桑普拉能源 (SRE) 2012 Q3 法說會逐字稿

Good day and welcome to the Sempra Energy third-quarter earnings call. Today's conference is being recorded. At this time I would like to turn the conference over to Mr. Rick Vaccari. Please go ahead, sir.

Good morning and thank you for joining us. I'm Rick Vaccari, Vice President of Investor Relations. This morning we'll be discussing Sempra Energy's third-quarter 2012 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 are several members of our management team, Debbie Reed, Chief Executive Officer, Mark Snell, President, Joe Householder, Executive Vice President and CFO, and Trevor Mihalik, Controller and Chief Accounting Officer.

Before starting I'd 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 reports filed with the SEC. It's important to note that all of the earnings per share amounts in our presentation are shown on a diluted basis and that we will be discussing certain non-GAAP financial measures. Please refer to the presentation slides that accompany this call and to Table A in our third-quarter 2012 earnings 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, November 6, 2012, and the Company does not assume any obligation to update or revise any of these forward-looking statements in the future. With that, I'll turn it over to Debbie.

Thanks, Rick, and thanks to all of you for joining us today. I know many of you are on the East Coast recovering from the effects of Hurricane Sandy and we appreciate you taking the time to be on this call. SDG&E has sent more than 40 employees and 20 pieces of heavy equipment to help Con Edison repair overhead power lines damaged by the storm and we will continue to do whatever we can to provide assistance. Moving to our call, today we'll review our third quarter financial results and provide updates on operational matters at all of our businesses, on regulatory matters at the California utilities and on our outlook for the remainder of the year.

Let's begin with our financial results. Earlier this morning, we reported third-quarter earnings of $268 million or $1.09 per share. Excluding a $60 million after-tax non-cash charge related to our investment in the Rockies Express Pipeline, or REP, adjusted earnings for the third quarter of 2012 were $328 million or $1.33 per share. In the third quarter of 2011 we reported earnings of $289 million or $1.20 per share.

This quarter, we were able to grow our adjusted earnings despite the loss of the CDWR contract which you'll remember expired in September of 2011 and I remain very pleased with our operating performance. We continue to execute on our strategy through the sale of 50% of our Mesquite Power Plant, our plans to build a new pipeline in Mexico, and our continued progress on the liquefaction project at Cameron. Now let me pass things over to Joe to take you through the details of the financial results beginning with Slide 4.

Thank you, Debbie. At San Diego Gas & Electric, earnings for the third quarter were $174 million, up from $113 million in the year-ago quarter. The primary driver of the increase was a $38 million reduction in tax expense due to a change in IRS tax law regarding how repairs on electric transmission and distribution assets are treated. $22 million of the benefit recorded in 2012 is related to the 2011 tax year, while the remaining $16 million relates to the year-to-date tax benefit for the 2012 tax year. Also benefiting the quarter were $12 million of increased transmission earnings including the impact of Sunrise Powerlink which is now in rate base.

I want to take a moment and discuss recent developments in our wildfire expense balancing account, or WEBA, proceeding. Last month, the CPUC issued a proposed draft decision denying SDG&E's request for approval to establish a mechanism to record claims paid out in excess of our insurance. They instead suggested we use an alternative mechanism, the Z-factor for recovery which is the same mechanism we use for excess wildfire insurance recovery. The assigned commissioner in this case issued an alternative draft decision approving a rate recovery mechanism for fires occurring after July 2010. Similar to the proposed decision, this alternate decision indicated that SDG&E can seek recovery for 2007 wildfire costs through the same Z-factor mechanism.

After reviewing these documents, considering the statutory and regulatory precedents, and communicating our concerns to the assigned commissioner through an ex parte meeting, we continue to believe that it is probable that SDG&E will be permitted to recover substantially all costs related to resolving wildfire claims in excess of insurance through customer rates and from amounts recovered from other responsible parties. As of September 30, 2012, we have recorded regulatory assets arising from wildfire litigation costs pending regulatory approval of $326 million. Of this amount, $292 million is related to CPUC operations while the remainder is related to FERC operations. In February of this year, FERC approved a settlement allowing for the recovery of wildfire-related costs expended through March of 2011.

