桑普拉能源 (SRE) 2011 Q3 法說會逐字稿

Good day, and welcome to the Sempra Energy third quarter 2011 earnings conference call. Today's conference is being recorded.

At this time, I would like to turn the conference over to Mr. Steve Davis. Please go ahead, sir.

Good morning, and thank you for joining us. I'm Steve Davis, Vice President of Investor Relations and Corporate Communications. This morning, we'll be discussing Sempra Energy's third quarter 2011 financial results. A live webcast of this teleconference and slide presentation is available on our website under the Investor section. With us today in San Diego today are several members of our management team including Debbie Reed, Chief Executive Officer; Mark Snell, President; Joe Householder, Executive Vice President and Chief Financial Officer; and Bruce Folkmann, Acting Controller.

You'll note that slide 2 contains our Safe Harbor statement. Please remember that this call contains forward-looking statements that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are not guarantees of performance and represent our estimates and assumptions only as of the day of this call. As you know, they involve risks, uncertainties, and assumptions so future results may differ materially from those expressed on our call. These risks, uncertainties and assumptions are described at the bottom of today's press release, and are further discussed in the Company's reports filed with the Securities and Exchange Commission. We assume no obligation to update or revise any forward-looking statement as a result of new information, future events, or other factors.

It's important to note that all the earnings per share amounts in our presentation are shown on a diluted basis.

With that, I'll turn it over to Debbie.

Thanks, Steve, and thanks to all of you for joining us today. On today's call, we'll start with a review of our financial results. I'll then give you an operational update on our businesses. Before we begin, I want to take the opportunity to acknowledge that two of the long-standing members of our leadership team are joining us today in new roles. As part of our ongoing succession planning process, Mark Snell was named President of Sempra Energy. Joe Householder, who had previously served as our Senior Vice President and Controller, was named Executive Vice President and Chief Financial Officer of Sempra Energy, the role that Mark had held since 2005. In addition, on January 1, Jeff Martin will assume a broader role as the Head of US Gas and Power. And George Liparidis will take over all of our international operation. I will discuss more about these changes later. I think we have a great team in place, one that has worked well together for many years. And one that is ready to build on our success and take the Company forward.

So, now, let's discuss our third quarter and year-to-date financial results, beginning on slide 3. Earlier this morning, we reported third quarter earnings of $296 million, or $1.22 per share, compared with $131 million, or $0.53 per share in the same period last year. On an adjusted basis, earnings for the third quarter of 2010 were $270 million, which excludes a $130 million write-down of our investment in RBS Sempra commodities. Earnings through the first nine months of 2011 were $1.1 billion, or $4.40 per share, compared with $459 million, or $1.84 per share in 2010.

This year's second quarter earnings included a gain of $277 million, reflecting the write-up in the value of our investments in Chile and Peru. And in 2010, earnings included an after-tax litigation charge of $96 million, as well as the write-down of the investment in RBS Sempra commodities that I just mentioned. On an adjusted basis, earnings per share for the first nine months of 2011 were up 17%, compared to last year. And I'm pleased with the strong performance from all of our businesses.

Now, I would like to hand it over to Joe so he can take you through some of the details of our financial results. Beginning with slide 4.

Thanks, Debbie. At San Diego Gas & Electric, earnings for the third quarter of 2011 were $113 million, compared with earnings of $106 million in the year-ago quarter. The increase was due primarily to higher earnings from work in progress, or AFUDC equity, mainly from the Sunrise Powerlink project. For the first nine months of 2011 SDG&E's earnings were $273 million, compared with $264 million last year. The increase was due primarily to the higher AFUDC earnings, net of increased interest costs.

At Southern California Gas, third quarter 2011 earnings were $81 million compared with $78 million in the third quarter of 2010. For the first nine months of 2011, SoCal Gas's earnings were $208 million compared with $212 million last year.

Now, let's go to slide 5. Sempra Pipelines and Storage recorded earnings of $66 million in the third quarter of 2011, compared with earnings of $43 million in the same quarter of 2010. The increase in earnings was primarily due to $11 million higher earnings from the accretive acquisition we made in Chile and Peru, and $18 million higher earnings from nonoperating foreign currency effects in Chile. Partially offsetting this was a net $7 million benefit last year due to nonrecurring items related to our investment in Argentina.

