Sea Limited (SE) Q1 2011 Earnings Report, Transcript and Summary

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

Thanks, Joanne,, and good morning, everyone. And welcome to Spectra Energy's First Quarter 2011 Earnings Review. We're very pleased that you've been able to join us today. Leading our discussion today 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'll then open the lines for your questions. Before we begin, let me take a moment to remind you that some of the things we will discuss today concern 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. So 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 from those contemplated in today's discussion. In addition, today's discussion includes certain non-GAAP financial measures as defined by 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, John, and good morning, everybody. As you've seen from our earnings release, Spectra Energy delivered solid ongoing first quarter results of $350 million, compared to $342 million in the first quarter of 2010. I'm pleased with our first quarter performance, which exceeded our expectations and has given us an excellent running start to the year. In fact, after a levelizing for the unusually low tax rate in Q1 2010, our EPS was up about 10% quarter-over-quarter. Key drivers for those of solid results included the following: continued strong performance from our fee-based businesses, $45 million in incremental EBIT from expansion projects placed into service last year, projects like TEMAX and our Fort Nelson Expansion in British Columbia; a strengthening Canadian dollar, which benefited our Canadian businesses; colder-than-normal weather for the first quarter, compared with warmer-than-normal weather in the first quarter of 2010, benefited our Distribution segment. The harsh weather also led to record deliveries on our Northeast U.S. pipelines. Our system ran safely and reliably and met the customers' needs during critical periods. And while cold weather is not an earnings driver for the quarter for our U.S. pipelines, the high utilization of our system, including about 1.5 billion Northeast capacity additions since 2007 really bodes well in terms of both ongoing business and future pipeline expansion opportunities. And while cold weather is generally a positive for our business, it can create some challenges at our Field Services businesses, DCP Midstream. This winter's unusually cold periods led to producer well freeze-offs in DCP Midstream's footprint, which in turn, reduced production volumes at its plants. Although we didn't see a decline in volumes compared to the first quarter of 2010, the volume growth that we've been seeing over the most recent quarters was delayed with the well freeze-offs. Field Services…

Well, thank you, Greg, and good morning, everyone. As announced earlier today, we reported first quarter 2011 earnings of $357 million or $0.55 per share, compared with $358 million or $0.55 per share in the first quarter of 2010. After removing the effect of discontinued operations, and special items, ongoing earnings for the quarter were $350 million or $0.54 per share, compared with $342 million or $0.53 per share last year. For comparison purposes, I'll remind you that the first quarter of 2010 results included a $0.04 benefit from a favorable tax settlement. We know that many of you focus on EBITDA, so the next slide provides that information by business segment. Ongoing EBITDA for the quarter was $904 million compared with $863 million in the first quarter of 2010, an almost 5% increase year-over-year. That increase reflects the strong cash generation capacity of our business mix. Let's now take a look at our performance by business segment, beginning with U.S. Transmission. U.S. Transmission reported first quarter 2011 EBIT of $279 million, compared with $247 million in the first quarter of 2010. The segment benefited from expansion projects placed in service late in 2010, including TEMAX/TIME III and Algonquin East to West. Now let's move on to Distribution. Distribution reported first quarter 2011 EBIT of $167 million compared with $146 million in the first quarter of 2010. This improvement is mainly due to higher customer usage because of colder weather, a stronger Canadian dollar, growth in the number of residential customers being served and an increase in industrial usage due to favorable natural gas prices. Let me turn now to Western Canada Transmission and Processing. That segment reported first quarter 2011 EBIT of $141 million, compared with $119 million in the first quarter of 2010. The business benefited from improved…

[Operator Instructions] Your first question is from the line of Jonathan Lefebvre. [Wells Fargo Securities]

Just had a question on DCP and the weather impact there. Can you quantify what that was? And then in terms of the volume impact, should we expect that we'll see that come back later in the year?

