Sea Limited (SE) Q3 2014 Earnings Report, Transcript and Summary

Good morning, my name is Stephanie, and I will be your conference operator today. At this time, I would like to welcome everyone to the third quarter earnings conference call. [Operator Instructions] Julie Dill, Chief Communications Officer for Spectra Energy, you may begin your conference.

Thank you, Stephanie, and good morning, everyone. Thanks for joining us today for our review of Spectra Energy's and Spectra Energy Partners' 2014 third 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. Pat will begin by sharing our financial highlights for the quarter. Additional information on these results are 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 Pages of our website. Next, Greg will update you on 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. Our Safe Harbor statement is contained within our presentation materials and available on our websites. This disclaimer is important and integral to all our remarks, so I would ask that you refer to it as you review our materials. Also contained in our presentation materials are non-GAAP measures that we reconcile to the most directly comparable GAAP measures and those reconciliations are also available on our website. So with that, let me turn things over to Pat.

Well good morning, everyone, and thanks for joining us today. Spectra Energy's third quarter results are well in line with our expectations and reflect continued growth in earnings and cash flows from our ongoing capital expansion program. Our businesses delivered solid performances for the quarter, with SEP in particular, posting exceptional results. Our consistent performance and the growth opportunities we are realizing gives us the confidence to increase Spectra Energy dividend by $0.14 on an annual basis to $1.48 per share, or an increase of 10.5%. Not only is this increase larger than we had conveyed earlier this year, we're commencing the higher payment in the fourth quarter. So let's turn now to the third quarter and the EBITDA results we delivered. As you'll note in the yellow highlighted area on Slide 3, Spectra Energy generated ongoing EBITDA of $704 million this quarter compared with $758 million in the prior year's quarter. Spectra Energy Partners delivered ongoing EBITDA of $401 million, $51 million higher than in the same period last year. The key drivers for the change in EBITDA are: growth in earnings and cash flows from execution of the capital expansion programs at both our SEP and DCP segments, which were more than offset by a weaker Canadian dollar, which was down about 5% from the prior year quarter, lowering EBITDA contributions from our Canadian segments by $12 million; higher plant turnaround cost this quarter relative to last year in Western Canada; lower equity earnings from DCP due to higher noncontrolling interest as a result of increased drop downs to DPM and mark-to-market changes in the value of hedges where DCP, as the counterparty for DPM. This trend will continue with future drop downs, but while we will lose net income, Spectra Energy will continue to benefit from the growth in GP and LP distributions from DPM. In addition, DCP had lower gains associated with the issuance of DPM units compared with last year's quarter. So all in all, a quarter in line with our expectations for EBITDA. Given that our investors are increasingly focused on cash generation to support ongoing dividend growth, let's turn to distributable cash flow, or DCF, on Slide 4. Spectra Energy's DCF was $236 million for the quarter, $10 million more than last year's quarter. With our more than $1.1 billion in DCF year-to-date, we continue to expect distribution coverage to be 1.5x on a full year basis, exceeding our original estimate of 1.4x. Distributable cash flow at SEP was $247 million for the quarter with coverage expected to be 1.2x on a full year basis. You'll recall that with the drop down of our remaining U.S. assets into SEP last November, we recast earnings but not distributable cash flows. Consistent with our objective to enhance transparency around DCP's cash flow, we are now providing DCP's DCF in our quarterly earnings material. Not only that this disclosure align with our increased communication of cash based financial metrics, it should also provide a means for investors to more easily value DCP and DPM cash flows to its owners. So distributable cash flow, DCP for Spectra Energy is 50% stake was $61 million for the quarter and $184 million year-to-date. You will find more details associated with the distributable cash flow calculations for Spectra Energy, Spectra Energy Partners and now DCP as well, in the appendix to our presentation and on our website. As we continue to focus on cash-based financial metrics, we are highlighting the actual cash contributions to Spectra Energy from both SEP and DPM that are embedded in Spectra Energy's distributable cash flow. Spectra Energy received general partner and limited partner distributions from SEP for the quarter of $44 million and $134 million respectively. Year-to-date, we received GP distributions of $123 million and LP distributions of $396 million from SEP. DPM, the general partner and limited partner distributions of $14 million and $9 million respectively for our account further contributing the Spectra Energy's DCF. As DCP continues to drop down assets to DPM and noncontrolling interest becomes a larger component of earnings, the owners have adopted a new methodology for calculating owner distributions from DCP. Effective with the fourth quarter payment made in late October, DCP will now make owner distributions based on distributable cash flow rather than net income. DCP declared owner distributions of $57 million to Spectra Energy in the third quarter of 2014, with year-to-date declared distributions of $177 million. Last quarter, we reminded you that we expected about half of our 2014 EPS target of $1.40 to be earned in the second half of the year in keeping with historical patterns. Thanks to a strong performance in the first quarter and results in line with the expectations for the second and third quarters, we continue to expect to significantly exceed the $1.40 target, assuming normal winter weather on a forward commodity curve that remains consistent with current outlooks. So overall, we are pleased with the quarter and where we are year-to-date with strong currencies and a balance sheet to support the additional growth we see coming. So with that, let me turn things over to Greg to talk about our portfolio of growth projects, our priorities and the progress we continue to make toward our goals.