For the first nine months of 2011, Sempra Pipelines and Storage had earnings of $457 million. Excluding the impact of the $277 million gain earlier this year, earnings were $180 million for the first nine months of 2011 compared with earnings of $120 million last year. The increase was mainly due to $31 million higher earnings from operations in Chile and Peru, $13 million higher earnings from the Mexican pipeline operations we acquired in April 2010, and $15 million from the foreign currency benefit in Chile that I just mentioned. I'd note that foreign currency gain in Chile resulted primarily from having over $200 million in US currency at Chilquinta, while there was a strengthening of the dollar relative to the Chilean peso. Some of the gain will turn around in the fourth quarter because the dollar has since weakened. The cash has now been distributed out of the operating company. And because we no longer plan to retain excess funds in excessive of operating needs at Chilquinta, we do not expect to see this as a significant item in future years.

Now, please go to slide 6. Sempra LNG had earnings of $24 million in the third quarter of 2011 compared with earnings of $5 million in the prior year's period. For the first nine months of 2011, Sempra LNG's earnings were $75 million, up from $50 million last year. The increase in earnings for both the quarter and year to date was due primarily to higher revenues for contracted cargoes that were not delivered.

Now, please move to slide 7. Our generation business recorded earnings of $49 million in the third quarter of 2011 compared with earnings of $59 million in the same quarter in 2010. This decrease was primarily due to lower earnings from natural gas-fired power plant operations, was partially offset by an income tax benefit. For the first nine months of 2011, Sempra Generation's earnings were $143 million, up from $60 million last year. Last year's results included an $86 million charge related to a litigation settlement.

I also want to mention that, as anticipated, Generation's 10-year contract to sell power to the California Department of Water Resources expired at the end of the third quarter. This contract anchored our fleet of gas plants for the past 10 years. Also, on October 1, the 480-megawatt El Dorado gas plant was acquired by SDG&E for its book value of about $200 million. And now it will earn a rate base return at SDG&E.

Now let's move to the next slide. As we mentioned on our second quarter call, there is a regulator item that I would like to point out as it relates to our expectations for the remainder of the year. SDG&E has requested the CPUC's approval to recover increased wildfire insurance costs for the period July 2010 through December of this year, which, if approved as filed, will result in about $50 million of earnings. You may recall that late last year, the Commission allowed SDG&E to recover its higher insurance costs for the July 2009 to June 2010 policy period, which resulted in the recognition of $16 million of earnings. It also provided guidance for the future recovery request until our next rate case. And our two requests are consistent with that guidance. The amount and the timing of recovery of these requests will play a key role in determining where within our guidance range we end the year.

Given our outlook for the remainder of the year and the strong performance across all of our businesses for the first nine months, we are on track to meet our 2011 earnings guidance of $4 to $4.30 per share. This excludes the impact of the re-measurement gain from our South American acquisition that we recognized in the second quarter.

And with that, I would like to turn it back over to Debbie, who will begin with slide 9.

Thanks, Joe. Now, let me update on activities in our California utility. In our general rate cases for SDG&E and SoCal Gas, the intervenors in the proceedings filed their testimony in September, and we filed our rebuttal testimony last month. Which sets the stage for settlement discussion. The proceeding schedules call for hearings in December and final CPUC decisions around March of 2012. The CPUC has already approved making these new rates retroactive to January 1, 2012.

Turning to the Sunrise Powerlink project at SDG&E, the project now is about 50% complete and remains on budget. We continue to expect the line to be completed in the second half of 2012. Earlier this year, the CPUC directed the natural gas utilities in California to file implementation plans to comply with new requirements to test or replace all transmission pipelines that have not been pressure tested. We submitted our pipeline safety enhancement plan to the CPUC in late August. This plan calls for spending a total of $3.1 billion over the next 10 years, primarily at SoCal gas. We have requested cost recovery for the first phase, which entails spending $1.4 billion of capital. And about $300 million of O&M expense through 2015 to pressure test or replace pipeline in the highest priority areas. Both SoCal Gas and SDG&E expect the CPUC to allow recovery for all costs associated with complying with these new requirements and to set the appropriate level of spending going forward.

