桑普拉能源 (SRE) 2016 Q1 法說會逐字稿

Good day, everyone, and welcome to the Sempra Energy first-quarter earnings results conference call. Today's call is being recorded.

At this time, I'd like to turn the call over to Rick Vaccari. Please go ahead, sir.

Good morning, and welcome to Sempra Energy's first-quarter 2016 financial presentation. A live webcast of this teleconference's slide presentation is available on our website under the investor section.

With me in San Diego are several members of our management team: Debbie Reed, Chairman and CEO; Mark Snell, President; Joe Householder, Chief Financial Officer; Martha Wyrsch, General Counsel; Trevor Mihalik, Chief Accounting Officer; Dennis Arriola, Chief Executive Officer of SoCalGas; and Jeff Martin, Chief Executive Officer of San Diego Gas & Electric.

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.

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 first-quarter 2016 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, May 4, 2016, 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 4, and let me hand the call over to Debbie.

Thanks, Rick. On today's call, we are following a slightly different format. As you know, the final GRC decision for our California utilities has not been issued. However, we expect to receive a proposed decision relatively soon. Because we have reached a multiparty settlement agreement, we continue to believe the most likely GRC outcome is one consistent with that settlement.

We also believe we have made a strong showing to support our historical treatment of tax repair allowance benefit. Therefore, today, we are updating our 2016 adjusted EPS guidance, and providing you with our long-term growth rate, assuming a GRC outcome consistent with the settlement.

We think the best approach is to postpone our analyst conference until we have a final GRC decision. We are tentatively looking at the month of July in New York City as a possible date for the conference. Once we receive a PD, we will confirm the date and location.

In our other businesses, we recently announced the sale of our Southeast utilities and our interest in REX. We expect to receive about $760 million of cash proceeds to invest in projects that align better with our growth strategy.

As you know, our strategy is to provide growth that is roughly twice that of the utility average, but with a commensurate risk profile. I will discuss these transactions later in the call.

Our updated 2016 adjusted guidance range is now $4.60 per share to $5 per share. This range reflects approximately $60 million of reduced earnings from REX. The sale of our Southeast utilities does not affect current or future earnings, since earnings reduced from the sale can largely be offset by lower interest costs.

Looking forward, we are well positioned for strong growth over the next five years. We expect our base plan to provide earnings in 2020 of $7.20 per share to $7.80 per share. The resulting adjusted compound annual growth rate for 2016 to 2020 is about 12%. Prior to the sale of REX, the comparable growth rate would have been about 11%.

Joe will address the growth rate further in his remarks. But I want to emphasize that we expect to have significant credit capacity in the latter years of our plan, which will provide us with flexibility in capital allocation. We will discuss our plan assumptions, business unit projections, and growth strategy in more depth once we reschedule the analyst conference.

Turning to our financial results, we reported first-quarter adjusted earnings of $370 million. As a reminder, until we receive a final GRC, we are recording revenues based upon 2015 authorized amounts. Once we receive a final decision, we will record the impact of the 2016 authorized margin back to January 1.

If the GRC had been finalized by January 1 and was consistent with the settlement agreement, utility first-quarter earnings would have been in line with last year, despite the fact that approximately $60 million of annual tax repair benefits will now flow to customers under the new GRC.

Now please turn to slide 5. There are several updates related to Aliso Canyon. First, SoCalGas is cooperating with DOGGR and the CPUC on the root cause investigation through their contractor, Blade Energy Partners. We expect the investigation to take about 6 to 9 months, with results being issued by the agencies late this year or early next year.

Second, we are working to get the field back in service for injection. Consistent with DOGGR's proposed safety review, we have implemented a plan to prioritize and test wells, with the goal to have the facility in service by the end of this summer.

Third, we are working with state and local agencies to address electric reliability concerns. Aliso Canyon currently has about 15 Bcf of gas available for withdrawal. When deciding how best to use that gas, reliability for both the summer and winter seasons must be considered.

Fourth, we are completing our estimate of the total amount of gas lost from the leak and formulating a plan to mitigate that amount.

Fifth, the temporary relocation program has been extended to allow the county to complete in-home testing, with results expected this month. SoCalGas and public agencies have conducted numerous tests of outdoor air quality. Results continue to confirm that air quality in Porter Ranch is at normal levels. Finally, we are addressing the litigation that has been filed related to the leak.

With regards to costs, we have incurred additional amounts, primarily from continuation of the temporary relocation program, as ordered by a court. The court has scheduled a follow-up hearing on June 7. Based on an expectation that the relocation program continues through June 7, we estimate the cost for amounts paid and forecasts to be paid at approximately $665 million.

We have recorded an insurance receivable of $660 million. Our cost estimate does not include certain potential items as described on the slide. Please refer to our 2015 10-K and first-quarter 2016 10-Q for more detail on costs and our insurance.

Now let's turn to slide 6 for an update on our other businesses. Sempra constantly looks at our assets to determine whether they fit with our long-term contracted infrastructure model, and whether they integrate with other assets to offer strong, long-term growth prospects. We identified three assets that are no longer a strategic fit for us -- REX, our Southeast utilities, and the TdM power plant in Mexico.

For the first two, we have announced sales agreements. And for TdM, we are conducting a sales process. For REX, we expect the sale of our equity interest to close in the second quarter and to provide $440 million in proceeds. The sale also allows us to forgo expected future contributions for capital investment and debt repayments. We believe our capital can be better utilized to further enhance our strong growth outlook.

As a result of the sale, we forecast a reduction for partial-year 2016 earnings of approximately $60 million, which is included in our adjusted EPS range of $4.60 per share to $5 per share.

