build, right?.

Well yeah, a big chunk of ours is new build, but also—but yeah, we are very competitive. Some of the rates I’ve seen people put out on the REX thing, I have—well, I have no doubt we’re better than that from a competitive perspective. I was actually surprised at how high those rates were..

Okay. Then my last question is, you talk about 2Bcf a day of Tetco being bi-directional by 2017.

Have we kind of maxed out with existing infrastructure being reversed? Do you have to do more new build to add more capacity capabilities to go to the Gulf? Can you help us think about how much higher you can go than the 2Bcf a day?.

I think the 2Bcf is about that.

There’s a little bit—and of course, then you start getting constrained on different parts of the pipes, so Christine, I think as I tried to mention earlier, I think with the two coming into service this year – TEAM South, TEAM 2014 – and then the two pieces next year, Uniontown to Gas City, et cetera, then I think we’re pretty close to utilizing or perhaps optimizing the pipe that exists, and now you start getting into bigger builds.

And therefore, we have to get into bigger builds to make this work, so I think it’s 2Bcf of very economic builds for our customers, and then after that we’re talking about bigger builds and then it’s going to be a fight from a competitive perspective and what type of diversity and opportunity and delivery points you have, and that’s why I love, as usual, the map that we have from a satellite perspective where we get all the lights, whether it’s west, north, south or east..

One of the things that I’ve kind of heard is with other pipelines who kind of have the capabilities from going Gulf to northeast, if they were to get through all of their low-hanging fruit and do new builds like you just described, they say that the tariff will be in the dollar range.

Do you agree with that?.

I think that totally depends on the size, Christine. I mean, beyond the 2Bcf, it might be in that amount; but again, it totally depends on how big. You know, obviously if it’s a 1Bcf pipe, it’s going to be a lot more expensive than 2Bcf a day pipeline, so I wouldn’t—I actually don’t want to get into a discussion about how well we’ll be competitive.

I know we’re going to be competitive, but I would suggest it totally depends on the size of the pipe that you’re talking about here..

Okay, super. Thank you so much..

Okay, thanks Christine..

There are no further questions.

Are there any closing remarks?.

Thank you, Bonita, and I want to thank everyone that joined us on the call today. We’re looking forward to seeing many of you in a couple of weeks at both the AGA Financial Forum and the NAPTP MLP investor conference.

But in the meantime as always, if you have any additional questions, please feel free to give Roni Cappadonna or myself a call at your convenience. So thanks very much, all have a good day..

This concludes today’s conference call. Thank you for your participation. You may now disconnect..