Each quarter, we must determine the extent to which it is probable that we will recover costs and be able to reasonably estimate the recovery. As we have disclosed previously, any negative assessment of the probability of recovery would likely have a material adverse effect on SDG&E's cash flows and results of operations. If the Commission fails to act or it acts in a manner which results in a negative assessment of the probability of recovery or in a manner that affects our ability to reasonably estimate the amount of the recovery we will record a charge against earnings at the time such conclusion is reached. As of September 30, this would have resulted in an after-tax charge to earnings of approximately $175 million. But to be very clear, we will continue to pursue recovery of substantially all of these costs and given statutory and regulatory precedent believe it is probable we will be successful in those efforts.

Now moving on to Southern California Gas. Third-quarter 2012 earnings were $71 million compared to $81 million in the third quarter of 2011. The decrease was primarily attributable to higher depreciation expense with no increase in authorized revenue due to the delay in our GRC decision. Keep in mind that until we receive final decisions in the SDG&E and SoCalGas general rate cases we will be recording revenues based upon 2011 authorized levels plus an adjustment for recovery of incremental wildfire insurance premiums at SDG&E based on recent CPUC decisions for recovery of prior years' increased premiums. Once the general rate cases are decided, we'll record the cumulative impact of the decision from January 1, 2012. In the event that a final decision is not reached until next year, the cumulative impact from the decision will be recorded in 2013 earnings, not 2012.

Now please go to Slide 5. At our South American Utilities, earnings were $40 million in the third quarter of 2012 compared to $50 million in the year ago period. Last year's results included a $19 million non-operating foreign currency gain related to cash held in Chile at that time. Third quarter 2012 earnings for the Sempra Mexico segment were $54 million compared with $47 million in the same period last year. The increase was primarily due to improved operating results across our businesses in Mexico.

Now please turn to Slide 6. Moving on to Sempra US Gas & Power. The Natural Gas segment lost $68 million in the third quarter of 2012. Excluding the $60 million charge related to REX, the segment lost $8 million. The loss in the quarter was driven primarily by lower natural gas prices affecting our US LNG business. The decrease from the third quarter of 2011 was mainly attributable to lower natural gas and power prices including the impact of the exploration of the CDWR contract which, as Debbie mentioned, expired on September 30 of last year.

As you may recall, Kinder Morgan a 50% owner of REX, has agreed to sell its interest in the pipeline to Tallgrass Energy Partners. In the third quarter as part of this sales process, additional market information became available that required us to reconsider the current value of our investment and as a result, we recorded a $60 million after-tax non-cash charge. As I mentioned last quarter we continue to expect to effectively recover our original investment in REX, on a cash basis, through a combination of distributions and tax benefits prior to the end of the existing contract periods.

When the sale closes, which is expected to happen later this month, we will receive a $41 million cash payment from Kinder Morgan related to a tax make whole provision in the LLC agreement. This will partially offset the impact of the charge on full-year 2012 results by $25 million after-tax which we expect to be reflected in fourth quarter results assuming the deal closes. The renewables segment generated earnings of $13 million in the third quarter of 2012, up from $1 million in the same period last year. The increase was driven by the addition of solar and wind assets.

I am also pleased to announce that we are finalizing agreements with the Salt River Project, a utility in Arizona, to sell a 625-megawatt block of our 1250-megawatt Mesquite natural gas fired power plant. We expect to receive a price of approximately $600 per kilowatt which is in excess of our book value. The transaction is contingent on executing definitive agreements and receiving necessary regulatory approvals and the deal should close by the first quarter of next year. And with that, please turn to Slide 7 and I'll hand the call back to Debbie.

