Sempra (SRE) Q1 2012 Earnings Report, Transcript and Summary

Good morning, and welcome to Sempra Energy's 2012 Analyst Conference. I'm Steve Davis, Vice President of Investor Relations and Corporate Communications. I'd like to thank those in attendance with us here in San Diego, as well as those of you who are joining us by webcast. We want this to be an interactive conference, so our webcast audience will also have the ability to ask questions via the link located at the bottom of the webcast screen. Before getting started, I'd like to remind everybody that presentations we'll be discussing today contain forward-looking statements within the meaning of the Private Securities Reform Act of 1995. Actual results may differ materially from those discussed today. The factors that could cause our actual results to differ materially are described on this slide and are further discussed in the company's reports filed with the Securities and Exchange Commission. I'd also like to note that the forward-looking statement contained in these presentations speak only as of today, March 29, 2012, and the company doesn't assume any obligation to update any forward-looking statement in the future. In addition, some of the financial information we'll be discussing contains non-GAAP financial measures. In accordance with Regulation G, you'll note that we reconcile these financial measures to the most directly comparable GAAP figures and you'll find that information in the appendices of the financial and U.S. Gas and Power presentation. We've got a lot of information to cover today, so let me begin by introducing Sempra Energy's Executive Chairman, Don Felsinger.

Let me also add my welcome to those on the webcast. And for those of you here in the audience, thanks for making the trip to San Diego. Your time is valuable and we appreciate the effort that each of you have made to be with us today. Those of you that attended last year's conference may recall that I told you that our board was engaged in a succession process in light of several planned executive departures. And that was Neal Smalley, who was our President and COO, was leaving at the end of last year, and Darcel Hulse, who was the CEO of our LNG business is retiring next month, and then my retirement coming up the end of this year. And today, I'm pleased to be able to report to you that we've completed a very seamless leadership succession process for all these positions. And to me, that just exemplifies the quality and the depth and the breath of Sempra's management pool. As a management, we take our responsibility of providing our employees an opportunity to learn, to grow, to be challenged, exposing them to different parts of the business. And we do this to ensure that we have a depth of leadership succession for management. And the Board of Directors has a similar oversight. But with respect to the CEO position, and they want to, see that have management talent that's developed, that they want to be able to assess the progress of that management development and look at what there is available for CEO succession that's within the organization. And Sempra's board, unlike any other board that I've been exposed to, takes this process very, very seriously. And I can speak firsthand about this, because I went through a very rigorous process in 2005 when…

Thank you, Don. And I would be remiss if I didn't comment on what Don has brought to our company. Don talked about when we first met during the time that we were forming Sempra. And it was his vision and his view of Sempra being more than just 2 utilities that really got us to where we are today. He was very focused on growing our business and doing that in a way that we managed risk effectively. And I think if you look at our history of TSR performance, he can take great pride in the leadership that he provided to all of us in his tenure as CEO, and before that, of leading our global businesses. On a personal note, and sometimes people say it's very difficult to have the person who was your predecessor stay on, I would say that in Don's case, he has been an incredible mentor to me, and I greatly appreciate that. And we all are going to wish him well later this year in his retirement where he can go and enjoy himself. So thank you very much, Don. Now I'd like to begin our presentations for today and start with an overview of the areas that we're going to be covering. And I'll start with a high level presentation on our strategies and our key focus areas and priorities. And then, we will have the California utilities come up and do a Q&A session. After that, the international utilities come up with Mark Snell talking about LNG, about our energy infrastructure business and the opportunities for MLPs and do a Q&A. And U.S. gas and power led by Jeff Martin doing that. On the whole opportunities with our North American renewable business and our Gas business. And then George and…

Thank you very much, Debbie. Thank you for that introduction, and I'm pleased to be with you this morning to talk about the Southern California Gas Company. So this is what I'm going to cover today. A brief overview of our business, what we've been able to accomplish in 2011, then I'll provide an update on 3 of our most important regulatory proceedings. And those are our Pipeline Safety Enhancement Plan, our general rate case and the cost of capital proceeding. I'll provide an update of our 5-year capital plan, and as part of that, discuss the major projects that we'll be working on over this period. And finally, I'll bring it together and provide a financial outlook for the company, and then Jessie Knight and I will take questions and answers after Jessie's presentation. So let me first just provide a brief reminder of the gas company. That's the nation's largest natural gas distribution utility covering about 20,000 square miles, serving over 21 million consumers to nearly 6 million meters. And we've been providing safe, reliable and low-cost service to our customers for over 143 years now. We have some substantial storage capacity, 134 billion cubic feet in our territory of working gas, which provides us system flexibility to meet our customer demands. And our existing infrastructure and access to large customer base positions us well as demand for natural gas will grow as prices remain historically low due to some of the shale gas that Debbie mentioned and the economy begins to improve. As a reminder, in California, natural gas is the primary fuel source for heating our homes, serving more than 90% of the homes in Southern California, and that's our primary fuel for generating electricity with more than 50% of the total electric generation coming from…

Thank you, Mike. Good morning, and it's a pleasure to be here with you here today. First off, over the next half hour, I plan to give you an overview of SDG&E and review our recent accomplishments and outline our strategic direction going forward and showing how we are very positioned well for future success. From a financial perspective, we continue to experience excellent results and we expect to continue that trend. Our management team and our employees are committed to our vision and we are able to strategically execute that vision by making smart, prudent investment decisions and delivering on our major projects on time and always on budget. The execution and implementation of our projects leads to operating excellence providing a safer, more reliable and more efficient system to serve our customers. And finally, I plan to discuss SDG&E's role as a leader in the utility sector for technological innovation, which has positioned us well in the changing electric and natural gas industry. But first, let start off with a brief overview of our company. SDG&E's business reflects the distribution and transmission of approximately 20 million megawatt hours of electricity and 47 billion cubic feet of natural gas to over 3.5 million consumers from the southern portion of Orange County to the Mexican border. Essentially, all these consumers now have smart meters, that is about 1.4 million electric meters and 900,000 gas meters. Our rate base has grown to over $5 billion in 2011, with an additional $2 billion in construction work in progress, a significant portion of which relates to the Sunrise Transmission line, which is scheduled to be placed in service during the middle of this year. The composite of rate base reflects the growth in our electric transmission business, regulated by the FERC, which is…

I have a general question as it pertains to the customer rate impact assumptions because de-coupling is such a big aspect of how you set rates. Really, my understanding is that over time for you guys to be able to socialize all these investments, you've got to have population growth. So there has to be some assumption that overall customer base continues to grow, so that you can hopefully spread the cost of a lot of the fixed infrastructure over a wider base of customers. Can you talk about what your demographic assumptions are in terms of underlying customer growth, population growth, your base case California economic assumptions as it pertains to the rate impacts?

