Sea Limited (SE) Q4 2012 Earnings Report, Transcript and Summary

Good morning. My name is Suzette, and I will be your conference operator today. At this time, I would like to welcome everyone to the Spectra Energy Quarterly Earnings Call. [Operator Instructions] Thank you. I will now turn the call over to Mr. John Arensdorf. Please go ahead, Sir.

Thank you, Suzette, and good morning, everyone. Thanks for joining us today. We were with many of you recently in New York, providing an overview of our 2013 business and financial plans, and we're here this morning to share our 2012 fourth quarter and year-end results. Since we had an in-depth conversation with you just a few weeks ago, we're going to switch things up a little bit today, and Pat Reddy, our Chief Financial Officer, will start us off with a look at our fourth quarter and year-end financial results. And then Greg Ebel, our President and CEO, will talk to you about our outlook for 2013 and beyond. But before we get started, I need to remind you that some of what we'll discuss today concerning future company performance will be forward-looking information within the meanings of the securities laws. Actual results may materially differ from those discussed in these forward-looking statements. And you should refer to the additional information contained in Spectra Energy's Form 10-K and other filings made with the SEC concerning factors that could cause those results to differ from those contemplated in today's discussion. In addition, today's discussion will include certain non-GAAP financial measures as defined under SEC Regulation G. A reconciliation of those measures to the most directly comparable GAAP measures is available on our website at spectraenergy.com. With that, let me now turn things over to Pat.