Thanks, Joe. Last month, Sempra Mexico announced plans to build a 510-mile pipeline project that will transport natural gas from the US/Mexico border, south of Tucson, Arizona through the Mexican state of Sonora to the northern part of the Mexican state of Sinaloa. This project which should cost roughly $1 billion will support Mexico's initiative to convert more of its electric generating capacity to natural gas. We expect to fund this project entirely through Sempra International's operating cash flows and Sempra Mexico's ability to access external capital. The pipeline will be supported by a 25-year take-or-pay contract with the Mexican state-owned electric utility, CFE, which will be de nominated in US dollars.

We expect the project to come on line in two phases. The first phase should start operations in the second half of 2014 and we expect the second phase to be online in the second half of 2016. This project represents a great growth opportunity for Sempra International and will add another asset with attractive returns to our portfolio of operations in Mexico. Now let me provide you with an update on what we've been doing to move forward on our plans to develop a liquefaction facility at Cameron LNG. Work on the front-end engineering and design of the project is ongoing and should be done by early December. With that process complete, we will be able to file our formal FERC application later that same month.

As you'll recall we made our pre-filing with FERC in April and that document, which was well over 1,000 pages long and contained detailed project and environment information, paves the way for our formal FERC application. We have always planned to complete a full environmental impact study, or EIS, as part of our application to ensure that FERC has comprehensive information upon which to approve our projects. The completion of the engineering work will also allow us to go out for EPC bids early next year as planned and we expect to get the bids back in the second half of 2013.

In September of this year the Department of Energy announced that it was delaying the release of its study on US natural gas exports until the end of 2012. We continue to expect to receive a DOE non-FTA permit late this year or early next year and we don't anticipate that the delay in the report will have a material impact on the overall timeline of the project. We expect to finalize negotiations on both our tolling agreements and JV participation agreements by mid-2013 and continue to believe that we will have received all necessary regulatory approvals by the end of next year, at which point we will begin construction on the facility.

Now let's go to Slide 8. I'd like to update you on some of the key regulatory proceedings of the California utility. As we mentioned earlier we continue to await a final decision on our general rate cases and the current CPC calendar calls for a decision by year-end. However, as Joe mentioned if a decision is not received by year-end the retroactive impact of a decision back to January 1, 2012 would be recorded in 2013. Turning to our cost of capital filings at SDG&E, and SoCalGas, evidentiary hearings concluded last month and all briefs have been filed.

A draft ALJ decision is expected by November 20 in time for us to receive a final decision as scheduled on December 20. The new rate set in this proceeding will be effective January 1, 2013. As a reminder for SDG&E, this cost of capital filing only covers CPUC jurisdiction all assets. SDG&E's electric transmission assets are regulated by the FERC which currently has an authorized return on equity of 11.35%. The currently authorized FERC return on equity is effective until September 2013.

Our pipeline safety enhancement plan is proceeding on schedule. We continue to expect a decision on our PSEP in the first half of next year and continue to receive public comments from commissioners that our filing and past performance are viewed positively. Finally, as Joe mentioned earlier, we did receive both a proposed and alternate decision on our WEBA request and we continue to expect that we will be permitted to recover substantially all these costs either through rates or settlements of third parties.

Let's move on to Slide 9. At this point in the year we would typically have good visibility on our full year results, but due to the delay in our general rate case proceedings at SDG&E and SoCalGas we are not currently in that position. However, due to the strong performance across our businesses, we currently believe that assuming we receive a final rate case decision in 2012, our full-year earnings will be at or slightly above the high end of our prior guidance range of $4 to $4.30 per share. In the event that a decision on the GRC is delayed into 2013, we believe that full-year 2012 earnings will be around the low end of that range.

This full-year guidance excludes the $239 million year-to-date charges related to REX and a $47 million year-to-date tax benefit related to Company-owned life insurance policies which we discussed on the second quarter call. Now let's go to the final slide. We are on track to execute on our strategy and meet the goals we laid out for you in March. Through our sale of one half of Mesquite we will further reduce our exposure to merchant generation and will redeploy that capital to areas of the business that fit better with our long-term strategy. Our operational results were solid again this quarter and our ability to more than offset the loss of the CDWR contract shows the strength of our businesses. We are excited about our future prospects and I'm pleased that we continue to find excellent growth opportunities as we've done with our new Mexican pipeline project. With that, I'll stop and open up the call to take any of your questions.

