Sea Limited (SE) Q3 2009 Earnings Report, Transcript and Summary

Good morning. At this time, I'd like to welcome everyone to the Spectra Energy third quarter 2009 Earnings Call. All lines have been placed on mute to prevent any background noise. (Operator Instructions). At this time, I would like to turn the call over to Mr. John Arensdorf, Spectra Energy's Chief Communications Officer. Please go ahead, sir.

Thanks, Celeste and good morning, everyone. Welcome to Spectra Energy's third quarter 2009 earnings review. We're pleased that you could join us today. Leading our discussion today will be Greg Ebel, our President and Chief Executive Officer and Pat Reddy, our Chief Financial Officer. Greg and Pat will discuss our quarterly results and update you on our year-to-date progress and our future plans. Then we'll open the lines for your questions. But as usual before we begin, let me take a moment to remind you that some of the things we'll 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. 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, our 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 Web site at spectraenergy.com. With that, I'll turn the call over to Greg.

Thanks very much, John, and good morning, everyone. As you've seen from our earnings release, Spectra Energy delivered very solid ongoing third quarter results of $190 million or $0.30 per share. We feel upbeat about our results for the quarter and for the year-to-date, particularly given the fact that 2009 has had its challenges, both, within and outside our sector, but we took steps to meet those challenges head on. First, earlier this year, we bolstered our financial flexibility. Second, we're achieving good growth performance from our core businesses, which are providing us with cash flow, not only to fund our dividends, our operations and maintenance capital, but also partially fund our expansion capital. Third, we've been able to use our MLP to finance accretive acquisition opportunity and expand our service offerings. Fourth, we're managing our costs and have achieved our $50 million cost reduction target. About one-half of this is capital and the other half is operating costs. We're successfully executing on our capital expansion project as well. These projects are earning returns above the high end of our stated range, and they will continue to provide earnings and cash flow for many years to come. Our core fee-based business is storage, transmission, distribution and Canadian gathering and processing performed very well in the quarter. In fact, third quarter earnings for each of these areas were notably higher compared to last year's quarter. After removing from ongoing earnings the effect of commodity prices and exchange rate differences, we saw quarter-over-quarter earnings growth in the 6% to 8% range. You'll hear the numbers break down from Pat shortly, but these operations delivered solid results for our customers and shareholders, and as you know, the overwhelming majority of this year's $1.15 per share earnings expectation will come from these fee-based businesses.…

Well thank you, Greg, and good morning, everyone. As announced earlier today, Spectra Energy reported third quarter 2009 ongoing earnings of $190 million or $0.30 per share compared with $302 million or $0.49 per share last year. As you can see on the slide, there were no significant differences between reported and ongoing earnings this quarter. Our fee-based businesses performed in line with our expectations, but our overall results were challenged by the commodity sensitive businesses at Field Services and our Empress plant. New projects continue to contribute EBIT at U.S. Transmission. Distribution saw continued growth in storage and transportation revenues and Western Canada experienced growth in their base gathering and processing revenues. Now let's take a closer look at our performance by business segment beginning with U.S. Transmission. U.S. Transmission reported ongoing third quarter 2009 EBIT of $239 million compared with $217 million in the third quarter of 2008. The segment showed significant benefit from business expansion as a result of growth projects we placed into service in 2008 and 2009. In addition, we experienced a $33 million positive change in project development costs. In 2008, we recorded $12 million of development cost expense. In this quarter, we recorded a net benefit of $21 million, due mainly to the capitalization of costs associated with our TEMAX/TIME III project. These increases were partially offset by lower gas processing revenues resulting from lower prices and volumes due to the anticipated restoration of third-party processing capacity in the Gulf and a non-cash regulatory accounting adjustment related to our Southeast Supply Header project. Many contracts for capacity on our system come due for renewal on October 31st and we're pleased that we have achieved 100% renewal rate among customers served by our U.S. pipelines. Let's turn now to distribution. Distribution reported third quarter…