Well thank you, John, and good morning, everyone. We appreciate you joining us today as we report on our fourth quarter results and our 2012 performance. As you've seen in this morning's release, Spectra Energy announced $0.32 in earnings per share and $213 million in ongoing earnings for the fourth quarter of 2012 compared with $0.44 and $287 million in the 2011 quarter. For the year, we delivered ongoing earnings of $1.43 per share or $938 million. Our original 2012 EPS target was $1.90 and reflected commodity prices consistent with the then forward outlook. While our fee-based businesses performed as expected, weak commodity prices dampened our overall results. The commodity challenges were most pronounced at our DCP and Empress businesses and reduced our expected earnings by $0.52 a share for the year. In addition, as you recall, an unfavorable decision rendered by the Ontario Energy Board late in the year affected earnings by about $0.03 a share. This slide is an overview of fourth quarter EBIT for our 4 reporting segments and Other, which houses our corporate cost. U.S. Transmission reported EBIT of $249 million compared with $226 million in 2011. EBIT results reflect increased earnings from expansions and lower operating costs, particularly -- partially offset by lower processing revenues and as anticipated, lower storage revenues. Year-end EBIT for this segment was $995 million, compared with $983 million in 2011. Distribution reported fourth quarter EBIT of $93 million compared with $120 million in 2011. As I've already mentioned, the decrease is primarily due to an unexpected retroactive decision from the Ontario Energy Board in November 2012, in which it ruled that certain revenues realized from the optimization of upstream transportation contracts must be refunded to customers. While we've appealed this decision, we did take a $30 million charge for it in our fourth quarter. Year-end EBIT for this segment was $374 million, compared with $425 million in 2011. Our Western Canada business reported fourth quarter EBIT of $72 million, compared with $137 million in 2011. This segment experienced lower earnings in Empress, which realized a $17 million loss for the quarter, primarily attributable to the effects of unusually low propane prices. As expected, an increase in Gathering & Processing revenue from expansions in the Horn River and the Montney areas of British Columbia were more than offset in the quarter by a decrease in revenue from the segment's conventional G&P areas where low gas prices have deterred production. Year-end EBIT for Western Canada was $387 million, compared with $510 million in 2011. Field Services, our 50-50 joint venture with Phillips 66, reported fourth quarter EBIT of $58 million, compared with $96 million in 2011. This decrease was mainly driven by lower natural gas liquids prices, which were down 36% quarter-over-quarter. The decrease was partially offset by lower depreciation expense and improved production mix as DCP Midstream increased its NGL production in liquids-rich basins. Overall, this quarter's NGL volumes remain flat compared with fourth quarter of 2011, but volumes are up 5% for the year, and we expect that trend to improve. During the fourth quarters of 2012 and 2011, respectively, NGL prices averaged $0.77 per gallon versus $1.20, NYMEX natural gas averaged $3.40 versus $3.55, and crude oil averaged $88 per barrel versus $94. Year-end EBIT for Field Services was $279 million, compared with $449 million in 2011. DCP Midstream paid cash distributions of $203 million to Spectra Energy during 2012. Other, which is comprised primarily of our corporate governance costs and captive insurance program cost, reported net cost of $29 million in the fourth quarter compared with ongoing net cost of $28 million in 2011. This next slide outlines certain other items affecting our earnings per share. Interest expense during the quarter was $154 million, unchanged from the fourth quarter of 2011. Fourth quarter income tax expense from continuing operations was $81 million compared to $115 million reported in the 2011 quarter. The lower tax expense was driven by lower earnings and a lower Canadian tax rate, partially offset by favorable tax adjustments recorded in 2011. This resulted in an effective tax rate for controlling interest of 27.6% as compared with 28.6% in 2011. At the end of the quarter, our debt-to-total-capitalization ratio stood at 56%, unchanged from a year ago. And as you can see, we have ample liquidity to carry out our business activities. When we were with you in New York 3 weeks ago, we said we would reconcile our 2012 results with our 2013 plan. This next slide presents that reconciliation. We begin with our actual 2012 ongoing net income of $938 million, which supports our $1.43 earnings per share, and compare that with our 2013 projected net income of $984 million or $1.50 per share. You can see that the ongoing successful execution of our Spectra Energy expansion program will be our largest contributor to earnings growth, accounting for about $70 million of expected incremental EBIT before associated interest expense. The $30 million increase shown for DCP Midstream is attributable mainly to earnings from expansion projects partially offset by interest expense. In Western Canada, there are 2 primary factors leading to the net $10 million decrease shown here. First, as we've mentioned previously, low natural gas prices in Western Canada are driving reductions in SET West conventional G&P business. The current low gas price environment, including a few days in 2012 below $2, have led producers to scale back. Once AECO prices strengthen, we expect producers to renew their G&P contracts with us or to use more interruptible services and we'll see a rebound in revenues. Second, we experienced a $49 million loss at Empress in 2012. And as we've said, we expect Empress to break even in 2013. There are many components in our miscellaneous EBIT category with one of the most significant items relating to the loss of about $20 million in EBIT at U.S. Transmission from the recent drop-down of our interest in Maritimes & Northeast U.S. to Spectra Energy Partners. In addition, lower storage revenues resulted in a reduction of about $20 million at U.S. Transmission. The increased interest expense shown here relates to our borrowing requirements for funding our growth. And finally, the primary drivers for the approximate $35 million increase to earnings from taxes relate to a $12 million benefit from higher 2013 tax depreciation on our regulated expansion investment in Canada and a $19 million tax reserve release in 2013 due to anticipated passage of favorable tax legislation in Canada this year. During our January meeting, we laid out the 2013 earnings expectations for Spectra Energy's business segments. We heard from many of you that it was difficult to see the incremental earnings from our cumulative investment in expansions and acquisitions at U.S. Transmission. This slide is intended to help you understand the various dynamics around U.S. Transmission's EBIT growth. Since 2007, we've invested about $4 billion in expansions and acquisitions at this segment. If you were to assume a return on capital employed of about 11%, which is in the middle of our targeted 10% to 12% range, you would see an increase of about $440 million over and above our 2007 EBIT of $894 million, all else being equal. However, we're expecting 2013 EBIT at U.S. Transmission to be almost $150 million more than it was in 2007. The approximate $300 million difference is due to 3 key developments. First and most significant are the effects of the changing storage environment. Our 2013 plan has storage EBIT at about $100 million less than one might expect given the lower margins and the lack of seasonal volatility, which have dampened returns from our storage expansions. It's worth noting that at the time we acquired the Bobcat Storage Development, we told you we were investing for 2015 and beyond. And while storage margins remain soft in the near term, we're confident that those margins will improve, especially as PowerGen conversions, LNG exports and industrial demand continue to ramp up along the Gulf Coast and in the Southeast U.S. markets during the mid to latter part of the decade. When robust demand for storage returns, we will be the premier provider of high deliverability storage on the Gulf Coast. We've also experienced about a $90 million reduction in processing revenues compared with 2007. Hurricanes Katrina and Rita on the Gulf Coast damaged many of the third-party processing plants in the region. We were able to utilize our contracted processing capacity during this time period to process significant volumes for others at higher commodity prices. And that resulted in a temporary boost to our processing revenues. Our processing EBIT for our 2013 to 2015 plan is in the $60 million to $65 million per year range, which we view as a more sustainable run rate. Additionally, Spectra Energy formed Spectra Energy Partners in mid-2007, with a significant drop of assets, including 100% of East Tennessee, 50% of Market Hub Partners and 49% of our interest in Gulfstream. We subsequently dropped another 49% of our interest in Gulfstream and 50% of our interest in Maritimes & Northeast U.S. These asset drop-downs from U.S. Transmission to SEP have resulted in a reduction of EBIT at U.S. Transmission since part of the EBIT now goes to noncontrolling interest at SEP. The change in noncontrolling interest between 2007 and our 2013 estimate is about $70 million. While these drops have lowered the EBIT at U.S. Transmission, they've been beneficial to shareholders as they have provided cash that has been redeployed in our growth investments and to support our growing dividends. In addition to the major elements that I've just described, there are a variety of other less material factors affecting earnings growth over this time frame. For example, you may recall that the way we treated project development costs in 2007 resulted in about $25 million of additional earnings that year that are not included in 2013. And, as you would expect, we've had some minor increases in O&M over this 6-year period as well. While you can never say with certainty that we're experiencing a low point in storage margins or that processing revenues cannot decline further, we believe that the most significant decline should be behind us. So we are delivering earnings at or above the returns we expected on our pipeline expansion projects. And those healthy returns give us confidence in our ability to deliver on the more than $25 billion in growth projects that we see over the rest of the decade and deliver significant returns in dividend growth to investors. Now let me turn things over to Greg, who will update you on our outlook for 2013 and beyond.