It is important to know that had we held our interest in REX, we expected 2020 earnings to be immaterial and dilute our growth, largely due to loss of earnings from west-to-east contracts that expire in 2019.

In addition, we plan to permanently release uncontracted capacity held by Sempra. The negative earnings impact of this capacity release is projected to be between $100 million and $120 million, and will be recorded in the second quarter. This amount reflects the acceleration of estimated losses that would have otherwise been realized over the remaining contract term. It is excluded from or 2016 adjusted earnings guidance.

Moving to our Southeast utilities, we finalized a sales agreement last week and expect to receive $323 million in cash proceeds, with the buyer to assume $67 million of debt. We did not see significant additional growth potential in our Southeast utility footprint, and the earnings impact is projected to be offset with reduced interest cost.

Similar to REX, we expect to use the proceeds to invest in projects with stronger growth prospects. Finally, TdM is the third asset that no longer fits with our long-term contracted infrastructure strategy. It is currently held for sale, and we are in the midst of a sales process.

Now, please turn to slide 7. IEnova is building upon its position as the largest private energy company in Mexico to identify and originate new investment opportunities. IEnova is working on multiple development initiatives, including M&A, asset optimization, strategic partnerships with established companies and new companies seeking to enter the Mexican market, and emerging opportunities in clean energy -- storage and liquids infrastructure.

One example of asset optimization is the building of laterals off our gas pipeline network to interconnect with end users. Just this week, CFE awarded IEnova a contract to build a small lateral that connects our Sonora pipeline to a combined cycle power plant. In addition to project opportunities identified by IEnova, that CFE bidding process for natural gas pipelines continues. We are currently evaluating two tenders, with likely bid dates during the second quarter.

In generation, we expect to see the second round of renewable energy auctions in August. And in electric transmission, we expect to see the first two bids under new rules of energy reform in 2016 and 2017. Each electric transmission project represents an estimated $1.2 billion of investment.

With that, please turn to slide 8, and I will turn the call over to Joe. Joe?

Thanks, Debbie. Turning to our long-term financial projections, we expect that our base plan can provide 2020 earnings of $7.20 per share to $7.80 per share. The resulting adjusted earnings CAGR from 2016 to 2020 is about 12%. Some of our key plan assumptions include an $18.5 billion capital program, including joint venture CapEx for Cameron Trains 1 through 3; full-year earnings of $300 million to $350 million from Cameron Trains 1 through 3 in both 2019 and 2020; a GRC outcome in line with our proposed settlement agreement; and tax repair allowance benefits prior to 2016 being retained by shareholders; and an optional $2 billion share repurchase.

Under our base plan, annual adjusted EBITDA is expected to increase by $1.7 billion over the plan period, raising our FFO to debt to roughly 22%. Including our targeted annual increase in the dividend of 8% to 9%, we project excess credit capacity in the later years of our plan to be between $2 billion and $4 billion.

Leaving excess capacity on our balance sheet would not maximize shareholder value. We have used a conservative assumption of an optional $2 billion share repurchase, split between 2019 and 2020. While we do include this assumption, it is our intention to allocate capital toward high-value development projects.

I will discuss all of our base plan assumptions and provide business unit guidance at our analyst conference. I want to remind you today that our plan is not aspirational in nature. It is anchored on expected utility performance and projects that are already contracted and operating or under construction. This approach gives us high visibility and conviction in our growth rate.

On a final note, before turning to the quarterly results, I want to address the long-term earnings impact from the REX capacity release that Debbie discussed earlier.

In the base plan we presented last year, we had only assumed about $5 million to $10 million of annual losses associated with this capacity for 2016 and 2017, because we had not factored in the financial distress that several counterparties have recently experienced. We had no capacity obligations in 2020. By permanently releasing the capacity now, our new five-year plan does not have to reflect any future losses from this capacity, nor any negative impact from the recently announced counterparty bankruptcies, beyond the loss we expect to record in the second quarter.

Now please turn to slide 9. This morning we reported first-quarter earnings of $319 million. On an adjusted basis, we reported first-quarter earnings of $370 million, or $1.47 per share. Adjusted earnings this quarter exclude the $27 million after-tax loss on the pending sale of our equity interest in REX, and $24 million of deferred Mexican income tax expense as a result of holding the TdM power plant for sale.

In addition, just as a reminder, in 2016 we are now including LNG development expenses in our reported adjusted earnings and adjusted earnings guidance, whereas in 2015 these were excluded.

There are several factors affecting the first-quarter results that are either timing items or items expected to reverse in later quarters. Please turn to slide 10 and I will discuss the key factors impacting our quarterly earnings.

Quarter over quarter, adjusted earnings were impacted by the following items. At our California utilities, we had $17 million of lower earnings, mostly due to higher operating costs from higher depreciation and litigation, with no increase in authorized margin due to the delay in our GRC.

As Debbie noted, until we receive a final decision, we are recording revenues based on amounts authorized for 2015. Once we receive the final decision, we will record the cumulative impact of 2016 authorized revenues back to January 1.

Including this retroactive benefit, we expect the utilities' quarterly earnings would be roughly in line with last year, which is important, given the fact that approximately $60 million of annual tax repair benefits will now flow to customers under the new GRC.

Moving to the parent category, we recorded $10 million of higher losses due to $7 million of lower repatriation tax expense that was more than offset by $10 million of higher net interest expense, combined with a $5 million income tax benefit that was recorded in the first quarter of 2015.

At U.S. Gas & Power, we had $9 million of lower earnings due primarily to the impact of natural gas price movements on inventories that we sold forward. We expect this $9 million loss to reverse by year-end.