Well, for customer growth, for SDG&E, it's about 0.6% as compared to last year was 0.5%. So we'll have about 8,000 new customers on the electric side. And so the -- it's not so much population growth that is a big contributor for how we are managing this, it's really the portfolio of options as I described in my presentation that will help us drive our cost down by becoming much more efficient and utilizing the technologies that are evident, that are being introduced in this business, for us to become much more efficient to help get rates down.

Let's not forget that for the gas company that for the last 4 years, our customer count growth has been less than 1% a year and we're forecasting that to continue for the foreseeable future.

Michael Goldenberg, Luminus Management. Looking at your assumptions, SoCalGas is very clear as to how much of net income comes from incentive mechanisms. I did not see the same kind of disclosure for SDG&E. Would you be able to shed some light as to what you see as levels of earnings above authorized and where it's coming from?

Right. For SDG&E, the incentives are not as robust as we had in the past. It's about $2 million in the plan as compared to -- we had $14 million last year, for example, for energy efficiency. The majority for us is really driven by AFUDC equity earnings on CWIP. So that's the difference that you'll see there and operating efficiency, obviously too.

Faisel Khan with Citigroup. Just a couple of questions. On SoCalGas, the levels of incentive mechanisms that you talked about, I think, $5 million to $6 million seems a little bit lower compared to the past. Why do you think that number is going to be lower going forward than what's in the past? I got a couple of other questions.

Okay. The incentive mechanisms for the gas company, the 2 major components are our gas cost incentive mechanism and our unbundled storage, both of those provide opportunities for rewards for our shareholders if we're able to be the benchmark. And the first one in buying gas less than the benchmark and the second one is selling storage. Both of those markets are depressed given the pricing impacts that we've seen lately. It's -- in fact, it's just harder to beat an index when the buy-dollar amount when the price of gas is low and as you know, the value of storage has declined recently. So those 2 drivers are reducing our opportunity for profits in those mechanisms.

And then SoCalGas, again, you talked a little bit in your prepared remarks about the cost of capital proceeding later this year and how you're going to try to include in that proceeding the increased risk of operating a gas utility. Can you talk a little bit more about that and how you guys are proposing to make that part of the proceeding?

Look, clearly, the risk of the operating a gas utility has changed. Go back a couple of years and ask yourself what probability would you have assessed in a gas distribution company in California would have a shareholder loss over relatively short time that exceeds the rate base of their transmission system. I think you probably would have assigned that something close to 0. But it looks like given what happened up north that, that's likely to happen. The continued to mandate for greater and higher levels of safety, I think, point to a clear direction that we need to entice shareholders to put money into our company for these important investment. We can't mandate that you invest in our company, we have to invite them through an adequate rate of return. So I think when you look at the cost benefit trade-offs, there's no doubt that the risk -- the gas risk is higher and therefore the return should be higher. And I will also point out that the current rate of -- authorized rate of return on equity of the gas company is the lowest across the state. It's traditionally been a little bit lower than where the electric companies are. Today, there's no reason for that -- there to be a difference there.

Okay. On SDG&E, 2 questions, the FERC ROE process that takes place in 2013, what are the risks that, that number goes, I guess, the downside, it goes down or the risk that it goes -- the benefit, it goes up? Like what's going to drive that process? And then the last thing on SDG&E, is the renewable energy mandate in the state, are you seeing any sort of political friction from consumers or customers that, that should slow that down at all?

Okay. The first one on the process for the FERC, the same rationale for the business in that, for the FERC and the PUC to look at what are the risk inherent in this business and what is the right level for -- and ROE and so the same considerations would be there, the same case is going to be made in both proceedings. As far as political friction on renewables, I think it's just the opposite. I think consumers are clamoring for more renewables. There's a talk about even trying to increase the level over the 33%, which we're not sure that's going to happen. But nevertheless, we don't see that, that interest on the part of consumers and our regulators and policymakers that that's going to wane anytime soon. I see fewer hands because I think we answered so many questions last night.

Greg Reiss of Catapult Capital. Just really a quick question to clarify, when I look at the rate base slide, when you showed the ranges there and then the dotted boxes for the CWIP. Do those ranges included the CWIP or is the CWIP on top of those ranges?

Yes. It's in the range.

It's within the range. And the same thing with the earnings? The earnings include the AFUDC?

Yes.

Winfried Fruehauf, W. Fruehauf Consulting Limited. Two questions. Debbie provided estimated earnings growth rates for the California utilities and for Sempra International, but she shied away from disclosing expected growth rates for U.S. electricity and gas, what is that rate or the range?

The rate of electricity gas earnings?

Yes.

Okay, we're showing 7% to 9% growth now. Well, earnings, I think, is 8.8% if you look at it specifically.

I'm talking about U.S. gas and electricity.

Oh, that I don't have. We can give that to you. In fact, it may be covered in Jeff's presentation.

Second question is why is SDG&E's expected earnings growth rate so much lower than the expected rate base growth rate?

I think it goes back to, I think, something that everybody has to pay attention to is that there's 2 segments of our earnings. One is we have so much in the construction work in progress, in 2012, about $1 billion, the earnings off of that has to be combined with the rate base. If you add those two together, you will see that, that's in line with our earnings CAGR. Okay. I think we're good.

Okay. Now I'd like to ask a Mark Snell, the President of Sempra Energy, to come up for the next part of the presentation.

Okay, good morning. Change of role here for me, being President. Used to be when it goes, my spot always stood between you and the bar. Now I stand between you and lunch. So I'm not sure that's better. Okay, what we're going to talk about today is really -- I first want to start off by kind of going through our new structure. I knew Debbie touched on it. I'm going to give you a little mapping of how we got there. And then the other thing that I want to talk about today, too, is part of the process that we went through. Debbie had talked on the conference calls earlier this year and also mentioned that we went through a fairly rigorous sort of evaluation of our assets and what we thought fit and what didn't fit, and I want to talk about those and kind of where we are in that process. And then lastly, I want to talk about liquefaction and what the opportunities are for that. And then at the end of the presentation, I'll take questions on liquefaction and on some structural things that we're looking at, mainly the MLP. But specific questions on the Gas business or the International business, we'll take those when -- after Jeff and George have finished their comments later today. This is a slide that you saw before, what our new operational or organizational structure is. And I would say that first and foremost, what we wanted to do here was we wanted to realign the company in a way that we thought that we could best most effectively manage the businesses. And then a sidelight to that is that we really wanted to be able to distinguish between our foreign earnings and our domestic earnings. And…

Winfried Fruehauf, W. Fruehauf Consulting Ltd. Regarding LNG exports, can you please explain to me why the suppliers of LNG, current suppliers of LNG to Cameron and other North American LNG terminals like for example the one in Canada, why would they want to partner with you when they have the choice of exporting the LNG simply to a different market, having regard to the widening of the Panama Canal, which will allow much larger vessels to transit that canal?

I guess I'm not sure I understand your question. Why would who want to partner with us?