Well, thanks very much, Pat, and good morning everybody. It was good to see so many of you in New York recently and look forward to chatting with you on the conference circuit in the next few days and weeks. As you heard in New York, we're excited about the array of growth opportunities ahead for the company, and we're hard at work delivering on our priorities for 2013 and beyond. Since we outlined those for you in pretty good detail just a few weeks ago, I'll focus on some noteworthy highlights, and then we'll get to your questions. Starting with the power of the portfolio. This map you've seen in the last 6 years, and it's grown substantially since we've been talking to you, I think gives you a really good sense of the scale and scope of our asset position that's growing. Our expansion portfolio provides us with really a great foundation, which continues to grow as we expand our market reach. Our assets continue to connect the major producing basins in both the United States and Canada with the growing demand markets in North America, and they interconnect with substantially all the other major pipelines in North America. These dynamics and our ability to serve our customers' supply and demand needs affirm the value of our assets over the long run. Separately and importantly, DCP Midstream enjoys premier positions in substantially all of the major U.S. basins being actively developed. DCP Midstream will place more than $3 billion of projects into service over the next 12 months alone. And given the magnitude of these opportunities, DCP has raised its growth capital investment outlook to $6 billion through 2015, allowing it to grow volumes and earnings nicely. We have a great portfolio mix, and as you've seen, we're able to use the sum of our business lines to navigate successfully through market cycles and overcome any headwinds. Equally exciting, we're expanding our footprint on this map into the growing crude oil pipeline sector with the addition of the Express-Platte system, which we believe will be a great acquisition from day 1. We expect to close on the acquisition during the first half of this year, and expect it to be immediately accretive to earnings, with expected full year 2014 EBITDA of approximately $145 million, and 2014 EPS accretion in the $0.03 to $0.05 per share range. This slide here gives you a snapshot of the momentum occurring across our system, momentum driven by more than $25 billion in growth opportunities through the end of the decade. We're confident that it will execute on a significant number of these, and we're not stopping there, of course. Between now and the decade's close, we expect to identify and pursue a host of new opportunities that haven't even made this map yet. We discussed our major projects in New York, so I won't go through each again, but rather reiterate where the growth is coming from and how we're moving forward. In U.S. Transmission, we anticipate more than $10 billion of investment in this segment. Our Northeast projects move Marcellus and Utica supply to the region's high-growth markets and include our New Jersey - New York expansion, TEAM 2014, OPEN, AIM and NEXUS. Growth in the Southeast continues to be driven by huge increases in incremental gas-fired generation over the next few years. Examples of our response to that demand can be seen in the expansion of East Tennessee's pipeline to serve Eastman Chemical, our Renaissance project, which will link prolific supplies on Texas Eastern to growing power generation and distribution markets in Georgia, Alabama and Tennessee, and our pending response to the Florida Power & Light proposal to build a third major natural gas pipeline into Florida by 2017. Gulf Coast demand, which we estimate at 10-plus Bcf a day is being driven by multiple market segments, both domestic and international, including LNG exports, gas liquids facilities, power generation, the industrial and petrochemical research, and of course, exports to Mexico as well. Our Western Canadian business has $7 billion of expansion growth on their horizon. SET West sits in the midst of 4 world-class gas resources: the Horn River, the Montney, the Cordova and the Liard. The growing gas supply environment in Western Canada is attracting significant international investment, with total investment in British Columbia natural gas sector alone projected to reach $250 billion over the next 20 years. Much of that investment likely will be directed towards the development of LNG terminals and pipelines to serve those. And we're excited to be a participant in this market. Our participation with the BG Group to construct a major pipeline connecting our northern transmission systems to BG Group's LNG terminal to be located at Prince Rupert will drive significant opportunities for capital growth. LNG players like BG and others will stimulate significant E&P development in the coming years, and that will require incremental Gathering & Processing services. As Spectra Energy is the service provider for 60% of the G&P market in British Columbia today, we're confident we can capture a significant portion of this additional G&P activity. So as you can see, our business plan remains solidly on track. We're expanding our impressive portfolio of assets, and we're continuing to demonstrate our commitment and capacity on all fronts through various commodity and business cycles, rewarding investors with steady, reliable dividend growth and accentuating our value proposition with the use of our MLPs and our C corp. Today, we've got a strong and growing base of assets on the natural gas side of the business. To that base, we're adding investments in NGL pipelines and a new crude oil segment. Combined, we see an attractive investment opportunities landscape of at least $25 billion through the end of the decade. And this growth builds on our record of being an early mover in high-growth market cycles and creates significant upside potential for Spectra Energy and our investors. These growth platforms with assets like Express-Platte, Sand Hills and Southern Hills create a catalyst for further advancement of our NLP strategy and enhance our general partner position. We see significant potential to increase shareholder value through the strategic use of our MLPs to further grow the Spectra Energy asset portfolio. As we stated before, both SEP and DPM are key components of the overall financial strength and flexibility of the company. Our corporate structure with a strong parent and GP position allows us to grow strategically by using the lowest cost of capital and the most efficient vehicle from a tax perspective for accretive acquisitions in addition to generating cash to reinvest in our asset platforms. This ongoing cycle of cash generation and reinvestment enables us to continue to grow our dividend and deliver attractive shareholder returns over the long run. With that, I'll turn things back over to John and we can take your questions.

