Good day, and welcome to the Sempra Energy Second Quarter 2014 Earnings Results Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Rick Vaccari. Please go ahead, sir.

Good morning, and thank you for joining us. Today, we'll be discussing Sempra Energy's second quarter 2014 financial results. A live webcast of this teleconference and slide presentation is available on our website under the Investors section. With us today in San Diego are several members of our management team: Debbie Reed, Chairman and Chief Executive Officer; Mark Snell, President; Joe Householder, Executive Vice President and Chief Financial Officer; Martha Wyrsch, Executive Vice President and General Counsel; and Trevor Mihalik, Senior Vice President, Controller and Chief Accounting Officer. Before starting, I would like to remind everyone that we will be discussing forward-looking statements on this call within the meaning of the Private Securities Litigation 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 discussed in the company's most recent 10-K and 10-Q filed with the SEC. It's important to note that all of the earnings per share amounts in our presentation are shown on a diluted basis and that we will be discussing certain non-GAAP financial measures. Please refer to the presentation slides that accompany this call and to Table A in our second quarter 2014 earnings press release for a reconciliation to GAAP measures. I'd also like to note that the forward-looking statements contained in this presentation speak only as of today, August 7, 2014, and the company does not assume any obligation to update or revise any of these forward-looking statements in the future. With that, please turn to Slide 3 and let me hand the call over to Debbie.

Thanks, Rick, and thanks to all of you for joining us today. On this call, we will discuss our second quarter financial results and provide you with key operating and regulatory updates. This morning, we reported second quarter earnings of $269 million or $1.08 per share. Together with the outlook for the second half of the year, we expect to be at or above the midpoint of our 2014 guidance. Given our strong operating performance and success in delivering planned projects on schedule, combined with the progress we're making on capturing some of those additional development opportunities, we are on track to achieve our 9% to 11% growth rate through 2019. Notably, our Cameron Liquefaction project has achieved several key milestones, and we expect to begin construction this year as planned. On June 19, we received our FERC order, and yesterday, we executed the financing documents and made the final investment decision with our partners. In Mexico, IEnova is on schedule to place and service the first phases of the Sonora and Los Ramones pipelines by year-end. We are extremely proud that since January 2013, IEnova is the best performing IPO in the Americas and the second best-performing IPO worldwide. In Peru, commissioning of the Santa Teresa Hydro project will begin this month. In the U.S., REX East-to-West loads of 1.8 Bcf per day are now fully contracted. Also, this past week, we signed a power purchase agreement with Edison for a 94-megawatt expansion at our Copper Mountain Solar facility. On the regulatory front, our California utilities received a positive final PSEP decision in June. We are also continuing to work on the development projects that could provide additional upside to our 5-year plan and sustain our superior growth rate. Examples include LNG, natural gas pipelines, renewables and hydro in Peru and we will talk about these projects later in the call. Now let me hand things to Joe to discuss the second quarter results in more detail starting with Slide 4. Joe?

Thanks, Debbie. Sempra's second quarter consolidated earnings were $269 million or $1.08 per share. This compares to adjusted earnings of $258 million or $1.04 per share in the same quarter last year. Moving to guidance. As Debbie just mentioned, we now expect to be at or above the midpoint of our 2014 guidance of $4.25 per share to $4.55 per share. Let me elaborate a bit on what this guidance range includes. Consistent with our development and partnership model for renewables, we include the promote we recorded on the CMS 3 project in the first quarter and the promote we will record on ESJ next quarter for the formation of these joint ventures. We also now include the $9 million additional charge we recorded in the first quarter related to the SONGS settlement agreement. However, we do not include any possible gain on the sale of the remaining block of our Mesquite combined cycle power plant, nor do we include anything for the tax reform proposals being discussed in Chile. Before proceeding to earnings for each of the business units, I would like to also mention one timing-related factor I discussed on last quarter's call. Remember that in the first quarter of 2013, we recorded a $63 million deferred tax expense related to the IEnova IPO restructuring. In the first quarter of 2014, we recorded $12 million of estimated deferred tax expense to reflect a portion of the planned repatriation for this year. We recorded another $12 million of deferred tax expense in the second quarter of 2014. Our estimated annual tax rate reflects the recording of deferred tax expense each quarter in accordance with the full year as planned repatriation. Now let's turn to Slide 5 for details on SDG&E. At SDG&E, earnings for the second quarter were $123…