Thanks, Pat. A pretty good third quarter and as you pointed out a good foundation from which to grow from. We're in the process of finishing our 2010 forecast, which we will finalize with our board toward year end and for our typical timing review with you earlier in the New Year. But I do want to share with you our current thinking related to one key input, commodity prices. Our current commodity view has oil in the $70 range for next year, and importantly an NGL to crude relationship of about 55%. This equates to $0.92 per gallon for NGLs which is inline with where we've seen the comp to an NGL price today and the 2010 forward curve. And we're currently looking for natural gas prices to average about 550 next year. A number of additional factors, of course, affect our forecast, so we'll be closely watching indicators such as volumes, customer growth, expansion projects, et cetera, across the company. However, if what we are currently seeing for commodities plays out, that should imply 2010 EPS growth of about 20% to 25% above our 2009 target. We'll continue to watch the forward curve and other indicators as to where commodity prices might be headed, so we may be modifying these assumptions as we discuss our plan with the Board. In terms of capital expansion plans for next year and beyond, we have identified a number of specific projects for 2010 and 11, totaling about $1 billion in investment per year. We've talked to you before about our expectations for 2010 and 2011 projects, but we thought you might also be interested in our thoughts about opportunities for expansion post 2011. This slide gives you a good sense of where new natural gas supply will come from in the…

(Operator Instructions). Your first question comes from the line of Ella Vuernick with RBC Capital Markets.

The first is could you just from slide seven you commented about a regulatory adjustment at SESH. Could you quantify that number?

Yes, Ella, this is Pat. The amount was $11 million and it related to the fact that we discontinued rate regulated accounting treatment for SESH this year and that was the amount of the charge.

Okay. So it's a charge of $11 million?

Correct.

Okay, very good. And I know that you mentioned that you would be giving us further guidance early in the year. I was wondering at this stage if you could give us further color into your outlook at DCP Midstream and western Canada for the field and services businesses both in terms of volume and pricing going into next year. I know you mentioned you're seeing some recovery, if you could give us some further clarity that would be very helpful.

Well, I think at this point probably only can speak to price. You know we're continuing to work in and around volumes. I did mention in western Canada, we're already starting to see about a 100 million a day coming out of the Horn River coming through our system. There is no doubt ACO pricing has jumped pretty dramatically in fact last month or so, I think we're in the $450 range now for ACO. We did mention with respect to DCP what we're seeing today is about $0.92 NGL prices for next year, which would be consistent with about a $70 oil price, 55% correlation of crude to NGLs. Again with volumes, we'll have to see where that goes. To date at DCP, the volumes this year versus last year are about flat. And so we'll just have to see how that shakes out as we look for planning for next year.

Your next question comes from the line of Ross Payne with Wells Fargo.

I just wanted to ask you as REX makes its way all the way east, are you guys going to be able to pick up some of that volume as it does hit?

I guess we should define all the way east. I don't think all the way east.

Right.

I think we're picking up as you know our TEMAX project. The big customer there would be Conoco which obviously is moving a lot of gas on REX. As that comes in, we're going to be picking up a good chunk of the volumes there. I think between that and the volumes a couple other projects with some competitors have about two-thirds of that volume is being taken away. So we're more than getting our share on that front. The TEMAX project is moving forward full steam ahead and that's about a $700 million project that is part of our plans for the next couple years.

Okay, great. Also, if you can just talk about the correlation going from the 40% range up into the 55% range, what do you think is going to be driving that?

Well, I think you've started to see a little bit of that move. I think the fact is, Ross that oil prices weren't moving and haven't been moving on much to do with U.S. domestic productivity, where NGLs, which is largely used here in the United States are driven by what is happening in the petrochemical industry and to the manufacturing industry. So I think what you're starting to see is the impact of some growth or maybe we should say less decline in manufacturing here in the United States, therefore, the need for the natural gas liquids, particularly ethane and propane. And also, you're seeing impact of things wearing off the inventories that were built up after Ike last year. So those combined are starting to move the NGL prices up in that $0.90 range. So again, the fact that we're saying $70 and 55% for next year is really just math, I guess if you had a different view on oil price, the NGL correlation would just move up and down.

And Horn River, that will be done at Spectra, I assume, not at DCP. DCP is just lower 48; correct?

Absolutely. Remember in Western Canada, its all fee-based businesses. So just like our pipeline operation, the processing in Western Canada is built upon reservation charges for the plant. So it's not driven by the volumes on any particular day. It's driven by producers' long-term view, and in fact in the third quarter, we saw contracted volume revenues go up in Western Canada, even though I think the actual volumes we processed in Western Canada were down slightly. So I think that gives you good insight on what processors are thinking, what producers are thinking, they'd like to make sure that they've got processing capacity, which I would argue a lot. I think it's pretty clear we've got the best position in that regard, and so they're signing up for contracted volumes.