Okay. Suzette, we're ready for questions from those joining us today.

[Operator Instructions] Your first question comes from Ted Durbin with Goldman Sachs.

I just want to start here with Western Canada. Volumes were down pretty significantly on the pipelines on the processing. I'm wondering if you can just give us some more detail on what you're seeing on the conventional declines. I mean, obviously, you've put some capital in there, but you're still seeing volumes down. How are you seeing that shape up for 2013? And then as well there, you've talked in the past about maybe getting some solutions for Empress. Maybe you can talk about what solutions that might be. Maybe with capacity rationalization amongst the industry, any progress there?

Sure. So I think as Pat mentioned, we see really -- the impact from the conventional side of things in Western Canada for 2013 is about $50 million, $55 million. Now you obviously have got growth in the unconventional side, which is helping to offset some of that. But we'll have to see how things develop in '14. There's always some risk that you could continue to see some of that. But different than on the U.S. side, where often you see G&P natural declines, that's not what's happening in Western Canada; it's pure commodity response. So with gas now, I think AECO is running around $3, maybe $3.10, and much closer to what you'd see on NYMEX, running $3, $3.35. A more traditional kind of 10% spread. You should see some of that drilling come back. And in fact, a lot of that might be on the interruptible side. On the pipeline side, I wouldn't -- that's not terribly concerning to me. As you know, same as on the U.S. side that that's a fee-based business and contracted up, so less concern. With respect to Empress, couple of things. Everything's on the table, Ted, in terms of looking at Empress, you're right, there's too much capacity up there, so is there a way to appropriately rationalize the overall asset base up there amongst all the various players, that's something we're looking at. As we've said before, Empress is not a particularly strategic item for Spectra Energy. And then lastly, obviously, a different contract makeup this year. I think as we shared with you last year, we had a pretty large buildup of contacts that ended up being out of the money, if you will, last year, and those have run off substantially. And so we don't see the same type of impact. Things like write-downs, which I think ran around $15 million last year, we don't have that. So I feel pretty good about our ability to claw our way back on Empress this year. But everything's on the table from a rationalization perspective.

Got it. And if I could just -- on the extraction premiums, what actually was baked into the budget there as well as what propane prices do you have in there to get you back to breakeven?

Yes. Well, the propane prices aren't much different from what we see in the rest of the company, so think about that 80% type range. Extraction premiums, don't budget on that basis because the extraction premium is only one element of this and it moves up and down. But you really got the impact of what's the price of the gas and the output on that front. So it's a little different than what you might see elsewhere, that's why we didn't give an extraction appraisal last year. What I will say, though, is the extraction premiums have come down substantially from what we saw in 2012, Ted. So you're seeing a fair bit more rationalization in itself, if you will, about what deals make sense for people as to people expecting it -- as opposed to people expecting that NGL prices just go up forever.

