Sea Limited (SE) Q1 2012 Earnings Report, Transcript and Summary

Good morning. My name is Tanisha, and I will be your conference operator today. At this time, I would like to welcome everyone to the Spectra Energy Quarterly Earnings Conference Call. [Operator Instructions] Thank you. Mr. John Arensdorf, you may begin.

Thanks, Tanisha, and good morning, everyone. Welcome to Spectra Energy's first quarter 2012 earnings review. Thanks for joining us today. As usual, leading today's discussion will be Greg Ebel, our President and Chief Executive Officer; and Pat Reddy, our Chief Financial Officer. Both Greg and Pat will discuss our quarterly results and provide more color around our strategic plans to enhance the value Spectra Energy delivers to its shareholders. We're then going to open the line for your questions. But before we begin, let me take a moment to remind you that some of the things we will discuss today concerned future company performance and include forward-looking statements within the meanings of the securities laws. Actual results may materially differ from those discussed in these forward-looking statements. You should refer to the additional information contained in Spectra Energy's Form 10-K and in our other SEC filings concerning factors that could cause these results to be different than those contemplated in today's discussion. And in addition, today's discussion include certain non-GAAP financial measures as defined under SEC Reg G. A reconciliation of those measures to the most -- directly comparable GAAP measures is available on our Investor Relations website at spectraenergy.com. With that, I'll turn the call over to Greg.