At Sempra International, we had $8 million of lower earnings from foreign currency effects. This was due to a $4 million negative impact in South America and a $4 million higher positive impact in Mexico in Q1 2015.

At SoCalGas, our Q1 2015 results included an $8 million GCIM award. No GCIM award was recorded in Q1 2016, as this reward was received in the fourth quarter of last year.

Now let's conclude on slide 11. In summary, we have updated our 2016 adjusted earnings guidance to $4.60 per share to $5 per share to reflect the REX sale. The annualized impact of the REX sale will also reduce earnings by approximately $70 million per year for the next few years. Our adjusted guidance is defined in further detail in the appendix.

In terms of our financial results, while our first-quarter earnings were impacted by the delay in our GRC, we will record the retroactive authorized margin back to January 1 once the final decision is received.

Finally, assuming the GRC outcome is consistent with the settlement agreement, we project a base plan adjusted earnings CAGR of about 12% from 2016 to 2020.

With that, we will conclude our prepared comments and stop to take any questions you may have.

(Operator Instructions). Julien Dumoulin-Smith, UBS.

Congrats.

Thank you.

So, quick question to get out of the way: what is the implied growth rate year-over-year on 2019 into 2020? You talked about share repurchases; I have been getting questions on it. Just wanted to settle that.

Well, what we have disclosed now is the growth rate through 2020, and we're not going to give any adjusted earnings guidance for 2019. We always give you the fifth year in our five-year plan. But I think you can infer from what we've given you before and the range of growth over that period of time.

What I will say is, as you know in our business, that some of our growth tends to be lumpy because we have large projects coming into service. And in 2019 will be the first full year of Cameron Trains 1 through 3 going into service. Those trains remain on schedule to be completed throughout 2018, as we told you before. So 2019, you will see that come into 2019. And so, 2019 will be lumpy in comparison to 2018. And 2018 will be lumpy in compared to 2017 as the trains come in service.

Julien, this is Joe. I'd just add on to that, exactly what Debbie said. But remember, though way we build our base plan, it will have utility growth ongoing from attrition, and utility growth in South America. But there are no new projects that we have outlined that would come on service in 2019 and 2020. So the growth rate that you would see there, or you would predict to see there, won't be what we expect to have, because we expect to have new projects. But we're talking about four or five years from now.

Great. And with that technicality out of the way, thinking holistically, what is the next focus, at least, of the Company when it comes to that capital allocation? I appreciate you delineating the share repurchase as a placeholder. You are selling down some of the gas assets, deeming them noncore.

Where is the Company going? If you can at least describe your preliminary thinking. I know it's a little bit of an Analyst Day kind of question. But I just thought I'd get it out there, especially in light of what should be nearer-term cash proceeds from the asset sales that you articulated already.

Well, let me talk to you about some of the things that we're looking at. And obviously there's a lot of M&A activity right now in the space. There's a lot of opportunities. But we have a lot of organic growth, as well, so let me talk about some of those things.

First of all, we are still looking at train 4 being developed. And so that we would anticipate having agreements in place by the end of the year, based upon conversations we've been having with the parties now. And that is not at all in our growth plan. So the numbers we gave you for 2020 has nothing for any additional LNG beyond trains 1 through 3. So we still focus on that. We think it's a good growth opportunity for us.

And then what we also think is the integrated assets, when you have such a huge demand for gas, the opportunity to develop pipelines and storage to serve those loads is a really great opportunity for us. So we continue to look at putting capital into those areas.

I would also say that as you look at the opening of the in energy markets in Mexico, they are at the infancy right now. They have only done some of the gas infrastructure. We have electric transmission; we have pipeline for liquids; we have pipeline -- or terminals for liquids. We have a lot of more energy infrastructure to come out for opportunities in Mexico. And we think we just have a wonderful foundation of assets there that allows us some opportunities.

And then I would say, our renewable business -- we don't talk a lot about our renewable business. But we have a growing, robust, successful renewable business that we continue to have new projects that we find. And we have the ability to expand on some of our existing projects.

What I would say is that we have a strategy that's really focused on growing at more than twice the rate, or at twice the rate of the typical utility, but with a similar risk profile. So, when we start looking at assets, we look at -- are they long-term contracted? Can they have low volatility? Because we know you all value low volatility with growth. And can they support our growing dividends? And can they give us the strength of the balance sheet that we're seeing over the five years of the plan?

And so, projects that fit that criteria, we're open to a lot of things. We constantly look at M&A. And we see some assets that may be on the market that might be of interest to us.

So, our strategy hasn't changed. And we just thought that the capital that we had in some of these things was trapped, and was not really integrated with anything else we had, and was not going to provide us the kind of growth that other investments might.

Got it. And the last little piece there on the cash in hand today. I know it's part of the broader capital allocation. Anything in particular there to emphasize?

I'm sorry. I didn't catch that.

Just the cash that you are getting for the asset sales (multiple speakers).

Yes. I'll let Joe -- go ahead.

No. I think, Julien, nothing particular; we're building out about $1 billion of renewables this year, and money is fungible. And we're looking at all kinds of opportunities. Mark's groups are looking at lots of opportunities. So, I can't name one thing because there's a whole bunch of things on the plate.

Great. Well, thank you guys very much. Good luck.

Neel Mitra, Tudor, Pickering.

I just wanted to touch on Mexico first, the three pipeline bids which IEnova got disqualified from. Could you explain the reasoning behind that, and if there's any way to reverse the result, or appeal it, and how that may affect the bidding going forward for you guys?

Sure. I'm going to have Mark address that, because I think it's important to know that it wasn't -- it didn't happen with us being disqualified, one bid after the other. Unfortunately, we had to submit all bids at the same time, and we didn't find out about being disqualified for the first one until the other two had already been submitted.