Right. Got it. And then last one for me is over on Field Services, we also saw some declines in the Gathering & Processing volumes sequentially year-over-year. You've been bringing up some new processing types. I guess, what are you seeing there? Is it just declines on the conventional production? Is it ethane rejection? Maybe a little bit more color there.

Yes, pretty flat. Ethane rejection ran around 15,000 barrels a day last year. We're actually seeing, if you look on the -- volumes will be up this year and NGL volumes will be up 10% or so, that's what we're seeing. You're right, driven by both some new facilities coming on service, but also just the growth in the sector. I think we're pretty flat on throughput last year. I think maybe you're right, Ted, 2% or 3% that was down. But the NGL production in 2012 was up 5%. As I said, you're probably going to see double that in 2013.

Your next question comes from Faisel Khan with Citi.

I appreciate the details on Slide 7. I was wondering if you could help explain a couple of things. The storage decline from '07 to '13, the $100 million, roughly, that's not all Bobcat, is it? And what other parts of the portfolio is that coming from?

Well, let me be clear. That's not really a decline. All we're saying is that relative to the capital we put to work, you might have expected, so I would say that's a loss in opportunity cost, really, Faisel. So I wouldn't look at it from a decline. As you know, the overall EBIT for the business, storage represents 5% or 6% of our overall EBIT. So that's not a decline from where we were. So yes, that's a good point.

Okay, got it. Okay. And then the drop-downs of SEP, the $70 million, what exactly is that? Is that just related to the dilution effect of dropping the asset in, and I assume there'll be offsets once you drop an asset into SEP, there'll be benefits reinvesting that cash flow within the C corp or expanding SEP. So if you could elaborate a little bit on that, that would be great.

Correct. So when you drop down -- so we own, call it 65% of SEP. So if we drop down an asset, we're only going to retain 65% of the earnings associated with that at the EBIT line, correct? So that's what you're seeing there. So as we drop down, so this is -- assuming we own 70% of SEP, if it was $100 million -- or assuming they owned -- we only own 30% -- we would've given up $70 million. So that's all that is. But you're right, below the EBIT line there, you get cash, so obviously reducing your interest expense. It's mildly accretive or flat to an EPS perspective on a cash basis, but then you go and reinvest that business. So as long as you keep dropping down businesses into the MLP, the entity above is actually going to lose earnings at the EBIT line but pick up cash and potentially EPS below the EBIT line. Is that clear?

Yes, but net-net over time, as you do these drop-downs in SEPs, it's not dilutive to earnings over the long run, is it? I mean -- yes, okay.

No, absolutely not. This is just comparing EBIT so that we're -- it was basically to create an apples-to-apples comparison.

Yes, I got you. And then just on the previous slide, that G&P decline, I think, Pat, you were talking about the $55 million in sort of declines year-over-year. Did you say that, that was related to contract renewal or was that related to just volume decline from the legacy assets that are under lines of lease?

Yes, it's really contract renewals. You see some declines, but it's really the contract renewals where you've got -- and obviously, guys aren't going to drill up $2 gas versus what they might be able to get in the U.S. Or the other piece is you've got to remember some of that gas up in that neck of the woods is a lot drier, so as you know, everybody is going after liquids-rich gas. So as we move down into places like the Montney, in places like that with more liquids-rich gas, those areas end up coming back. But in the northern areas, closer up near the Horn River, where it's drier, you're seeing people decide not to renew contracts.

Okay. Were these contracts that are -- like 1-year, 2-year, 3-year? What kind of tenure are these contracts in?

They can be all different. We've got -- you've got everything from -- just like on the pipelines, you've got annual contracts that come up for renewal. So they could be anywhere from 1-year contracts to 5- or 10-year type contracts that came up for renewal. Now what we did see a pickup in last year to help -- and again, this year, I would expect we'll see that -- is people, as gas prices come back, pick up more interruptible. Obviously interruptible is at a higher rate, but it's just a little bit more uncertain. Now as you start to fill up your plant, then people want to sign up long-term contracts. This is pretty typical for Western Canada over a 5- or 6-year period. You see the buildup, you see the come-off, you see the buildup, and it's got nothing to do with the gas not being there, which as I've mentioned to Ted's question, is a little bit different than what we see in the U.S., where you may see complete declines in fields.

And your next question comes from Craig Shere with Tuohy Brothers.