Thanks, Joe. Now we will give you an update on our major businesses starting with LNG. As I mentioned earlier, on June 19, we received the FERC order authorizing construction and operation of our Cameron Liquefaction project. In July, FERC provided Cameron with a notice to proceed on site separation activities. Now that all FERC hurdles have been cleared, the only remaining significant regulatory step is receipt of the final DOE non-FTA permit, and we expect to receive this permit and begin construction later this year as planned. Yesterday, with our partners, we also executed the financing documents and completed all requirements for making the final investment decision, commonly referred to as FID. Financing commitments for the project totaled $7.4 billion and will be provided by JBIC and a group of 29 international commercial banks, some of whom are insured by NEXI. Cameron received 16-year financing and highly competitive pricing due to the quality of its lenders, sponsors and customers. The transaction represents one of the largest project financings in U.S. history. Now please turn to Slide 10. At our Analyst Conference in March, we discussed our interest in growing our LNG business. We are continuing efforts in this area with an initial focus on expanding existing assets. For our Cameron facility, now that we have reached FID, we will begin working with our partners to complete the development plans and initiate the FERC process for trains 4 and 5. We believe the Cameron expansion will be one of the lower cost alternatives, especially when compared to greenfield development. Our ECA LNG plant in Mexico is also well situated from a market perspective as the only brownfield facility on the West Coast. We are focused on determining the critical path items that would influence the feasibility and size of a…

[Operator Instructions] We'll take our first question from Julien Dumoulin-Smith of UBS.

So first, can we discuss REX here for a second, in the context of what's in the 5-year plan versus outside? Could you give us a little bit of a sense, what does 25% mean, just if you could define that? And then also regarding the non-binding open season, where is that shaking out as far as you've received interest, if you could comment a little bit more, if you wouldn't mind?

Okay. I'll start, and we did put a slide in the package because we do understand the REX issues are kind of confusing. So if I could refer you to the slide and the slide number is 17. I think that would help you understand what's in and what's not in the plan. So let me kind of walk you through that. If you look at the Seneca lateral piece of that, that's 0.6 Bcf, and about 0.25 Bcf of that went into service in June of this year. That piece was in our plan. We expected that to happen. That was in our 5-year plan. But what has now been contracted is an additional $1.6 billion in addition to that, and that comes in over phases. The next phase of that is another $400 million or so that will come in at the end of this year and provide some upside to our plan in next year and beyond. And then the remaining 1.2 Bcf comes into service in the middle of next year. And that is, again, incremental to what we had in our 5-year plan. So this is a really positive thing for us, just with what we have under contract. In addition to that, there was a non-binding open season that was conducted in May, and that we're in negotiations with parties on the results of that. And we will announce the results of that when we've concluded those negotiations which are underway right now.

Great. Is there a timeline on the negotiations?

I would say within the next couple of months, we would anticipate something coming out.

Great. And then...

And again, I would just say, none of that was in the plan. So whatever that is, that was not in the plan either.

Excellent. And then moving back to the LNG side of the equation. Could you comment a little bit on where you stand on incremental contracts for both of the projects, 4, 5 and ECA? And perhaps specifically, kind of where you sit in the decision, FTA versus non-FTA?

Yes, what I'm going to do is I'll just give you a high level, and then I'm going to turn it to Mark to go through kind of project-by-project and what we're looking at there. I would say, the great thing that we have is that when we look at our Cameron facility, it is a very commercially-viable facility. It's -- we think, it's really well positioned in the marketplace, and we also believe our ECA facility would be very well positioned in the marketplace. So a lot of effort is underway to look at kind of the next steps at those facilities, and then we have this wonderful location with Port Arthur, and what might we be able to do with that. So we are very focused on kind of the next steps, and let me turn it to Mark to talk a little bit about that.

Okay. Well, with respect to Cameron, I think, as Debbie says, a great facility. I think the thing I would add to that, too, is the partners in this -- in the facility are world-class trading partners with extensive LNG businesses. So while we have not signed contracts yet for trains 4 and 5, we're really just beginning, just starting to think about that as we have completed FID and move forward with the constructions of trains 1 through 3. So I think that the next step for us is to talk with our partners, decide how much capacity everybody would like, and then to see if we're going to market any of it out to other parties. And that hasn't really begun yet, but I think that is something that will be in the works now that we're moving forward with FID. And I would just say with that facility too is there are -- the big point here is that, that facility, along with our ECA facility being brownfield sites, obviously, have a cost advantage and a construction advantage over any of the greenfield sites. So it's our expectation that the market will look to brownfield sites, ours included, but also including others and expansion of those existing facilities, first, before they really look at a lot of greenfield opportunities. With respect to ECA, we are undergoing studies right now to determine the amount of gas that's available for the facility and the cost of delivering that gas into the facility. And then once we kind of determine that, which we think will take us towards the end of this year, once we determine that, we'll lay out some plans for the size of the facility and start marketing to customers. We have a lot of customer interest, and we don't think that acquiring customers will be a big issue, but we haven't started that marketing yet because we haven't sized the facility, but we're in the process of looking at the parameters to do that. And then with respect to Port Arthur, another -- it's a great site, it is a greenfield site. We think the advantage of Port Arthur is that it's such a large site and has such good water access that the possibility of doing things beyond just LNG are there. We can -- there's other -- it's actually been proposed in the past as a crude terminal and other types of activities, and we think those activities could coexist with LNG, making it, in the long run, one of the more cost-effective greenfield sites in the country. So those are all, kind of, positives and where we're going, and then did you, Debbie, you want to comment on the process?