Well, the weather was kind of in the $10 million range, maybe a little bit more. And then volumes were down from what we'd expect to probably about 5%. I would expect some of that to ramp up back up, projects like Mewborne and Eagle Ford, they get impacted by that and gas gets backed up in the field. But as those plants come on, obviously, the freeze-ups are done, I'd expect you'd see acceleration of results as we go through the year. And needless to say, the commodity prices are very attractive from what our assumptions where, Jonathan. And gas prices were below what we thought in the first quarter and now they're above what we thought. So pretty good dynamics from a fundamentals perspective, from a volumes perspective, and so I'd expect you'd see that corresponding improvement.

I appreciate that. And then just was wondering if we could get maybe an update on the Sandhills project, when we might see a binding open season filed and kind of where are in the process.

Well, pretty competitive. I'd still expect in next month, you'll hear something for us on that, Jonathan. And I'll leave it at this point in time. But we like our position. We like kind of what we're hearing from producers, and give us 30 days or so and hopefully, we'll be giving you something that will be very positive.

And then finally on the Kitimat LNG project, I know you guys are seeing opportunities to service that with infrastructure growth, just wondering if maybe you have any idea of maybe potential size of what might be needed and maybe if you can put some dollar amounts around that would be helpful.

Pretty early days so that project would be probably still mid-decade. And it may not be just one project, I think there could be some attractive opportunities from more than just one export facility there. But a pipeline going from the old Westcoast systems, our SPC [ph] system, is probably in the kind of $2 billion to $3 billion range. Maybe those are pretty rough numbers, but you're going through a rough terrain there, obviously. But that's obviously a pretty attractive opportunity to put a lot of capital to work for a long period of time.

Great. And any idea of what type of size you might need in terms of volumes?

Well, I think that's really kind of in the producers' hands right now. I think you've got everything from proposals out there, from kind of 1 billion to 2 billion [ph] in terms of facilities. I think you get below 750 million [ph] kind of thing or at least something that's not expandable for well over 1 billion [ph] then it becomes kind of economic. So I think you're going to be 750 million and up and obviously, the bigger it is, the more economic it becomes.

And Jonathan, the announcement was that the NEB would begin hearings on the export permit in June with an anticipated decision by the end of the year so that may help give some clarity to the starting point at least.

Your next question is from the line of Ted Durbin. [Goldman Sachs]

You talked a little bit about the MOU [memorandum of understanding], the range, fine with Dow. I'm just wondering when we might get a little bit more clarity on gaining more producers to sign up, what kind of costs you'd see on the MEPS project, the returns you'd look for and are you looking for more of the producers or more of the consumers to be paying the tariff?

Originally, I would've said more the producers, but I think the Dow -- and obviously, we're in discussions with those folks as well. I think you're seeing a combination of both. Both producers obviously want to push the product, but the consumers want to make sure that they've got a couple of things. One, close access to their plants, but two, expandability. And we think that really creates an advantage for the MEPS project. I think that's still going to be later this year before we get that all clarified, I think producers and consumers are really weighing all their options. It's very competitive. I just really like our position. Obviously, I like the partnership between El Paso and ourselves. And I think that expandability piece is going to be really valuable. But I think I don't see anything in the next 20 days kind of thing. But let's see, as the year goes on, we'll get folks signed up, I would hope. And it's still a 2014 project, Ted, so it would not be unusual for us to be in a position where you're a couple of years before you actually get the project nailed.

Okay. And any sense of what the cost might be for the total project?

Yes. Something in the $800 million to $1 billion range. And that's up to like 60,000 barrels a day.

At 60,000 barrels a day. Okay, great.

And that's a 100%, Ted, right?

Yes, you'd be 50-50.

And Ted, we've talked about ROCEs on all of our projects, in the 10% to 12% range. And some will be lower and some will be higher. And as Greg said, this will be very competitive. But that's the nice thing about having a portfolio where we're going to invest more than $5 billion over the next 5 years.

That's helpful. Maybe just switching over to the Horn River and the Montney, what are you seeing in terms of competition? I mean, you have some E&Ps announce they might do some of their own Midstream work. I'm just wondering how the competitive landscape is out there.