Now, please go to slide 10. Given the dramatic rise in North American natural gas production from shale resources, and the disparity in natural gas prices between North America and both Asian and European markets, several liquefaction projects have now been proposed that would export LNG to international markets. We have strong interest from large creditworthy counterparties who want to procure liquefaction services from Cameron LNG on long-term 20-plus year contracts. Due to the significant interest, we will be submitting an application for an LNG export license from the Department of Energy in the very near future. Our goal is to get long-term contracts, fully utilize our existing infrastructure, and minimize our future investment risks. Given the stature and enthusiasm of the interested parties, we believe this is a realistic objective.

Now, before I move on to the final slide, I would like to provide an update on our strategic planning process. As we discussed on our second quarter earnings call, this is an exercise that we undertake each year to update our five-year business plan. You may recall that I outlined three primary objectives as part of this year's effort, which are to conduct a thorough market assessment to identify opportunities and risks. Review the current and expected performance of our asset portfolio with a goal of getting the greatest value from these assets. And put in place the organization and leadership to execute and deliver on our plans. We recently announced management changes in a business unit realignment, which is an initial step in the evolution of our business. I want to stress that our strategy has been and will continue to be focused on regulated utilities and contracted energy infrastructure.

Our realignment reflects this continued focus. The leaders of our two California utilities, San Diego Gas & Electric and Southern California Gas, now report directly to me. In his new role as President, Mark Snell will oversee our operations outside the California utility. Effective at the beginning of next year, Sempra Generation, Sempra Pipelines and Storage, and Sempra LNG will be consolidated into 2 new business units reporting to Mark. Sempra international and Sempra US Gas and Power. With regard to our market assessment and portfolio review, our work is ongoing and we plan to detail the results at our analyst conference next spring.

Now, please turn to the final slide. To summarize, I'm very pleased with the strong performance across all of our business units so far this year. Our adjusted earnings for the first nine months of the year are up 17% from last year. And we're on track to meet our earnings outlook for 2011.

With that, I'll stop and open up the call to take any questions.

(Operator Instructions) Michael Lapides from Goldman Sachs.

Two questions. One, I know you're in the early stages of taking a strategic look at the various assets. Where do you think you have scale? And maybe more importantly, where do you think you lack scale?

Certainly, Michael, I would say that we have scale at our utility operations, both internationally and in the US. And those are clearly profitable businesses for us. I think that in our US Gas and Power business, this is an area where we want to focus in looking at those assets and how those assets can be utilized, more fully in some cases, and in different ways in other cases, to grow that US Gas and Power business. And Mark Snell and his team will be involved in doing that.

The other question, and this is thinking about the balance sheet over the coming years. How are you guys thinking about in terms of dividend growth versus share buyback versus funding CapEx versus even potential debt reduction or minimizing debt issuances at the holding company level?

Michael, I'm going to ask Joe to shine some light on that further. But let me just say that that is part of our overall strategic review. We fortunately are in a position where we have a lot of good investments, mainly in our utilities. And so, we want to make those investments in our utilities, and we'll be looking at that as a top priority. And then we will be looking at the dividend that always occurs in our February board meeting, where our board looks at that. Let me just hand it over to Joe and see if he wants to shine any more color on that.

Sure. I think, Michael, I would just stay with what Debbie was saying, part of the strategic review is to look at capital allocation. And that question that you asked is simply around capital allocation. How are we going to look at the dividend. We have a policy now, we'll continue to look at that with the board. And we will maintain our strong investment grade credit ratings. That's important to us, so that's something we will focus on. And we'll look at the great investment opportunities we have and decide upon the capital allocation. And whether that includes more capital to the utilities or the US Gas and Power business or more to dividend or more to share buyback, we're going to look at that in this process. We'll be talking about that when we meet in March.

Paul Patterson, Glenrock Associates.

The income tax benefit and generation, could you quantify that?

I'm going to ask Bruce Folkmann to give you the details of that. But it was a component of Mexican tax benefits and obviously we have some solar credits that we're recognizing.