But Mark, would you talk a little bit about (multiple speakers) really going forward and how we're dealing with (multiple speakers).

Right, sure. On those particular bids, what -- the methodology that we used was to adjust our tariff to CFE by additional capacity that we anticipated to sell to other customers down the road. But without specifying exactly where on the pipeline we would do that -- and that's the basis of which they would disqualified us. And as Debbie said, we submitted three bids at once, used that same methodology, were disqualified. We don't agree with it and we've challenged it, but I think we have adjusted our bidding procedure going forward. And frankly, it's behind us now, and we're looking at the other bids. And we have adjusted how we're doing it, and we would expect to be quite competitive in the future.

So, it's not something -- it was unfortunate in just the way those bids came together, but it's behind us now and we're moving on. But I will say that I think -- talking about Mexico in particular, we're still in a very, very good competitive position there. And I'm really pleased with the growth that we've had. Unfortunately, you don't see it quite in the financials. But our EBITDA there was up 19% from $93 million last year to $110 million, if you include our ownership in the JV and our proportionate share of their EBITDA.

And it gets masked a little bit in the GAAP reporting because of FX. Last quarter in 2015, in the first quarter, we had a 3% inflation with -- or a strengthening of the peso, which actually reduced our tax expense. And in 2016 it was pretty much flat, and so we didn't get that same benefit. So that masked the underlying growth. But we had very strong growth there, and are in a very good competitive position in Mexico.

Got it. And Debbie, you mentioned a lot of opportunities in Mexico beyond just the CFE pipelines. Could you maybe comment on, nearer-term, what maybe the best opportunities are that we should be looking at?

Sure, I'll talk about some. And I think one that we have before us that we expect to close during the third quarter is the Pemex acquisition of the JV assets that we currently hold jointly with Pemex. And we're still moving forward on that. But as you probably read, Pemex is looking at other potential asset sales. And they have a number of assets that we would be interested in that would give us some opportunities.

We're also looking at some of the other energy assets that are in Mexico now -- some of which are in operation, some of which are in the development stage -- that we could potentially acquire. And we have some that we are looking at there.

And then, just in terms of the broader markets opening, you have the bids coming out that are about $1.2 billion apiece for electric transmission that we're seeing. You have renewables being bid, and several billion dollars worth of potential there.

And then, for us, since we own and operate pipelines, there's a lot of liquid pipeline assets in Mexico that are currently held by Pemex now or needs for new liquids pipeline that deal with their opening of the oil markets. And so, we think that that's a great area for us, as well, to have similar type of long-term contracted infrastructure in liquids.

Got it. And my last question, with you guys divesting REX, there's no real domestic midstream presence. Are you looking to grow that through acquisition or organically. Or is that something that's not necessarily important, as long as you have contracted growth in other areas?

Yes, what we have looked at as a strategy to grow that, but more on an integrated basis with our other assets. And that when you have a huge load, like building an LNG facility, that gives you the opportunity to build pipelines and storage to serve that load that integrate with others. And then to expand those in a way that you can pick up additional customers, whether they are electric generation facilities or manufacturing facilities, and really have a full pipeline.

So, what we tend to look at is where we have a load, and we're the one that has that load -- whether it's a utility or a contract with Pemex, or it's a contract for LNG export -- that we like to have assets that integrate with that load. And so that would be our priority for looking at assets, as to how they could be more integrated with our business.

REX was fine, but it didn't integrate with anything we had. We only had a 25% interest in it. We didn't control it. It had contracts expiring. It just really didn't fit our model. And I don't want that to tell you at all that we're reluctant to get into other midstream assets.

We are very interested in getting into those types of assets. But they need to provide us more growth. And when we looked at REX, we just did not see the profile as providing the kind of growth. But there are some interesting assets that we're starting to look at now that may come on market that we -- are already in existence. And then there's some that we foresee the need to develop that we think would be very interesting as well.

Okay. Thank you very much.

Greg Gordon, Evercore ISI.

So, I just want to be clear on -- if I were trying to replicate your business plan with my own financial model -- that we take the balance sheet capacity you have, and we just assume that you buy the shares back at some higher stock price as we compound out four years of growth. And that would be a pretty low implied return on equity on that capital, relative to what you would consider a competitive hurdle rate for an actual infrastructure project. Is that a fair articulation of the math?

Yes, Greg. I think you've figured it out actually quite well. One of the things we've struggled with is that when we do our base plan, the only things we put in our base plan are things we already have contracted and our expected utility earnings. And most others, when they build those plans, they put aspirational projects in. We don't do that.

So then when we looked at this, and we saw with all the projects we have under contract and what that would yield, and then looking at all the cash flows we have coming from the projects that are in service at that time, and what that did to our FFO to debt, we just said there is no way we would sit with that FFO to debt on our balance sheet, at that time.

So, what's the most conservative assumption we could put in? And decided that to do a stock buyback was the most conservative way to handle it.

But I'm going to return it to Joe to talk a little bit more about how you might think about that in your question.

Thanks, Debbie. Yes, Greg, I want to emphasize the two key factors that she mentioned that are the element of the base plan. It's built on the strength of our regulated utilities and the already-contracted infrastructure business that contributes to the strong balance sheet and the cash flow.

So we did kind of what you said: we looked forward, we had to pick a price; we estimated price based on a reasonable utility multiple out, several years out; and used that as a way to develop the optional share buyback. And I think that our goal is really to develop infrastructure, and beat that. So the earnings from those projects will replace this, and that's the goal that we expect to achieve.

Great. I would presume once we get to Analyst Day that you would give us a similar framework of, this is what we have on the list of things that are moving ahead. And the checklist of the aspirational items that we could hold you to either achieving or not achieving as you move through time, much like you did last year?