Well, thank you very much, Pat, and thanks to everybody for joining us today. As Pat described, Spectra Energy's third quarter results really do reflects strong performance by our base business and the positive earnings and distributable cash flow generated by the assets we are consistently delivering into service. I say consistent because consistency is imperative and important theme for us. Spectra Energy is dedicated to delivering reliable results to our investors, customers and, of course, to stakeholders. That dedication is evident in our focus on operational excellence and our commitment to bring critically needed projects into service on time and on budget. I think it's also apparent in our record of delivering attractive returns and dividends and distribution growth, underscored by Spectra Energy's most recent dividend increase of 10.5%. That dividend increase affirms our successful execution of our growth strategy and our pursuit of new opportunities that bring with them long-term contracted, firm cash flows to serve our investors going forward. We have indicated to you previously that we've secured $35 billion of expansion projects between 2013 and 2020. And we're doing just that. Of the $35 billion, $16 billion, almost half, has now been placed into service or is in execution. We delivered 2 projects totaling more than $500 million into service this year, which I'll speak to shortly. Year-to-date, we've moved almost $3 billion in growth projects into execution, including 4 projects in the third quarter alone. We're in an unprecedented environment of infrastructure growth and favorable dynamics, and we're pursuing multiple projects that will allow us to achieve our goals. So let's take a look at how we're doing and where we're headed. The best way to gauge our progress, I think, is to look at the map. You can see our expanding position, our impressive slate of projects and our record of executing successfully, consistently and with an eye toward sustainable results that reward our investors. Our list of projects and service and execution continues to grow. During the third quarter alone, we placed TEAM South into service 2 months before its scheduled in-service date. This 300 million cubic feet per day project was fully utilized on its first in-service date, highlighting the pronounced need for this takeaway capacity. In addition, TEAM 2014, which will help customers move Marcellus gas production both east and south came in well within budget and is fully operational this month. Both TEAM South and TEAM 2014, underpinned by contracts with CONSOL, Rice Energy, Chevron and EQT, total more than $500 million in investment. And they represent the first 600 million cubic feet per day of the 2.4 Bcf a day in projects that will transform Texas Eastern to a bidirectional system by 2017. We're also making great progress on the projects in execution. By January 1, 2015, the Kingsport Expansion Project, which expands Spectra Energy's East Tennessee system and the Spraberry Supply Lateral off our Sand Hills NGL line will go into service. And we moved another $700 million of expansion capital into execution during the quarter. Access South and Adair Southwest, 2 projects that advanced the bidirectional capabilities of Texas Eastern, will provide incremental firm transportation capacity from Appalachian shale to markets in Southern U.S. Access South is fully subscribed with Rice Energy; and Adair Southwest is fully subscribed with Range Resources. Both projects will be in service by November 2017 with a combined capital expenditure of approximately $350 million. New to our map is another project now in execution. Stratton Ridge, which is a component of our Gulf Coast LNG opportunities. This Texas Eastern project will deliver natural gas supplies to Gulf Coast LNG markets and is moving forward with an anchor shipper to serve Freeport LNG. The more than $200 million capital expansion project is scheduled to be in service in 2019. The fourth project we've moved into execution is the recently announced PennEast project, a 1 Bcf per day pipeline that will connect Northeast Pennsylvania production to our Texas Eastern and Algonquin systems. We have committed to take a 10% equity ownership in the approximately $1 billion project. The investment allows us to leverage existing assets to directly connect to growing northeast Marcellus production, and partner with some of our biggest customers: AGL, NJR, South Jersey, UGI and PSEG. PennEast has an anticipated in-service date of November 2017. Those are projects that are new to our execution ledger, but there's a lot of progress across the board. We plan to submit our FERC application for the Sabal Trail pipeline in Florida by year end, keeping us on schedule for a 2017 in-service date. The Algonquin Incremental Market project, or AIM, is 100% subscribed by New England's major local distribution companies. And we expect to receive our FERC certificate for this billion-dollar project in the first quarter of 2015. NEXUS, which will bring supply diversity to U.S., Midwest and Eastern Canadian markets by delivering Utica and Marcellus gas, has signed precedent agreements with Chesapeake, CNX Gas and Noble in addition to previously announced agreements with Midwest, U.S. and Eastern Canadian LDCs. This 1.5 Bcf per day project provides Spectra Energy with an investment opportunity in the $700 million to $1 billion range and is scheduled for a late 2017 in-service date. During the quarter, both our OPEN and Uniontown to Gas City expansion projects received their FERC environmental assessments, and we anticipate receiving final FERC certificates for both these projects in the first quarter of next year. The $500 million OPEN and $60 million Uniontown to Gas City projects are both scheduled to commence in-service in the fourth quarter of 2015. We've been working hard to move our projects forward and take full advantage of this amazing window of opportunity in the U.S. This year alone, we've completed 6 FERC filings, received 3 FERC certificates and achieved 4 important regulatory milestones with environmental assessments and draft and final environmental impact statements that move our projects forward. Moving onto the growth plans at Union Gas. We're on track in the execution of our 2015 Dawn-Parkway project as well. Additionally, we have customer commitment supporting the 2016 Dawn-Parkway expansion and filed our facilities application with the Ontario Energy Board in September. We expect an OEB decision on the 2016 project in the first half of next year. And while still in development, I'll mention here that by year end, we plan to launch our open season to seek market interest in a further expansion of our Dawn-Parkway system to 2017. In total, the 3 Dawn-Parkway projects represent a CapEx investment of well over $1 billion. So as you've seen and heard, we're making good on the commitments we made to investors, executing consistently on a range of projects that contribute very stable cash flows, earnings and provide attractive returns. Let me turn now to the great opportunities we're also pursuing. We continue to believe that the next 18 months represents a defining period in which important decisions about U.S. natural gas infrastructure are going to be made. Spectra Energy fully intends to participate and lead that massive replumbing, and we've got a great backlog of projects in all the different phases of development. Access Northeast will improve electric reliability in New England by directly supplying about 60% of the region's most efficient gas-fired power generation. The project will expand our Algonquin, and Maritimes & Northeast systems and utilize their existing footprints. We're partnering with Northeast Utilities on this $3 billion joint venture, and we're in active discussions with additional potential partners. Yesterday, we launched an open season for the South Texas Expansion Project, or STEP. The project is designed to deliver natural gas supplies to markets in South Texas. And we're targeting an early 2017 in-service date for the STEP project. Our Appalachia to Market project represents another build-out of the Texas Eastern system to the East. Our open season for the project resulted in very strong expressions of interest in numerous bids, and we're working with bidders to determine the optimal solution for moving their gas to markets. We're also advancing development on our liquids projects. Progress on the Inland California Express Project continues with Questar, and we are in active negotiations with the terminal site landowner. And will compete preliminary engineering and submit conditional land land-use applications in the next few months. If all proceeds as planned, the ICE Project will go into service in 2017. We're also enhancing our Express and Platte crude oil pipelines. On Express, we're pursuing the construction of on-system storage to allow for additional contracted capacity, and we plan to conduct an open season by year end and begin service in 2016. And as we announced in October, we're pursuing a new oil pipeline project with service from Guernsey, Wyoming to Patoka, Illinois. The project will provide shippers with unprecedented access to markets in eastern PADD 2 and the flexibility to meet light crude refinery demand on the Gulf Coast. It's targeted to be in service in 2017 with an initial capacity of about 400,000 barrels a day. So clearly, there's no shortage of opportunities, and we're actively pursuing those that build out our asset base, enhance our competitive position and, of course, enable us to deliver desirable returns for our investors. Let's turn now to the priorities we shared with you at the beginning of the year and report on the progress we're making on these important areas of focus. You'll note a lot of positive checkmarks, which indicates an achievement of a particular goal. Those that aren't checked are in progress and on track, and some can't be fully assessed until we have fully covered the year and got that under our belt. But here is where we are and what's new for the quarter. Our U.S. Transmission business has made great strides toward its $3 billion in expansion project goal, getting very close to that target at this point. Year to date, the business has secured $2.3 billion of new projects. As you will recall, many of our natural gas pipeline contracts come up for renewal in November 1 of each year, and I'm pleased to report that, once again, we have achieved a renewal rate of more than 99% of our contracted revenue on Texas Eastern and Algonquin. Earlier this year, our Liquids business expanded the Buffalo terminal out of the Express pipeline, which fulfilled the goal of expanding on system pipes and terminals. And good progress on 2 priorities at Union Gas. We have a strong, stable asset base there, of course, and we continue to add approximately 20,000 customers per year. And our customers increasingly express a growing interest to procure a supply at Dawn, which is driving the related transmission expansions on our system, which I mentioned. In addition, earlier this year, we filed an application with the Ontario Energy Board to modify our Hagar LNG balancing facility to produce additional LNG to the expanding transportation and mining sectors in Ontario. And as previously mentioned, Union Gas has filed its facilities application with the OEB for the 2016 Dawn-Parkway expansion project. We're continuing to work hard all of our -- on all of our priorities and goals, and we'll update you again when we report our fourth quarter and year-end results. We're pleased with the third quarter performance and with the progress we're making in our capital expansion program, and you can count on us to continue to deliver on our growth project and here's why: Spectra Energy's execution advantage allows us to deliver infrastructure projects that are critically needed and build the backlog of attractive strategic opportunities. Quarter-after-quarter and year-after-year, we demonstrated our ability to bring projects into service on time and on budget and importantly, to the satisfaction of our customers. And keep in mind, the projects we're delivering are firm, fixed-fee projects with very long-term contracts. We've got the financial strength and flexibility to continue executing on our expansion plans, and we're able to move quickly and decisively to optimally leverage our structure and our balance sheet, and related [ph] to finance, all of this growth within advantage cost of capital versus our peers. And we demonstrated our ability to deliver consistent attractive dividend and distribution growth across various market and commodity cycles. You see that again in our announced 10.5% increase in the annual Spectra Energy dividend, which confirms our commitment to create and grow investor value. There's more value to come as we capture the opportunities and pursue the growth that you've heard about today. But with that, let me thank you for your time today and turn things over to Julie, so we can take your questions.