Two questions on the GP/MLP front. First, post the plan, the drop-downs through 2014 with Express-Platte, DCP pipeline interests and the rest of Maritimes Northeast U.S. Can you highlight what organic Spectra growth CapEx projects would be structured as independent assets with fully loaded cost basis that could be the next round of incremental drop-downs further out?

Well, I don't want to get too far ahead of our ourselves. But we've got -- I think important to point out, Craig, we've got $2 billion-plus in just the assets that you've mentioned, Sand Hills, Southern Hills, Express-Platte, and if you did the other part of Maritimes & U.S. I guess, longer term, I'd look at assets -- firstly, you've got to take the Canadian assets out, even things that we build up there that are generally not qualifying or get captured at the border. So the type of projects and this isn't definitive, but probably the best example would be an expansion into Florida, which as you know, that would be a brand-new project that created the opportunity. We would look at things, and it all depends on how it's structured, things like Renaissance and NEXUS as opportunities as well. So those are probably, and if you add up all those, those are huge entities in themselves. I would also point out from an MLP perspective, that the NGL pipelines are going to ramp up over a 2- or 3-year period. So you've got -- for lack of a better word -- good organic growth, And I'd expect the same thing on Express-Platte as well.

Great. And Greg, at the last meeting in mid-January, you really highlighted the opportunities from these drop-downs in the GP interests both for SEP on that new inventory of drop-downs and also at DPM. And I wonder if you'd consider, if the market just doesn't catch on to this, if you'd consider at some point sponsoring GP/MLP IPOs to help the market appreciate the value of these interests if it doesn't get reflected in your share price over the next couple of years?

Well, obviously, we're here to create shareholder value, so whatever is going to do that, we'll definitely look at that from a long-term perspective. But Craig, I don't want to get ahead of ourselves. Let's get the drops done that make sense, that serve SEP and serve SE at the same time. We have a very small GP position at this point in time, but let's take a look at things down the road. When we get the, call it, $2 billion or so dropped, then we can have a discussion at that time. I think you're already seeing some of the value in what we've discussed both in the response since, call it, mid-January. SEP's done pretty well. I think SE will move up here. You've got some headwinds on the commodity price that might be masking that a little bit. But I believe the market is smart. They look at this, we have not had similar-type opportunities as maybe some others have had to do drop-downs, and now I would suggest we have a better backlog of drop-downs than many other have. So I think the market will recognize that.

Your next question comes from Curt Launer with Deutsche Bank.

I wanted to follow up a bit with Ted's first questions relative to the Canadian business and try to think about it in the terms of when will the lines cross? In other words, it seems like the propane price impact caused Empress to have a much bigger loss than originally anticipated last year, and now you're talking about breakeven. At what point in pricing should we look at -- many of us believe propane prices will improve this year for various reasons, exports and the like. So what are we looking for in terms of Empress turning back into that profitability that goes beyond the break-even projection you're talking about? And secondarily, another similar issue in Western Canada, I guess it seemed a bit of a surprise that Horn and Montney did very well but the conventional production offset the growth. What should we be looking for in that regard so that, that business begins to contribute a bit more than what it is right now?

Yes. Let me start with Empress. So I think as we look at this and look at the contract structure and what we're seeing today on extracts and premiums and as you will well understand, Curt, it's dynamic. But I would say, if you get propane in that $0.90 range, we're making money, all other things being equal, right? So the extraction premiums are important here. But the $0.90 range I think is where Empress does pretty well. I would say that is not the only issue with respect to Empress. The Empress issue is more of, I would say, the rationalization of overall capabilities up there, not just our plant but the other plants. You still have a situation where you've got too much capacity for not enough volume. So if you could figure out a way to rationalize the capacity, the issues with respect to extraction premiums help to look after themselves. And I agree with you. You're going to see NGL prices move back up. And as I said, if you get propane in the $0.90 range, it's pretty good. And remember -- and we'd make money. And remember, ethane's done on a fee basis up there. So ethane is not a big factor where it is in the United States business. So that's the Empress piece. With respect to the rest of Western Canada, one thing I would remind you is that we've booked a lot of earnings with respect to Horn River and Montney development projects as we've been building them, that's the way the contracts work. So you have been getting that earnings growth there. There's not a ton more than can happen on the unconventional side from our perspective, where the price is. I mean, sure, maybe you can have a similar type hit for a year or so, but I think you're going to see that turn around so that you will see expected growth across the entity, I think -- across the Western Canadian entity. I think the other factor out there, which will be very positive on the processing side, will be as these LNG facilities start to get in place, you're going to need more processing capability to take that on. And again, as we've got 60% of that processing capability today in some of these LNG facilities, I bet you and I both know, they're not all going to go. But even with a couple of them going, you're going to more than exceed the current capacity of gas production in British Columbia today. And nothing's going on in Alberta. So gas production in British Columbia today, and that's going to need processing. And that's where I see some real opportunities for us over the longer term.