Well, from a size, we're clearly the largest single player there. We've been there for a very long time. These are not -- some of these plants have very high H2S content. These aren't easy plants to run, and it's our expertise. So we feel really good about the competitive position there. There's a number of smaller Canadian players there that we don't take for granted, that's for sure. But as producers look at where is the money best spent, is it spent at the wellhead or the drill bit or is it spent better on processing. I think they'll turn to folks like Spectra, who have shown they can deliver on their commitments to build those plants out. So as people decide if they want to build out additional processing themselves, people, i.e. producers, or they want to see processes, I think we're going to be in a really good position to do it. And as Pat pointed out, with the new credit facilities in place, a really great access we have to capital markets in Canada, very attractive tax rates in Canada and a strong dollar, I think we're going to like and I think investors are going to like the opportunities we have up there.

Okay. And then if I could just -- coming back to DCP, you said $700 million, $800 million of CapEx this year. Which products are actually in that budget? What could that number be if you got some other project wins this year and even going forward into '12 and '13?

Yes, well, I think that $700 million, $800 million average over the next few years is a good number. Even the projects that we picked up this year, Ted, like if you pick up Sandhills and stuff, that's not going to have a huge impact this year. And so the kind of stuff that I'm talking about is some of Eagle Ford activity that's in there, the Mewborne plant, which is up in Weld County, we have some buildouts in that regard. So some smaller plants this year, the bigger projects would be in places like in the Permian. The bigger projects will come in over the next couple of years. But I think that $700 million, $800 million is a good number. And remember, the nice thing about that is we can continue the dividends coming up to the parents because we've got DPM there to fund the equity side, if you will. And at these commodity prices, more than enough cash flow to fund the remainder of the DCP Midstream.

Next question is from the line of Carl Kirst. [BMO Capital Markets]

Just a couple of cleanups on my end. Do you guys have the effect of what the Canadian EBIT is at Union, at the utility just from kind of a weather normalized?

Well, and you're just looking for the weather impact?

Yes, exactly.

Okay. We had the impact of customer usage -- I think weather was only a couple of million dollars, maybe $4 million or $5 million.

And actually, Carl, weather was about $9 million which -- if that's customer usage, primarily due to colder weather, the Canadian dollar strengthening, added about $9 million. But we also saw growth in a number residential customers that added about $2 million, and then an increase in industrial usage because of favorable gas price economics, that was another $2 million.

Okay, now very helpful just to dead-reckon everything. The second question I had was just on the pipeline EBIT. Very nice results here. And I guess, to a certain extent of looking where we were as we entered the year targeting roughly right around $1 billion for pipeline EBIT as a whole for 2011. Did you see anything within the first quarter that was better than expectation? Are we ahead of the budget right now? Or is this something where we should kind of continue to really focus on that $1 billion, and we have really more just sort of quarterly progression noise?

Well, I think it's a little too early to kind of start to see it exactly. We have three quarters to go. As you know, it's pretty even. There was nothing spectacular. I mean, the project's so sweet, tell you they'll do, they come in on-time and on-budget and they produce [indiscernible] earnings, call it $30 million or so. And maybe we're a little bit ahead of budget, but let's see how the rest of the three quarters go. I wouldn't change that number at this point in time, Carl.

No, that's fair. Just trying to get a sense of flavors so that's very helpful. And then last question, Greg, if I could, just to make sure I understand what the growth opportunities set is. In particular, on the LNG side as we look over it at Kitimat, is what you're referring to when you say potentially $2 billion to $3 billion and recognizing how early you are in this process, is that a new Westcoast line to Kitimat? Or is that somehow, using PNG's [Pacific Northern Gas] rights-of-way -- or I mean, is this in competition with PNG? Or is this somehow connecting into PNG?

No, this is a separate pipeline. Whether you use the PNG right-of-way or not, that's something still to be discussed. They're small operators. What I'm just saying is that kind of building out from call it, station 2 or somewhere in that range, over to Kitimat. That's what I'm talking about. So the right-of-way issue is important, but that's an extremely small lateral or pipeline that PNG exists out there. So I would look at it as a new pipeline, and that's just the pipeline cost that I'm giving you from that perspective, Carl. Does that help?

