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 Investors 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 will turn it over to Debbie.

Thanks, Rick, and thanks to all of you for joining us today. I know many of you on the East Coast are 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 our 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 REX, 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 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 our insurance through customer rates customer and from amounts recovered from other responsible parties. As of September 30, 2012, we have recorded regulatory assets…

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, to 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 denominated in U.S. dollars. We expect the project to come online in 2 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 environmental information, paved the way for our formal FERC application. We've 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…

[Operator Instructions] And we'll now take our first question from Faisel Khan with Citi.

Just I had a couple of questions, one on LNG and then 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 that there's really only 2 projects in the queue that are on track to meet all these requirements to get that approval by 2014. Can you just -- can you talk about a little bit like how this differs from -- why this differs from kind of what you're saying and that you expect the DOE will be both be looking at your filing in 2013 and maybe even later this year? 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've 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 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, that 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 that we will be seeing that sometime 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. And it was made by an outside consultant that was 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 really 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. Yes, as you know that there has been a delay in 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 sometime in late December, so with the full engineering study. So we're moving forward on this, and we really haven't -- we really don't expect this to be a big deal.

Okay, great. That makes it clear. My second question is on the pipeline development in Mexico. In the past, you've talked about dividend-ing out cash flows from your South American operations and taking a tax hit up here in the U.S. through 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, or potentially the dividends you're receiving back from those assets in the U.S.?

Well, as you will recall that we were planning, as you mentioned, to repatriate dollars back over the 5-year plan period beginning in late 2013. We're still planning to do that, and the amounts that we were looking at over the 5-year period we believe are going to be consistent with what we showed you in the 5-year plan. So we don't see any real change in that as a result of this pipeline.

And we'll now go to our next question from Greg Gordon with ISI Group.

So I just wanted to be clear on the earnings guidance. So presuming you get a decision from 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 spoke in the third quarter at the utility operating companies, correct?

That is correct.

Okay, I just wanted to make sure.

And we'll take our next question from Naaz Khumawala with Bank of America.

I have a 5-part question on the wildfire case. Sorry, Steve made me say that. So actually, real questions that I have. One is on the REX write-down. Philips also took a write-down this quarter I know you guys know that. Their write-down, I think, 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 kind of trigger a write-down past this point?

Sure. Let me address it at a high level, and then we'll have Trevor or Joe kind of fill in more detail. What I would say is in going through the process of assessing this, is our best estimate and we consider all factors involved. There is a ROFR and at this quarter, we had information on the ROFR. We also had the opportunity to have discussions with Tallgrass and understand their kind of 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 ROFR and made our determination of what we felt the value of the line was. In terms of in the future that 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 pipeline share would sold at, whether it's a fourth sale, or if 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 of the line was an appropriate level.

Naaz, this is Trevor. And just to kind of reiterate a little bit of what Debbie said here, again, we got the ROFR in the third quarter and so that was another market level input that we needed to consider in determining the equity value from an accounting perspective. We weighted that, 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 ROFR was more of a level 2 input from an accounting perspective and the other unobservable inputs were level 3. And 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. And then on the Mexico pipeline, just had a couple of quick questions. One is how much Bcf a day of capacity will flow on that? And then when we think about kind of returns on the pipe, should we weight them more toward international returns or more toward the utility-like returns, if you can give firm perspective on that?

Yes, let me just kind of 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 [ph] 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 returns that we would expect for this 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.

The pipeline is in 2 phases. The first phase is a little under 800 Bcf a day, and the second phase is a little over 500 Bcf a day.

Okay, so 1.3 Bcf in total?

Well, no. I wouldn't add it together. It's a little under 800 Bcf coming down to a certain point and then it gets sold [indiscernible].

Okay, I see what you're saying.

And we'll take our next question from Kit Konolige with BGC.

So just to follow again on the Mexican pipeline, can you give us an idea then. Sounds like you will finance it at the project level. And so what -- how should we view how much equity you would have in that business, either parent level cash and net investment or even parent of 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?

Kit, Let me just try to 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. And so that we have -- 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 and 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 that 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?

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, and 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. But 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 go on, 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 as something like $0.15 of the tax special item or kind of onetime 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 had thought at that time?

Yes, first, let me say that the special tax item that I think you're referring to, we had the -- 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 onetime item or the majority of it was not a onetime item.

Very good. Okay. And so then segments compared to the Analyst Day, which are doing better than you'd thought and which not as well?

Yes, if you've kind of looked at our segments, SDG&E has had a very, very strong year. And that -- when we get a rate case decision, SoCalGas will have had a very strong year. I mean, we are booking based upon 2011 revenues with no attrition at those 2 utilities. And so -- and 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 2 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.

And we'll take our next question from Rajeev Lalwani with 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 do -- you just cancel a project? And then I have a follow-up.