Thanks very much, John, and good morning, everybody. As you've seen from our earnings release, Spectra Energy is off to a good start in 2012 delivering solid first quarter ongoing results of $331 million or $0.51 per share. A couple of key takeaways for you that I'm sure will come as no surprise, first, our results for the quarter were affected by much warmer than normal winter weather. Historically warm, in fact. Union Gas experienced its warmest winter in more than 100 years, which in turn lowered customer usage by almost 18%. Second, weaker commodity prices. Lower NGL and natural gas prices did adversely affect DCP Midstream's earnings and the higher extraction premiums reduced margins at our Empress facility in Canada. Fortunately and positively, the effect of low commodity prices at DCP were more than offset by volume increases. DCP's NGL production increased by more than 15% quarter-over-quarter and gathering and processing throughput increased by almost 8%. With the exception of commodity prices and weather, earnings for the quarter were in line with, or slightly ahead of, our expectations and we continue to execute well on our business expansion plans. The power of our diverse portfolio helped us manage through the effects of lower commodity prices and weather. And with NGL prices typically lower in the first quarter of the year, and with pet-chem facilities coming back online from outages and the expectation of greater propane exports, we remain optimistic regarding NGL prices for the remainder of the year. That said however, at least through the day, the outlook for natural gas on its own continues to looks challenging as do the steep extraction premiums at Empress. Nonetheless, we've got a good handle on things we can control and a proven track record of successfully navigating through the challenges and identifying and acting on opportunities. We're continuing to execute on our impressive slate of expansion projects underway, and those on the drawing board. And as we've indicated to you before, we've got $3 billion in Spectra Energy-financed expansion and execution and more than $4 billion of DCP-financed expansion in flood. Spectra Energy will derive additional value from the increasing distributions made by DCP Midstream to its owners, a value that'll be passed along to our investors. DCP Midstream is in the midst of a high-growth phase and continues to deliver attractive distributions to us and our partner, Phillips 66. Our expansion projects across the company, including many at DCP Midstream, will deliver a high level of fee-based growth to support ongoing earnings and dividend growth through various commodity and market cycles. Let's take a look at some of the Spectra Energy and DCP Midstream opportunities. Since we just returned from a trip to Asia in which we met with various parties about prospects for exporting liquefied natural gas or LNG from North America to international markets, let's begin there. While it's definitely still early in the process, LNG exports in British Columbia would be a game changer for that region. There's a great window of opportunity for the construction of pipelines from the suppliers to export terminal locations. I mean, given our excellent B.C. assets, we're well positioned to participate in the necessary infrastructure growth. We would like to build at least one of the pipelines to the west coast of B.C., but we also see great opportunities in the higher returning upstream gathering and processing investments that will be required as the export market develops. That's an opportunity for us to further expand our impressive fee-based gathering and processing network in Western Canada. Of course, Texas Eastern is well situated to serve Gulf Coast LNG export terminals. Our existing pipeline infrastructure will ensure we gain our fair share of Gulf Coast LNG opportunities as well over the coming years. Now let's take a look at some of the other opportunities in the U.S. In response to both changing supplies and growing demands, Spectra Energy is pursuing an extraordinary suite of U.S. projects representing $2 billion to $4 billion of investment opportunities over the 2014 to 2017 time frame. These are in addition to the $3 billion of projects currently in execution. The projects are designed to connect a variety of growing supplier regions to the growing Midwest power market, premium Northeast and New England markets, LDCs and power generators in Eastern Canada and finally, both gas and electric utilities in the Southeast U.S. This slide provides an update on 5 projects connected to the Marcellus and Utica basins, which further demonstrate our first mile and last mile competitive advantage. I won't go over these in detail but rather point a few highlights. We reached binding agreements with the 2 anchor shippers for 2014, Chevron and EQT. We expect to have this 600 million cubic feet a day project in service by the end of 2014. Our open project has AEP as a committed anchor shipper, and we recently initiated an open season to further define the project scope. Our next project is an exciting opportunity in Ontario and the Quebec markets. Next is focused on connecting Utica and Marcellus producers directly to the Dawn storage hub in Ontario and the growing Eastern Canadian local distribution and power markets. We have MOUs in place for our next several customers. You may have seen our AIM Project featured on the front page of the Boston Globe last week. The article described how AIM offers growing Northeast and New England markets access to abundant and inexpensive Marcellus gas, increases supply diversity, produces price volatility, providing greater supply security and hundreds of millions of dollars in cost savings for consumers. And earlier this year, we announced an open season for our Renaissance project, a new pipeline system that will link growing natural gas supplies in various basins to high-demand power generation and distribution markets in Georgia, Alabama and Tennessee. We had a successful open season and expect to finalize commercial terms during the second half of the year. And let's not lose sight of the tremendous power conversion opportunities in Florida as older coal and oil-fired fleets are converted to cleaner burning natural gas power generation. As you know, we have an existing footprint in Florida which crosses the primary service areas of 3 investor-owned utilities in the state, which really gives us a strong competitive advantage. Now let's take a look at DCP Midstream, which is seeing significant volume growth particularly in the liquids-rich, high-margin regions like the Permian, the Eagle Ford and the DJ Basin. DCP is also building a premier pipeline network to relieve NGL constraints and bottlenecks. This fee-based network is designed to deliver NGLs to the premium-priced Gulf Coast markets. As you know, DCP Midstream is our 50-50 joint venture with Phillips 66, and we recently had our first board meeting with the Phillips 66 change. We've been working with them throughout the transition and continued to be fully aligned with the strong consensus view on DCP's growth plan and the utilization of DPM and the MLP. DCP Midstream is a top-tier processor and by a fairly wide and growing margin, the largest producer of natural gas liquids in North America. The business has an excellent existing NGL position concentrated in basins where NGL and crude fundamentals support active drilling today. It's important to recognize DCP's recent history of investment, which in turn drives gathering and processing throughput and NGL volume growth. Natural gas and NGL market dynamics provide DCP with tremendous CapEx investment opportunities, which we're actively pursuing. Those investments drive volume and earnings growth, and with DCP's $4 billion-plus slate of projects in execution and at least another $2 billion on deck, it's clear to see that this positive momentum will continue to benefit Spectra Energy investors through the decade. Let's take a look at those projects that DCP has in execution. Two of the major wide grade pipelines we've talked about before are under construction and on target to be placed into service on time and on budget. Sand Hills Pipeline provides NGL transportation service from the Permian and the Eagle Ford to Mont Belvieu. And we expect to complete the project's first phase during the second half of this year for Eagle Ford service, but Permian slows by the middle of 2013. Southern Hills Pipeline targets new NGL transportation capacity from the Midcontinent to Gulf Coast markets, and we expect to bring Southern Hills fully into service by mid-year 2013. Capacity for Southern Hills will be about 150,000 barrels per day. Now subject to approvals from the boards of both DCP and DCP Midstream Partners, we would expect both Southern Hills and Sand Hills to ultimately reside within DCP Midstream Partners in the 2013 to 2014 time frame. A couple of recently announced projects will add additional flexibility and incremental fee-based earnings to DCP's interconnected system. The new Front Range pipeline being jointly developed by DCP Midstream, Enterprise and Anadarko will connect producers in the DJ Basin to reliable takeaway capacity and a market access to the Gulf. Three weeks ago, DCP Midstream Partners acquired a 10% interest in Texas Express Pipeline. The pipeline will provide much needed takeaway capacity for producers in the Rockies, Southern Oklahoma and the Midcontinent area given them access to the largest NGL market along the Gulf Coast and the opportunity to maximize the value of their NGLs. The quadrupling of NGL pipeline capacity from these 4 projects will result in significant fee-based earnings growth. In addition to these pipeline assets, DCP has announced plans to invest in more than 700 million cubic feet a day of new processing capacity and over 1,500 miles of new gathering infrastructure between 2011 and 2015. And on Wednesday, you may have seen DCP Midstream announced capital investments underway in the Midcontinent, including about $1 billion for the Southern Hills project I mentioned, and roughly another $1 billion for additional gathering and processing assets which significantly enhance its leading position in the area as the largest gatherer and processor of natural gas. And to increase its reach in liquids-rich production place like the Granite Wash, Woodford-Cana and the Mississippi line. All of these growth projects will enhance DCP's asset portfolio to provide producers with an integrated liquids solution. So as you can see, Spectra Energy continues to create value by connecting natural gas and its related products and services to growing markets. Our business plan and strategy remain solidly on track, and we're making good headwind in our projects. We're expanding our impressive portfolio of assets and businesses, which will generate increasing levels of cash to reinvest in our business and return to our shareholders. And we continue to demonstrate our commitment and capacity on all those fronts through the various commodity and business cycles. So with that, let me turn things over to Pat who will walk you through our first quarter financial performance.