(Operator Instructions)

Faisel Khan, Citigroup.

So just had a couple questions, one on LNG, and one on the Mexico pipeline. On the LNG liquefaction proposal, there was recently some statements made by a DOE official stating that he didn't think that the DOE would be granting non-FTA export license until 2014. And then he went on to say there's really only two projects in the queue that are on track to meet all these requirements to get that approval by 2014. Can you just talk a little bit about why this differs from kind of what you're saying and you expect the DOE will be looking at your filing in 2013 and maybe even later this year? And then I have a follow-up on the Mexican pipeline.

Okay, sure. Well let me address your first question and then we'll go to your second. In terms of some of the comments that have made on non-FTA permit and timing of that, there have been a lot of comments that have made in different presentations that have been made from members of DOE. I would say that one of the comments that was made was an error and actually there was a withdrawal of that comment and I think it was related to the comment that you're referring to. What we're hearing is that the report will be out later this year and that after the report is out there would be a comment period of about 60 days. And then after that comment period, the decision would be made regarding non-FTA. So we feel we'll be seeing that some time in early 2013. Mark, I would ask if you have any additional comments you want to make on that?

Yes, Faisel, it was unfortunate, but the comment that was attributed to a member of the DOE staff was actually not made by a DOE person. It was made by an outside consultant speaking at the same event and it wasn't really intended to be -- it was more of a reflection on market conditions, not on regulatory permit restrictions and we really think it has almost no bearing on our permit or any of the others that are being processed now through the DOE and the FERC. We expect to go forward, as you know there has been a delay and the issuance of the DOE report. We don't expect that to affect our project. We're moving forward. We should have our full engineering study done by the end of the year and we expect to file our FERC permit some time in late December, with the full engineering study. So we're moving forward on this and we really don't expect this to be a big deal.

Okay, great thanks for that. That makes it clear and my second question is on the pipeline development in Mexico. In the past, you've talked about dividending out cash flows from your South American operations and taking a tax hit up here in the US for repatriation of that capital. With the development of this pipeline does that change how you're allocating your cash flow from these international assets into this project to potentially the dividends you're receiving back from those assets in the US?

As you will recall that we were planning as you mentioned to repatriate dollars back over the five-year planned period beginning in late 2013. We're still planning to do that and the amounts that we were looking at over the five-year period, we believe are going to be consistent with what we showed you in the five-year plan so we don't see any real change in that as a result of these pipelines.

Okay, great. Thanks for the time.

Greg Gordon, ISI Group.

So I just wanted to be clear on the earnings guidance. Presuming you get a decision on the GRC this year which hopefully you will, your guidance at or above the high end of the range excludes REX, excludes the parent life insurance but includes the tax benefit that you booked in the third quarter at the utility operating companies, correct?

That is correct.

Okay, I just wanted to make sure. That is it. Thanks.

You're welcome.

Naaz Khumawala, Bank of America.

I have a five-part question on the wildfire case. (laughter) Sorry, Steve made me say that. So, actually real questions that I have, one is on the REX writedown. Phillips also took a writedown this quarter, and I know you guys know that. Their writedown was a little bit bigger than yours was. I don't quite understand how these determinations are made and if it's the same pipe, is it just based on your forward projections on how this is done and what more could trigger a writedown past this point?

Sure. Let me address at a high level and we'll have Trevor or Joe go into more detail. What I would say is going through the process of assessing this, it's our best estimate and we consider all factors involved as there was a [rofer], and this quarter we had information on the rofer. We also had the opportunity to have discussions with Tallgrass and understand their strategy long-term for the development of the pipeline and what they might do to change the operations, the flows on that pipeline.

We did market modeling and had various models that we consider and we did a full assessment of all of the data that was available to us and put a significant amount of weight on the rofer and made our determination of what we felt the value of the line was. In terms of, in the future, we have to assess as information becomes available to us, if that changes any of our modeling, if it changes our assumptions, if there was a sale by one of the parties and we had information on the prices that the pipeline share was sold at, whether it's a forced sale or it's a really full open market sale,. All those are things that are considered in terms of the valuation and that's the process we went through and concluded that the level of $369 million for the value that the line was an appropriate level.