Yes. You asked the question, Julien, about the DOE, non-conditional FTA. And going through the conditional FTA was really where the review, the extensive review occurred with DOE. So we would anticipate in the next few months to see the DOE, non-conditional FTA. We've seen, recently, other companies get their conditional FTAs. We haven't seen any change in criteria, so we would expect that to be coming out in the next couple of months. And then, that would allow us to begin, really, full construction on the site. But we are doing some site preparation activities. We've gotten the authority from FERC to be able to do that. And so, we're, actually, working on the site right now.

We'll take our next question from Steven Fleishman of Wolfe Research.

A couple questions. First, just with the final financing terms and the like, are all the numbers you've given for Cameron 1 through 3 still, kind of, right in line with what you've said before?

Yes. We did -- and I think a couple of things, Steve. We've given you the range of $9 billion to $10 billion. We're still in that range. And we looked at the financing, the financing came in very competitively, as I mentioned in my comments. What we're looking at now is, at the $10 billion range, being somewhere towards the middle of the range that we've given you, for the first few years of operation. And then as the loan starts to be amortized, we would anticipate that, over time, the annual earnings would be $400 million or so. So $300 million to $350 million is still a range we would see being closer to the midpoints of that range in the first few years of operation, and then we would see being in excess of $400 million after the loan starts to amortize.

Okay. And then just -- what's the -- just to set expectation, what's a reasonable timeframe to think about potential contracting of trains 4 and 5?

I can't really answer that question. I will tell you that it's something that is a big focus for us, and that we're going to put a lot of energy into it, just like we did getting Cameron done. But that -- you got to get -- you got to do the same things we went through Cameron. And the good thing is we've been through the FERC process on that site, so it's not a new site to go through the FERC process. So, kind of, telling you a timeframe on that, I can't tell you. I'm hoping it would be expedited because we've already been through the FERC process on that site, but I really can't give you a timeframe at this point.

Okay. And then just one last question on the -- you've given your 3 kind of scenario options on MLP back at the Analyst Day. Any new thinking on those 3 options or is it pretty consistent with what you said then?

Yes, let me have Joe talk about that because we continue to do work in this area. And clearly, with the situation with REX being as positive as it is, we constantly are looking at that. So let me ask Joe to hit that.

Thanks, Debbie, and Steve, thanks for the question. As she said, it's some subject that we spend a fair amount of time on because it's very important to us and to the shareholders. And we're looking at the MLP space and the YieldCo space, actually, and the ones that have the highest visible growth, particularly, with large drop-down portfolios, those have the lowest yields and the potential for the highest value. And so let me tell you a little bit more about that we really are doing. We're continuing to evaluate the value proposition and we're studying the legal and financial aspects of both the MLP and the YieldCo space. And as we've noted before, having the clear growth strategy for the business is a critical element. So we're very excited about our growth at Sempra and focused on executing, as Debbie said, on all these projects that we're doing. At the same time, we're focused on getting the best market value for the shareholders on this growth and that current MLP YieldCo structure offer good opportunity for that. So we haven't made a decision at this time, which of the structures is exactly the right one, but we are very focused on it and looking at it and continuing to evaluate all of these opportunities.

I would just add to that. We'll look at that in conjunction also, with the timing, and as I've said before, part of the analysis is looking at, with an asset as valuable as Cameron, how does the timing set, with splits and things like that? So all of that kind of analytical work is part of our assessment.

We'll take our next question from Greg Gordon of ISI Group.

The first couple of questions checked a lot off my list so I'll try to be brief. I'll probably fail, but I'll try to be brief. So thinking about when the revenues are rolling in on the stuff that's not in your plan. You've been very clear that 2015, 2016, there's 1 point more Bcf a day of revenue opportunity off of the REX backhaul that wasn't in the plan. Should we assume that -- should the Clarington West open season become a commercially viable opportunity that, that would hit in the second half of '15? Or is it hitting the first half of '16 in terms of incremental revenue? What's the timing assumed on the current path to bringing that into the revenue line?