Whoever supplies Cameron. And I know who supplies the Canadian LNG terminal. Why would these suppliers come out of Trinidad, essentially? Why would they not simply redirect the LNG production without joint venturing with you?

They may want to redirect, but it's not those suppliers that really would be our customers. I think the suppliers that would be likely to be customers to the Cameron LNG liquefaction facility are people like the Japanese that are end users. There are also people that have global LNG markets, who recognize this as being one of the cheaper forms of LNG currently available in the world. That could include BP and Shell and all the majors. Most of the national oil companies are looking at this. The success of this facility is not going to be -- right now, it's certainly not the case, but it's looking -- the facility looking for customers, we have lots of customers that are interested in the facility. It's probably the more challenging part. It's probably more the regulatory process and how big of a facility we'll ultimately be able to build.

Faisel Khan with Citigroup. If you can talk a little bit about kind of where you guys are in the process versus everybody else. If you feel like you're ahead -- I'm talking about the project timeline in Page 14. How do you feel you are versus the rest of the guys out there Freeport, Cove Point, Lake Charles? And then I've got a follow-up after that.

I would say -- Shaner is clearly in front of us, in front of everybody. They've captured this opportunity early and kudos to them for doing a wonderful job with that. And I think we all kind of wished we would have started a little sooner. I think we're a little more skeptical in the beginning, and we had to see the market really -- the market pushed us into this as opposed to us pulling the market into it. I mean, we really got so much interest in developing this facility that it prompted us to action. So I think from that perspective, we're -- I do believe we're #2, but I think it's a crowded #2. We've got a lot of people kind of right around with us.

Okay. And then where are we with the political friction? Export, is it -- is this -- we hear banter about it in the news all the time and you see it in the Journal, but what's the reality? And I think we're also recently heard that the DoE's doing some sort of study. So can you kind of explain to us kind of where things are then?

Well, let me tell you what I know. And some of it, I'll try to keep the opinion and just kind of stick with what the facts are. The DoE is doing a study. They're expected to come out with it. There's rumor in the market that it's going to imply, sort of, an 8% to 12% upward price pressure on natural gas, if we were to export something in the neighborhood of 8 or --excuse me, I think it's 12 million to 15 million metric tons a year, something like that. But that said, there is a couple of interesting things at play here. One is there's kind of 3 outcomes for this as we see it. There's full sort of export capability, full non-FTA country licenses and probably granted on a fairly large scale basis. That could happen. That would be great for the natural gas industry. It would be great for employees that work in that industry. It's a huge uplift for the natural gas business. After that, you could have something that's something reduced, maybe that's kind of -- sort of 1A. You get full export capability, but it's capped at some number of metric tons per year. We think we're far enough in the queue that we would get some of that. We really believe that we would. But that's a possibility. The other possibility is that we only are allowed to export to free trade countries with the special exception for Japan. Somehow Japan gets -- because of their problems with their nuclear fleet and the fact that the world would like them to be nuclear free, they need to export -- they need to import a whole bunch more natural gas. And I think the U.S. special relationship with Japan will come into…

To follow up on that. Are you in exclusive negotiations with counterparties right now, only you and the other counterparty? And then just one question on the self [ph] cavern storage, does that mean you guys are injecting base gas, but leaving compression kind of to a future investment later on?

Let me handle the first one first. I'll take them in order. We're not in exclusive negotiations with everybody. Once we sign CDAs, these commercial development agreements, then we will have binding -- we will be bound together and only in negotiations with them. But most of the negotiations will have been completed. But we're talking to lots of parties right now about these, and we expect to sign CDAs, as you said, like I showed you on the timetable. With respect to storage, what we're not doing is, we're not paying for a lot of compression, which actually increases the number of turns in the facility. So we're -- but we still have base gas cost, that's still part of the development cost. It's just that we don't have the extra money for compression. Does that answer your question?

Just a couple of questions. One, is the $300 million your portion of the net income or is that the overall facility?

Our portion.

Okay. And then the second thing is, can you talk about what kind of JV partners you're looking for?

We want our partners to be our customers. So we train same people.

And any kind of sense on...

On who they are?

Big producers. You have that...

No, we're not going to tell you, but you can guess. It's small universe.

And then the cash flow from this facility, would that be significantly more than the earnings?

Well, it's a $6 billion facility with -- plus our $1 billion to $7 billion, call it a 40-year life. Depreciation is a big difference and the interest on the debt. If you add those 2 back, you can come up with EBITDA. I would do it for you, but I can't do it quick in my head.

Greg Reiss [ph]with Catapult. It seems like -- I guess your view on low natural gas price environment is driving this LNG export facility. Just wanted to see how you guys reconcile that with the kind of a robust outlook you guys have on the renewable business. So it seemed kind of counterintuitive with low gas prices usually being a headwind for renewables.

Look, I think -- we believe that the renewable program, and Jeff will get into this more after lunch, but the renewable program right now, especially in the West, is driven more by mandates than it is by economics. It's not to say they're the best economics -- renewables compete on economics against other renewables. Clearly, they're not competing on economics against natural gas. Now that's primarily a California phenomenon, which has had a higher target. But even all the states have some minimal targets in the West, or at least most of them do, that are driving renewable development. And I think one of the reasons that we've been more successful, especially on the solar side than others, is because we have really -- we've been able to be the kind of the low-cost renewable provider because we have existing land positions. We're not dealing with the BLM [ph] or a bunch of government programs that delays and had a lot of issues with trying to get things done. So we had our own land. We've been adjacent to our current generation facilities. That's where our land is. So we have all of the energy infrastructure, the transmission infrastructure in place, so that we felt we had a cost advantage. And I think we've been taking advantage of that and then kind of a low-cost renewable provider. We're not trying to compete with the natural gas-fired generation.

Larry Alberts with Columbia Management. This goes back to one of Debbie's charts and has to do with the goals and initiatives for 2016. So I make sure we get this answered a little bit. It says larger U.S. facility footprint with adjacent energy infrastructure growth opportunities. Could you expand upon that a little bit?

Sure. I think one of the things that we realized as we did kind of our strategic review and looked at where we've been successful and where we haven't been successful, one of the things that did kind of come to our attention and it was fairly clear and obvious was where we have a utility footprint, we tended to do very well around that area. We had a very good understanding of the infrastructure. We had a very good understanding of customer needs. We had a very good understanding of the regulatory model. And we tended to be very successful even on the non-utility side, if we kind of focused in that footprint. One of the things -- we have Mobile Gas in Alabama. We've been doing some things down their trying to -- we did a little acquisition recently to expand the footprint. I'm just using that as an example. It's not necessarily the only example. But we did this small acquisition, and people may have said, well, gee, that's just a little tiny LDC. Why would you do that? Why would you add that to Mobile Gas? But we started looking at that and we looked at what the needs were in that area and there's a lot of munis in that area that need power, and they're looking at natural gas. And if we have one power plant located in that little LDC, one power plant doubles its throughput. So we look at opportunities like that and say, hey, this is something that we can really grow and expand upon. And we're trying to do that. We're trying to do that all over the place. And one of the things we'd like to do is continue to expand our utility footprint because we think that gives us a lot of insight into how market works and how we can really be successful. That's the way we've been successful in the past.