Yes, Naaz, this is Trevor. Just to reiterate a little bit of what Debbie said here, again we got the rofer in the third quarter so that was another market level input that we needed to consider in determining the equity value from an accounting perspective. We weighted that input at about 2/3 of the value and then we utilized the other inputs that we used in the second quarter as about 1/3 of the value and that's because the rofer was more of a level two input from an accounting perspective and the other unobservable inputs were level three. So in determining that, we came out with a fair value of approximately $369 million for the quarter, and so we disclosed that also fairly significantly in our Q.

Okay, great. Thank you, and then on the Mexico pipeline, just had a couple quick questions. One is how much Bcf a day of capacity will flow on that and then when we think about returns on the pipe, should we weight them more toward International returns or more toward utility-like returns? If you can give perspective on that.

Let me just go through the high level of the pipeline and the returns. In terms of the pipeline, as I mentioned, it was going to cost about $1 billion and it's a little over 500 miles. We are expecting returns on that pipeline that are slightly higher than what the ROEs are that we have authorized by our California utility so that's the kind of return we would expect for the pipeline assets that are contracted with CFE for 25 years. And in terms of the Bcf a day I'll have Mark talk about that.

Yes, the pipeline is in two phases. The first phase is a little under 800 a day and the second phase is a little over 500 a day.

Okay so 1.3 in total.

Well, no, no. I wouldn't add it together. It's a little under 800 coming down to a certain point and then it gets-- (multiple speakers)

Oh, I see what you're saying. Okay, thank you. That's helpful.

Okay.

Thank you.

Kit Konolige, BGC.

So just to follow again on the Mexican pipeline, can you give us an idea of then -- sounds like you will finance it at the project level. And so how should we view how much equity you would have in that business, either parent-level cash or net investment or even parent-level equity that would be attributable to that? And then if you could discuss a little bit what, under the contract do you get dollars that can be repatriated immediately or is this generating more cash that's held overseas?

Okay, let me just give you a very high level and then I'm going to have Joe go into our thinking on the financing. At first, I would say, as you know, that we have a lot of debt capacity still in Mexico and we've talked about that in prior meetings. We are looking at all the options for the financing of this and what ends up being the best for us in terms of the goals that we have in lower rates and security and all. So let me turn it to Joe and he will go through kind of where we are. Let me just also say though, we haven't made a decision. I mean we just really got the notification that we received these and so we're going to look at all of our options there so Joe?

Yes, thanks. Hi, Kit. We're very excited to have this new project be part of our growth profile and the sources of the capital that we're going to use to fund it will depend on minimizing our cost, maintaining the strong credit quality we have, and enhancing our financial flexibility. Part of that will be looking at the dividend, as you mentioned. And as we begin to incur significant expenditures as we start to develop this project, we'll work on finalizing that approach and let you know as we know more about how we're going to do that.

But it will produce dollars, but those dollars will be part of the retained earnings and then depending on how we finance it we'll have to look at what we do to bring that money out. It doesn't immediately just come out. It obviously will be part of our whole Mexico franchise and we'll have to evaluate those dividends. As Debbie mentioned earlier, to Faisel's question, we will be continuing with the program of about $300 million a year into the near term as we see that going unless something happens here in the election and we see a different tax regime.

Okay, and on a separate topic then. Your guidance for 2012 now, assuming that you did get a decision in the GRC by the end of the year and therefore, you'd then, I gather, be indicating you'd be at or slightly above the high end of the current range. But that's with what I calculate is something like $0.15 of the tax special item or one-time sort of item. A, is that an accurate way to look at it; B, compared to at the analyst day earlier in the year, which segments are stronger and which are weaker than you'd thought at that time?