Yes, this is Bruce Volkmann. The Mexican tax benefit is the primary driver for the change in rate. And let me just explain that. It affected Generation and it also touches on our other operations in Mexico. Many of those subsidiaries use the US dollars as their functional currency. During the third quarter, the US dollar strengthened versus the Mexican peso. As a result, US dollar denominated liabilities, generally debt, resulted in Mexican tax benefits. This lowers the tax rate for our Mexican operations and for Sempra. We have economically hedged this exposure in 2011, but the impact of the hedge isn't reflected in tax expense. It's reflected in other income and expense. Another impact of the weakening peso is that our deferred tax liabilities declined in US dollar terms, resulting in lower tax rates. Again, lower tax rates from Mexican operations and for Sempra.

And how much was this?

The impact on generation?

Yes.

It really drove the rate from 25% to 20% -- or negative 20%, rather, of benefit.

So just a dollar number, do we have that? I can circle back after the call, if that's easier.

Yes, we have it. Just one second. I believe it's about $7 million at Generation.

And then the gas pipeline plan, as I'm sure you guys know, PG&E had quite an announcement this morning. And I was wondering whether or not you could just comment. Obviously it's a different situation. If you could just maybe comment a little bit about the pipeline safety enhancement plan and how that differs. It sounds like you're planning on getting full recovery. If you could elaborate a little more on that?

Sure, very much so. I think we are in a different situation, clearly, in that regard. As I told you, the filing that we made is really for new activities that the CPUC is requiring of the utilities as a result of the PG&E situation. And so they are requiring us to test all lines that haven't been tested. And that was not previously required under the regulations. So we made a filing consistent with the CPUC's request. We would anticipate that they would authorize a memorandum account for us so that we could begin recovering costs, or being booking the costs to the memorandum account within the first quarter of next year. And as I mentioned, our total filing over 10 years is $3.1 billion, $2.8 million of that is capital. And then our five-year request for funding, which we have requested to occur prior to the next rate case, is about $1.4 billion in capital. And we fully expect to recover that.

On then on the liquefaction, how much are we talking about? Because that's usually a lot more expensive than the LNG terminal stuff. I know you guys already have some stuff in place and what have you, but could you give us a feeling for what you're thinking about here and what the next steps might be in terms of when we might get a better picture as to what may or may not happen, and the time frame if anything does happen, when that would be?

Yes, let me just give a high level and then I'll have Mark give a little bit more color. We're in discussions with very strong counterparties about making this conversion. But those discussions are still at pretty early stages. And so we don't have a specific structure identified. What we do have identified is that we would only do this if we had a long-term contract. And we would not build something that we couldn't have fully contracted. And in doing this, we would really look at the risks of the investment and structure. We have not taken commodity risks and wouldn't intend to in anything that we would do. So those are the key things from our side that we're looking at in terms of any deal structure. And Mark, do you want to comment?

Yes, Paul, I just would say this. It's pretty early stage. But the good news here is that we have a real opportunity to take the Cameron facility and start utilizing it to its maximum potential. And I think that's really the exciting news. And then beyond that, how we structure it, whether we do this on our own or in partners, we have very sophisticated, large counterparties that we're talking with here that essentially would become our partners in this. And so at the end of the day, we haven't really spelled out ourselves here internally how we would fund this. But it wouldn't necessarily be our capital that we would put at work. There's lots of opportunities to do different things. And I think you should just look at this as a very real and very positive upside to a business that's just coming into its own right now.

I'm wondering, though, can you throw out a ballpark number what a facility like this would cost, given the infrastructure you already have in place? Just in general.

Yes, it could be anywhere from $1 billion to $2 billion. It depends on the size of the facility and what's optimal for the people that we're dealing with, what they want. And so it's pretty wide parameters right now because we don't know how big of a facility that is going to be required, or be desired. So we're looking at all those options and we'll keep you updated. This is a longer-term process because, as the DOE has recently announced, they're going to review the export permits carefully. So this could take some bit of time before this comes to realization. But we should be able to know sometime in the next year how this will move forward. And we'll give you more details as we know them.

Then just finally, the RBS wind-down, are we pretty much set for the rest of the year? I think you've got a little over $300 million there now. Do you expect to get all of that by the end of the year, or any thoughts on that?

Yes, we're on track with what we've told you before. A little bit over $300 million that we would expect to recover. Some of that may come into the first quarter of next year, but we would get the majority of it this year.

And that $7 million gain that we talked about for the income tax thing, is that going to be an ongoing thing, or is that just a quarterly impact with all the stuff you were talking about with the Mexican US debt thing?