Your next question comes from the line of Matthew Aikman with Macquarie.

First of all, Pat, I wanted to ask you about your comment on the 100% renewal rates on, I guess, is that Texas Eastern is my first question? And second part of that question is, were those still at max rates?

They were still at max rates, yes.

Matt, it's Greg. That's both Texas Eastern and Algonquin.

How do you guys, kind of, account for the fact that producers or customers generally shippers are renewing at those rates and to that extent given weakness lately in the natural gas market?

Well, a couple of things on that. First of all, our customers are both producers and LDCs, right? So the LDCs can do a lot of things, but not run out of gas in the middle of the winter. So it's critical and as we hit 10 out of 25 peak days last winter that they've got the capacity, they're also thinking long term as well. They need to have that gas available to them and short-term fluctuations in the price of natural gas aren't going to change their long-term view about that. I think that it's also the critical position that Texas Eastern has to feed that northeast market, that last mile, that critical position is very difficult to replicate. And so people want to make sure that they maintain capacity on lines into those large markets. I mean look throughout the Northeast, even with the economic challenges, you continue to see more gas-fired generation. You're going to continue to see the more use of natural gas for a variety of products, and therefore, people want to make sure that they have capacity into the region. So, I think that's what you're seeing when people sign up at max rates and see 100% renewal type rates.

Okay, thanks. And my next question is more, I guess, of a strategic nature, and it revolves around the use of the master limited partnership, the cost of capital on the Spectra partnership, Spectra Energy Partners, and pretty much all the MLPs has really dropped. And I'm just wondering if that's changed your strategic thinking at all in terms of how you use that vis-à-vis your own balance sheet?

It hasn't changed at all for the following reason. We've always looked at our MLPs as a financing vehicle, and we use them when there's a better cost of capital. Obviously earlier this year, where Spectra stock price was, it was an easy decision to see Spectra Energy Partners buy the Ozark Pipeline. You know today, you look at it and maybe it's a bit of a wash in terms of the cost of capital. It has, obviously, a higher yield than we do, but you know, then anything you have to look at the debt costs too, what MLPs look at. So, whatever the best cost of capital is at that given point in time, we'll use it and the same at DPM. If the cost of capital advantage is with the MLP, we're going to use it and you know SEP, obviously, I think has the lowest yield of any of the significant pipeline MLPs out there. And so, it's in a pretty favorite position to be able to react as those opportunities come forward. A key with SEP is we want to keep that in the pipeline and storage fee-based business, so we can see steady growth not only from organic opportunities, but also through acquisitions and then DPM is focused on the processing business.

Okay, my last question is I guess maybe for Pat. It's around your own balance sheet and the weakening of the Canadian dollar last year caused the equity issuance, but now things have gone the other way and Canadian dollar has really strengthened, so do you see Spectra as having excess capital on its balance sheet that might be available for acquisitions?

I wouldn't say excess capital. I think we're very well capitalized, Matthew. We issued about $1.8 billion in net securities this last year including an equity offering. Our debt-to-cap has come down from 62% to 57%. We've got about $2.3 billion in net liquidity available to us, and so we're very well positioned to make acquisitions. As we talk about it, there is (inaudible), the challenge, of course, is getting you know, meeting the sellers' expectations for multiples on pricing and getting realistic price expectations. But from a balance sheet and a capitalization perspective, we're very well positioned.

Your next question comes from the line of Carl Kirst with BMO Capital.

Just looking up at Alberta, the comment was made about certainly the volumes through Empress being lower, I guess field receipts are also down about 1.5 Bs, but is there any estimate of how much that volume drop has impacted the quarter?

I don't think it had a big impact, Matt, in the third quarter. I think what we're focused on and why Pat made that comment is really what will the impact be on next year as we said we feel pretty good about the budget for this year with respect to Empress. I think the thing to watch for is for next year what the impact will be vis-à-vis volumes going by the plant. I think the Empress area there, as you know, we're just one of many plants typically seen kind of 6 Bs a day kind of passing by and I think that's more in the 4 billion cubic feet and 5 billion cubic feet right now, so will that continue? Obviously the prices in the third quarter I think ACO were sub $3 and now they're just sub $5, what the impact of that will have, all those are going into our thinking as we finalize the forecast for next year.