Good morning. As Greg mentioned, Spectra Energy reported ongoing first quarter earnings of $331 million or $0.51 per share, compared with $350 million or $0.54 per share in 2011. Ongoing EBITDA for the quarter was $902 million compared with $904 million in the first quarter of 2011. Strong earnings and cash generation from our mix of businesses allow us to fund our sizable CapEx program with no need to issue equity, while continuing to strengthen our capitalization ratios, maintain a solid balance sheet and grow our dividend. Let's take a look at our performance by business segment, starting with U.S. Transmission. We reported first quarter 2012 EBIT of $271 million, compared with $279 million last year. The 2012 quarter results reflect lower interruptible transportation revenue due to unusually warm weather compared with colder than normal weather in the first quarter of last year, the effects of expected contract reductions at Ozark Gas Transmission and the acceleration of certain software amortization costs. These results were partially offset by expansion projects previously placed into service. Turning to Distribution. That segment recorded first quarter EBIT of $151 million compared with $167 million in 2011. This decrease is almost entirely due to lower customer usage as a result of warmer than normal weather, the warmest in more than a century and 23% warmer than the same period last year. Lower operating fuel cost partially offset some of the decrease. Our Western Canada Transmission & Processing business reported first quarter EBIT of $138 million compared with $141 million in 2011. This segment experienced improved results in the gathering and processing business, primarily driven by higher revenues from expansions in the Horn River area of British Columbia. However, these results were offset by lower earnings at the Empress natural gas liquids business. This reduction is due to lower NGL margins driven primarily by lower propane prices due to the warm weather and significantly higher extraction premiums. Now let me turn to our Field Services business, which represents Spectra Energy's 50% interest in DCP Midstream. Field Services is enjoying great momentum from its growing slate of expansion projects. Field Services had a very strong first quarter with EBIT of $93 million compared with $81 million in 2011. This EBIT increase reflects gas throughput that was 7% above last year and NGL production volumes that were up 15% in aggregate, with especially strong growth in the Permian, Eagle Ford, DJ and Midcontinent areas. You'll recall that during the first quarter of last year, volumes had been significantly reduced due to severe weather. This segment did not experience volume-reducing weather this year and in fact, its earnings for the quarter reflect higher volumes from expansion projects like Mewbourn and Roberts Ranch, which were placed into service in 2011. The positive effects of these volume increases were partially offset by lower NGL and natural gas prices, which reduced our share of partnership earnings by $24 million in the quarter. As a reminder, almost 50% of DCP barrels are priced at Conway. DCP and its customers will benefit once Southern Hills is in service and relieves the current bottleneck between Conway and Mont Belvieu. With its $89 million cash distribution to Spectra Energy in the quarter, DCP Midstream continues its record of paying attractive partnership distributions to its owners. Now let me turn to other, which is primarily comprised of corporate costs including benefits and captive insurance expense. Other reported net costs of $29 million in the first quarter of 2012, compared with net costs of $24 million in last year's quarter. Interest expense was $157 million compared with $155 million last year. At the end of the first quarter, our debt to total capitalization ratio stood at 55.6%. We expect to fund our CapEx program through a combination of internally generated funds and debt while staying within our targeted 55% to 60% range for leverage. And at the quarter's close, we have total capacity under our credit facilities of $2.9 billion and available liquidity of about $2 billion. So that's an overview of our first quarter results. We feel good about where we are today and where we're headed in the future. We're continuing our growth focus and we see opportunities to profitably invest about $15 billion to the end of this decade. That investment will allow growth with robust returns on capital. Our record of strong, sustained cash generation benefits our investors. You can expect continued and attractive dividend growth from Spectra Energy. We intend to grow our dividend by at least $0.08 a year, with upside potential to our 65% payout target. As you've heard today, we're able to deliver value and growth across all market cycles because we have an expansive asset footprint featuring our first and last mile competitive advantage. We have considerable financial strength and flexibility enhanced by multiple financing vehicles. We have a proven track record of delivering attractive returns on capital employed. And last but by no means least, we deliver reliable earnings and ongoing dividend growth. So with that, let me turn things back over to John so we can open the lines and take your questions.

Okay, thanks, Pat. Tanisha, would you instruct the participants how to ask questions, please?

[Operator Instructions] Your first question comes from the line of Stephen Maresca with Morgan Stanley.