This is Joe. That can fluctuate from quarter to quarter because of the difference between the Mexican peso and the US dollar. But think of it as a noncash adjustment to the deferred tax liability, because that's in pesos and we have a dollar functional currency. It moves around, it goes up and down. It usually isn't quite as dramatic as it was this past quarter, because the peso really devalued against the dollar quite a bit in the quarter itself, mostly in the last couple of weeks of the month as we were dealing with the Greek crisis and all that. But I don't expect it to be a significant number from quarter to quarter.

Leslie Rich from JPMorgan.

Can you refresh my memory on your cost of capital mechanism? Do you have that dead band range that annually gets tested to see if it triggers a cost of capital change?

Yes, Leslie, we do, at both utilities. And they are different mechanisms at each of the 2 utilities. The SoCal Gas mechanism is based upon the 30-year treasury and the SDG&E mechanism is based upon the utility bond index. And so, when we've looked at those mechanisms, that we do not expect either of them to trigger. So we would expect to keep the same cost of capital until we get into our next proceeding. SoCal Gas is a little closer than SDG&E is in terms of where we are on the triggering mechanism. But the 30-year treasury would have to fall below 2.81% for the remainder of this year in order for that to trigger. And since it's been over 3 -- it's 3.11% today -- we would not anticipate a trigger.

So is that the kind of thing that's tested once a year, or is that up for potential adjustments?

It's tested once a year. But the last testing, until the cost of capital, will be for us, for SoCal at the end of this year. And SDG&E's test period is earlier and they have already cleared the test period. So basically, unless the 30-year treasury rate goes below 2.81% for the remainder of this year, there would be no triggering at either utility.

Mark Barnett from Morningstar.

Quick question, you may have already gone over this briefly, but I think I might have missed. The time line on the review process for your submitted PSCP program?

Yes, the time line for the review, we're anticipating that a memorandum account would be established in the first quarter of next year. And the memorandum account would allow us to book costs for future recovery. And then the proceeding, it is unclear to us exactly what the timing of the full proceeding would be for the approval of the entire filing, but once we have a memorandum account, then we can begin implementation.

And with the final proposal or accepted proposal, are you expecting it to just take the form of a rider?

I'm not sure I quite understood.

Like an ongoing rider mechanism?

What we filed for is a surcharge, and that surcharge would stay in place until our next rate case. And then on our next rate case, they would look at the future periods and put into our next rate case an amount to continue with the $3.1 billion over the next 10 years that we've requested. So we broke it into two pieces. The first piece is $1.7 billion, and $1.4 billion of that is capital. And we would look at that, getting the memo account to begin that, in the first quarter of next year. And then the second piece would occur after the rate case period.

And just one more quick question. Would the LNG export, the impact on your existing import capability, would there be any, just in terms of physical space? Or how might that work?

As you probably know, Cameron is about 33% contracted and so the facility has capacity to add the liquefaction and keep the gasification plant in operation. So we would envision that we would be able to do both at that facility.

Faisel Kahn from Citi.

On the El Dorado plant that's dropped into SDG&E, do we see an immediate true-up in earnings as that plant is dropped in?

It goes into rate base immediately. And that was under a separate proceeding, so there should be a true-up in earnings for that plant, because it was not part of the GRC. It was incremental to the GRC. It was transferred in the beginning of October at an amount of a little over $200 million.

And then on the $3.1 billion capital plan for pipeline integrity, and replacement at SoCal Gas, do you envision that being front-end loaded, or is that going to be equally amortized over a 10-year period?

As I mentioned, over the first five years, we're requesting $1.7 billion out of the $3.1 billion. So it's a little bit front-end loaded. But out of that $1.7 billion, we're estimating about $1.4 billion of that being capital, and the most of that is SoCal Gas.

If I'm just looking at your earnings from the gas pipeline and storage business that you guys have right now, how much of that earnings is -- or Pipelines and Storage business -- how much of that earnings is from foreign entities? What percentage, if you can give me an idea?

I know that 60% of that is really coming from our utilities, and that includes our utilities in Chile and Peru. I don't have a precise percentage of how much is foreign. But I would say it's probably pretty close to that 60%.

And then on the LNG side, in terms of the earnings that we're seeing from the LNG segment, is almost all of that coming from Costa Azul or is there a little bit of contribution from Cameron?