Yes, first let me say that the special tax item that I think you're referring to, we're taking out the COLI which was not a tax item. We're taking out the REX, and that's what our guidance includes. And then we had the tax item at SDG&E this quarter which is really not a special tax item. It's an ongoing change in how taxes are calculated for SDG&E and so we should see that impact continuing into next year, some of it. Part of it, about $0.09 a share this year, was retroactive to 2011 and the remainder of it was for 2012 and would continue subject to no other changes into 2013, so I just want to clarify that it wasn't a one-time item or the majority of it was not a one-time item.

Very good. Okay, and so then segments compared to the analyst day, which are doing better than you thought and which not as well?

Yes, if you kind of look at our segments, SDG&E has had a very, very strong year and when we get a rate case decision, SoCalGas will have had a very strong year. We are booking based upon 2011 revenues with no attrition at those two utilities. And so we are booking based upon the depreciation and the interest expense and all that we had in 2011 and that that is much higher this year than it was actually in 2011. But we don't have any additional revenues we're booking for that until we get a rate case decision. So those two segments are doing extremely well. Our International segment is doing extremely well and our Gas and Power segment is pretty much on track with what we expected.

Very good, thank you.

Rajeev Lalwani, Morgan Stanley.

Just another question on Cameron. Assuming you don't get non-FTA approval, what then happens? Do you only do a train or do you just cancel a project? And then a follow-up.

Let me have Mark talk about that. I don't think there's much of a change in our views from what we've talked about before.

No, I think what we've said publicly is that the project would be smaller and that means it probably goes from three trains to one or two trains. And we'd have to evaluate that at the time but let me stress that none of the feedback we've gotten from the FERC or the DOE and the way the rules are written and what we expect to go forward and the rumblings we heard about the report of DOE, we fully expect to get this thing permitted and moving it forward. We don't think that that's going to be -- that we're going to have to deal with that but if we do, we do think that there's enough of a market with our partners in the FTA-approved countries already that we would continue to do a project but it would be smaller.

Okay, and then in terms of the remaining merchant power assets, are you comfortable with the amount you have there now or are you still looking to monetize the remaining megawatts?

Yes, thanks for that question. Just to clarify, our desire is to exit the merchant power business. We don't see that as part of our long-term strategy and we've been doing that and we sold El Dorado to the utility; we've sold half of a plant we co-owned with Occidental earlier; now we've sold half of Mesquite to Salt River Project; and we have about 250 megawatts sold of the remaining block at Mesquite. We are on the path to exit the merchant generation business but as you can see, from this transaction, know that we were able to transact at about $600 per KW, so we are not in a big rush to sell, that we will find buyers that we can work with effectively to get good value for our shareholders from the assets.

Great, and can I ask one more?

Yes.

In terms of the tax item at SDG&E going forward, is it just going to be a modestly lower tax rate than we've historically seen?

Joe, do you want to comment on that?

Yes, sure. Essentially, this change in the rule will allow us to continue this going forward but we will have to actually do the calculations after we spend the funds and see what the repairs were and so it's a little bit harder to predict what it will be going forward, but it will continue forward. And if we continue to operate in the way we are, you might consider it to be a similar kind of amount.

Thanks guys.

Thank you.

Paul Patterson, Glenrock Associates.

Just on the tax thing again. First of all, what was it exactly that happened I guess, if you could just flush it out a little bit more in terms of what the IRS has now determined. And was that unique to you? And also just what would be the regulatory treatment with respect to your current regulatory proceedings? Would this just be something that would be incorporated into rates or how should we think about that?

I'll have Joe respond.

Hi, Paul. This has been an issue that's been going on for a long period of time. When I arrived here at the Company in 2001, people were looking at this issue and the IRS was auditing a lot of companies. The big four were looking at a bunch of companies trying to do this thing and there was no guidance really and there was a big question about whether certain repairs that were made should be deducted or whether they actually should be capitalized for tax purposes. Some companies have early adopted this rule if you will without any guidance and they're under audit, so each Company will be a little bit different here.