Thank you, Greg. So we want to hear from you now, and we'll open up the lines for your questions. So Stephanie, if you would please provide instructions on how folks can ask questions, I'd I appreciate that.

[Operator Instructions] Your first question comes from the line of Darren Horowitz from Raymond James.

Greg, I want to go back to your comments regarding transforming Texas Eastern to a bidirectional line by 2017. When you think about other bidirectional opportunities behind Access South and Adair Southwest and also including your Appalachia to Market project, when you're talking with producers and you're looking at the multi-year production profile there, how much more incremental Appalachian takeaway capacity and CapEx do you think is necessary? And when do you think we get to a point where we possibly could get saturated with too much incremental pipe and not enough volume to fill it?

Well, I guess to the first point is, we don't build incremental capacity unless we've got contracts to it, typically 100%. On occasion, I guess, we got 70% or 80% also. I'm not very worried about building too much capacity, at least from a Spectra Energy perspective, that is not contracted. We've got about $1 billion more of projects when you look at OPEN, Uniontown to Gas City, the Gulf Market stuff, Adair Southwest and Access South. All that stuff is $1 billion more than, say, the $500 million or so that we put in today through TEAM South and TEAM 2014. That takes you out to that second half of 2017 from that perspective. And again, all those are contracted for. So from our perspective, Darren, I don't see a concern from too much pipe and not enough volume. I think at some point in time, as the LNG projects get going fully, I think the next interesting thing is when you get out to that '17, '18 time frame, we seem to keep finding ways to get incremental volumes. But at some point in time, as Marcellus get as large as it does, the really exciting thing for us is what else can we do with Texas Eastern, do you actually -- or Texas Eastern might build a very large pipe that starts to move incremental volumes as well. So I think at this point in time, we've got, as I said, another $1 billion of projects or so to get us up near that 2.4 number. But then I'm sure we'll find some pieces along the way as our operational guys have done. I think a similar question was probably asked a year ago: Did we have additional opportunities? And we're probably hesitant to say all those -- at there now on the books. But what you've seen over the last year, we've added several new projects that just goes to show that capability. So hopefully that answer -- answers your question.