Awesome. That was perfect. :p id="-1" name="Operator" /> Next question is from the line of Matthew Akman. [Macquarie Research]

A few questions. On Western Canada, obviously, Empress had very strong volume throughput in the quarter and Horn River was better. As you grow volumes organically there, is there any kind of rough breakdown of the improvement from each component? Were they mostly Empress or mostly Horn River? Or how do you look at it?

No, mainly the expansion at Horn River, I mean, Empress was no different year-over-year actually, Matt. So the pickup from G&P business was about $20 million, then you picked up $6 million or $7 million from the currency.

Okay. So that's just ongoing, sustainable fee-based-type volume?

Absolutely.

Okay, that's great. Pat, I guess, this question's for you. You booked $139 million of income tax, are expensed that much in the quarter. But I know this year, there's the bonus depreciation and your cash tax will be lower. Did you pay much in way of cash tax in the quarter?

No, in fact, we're not looking to pay cash taxes for the entire year because of bonus depreciation. And as we have sharpened our pencil, our estimate now, instead of $250 million, is closer to $350 million, with $300 million of that attributable to 2011 operations and $50 million, a look-back at 2010. So we're well positioned to not be in a cash tax paying position this year. But of course, as you know, it's really just an interest-free loan from the government, a switch between current and deferred. If you look at the cash flow, operating cash flow is up, call it, $0.25 billion. $100 million of that is from cash taxes not being paid, so that's positive.

Okay. So operating cash flow in the quarter was up $250 million?

That's correct.

And my last question, maybe this is for you, Greg, to just maybe pontificate a little bit on the whole MLP tax situation. I don't know if you've been following, but I guess, there's a little of noise that there might be consideration of changing that. And just maybe your thoughts on whether you think that might happen. And if it would, how it will affect Spectra? And that's my last question.

Okay. Well, we've seen this in Canada come and go. I think it's important to have a balanced approach here. Obviously, we think we've got structures that can take advantage of either scenario. I have no idea what's going to happen from a taxation perspective in Washington. I don't know if anybody does. I guess, again, for us, having a large C corp structure both in Canada and in the United States, having MLPs in our key business units, that seems to be a wise idea as well. And whatever the scenario is, I think Spectra's going well-positioned. So we'll have to see what happens. As long as they exist, we're going to use them to finance the growth. And I think it's a long ways down the road to think that they're going to go away anytime certain. But that would -- that is definitely pontificating because we'll have to see what happens from that perspective.

The next question is from the line of Craig Shere. [Tuohy Brothers Investment]

Greg, in the past, you've been pretty clear. You've cited collateral requirements and counterparty risks and mark-to-market confusion as all obstacles to Spectra every pursuing hedging options for the commodity exposure from DCP. And I wonder, though, if you would support DCP itself, signing more hedgeable or fixed-price long-term petrochem ethane supply agreements, if that became available. And if that happened, then you had more long-term consistency of distributions from the JV. Could that impact kind of a step change in your own dividend?

Yes, well, the dividend is more than paid for from the fee-based businesses as you know. So we don't look for the DCP at all to help us pay the dividend to Spectra Energy common shareholders. So that's one. Two, my philosophical view on hedging hasn't changed nor amongst the board or the rest of the management from that perspective. And I think some of the challenges you pointed out still existed. There is some hedging that goes on at DCP for DPM. So they do it at a very small basis just to predict their distribution down at that level. And then last, we have a joint venture partner in ConocoPhillips, and they don't see any great desire to hedge either. And as such, we'd have to do it here at the Spectra level. You'd have to do in on a dirty basis, so you'd see inconsistencies. You'd have to do it with oil. So I continue to think, look, as the rest of the business grows at SE, and we pay far more -- or we make far more than is required at the fee-based businesses than to pay the dividend, I don't think our ownership of DCP Midstream in any way impacts the growth of our dividends. And that's actually changed since back in 2007, where we didn't pay the dividend entirely out of our fee-based businesses. So Craig, at this point in time, I wouldn't change it. Now the contracting structures out there in the industry can change from time to time, and if that's the case, then that's separate. But from a specific hedging perspective, I wouldn't see us making any changes.