There's some contribution for Cameron from the unique contract that we have. But the bulk of that is Costa Azul where we have the plant fully contracted and the contracts provide for, if there's a lack of delivery of cargoes, a fee to be paid.

On your statement of operations by business unit, and the table that you guys provide, I was wondering if you could clarify just a few line items. In your consolidated adjustments to parent and other, you've got a $32 million loss in the other segment. It's other income expenses of $32 million.

Faisel, you were fading out. Can you repeat that question?

Yes, sure. In table S in your release, you guys talk about a $32 million expense under parent and other. It's in the other income and expense net. I'm just trying to figure out what that is. It's a big number year-over-year. And then there's also a large income tax item, too. So I just want to understand what those movements are.

Okay, I'm going to have Joe handle the details on that.

Yes, Faisel, as Bruce was mentioning earlier on the Mexican tax issue, we have the FX and inflation effect on monetary assets in Mexico. And we hedge that so that we don't have cash flow and earnings fluctuations from that. But the hedge is at the parent, so there is a hedge loss in that $32 million number. And the income tax benefit is the Mexican tax benefit that is offsetting that, down in there. So that's what's going on. I don't know if, Bruce, do you have the actual number?

That's the main driver.

Yes, that's what's happening there. The other thing I would mention, in that column is that in the $17 million right above the $32 million, we had a small adjustment to our net book value in the RBS Sempra commodities, which resulted in about a $10 million after-tax impairment there. So that's what that $17 million is.

And at SDG&E, the earnings attributable to noncontrolling interest, that negative $21 million, it's a very large change over last year. Just trying to figure out what that is, too.

It's from the Calpine Otay Mesa plant that we have to consolidate.

So it's a variable interest rate entity or something, right?

Yes, that's right.

Winfried Fruehauf from W. Fruehaul Consulting Limited.

Regarding the termination of the contract with the California DWR, what is the estimated annual loss in earnings resulting from that termination of the contract?

Winfried, as you know, the contract expired on the 30th of September. And I would say that the impact of that was fully considered in our guidance that we gave you. When we gave you the guidance and Jeff went through all of this at the analyst meeting, that impact was fully considered in our guidance. We don't disclose details on specific contracts. But I would say that there's been some positive things happen since that time, including us contracting with [Spur] for 240-megawatts. And we just are seeing some increased value of those assets. So I think if you look at our guidance, you can pretty well determine what we're anticipating there.

And have you any other plans to mitigate the impact of the loss of earnings on that contract with the California DWR?

Yes, we do. I'll have Mark talk about some of the things we're doing. But certainly one of the things I want to stress is that we are really ahead of our plan on renewables. We had planned to add another 1,000 megawatts over the five-year period. We're more than halfway there already. So those are the kinds of things. And Mark?

Yes. I think we've already done it. We've taken a couple of steps already. One, we've signed some long-term contracts, as Debbie mentioned, with other counterparties that are going to start in the next couple of years, and they are fairly good size. The other thing we did, of course, was we did, as part of the DWR contract litigation settlement, agreed to transfer El Dorado into the utility at rate base. We have 2 plants that we're in the market marketing, and taking a look at what we can do to enhance their value. And we're making some real progress on that. Also, as part of the strategic review, we continue to evaluate the progress that we're making on that against what we could sell those for in the market. So I think we're always open to doing whatever we think is in our shareholders' best interest.

Before we go on to the next question, I would like to clarify or modify an answer that we gave earlier. When we were looking at the percentage of foreign earnings coming out of our Pipeline and Storage business, we talked about 60% coming from our 2 utilities. And that is correct. The part that we didn't include is all of our Mexico operations. And so the percentage of the Pipeline and Storage earnings that are foreign is about 90%.

I have one more question, if I may. And relates to the decrease in earnings from your natural gas-fired generation plants. What caused those lower earnings?

One was the tax thing that Joe had talked about already. And then the other was, last year, we had about $6 million of marked-to-market gains in the amount, and this year we had about a $5 million mark-to-market loss. So that net change of $11 million makes up really most of the difference.

This is Joe, Winfried. The TDM plant was down because of a fire for part of the period.

And are you expecting any insurance compensation for the outage?

I don't think it was out enough days to collect on the insurance, but there might be some small recovery.