Yes, it does. And if I could just, as a follow-up, maybe frame that opportunity set a little bit different with a question. Just trying to get a feel beyond 2017 as you outlined from kind of an unlevered rate of return perspective. As you think about further leveraging Texas Gas and moving a lot of that Northeast production South or possibly to Midwest or down to the Mid-Atlantic. If the Marcellus and Utica ends up being a 20 or 22 or 23 Bcf a day market in terms of dry gas production by the end of the decade, where do you see geographically the biggest opportunity set beyond kind of what you've got in the backlog as your commercial guys are looking to lever incremental aspects of Texas gas? What's the next stage of evolution on that pipe?

Well, I think if you look at things on Texas Eastern, I think there's a couple of interesting pieces. Think about the PennEast project, which is only a 10% position, but that's going to the Northeast Marcellus where as you know, Texas Eastern does not run directly through. So being able to leverage areas that we're not accessing today. And then there's things like the STEP project, which is going to move projects -- move gas for those who don't want to use compressor stations, they use geographic areas. It gets them going from Belmont to Corpus Christi. That's an opportunity as well. So I think as you start to see all of the assets start to point south, when you end up going as far west as, say, the middle of Pennsylvania or Ohio, you're going to continue to see assets points south, so STEP-type of project. And as I said ultimately, producers, I think, are going to need a much bigger solution some time post-2017. And I think those of us with existing right away ability to deliver on pipes and end up serve them well on the smaller projects are going to be in a good position.

Your next question comes from Christine Cho from Barclays.

You posted some solid numbers for SEP. And just due to the drop down and all that stuff for year-over-year comps, it's a little difficult to tell where exactly the bps are coming from. So if we were to exclude the onetime event, such as the cold weather earlier this year, can you give us more color on where your results are better than you expected? Is it Express type? Is it the NGL lines? Is it TETCO? Any insight there.

Yes, yes. So I think you're right, the cold weather largely affects the Union a little bit of benefit. But yes, I mean, if you look at SEP, it's things like a full year of New Jersey, New York, which is probably the biggest change from that perspective, and other U.S. Transmission expansion continued to ramp up of Sand Hills and Southern Hills and then the crude transportation revenue as well, Christine. So pretty well on all of those fronts we're seeing the benefits that are really starting to play through from a cash flow perspective. Particularly as you turn things like equity AFUDC into projects that turns into real cash and hence, the accelerating Bcf.

Well, but I mean, like all of those things I would think were included in the guidance that you gave for what you're expecting from the drop down at the end of last year. So like what's coming in ahead of budget?

Well, I'd say New Jersey and New York is coming in a little ahead. We always have some incremental volumes that we put through. The guys always seem to find a way to do that. We're doing better on Sand Hills and Southern Hills than we expected and the crude oil pipeline as well. And also a little bit on the cost front as well is helping, Christine. It seems [indiscernible] that we're doing better. And I think you really see that benefit, and I think maybe we're -- we typically try to give people a good forward look. But as you look at the cash and the benefits that are ongoing, they've just added to the, you're right, a very strong first half of the year. More IT on Texas Eastern as you pointed to in the first quarter as well.

Yes. Okay. Your partner in the Canadian LNG project has recently talked down the likelihood of moving forward with the project. When I look at your CapEx guidance through '16, there are some big numbers there are for 2015 and '16 for Western Canada. And I think most of the spending in the Montney processing should be done by now. So I'm guessing a lot of it is for the pipeline since original timing plans to reach FID or some time next year, I think. I'm assuming -- and I'm assuming very little of that CapEx was tied to expectations for increased GNP activity, at least in '15, '16 since even if another LNG project goes, it wouldn't be until the end of the decade and lead times to build a processing plant isn't as long. So how much of that CapEx is potentially at risk?

Well, I think in '16, you'll see some of it shift out. That's probably what you'll see, but I don't see many much change in '15. Some of the GNP were -- remember, the GNP work isn't all tied to a single LNG project. As we've consistently said, anybody that moves forward with an LNG project, whether it's our project or somebody else, we would expect to probably put about $1 billion to work over the following 18 months after FID, as they ramp up the need for gathering and for processing, if it isn't us. So that's one. Two, I don't think -- well, BG, as you know, is going through a CEO change, so I think you shouldn't be surprised to see some delays on that front. But -- so call it at risk, I don't see it as risk. I do think maybe you could see a shift in timing on the LNG spend associated with that project. And as you pointed out, there are other LNG projects that are out there that are being worked on, but they aren't public. So I think there's a combination of GNP dollars that will still come in regardless of the projects. And I think probably what you'll see when we come out in February, our specific projects, with respect to LNG for BG, you'll probably see that back end shift out a bit. And we've typically put up 3-year numbers that we have in the last year, and I'd expect to see that again. So you'll get a good view for that on '17.

Okay. PennEast, you have a small minority stake, and it's nonoperated. So it sounds like your decision to get into this project is more strategic, and you talked out leveraging your existing footprint. Are there plans to add interconnects with TETCO and Algonquin? And anymore insight into why you decided to stake -- take a stake...

Yes, right. That's absolutely the reason, Christine. So as you know, where Texas Eastern doesn't run through some of those areas that PennEast is going to serve. So we will build direct interconnects with Texas Eastern and hopefully, Algonquin as well. So you're exactly right. I mean, our customers are going to a location. We'd like to go with our customers and serve the needs that they have. Obviously, it's a small investment opportunity there, call it $100 million. But yes, it's really the opportunity that go to and have an opportunity to get into markets that our current pipelines don't go to, but also leverage the existing pipeline system through Texas Eastern and Algonquin. So yes, I think you'd expect to see those customers use opportunities along Texas Eastern and Algonquin.

Are you going to have to expand TETCO and Algonquin as a result of this?

We may. I mean, let's hope that's the opportunity. I mean, we have to see how it all pans out, but there's a Bcf a day that's got to go somewhere, so I think we'll be looking at opportunities to do that.