All right. That's great stuff. I have one other brief one, if I could. Spectra Energy Partners had a higher maintenance CapEx this quarter, and the coverage ratio dipped below 1. Can you comment on what drove that maintenance CapEx number?

You know what, Curt, I can't off the top of my head. It was -- I'm speculating, I bet it'd be East Tennessee, but I promise you at the call in about 2 hours on SEP, that question will get answered for you. Sorry to punt, but that's all I'll tell you.

[Operator Instructions] And your next question comes from Carl Kirst with BMO Capital.

Actually, just a couple of cleanup questions, and not to keep focusing on Western Canada but a lot has been asked and answered. The one question, as we try and sort of figure out sort of the trends of the conventional decline, is there a way to characterize, of say, for instance, guidance of the $380 million, how much would be sort of in that conventional G&P bucket versus the unconventional Westcoast, Empress, et cetera? Kind of in a sense of as people are wondering as we go forward in 2014 like, if under the case we just don't have gas prices recover, are we basing out or is there still a base that could still erode?

Carl, as we looked at this -- as we prepared our plan, just a little over $200 million of EBIT associated with those kinds of supplies, I mean, in a scorched-earth situation, if nothing got renewed, that's the bread basket. But we're not -- those roll off over time, as Greg said, and we're certainly not predicting -- as we talked with you guys a year ago coming into '12, we said that the roll-off would be $65 million. This year it's $55 million, incremental. And we expect it would be substantially less in the next couple of years, more like, incrementally more like in the $20 million range. So things would have to -- it really would have to stop with no renewals for all of that to go away.

I think the other thing to think about, Carl, is that with the investments we've made out there, the $1.5 billion or so, as those get fully loaded here as we finish up those projects, there's an excess of a couple of hundred million dollars worth of EBIT related to those projects. And the other thing to remember is that 30%, 35% of Western Canada is the pipeline business. So that's not impacted obviously by the G&P side of things.

Right. That's great color. And then lastly, and this is just kind of more from a minutia standpoint, or perhaps, we've talked a lot about high level of the year, maybe just a quarterly shape, when I take a look at the numbers, it looks like the drag on Empress, for instance, in the fourth quarter was about similar to the third quarter. And so what I'm wondering is to the extent that there's a sequential EBIT decline, is that coming from an acceleration of the conventional G&P. And I guess, where the ultimate question is, of the $55 million drop in G&P for 2013, is that something that you think happens ratably over the year? Or does it get -- or are we seeing an acceleration where it's more front-end loaded or how should we think of that?

Yes. I think it's -- think about it pretty even, because remember, this is -- we get contract renewals just like you do in the pipeline side, so late in last year, you start getting the view on this, so it starts to kick in. So I wouldn't see it as back-end loaded. Maybe this will help you. In the overall EPS, think about $1.50 split 60% between first and fourth quarter, fourth quarter with a little weather is usually a little better, but 60% in those 2 quarters, and 40% in Q2 and Q3. Maybe that's the way to think about it, Carl.

Your next question comes from Chris Sighinolfi with UBS.

I just wanted to follow up on Craig's questions on the drop-down strategy. I'm just curious if the initial SEP drop-downs are traditional in the sense that they're underappreciated, newly constructed or purchased assets. You've outlined a couple of the candidates there. And SE's limited partner interest gets diluted down by that process, I'm wondering about the longer-term appetite of maybe marrying these types of drops with drops of the legacy assets for unit exchange in order to keep growing GP cash flow. I appreciate your comments about not getting ahead of ourselves, but just wondering about sort of longer-term strategy.

Yes, I think that's fair enough. Again, if it's going to create a real tax problems for us, we don't have some of the NOLs that some other players have had historically. And then that doesn't seem to make sense. But obviously, as you've seen us in the past, we have looked at drop-downs of assets that we've held for some period of time. The biggest challenge for us has been the really low-tax-basis assets, where the only way to avoid it is if you take back all units. And then obviously, that's not going to create the kind of cash benefit for us to reinvest in the business, although you'd still get cash from the units. So definitely open to it, but again, I'm expecting between the $2 billion-plus we have, some of these other projects the business development teams are hunting, that we get to -- we reload the drop-down capabilities with a long-term good backlog of drop-downs that don't have us facing that tax issue and doing something that might be tax-inefficient as opposed to doing things that are tax-efficient through the MLP.