The timing on the current path is sometime in the middle of 2015 as that is -- it's expected to go in service. And I think, just go through the increments again to be sure the numbers that you have are consistent. We have $200 million to $250 million in service now, and that was in the plan. We add, incrementally, $350 million to $400 million at the end of this year, and that's additive to the plan. And then, we would add the remainder to get to the $1.8 billion, which is another $1.2 billion in the middle of next year some time.

And I think you might have been asking [indiscernible].

[indiscernible] on the Clarington West?

And then on the Clarington West, the timeframe on that is not certain because with that -- a lot of that has to do with how you design it, and what the volumes are and how you design it. So we don't know what the timeframe of that would be.

Right. And Clarington West, if it's successful, would require more capital investment than the Seneca lateral and the $1.2 billion that you've already signed up, correct?

Yes. There would be compression for one piece of it, and then there would be looping for the other piece of that. And for what we've done so far, the capital is really not very large at all, I think it was like $70-some-odd million, $80 million.

And the maximum size of Clarington West was another $2.4 billion? Is that -- or am I overstating it?

No, that's right. That was the maximum size if you do compression and looping.

Great. And then, I have one question back on the utility. You gave guidance for a range of earnings for SoCalGas of $360 million to $390 million in 2015 at your Analyst Day. I'm wondering, as you now are analyzing the rate decisions you've gotten, for instance, the PSEP decision, where you think you would come out inside that range?

Well, the ranges that we gave you in March of this year, we would anticipate being in those ranges for SoCalGas.

We'll take our next question from Rajeev Lalwani of Morgan Stanley.

First is just a clarification. Joe, when you said earlier you're looking at different options for structures, were you saying that you're considering doing a YieldCo and having Cameron be a part of that?

I was saying that we're open -- we're looking at all of that. We're trying to determine what vehicle might, exactly, be the best, and we are keeping our options open as to what the right vehicle is. So at this point, it's open.

Okay. And then, hypothetically, if you did go, sort of, down the YieldCo-type route, what other assets in your portfolio do you think would fit well? Obviously, you've got the renewables, but do any other assets come to mind?

That would be probably the primary asset other than the ones that we've spoken about before that would go into an MLP.

Okay. What about some of the, like the Latin American assets you have. There have been a couple of YieldCos with those type of assets.

We've spoken about it a little, we haven't really done much analysis on it. It's a lot more complicated, obviously. And inside the utility, it probably wouldn't fit that well, but it's certainly something that we are keeping an open mind about.

Okay, great. And then in terms of -- there was a pipeline that was bid, I think, in Peru a couple of months back, and I think you were disqualified or there were some sort of issues. I was hoping you can provide an update there and just some color on what happened?

Yes. I'm going to have Mark talk about what happened with that.

Okay. Well, what happened was we were in a competitive bidding situation and we were in a consortium with other bidders -- I mean, with other participants in our consortium. And one of our members at the last -- kind of, at the last moment decided to change ownership percentages, and that caused us to have a technical disqualification. And so our bid was rejected, although we did open it publicly and announced it, and it was the best bid, it was the low bid, so I think would have won. And it was just unfortunate that we had this, sort of, technical problem that caused our bid to be disqualified. But I think it gave us a lot of encouragement in the sense that having gone through this process on this pipeline, and there's other projects coming up, that we were obviously very competitive. We came up with the lowest price. We think we had a better route and a better approach to the project. And so I think we're sort of emboldened to think that we're going to be very -- quite competitive in the future. It's unfortunate we have this little setback. But I think, moving forward, we look upon this, our group, as positively, as one that we can win projects down there.

Okay. And just one last question, if I can. In terms of thinking about the potential economics for an ECA or -- under Cameron 4 and 5, how similar or dissimilar would it be to Cameron 1 through 3, both in terms of the equity investment, as well as the return potential?

Well, I'll take that. This is Mark. Obviously, the expansion is less expensive per ton of production than even the brownfield conversion to a certain extent. As you get bigger and bigger, then you start -- then it becomes less effective because you might have to add tankage and stuff. But with what we're considering, I think we would be very cost competitive. So the cost wouldn't be -- would be less than what we're currently contemplating, and I think that's what going to make it very attractive. We would expect similar kinds of returns as we would get. So I think that we would probably share those efficiencies with the market to make sure that we can sell the capacity. So I think those are all positives. And then with respect to ECA, a little different facility there, a little different footprint. But I think, roughly speaking, the economics are somewhat the same, but ECA would likely be a smaller facility or will be a smaller facility.

Before I take another question, I just wanted to comment on something back on the REX sheet to be sure everyone was clear. On the sheet that we have at 17, it says 25% of the volumes. I just want to remind everyone that we own 25% of REX. So when we're talking about 1.8 Bcf and 2.4 Bcf, not all of that flows to Sempra. I think you all know that, but I just don’t want to mislead anyone. Okay. We're ready for the next question.