Okay. And then last question for me. The Stratton Ridge project, you talk about moving forward with an anchor shipper to serve Freeport LNG. Would you happen to know which train this customer is in contract with? Is it the third train? And what's the capacity the customer has taken?

Yes, it's -- I believe it's the third train, Christine. And the capacity number off the top of my head, let's see if I can get it for you, which I don't seem to be able to get it. I think it's around 300 a day. If that's not right, we'll get back to you on it, Christine.

Our next question comes from the Ted Durbin from Goldman Sachs.

Just sticking with the Marcellus here. We have heard about your big projects announcements coming down to the Southeast. Carolinas and whatnot. If you think about where the demand growth is coming from power generation seems like kind of an attractive market, but you've not been involved. Is there anything behind that? Just kind of where your assets are? Is it the return to the risk on the projects? Maybe you just -- you plate is full with everything else you got going on?

Well, I think, yes, the Southeast, the Carolina project, I think it's pretty clear that Utilities kind of want to build that themselves in going down that route, which is fine and dandy. Remember, we do have a little project called Salem -- Sabal Trail, which is $3 billion serving in the Southeast. So that's obviously a pretty major project and expansions like Kingsport as well. But we'll look at any opportunity that come along, but I think when you look at the map and you look at our footprint, we don't go along the Mid-Coast -- the Mid-Atlantic. So obviously, some others do have better advantages in those locations. You can't have the #1 position everywhere. But if we see competitive opportunities and the returns are favorable, we're going to go after that stuff. So it's not an ability to absorb more. We did look at that Carolina project, Ted, as you know, but we weren't able to secure that win, given the project at [indiscernible] that we were looking at.

And then you sort of hinted here, I think, pretty strongly at maybe doing some greenfield all over the Gulf Coast, I think is the way I'm reading what you're seeing. Can you just give us a sense of a ballpark what kind of tariff you would need to get the return you would want to get to get the Marcellus gas all the way down for all this growing LNG?

I think what I would tell you, Ted, is we're obviously going to be seeking our typical kind of a 10%-type unlevered IRR returns is what we'd look at. I don't think we want to get into tariffs at this point in time. Obviously, there's going to be a competitive situation when it does develop, which I think as I mentioned, is probably a post-2017 opportunity.

But we can assume it's a pretty significant amount of greenfield for you, in other words?

Yes, I think it is for anybody. I don't think there's -- there's a reason why that hasn't been done yet, right? There's a lot of the capacity that we're selling now and utilizing, and the shorter haul projects as you will are: a, very competitive and economic for both the customer and obviously, for Texas Eastern and others. So yes, I think that's a fair comment, Ted. And that's why I think it's going to take let's see where Marcellus goes, depending on your view and how big Marcellus goes. And the LNG projects as well, a lot of those dynamics are going to drive how big a pipe and when a pipe actually gets done.

Got it. And then if we can just talk a little about the dividend here and your -- the bump, obviously, today ahead of expectations I think even at what you guided to. Are you thinking about at it any differently your presenting DCF a little bit of different way versus I think what we've seen before? Have you talked about some of the dynamics around where your maintenance capital is coming in, cash taxes? Is this just -- kind of what's all going into the mix there in terms of how you're thinking about [indiscernible].

I just think it's our growing confidence as we go and secure more projects, Ted. And we're able to secure those projects, bring them in service. I think that increasingly, you really see the benefits of our Liquids business, the overall Gas business. And increasingly, the smaller impacts of DCP, if you will, as the rest of the business grows. So as you know, we pay our dividend out of the cash flow, the steady cash flow that comes out of the fee base, the businesses with contract, not volume risk. And so I think that gave us confidence as we look at things where the dividend could go. So we had no issues, frankly, moving it to $0.14, move -- increase it by 10.5%. Obviously, we'll -- as we put our plans together for the next 3 years, we'll look at the opportunities there as well and look forward to speaking to the Street about that in early February.

And Ted, I'll just add, if you look at maintenance CapEx and cash taxes on the maintenance side, we're at or below what we've been projecting. Were still thinking that we'll be pretty much on track for the full year. It's just kind of the way the maintenance work gets done in the business. On cash taxes, we're a little bit below the estimate that we put out, so that's all good. And I think just recalling the discussions after the first quarter conference call, where commodity prices were still strong and our coverage was very high, we were outlooking coverage of about 1.4x for now looking at about 1.5. And like what Greg had indicated earlier was as we -- yes, we had a really big drop down last year, and we're kind of just getting our sea legs in the first couple of quarters, making sure that the way we'd outlook is the way it's folding -- unfolding, and it certainly is. So I think we'd indicated there might be some room to share a little bit more and still hold the coverages where we think they need to be.

Our next question comes from Bradley Olsen with TPH.

If I could take things to Canada for a minute. There is obviously a big announcement out of TransCanada talking about signing up $3 billion worth of contracts coming out of Alberta and BC. And as I think about kind of the macro landscape, as well as some of the exciting new completion techniques we've seen out of the Montney. When I think about the way that the West Coast business is positioned, it seems like we've talked a little bit about kind of LNG on the Gulf Coast growing demand. And obviously, there is potential, if not in Canada maybe in Oregon or the Pacific Northwest for LNG demand growth as well. And the BC pipeline that you operate is kind of ideally positioned, it would seem, to deliver gas from the Montney into those potential Pacific Northwest, U.S. LNG projects. When we think about kind of what share of opportunities or what share of volume growth the West Coast business should be able to capture, both in kind of gathering and processing, but also in kind of firm transportation arrangements down to the Vancouver, Seattle area, do you guys have a way of thinking about that? Or a way that maybe you could help me think about that? And specifically, is there an opportunity to potentially expand the BC pipeline to service that prospective demand growth?