They didn't all take exactly the same treatment at the same time. We're following the Safe Harbor guidance that the IRS published late in 2011. We had to do a lot of work to study because we had to go back to the beginning of time of all these assets and these repairs and roll forward the study. And then we also had to make sure we had the systems to implement that and carry it forward. When you change tax basis like this not through depreciation, it is normally a flow-through item for rate-making purposes and that's why it's flowing to the bottom line here. So that's how it's treated for rate-making purposes and those kind of flow through items we always have to forecast into future rate cases.

So would it be captured in this rate case that you're currently dealing with?

No.

Okay, and then just a few quick housekeeping items. There's a US Treasury grant receivables, about $181 million I see, and I was wondering does that impact earnings and when would we see it impact earnings?

Joe?

Yes, that's a receivable. It doesn't impact earnings. It is a reduction of the basis of the assets so when we get the receivable, it just reduces the basis of the assets that you're putting into service. We're using that grant rather than the ITC, it's more efficient for us.

Okay.

And we expect to get that in the early part of the year.

Okay, and then the--

It's from the solar assets.

Okay, I got you and then with the sundry assets, I've noticed that they've been increasing, really since the end of 2010, and I was wondering -- the latest seems to be $55 million. How should we think about that in terms of, does it have an earnings impact or what's driving that?

The sundry assets, the increase from the end of the year until now is a couple of different things but one of the things is we have a portfolio of assets that are used to cover our various executive plans and other things that's in a Rabbi trust and those went up in value so those actually do go to earnings. Some of the other changes were unamortized debt issuance costs and things like that, but mostly the change was the Rabbi trust going up in value. Is that excluded, is that part of the COLI thing or was that in earnings? It actually -- some of those assets are in the COLI, some of them aren't, but it's to support our various deferred comp and other benefits.

So there's like a $55 million benefit in that, is that how to think about it in this quarter?

That one was not much. I'll see if Trevor has the actual number for the Rabbi trust but in the quarter, I think it was about $15 million --

$17 million.

$17 million.

Okay, and then just finally, we have -- it's election day today, and I was wondering, real easy question here, perhaps not, but any thoughts about how whoever wins the presidential election might impact you guys at all, if at all?

I would just say that our history has been able to be able to work under any administration and that I don't think either candidate has been very, very clear on their energy policies as part of the debate, so whoever gets elected that's one thing we'll work on with them from the very beginning of them taking office or continuing. But I think it's really not that big of an issue for us, that both are very favorable natural gas infrastructure and have made public comments to that degree and so I think that we feel that we can work under any administration and look forward to doing that.

Okay, great. Thanks a lot.

Ashar Khan, Visium.

Debbie, is there any way you can handicap, I guess you've got another two weeks, whether we get the rate cases here or no, any kind of feedback or anything?

It's very difficult for us to determine what's going to happen in the next -- actually, we could theoretically get it through the end of November, a proposed decision and they could call a special meeting in December and vote it out. They haven't typically done that, so we're looking at November 20 as kind of being the date. And if we don't see a proposed decision by November 20, we would anticipate it to be next year. It's unfortunate that the Commission has just had a lot of issues on their plate, a lot driven by San Bruno which has caused their normal schedule to lapse a bit and it's really hard for us to predict what is going to be the outcome. That's why we wanted to give you a heads up and let you know how it would be counted for accounting purposes. We would get our dollars retroactively, but in one case, it would come into 2012 earnings, and another case it would come into 2013 earnings which theoretically shouldn't really make much difference.

Okay, so just--

Just to be clear we did not have those earnings in our 2013 guidance, so--

That's what I was going to say is that if the case goes into 2013, right, then the 2013, the variance on the guidance is about $0.30, so that would mean 2013 earnings would be higher by $0.30 from what you had projected at the analyst meeting. Am I thinking through that right?

I would say we're not going to give any information on guidance. I just wanted you to understand that we had assumed we would get the rate case in 2012 when we gave our guidance and I'm not going to tell you what's going to happen in 2013. We will do that at the analyst meeting as we always do and typically we also on our fourth quarter call give you some indication, so we'll do that at that time and then we'll have a better picture on what the actual rate case outcome is at that time.

Okay, thank you.

Mark Barnett, Morningstar.