I wanted to see if I could get your view on the Southern Hills' 150,000 barrel a day expansion and you talked about the Conway, Belvieu. And just your view, is that -- do you think the 150,000 along with the other lines out there are enough to help alleviate this discount between Conway and Belvieu? Is there an opportunity or a need to expand Southern Hills beyond that 150,000 barrel a day? And how long do you think it takes before we get more even pricing between those 2 points?

Yes. I think that there's definitely going to be a need for more. And I think we could take the Southern Hills up to probably around 200,000 over time. So there's no doubt that -- you still -- I saw it yesterday, I guess it was still a $0.30 or so [ph] delta between the 2. And as you know, Stephen, we've got 50% of our barrels coming at our Conway base. So obviously, closing that is a big uplift for us. So I think given the amount of investment that we've seen just by doing Sand Hills and doing Southern Hills, I think you'll continue to see more pipelines be built. And there's some others with other phases [ph] as well. So I don't think by any stretch of the imagination this will be the end or that that will be enough to close some of the delta that you see. It's also why Front Range and Texas Express were important for us to be involved with, as well.

Okay. And then looking at the quarter, you guys realized about $1, I think, again on NGL pricing, which I guess it compares to sort of $1.25 guidance that you had in the beginning of the year. And just your views, if you have any, just on how this is going to play out in terms of NGL pricing for the rest of the year. How do you think that impacts you, obviously?

Well, I mean I think we've put out our impacts on that full year every change in penny and NGLs. But I think people have there -- there's a couple of things we can't forget. One, traditionally and historically, the odds are that your first quarter is going to be the weakest quarter on NGLs. Not every first quarter, but most of them. Secondly, inventories tend to peak in May, and then those inventories are drawn down. And that's driven by the fact you've got all the crackers and turnaround in the first quarter. This year, interestingly enough, a number of those turnarounds lasted longer than expected and there were several that were unexpected, Williams, Eastman, but they had downtime that they hadn't planned on. And then finally, you had the very warm winter that pushed down prices of propane, which obviously has an impact. All of those things I think you'll see turn around as the year goes forward and you'll start to see a recovery in the natural gas prices, in the natural gas liquids prices as well. So at this point in time, I'm optimistic that those will turn around and obviously, whether we'll get to the $1.25 for the year average, we'll have to see. But it's a little early to make that call.

Okay. Final point from me. You mentioned Greg, Southern and Sand Hills going into DCP Partners in that '13, '14 time frame, which I think was something new. Just how do you view financing there at DCP Partners? Those are pretty big projects. Would the parent potentially be willing to take stock back as what we've seen a lot recently with some parents helping out on big financing plans? And then you just what this means potentially -- where you'd like to be. You mentioned your payout ratio and the dividend at 65% but upside potential, where would you be willing to go down the line with that?

Well, just let me work those in reverse. I mean, we haven't even got the 65%, so we still have a ways to go there. And I think that gives us some opportunity, which obviously we'll look at with the board later on in the year. With respect to DCP, I mean, we're already financing both Southern Hills and Sand Hills, and we have typically taken back our -- taken back units for the proportion that we own. I will say DPM has put in its own funding capacity of up to $2 billion in the last year, with a $1 billion capacity and credit facility, and I would expect they'd access to market for the remainder of the equity. The real power of this, as you well know, is that basically the partners, Spectra and Phillips 66 through its ownership of DCP, will fund about 1/3 of it. DPM will fund about 2/3 of this and yet the partners will realize about 50% of the earnings and cash flow, all of which will come back in increased distributions to the parents. So I'm pretty excited about that. I think that's the right way to do it for DCP. And I think that'll allow DPM to be able to manage that. You're going to use the cheapest cost of debt i.e. at DCP, and at least at this point in time, a cheaper cost of equity at DPM to be able to move those fee-based projects over.

Your next question comes from the line of Ted Durbin with Goldman Sachs.

Just a follow up on Stephen's question there. I guess you are getting a lot bigger in terms of spending profile at DCP. Would you -- if you continue to expand, would you consider not taking distributions back for a limited amount of time just to make sure that DCP Midstream can actually fund all the growth CapEx? And part of what I'm thinking is you continue to nail up all these new pipeline projects, maybe you want to expand further into say storage, fractionation, et cetera. I'm just wondering what the capital constraints are in DCP, and if you'd be willing to give them a break.

Well, I mean look, I would suggest that the partners are going to do whatever's in the long-term economic best interest. At this point in time, we don't see the need for that. But if -- as you know, the pipes that we're building now, we're going to quadruple the volumes on NGL side that we'll be able to move. That's going to generate cash obviously. Some of which already does stay with the business. But, yes, it'd be open to that. But at this point in time, I think with the 2/3 funding come from DPM and 1/3 from DCP, it should be manageable. But, if it quadrupled again in terms of the amount of CapEx, then that's something we'd obviously have a discussion that make economic sense. I would think that's interest in all the shareholders, both 66 and SE, but also in just SE shareholders directly.