Yes. And I think you've framed it up well. I mean, still early days and there's no doubt there's -- I see comments out of Shell and BG. There's definitely a bit of a slowing in terms of their focus on Western Canada right now, but I don't think that's a long-term issue. I think that's a short-term issue. So when I think about the projects, think -- we kind of split the West Coast pipeline into 2 sectors: a Northern sector and a Southern sector, which we call T-South. I think your bang on. We're looking at opportunities right now and responding to customers' request to expand the Southern half of that to move gas to, as you say, into the Vancouver area to the [indiscernible] the Washington State border. I think if the projects come forward, you'll see that. Remember that we kind of process about 60% of the GNP, process about 60% of the gas that gets produced in British Columbia. So in the Duvernay and the Montney, I think there's some liquids opportunities as well, which may lead to pipeline opportunities and some other infrastructure that I think we should be well set up. But specifically, T-South, so the southern part of West Coast pipeline, I think you should look at opportunities there. They may be a year or so out, but that's definitely part of the discussion that's ongoing in Western Canada. I think the big thing has to be clarified exactly what's going to happen here in the Gulf Coast versus LNG on the West Coast of Canada, take a big step forward, the BC government has come out with what looks like to be a favorable tax structure, at least from some of the comments I've seen from big producers. I think it's just the issue of some of the challenges of how far from market you are and get in the projects approved that are actually holding up the next phase there, Brad.

That's great color. You kind of hit on it a couple of different times during the call, but you guys have historically done a great job connecting with LDCs and partnering with LDCs on Texas Eastern. But when I think about the next 5 to 10 years in North America, really, the demand growth is overwhelmingly coming from LNG, petrochemical, industrial, and there is obviously LDC and PowerGen growth as well. But Mexico LNG and petrochems are kind of the really big slugs of demand. When you think about kind of your relationships with those LNG, petrochemical and potentially even Mexican gas importers, are those areas where you continue to have discussions? I mean, how would you kind of characterize your relationships with the parties who are really going to be driving most of North American demand growth? Because you've obviously done great job getting projects done up in the Northeast and bringing a lot of that gas down to the Gulf Coast. But when it comes to kind of taking the next step and signing up direct agreements for gas delivery to these facilities or even across the Mexican border, should we expect to see those types of projects in the next year or 2?

Yes, I think. So look, if anything -- we already have a strong relationship. It's -- as you point out, look, that the -- that's why you got a pipeline system that goes from supply push to demand pull, as you know, and then there's a balance in between. A few years ago, all the projects were supply push. As you rightly pointed out, a number of projects today are demand pull, but I think back. When I think about the customers that we serve, whether it's BP as the major customer; Chevron, a major customer; the Shell guys, all that works out extremely well, obviously, our joint venture at DCP with Phillips 66, one of the biggest players in that regard. When I think about the people that run companies like Tesoro, folks that we know well. I like our relationships on all of those fronts, a; b, the expansion into the crude oil business has given us even more confidence with that group of people, so we feel good from that perspective. With respect particularly to Mexico, I think it's fair to say that you would see us do joint ventures there, whether it's with intrastates, another interstate or if we actually went into the Mexican side of the border with a partner down there as well. I think that just makes good common sense. Play the where your strengths are, partnership where you need to have partnerships and do things on your own when you can do that. So I do think we have a dogmatic approach, but I think you're exactly right. As we look and you start to see projects like STEP start to turn more to the Mexican border, you may see us partners with some other folks that are also involved in that area on both sides of the border. So it seems to me there's probably about $2 billion worth of an opportunity set here over the next several years on both -- on each of the U.S. and Mexican side of the border.

Got it. That's really helpful. The -- I guess that makes a pretty good segue into the crude project. The -- there's -- obviously, you guys have discussed expanding Express-Platte or expanding specifically Platte for some time. And now, you're being a little bit more direct talking about an expansion in the Bakken. We've seen, over the last year or so, quite a large plate of projects proposed to either move crude out of the Wartenberg or the Bakken. We've seen, let's say, even some of the biggest players in the midstream space like Enterprise basically see those efforts fail. And we've seen 1 or 2 big projects go through, but even then, only by giving large portions of the economics away to anchor shippers. It seems like a very crowded market, and I guess I was wondering if you could provide some color on was it producers that are asking for your participation in that market? Or do you feel like you have sufficiently differentiated economic propositions that you could maybe make something go ahead when we've seen a handful of others fail and then there's plenty of projects are there that obviously are kind of in open season purgatory, so to speak?

Right. And as you know, Brad, I mean, we haven't moved anything to execution on that front. But on the Platte pipeline, look, Platte has been consistently apportioned for 9 years. Meaning, that basically the shippers don't have the capacity they would like, and they have told us they need more capacity on the route from Guernsey to Patoka. And it's increasing production from the DJ and the Powder River basins, as well as those new pipelines you mentioned from the Bakken converging on Guernsey. We think there's a real need to move light, sweet crude from Guernsey to market, and a handful of parties, actually, a large handful, as you pointed out, have proposed pipeline secured crude from the Rockies to Cushing. We believe that a stronger course can -- case, can be made for taking that crude further east to market rather than just flooding Cushing. And we think that capacity has that opportunity to go further east. And arguably, you could take it further east, or you could take it down to the Gulf via barges, et cetera, so a slightly different proposition. And then last thing I would say, you're right, many people have proposed projects. As you may recall, we blocked the Express pipeline project for exactly that reason. Many people proposed many projects, and you know the most infamous one of all and have not been able to get them done. The people that have been able to do well have been people with assets already in the ground and finding ways to do that. The same way we've strategically been able to do that on the gas side. I expect we'll find a way to do that on the oil side. And I've already seen that with some small brownfield work on Express. We talked a little bit about some capacity debottlenecking that will go up for an open season here at the end of this year, early next year that allows us to bring in, call it, $150 million or so of expansion on Express, and get that up closer to nameplate. That stuff is all driven by the customers wanting to do that and our ability to already have an asset in the ground. We're an early player on that front. There's no doubt about it. There are some bigger players, but I like our position in that regard, and we're going to keep pushing forward with that. And what I'll guarantee for you is we can't get the commitments to take on those projects, so the returns that allow us to keep growing our dividends and distributions, we won't do them.