So other than this fire, there were no operational reasons that contributed to the lower earnings?

No, there's no operational reasons, but the market for power was lower in the period than it was in the year-ago period, too.

So notwithstanding favorable natural gas costs, that advantage was wiped out, either in whole or in part, by lower electricity prices?

Yes. When you're in the generation business and you have very efficient plants, favorable natural gas prices don't always help you, right? Because a lot of times, as you have lower gas prices, that tends to lower your advantage.

Kit Konolige from Ticonderoga.

I think, Debbie, you mentioned in the GRC that the filing so far, I think you said, sets the stage now for settlement discussions. Can you discuss any likelihood that it will reach a settlement? And if it does, what the timing on the settlement might be?

Once all the parties have filed their testimony, as has now been done, then this is the time when we can begin some settlement discussions. I cannot comment on settlement discussions because they are confidential. But I can tell you that we have settled all of our several rate cases. We think that in terms of what our past practice has been, that we would very much like to work with the parties and see if we can't settle this rate case, as well. But we're pleased also, if we need to go to litigation on it, we can go to litigation, because we think we have a very strong case. So we'll see if we can reach settlement. We've had a history of doing that, but if we can't, we are prepared to go into hearings in December.

And if there were to be a settlement based on your history, when might that occur relative to, say, the December hearings or the March litigated decision time line?

That's hard to call because we've had some settlements that occurred before the hearings began, some settlements that occurred during the course of hearings, and some settlements after the hearings when the case was wrapped up. So I would say sometime during the next six months would be likely, but to call it beyond that, I wouldn't be able to.

One separate area, if I could. You talked about the pipeline safety initiative and the higher spending that might be involved there. At what point do you get concerned that the level of CapEx for that kind of program, in addition to the other spend you're doing at the utilities, starts to imply rate increases that get difficult to see implemented, such that you can earn the allowed return?

Let me address that, because I think the thing that is fortunate for us is that SoCal Gas has some of the lowest bills in the country. Our average gas bills are $40 to $50 on an annual average basis. So we have very low gas bills. And so I think that, because of the focus on safety and because of the need to make these kinds of investment in the system, I think there's room in those bills to accommodate this kind of expenditures because we start with very low bills.

And does the gas initiative apply to SDG&E as well?

Yes, it does apply to SDG&E, but as I said, most of the dollars are on the SoCal gas side. Over the next five years, we're only requesting about $200 million on the SDG&E capital side. And the $3.1 billion includes both utilities.

Mark Siegel from Canaccord Genuity.

Could you provide an update on the time line on your smart metering project at SoCal Gas? And then also, has the introduction of an opt-out clause or an opt-out option on some of the electric meter AMI products going on right now had any impact on your planning or the scale of your gas project?

Good morning, Mark. On the SoCal Gas side, we're doing all the IT work, the systems work right now for the AMI roll-out. And we will start putting meters in at the end of next year, beginning of 2013. And we would go through 2017 with our installations. As far as the opt-out, it's interesting. We haven't had, on the SDG&E side, a big desire by customers to opt out. We've had basically virtually no complaints on our smart meter program at SDG&E. But I would say that what we did is up-front, we spent a lot of time acquainting customers with the system, what the advantages are, how to use this to their benefit. And so I think that we would be doing the same types of things at SoCal Gas. And on the SDG&E side, we're nearly finished. We're at about 98% completion right now. And I think our total complaints were like 0.16% of customers. So it's nothing. So we had good experience at SDG&E. We will apply that experience to SoCal.

Vedula Murti, CDP Capital.

I'm wondering, in terms of if there is ultimately going to be some tax changes in terms of foreign repatriation and that type of thing, can you quantify in aggregate, what type of investment dollars or income that has the ability or cash that you have that is offshore right now, that might be able to be repatriated back into the United States at some point in time, that can either help fund the capital program or any other types of entries you might choose.

This is something that we are very much on top of. We have been involved in trying to work on a territorial tax system for the reasons that you say. Because over time, we do produce a lot of cash offshore that we would like to be able to bring back. So I'll have Joe go through the particulars of how that builds up over time.