And, Ted. We've modeled this in pretty good detail even for our 5-year plan at the partnership. And it's really reflecting the fact that it's a combination of dropdowns and co-investment and that construction takes place, like on the pipelines, over multiple years. So it does look like it fits pretty nicely with DPM's ability to issue equity in reasonable tranches. And even for things like potential fractionation investments in the future, as Greg said, we just haven't faced that yet.

Okay. And then next, just any update you can give us on the New Jersey-New York project, when you're expecting approval from FERC. Still feeling good about sort of $1.1 billion cost estimate there?

Yes. Absolutely. When we put our $1 billion to $1.2 billion, we feel good about that. I would expect that we'll get the FERC approval. And I am reading tea leaves a little bit but I feel pretty good about getting that this month and then moving on to construction in the summer. As you know, they -- their schedules -- they meet typically monthly. And so [indiscernible] I would expect that, which getting into construction here, this summer is obviously going to be important for us to hit our November 23 time frame, but we're all lined up from contractors, from equipment, from what we can do on the land side prior to getting a FERC approval. So I feel good about where we are, Ted, and believe we will get that in on the cost estimates that we've provided you.

Okay, that's great. And then last one for me. I don't know how much you can comment, but there is a large -- call it a large package of natural gas pipeline assets that are out there in the market. I'm just wondering how you'd see those as a potential set with your asset base.

Yes, I'm not going to comment about that a ton other than to say that anything -- there are various assets out there that come on the market every so often. We have a very strong balance sheet. The balance sheet just continues to get stronger, we have great liquidity, good cash flow. We obviously have SEP and we have DPM, and I don't think there's any doubt that we could pounce very quickly if we found something that we've thought, a, made good strategic sense, and b, we could do from an economic perspective. So I would leave it right there.

Your next question comes from the line of Matthew Akman with Scotiabank.

Have you looked at the possibility of an institutional-type share for the MLP? Or is Spectra broadly looking at that in order to gain more access, wider access to capital markets as DCP's business accelerates?

That's not something that we've actively pursued at this point. We haven't really seen any governor or limiter on receptivity or market interest in DPM shares. Obviously, as we get bigger and they issue upwards $1 billion a year of equity, we'll consider all facets. But that's not something that we've needed to look at yet.

Okay. Guys, still on that segment, obviously the business is taking advantage of its ability to capture growing NGL volumes or pipeline and other infrastructure and moving more into the NGL area than gas in the U.S. In Canada, it's less so and it's more on gas processing, but there is a lot going on in Canada, also in NGL infrastructure. Have you guys looked more at taking that U.S. business model that's more -- getting more focused on NGL and for growth and kind of transporting it to Canada? Or can you see yourselves as getting more aggressive in Canada on NGL infrastructure?

Absolutely. I mean, as you know, we have -- we're currently completing $1.5 billion spend in Canada, in both processing and on the pipeline side. But there's no doubt as you move in the -- down from the Horn River into the Montney regions, Duvernay, et cetera, there's some good opportunities, we think, there on the NGL side providing infrastructure solutions. Yes, it's a challenging market there with the gas price at AECO. But we are definitely looking at those opportunities and think that those could come to fruition here over the next 12 months. As you know, a lot of producers are trying to figure out exactly what their next move is in Canada, but we're throwing ideas against the wall as to what could be the next phase of growth.

Just my last follow-up, I mean with Plains buying BP, and Pembina merging with Provident, I mean just, is Spectra thinking about doing maybe something bigger, more dramatic in Canada? Or just kind of incremental bolt-on to the more gas processing business?

Yes. I wouldn't say -- there's 2 answers to that. No, with respect to going bigger on the Empress-type business. As you know, that's a relatively small part of our business. But yes, definitely on the NGL infrastructure side. And of course, we're pursuing hard the opportunities both upstream vis-à-vis fee-based GNP and pipeline associated with LNG on the West Coast. I mean, those investments could be extremely large, as you know, the pipelines that could get built. And I think it's still a couple of years away before people decide pipelines could get built for LNG. It could be anywhere from $4 billion to $10 billion.

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

It's Faisel from CitI. On the U.S. transmission, you guys talked about I think lower interruptible transportation revenues. Is that just weather? Or was there something else going on in the quarter?

No, just weather. And it's really that we did really well on that front last year. It was a cold year last year. When I say last year, 2011 winter. And so, with much warmer weather, the opportunity to capture the interruptible, that was really the delta that was out there. Pretty unusual that you'd see that much of a swing in weather from year-to-year.

Okay, got you. Yes, I guess if it's a -- the warmest winter in 100 years, I guess we'll see that. Okay, and just on the Conway issue, do you guys -- have you guys calculated the opportunity cost that's kind of been loss by you're not being able to get your barrels further south?