Fair enough. Pat, if I could just get some little more detail on the U.S. Transmission side, you had broken out what the delta was as far as the change of capitalized costs. You also have the same delta or what the number was for the actual NGL component as well?

Yes. The offset for lower processing earnings was due to lower pricing and volumes and that's a total about $26 million; $20 million of that is due to price, $6 million is due to volumes.

And I'm sorry that's a delta or that's actually what was realized in the quarter?

That's the delta.

That's the delta, Okay. And then you guys got most of the questions already answered for me, but then maybe just one other not as if you need a new area or new opportunity with everything that you have going on. But as you maybe go back to British Columbia, it looks like we've got a lot of liquids rich gas coming out of the Montney as well. Clearly, you guys have the competitive advantage in Horn River, but you also have this great skill set. I mean is that also an area that you're evaluating or just for various reasons it's more kind of Horn River and then down Eagle Ford, Marcellus, et cetera?

No, that's actually, Carl, good point. The Montney is an important region for us. In fact, West Doe I, II and III, which will come on this month are all Montney based and you know you see the Peace River pipeline is all that's Montney based. So I see the opportunities throughout and as you point out, we have a very strategic position there well placed to be able to take advantage of the growth. So in some respects, you know just like in the United States and Canada, the shale plays have gone South to North in terms of development and that's what you're seeing going on. So you're actually seeing some of the Montney play has already kicked in and I would hope and expect the guys running that operation, Doug and the gang out there will definitely secure some more projects in that region as well.

And if I could just a sort of last follow-up on that, Greg, would you care to rank order, perhaps what you think, you know as you look out beyond 2011, I mean you've got a you know whole slue of areas. You know was it kind of as you listed Marcellus first, Florida second, BC third, or would you shift that a little bit?

Well, I think the great thing about our footprint is that in any one year, not all of them are actually the big capital spend. For example, in the last couple of years, most of our capital spend has been in Florida or the Southeast, shall we say, and in Ontario. In the next couple years, 09 and '10 and perhaps '11, you're going to see much more in western Canada and the Northeast. And so the great thing is at any one point in time with our set of assets, we see opportunities. So I don't think it's an either/or, I think it's as producers and customers look at their own opportunities the timing could make all of them run but typically you see one or two doing well at any point in time. Our issue, you know, you're going to spend about a $1 billion a year. Last year, we spent actually a $1.8 billion. Let's make sure we do projects that have consistent good returns and we deliver them on time and on budget. And I think having done 42 projects in the last three years, we've learned a lot that perhaps we may not have learned if you only had three or four projects. So I think the real advantage is that multi-geographical base and the ability to do many projects well that really give us those returns.

Your next question comes from the line of Faisel Khan with Citi.

Just a following up on the Empress volumes, so is it fair to say the sequential decline in Empress Inlet volumes from second quarter to third quarter was more a result of gas pricing around the ACO hub? Is that a fair statement?

Yes, I think that's fair. I mean to the extent that western Canadian producers you know either shut in stuff or just lay down rigs, I think that's entirely fair. As you know, TransCanada pipeline that goes by there saw big declines in volume throughput. So I think that's fair. How that all shakes out next year? I think given the volatility and commodity prices this year, we'll just have to see, Faisel, what the impact is for next year.

And then on the steel services side and this looks sequentially volumes went up both in terms of NGL production and gas gathering process. Just curious what's driving that because obviously prices came down in the third quarter.

Yes, the important thing to think, I mean basically, they were about flat, but you're right. You see some uptick. But remember last third quarter we had Ike and so that had an impact on volumes. And so you know I think if you look Q2 to Q3, they're probably pretty flat.

Okay, got you. And then I guess in terms of what you guys are seeing in some of these areas in the panhandle of Texas and then Oklahoma, there has been a fair amount of activity, especially kind of wet gas. What's your excess capacity to process liquids and gas in that kind of panhandle sort of central area of the U.S.?

Well, I don't know if I have a number for you off the top of my head, but maybe we can get you something for that. I think if you look in areas like Eagle Ford and stuff there is probably a couple hundred million a day that we have in terms of capacity. But you know what I feel very good about the position that DCP has that anything that producers need for us is that we're going to be able to put it through our plants. And you know, DCP, while it does not get any cash and in fact, it gives cash to the shareholders both us and Conoco, it continues to tap CapEx itself. And, in fact, it's CapEx run you know between $350 million and $400 million. So it's continuing to pick up capacity and tie-ins as well.