Our next question comes from Danilo Juvane BMO Capital.

You mentioned in the press release that you had an impact from the lower Canadian dollar in the quarter. I was curious if you guys are comfortable with your Canadian dollar exposure for 2015? And I guess is that something that you're thinking about hedging?

Yes. The nice benefit we have in -- and I think the impact was a single digit, it was pretty small. And that's because -- remember, Canadian assets are financed with about 65% debt up there, so you have a natural hedge. So while interest rates -- while the dollar goes, the Canadian dollar declines, so as our interest exposure in Canada. And the earnings go down as well, but vice versa. So 65% of it is naturally hedged. And given that it's a pretty significant and persistent change in the Canadian to dollar to have any huge impact, yes, I wouldn't expect to see us hedging that for -- definitely for cash flow purposes. That doesn't make a whole lot of sense from our perspective. So again, that natural hedge and the growth of the over portfolio, it's a small dollars. I think that was probably in a $4 million range.

You -- exactly, Greg. The EBITDA impact was $12 million, but at the net income line, it was only $4 million. It was actually slightly positive in the second quarter. First quarter was where we saw a more significant impact because of the rise in propane prices, but to Greg's point, it is largely hedged, and you just don't see the impact in distributable cash like you do on EBITDA.

Okay. I appreciate the color. And I guess, as a follow-up, when thinking about the weak Canadian dollar along with the recent constructed BC LNG tax, does this, in any way, make you more interested in bolstering your Canadian presence? Do you see opportunities to maybe acquire or even build as a result?

Well, definitely on a building side, I think the -- well, I think Western Canada is in a bit of a slowdown according to all the producers that have had earnings calls from that perspective. I think long term, the supply there, I think in the -- if you look in the Horn River and the Montney, they're up there with any of the largest plays in the U.S. So the supply is definitely there. The long-term build opportunities are there. As well as I mentioned, billion dollars plus of opportunities at Union Gas, which as you know, is a distribution company utility. But importantly, it's got a 5 Bcf a day pipeline through the middle of it, which we own. And that's really where we see the opportunity. So I think we'd continue to build into Canada. Obviously, the returns are a little bit lower there, but I would say the risks are a little bit lower there as well. And the opportunity above -- to earn above the regulated rate of return. I think importantly, there's a great connection between at least the Eastern Canadian assets and our U.S. assets, and you see that increasingly through projects like NEXUS where in fact, you can augment the assets on both sides of the border for the benefit of customers.

Our next question comes from Becca Followill from U.S. Capital Advisors.

Can you talk a little bit more about the change in the payout methodology from DCP? And maybe quantify, maybe looking at the past year, the delta, what it would mean?

Yes. Well, maybe -- Pat'll speak to that. But as -- just for everybody, it's not as we used to be in net income. But basically as a response to investors, we wanted to show kind of what the distributable cash flow was. And importantly, and I think from evaluation perspective, the increase, substantial increase in GP and LP cash flows that we see as part of that DCF, I think, it makes up about a third of the distributions to the parent now versus 20% just a year ago, but Pat, I don't know. Any other...

Well, Becca, that's a good question. But interestingly, we did a backcast for 5 years and a forward look for 3 years. And whether we use the old formula of 90% of net income or the new approach with the coverage of, say, 1 1 on cash flow, you could see a difference in any 1 year. But over time, they were right on top of each other, which I guess wouldn't be surprising. So it's really not so much about trying to change the amount of cash distribution. That's really more about aligning how we communicate all the way up the chain. So distributions from our MLPs to the parent, distributions from parent to parent in the form of dividend. It's all synched up now based on coverage in distributable cash flow. But there's really no net change in dollars received.

Great. And then on the announcement of adding the additional storage on Express in order to expand the capacity, how much does it expand capacity volume in the system?

I think it's a couple of -- if you -- the current one is pretty small, but the one we talked about, the $150 million by '16. I think in terms of tankage, it's around -- about 24,000 barrels. Is that the question you're asking? Or you're talking about...

No. In terms of -- it sounds like it adds -- enables you to add capacity on the systems...

Oh, I'm sorry. Yes. Got it. Sorry, Becca. Yes, so we go from about using about 89% of nameplate to getting close to about 98% of nameplate on Express.

And then just with the change in the Senate following yesterday's election and maybe a little more likelihood that Keystone might get approved. Does it change your view on potentially 20 [ph] the systems?

No, it really doesn't. I mean, I think quite different customers. Remember, all the way along Express, which is what the really heavy crude, which is like what you've seen in XL. You have several -- a lot of refiners there that need access to those supplies, and we'll continue to need access to those supplies. And my understanding of the dynamics whether XL goes 4 or the Trans Mountain goes 4, et cetera, the Canadian producers continue to look for outlets given the production there, so that's one. And then along Platte, a lot of the Platte expansion that we're talking about is associated with, as I mentioned earlier, call it, Bakken and Rockies production in that light, sweet crude. So we don't really see that having a major impact. Then I go back to obviously -- we're not going to build anything unless we've got a long-term contract associated with it.

Our next question comes from Craig Shere with Tuohy Brothers.

Taking off on Brad's questioning around the Bakken crude takeaway expansion. Do you see falling oil prices hurting producer interest due to potential reduced activity? Or increasing interest due to the need to reduce costs relative to rail takeaway in a more efficient market?

