桑普拉能源 (SRE) 2003 Q1 法說會逐字稿

Good afternoon, my name is Junega (ph) and I will be your conference facilitator. At this time I would like to welcome everybody to Sempra Energy First Quarter 2003 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer period. If you would like to ask a question during this time, simply press star then the number 1 on your telephone keypad. If you would like to withdraw your question, press star, then the number 2 on your telephone keypad. This call will be available for replay beginning at 2 p.m. today through 11:59 p.m. Eastern Standard Time on May 8, 2003. The conference ID number for the replay is 9599599. The number to dial for the replay is 1-800-642-1687 or 706-645-9291. I would now like to turn the call over to Mr. Dennis Arriola, Vice President of Investor Relations. Thank you sir. You may begin your conference.

Thank you and good afternoon. Thanks for joining us to discuss Sempra Energy's 2003 First Quarter financial results. A live webcast of this teleconference and slide presentation is available at www.sempra.com under our investor relations section. With us today from the company are several members of our management team including Steve Baum, Chairman, President and Chief Executive Officer of Sempra Energy, Neal Schmale, Executive Vice President and Chief Financial Officer of Sempra Energy, Don Felsinger, Group President of the Sempra Energy Global Enterprises, Ed Guiles, Group President of Sempra Energy Utilities, and Frank Ault, our Senior Vice President and Controller of Sempra Energy. Before handing the call over to Steve for today's financial update, I'd like to remind you that this call contains forward-looking statements that are not historical facts and constitute forward-looking statements within the meaning of the Private Securities Reform Act of 1995. Forward-looking statements are not guarantees of performance, they involve risks, uncertainties, and [Inaudible] . Future results may differ materially from those expressed in the forward-looking statements. 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. With that, I would now like to hand the call over to Steve who will begin with slide 3.

Thank you, Dennis and thank you all for joining us. Earlier this morning, we reported net income of $88m for the first quarter of 2003, or $0.42 per diluted share compared with $146m in the same quarter in 2001 or $0.71 per diluted share. The 2003 first quarter results included the effect of implementing accounting principle EITF 02-3, which eliminated the use of mark-to-market accounting for certain commodity trading assets, changing the timing for revenue recognition. Based on the impact of this new accounting principle, Sempra's net income was reduced by $38m or $0.18 per diluted share. This non-cash effect was made up of $29m of one-time after tax adjustment related to the cumulative effect through December 31, 2002 and a $9m after-tax effect related to the first quarter. Adding these non-cash items to our reported GAAP earnings for the quarter provides a more accurate picture of how we did relative to last year before the implementation of the required accounting principle took effect. Using this comparison, Sempra would have had a net income of $126m or $0.60 per share versus the $146m or $0.71 per share in the first quarter of 2002. The effect of the accounting changes and lower profitability from energy trading directly impacted our performance in the first quarter. Given the history of our trading company over the last three years, however, I'm confident that trading will provide annual earnings that are consistent with our plans and I'll speak more on this point when I address tradings first quarter results.

I'm pleased that all of Sempra's other businesses performed well during the quarter and are on track to meet their profit plans for the year. In addition, there were several positive developments during the quarter that I would like to discuss on slide 4. First, our resources group is on track to bring on line over 2,135 megawatts of power by the end of the year, including 1,510 megawatts by June. The gas turbines for our plants at Elks Hills, Mexicali, and Mesquite were all successfully tested this quarter. We're confident that these plants will be ready to help us service our power requirements under our contract with the California Department of Water Resources or CDWR. In February, we also announced our agreement to acquire a liquefied natural gas project in Louisiana from Dynegy and we closed that transaction on April 23. The project has been renamed Cameron LNG. We expect to have the necessary Federal Energy Regulatory Commission approvals before the end of the year and plan to have Cameron fully constructed by 2007. We are also pleased with the progress on our Energia Costa Azul, LNG site located in Baja California. In April, we received the environmental permit for Costa Azul and expect to receive the remaining local land use and energy regulatory commission operating permits shortly. Our plan is to have Costa Azul fully operational by 2006. Together, Cameron and Costa Azul will provide Sempra with processing capacity of 2.5 billion cubic feet per day of natural gas making Sempra the largest owner of LNG import capacity in North America. We remain confident that Sempra will earn between $2.60 and $2.80 per share in 2003 excluding the $0.14 cumulative effect of the EITF 02-3. Our liquidity position remains very strong with over $2.6b in cash and committed credit available. We further improved our liquidity in January after Sempra issued $400m of 10-year debt at 6%. We expect our capital plan of approximately $1.3b for 2003 to be in balance with our internally generated cash flow. We remain focused on maintaining our strong financial position, including our stable investment grade credit ratings.