Absolutely. We will do the blue box, which is the base plan, and the green box, which is the aspirational items. They key thing is that some of those aspirational items will replace the stock buyback, obviously. But to the extent that we can do more of those projects, they would also be additive to the stock buyback. And we'll go through all of that with you at the analyst meeting, as we usually do.

Great. Switching to Aliso Canyon, the costs obviously are pretty significantly since the 10-K disclosure of around $330 million, if my memory serves me correctly. Can you give us what the incremental costs have been in basic buckets? Has it been mostly the extension by the judges of the relocation program? Or has it been other items that have also been significant?

Yes, I'm going to refer this to Dennis, so he can walk you through some of that and what's happening relative to the relocation. But the majority of these costs are associated with relocation. The vast majority -- I think it's about 70% of the costs are relocation.

So Dennis, do you want to walk him through that a bit?

Sure. Good afternoon, Greg. You're right; if you think back when we reported in the 10-K, the costs were about $332 million. Since that time, we have had the relocation program extended at least a couple times by the courts. So if you look at the change of about $333 million, the majority of that has been relocation, 70%.

Then you basically have two other buckets. About 15% of the overall total relates to the work of stopping the leak, building the relief wells; the root cause investigation that's under way and everything. And then you've got the buckets of the other costs related to legal, and other out-of-pocket. So those are the three main -- 70% relo; 15% for the stopping the leak, and the investigation; and then the other 15% related to legal expense and other costs.

Okay. Thank you very much. Take care.

Faisel Khan, Citigroup.

On the TdM asset sale, I suppose that with the sale announced, did that mean it was difficult to get a long-term contract on that plant for sales into Mexico? Is that the genesis behind why this asset is being sold? I thought that this would fall underneath that bucket of assets that could be under a long-term contract, but maybe that wasn't a possibility.

Yes, I'm going to have Mark talk about that. But it had been sold into the US previously, and we were working on the possibility of trying to sell it into the Mexican market. But as we looked at the asset and the difficulty in that, we decided that it was not likely to be -- not long-term contracted in the near term.

Mark, you want to --?

Yes, I think that's right. The plant right now is configured only for sale into the US. We have looked at -- and we have a plan to connect it into the grid in Mexico. It could be that in the not-too-distant future that there could be a long-term contract opportunity with the CFE. They did -- the CFE did just sponsor and build a new plant very close to our LNG facility down by Ensenada. And so, it's going to delay for some years the need for additional capacity in that region.

And also, too, just with those kinds of plants -- fossil fuel fired plants in Mexico -- the contracting periods are not as long as they once were. And so, we started to see that this asset is not likely to meet our kind of long-term contracted objectives. And, therefore, we thought that we ought to put it on the market and see if we -- and move to sell it. All that said, I think we have certainly a reserve price in our heads that, if we don't get it or don't get it, then we will rethink that. But I think we're in very good -- we're looking at trying to move forward on it.

Okay, makes sense. And then just going back to Aliso, just want to understand. So, you're saying that we probably won't get any sort of major final report from the agencies until late 2016 or 2017. Are there going to be any initial findings that come out through the regulatory process over the next few months?

Well, I would say there were some initial findings from DOGGR that indicated that SoCalGas was in full compliance with all the rules that were in place at that time. And DOGGR came out but those findings early on from the preliminary review. But right now, the work that Blade is doing on-site in conjunction with CPUC, I don't think we're going to get any preliminary information. What they will do is they are gathering the data, and then they will write the report. And it's likely that report will be out at the end of this year or early [next] year.

Dennis, do you want to add to that?

Now, the only thing that I'd add to that, Debbie, is that there is a lot of work going on, not just under the root cause investigation with DOGGR, the CPUC, and Blade, but work to get Aliso back up and running. And I can tell you right now that it's really clear that the regulators and policymakers truly understand the importance Aliso Canyon, and gas storage to both gas and electric reliability. So, the tone is basically -- let's make sure it's safe, but let's get it back up and running as quickly as we can.

And so far, we've got -- of the 114 wells at Aliso, about 100 of them have completed the phase 1 inspections. And we're transitioning those now to phase 2 so that -- our target right now, Faisel, is to have the field ready for full operation, obviously subject to DOGGR confirmation. But by the late summer, probably late August; so a lot of work going on there.

Okay. And then the storage field would not be able to go back into operation until this report comes out? Or could you put it back into service before then?

Well, today we've got out of the 15 billion cubic feet of gas. So if needed, we can withdraw. We're just not allowed to inject until the field has been confirmed ready by DOGGR. And as I said, our current target right now is to have wells ready for re-injection by late summer.

And that is before the whole report will be out.

Yes, okay.

And that is separate from the root cause analysis. Those things don't -- they aren't linked. The root cause is going down one work stream, and then there's a separate work stream to get the field back up and running.

Okay, makes sense. And then just on REX, just wanted to make sure I understand the -- what you had initially as guidance in the past. Did you always have the legacy REX interest that you have going to zero earnings in 2020? Just wanted to make sure I understood that correctly.

Yes. No, you understood it correctly. We basically had -- it was de minimis in 2020. Because we had looked at the contracts all expiring in 2019, and then there was debt refinancing that needed to be done. And so we looked at the economics of that. When we were putting our plans together, we were not expecting REX to continue at the kind of run rate that -- we told you it was $60 million for the 10 months we had this year. We were not expecting it to continue at that kind of run rate after those contracts expired in 2019.

[This is what I want to understand]. So do you expect the contracts to expire and nothing would happen after that? Or did you also -- did you expect some recontracting, but at a lower rate? And did it also include the east-to-west contracts that were signed?