We'll take our next question from Matt Tucker of KeyBanc Capital Markets.

I guess, I wanted to ask about Mexico first and how you feel about your chances on these 2 CFE pipeline bids and if you could comment on how the competitive environment for these bids compares to other pipeline opportunities that you've gone after there recently?

Well, I'll just start by saying that we are really excited about the opportunities in Mexico, and the good thing that we have is we have the infrastructure there, we have the team there, we have the ability to get pipes to the job, we have all of that because we've done projects. So I think that, that -- why competition is probably going to be higher than we saw in the past. I think also being on the ground with the projects that we already have there provides us a great competitive advantage in terms of our ability to show that we can deliver on these projects. And then we have the 2 projects coming in this year that are on schedule, on budget, and there are not very many companies that have that kind of proven track record. So I think we're in really good position to compete, and there's a lot of projects that are going to come out, and we're going to be, as we have in the past, selective of which ones we bid on, the ones that we feel we can be most competitive.

Great, thanks. And then just circling back to Cameron. You mentioned you expect the final DOE approval within the next couple of months. I guess, what's, kind of, holding that up, and what issues are they still considering? I kind of felt that like would be somewhat automatic. So maybe you could comment on that.

Well, like I said within the next couple of months. I mean, we're not sure. It could happen soon, it could happen -- as DOE is looking at it, I think that one of the considerations was what kind of comments would come in on the FERC issue. And since that appears to have been that there were no comments that were filed timely, that, that may change how DOE focuses on it. Certainly, Senator Landrieu has already sent a letter that was made public asking DOE to act quickly on this. And as I said, it's not stopping us from getting on site right now and doing some of that pre-work. But the sooner we can get it, the better. So we're very anxious to have DOE act quickly and hope they will.

And then with respect to the possible expansion. I guess, I just wanted to ask about the construction side of that. If, hypothetically, you were able to secure commitments and were able to get the permitting process, would you be able to start construction on trains 4 and 5 before trains 1 through 3 are completed, or would you have to wait until, really, 2019 to even start construction?

No. I'm going to have Mark talk about how that might unfold.

No, I mean, it really -- they have to be kind of done sequentially. And it's not just the construction issue, but also the terms of the financing require us to finish the projects that are being financed first. So unless we redid some of the financing, we -- it's -- they have to be done sequentially.

So we'd be talking about something like a 2020-type timeframe, the earliest, 2021 maybe for those to come online?

Yes, it could be a little shorter than that. I mean, one of the things we are doing, we are constantly looking at the construction schedule and the construction that we're doing and we, kind of, call it a no-regrets construction policy, which is we're anticipating further expansion as we build. So there are certain things that we can kind of pre-build into the process so that we don't have to go back and redo it. So I think we can save some time there. So it may not be quite as long a timeframe as trains 1 through 3, but it would probably be sequential.

And then just looking at the 3 LNG expansion opportunities. You discussed Cameron, ECA and Port Arthur. Would you be able to, kind of, rank those in terms of both the probability and the, kind of, timeline between those 3 projects?

Well, I think the reality is the expansion of Cameron is probably up there. It's probably first, but very close behind is ECA, and that's, probably, almost a push as to which one could go first. Probably -- actually, ECA could start earlier than the expansion. So I think both of those are, kind of, at least, equal. And then Port Arthur, because it's a greenfield facility, obviously, would take longer to develop, and it could be quite a big facility. So that's further down the road. I'd kind of -- but I'd keep ECA and Cameron, kind of, neck and neck.

We'll take our next question from Michael Lapides of Goldman Sachs.

I want to ask about the good old-fashioned utilities. When you think about -- right, like nobody's asking, and you have really, really, really strong utilities. When you're thinking about the rate cases, how material? Meaning, how big of a number are we talking about in terms of either requested revenue change or a percentage rate change if you're the -- I don’t know, if you're the intervenor looking at it from the other side?

Yes, actually, I think that's the real positive that we have. If you look at SDG&E as example, our filed notice of intent to file the rate case set forth a number of $168 million increase. And on a combined electric and gas build, that's about 1.4%. And then on SoCalGas, we're looking at a $290 million increase, and that's about 5.5% increase in a bill. But I will remind you that in both cases, the bills are already much lower than the national average. So I think that we have operated our utilities efficiently over time. I think there's a benefit in that and going in to these rate cases and asking for what we really need to operate those businesses very efficiently and have it not be huge increases in customer rates.