Mark, I seem to recall that when you originally financed Cameron, it was with Sempra debt.

Debt, yes.

So should I think of that asset now as being basically un-levered? Or like how should I -- if you're contributing $1 billion of the assets, you're not contributing the debt because you plan to finance it with nonrecourse project financing?

Yes, you should think of it that way. Because, yes, we would finance it with nonrecourse project financing and whatever debt we originally incurred. We really financed that facility out of cash flow and current borrowings. It is really -- but if you look at our debt position now, it's actually -- our credit metrics over the five-year planning period really improve.

Follow-up question. Suppose there was a significant impact on U.S. natural gas prices as a result of LNG exports, would you and others clamoring for these exports have to overcome the hurdle of just and reasonable rates?

Well I don't know that we have to overcome the hurdle of just and reasonable rates. I mean the natural gas market has been relatively unregulated pricing market for a long time. But I do think if there was -- could the government -- I will put it this way, could the government revoke export permits that they've given if natural gas prices were to spike to an unusually high level and create problems? I think they probably have that authority. I will tell you though that all of the customers that we're dealing with, all of the customers that we're signing commercial development agreements with, they all will take that risk. They will all pay the tolling fee even if they have revocation of their export permits. So what we're -- I think what most people believe and what most commercial interest believe is that once the permit is granted, if it were to be revoked, it would only be temporary due to some kind of unusual nature. But generally speaking, I think most people are confident that they would ultimately be able to continue to export.

What's the interest per liquefaction at the Costa Azul facility?

Great question. It's actually pretty high. That facility is a little more land constrained, so it's not going to be -- we probably couldn't build as big a facility as we can in Louisiana, but there is some real interest. Even though the extra cost of transporting the gas from, say, Permian or the Rockies into Southern California then down into Mexico would have to be factored in, the closer shipping avenue to Asia is attractive. And so I think if, long-term, these gas prices persist, we will see probably some kind of liquefaction, at least kind of 1 train sort of thing, coming out of Mexico too. It has an interesting group of issues because we do already actually have our U.S. export permit, to export gas to Mexico. So that's not a hurdle. We have to get a permit now from the Mexican government to export gas to other countries. We think that's a doable proposition. But we haven't started on those projects, yet, because our main focus has been to get this underperforming assets, Cameron, up and running and make that work and then we'll turn our attention to Costa Azul.

[indiscernible]

There's enough for a small metal liquefaction . If you really want to do something bigger you have to increase the pipeline capacity and that would require FERC permits.

Chris Shelton from Millennium Partners. Just one follow-up. Do you expect one customer for each train, kind of the way [indiscernible] has one off taker [ph] for each train or is there a customer big enough size to take 3 trains on their own?

Well, I don't think anybody will -- we're not talking to anybody that will take 3 trains. There are customers that want more than 1. Some of them want to have 1.5. I do think, ultimately, the easiest is to have 1 train per customer. But it's possible that we could have 2 trains with a single customer or we might have 2 trains, 1 customer taking a greater share of the second train than the other. All of those permeations are sort of in discussion.

Got it. And does that also mean the JV could be with multiple parties or is it probably just the one...

I think if probably the JV could have multiple parties that have percentage interest equal to what their -- how much of the train is they're each taking. It's a little bit open for discussion. Some parties, especially ones that want a really small amount of capacity might not want to make a JV investment, others would have to pick up the slack, I think that's left open right now.

Got it. And then just one quick one on generation. Do we know what the tax basis for the generation assets are?

Of course, we do.

Is there somewhere I can look that up?

I don't know. Well, we can get it to you.

We could follow up.

Yes. We'll follow up. I don't know what it is off the top of my head.

Thanks, Mark. We're now going to break for lunch. We will reconvene at 1:00 p.m. Pacific Time. So this ends the webcast. And for those of you in the room, we're going to be in the same room that we're in last night for lunch. [Break]

All right, let's begin. I was searching for Hail to the Chief music to introduce our next presenter, I couldn't find it though. So he'll just have to have my welcome. Please welcome, Jeff Martin, President and CEO of Sempra U.S. Gas & Power.

Thank you, Steve. You can obviously tell that a lot of people are having fun with me over the last couple of days. In fact, over the break, there were a couple of investors that said, Jeff, how can [indiscernible] a little bit concerned about it. I said, look, I have a thick skin. No problem. It's all in good fun. So a little bit more of a lighter note, I had several canned jokes regarding Michael Lapides, which I used to roll out every year. And Michael ducks the conference and someone said why don't you just use it on Greg Gordon and Faisel. I said, this won't be the same, right? So I'll hold this. One thing I'll just say before I start my presentation is we were talking with both Rick and Steve Davis last night. If there's a magic ingredient to running a successful Investor Relations program, it's typically having a management team behind you that enjoys spending time with investors. If you think about the tradition at Sempra, going back to Steve Baum, I think Don Felsinger certainly took that mantle of making sure that we are accessible and engaged with investors. Certainly Debbie and Joe and Mark and the balance of the team have done that. So when we meet with you in events like this, we have a lot of collective preparation. We look forward to these events. We do road shows throughout the year. We spend time at other conferences. And the fact of the matter is, it makes us better as a management team. So we're very grateful to have all of you here today. And hopefully the conference will live up to your expectations. The outline for my presentation is very similar to what you've seen from other presentations today.…

Jeff, question on the tax credits, the BTCs, ITCs. That slide, does that show the cash received in each of the years? Or the amount that flows through on the income statement?

That shows what's allocated to us that year. It doesn't show the timing of when that is actually converted to cash.

So is that the amount that increases net income by?

No.

So when you say allocated, what do you mean?

So when you put a project into operation, you've earned that tax credit. If you don't have tax liabilities to match it off with, you can't use it in the year in which you allocated the tax credit. You can only use it when you have a tax capacity to utilize it, right?

Okay, I understand. But it is a cash number that you may not necessarily receive from IRS but that's a cash book -- cash bank number?

Michael, let me help him out. For the wind credits, production tax credits, that's going in earnings. For Solar, as you know, we just changed our accounting methods, it's not going in earnings. So that's why -- but some of those are investment tax credits, not production tax credits.

Right.

Investment tax credits, we're generating them. That's the year we're generating them in. You can discount them to when you think we're going to use them. In my presentation of when that might be. I'll be gentle on the discounts coming from treasury, and it's only a few years away.

Greg Gordon. Just to be clear, some of these tax benefits are coming in the form of cash in that year and some are being booked as deferred tax assets in that year and then will be consumed.

Correct.