Yes, painfully so. Yes, we have, Faisel. I mean -- and I think where you're going is, "So, what is that front number?" I don't think I'd put that out there right now. I mean, part of it's a bit of a mug scheme as to how much more in volumes, how much of the decline or closing of the gap you will see. But I mean, in some respects, you can look at what we produced, call it a couple of hundred thousand barrels that are kind of associated with Conway, and if you thought you had a $0.30 delta today, and that that will help close it, I mean, you could pick a point in between I guess and come up with a number and make your own judgment as to how much that's going to move. If you don't think it will move at all -- and if I look at it, 2016, '17 and see all the crackers that could be -- that could kick in, maybe it's not going to move as much as people think it is. And that's further upside for us.

Okay, got you. And then just -- since we've seen another transaction in an MLP and SE Corp. space, I just want to ask the question again -- I know I've asked you this before, but would you guys do anything within the current company in terms of moving some of your SE Corp. assets into the MLP and doing some sort of transaction like that? Or is there any benefit for you to even doing something like that?

Well, I think the real benefit is at DCP. And that's where, as I mentioned earlier, that's where you're really see us making that move. It's -- sure, I mean, it's an option, I guess at SE, but -- directly, but we don't see those assets -- I mean, we've moved a lot of the good assets into there at this point in time. Remember, we have a large bulk of assets in Canada, so it's not very tax efficient from that perspective in terms of moving cash back and forth to cross the border into an MLP. And then lastly, obviously, you got very low tax spaces in the assets we have remaining. As we build new assets in many of these other projects, that's definitely something we'll look at. And if we see value upside, then we'd go down that route.

Your next question comes from the line of Curt Launer with Deutsche Bank.

Just wanted to ask for some additional information with what you can tell us relative to Western Canada transmission and processing. It sits at about 20% of the overall earnings now. And the upside in Horn River and Montney seems a little bit more clear relative to what's happening with the development of Cabin Gas, but also was offset by the Empress business, which continues to be troubled. So the magnitude of those things now that you're not reporting Empress separately is what I'd like to get a little bit more information about if we could.

Sure. Well, you know in the expansion, and I think you'll continue to see this growth, $30 million of new expansion EBIT that came in in the quarter versus a year ago, and we'll continue to see that rise through -- as the projects come online, but that's a pretty healthy side. No doubt, as you pointed out, we'd probably gave up about that much or a little bit more at Empress but that has a limited downside, if you will. So I think you'll continue to see those type of increases quarter-over-quarter on the expansion side and you won't see that type of decline obviously at Empress. Even -- last year at full max, the full year last year was around $100 million at Empress. So that's your order of magnitude if -- I guess, if you wanted to be ultimately negative.

Right. Well, the ultimate negative is sort of sounding like where we are now. So the next follow-up then becomes what would it take for Empress to get anywhere near better here?

Well, I think, 2 things. Obviously, more volumes out of Western Canada would be helpful. But remember, one of the biggest -- there are 2 things. There -- so that's an extraction premium issue on volumes. So that's about half the impact, but the other half is just low propane prices, Curt. So, obviously again, with the 100-year warm weather, you're going to have extremely low propane prices and that would have been about half of the impact from a negative perspective we saw this quarter over the last first quarter. And so I would expect those propane prices, as you move back to normal weather to come back online.

And your next question comes from the line of Carl Kirst with BMO Capital Markets.

Actually, I think -- well, maybe 2 clean-up questions if I could on Union. The first is just if you could just refresh my memory with the 5-year settlement kind of concluding this year. What's the time frame of when we should be reaching something new with the Ontario regulators?

Well, I believe we just filed or we're just in the process of filing for next year. So you set a new base year, and we'd expect that to be settled obviously before you get into next year. And then, after that base year, so it'd be another year out before you -- if you go down the route of another 5-year rate deal. So you got 1 year setting base rates, which I wouldn't -- we'll have to see how all that shakes up. But I think we've seen a good benefit for consumers as well as shareholders. So I'd hope we'd stick in the same range. But it's another year out before we determine if you're in a 5-year rate deal or something longer or something shorter.

Okay, I appreciate that and then...

Carl, this is Pat. The key thing we're going take in '13 and then for the 5 years and beyond in terms of preserving the incentives that we have in the existing 5-year structure, they're trying to thicken our equity compounded [ph] of capital structure and increase our return on equity more in line with NEB standards.

No, fair enough. And then just also on Union and just trying to kind of get a better sense of -- if you could quantify perhaps the weather impact given how historically warm it was. Only because since we were colder than normal last year, the EBIT shift isn't -- favorably not as bad as we thought it would be. And so, I didn't know if there was anything else. I mean, you cited sort of lower fuel cost, but I didn't know if there was anything else in Transmission or storage that was cushioning it that was sort of basically increasing that base business, shall we say.