Okay. And then one question on Clarington West, kind of, the part that you're still trying to figure out, you and your co-owners are just still trying to figure out what to do with. What's the timeline for the open seasons there? And I want to make sure I understood this, what would be the potential, kind of, range of capital requirements from your perspective?

Okay, Mike, I'll answer the first and then I'll ask Mark to talk about the capital requirements under the different phases, if that's public and -- when I'm not sure, I guess, that's not public information. So I won't answer that part of your question. But I will answer the first part of your question. The non-binding open season went out in May and now, we're in negotiations with participants in that non-binding open season relative to contractual commitments. So however long it takes to secure those is the kind of timeframe that we're looking at. And that's why I said I think we would anticipate something in the next couple of months most likely.

We'll take our next question from Christopher Turnure of JPMorgan. Christopher Turnure - JP Morgan Chase & Co, Research Division: Did you guys give more color on the timing of the rest of the 2014 RFPs for the Mexico pipelines? There's a lot left in there besides just the 2 that are out there already, and it looks like each one individually will take a couple months at least from start to finish.

Yes, there's 2 that are outstanding right now, and then there's 5 more that they've announced to come out of this year, and that's what's been indicated, and that's in the pipeline side. But I would also focus you on -- there's other areas of opportunity like transmission. And so, Mark why don't you hit, kind of, what we see over the next few months?

Okay. I think, well, like Debbie said, there's 2 out right now, and we're actively working on those bids. And then the next 5 that are coming out of those, 2 big ones are in the United States that are for CFE. Those will be, probably, hotly contested just because they are the MLPs and everybody can compete with those. So we expect that to be -- have more bidders than the ones in Mexico. But we do believe that we have some unique things, properties that we can bring to the bid, to our bid, and then -- and I think that we can try to -- we can be competitive, and we should have a good chance to do that. And we've had a long history, obviously, working with the CFE, so I think that should bode well in our favor. But then there's -- and then beyond that, there is a whole list of pipeline opportunities that are scheduled to come in -- to come out in the first half of '15. And obviously, we're even beginning to look at some of those and be prepared for those. But there is, certainly, a long list of opportunities on the natural gas pipeline side. But then we also have -- there are electric transmission projects and power generation projects, also product lines for PEMEX. So I mean, I think, the story here is that energy reform in Mexico is going to produce billions and billions of dollars of capital opportunities for companies that have a history of operating in Mexico, and our positioning with our IEnova subsidiary makes us probably the premier energy company to bid on these competitive projects. We're the second largest energy company in Mexico behind PEMEX, and we're really the hometown incumbent there. So I think we feel very good about our chances of being successful and participating in this reform, and we certainly look forward to continuing to grow our business down there.

And just to, kind of, add a flavor of the big numbers we're talking about over time. As part of the infrastructure program that the Mexican government has announced, they've announced 15 generation projects worth $13.6 billion, 17 gas pipelines for $13.1 billion, and 7 electric transmission lines for $1.7 billion. So you're talking about tens of billions of dollars of investment in Mexico. And they're moving forward on it. So we think this is going to be a great opportunity area for us. Christopher Turnure - JP Morgan Chase & Co, Research Division: Okay. And then just on cash repatriation. You guys have, I guess, some potential incremental opportunities in Peru after the failure of that initial RFP for the pipeline there, and then certainly all of the opportunities in Mexico. Will there be any pause that you contemplate with brining cash back here as a result of those and how should we think about that and, kind of, what's contemplated in guidance through, I guess, 2018 now, with the repatriation?

Yes, what we've had in our plan and what we continue to have in our plan is repatriating $300 million a year. And that -- we look at that based upon the needs of capital in those countries. As we've told you before, we have a lot of debt capacity left, and so that's what we would go to first. And then, we have the ability to issue equity in those 2 countries. We would look at that as well. So right now, what we're planning on is still the $300 million a year repatriation.

We'll take our next question from Kit Konolige of BGC.

On the possibility of the MLP/YieldCo that, obviously, has been a hot topic that you've talked about and we have asked you about. Any further thinking on any kind of bridge assets that could be put into a hypothetical MLP, let's say, before Cameron was up and running? If I understood you correctly, in the past, REX alone as it was envisioned -- you wouldn't really have considered sufficient to be the, kind of, the lead-off batter for the MLP for that length of time.

I'll have Joe talk about this. Joe?