Yes. Yes, we looked at all of that, and we expected that there would be some contracting at a lower rate.

Mark, you want to --?

Yes. Faisel, yes, obviously we did. We had a projection of what we thought the recontracting rate would be. And then we also assumed that we would continue with the east-to-west contracting that we've done. And we had a market check on that, and that's what was in our plan. But that, combined with the interest cost and some refinancing that we thought was going to happen, it just didn't have a material impact on our financials beyond 2018.

Okay, got it. Then last question for me. With the midstream and MLP markets coming back, to some degree, off the bottom, just wondering -- and also with the sale of REX -- does this mean the MLP is completely off the table, even in the future?

I would say nothing is off the table in the future. I would never do that. We will always look at what's the lowest cost of capital for us to grow, and that's the way we look at it. REX was not a core asset for the MLP anyway, since we only owned a fraction of it. And we really didn't have the ability to use that as openly as you would an asset that you had 100%. And I would say Cameron Trains 1 through 3 are excellent assets for an MLP, so that those would be not off the table. But right now, if you look at where that market is, it's certainly not our top priority.

Understood. Thank you, guys.

Michael Lapides, Goldman Sachs.

Thanks for taking my questions. Actually, I have a couple of them. First of all, Debbie, can you talk about the portfolio, and whether you think there's anything else within it that you wouldn't view as core or strategic to Sempra over the long-term? And if so, why?

Sure. No, there's nothing that we identify right now that fits that category, Michael. We look at our assets all the time. And all of our assets, other assets, really are pretty well long-term contracted. The only one that comes up that we look at constantly is gas storage, and that we do have still contracts on gas storage that have some duration left on those contracts. And we look at that and say, how does that fit with our other assets? And what we see happening in the Gulf region with the export of LNG, the conversion of coal to gas, and need for different types of assets to support that, and then looking at the storage market right now.

We think that the timing on that asset, if things are going to happen, they are going to get better, not likely worse. And so, that's one we constantly look at. But we have concluded on that, at least for the time being, it doesn't seem like something that we would want to try to get out of our portfolio at this time.

Got it. When you talk about the $18.5 billion capital plan over the next five years, how much of that is at the two core California utilities?

It's about $12 billion of that at the two California utilities, so the vast majority of that. (multiple speakers) And there may be some opportunities. I was going to say, there may be some opportunities for the utilities to actually consume more of that. There's some projects that we have that are on those green sheets that we show you that we are hoping to get some approval on that would add to the capital expenditures at the utilities during that time. But we really put in that only the ones that we have some great visibility and high certainty that we either have a rate case approval or project approval from the CPUC or FERC.

Okay. And last question, how are you thinking about the growth rate in the South American utilities, relative to the rest of the Sempra portfolio? I ask only because if I back out the FX impact, it still doesn't seem like it was a huge growth rate, and going back over the last couple of quarters as well. Just curious how you are thinking about that business and its organic growth potential.

Yes, we still see a lot of organic growth potential there, because similar to Mexico, there's huge needs for infrastructure in those countries. And we're looking at quite a few things right now in Peru, in particular.

Mark, why don't you maybe hit a little bit about some of the things that we looked, at and opportunities for growth?

Right. There is huge infrastructure needs there. I do think both economies -- probably Chile more than Peru -- but both economies have been affected by the downturn in the mining sector, and effectively China's downturn. So I think that's hurt their overall growth.

But I think when you look at them, where they been historically and what the expectation is for this year and next year, we still see strong underlying growth that you just don't see in any domestic utilities. You still see the 3%, 4% customer growth and 3%, 4% energy growth coming back.

And I think with the recession, we've had a little bit of a downturn there, but we see that coming back. And then on top of that, we see some large infrastructure needs, which really we wouldn't be available to us if we weren't active in that market in the utility market there. We just wouldn't have a presence to be able to capitalize on those.

Again, we don't put those in our plan because we don't have them signed up yet, but we're close on several things, and I think it looks promising. It looks like that there's definitely some activity level that's going to be happening down there that will increase the growth for those facilities.

Got it. Thanks, Mark and Debbie. Much appreciated.

Steve Fleishman, Wolfe.

Couple quick questions; first on the assumptions on the rate case. So you highlight that the guidance includes of the settlement, including the repair tax treatment. Could you just remind me -- I recall that not being a big number, but I just want to make sure I know what the number is for the prior repair tax treatment.

Yes. Let me have Joe walk through the repair tax treatment numbers for you. Let me talk about the rate case, though, while he's getting the precise numbers on that. What I would say is on the GRC, that we've been given every indication that we should be getting a decision soon. And that we're expecting -- since we had eight out of 11 parties sign on to the settlement, that we would likely get the settlement as the outcome. We would also expect to get the repair allowance. Because we feel like we have very strong arguments and have differentiated ourselves in terms of how we handle that in our rate cases going forward, and returning the benefits to customers.

We would anticipate getting a decision hopefully very soon, and that very consistent with the settlement. And what we've been told is that the hang-up and the delay is not any different than when you are hearing from other utilities commenting on their proceedings, is that there is just a lack of resources at the Commission right now, especially in the ALJ division, to get some of these things out as quickly as they would like.

We anticipated it would come earlier, but we continue to be told it will be soon, and that it is really more hung up because of their resource issues.

Joe?

Hi, Steve. Let me just remind you all, Jeff and Dennis and their teams have been working closely with the Commission on this issue. And we've tried to emphasize with them that we have very unique facts that are differentiated from some of the other utilities. And some of those things relate to our rate case was actually worked on and closed, and officially closed by the ALJ before we made our changes in the tax treatment. And in our 2012 GRC, we offered up a sharing mechanism, much like we have in the past, and that was rejected. It was denied.