I guess just a quick question on the pipeline projects in Mexico. You've obviously hit a lot of the details on the current project that you've announced but you said it's more of a $2 billion total opportunity and that there might be some more beyond the announced project. I was wondering, are all bids in for that remaining and how do you feel about your prospects for the remaining maybe $1 billion or so of investments?

We looked thoroughly. There were different segments that were biddable, four segments that were biddable, and we elected to only bid on two of those. And we got the two that we bid on. So as far as we're concerned, the full length of the pipeline we got the two segments that we had bid on, we received the go-ahead on those.

And that's $1 billion. Just $1 billion.

And that's $1 billion. Yes.

So there are no other projects that could be announced later on from this?

Not from this solicitation, but obviously Mexico is doing so much to change from an oil-based economy to a natural gas-based economy so it's a great growth area for us. But in this solicitation there will be no more.

And one minor thing. I missed your comment on the mitigation payment from Kinder, maybe around some of the timing and maybe an earnings impact from that?

Yes, Joe mentioned that there was a $41 million payment that we would receive in fourth quarter most likely assuming the deal closes. And that would have an earnings impact. But when we took out the REX amount and looking at our guidance, we take out both the impact of that and we take out the write-off for that, so as we're giving you guidance of the $4 to $4.30 range and where we would be depending on the GRC, we've taken into account the potential of that payment and not including it in the guidance estimates.

Okay, great. Thank you.

Winfried Fruehauf, Winfried Freuhauf Consulting Limited.

I have a question on the accounting treatment of repairs on the IFRS. Does it make a difference if the repair not only restores the assets to the pre-repair value but results in a betterment, either in terms of life extension or higher quality, higher capacity or not?

I'm not sure that I understood your question clearly. It was a little muddled here but I think it had to do with the IFRS?

The IRS treatment of this. It really under the Safe Harbor, it just really gives guidance as to what amount of the line can actually be subject to capitalization or what amount of the line is subject to really expense based on the repair. And so that's what really the IRS is giving guidance on is even though that the repairs may not add longevity to the line or increased capacity to the line, you're still allowed to capitalize a certain amount of the repairs and that's what this Safe Harbor ruling does, is allows you to capitalize some of the amounts that we historically would have expensed.

Thank you.

This is Joe. I understand what you're saying and those betterments and all those rules are kind of the old way that the IRS looked at these sort of things. What they've done with these rules is they've tried to define what a unit of property is, so they're looking at a certain number of feet or miles of pipe or in this case, a transmission line or a distribution line and if you only repaired a certain amount of that and it's less than the whole unit, then you get to expense that as a repair rather than capitalize it. And so that's what this has to do with and it's kind of getting away from a little bit that betterment language that you're referring to.

Okay, that's helpful. The other question I have is on the losses at natural gas resulting from lower natural gas prices which impacts your LNG business. Is there a metric that would allow one to determine the impact for say a $0.10 up or down change in natural gas prices and the impact on LNG?

Yes, we generally use for the LNG business a rule of thumb or $13 million per $1 change in gas prices, is what we traditionally used as a rule of thumb for that. And that applies to the LNG business. (multiple speakers) And there's also some variability in some of our other businesses, but those businesses depend on what our hedge positions are and are not so easily done by a rule of thumb, but for LNG, about $13 million per $1 change.

And SoCal border price was down about $0.66 from what it was at the end of last year and that's what's causing this $8 million or $9 million effect.

I'll remind you though that for our utility businesses, we are not at risk for any of the commodity changes, so gas price impacts are really in our US gas business and are International for the LNG.

And this $13 million is that pre-tax or after-tax?

Pre-tax.

Okay.

After-tax.

Excuse me, after-tax.

Okay, thank you so much.

(Operator Instructions)

It appears there are no further questions at this time. Ms. Reed, I'd like to turn the conference back to you for any additional or closing remarks.

Well I again want to thank you all for joining us this morning and if you have any further questions please feel free to contact Rick or Victor and have a great day. Thank you very much.

Ladies and gentlemen that does conclude today's conference call. We thank you for your participation.