Sure, thank you. Vedula, we support, as Debbie said, either a territorial system or lowering the corporate tax rates in the US, or both. We're very encouraged by the dialogue that's happening now and the recent draft legislation from the House Ways and Means Committee. You asked a question about what we would do if there were a temporary bill, a tax holiday, if you will, and we're prepared. We have plans in place and we're prepared to lever up all three of the businesses where we have operations. And we have fairly low debt levels in each of those three countries. But recall also, that we have very attractive growth opportunities in each of those three countries. So we do have opportunities to spend the money there, but I think if we had the chance of repatriating some money, we would probably lever up and bring back at least $1 billion.

So $1 billion would be able to come back to the United States to help fund the utility capital program or the other US-domiciled business?

Yes. Money is fungible so it would go for our whole capital program, wherever that may be, or other resource needs that we have.

And at this point when you lay out your capital program and financing and everything like that, you make no assumptions that that actually occurs?

We do not.

Ashar Khan from Visium.

Can I just ask you, you mentioned that depending upon the wild fire insurance proceeds, will depend where you end up as part of the guidance. So what is in dispute over there, the amount or getting it this quarter?

I'll address that, Ashar. Good morning to you. We have filings before the CPUC now that would provide for recovery of about $50 million on an after-tax basis. And last year, we got a decision granting us this incremental amount for wildfire insurance. And this year, we followed the process which was to file an advice letter, which we did for part of this in April and part of it in September. So if you look at the history, we recovered these amounts last year. The issue that we don't know when a CPUC decision might come out for this year, for the $50-plus million of earnings that we're waiting for from the incremental fire recovery.

So the issue is only that it might go from the fourth quarter to the first quarter, right? So that's the issue, it's not the amount?

I can't speak of what the Commission will do, but I can tell you that last year they approved the recovery of a filing that we had for $29 million, or $16 million after-tax. And we recovered all of that in December of last year. What the Commission does going forward, I can't say what they are going to do. But we had a history of recovery and now it's largely a timing issue.

Michael Worms from BMO.

This may be a question more for Mark. But with regard to the Cameron facility and developing a liquefaction plant, and I know it's very early in the process and there's a DOE review at least at some point, but what other regulatory approvals might you need? And let's just assume for argument sake that at some point you get a green light and you go forward with all of this, what's the timeframe at that point to completion when the liquefaction plant will actually be operating? How long are we looking at? Three years, five years?

Yes, I'll have Mark answer those questions for you.

On the regulatory side, the other fairly big permit that you need is from the FERC, as well. And then there's a host of other construction and environmental permits and those kinds of things that you'd have to go through in that area. But I think the FERC permit could be a 12- to 18-month kind of process. Beyond that, the construction period, it will depend a lot on the type of facility, the size, and how long it will take. But you would think of this as a couple-year construction period at a minimum. So it's fairly far down the line. And really, our purpose in highlighting it today is because of the swirl of activity around it. And also because we do plan to file for our DOE permit and you're going to see that as a public filing and we wanted to give you a heads-up on that.

(Operator Instructions) Michael Lapides from Goldman Sachs.

And this may be a Jeff Martin question. Just curious, in terms of when you're looking out at the California, Nevada, and Arizona utilities, where we are in terms of the RFP or the RFO cycle. Meaning, when was the last time RFOs were issued by the 3 big California utilities, Arizona and Nevada ones? When do you expect to get answers back from them? When would decisions likely occur?

As I mentioned, we already were successful in the Spur deal for 240 megawatts. And there is an RFP that is out right now and so I'll have Mark talk about that and the timing.

Yes, I can't disclose a lot about the RFP process other than to say that all of Nevada and Arizona utilities are looking at different opportunities to change their generation mix. The desire to wean themselves off of coal, move into natural gas-fired generation and also to move into renewables is strong. We're working with all the interested parties on a lot of different projects. But they will get done when they get done. There isn't really a season for this, although they do tend to try to solidify their summer, their peak load needs early on. But most of these are multi-year types of engagements, and so they are not really geared towards -- it's not like, we're not just looking for next summer, they are looking for multi-year kind of commitments.

And with no further questions in the queue, I would like to turn the conference back over to Debbie Reed for any closing remarks.

Thank you for joining us for Sempra's third quarter 2011 earnings call. If you have any follow-up questions, please contact Steve Davis, Scott, or Victor. And have a great day.

And this concludes today's conference. We thank you for your participation.