Yes, let me have Mark talk about that. I don't think there's much of a change in our view from what we've talked about before but...

No, I think what we've said publicly is that the projects would be smaller, and that means this probably goes from 3 trains to 1 or 2 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 none of the -- and the way are rules are written and what we expect to go forward and the rumblings we've heard about the report at DOE, we fully expect to get this thing permitted and moving it forward. So we don't think that that's going to be a -- 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 FDA-approved countries already that we would just -- 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've sold El Dorado. It's a utility we sold half of the plant we co-loaned 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. So we are on the path to exit the merchant generation business. But as you can see from this transaction, that we were able to transact at about $600 per kW. So we're 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'll 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 an amount.

And we'll take our next question from Paul Patterson with Glenrock Associates.

Just on the tax thing again, what would be the regulatory -- first of all, what was it exactly that happened? I guess, if you could just flesh it out a little bit more in terms of what the IRS has now determined? And I mean, was that unique to you? And also, just what will be the regulatory treatment with respect to your current regulatory proceedings? I mean, will this just be -- so that would go into -- somewhat would be incorporated into rates or how should we think of that?

I'll have Joe respond.

Hey, Paul. So this has been an issue that's been going on for a long period of time. I mean 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 4 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. And so 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 sort of beginning of time of all of these assets and these repairs and roll forward the study. And then we had to also make sure we have the systems to implement that and carry it forward. And the -- when you change tax bases 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. And 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.

Okay. So would it be captured in these rate cases that you're currently dealing with?

No.

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

Joe?

Yes, that 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. And we're using that grant rather than the ITC. It's more efficient for us. And we expect to get that in the early part of the year. So the solar -- I'm sorry, some of the solar assets.

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

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 where unamortized debt issuance cost 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 -- I mean, was that in earnings [indiscernible].

Yes, 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. In the quarter, again, there was about $15 million.

$17 million.

$17 million.

Okay, and then just finally, we have -- it's election day today, and I was wondering -- a real question here, perhaps not, but any thoughts about how either 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 administration -- or 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 on 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.

And we'll take our next question from Ashar Khan with Visium.

Sorry I joined late. Debbie, any -- I mean, anyway where you can handicap, I guess, you got another 2 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 20th as kind of being the date. And if we don't see a proposed decision by November 20th, we would anticipate it to be next year. And it's unfortunate that the commission has just had a lot of issues on their plate, a lot driven by San Bruno, which has kind of 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 accounted for accounting purposes. We would get our dollars retroactively, but in one case it would come into 2012 earnings and in another case it will come into 2013 earnings, which theoretically shouldn't really make much difference, but...

Okay. So just to kind of like...

And I would just add that just to be clear, we did not have those earnings in our 2013 guidance so...

Yes, 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 $0.13 -- $0.30 from what you had projected at the Analyst Meeting, am I thinking through that correctly?

I would say we're not going to give any information on guidance. I just wanted you to understand that we had assumed we will 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.

And we'll take our next question from Mark Barnett with 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 kind of a $2 billion total opportunity and that there might be some more beyond the announced project. And I was wondering, are all bids in for that remaining? And kind of how do you feel about your prospects for the remaining maybe $1 billion or so of investment?

Yes. We've looked thoroughly. There were different segments that were biddable, 4 segments that were biddable and we elected to only bid on 2 of those and we got the 2 that we bid on. So as far as we're concerned for this, the full length of the pipeline, we got the 2 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, again, there will be no more.

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

As Joe mentioned, that there was a $41 million payment that we would receive in fourth quarter most likely assuming that the deal closes. And that would have an earnings impact that when we took out the REX amount and kind of 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.

And we'll take our next question from Winfried Fruehauf with Winfried Fruehauf Consulting Ltd.

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 asset 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 and...

The IRS treatment of this. And 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 increase the capacity of the line, you're still allowed to capitalize a certain amount of the repairs and that's what this Safe Harbor ruling does, it allows you to capitalize some of the amount that we historically would have expensed.

Winfried, 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 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 betterment language that you're referring to.

Okay, that's helpful. The other question I have is on the largess 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, the impact on LNG?

Yes, we generally use for the LNG business a rule of thumb of $13 million per dollar change in gas prices, is what we traditionally use as a rule of thumb for that. And that applies to the LNG business. There's also some variability in some of other businesses, but those businesses depend on what our hedge positions are. I know they are not so easily done by a rule of thumb, but for LNG about $13 million per dollar change.

And SoCal board of price was down $0.66 from what it was at the end of last year and that's what's causing this $8 billion 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 U.S. gas business and our International for the LNG so.

And this $13 million, is it pretax or after-tax?

Pre-tax.

After-tax.

After-tax.

[Operator Instructions] And we'll go now to our next question from Vedula Marti with CDP Capital. [Technical Difficulty]

And 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.

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