So we have offered up avenues for them to look at these kind of things. And as we've talked about before, there's very good precedent that the savings you generate before a next rate case -- for all kinds of things, tax and general operating -- flow to shareholders. So we think this will be resolved favorably.

But let me get to the numbers that you asked about. There's two timing periods that are important. One is up through 2014, and then one is 2015. And I'll talk about the first period, first. From the beginning of the rate case through 2014, the intervenors that applied for this suggested that we had about $90 million at each utility that they want to be adjusted through rate base. So that would be a rate base adjustment. And the impact if we lost that -- we don't think we will, but if we lost that -- the impact would be $6 million to $7 million at each of the utilities going forward, because of the change in rate base.

But then the Commission asked us to put a memorandum account together for 2015 savings from this tax repair allowance. And if we were to lose that issue, we will of course appeal it and fight it. But if we were to lose it, we would have to take a charge of about $70 million. It's broken between the two utilities; but in total, $65 million to $70 million in total, for the 2015 memorandum account. Again, I think these are things that we expect to go in our favor. We're giving you all the data (multiple speakers) we've done before.

Okay. But I guess the main reason I asked the question is a scheme of a range that's 720 to 780. These are pretty small when you look at the ongoing (multiple speakers). They are really not meaningful, so I didn't know why you highlighted it out, because it really doesn't move the needle very much at all.

It doesn't move the -- yes, it doesn't move the needle at all in the outer years. It was really a 2016 issue, because if that decision were to come out in the next couple of weeks and we had a negative result, then we didn't want to surprise anybody.

Okay. And just on the Aliso, with the changes to the relocation that you've set up, could you give a sense for what the ongoing weekly cost is? Is there some way to get a sense of that?

Yes, let me hand it to Dennis. I think that one of the things that we need to put in perspective is that we've made a lot of changes to the program that reduced the cost from where it was. Dennis can walk you through, including the number of people that are going home now, which is quite significant.

Dennis?

Let me give you a little color around that, because I think as we get some questions. people want to understand and put it in perspective. When you look at -- first of all, the leak, as you know, was permanently sealed back on February 18. And at that time, when you look at the number of people that were impacted, it was really a -- the vast majority of the households around Aliso Canyon, they never left. They stayed at their homes. Everything was safe and everything. So it was a smaller number to begin with.

But since then, we've had over 54% of any impacted residents that have actually gone back to their homes. And every week, we are seeing more and more. So to give you an actual run rate is difficult. Because as Debbie said, we're doing things within our program that allow us to -- and help the residents move, say, from hotels to corporate style apartments, more family situated apartments, with kitchens where they can cook and everything. And that helps bring down the cost.

The other things that we're doing is we've been offering in-home cleaning services to give further assurance to residents that everything is safe. So, while we haven't given an official run rate, what we can tell you is that the number that we gave out for -- $665 million -- assumed relocation expenses through June 7. And as we said, we expect to get additional information from the Department of Public Health this month regarding their testing. And I think that type of information will even further get people more comfortable that they can go home. And we will see the numbers continue to drop, week after week.

And then just very quickly, last question: Debbie, any incremental color to your year-end call on news on Cameron 4?

Yes, let me just ask Mark to address that, since we've been having some conversations with Octavio recently about how those discussions are going; and actually feel pretty positive about what we're hearing from the customers and the high level of interest.

So, Mark?

Steve, thanks. I think the -- the big thing -- the point to keep in mind is, as far as US LNG exports go, we believe train 4 will be one of the least expensive options available. So that's why we continue to have pretty good interest from people looking at securing that option early, and maybe even in advance of when world demand may require it. So we are feeling pretty confident that it's going to move forward.

Our original statements that we made on the last call, at the end of the year or two, were that we expected to have something wrapped up by the end of the year and that our FID amount would be in the first part of next year. And that hasn't changed. So we're still working towards that. And if we get any indication that things are different, we will tell you right away. But I think right now we're still feeling like this will happen sometime this year.

Yes, and I would add to that just that you all read about what's happening in the markets. We have great expressed interest from customers. They are spending time; they are spending teams on this to negotiate with us. So it's not like they're just saying, oh, we'd kind of like to do something. They are actually dedicating resources to this. But this is a very challenging market to get agreements signed in. And I'd just want to counterbalance that. And honestly, if we get agreements signed in January or February of next year versus December of this year, I will be a happy camper.

We're really focused on it. And as I said, it's not like the counterparties are not engaged fully. They are engaged fully.

Rose-Lynn Armstrong, Barclays.

Can you just talk with a little bit greater specificity about the construction progress at Cameron Trains 1 through 3? And then separately, regarding the Aliso estimates of $665 million -- with regard to the relocation assumption in there, are you assuming that the same number of households are relocating over the entire period? Or is there a decline in trends through June 7?

Sure. Let me take the LNG question first, and talk a little bit about that, and then have Dennis address the assumptions on the relocation. So for Camerons 1 through 3, we are 43% complete. The construction is going really well. We're slightly ahead of our construction schedule. I would say on schedule, but if you look at some of the data are slightly ahead. And that we're still expecting Train 1 to come on in March of 2018; Train 2 to come on in July of 2018; and 3 in November 2018, which was the schedule that we had outlined for you previously.

Everything is going very, very well there. I would say the safety performance has been exceptional on the job. And the major materials, the long lead time materials, have all been ordered. And everything is moving on quite well on construction.

I don't know, Mark, is there anything else you want to add?

No. I think, right now, the project is moving as smoothly as we could have expected it. It's in very good shape.