Well, I guess, the last point you kind of referenced is what I was trying to touch on. My understanding, weak as it is, is that maybe we have gone from weeks to months in terms of petrochem contracting. And with all the talk of now [ph] greenfield construction in North America for the first time in over 20 years and everybody converting the crackers to be able to on run lighter feedstock, that the petrochems for the first time are kind of on an equal footing in terms of negotiating with the more diffused midstream players and that maybe really long-term contracts possibly measured in years might be available.

Yes, again, I mean, we're not -- obviously, if that's what the market really wants to go, then that's something we'd be open to. But the vast, vast majority of contracts where we're current we are still on a POP [ph] basis. And our customers at DCP continue to want to be served on that basis. We do have some fee-based contracts very little on the people [ph] side. But yes, I mean, obviously we're not agnostic to where the industry wants to go. I would suggest, and if you look at the returns on our DCP business versus some of the peers in that regard, the current structure served us very well and shareholders as well. And even in challenging times back to 2009, we continued to see strong distributions from that company.

And Craig, one nuance on that is that the kind of the standard NGL barrel out there would be sort of 40% ethane, maybe 30% propane. But just given the relative value of propane, it's significantly more part of the economic barrel, if you will, than ethane is certainly today.

Understood. And kind of on the last point that was being touched on in terms of the various high returns from DCP, which is true. I mean, you guys are just off the charts on your cost basis there. It's been a phenomenal investment. But because of that also, I think you all have highlighted that you're not inclined to monetize but to grow that asset, and enjoy those returns off your low basis going forward. I guess, the question is how do you think the market should look at the value of this effectively private MLP in a period when publicly traded MLPs and their GP [general partnership] interests are reaching new highs?

Well, that's exactly what I think. I think they should be looking at Spectra and Conoco as on a GP basis. It should be more like how I see them looking at some of the Kinders and Enterprises and Williams with its split. I mean, we should be getting those types of valuations as far as I'm concerned. But we're not going to -- Conoco and ourselves aren't going to change the structure that we have there at this point in time. I think the market needs to look more at the cash flow that comes up and how we regenerate those very nice earnings into fee-based earnings, which drive the dividend, which is very much what I see from the other C corps and MLPs trying to do now. Some of the things that I -- it's interesting to me because it seems like we already did that stuff back in 2007, and we just need to talk about that a little bit more, show the cash flow that's coming home from DCP, showing that being reinvested in the fee-based business and seeing all that cash up and help fund the dividend and dividend growth.

And then being self-funded, it's ironic that with production shifting really to the oilier plays, that benefits DCP quite a bit because they're the biggest player on the Permian and they're very active in the Eagle Ford, among other areas. And that's going to allow them to grow their volumes at about 3% to 5%, increase their net income about 2% to 4%, and again, fund that $700 million to $900 million, including maintenance CapEx internally.

Great. And last question, guys, I appreciate it all. Can you make any comments about how the storage market is shaping up for Bobcat?

Well, we don't have Bobcat built up until 2015, so obviously it's about where we thought it would be. We knew that storage values were going to weaken, and until you get this rebalancing done on the supply side and exactly what that means. Our big driver around Bobcat continues to be the gas-fired generation, the connection to multiple pipes, et cetera, that's going to be important as we get into the middle of the decade. So we're moving forward with continuing to build out that pipeline, but really earnings [indiscernible] coming into that '14, '15 timeframe.

Your next question comes from the line of Nathan Judge. [Atlantic Equities]

As we've gotten some of these rules from the EPA on various [ph] emissions, have you had a chance to kind of sharpen your pencil on what you'd expect from power generation opportunities for the pipeline side?