Kit, while we haven't made any decisions at this point about the exact timing or asset composition, I will remind you, what we talked about on the first quarter, the things that are going on at REX that we talked about today and last quarter are really exciting because it does give us additional cash flow starting in the middle of next year that we can use in this regard. However, I did note that because we have a 25% interest in REX, it can't be the only asset that goes in there because of some 40 Act issues, so we need other assets. So what we've talked about is using some of the cash flow from REX, using -- as we get further along, obviously, the cash flows from Cameron, and now that we have FID, that puts us in great stead for that. But we have some additional cash flows from our LNG facility in Mexico that, actually, are in the U.S. and we would use those. We have some other, a little bit of midstream asset revenues not including the storage that we would put in there. And then if we did something broader, we could also include renewable revenues. But I think, given what's happened with REX, given that we now have FID, I think we have a mix of assets that we can use, as you call, sort of, a bridge to do something between now and 2018, 2019.

So what should we assume is the earliest that you could do something given the mix that you see in front of you there? Is it some time in '15 or '16?

As I started out to say, we haven't made any decisions at this point about the exact timing, so more to come.

Okay, we'll stay tuned there.

I'll say one other thing. Obviously, we talked about the CFE pipelines in the U.S, Mark spoke about that, and we think we have a good opportunity to capture some of that. That would be an additional help that would get us there.

Right. And speaking of assets that are being bid out in Mexico. Are -- is it your idea that IEnova would be the owner as those assets are billed or, let's say, for ECA, would there be a different company?

Now everything that's located physically in Mexico would be an IEnova position. As Joe said, there are some contracts that relate to gas that are not -- that are tied to ECA but are U.S. assets. Those would remain in the U.S. But to the degree that we developed ECA, to the degree that we're doing pipelines in Mexico, those would be Mexican assets under IEnova. To the degree that some of these Mexican bid pipelines occur in the U.S., those would not be part of IEnova.

Right. One last question on tax rate. You had some discussion earlier about how the tax rate varies quarter-to-quarter depending on what's repatriated and, obviously, other factors going on, several moving parts. How should we think about the tax rate, say, an annual tax rate over the next few years? Is it going to be pretty steady for estimation purposes?

Yes, over the next several years. This year, it will be just a little under 30, and over the next several years, in the low-30s. Pretty stable.

We'll take our next question from Mark Barnett of Morningstar.

Sorry to jump back into the LNG. You've been talking about it a lot today. I really appreciate all of your comments on it. Just wondering, it seems the agreement or the nature of the agreement for Cameron is a pretty successful one. If you are going to be moving forward with ECA or with the new Port Arthur facility, are you going to be looking for, kind of, a similar ownership structure?

That is yet to be determined. And we'll look at the option that makes sense for each of those facilities. We have great respect and have worked really well with the partners that we have at Cameron, but that model doesn't have to continue on, and we would be looking at what model would make sense for us at each of the facilities.

Meaning, it's possible by the time you're ready to make that decision, you might feel comfortable taking on a project like that on your own?

It depends on what kind of contracts we had. And all of that -- all I can say is it really depends. I would not preclude it, but it would have to also fit within our Sempra risk profile, and that's what we would look at.

Yes, I would say the thing that we would be focused on is that it would be fully contracted.

Okay, fair enough. And just one smaller thing. At the Analyst Day, you also mentioned the opportunity for some re-gas, maybe in Hawaii. Obviously, not maybe as large an opportunity as some of the stuff you mentioned this quarter, but just wondering if that's something you have an idea about, maybe the capacity that, that market might demand eventually? And that's probably, I would guess, a lower priority than any of the projects that you've spent so much time discussing, already, today?

Yes. I would say, I'm going to have Mark talk about it. But I would say, one potential customer probably for ECA would be Hawaii so...

Yes, look, I think, the reason we mentioned it is because there is, obviously, a real need there, and this is one of those interesting situations where bringing LNG into the island would do -- would have 2 beneficial effects. One, it would be a much cleaner burning fuel source for electricity because they're using fuel oil now. And two, it would actually lower their costs because they would go from a crude-based pricing to a natural gas-based pricing. So it's really got a double benefit and a clear need, and we think the desire on the part of the Hawaiian -- of the state government and the local utilities there to move with this direction. So we think there's going to be an opportunity there, and ECA is the natural, logical supply source. So that's why it was mentioned. We don't have an agreement. We don't have -- well, we've been talking to them. We think that there's a possibility, someday, of working something out, but we don't have anything. We don't have anything firm.

We'll take our final question from Paul Patterson of Glenrock Associates.

A lot of my questions have been answered, but just -- I wanted to clarify something on the DOE process. The Chris Smith proposal to, sort of, accelerate the -- to streamline the process and have them deal with the approvals at the end of -- other regulatory agency approvals. I'm sorry if I missed this, what is your expectation in terms of how that's going to proceed?