Now let's turn to slide 5 and I'll review the quarterly performance for each of the business units. I will start with our two units at Sempra Energy Utilities. SEG and E had earnings of $45m compared to $53m in the first quarter of 2002. The decrease was primarily due to the end of sharing merger savings at the end of 2002 as well as higher O&M and depreciation expenses this quarter. The 2003 quarter did include approximately $4m after-tax related to gas procurement incentive award. In the same quarter, Southern California gas company earned $58m, down slightly from $60m in the first quarter of 2002. The decrease was primarily due to the end of sharing merger savings. With the recognition of the gas procurement award at SEG and E this quarter, the two utilities have $106m in pending awards and incentives awaiting California Public Utility Commission approval. While we cannot determine the exact timing of when we will recognize these awards and incentives. We're urging the commission to address these programs in a timely manner. In December of 2002, both utilities filed their cost-of-service cases with CPUC. We recently received a preliminary procedural schedule and are working with the commission's staff to expedite about the process.

Now, please turn to slide 6, where I will discuss the results of Sempra Energy trading. The implementation of EITF 02-3 at Sempra had its largest impact on Sempra Energy trading. For the quarter, trading reported a net loss of $18m compared to net income of $42m in first quarter of 2002. Adding back the one-time noncash cumulative effect of $28m and the $9m noncash effect related to first quarter business, tradings earnings for the quarter would have been $19m on a comparable basis. Our trading company runs a customer focused business and this quarter's results reflect less high margin customer business. Over the last 13 quarters, trading has generated quarterly earnings that range from $10m to $86m. It's this profitable track record that gives us confidence that trading will continue to be a solid earnings contributor to Sempra this year and beyond. The positive news for the quarter trading is that we maintained our disciplined business approach during this difficult customer environment. Our internal risk management systems and controls ensured we weren't taking on more price or credit risk than we wanted. During this historically unprecedented period where volatility in the natural gas markets exceeded 10 standard deviations. We focused on limiting our downside through strong risk management. As of March 31, we had unrealized revenues from over-the-counter sources of approximately $452m. Over the next 12 months, we expect all of this to convert into cash.

From a credit perspective the quality of our unrealized trading assets were relatively unchanged as assets related to commodity exchanges and investment-grade counterparts decreased slightly from 70% in the fourth quarter of 2002 to 69% in the first quarter of 2003. Resources generated earnings of $10m compared to a loss of $3m in the first quarter of 2002. The positive Variance was due to our scheduled deliveries under our contract with CDWR as well as to earnings from our Twin Oaks plant in Texas.

On the construction side, we will add 1,510 megawatt of generation capacity to our portfolio by June. This additional capacity will help us meet our obligations under the CDWR contract as the deliveries step up to 1,350 megawatts beginning on June 1. An additional 625 megawatts will come on line by December 2003 from the second phase of our Mesquite plant. Through 2005, an average of 85% of our peak generating capability is sold forward and this will provide our Resources unit with predictable earnings and cash flow.

On the regulatory front, we believe that the Federal Energy Regulatory Commission will soon affirm the validity of our contract with CDWR. Both Resources and the CDWR continue to perform their obligations under the contract. We're delivering power and the CDWR is taking it and paying for it.

Now, slide 8 provides the table of earnings results by business unit for the quarter. Let me review a few items. At Sempra Energy International first quarter 2003 earnings of $7m were down slightly compared to $8m in the same quarter in 2002. The modest decline in net income was related to lower earnings from Argentina, partially offset by a positive contribution from the Baja Norte Pipeline. During the quarter, the Argentine peso continued to strengthen relative to the dollar and we had a favorable adjustment to other comprehensive income on the balance sheet. As a result, the OCI adjustment related to Argentina was reduced to $199m.

Our Solutions group reported $1m loss compared to $1m in net income for the same period in 2002. Solutions was impacted by a $1m adjustment related to the cumulative effect of EITF 02-3. Earnings from our financial unit increased to $11m from $7m in the first quarter of 2002. The increase was driven primarily by higher income tax credits due to increased production from our Section 29 coal plant investments. Apparent and other after-tax expenses increased from $22m in 2002 to $24m in the first quarter of 2003 due primarily to higher interest expense. The effective tax rate for the first quarter of 2003 was just over 17%. The tax rate was favorably impacted primarily by the higher Section 42 income tax credit related to low-income housing and Section 29 income tax credits related to coal plants. Based on our current outlook we expect the effective tax rate for the year to be in the 17% to 20% range.

Before opening up the call for questions, I want to emphasize, we have, that we reaffirm our 2003 earnings per share guidance of $2.60-2.80, excluding the $0.14 cumulative effect of EITF 02-3. We continue to believe that we have the right strategy to deliver earnings growth on an annual basis going forward. We will discuss our strategy in more detail at our Analyst Conference next week, and provide you with additional information regarding each of our business units, including earnings targets and capital spending plan. And with that I'll open the call for questions.