Well, as we look down, what we do is we go along -- and take Texas Eastern, for example, you see in places like the Northeast region of that, where we've got, call it, 50 coal plants within 30 miles of the pipe. And as we kind of look at that and we look at the changes in the Southeast, particularly in Florida and the Mid-Atlantic South, look at Tennessee, look at the Carolinas, look at Georgia, we see opportunities there. And call it, the Southeast probably $1.5 billion to $2 billion and in the Northeast, I think you're talking about $500 million plus. And the Southeast is a bigger number because there's a couple of big opportunites associated with things like Gulfstream. There's going to be another need for a build to support all those plants in Florida. In the Northeast, it's much more the laterals. And a good indication is the kind of stuff we're doing right now. Well, this is not the Northeast kind of projects that you'd see, the East Tennessee, the Northeast Tennessee project, which is around $125 million, $130 million, lateral and then the Arkansas Hot Springs plant was about $40 million. So you can see a number of smaller projects. And those are obviously lower risk but nice returning projects, and then a couple of big ones that I think would go on in the Southeast. So that all that's going to play out over the next couple of years. Most of that stuff is kind of '14, '15 and beyond in terms of buildouts in terms of the big ones. But maybe that gives you an idea of the order magnitude anyways, Nathan.

And just as it relates to the -- can you just remind us what rate cases you have pending or essentially in the next several years?

We've got no rate cases currently pending in the United States. In Canada, we have a small rate hearing going on in Maritimes & Northeast. Our 5-year rate deal at Union complete -- finishes at the end of 2012, so we'll put a new one in place there. And of course, Western Canada, they've just signed a new rate deal, but they go in every 3 years, but nothing significant. You might recall that we had a settlement where we had a Section 5 going on in Ozark. We've settled that and that's what FERC [ph] that they'll approve that over the next couple of months. But that's no degradation in where we expect it to be from an earnings perspective.

[indiscernible] if you don't foresee a rate case [indiscernible]?

No, I don't. It's been a long time since we've had a rate case at Texas Eastern. I think that's represented a good relationship between the shippers and ourselves in finding ways to cover our cost increases over the years and obviously, the revenue changes and new services that they're looking for. So I think it's been a good balance and a fair situation for both parties.

Just a follow-up on this, but obviously, the origination of the MEPS project has -- a part of that is related to some of the differentials now that are being seen where the gas supplies come from, in the -- can you just comment on where you see Texas Eastern being -- how that's different and why that wouldn't replace or replicate some of the issues that we're seeing with your competitors?

Well, I think right now, you don't have a way to get the ethane from the Marcellus down into the Gulf Coast. So I think the advantage you have is some pipeline that's not being utilized, which El Paso brings to the table, some of the attributes we bring from the table, whether it's rights-of-way or markets, et cetera, down here in the Gulf region. I think the real driver is the fact that you've got a, call it, 600 million, 650 million-barrel a day market in the Gulf Coast. And that's where you want to be taking the ethane. And again, with announcements like that, you could see several hundred thousand more a day happening here by the middle of the decade. And again, that's going to be the real driver. So in effect that we've already -- there's already some pipeline and right-of-way available, that's obviously be easier than building all greenfield. That MEPS project might be a couple [indiscernible] greenfield. The rest of it would be using existing right-of-way and pipe. And then last and definitely not least, the expandability of a pipe versus some of the other options, I think, is going to be really critical for our customers because as they see increasing opportunities and the opportunity to build out more in the Gulf Coast region, that expandability of a pipe, I think, is going to serve them better than say a marine solution, et cetera.

And Nathan, if you're asking about the parallel with respect to optionality, we had in our December contract renewals, 94% renewal rates on TETCO and Algonquin with a year to remarket the slight amounts that were turned back and very good progress there. I think that's just a reflection of the option value that both producers and end users see on Texas Eastern. All the supply basins that we access from the Gulf forward and the potential to move gas -- to continue to move gas to the Southeast as those markets expand and as coal plant conversions takes place.

I guess, what I was referring to is as we see more production from perhaps the Northeast from sales we've seen some commentary from your competitors saying that the volumes being shipped from, natural gas volumes, not ethane, being shipped from the Southeast up to the Northeast is perhaps is not being as utilized as it once was before. And I just wanted to ask how, as a follow-on to that, how could the decision by Excelerate and the potential for decommissioning the O&G down in the Gulf Coast have on impact on both storage and usage for shipping gas north to east.