And Chris, this is Pat. As Greg said, from a sequencing standpoint, we've committed to thinking about a 2-year time frame for the $2.25 billion of assets we've either acquired or are in the process of acquiring. And then beyond that, we're developing projects like OPEN, NEXUS, Renaissance, AIM. And while it's not clear at this point that they could all be structured in a way that they could be severed from the Texas Eastern mainline proper and dropped down, that's certainly something that we'll do if we can. And so that would sort of -- both of these projects have current costs without depreciation that could come on, maybe beyond that 2-year time frame. So while you don't rule out what you asked about, we may not need to, to keep the growth growing.

Okay, great. I guess one final cleanup question for me, and I'm sorry if I missed it, do you have an updated timeline on Express-Platte closure? You still targeting, I think mid-year was what you had said originally?

Yes, we're still targeting mid-year. Obviously, it's important to us to get it done even sooner than that, if possible. Liked the responses we've heard out of federal governments on both sides of the border. And obviously, if we can get it done early, we won't be delaying. So I think you won't be surprised, I don't think I'm telling any tales out of school here, looking at the General Counsel, about -- we've got the federal government approvals in place here in the United States, so that's good, from an FTC perspective. So we'll keep moving down that trail, and if we can do it quicker, Chris, that's obviously a good thing for everybody.

Your next question comes from Ross Payne with Wells Fargo.

First question is on the U.S. Transmission side. The short-term rates, are those increasing or staying about the same as they've been in the last couple of years in terms of the percentage of the contracts? And second of all, what direction, if they are down, how much are they down year-over-year?

Ross, this is Pat. We've had 98% renewal, so we're not really adding much to our base of interruptible. And the rates are holding steady. We're not really seeing declines. It's pretty constant.

Okay. On the Florida pipeline, can you guys talk about how you're positioned relative to maybe some of your competitors for being able to bid on that?

Yes, I think we're in a great spot. I mean, look, there's 2 pipelines that go in there now, and we're one of them, obviously, in terms of with Gulfstream. We've got a good partner in Williams, and that's been a relationship over a considerable period of time. We have good relationships with the customer, and I'll even say customers because I think that's an important issue. So I like our position, frankly, and we're going to go at this one hard. As you know, it is a great customer, it's not driven by demand per se; it's driven by a change-out to gas-fired generation, which Florida has responsibly pursued for a long time. So I like where we are relative to others. I like where we are relative to our partner. And I like where we are given the history of how we've operated in the state to date.

Okay, great. And also BG's position on the LNG facility out of Prince Rupert, is it -- can you speak to how that project is moving forward relative to the one in Kitimat with Shell?

Yes, absolutely, I think well, BG, we've had discussions with them recently. And obviously those are ongoing full tilt. They're very keen on the project. We are only project in Prince Rupert that has filed its environmental assessment documentation with the provincial government there, so that's moving forward. And I think you'll expect to see, as we said, that kind of 2015, '16 time frame for FID, which should be in the same time frame as what I'm hearing on the Kitimat side. I think the interesting thing is that they still have multiple projects going on there and you probably -- I think the latest count might be up to 7 projects between Prince Rupert, Kitimat, Port Alberni, a whole variety of places. And you'll definitely see some rationalization, but BG's got a good track record in being able to bring these projects forward, and I expect you'll see some other players step up too, and that will create an opportunity for even stronger partnerships going forward.

Okay, great. And my final question is, can you guys give us an indication of where you think the debt number is going to end up at the end of the year and/or what your debt-to-EBITDA metric might look like?

Certainly. We ended the year at about 56% debt to cap, and we're looking to add -- we're going to do about $2 billion of financing, about $900 million for maturities, so about $1.2 billion net. And that would -- our FFO to interest would still be just under 4x, call it 3.7x and our FFO to total debt in the mid-13s, so about the same.

I guess what I would say, Ross, is that each year we've talked about where our debt's going to be, and we've never hit it. We always seem to have more cash generation than expected. Interest expense is always lower than we expected, and our credit metrics seem to end -- which is the right way to be. We're conservative on that approach but feel pretty good about where we are.

And those metrics don't include the effect of any drops, which could help us by raising equity at SEP.

Thank you. There are no further questions in queue.

Okay. Thank you very much for joining us today. We appreciate it. And as always, if you should have additional questions, please feel free to contact either Roni Cappadonna or me. Thanks again for joining us today.

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