When you have, like, the appetite to...

That's correct.

Okay. Great. So follow-up question on the gas business. It seems -- to summarize what you're saying around sort of the potential future improvement in returns around some of the assets, mainly storage which it looks to me if I look at the stat supplement, lost money in 2011. It really hinges on 2 things. One, coal-to-gas switching in the Southeast over time driving more demand and getting an LNG export hub in the Gulf. Those 2 things happen, those assets increase demonstrably in value and bottom line is you don't want to sell them here at the bottom when those 2 sort of potentials exist, is that fair?

That's correct. And with the cash flow that you are producing now, Greg, remember you're going from 20 Bcf in 2011, right? To 43 Bcf, right? You've got more capacity. Even though the market prices are depressed, you're going to benefit from having more capacity to move in the marketplace. But your summary is correct. Winfried?

Jeff, are the utilized renewables tax credits included in the adjusted EBITDA?

No.

Okay. Other question I have is on your model solar project. Have you a similar model wind project that you could show us?

Not readily available. But the goal is really to show you that as you think about renewables, and you think about project financing, and you think about whether using the grant or the ITC, for example, you're using the grant on the Auwahi Wind project. I was really just trying to show you that in terms of a capital-intensive business, you're not putting a lot of capital at risk until you have a hedge. And that your cash comes back to you relatively quickly. So you're not sitting out there for 8 or 9 or 10 years which you potentially could even in a regulated investment.

For your operating solar plants, are you expecting to receive payback under 4 years, 4 years or more than 4 years?

Yes. I'm not going to give a generalization. I think we've seen them shorter and we've seen them longer. So I'm not thinking -- it is reasonable to believe that we're going to have simple paybacks across our renewable portfolio between 3 and 5 years, wind and solar, yes.

No, I was just confirming my question to Copper Mountain 1 and Mesquite 1, whether you expect to achieve 4 years of better or 4 years of worse.

And I'm going to confine my answer to the, in general, in wind and solar projects, you expect to have your money return in 3 to 5 years. That's inclusive of all of them, right?

Can you elaborate on what you said about boil-off gas at Cameron? So I think previously because of low utilization, you had to buy cargoes, basically, just to run them through. And what you said you made some sort of technological upgrades so that you no longer have to do that?

Right. Over the last 15 months, we've started a capital investment and a relook [ph] capability. So you really have a very small plant that can really just take your boil-off gas, Leslie, and basically use it, put it back in the tank. That really relieves you from having to go in the marketplace and replace it. Because if you don't, with that boil-off gas moving, the gas inside the tank gets hotter. So it really is something that had a great short, again, similar to his question, very short return of capital for the overall simple payback. And it's something that will be in place before the end of this year. The benefit of which is really enjoyed at 2013. If there are any other questions, there's one more here. And then we'll move to George.

Andy Stone from Tufton Oceanic Energy found in London. Could you expand on the developments that you've seen, the evolution in the solar market and the technologies? Which technologies you expect to use going forward, the cost reduction that's been achieved? And also on the wind side, levelized cost of energy? And how you see that sort of evolving in the future?

Well, there's a lot of question there and I'll try to answer as many as I can. I'll harken back to Debbie's point, which is really kind of our mantra on the renewable side it is, we want to participate in a wider basket of projects with multiple technologies, multiple counterparties. We think that's the right way to go. So it's fundamentally, as a company, not just in our renewables business but including in our utilities. We have traditionally held ourselves out to be technology agnostic. So we're looking for the best fit, lowest-cost opportunities that we think will fit into our portfolio. But I will talk a little bit about the cost side of wind and solar. Over the last 3 to 4 years, we've seen tremendous gains in the cost advantage around solar. And at first they can't take credit for it, Mike Allman was at the Helm [ph] at that time, but they made 2 very [indiscernible] decisions: One was to avoid solar thermal and focus on photovoltaics, because they believe it will come down the cost curve the fastest. The great clarion call. Secondly, they want to avoid really public lands because there's a lot of complexity associated with permitting there and focused on private land utilization. Both of those 2 decisions gave us competitive advantage in solar. In terms of the cost side, you've seen price reductions in panels over the last 2 to 3 years between 30% and 40%. The most interesting thing, too, is you're also seeing 10% to 15% cost reduction on the balance of system. So as panels become more efficient, you're using less land and you're also using less balance of system plant. So the solar side has been absolutely fascinating. What actually takes -- causes a little bit of…

[indiscernible] In 2016, you mentioned that natural gas will be about 45% of your earnings. Could you give us a sense as to how much of that is related to natural gas plants versus the storage and [indiscernible] asset?

I'll let you back into that. I mean, Mark did what we don't normally do, which is he gave us some subsegment guidance in terms of what the gas fleet would do. Mark put out $150 million EBITDA number for the gas fleet. You can kind of partially what that might be in terms of our pipelines. Remember we've got one distribution business today. We're looking to close on our second distribution business in the second quarter as well as our storage businesses. But there's no question, I think, that the big opportunity in the Southeast is that we are participating in different assets with different customers on top of a place where there's going to be a lot of structural change, which I think Greg Gordon summarized correctly. Next, I have the pleasure of introducing someone I had a chance to work with for a long period of time. George has been with the company for close to 30 years. He has worked both at SDG&E as well as a variety of our unregulated businesses. I'm the beneficiary of a lot of his investments here in the United States. And I think George has certainly performed well on the international side. And he'll take you through how he plan to grow our international footprint.

Thank you, Jeff. Good afternoon. It's a pleasure to be here. I'm going to discuss Sempra International business, which is, as this presentation is concerned, is assets in Mexico, Peru and Chile. The outline of the presentation is to talk about the accomplishments from last year. I'll give you a good understanding of our assets in South America and in Mexico. And I'd like to spend a fair amount of time in doing that, because it's always something that's evolving and something that has grown over the past few years. I want to make sure you have an appreciation of what we manage and what we own in these countries. Of course I'll talk about the opportunities for growth that we have, and after, give you the forecast that we have for the outlook of earnings. And after my presentation, Eduardo Pawluszek is going to do a presentation on the regulatory process in Chile and Peru, which of course, is a key component to the success that we've had with these investments in the past 12 or 13 years. And after Eduardo's presentation, we are going to bring up Mile Cacic, who is the CEO of our Peruvian business and Francisco Mualim, who is the CEO of our Chilean business, and they're going to participate in the Q&A, give you a chance if you want to have some questions with them directly about their businesses and about those countries, so you can have a better appreciation of what we're doing in Chile and Peru. 2011 accomplishments. Of course, you know we closed the acquisition of the -- of a controlling interest of what we had in Chile and Peru. This was $775 million that we paid to buy out our partner. This was net of the $100 million that was…