Great. And then just on the favorable tax settlement, how much of the kind of tax rate going from 30% to 20%, how much of that was a favorable tax rate?

About half of the improvement relates to favorable tax settlements and the other half relates to the fact that our business mix you know has changed. For the first two quarters, we were using an effective tax rate closer to 30%.

Right.

And that was reflecting our budget for the year which had a significantly higher contribution from field services than has turned out to be the case. So in the third quarter, we made an adjustment which kind of looks at the whole year and says where do we think we're going to come out. We still feel like we're going to be in the 29% to 30% range. We saw this quarter a $45 million contribution from field services which was double the $24 million that we earned in the second quarter. So an improving trend there and still feel like our tax rate will be about 29% to 30% for the full year.

Got you. And does foreign currency have kind of any impact on it, clearly, if you're getting more of your earnings on the Canadian side of the border then and that will flow to the bottomline. I'm just trying to conceptualize that to some degree.

No, it has a net income impact within the translation. It shaved about $3 million off our Canadian earnings for the fact that the Canadian dollar wasn't quite where we budgeted for the year. But it doesn't really affect our tax rate.

Okay, got you. And in terms of your EPS, your kind of EPS looks into next year up to 20% to 25%, what's going to be the mix of, I know clearly some of that is a lot of commodities, but a lot of it also is growth projects that you guys have outlined in your presentation. In terms of the growth projects coming online, what's the mix between your expected mix of earnings between U.S. and Canadian projects?

Well, I think, Faisel, until we kind of get all of the numbers finalized, I'll hedge with you and say give us the opportunity to come back in February and I'll lay that all out for you.

(Operator Instructions). Your next question comes from the line of Mark Caruso with Millennium Partners.

Hi, guys. Just two quick questions, one is more of a clarification but Faisel asked most of my text questions, but I just want to make sure that I heard you right. So as far as we think about for 2010, should we think more of a normalized mix in terms of for the tax rate for next year until you give us clarity?

Yes. I continue to assume about 29% to 30% for next year with a restoration of a more normal business mix.

Okay, great. And then the last question I have is just about M&A. Both you and Greg talked about M&A a little bit and you said that you know there is some of the expectations around multiples, but one thing I'm curious about is your partner at DCP has talked about asset sales and I was wondering as you sort of look across the landscape and look at midstream and pipeline opportunities. If there was something to happen there, how that would factor into your thought process?

Well, you know, obviously, I think Conoco is better to speak about what they're interested in doing, but I'm sure not aware of any interest they have vis-à-vis the processing business. I'm very pleased with them as a partner, as a 50/50 partner. Obviously, we're not really looking to up our commodity exposure. But vis-à-vis other opportunities they maybe looking at, you know pipeline is obviously that's our right in the fair way, so we'll look at that. But as you mentioned, you know price is always the factor here. The great thing is we do not need acquisitions to get the type of growth that we're seeing. That will be incremental or we can do it to the bottomline.

You have a follow-up question from the line of Carl Kirst with BMO Capital.

A clarification on the interest expense. Pat, this year, we're tracking about $80 million under 2009 guidance. I was just wondering what was behind that if that was kind of a capitalized interest issue, if we were just having better rates than what was originally baked in the guidance, but just trying to get a little more color.

No, it's not really around capitalized interest. It's the fact that while we have higher long-term debt balances we have significantly reduced short-term debt balances. We have very little commercial paper outstanding. Part of that was helped by the equity offering earlier in the year, but our cash flow from operations has been very strong. And so, it's really just lower short-term debt balances and lower interest rates.

(Operator Instructions). And we have no further questions at this time.

Okay. Thank you very much for joining us on the call today. We appreciate it very much. I want to remind you that next Tuesday, November 10th, we're going to be in New York for lunch and on Wednesday, the 11th, we're going to have a gathering here in Houston in our offices for breakfast. So we'd be very pleased if you could join us at one of those occasions. And if you haven't already done so, I'd appreciate it if you'd RSVP. With that, we're going to look forward to seeing you next week and thanks for joining us today.

Ladies and gentlemen, this concludes today's Spectra Energy third quarter 2009 earnings conference call. You may now disconnect.