You know what, Craig, I think it's a little early to tell. We're talking about 3 or 4 weeks, really, of dramatic moves in the price of crude. There's no doubt you still have significant differentials. I'm sure you've seen in the paper today the desire of people to ship very light crudes offshore in the United States without even government approval. Does that make them more interested here? I think it's too early to tell. I think if projects -- there's no doubt that I think producers are going to pause and think about what are the dynamics going forward. But I think it would probably take 6 or 8 months of consistent lower prices, whatever you want to define that as, before people start really pulling back from looking at these projects. But I think it does mean, over that 6-month period as people pause and think, signing up a long-term contract is going to be a little bit tough for major projects. And so I think things like the debottlenecking around Express for '16, relatively modest expansions with economics both for us and producers, that kind of stuff, again, is going to be very positive. And obviously, for players who have assets on the ground, and I'd say this both on the gas and oil side and natural gas liquids side, the ability to draw huge volumes for brand-new greenfields may be a little tougher than building on existing pipes where you don't need anywhere near the same volume take up and the economics can be -- for both parties still just as good.

That's helpful. And Greg, you kind of referred to export opportunities. It seems like Saudi Arabia is specifically targeting the U.S. production industry, which kind of puts producers in a difficult situation since they're kind of hamstrung by export regulation. And now with some changes in the U.S. Senate, one wonders if there might be some shifts there. How do you see any changes in U.S. export policy impacting your business up or down?

Well, obviously, the more that there's exports out of the United States, that business is desired of the various parties at play to be able to do that. That's going to lead to further replumbing of the industry, and that's the business we're in. We like to consider ourselves like Fedex or UPS. We'll pick up your product, clean your product, store it and deliver to where you want to go. Ultimately, if that means more of it going offshore, you're going to need more infrastructure because we already know the demand for natural gas and natural gas products within the United States is drawing infrastructure needs, obviously, the export would is well. So I think that's probably going to be play out positively. I think you see -- I -- let's see what the BHP situation is really saying. If they got a nod indirectly from the government saying that's fine to do that, and as such, you'll see if -- or if such projects, or will that lead to more of a formal change in policy. I think time will still have to tell on that front, Craig. But if anything, I don't see there'd be fewer exports, either of natural gas liquids products or crude or superlight crude, I guess better stated, it can only get better from that perspective. And I think that can only be a positive for the overall infrastructure industry, but Spectra Energy in particular as well.

Our next question comes from John Edwards with Crédit Suisse.

So just backing up. I mean, so looking at your 2 slides here. There's 34 different projects you're having to keep track of. That's quite a lot. So I thought maybe if you could help us think about where and how much do you think you're ahead of schedule, kind of order of magnitude, do you think you're ahead of schedule would be helpful. And then perhaps you could quantify where you think you're a little behind schedule kind of order of magnitude in terms of dollars is kind of what I'm looking for.

Look, I think if setting out a target at the beginning of 2013 of $35 billion, and you're always going to have projects coming in and out throughout that time period. We set a target that's basically '13 to '20, so it's a long time frame. But being $16 billion out of $35 billion in less than the first 24 months of what is a 6- or 7-year goal, I think is -- makes us feel very confident. I think you see that in our dividend acts and other activities. That being said, I think there are a couple of big projects that are end-of-decade projects. I think LNG-type projects, crude oil projects are moved towards the end of the decade, which we -- but we feel good that we can get that stuff secured. So I think we've got the right process to get this stuff signed up. We've got the right process to get projects executed, and I see -- think you see that in the 50 or 60 projects, which we've executed over the last 5 or 6 years and the projects even year-to-date. But the other thing I think that's not included in the number, in those projects that you saw, would be M&A. If there's opportunities on that front, that could allow you to accelerate this as well. So I think there's -- well, you say 34 projects will add to track, that's true. But I can assure you, since a lot more projects than that than we actually are looking at to ensure that we can secure that remaining $19 billion in the $35 billion, if you will.

So -- I mean, as far as securing the rest of it, do you feel like you're tracking ahead of plan at this point?

I said we're tracking right on schedule to what we would have expected in our less than 2 years into our multi-year goal. Probably a little ahead on execution and on track with the securing projects.

Okay, that's really helpful. And then in terms of the volumes that are now going north to south, maybe you could just kind of help us think about how much now in aggregate have you contracted. And at this point, how much more do you feel there is to go? Because there's so many projects out there relative to the growth and demand, so maybe you can help us step back and think about that.

Yes. Well, I think we've pretty well contracted about $2.4 billion -- almost $2.5 billion worth of projects. So -- and to date -- sorry, 2.5 Bcf a day of volume has been contracted to move south. And in-service to date is about 600 of that. So as we indicated, TEAM South came in a little bit earlier than we expected. TEAM 2014, on time and a little under budget from what we expected. But the remaining [indiscernible] in Uniontown to Gas City, Gulf market, Access South and Adair Southwest, that makes up that remainder, but that's all contracted for.

Okay. And then in terms of how much more you think you're going to get in terms of moving north to south.

Yes. I don't know if I could put a number out there on that front. As -- we're probably doing more than we thought we did a year from that -- a year ago. And I would expect you're going to see more than we expected on this 2, 4 year from now. At some point in time, there is -- at some point in time, there's a limit as we talked about, you'll have to build even bigger projects. For example, one to think about is the STEP project. I think STEP project expects to move almost another 0.5 Bcf a day potentially. So let's see if how that project comes in. Again, that's coming from, call it, Belmont to Corpus, so that's another opportunity that I didn't included 2.4. Actually, we lack -- we never seem to lack for a number of opportunities. That's for sure.

There are no further questions. I'll turn the call back over to the presenters.

Well, listen, thank you very much for joining us today. As a reminder, we have Greg in New York tomorrow for a breakfast meeting. Unfortunately, Pat is not going to be able to with us because he has another commitment, but both Greg and Pat are going to be at various investor meetings over the next couple of weeks, so you'll have an opportunity to hear from both of them going forward. As always, if you have any questions, give Roni Cappadonna and I a call. We are traveling to New York today, so if we don't get back to you as quick as we normally would, bear with us or leave a message, and we'll call you back as quick as possible. But thanks again for joining us, and we hope to see most of you tomorrow in New York. Thanks so much.

This concludes today's conference call. You may now disconnect.