Yes. The weather impact, you're right. It was warm. I'm always saying that if you'd a 100-year warmer weather, you'd be plus or minus 10% and I think -- well, obviously minus in that regard, and that's about where we were. So you're about to $25 million down from a weather perspective versus the year earlier. And then, that was partially offset -- you benefited, $6 million to $8 million from [indiscernible] so obviously by now pushing as much gas through. So the net of those, call it $17 million, $20 million kind of impact.

And your next question comes from the line of Chris Sighinolfi from UBS.

Greg, I'm just curious. You mentioned earlier in your commentary about a recent trip to Asia, and we've been talking about the Western Canadian LNG export opportunity for some time. I guess I'm curious, we've seen a couple of facilities up there permitted by the NEB and the federal government and I think you had a trade mission back in the fall. So as the discussions become more mature, are you able to tell me a little bit more of that sort of how they're progressing, and the sorts of issues that are now being in focus as sort of discussions become more mature?

Sure. I think there's a couple of factors. One -- and when we go over there, we see everybody from the trade houses to utilities, and this is the first trip that I personally had been on, and also, investors, frankly. And the issues are probably threefold. So first of all, just -- they want to know who the pipeline potential carriers are, us and others, the size of the pie, if you will, right down to kind of drawing pictures on maps, if you will, and how much that would cost. Two, they want to know our views and share their own views on what you think the pricing mechanism is. Is it typical JCC, or is it going to be something off NYMEX? Similar kind of discussions you would see in the Gulf. And then lastly, and this is an important one, and it's a political risk issue. Can you get projects permitted in a time that makes it relevant to the market? And so, on that regard it seems like both the B.C. government is very supportive of multiple corridors whether it's Prince Rupert or other sites like Kitimat. And it seems like the federal government is trying, in Canada, is trying to accelerate the whole regulatory review process for that. So that's the nature of the 3 discussions. And of course, obviously, we also talked about our position in the Gulf and our ability to build header systems into any and all the LNG facilities there, and storage. And so, that's the general nature of the discussion. As I've said, I think it's still a couple of years away before FID is made on many of these projects. And so people are really in a due diligence mode, both from provider of services, macroeconomic sides and whether you can actually get things built.

Okay, that's very helpful. I guess given the fact that you can speak about this issue from both a U.S. and a Canadian perspective, when you're over there, can you give me a sense, if at all, if there's a sort of an inclination that the Canadian government would be more favorable or work faster than the U.S. government or vice versa? Or is it too early to say?

Well, I guess what I'd say, they're more concerned about political risks in the United States than they are in Canada. But there's no doubt they understand it's bigger built in Canada than it is in the U.S. So I don't think it means one way or the other for different reasons there. And you can see the various players in both British Columbia or Western -- North -- West Coast of North America and the Gulf. They're often the similar players. So you see a lot of hedging of bets at this point in time.

Okay, great. And I just want to follow-up very quickly on Greg's question earlier about Empress. We spoke, I think around fourth quarter, about your cautious optimism about sort of holding a line on some of these extraction premiums. Obviously, Greg, you mentioned the broken situation up there in the first quarter. I think you guys have had formerly around $100 million in EBIT in the guidance. Do you have any updated thoughts on where that might shake out or things that you might do? Is there any -- I guess my curiosity question. Is there anything you can do just to help mitigate those extraction premiums, or is it just a volume situation?

Well, I think it's a volume situation. There's not a ton that we can do to make it the extraction premiums. I think the biggest thing is you have propane prices coming back vis-à-vis kind of improved weather and fundamentals on that side. Trying to do a few more things for customers may help. But if I was looking at it now, I'd kind of more be in the kind of $40 million range, probably $30 million to $40 million range for Empress today. But again, that depends on if we get back to a normal overall year weather, that means you could see a very cold start to the winter in the fourth quarter, and then that number is going to be low. So we often -- I know I often say this, but we really do often forget what a major impact weather does have across the entire value chain. And so I'll have to see how that shakes out. But hopefully that gives you a little bit better color on it.

Okay. You do have a question from the line of Jonathan LeFebvre with Kensico Capital.

Greg, it's Jonathan LeFebvre of Kensico. Just wanted to focus for a moment on your MLP strategy that you discussed with Faisal as it relates to the U.S. Transmission assets and SEP. Over the last few years, we've seen guys like Williams, Kinder target at ONEOK, all shift to this GP, hold co [ph] strategy, which has unlocked a lot of value for them. And so I guess my question is, have you looked at or have you considered utilizing tax efficient 1031 exchange of your U.S. Transmission assets for SEP units with the idea that you could remove the growth CapEx off the parent's balance sheet and therefore, significantly increase the dividend and dividend growth rate at Spectra Corp., which is obviously a key value driver for a lot of your shareholders. So I guess I'm just curious have you' looked at it and if you have, what are the key impediments with utilizing this strategy? Because clearly on paper, it appears to unlock a lot of value.