Thank you, George. Thank you, and good afternoon, everyone. The objective of my presentation will be to provide a brief presentation on the description of the regulatory framework existing in Peru and Chile for our utilities as the system is different from what you are used to see in the California utility of Sempra. And I have to say that the improvement in these credit risk profiles of countries where we are jointly with efficient operations that we are running to grow, that George has described. And stable and very predictable regulatory framework has been the key for Sempra's long-term successful in South America. The regulatory rules have been in Chile and Peru for a long time, 31 years in Chile, 18 years in Peru. Chile has been the pioneer in the region and after that, a similar system has been adopted by Columbia, by Peru, obviously. But to a certain extent, by Brazil and other Central American countries. So that's been very, very, very successful. And really in 31 years, we have seen central-left government, central-right, very, very many, many changes. And this regulatory system hasn't changed, has not been touched. Why? Because it works. Because it works and the system creates a foundation for the -- for attract foreign investment and supports the growth and the GDP evolution of these countries for a long time. So I mean, this has been one of the keys and one of the answers on why this system has been so successful. The system itself clearly is divided between Generation, Transmission and Distribution. And Generation is open to competition, while Transmission and Distribution are regulated as they are natural and monopoly. In spite of this division, in fact, the system allows, to a certain extent, to vertical integration. And George has mentioned…

That's Mile, that's Francisco.

I understand that the regulations are a little different from the United States and tariffs are set a little differently. But can you give us a sense of the rate base for each one of the entities and what that ultimately is in return on assets? I understand there's a gap of 6% to 14% as long as it's for everybody, but maybe if there's some specific numbers you can provide?

Depending on the efficiency of your operation, you can -- your return could be over the range or under the range, okay? The key for our success and the range are for returns as what I described before with a medium point and 10% in the case of Chile and 12% in the case of Peru. So it doesn't mean that your particular -- that our particular distribution company cannot really get a good return under that point. As for us, we are efficient and the growth in our geographic area allows for that. 10% and 12% are the levels approved by law as return on the New Replacement Values on the global industry as a whole.

Yes. Because the rate basis is not a critical factor to what we're doing, like we can get back to you on what the numbers are. I don't have it at the tip of my tongue. I will say this though, when we have monthly meetings in Chile and Peru, we start out every meeting what the customer growth was last month and what the gigawatt-hour growth was last month because that's what's driving our financials. So I will get back to you with that information, and again, it's like a different model on the types of things that we focus on in managing that business.

Ted Hine [ph] with Point State. Just a quick question on the -- you mentioned the re-gas or gasification of the western part of Mexico. Could you give us some color on how many Bcfs a day that would be, and how much, I guess, the CFE is -- how the RFP process works, how many -- how much dollars that could be? Do you expect to win any of those or is it in your CapEx, et cetera?

Okay. The market is approximately 1,400 megawatts of steam-fired generation of vintage that goes back in the '60s and '70s. In addition to that, there are specific combined cycle plants that CFE plans to build to enhance what the system can deliver or substitute some of that gas. The bid that they have put out, the 1,200 miles that I mentioned, will be a competitive bid. There will be international bids done, we've participated in these in the past. Typically, there's 2 or 3 bidders involved. The magnitude of the dollars depends on what section of the project you add. There are some sections that are over a mountain in Syria that will be in the range of $3 million to $4 million a mile. There are some areas -- there are more desert areas that are easier to build on that's much less than that. But the overall volume of investment is over $1 billion that -- what the CFE is doing. The other thing that CFE is doing, they're making sure that they're only going to do this once. So they're not bidding an 18-inch pipeline because that's what they have in their plan for gas use right now. They're bidding 30 [indiscernible], I want more capacity than the market is because they don't want to go back in 10, 20, 30 years and redo this again. So the 5 projects, sizable investments, not in our plan.

[indiscernible]

I'm sorry? Say that...

How much [indiscernible]

No, they haven't specifically stated the capacity that they're going to buy. Again, they're going to buy capacity on a 20-year basis, they will buy 100% of the capacity. All they stated, so far, is that they wanted to make sure that it -- they do it once. So the specifics of the bid have not come out. All they've laid out is a schedule on the sequence of these bids. And you can imagine -- what's going to happen is the pipes closer to the border are going to be built first, and they're going to move their way south.

The generation build that you're doing in Peru, the hydro, that's unregulated generation. So is it fully contracted? And if so, what kind of counterparty risk, like who are the counterparties that you would sell the power for? I mean, would you do a 20-year PPA or it's more annual?

Yes, let me give you some points. It's not merchant generation. Because it's run-of-river hydro, there's a certain amount of capacity that is firm, and it's roughly 2/3 of that capacity. And under the law, we can sell that as firm capacity. The off-takers are primarily or solely free customers, these are customers that are buying only transportation service from Luz del Sur but they're buying the generation in the marketplace from other generators because they're big customers -- 5, 10 type of megawatts load. And those free customers that Luz is serving right now, generation and distribution. But Luz is going out and buying that generation from generation companies. So what we've done is, we've come up with a transition plan, where we're transitioning the supply for these customers that we have from market generation to our own generation. And typically, the contracts that these generate -- these large free customers sign go from 7 to 10 years. Mile, do you want to add anything?

Maybe just to add that we didn't consider to have a conventional PPA because that kind of contracts go to satisfy the regulated market where the prices are related. Instead of that, when you go to the free market, you can negotiate the price, the price is free. And obviously, in the free market, the possibilities to get much higher prices are much better. So the plan in short is to place everything that is considered firm capacity and firm energy in the free market. And the strategy is to contract -- and we have started already that capacity and that energy with other generators with contracts that would end in the summer of 2014, dating which the project of Santa Teresa will start delivering capacity and energy. And at the moment, we will just replace the provider from the other generators to our generator.

Raymond Leung, Goldman Sachs. Couple of questions about the utilities being underlevered. Can you talk about what is your target for the right leverage and what that may translate into how much incremental debt would come out of it -- those units? And also maybe just about on the regulatory regime, what's the maximum leverage you could actually put on those utilities?

Okay. In terms of the regulatory regime, you saw the way the rules work. They just provide you on an unlevered return and it's up to you to structure your balance sheet as you want. So there's no restrictions there. I think the second part, obviously, there's an ideal capital structure that we can achieve, but it -- the practical aspect is, it's going to be driven by how much growth that we have. So for example, the higher $155 million for the Santa Teresa Hydro plant is being funded 100% with a local debt on the Luz balance sheet. Because we only have $230 millions of debt. So if local currency, 100% funded, so we're levering up. And we have great earnings from that project, and we're utilizing that balance sheet. So it's going to be driven, the pace of it and how much we do, by the projects that we identify and look forward to. Like same thing in Mexico, right? We have the capability to borrow money and do a lot these pipeline projects that we're thinking of, and because we have no debt in Mexico right now. It's all -- we have some intercompany loans between Sempra, but in reality, no external debt.

Faisel with Citigroup. Just on Slide 11 on your earnings outlook. I just want to make sure that this exclusive is not -- does not include the LNG facilities.