Well, we think that's moving forward, and we're very positive on that. I mean, what we've seen in the queue is that we spent a lot of money going through the FERC process, and that it doesn't cost that much to go through the DOE process for our company, but they can block you in terms of timing for the queue. And that, we really like the idea of the FERC process, kind of, becoming the driver because that's what requires all the engineering, all the environmental work, all the things to really make the business decision on the facility. And we think that this change in process will actually help us in terms of the development of additional size for trains because we've gone through that process. And there -- I will tell you, it is a stringent process, and you can see now that are not very many companies that have made it through the whole FERC process. In fact, we're the first one that made it through the whole EIS process. So we think it's an advantage to us, as a developer, having had the experience with that for them to make those modifications.

Because the reason why bring it up is that, as I'm sure you're aware, API and others made comments that seems to be critical of that path. And I guess, you guys just have a different perspective on it. I'm just wondering if there's a simple -- I don’t want you to go into anything elaborate, but I'm just wondering, is there a simple reason for that or...?

Well, [indiscernible] your level of seriousness on these projects is tied to the FERC process. And so, that your expenditures and your level of seriousness -- and with the process that DOE was using with every few months one coming out, you could have projects that may not get developed, may not get the financing, may not have the customers, and have not even begun the FERC process move ahead in the queue because they filed something that didn't cost them anything really to file. And so we think the FERC process, really, drives your true commitment because when you file at FERC, you have invested a lot to get there. And so we're supportive of what DOE is looking at.

Okay, I think I understand the difference. And then on the -- just in general, we've seen some real changes in the global LNG and gas market, et cetera. And I'm just wondering, where things stand now. And obviously, you guys have a competitive advantage with the respect to recent brownfield and stuff. Just in general, what's your thought about, ultimately, how much LNG is actually exported from the country? Or is that -- I'm saying in terms of just any market dynamic outlook, did that change at all from previously, when we've talked about this? Or I'm just, sort of, wondering, when we look at this -- like you said, it seems like everybody's brother's is announcing something, and of course a lot of it isn't, probably, going to happen. I'm just wondering if you could maybe give a little bit of flavor as to how you see the recent changes in the gas markets globally?

Yes, I'll ask Mark to talk more about this. But what I would say is that all depends on what the relative cost in the market is. And I mean, some of the projects that we're doing now, which are brownfield projects, are very cost competitive. One of the advantages that you have in the U.S. or that you would have in Mexico is that you have an infrastructure, and then a lot of these other places, where they're having to build their LNG facility, they're having to build the pipeline infrastructure, they're having to access the resources to the supply. There's different hurdles that go with it. So we think that our country is really well positioned on this. And it's hard to say how much of that global market we get. I do think that we can be very competitive in that global market because of some of those issues. Mark?

Yes, I would say in the near term, say between now and 2020 to 2022, you'll see the development of, probably, the brownfield facilities because those will be the most cost-effective and that could be somewhere in the neighborhood of 7 Bcf to -- just call it 8 to 10 Bcf a day. And I think that's what is probably likely to happen, and then given the size -- and then, I think it'll probably depend a lot on how much the world market is going to grow. I mean, right now we're talking about -- there's some estimates out there that the market for LNG could double over the next 10 or 15 years in the world market, and that, obviously, would create additional opportunities for gas-producing countries. But we've said all along that we don't -- we think other gas-producing countries, especially, ones like Qatar and others that have low-cost reserves, are going to be competitive in this market and they're not just going to seed market share to the U.S. or Canada or the North American market in general on a whim. So at the end of the day, I think, there will be a demand for diversity of supply, which will include North America, and we're going to see other projects get developed and get built. We believe some of those will be ours. But at the end -- but it isn't an unlimited market and clearly, I think we're not approaching it, and I think responsible developers are not going to approach this with the idea that it's never-ending. And so you'll see a lot of proposed facilities, but at the end of the day, we think the actual ones that come online are the ones that will have sold their capacity. And that capacity market is going to be -- it's going to be looking for diversity, it's going to be looking for certainty of supply, and that bodes well for the North American market, and so I think it'll continue to grow. But it's going to be 2022 kind of 10 Bcf a day sort of market and kind of grow from there.

I also would say that there's just a lot of things that have been happening in some of the international gas markets that are affecting us. Clearly, what's happening in Russia has a big effect. China just announced that their development of their shale is not progressing as they had anticipated, and it's going much slower and much lower production rates and more expensive. And so I think, those factors will play out over the next 3 to 5 years, where you have greater visibility in those areas, which have a lot of impact on what happens to the LNG market as well.

Thank you, all, very much. As always, we have a top-notch Investor Relations team, and that they are there to answer any follow-up questions that you have following our call today. So if you have any additional questions, please contact our Investor Relations group. And thank you so much for joining us today on the call.

This does conclude today's conference. Thank you for your participation.