So, then your second question related to the assumptions that are in the $665 million on the relocation.

And let me have a Dennis address that.

Sure, Rose-Lynn. Yes, as I mentioned, what we did is we assumed that the relocation costs would continue through June 7. And we basically, to be conservative, we've assumed that they stay flat throughout that period. Now, what we are seeing -- and this was incorporated into our assumptions -- is that as we're cleaning more homes, people are going home. They are even more comfortable that their homes are safe and everything. So we are seeing more and more people go home that way.

The other thing that we've been doing that we incorporated into our assumptions is, as we are able to locate more of the family-style corporate housing options within the area, we're transitioning more people from hotels, where they are also receiving per diem, to these corporate apartments where they have their kitchens and we don't have to pay the per diems. So those are the types of -- and that's part of the program that we have, and that's part of the approved program.

So that helps reduce the overall costs, as well. All those things are built into it, but we aren't assuming a huge drop off, but we are seeing that on a week-to-week basis. So I think that's favorable.

Okay, thank you.

Paul Patterson, Glenrock Associates.

So, I just wanted to touch base, just to revisit Steve's question on the growth rate and the repairs deduction, just to understand this. The impact is roughly -- approximately $70 million in 2016. And then after that it really doesn't have much of a significant impact afterwards. Is that the way to think of it?

Yes, Paul. This is Joe. Yes, that's the way to think of it, but the $65 million to $70 million is not in any of our numbers. We are assuming that we win that, and we don't have that impact. So it's really -- if we get a negative impact going forward, there's just really very -- it's not significant, not material.

Okay. Just wanted to double-check on that. And then with respect to the $100 million to $120 million of capacity release and the loss that you guys expect to take in the second quarter on that, what would it have been if you -- I'm just not completely clear. What is it that -- I mean, you did describe it, and I apologize -- but what would it have been if you hadn't done that? Would it have just been pro-rated through -- what was it, 2019 or something, or --?

Yes, Paul, I said that. And so I'll say it again so it's clear. It will be in the transcript. I said that in our plan, the one that we gave you last year, we had for 2016 and 2017 between $5 million and $10 million of losses related to this capacity, because we had a lot of capacity sold forward. It wasn't exactly at the same price we were buying the capacity at, but it was pretty close. So we had a $5 million to $10 million loss for 2016 and 2017.

That did not take into account some of the recent financial troubles that some of the capacity holders had. So if we had kept it, we would have had bigger losses going forward. Which is why, as we try to sell this forward on a permanent basis, we're taking a bigger loss than you would assume from the $5 million to $10 million that had been in our plan.

But for you to go adjust your plans, you were probably basing them off of our numbers. And I wanted you to know what was in our numbers before, which was $5 million to $10 million for the next couple of years.

Okay. And then the potential buyback -- that's kind of a placeholder. And if I understand it correctly, you guys are aiming for better returns with investments, and what have you. But the 12% has this as a placeholder, in the event that you were for some reason not able to find investments. Is that the right way to think of it?

Yes, Paul. That is the way to think about it. And what I'd like to emphasize is, look, we are pretty unique here. Most of our peers, whether they are utilities or midstream companies or renewable companies, are issuing equity to grow. We're actually growing our earnings and cash flow so fast, and increasing the strength of our balance sheet and increasing our dividend 8% to 9% a year over this period, that we are able to actually look at a potential buyback if we don't capture some of these projects we're working on. But we fully expect to capture those projects and do better. We just showed this as an optional thing that is within our control, and we can do. That's unique.

Okay. So if you were to be able to find the investments, the 12% would be on the lower end of the range? Is that the way to think of it?

Yes. Let me just add to that. The 12% is based upon what we already have under contract and in construction. So -- and what our expected utility earnings would be, assuming we get the settlement and the rate case. And then we just assume in out years that we use attrition in addition to that. We try to use conservative assumptions for that. But then we show you all the development projects.

And then, this time, we thought that using the assumption of the buyback was conservative, because we wouldn't be sitting there with 22% FFO to debt on our balance sheet and not do something with it. What we fully expect in the next five years that we will have projects that will have a much better return than what we're showing you with the stock buyback.

But we have, as Joe said, we have wonderful flexibility. To be able to show you five years what we have long-term contracted that yields that kind of a growth rate, and gives us the strength of the balance sheets, that gives us the flexibility, if we were not to find projects, to buy back stock, which we don't think is going to be the outcome because we have a robust backlog of projects that we're working on. But it's just a wonderful position to be in.

And honestly, this is what I was going to talk about at the analyst meeting, because this -- not too many others can talk about having a strengthening balance sheet, having this type of a 12% growth rate with conservative assumptions, and then having the ability to grow the dividend by 8% to 9% over that five-year period of time, with nothing else. So, that was going to be a lot of my presentation. (inaudible) closing what we're going to talk about, but it's a really great position to be in.

And since we didn't do the analyst conference, we wanted you to all understand where we stood relative to that. And we will go into a lot more details, as we always do, when we get to the conference.

Great. Thanks so much.

This does conclude today's question-and-answer session.

I'd like to turn the conference back to Debbie Reed for any closing comments.

Well, thanks for all of you joining us today. And, as always, if you have any follow-up questions feel free to contact our IR team. We look forward to seeing you at the analyst conference. We will let you know as soon as we get a date scheduled so that you can plan around that. And thank you very much for being understanding with our decision to postpone that.

We would not liked to have done that, but we also want to do the best job possible in outlining our business. And I think having the certainty of a rate case decision will be a much better position to be in when we really talk to you about the business.

So, have a great day, and we will see you sometime hopefully in July.

This concludes today's call. Thank you for your participation. You may now disconnect.