Excludes.

Did it include the LNG facilities or does it...

Excludes.

The 2016 number is -- for $425 million...

Yes, what you see in my 2016 number is Mexico, Chile and Peru. The Cameron impact to our earnings is in Jeff's forecast.

And it's not in here?

No.

What of Costa Azul? Costa Azul?

No there is nothing for Costa Azul in this because we were thinking it would follow what we're doing in Cameron.

Okay. So this is...

[indiscernible] the current, current, the current.

Yes -- No, no, no. The current re-gas contracts in Mexico, in Mexico, just Mexico, is in my forecast, right?

Okay. Right. So then...

I'm sorry. I misunderstood the question.

[indiscernible] This is a fully taxed version, the way you guys have described the repatriation of these earnings, right? So this is -- okay. So this is the -- if I take this number, minus your CapEx, that's the distributable cash flow back to shareholders?

I'm going to ask Joe to step in here.

Sorry. Faisel, I was going to address this in my presentation but I don't want to be confusing. The tax that we're going to incur -- that we're going to book actually, on bringing the dividends back from our international operations will actually be in the Parent line, within the Parent line in your numbers. His numbers are international earnings at each of the 2 South American utilities and in New Mexico. It doesn't have the repatriation tax in it, that's in Parent.

Larry Albridge [ph], Columbia Management. Just going back to the hydroelectric plant in Peru. You've mentioned that about 2/3 of the capacity energy, the intent is to contract that out. Is that a function of just primarily expectations in terms of the resource itself, the run-of-river? And the reason why I'm asking this is it used to be a fine dam back in the '90s and its investments in Peruvian -- excuse me, Chilean generators, and they'd come in and they talk about the adequate resource. And then at CM Next Gen [ph] and said we're negatively impacted by the 500-year drought. It happens once every 500 years and they come in next year and say another 500-year drought. And I ask them, it sounds like a biannual drought or whatever. But the reason being, I guess, is when you go out and contract this out, does that take into consideration potential changes in the run-of-the-river? And also what happens if the resource is just not there, what happens in terms of what you have to do in terms of providing power or weather with respect to these customers? You have to go Let's go to market for it and obviously with that impact returns in markets that you have on that business.

Yes. Let me start and Mile can augment what I say. The facility that we're building is taking now the exit watering essence from a power plant that has been there since the 1960s, so it's the same water. The hydrology data, I forgot the exact years, but Mile can say, so there's long-term hydrology data. But -- and we're being very careful about how much we call firm and how much we -- because we're selling it to free customers. But they exist that, I guess this 500-year event that we haven't seen that you need to go out and replace that power. Part of that is -- part of what we're doing now is looking at projects upstream that would create new generation opportunities but would also enhance the hydrology of the plant that we have. But Mile, you might want to say -- talk more a little bit about the history of the data and our confidence with regards to the firm capacity.

Okay. We have a long story of the flowing that river, it is about 52 years of history. So with those numbers, we have ran different kind of models in order to calculate if the design flow of this plant is within a reasonable range. And just to give you an idea, in that river, this year during the rainy season, it was flowing about 700 cubic meters per second, and our design flow is 61. Besides that, as George have said, we have some reservoirs in the Highlands that are going to increase the flow of water in the dry season. Regarding the calculation of the firm energy and capacity, there is a formula to calculate according to the law, and it considers the worst flow in the last 20 years of the worst day in the worst month in the dry season, and you calculate your firm capacity using that particular flow, which is very drastic. And the result of that calculation is about 62% of the nominal capacity that qualifies as a firm capacity. Therefore, that is the only amount of energy and capacity that you are able to contract through bilateral contracts. The difference will go to the spot market which is very hard to predict what is going to happen in that market because it depends on how much water are you going to have. So I think it's very reasonable, we are reasonably covered.

We have one more question.

If I look at Slide 11 and you guys show that the growth in earnings relative to the capital will be spent over the 5-year planning process, it looks like there's a 17% return on assets from a net income perspective which is a very pretty high return on a fully consolidated basis. Is there anything capital-wise that's going in service that's helping that number? Or any given projects that generates such a high rate of return?

Well, I think the investments that we're making have targeted returns that are in the low teens on a levered basis. So I think that what you're seeing is consistent with that.

All right. We're going to take our afternoon break. It's now about 2:40, we're going to -- we'll be back on the webcast, and in the room at 3:00. Joe Householder will be giving the financial wrap up, and then our final Q&A. [Break]

Everyone could grab a seat, we can get underway. All right, next, let's begin the webcast. Great, thank you. Now we have up Joe Householder, our CFO, and he's going to give a financial wrap up. And then following that, he will be joined by Mark and Debbie for the final Q&A. Joe?

Good afternoon, everybody, and welcome back from the break, and good afternoon, to those of you on the webcast. Before I get started, I would like to thank Steve and Victor, Scott, Lisa, Rachel for putting this conference together. I think they did a great job, it's a nice facility. I did hear one concern about the weather from the golfers, and I heard from good sources that it's going to be sunny tomorrow. So we'll hope so. Throughout the day, you've heard from all of our business unit leaders, all the CEOs from each of our business units how they're going to grow their businesses and all the great projects each of them have to grow their earnings at top quartile rates. And my job now is to tell you how it all comes together on a consolidated Sempra basis. Our financial goals are driven clearly by our strategy. As Debbie mentioned to you this morning, we have an EPS growth CAGR of 6% to 8%. Our strategic review has led us to maximize and optimize our global tax position. This allows us to bring back cash distributions from Peru and Mexico and bring dividends from those international operations to the United States and help us pay a higher dividend. As we've discussed throughout the day, we intend to grow our renewables business and build the liquefaction opportunity with partners and with project financing. And we've also talked about how we're going to explore an MLP structure for our natural gas business in the United States. We're going to do all of this with an eye toward maintaining our strong balance sheet, at a competitive dividend and healthy credit ratings. For those of you who've been with us for many years in the past, this chart is going to…

No questions? That's unusual.

Mark, when you flex the numbers for the sort of the optionality of dropping the gas business into an MLP, so if we look at year-end 2013, everything is going -- sort of best-case scenario in getting, moving forward on doing the 3 trains, and you decide to move ahead, how does that -- what are the sort of the big puts and takes on how that might change the sort of the financing plan and the cash flow profile off this base case?