I think it's a couple of things. One, the big Canadian side of things, which is an important piece -- so if you don't want to leave an orphan piece -- today, we've looked at it, seeing it from a hybrid perspective where we've got SEP, we've got DCP. I think the biggest value increment is actually on the DCP, DPM side of things. Yes -- but there's no doubt -- look, I mean, we always look at these things. If we thought there was a big value piece in there, that would be something that we'd look closer at. I think the very low tax base of side of things, there's no doubt you could take back some units, but that's not going to do much from a cash perspective. And we think, as we've said, we can grow the dividend at a very healthy rate in the C corp-type structure, where it gives us the balance of being able to utilize what would be a cheaper cost of debt at the corporate side of things while still being able to use SEP equity on the growth side. I mean, when you've seen us with assets such as Gulfstream and other singular assets, if you will, with higher basis, those been opportunities to drop in and we'll look at continuing to do those. And then the other issue I will say in the next year, that is at least something that I think one has to consider is the whole issue of tax reform. And that's something that we're watching cautiously. We've seen that happen in Canada where we had an MLP structure and then we saw corporate changes on that front that hurt the tax side of things. So for now, the focus is really at DCP and moving those assets which will benefit us obviously into DPM. And they're building very large new pipelines on that front.

Right. I guess my -- just as a follow-up, if I may. You talk about tax reform. I mean, I guess there's a risk as well that if you don't move these assets and they're left at the parent, you could be at a competitive disadvantage relative to the peers who already have moved and could potentially be grandfathered in that scenario as well. I'm just wondering how the board thinks about that risk.

We haven't seen ourselves in a competitive disadvantage at this point, that's for sure. Remember, a lot of other MLP structures were put in place and things -- a lot of it because they have a lot of -- they hadn't separated out businesses like E&P, et cetera. We haven't had that challenge. We separated in 2007 from Duke, and hadn't seen that. I mean, look, our history on MLPs is pretty clear. We've had a great history on MLPs. We do like to use them. We just today have not seen the value increment, again, given the DCP side of things from a commodity perspective and given that 40% of our assets are in Canada. But obviously, all structures are on the table and we look at that and if we thought that was the right way to go, that's something we'd definitely look at closely.

And your next question comes from the line of Yves Siegel with Credit Suisse.

Just a couple of quick ones. Qualitatively, could you just discuss what the impact of the low gas prices has been?

Sure. Well obviously, the biggest impact has been at DCP Midstream. And the gas prices are about $1.25 lower. Do we have a...

We averaged $2.74 in the first quarter of this year versus $4.11 last year. And then of course, we provide the sensitivity for natural gas but as Greg said earlier, the primary impact there is on the NGL gallons. That's the biggest mover at DCP. Ironically, of course, lower gas prices qualitatively can help Transmission and Distribution as long as we have decent weather. You probably saw the article in the Wall Street Journal earlier in the week about how dramatically power generators have shifted to natural gas and away from coal in the last just few months and that's the trend that continues to accelerate. So there is some upside of lower and stable gas prices for us.

Okay. And then if I could, when you think about the CapEx budget for this year, the timing of sanctioning any of the projects that you have is potential. Will that -- could that impact spending this year? Or is that going to more be pushed into the next year?

It's pretty small. I mean you could push some of it into the next year. But you know, I don't expect that to be a significant mover of cash flow or utilization during the year, Yves.

Okay. And then my last question too is just all the questions about -- around how you're going to finance growth and restructuring and all that stuff. It would seem to me that really, a return on capital and cost of capital are the -- sort of the important drivers here. And when you think about acquisitions and you think about the return that you're getting on your projects, can you sort of put that into context as it relates to 10% to 11% type of rosy target? How that compares to what you're thinking about on the MLP and then how that might impact your thinking about acquisitions.

Yes, absolutely. Well obviously, again, when we look at DPM or SEP, I think you've seen us use the SEP or DPM equity to go out there and finance acquisitions. But we view C corp debt, which is obviously cheaper because you've got the tax shelter there. We've continued to target 10% to 12% returns in the last 3 years. You've seen us actually being above 14% type returns. DCP would even see higher teen returns in the activities that they've got going. So I think the hybrid model, as we look at it being able to use both C corps when that's the cheapest form of capital and MLPs when that's the cheapest form of capital, actually, it works well for our shareholders. And it works well for our unitholders at our MLPs. You've us do drops on occasion, you've seen -- both at SEP and at DPM and you've seen us do acquisitions there. So I think it's that hybrid model that we see that allows us to get the best return overall for both the unitholders and shareholders, whether it's common or it's LP unitholders.

[Operator Instructions]

I think we'll just go ahead -- and our hour is about up, so why don't we go ahead and end the call today if there are no more questions. Thanks very much, for joining us today. I appreciate it very much. And as always, if you have additional questions, feel free to call either Roni Cappadonna or me. And I'll just look forward to seeing many of you out at the AGA conference early next week. Thanks, very much.

This does conclude today's conference. You may now disconnect.