Totally unrelated. I think if you look at Texas Eastern, again we're seeing peak days across our system. If you think about the amount of gas coming from the Eagle Ford and other locations down here, and while maybe some of the gas might not all the way up north, those pipelines I'm convinced are going to be utilized. I think if you look at those statistics, if you go out 20 years, you're still going to find about 40% of the gas produced in the lower 48 coming from the Gulf Coast region. And if you're an LDC in New York or New Jersey, you can do a lot of things. But you can't run out of gas in the winter, so you've got to be able to make sure those contracts are in place. It's a flowthrough on the cost basis. The cost of holding that pipeline capacity is pretty minimal, when you think about that, so I don't see that. With respect to the Gateway situation in the Gulf, remember that's actually not related to anything with respect to changing supply dynamics. The wells that supported that were damaged in the hurricanes, and they never came back and so that created some challenge in and around the system. And the LNG facility, this wasn't going to be operated in the same way that they thought. So I don't think it's so much the changing the supplies as it was to some of the weather impacts in and around that region.

I appreciate that. And then just to confirm on the Ontario storage expansion, can you just give us a little bit more on that, as well as if that's going to be outside of Great Basin? Is that correct?

Yes, that's just a couple of -- it's pretty small. And yes, that's one of those projects that we'll take advantage of given the new regulatory structure in place. There's probably less than a couple of hundred million dollars of additional storage opportunities in Ontario right now. The real benefit is as you pointed out, we've pulled about 1/3 of our storage out of regulation and have seen the benefit of market rates there. And even with depressed storage prices across North America right now, those are still better returns than you get from a regular perspective.

Your next question is from the line of Faisel Khan. [Citigroup Research]

Just a couple of quick questions. In terms of the G&P volumes in Western Canada, what was the volume year-over-year? Did I miss that in the press release? Because I couldn't quite find it.

Yes, it's usually in the quarterly highlights piece. But we're just flipping through. So process volumes in Western Canada were 176 TBtu. And if you're thinking about Empress there, basically flat, kind of 181 to 187 TBtu, the Inlet Volumes there.

Okay, because I was trying to figure out what the differential was with some of the new volumes and new projects because of bottom line in British Columbia.

Well, remember, Faisel, this is a really important point that, that's a fee-based business, so the volumes don't always tell you. What it is, is the contracted volumes. So as we put the capital on the ground, we have contracted volumes. You may not always see that type of uptick that would correspond with the earnings. You've got people paying you fees to have the assets there as opposed to necessarily just utilized. Obviously, we like them fully utilized, but that's why it's not the same type of indicator that you can get out of DCP Midstream in the U.S., for example.

Okay, sorry, so you're saying that the fee-based contracts are -- they pay a fixed fee on a monthly basis?

Absolutely, just like the pipeline system.

Okay. They're not paying you a volume metric fee?

Correct.

Okay, understood. And then if I'm looking at -- Pat, I think you talked about in the quarter at DCP, some of the colder weather decreased the efficiency of the plant. Is that a function of some of the older plants not having kind of a higher cut of the ethane and propanes that weather affects those plants a little bit more than some of the newer plants that you guys have online? Or it across the entire system?

I think it's that, it's sort of the age of the plants and not across the entire system. The newer plants that we're building have the ability to take a deeper cut and are less weather-sensitive.

Well, the other thing, Faisel, is you ramp up and down on power. You have rolling blackouts and water cut [ph] that makes your plants inefficient to be able to do that. You have freeze-ups, you're not running your plants at full capacity. That makes them inefficient, so it's a combination of all those things that the best plants run at full tilt, all out, all full.

No further questions at this time.

Okay. If there are no further questions, then we'll just say thank you for joining us today. We appreciate it very much, and we'd like to remind you that next Tuesday, we will be in Boston for breakfast and in New York for lunch. So if you haven't already given us your indication as to whether or not you'll be joining us, we'd appreciate it if you do that. And as always, if there are any additional questions, please feel free to contact Roni or me. Again, thank you very much for joining us today.

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