Well, I think, ultimately, what you would think of is, we would drop the -- we would put our existing midstream assets in and probably fund the MLP at that point if we did it in -- say, late 2013 and early 2014. We'd fund the MLP distributions primarily out of REX, the $85 million or so cash flow a year that we get out of REX and the other cash flow from the other units. And then over time, liquefaction goes forward, the REX contracts taper off at the -- for the end of -- starting in '15 and '16 down the road. And we drop in the liquefaction amount sometimes earlier than that -- probably do it in chunks, mainly because of the ideal size of the market, it's just not big enough to drop in something that makes $300 million a year right away. I think it makes more sense to probably get at optimum price, but it would change our financials a little bit in the sense that we have more cash earlier, the 20% units that we sold. If we sold some of our own units, so we could generate some cash earlier if we need it, had a need anywhere else in the company. But primarily, we'd be doing it to create a vehicle to grow the midstream space. And then I think what we really -- we'd look and try to do is try to continue to have the corporate GP, the general partner, and create value there because as you drop these things in, we would get into the high splits and that's how the Sempra shareholder really gets the juice out of this and it makes sense for the Sempra shareholder.

Two questions. First, no one has really talked about today, and I don't know if this is something that Debbie can talk about or maybe it's for Jessie, but give us an update on what the implications are for an extended outage at SONGS or what's the current thinking there. And then secondarily, with respect to -- something that you brought up, Mark, about the development or the movement towards more gas in the Southeast, you didn't say anything with respect to generation and your aspirations there, if there are any, will be through acquisition or future greenfield development or whatever.

Hey, Bob. Yes, I'll take the SONGS question. As all of you know, we're 20% owner of SONGS, we're not the operators. So Edison is very much involved in doing all of the assessment for this -- and I know they had a meeting yesterday. So I think what they told you yesterday is pretty much what we know relative to the situation at SONGS. The Nuclear Regulatory Commission is very much involved and looking up what the issues are, and Edison is extremely focused, as they should be, on ensuring that this plant is safe before they restore it to service. I think their plans are such, that when they are convinced and the NRC is convinced that the plant is safe, it's when it will all be restored. So they are not doing any kind of projection at all on when that is going to happen. They really got to diagnose the issue and be sure that they're corrected.

I think, 2 things, just tailing on SONGS. Jeff's group, on the generation side, we're obviously looking to make sure -- we're looking at our maintenance schedules on our plants. We definitely want to make sure that we're running in July, in August and September because we could see some higher power prices. But beyond the other issues, too is we want to make sure that we've done everything we can to make our facilities available for customers when we could be short and I think the utilities are doing the same thing. You're seeing that at SDG&E. So everything is -- we're anticipating and working as if we might have a large unit out this summer and so we're taking that into consideration.

I would just say that I don't want to be taken as the best speculation that is going to happen. We go through this kind of process every year in summer planning for resources, and we've had periods of time where we have resources out for periods of time. And we have to plan ahead for that occurring. But I wouldn't want anyone taking away that anything that we said indicated that SONGS is going to be out for the summer because quite honestly, we don't know.

And then with respect in the Southeast, we do think there's going to be opportunities there. There's been other people that have tried to develop power plants in Southern's backyard, and Duke's backyard and hasn't always proved to be all that profitable. So I think, our focus is really helping those munis and co-ops in things that maybe there's a role for us that make sense where we could provide some capital or provide something in exchange for a long-term PPA or something where they can buy the plant back over time. I mean, those are the kinds of things that we'd like to do. But our primary focus, as Jeff said, in that area is growing our midstream business that would feed our MLP. So while a gas plant really helps us grow our midstream business, it needs storage, it needs pipeline capacity and we would really want to try to accommodate those things, our main focus is really on the midstream stuff.

Given the headwinds that Rockies Gas is facing in the Northeast, is there a worst case scenario that would cost cash flow from REX to taper off before 2015?

I don't think there's a -- there's not a worst case scenario. I mean, there's no indication that the fully contracted pipeline that people aren't going to honor their contracts. And I don't think the basis for it is you can get a heck a lot lower for what little is given to this is not contracted. I don't see anything between now and sort of contract expiration that changes things a lot with one exception, we do have -- there is some debt on that pipeline that will have to be rolled over prior to the expiration of the contract. And I don't know what's the -- we haven't had those negotiations yet, so I don't know if -- what will happen or what might have to be paid down or whatever to do that. But for the most part, we don't see a significant impact until well beyond the contract period.

A follow-up. Is there a possible scenario that you might backflow or flow shale gas from the Northeast partway west on REX and reduce the transmission distances from the Rockies, say, to Chicago -- that you can get a better proposition?

There are certain people that are looking -- a lot of people that are looking at that. We think it's a real possibility to flow really from Ohio down to the trunk line up to Detroit and the other pipeline is going up into Chicago. It's a possibility, there's a negotiation that needs to be had with the current capacity holders, because they have some rights. If a different service is being offered and we have to take all of that into consideration, but there's -- I think there's a likelihood that, that happens down the road and it's probably pretty likely really.

Just a follow-up. How much debt is on REX and when is it due?

I don't know the total off the top of my head. Is anybody...

I think $3 billion, yes.

Yes, $3 billion.

All of that is due...

It's -- most of it is -- a lot -- most -- the majority of it is due beyond the contract period, but there is 2 pieces that roll off, one in late 2013 and I think the other one is in 2015.

I just want to clarify that the $3 billion is not our share.

Yes, that's total debt. Yes, that's total REX debt.

Faisel with Citi. On the earnings outlook for '13 and -- for '13 what's the tax rate that we should assume for that number?

For 2012, it's about 30%. And for the later years, it's in the low part of the mid-30s. You can actually -- if you look at my EBITDA reconciliation in the back, in the appendix, you can back into it, the low part of the mid-30s.

Okay. Got you. And then in terms of the timing for a potential filing for an MLP, when do you think it -- you're going to market for that?

I think it kind of depends on where we end up with liquefaction that'll kind of control our timing on it. But I mean, I think the earliest is probably -- I mean, what would you say? Next year, sometime late next year.

Okay, got you. And then just going back to some of your comments on potential acquisitions in the utility space or on your footprint, would those type of acquisitions be company-transforming transactions are more like small bolt-on transactions or how would you -- how are you thinking about those set of opportunities?

Well, I think we're open to either that. I mean, I wouldn't say that our plan is to acquire a whole bunch of work. That's not our strategy as a whole bunch of small, but what we really want to focus on is when there's greater benefit than just synergies. And so if there were some opportunities with our midstream assets and another utility that also have midstream assets, then we could bring those 2 together. And it works for everyone, that might be great, that can also be done in other means besides mergers or acquisitions and we would look at all of that. And I think some of the combinations that I've been announced when there's value creation, other than through synergies, is what we're really looking for. And that was really truly the way Sempra was formed. We have these 2 utilities but the merger of those entities the formed Sempra was largely about not just synergies, but the opportunities to create growth in our other businesses. And so, that's the way we kind of look at it. I think, Dan, we are done with question. I'm amazed because every time I go to the ladies room, I get questions. I just want to thank you all so very much for joining us today, either on the webcast or in person. And I thank you for our -- your interest in our company. I think you can see that we are very enthusiastic about our future and the high growth and the opportunity to return capital to our owners. And so thank you very much, Steve is going to give you the details of this evening.

Thank you very much. This concludes our webcast.