At this time, I would like to remind everyone, if you would like to ask a question, please press star then the number one on your telephone keypad. We will pause for just a moment to compile the Q&A roster. First question comes from Michael Goldenberg from Luminous.

Hey, good morning guys.

Good morning.

Hey, I just wanted to kind of touch up on trading for a second.

Yeah.

It seems, obvious the earnings are down, but it also seems your mark-to-market is up considerably. It seems it was 324 last quarter, and now it's 450 . So, it seems you made a considerable amount of money in that department. Where did you kind of lose money? Was it kind of day-to-day trades or was it previous contracts and change of fair value of those previous contracts?

I think, the granularity were the effects of the accounting change, it is one of the issues. There was a $9m adjustment in after-tax earnings in the quarter, and I think if you look at the Table D in the attachment to our earnings press release, you can take a look at a breakdown of the margin in the trading operation by product line. And you'll notice that the principal impact or one of the principal impacts during the quarter was in power trading and that is coming principally from the effects of EITF 02-3. I would say to just to make a general comment about the quarter in terms of our results, we run a fairly flat book, we don't take large proprietary positions and I have emphasize that repeatedly with investors in conversations that I have in these public fora. And therefore, major price spikes, unless they result in a significant increase in customer margins, don't really affect us tremendously, as they may other people or other market participants who carry larger proprietary positions. So, that was one of -- despite the rather remarkable run-up in gas prices during the quarter, we didn't see a big gain from that change and I think, you know I like to look at our trading operation on an annual basis. We don't really expect even quarters out of that operation and as I mentioned historically, we have run, we got lower quarters and still made well over $100m in the year. So, I am not -- we're not -- well, I think that it is fair to say that this was a less robust quarter than some. We are not changing our anticipated, or our expectations for trading this year.

Okay, and just one follow-up question on trading. You guys took a $38m charge on EITF, obviously that is going to reverse itself as time goes on and given the short-dated nature of your book probably this year. Are you guys including the reversal of $38m to your guidance?

Well, let me say that that your assumption that it reverses this year is not entirely correct. Again this is a complex issue because the items that are most affected by EITF 02-3 change in eliminating mark-to-market accounting for some non-derivative -- class of non-derivative items, affects things like storage contracts, transportation contracts both for gas and electricity principally, and inventories. Now, we may carry inventory and contracts for relatively long periods of time against which we would trade repeatedly. And so, I think it is fair to say that some of this change will not reverse this year. Some of it, in fact, transportation contracts, you will see reversing in 2004 and 2005.

Okay, but whichever portion is reversed this year, would that be including your 260-280?

Yeah, we are not including the ongoing effect of EITF 02-3 or, maybe I should see it get away. We're including the ongoing effect in our forecast, our target forecast of 260-280. We're not including the $0.14 that resulted from the one-time cumulative adjustment.

Okay, and just one final question. Could you please give us LNG CAPEX, kind of what numbers are we looking at from today through when both projects are going to be built?

Yeah, for Costa Azul, the anticipated capital cost to be expended through 2006, is about $600m and we would spend relatively little of that, about $20m or so, so far on land. I am not including whatever accumulated other costs or may be they are not terribly significant at this point. And in Cameron LNG, the anticipated cost is about $700m through 2007. And again, I think we reported that we have spent $20m initially and there will be other expenditures as we reach milestones in each of these projects.

Is there any way to break it down by year in, any sort of, percentage terms or anything?

We haven't broken that out yet because we -- obviously and much of that is driven by the licensing process and also by our contracting activities.

Okay, thank you very much.

We will, and for those of you who are going to attend our analysts' conference, we'll try to get to a little bit greater detail about those capital projects.

Good luck in the future, guys. Thanks.

Thank you.

The next question comes from Anatol Feygin from J.P. Morgan.

Hi, good afternoon.

Hi, Anatol.

How are you, Steve? Just one or two, drill into, I'm sorry, the trading business a little bit more. The volumes were up substantially in gas as was the VAR and yet the results in a highly volatile quarter was substantially lower than I guess, we expected. I appreciate that you guys do a lot of customer business. Does the triangulation of all of that mean that it was a very low margin business in the quarter or how do we reconcile all of those data points?

Or maybe I will let Don Felsinger talk about that a little bit and I will come into if it is appropriate.

Yeah Anatol. As you look at you look at Table D, one of the things that probably is not clear. As you look at physical statistics, those are the actual volumes that we moved through the quarter, both electricity and gas. Much of that volume has already been mark-to-market in prior quarters. So, there's no correlation between what you see in terms of trading margin and actual volumes.

Okay, so this isn't a leading indicator of greater customer-driven business?

That's correct.

Okay.

Anatol, let me also comment that, you know, I guess it's an arithmetic outcome that the VAR will increase with the commodity price unless the positions are reduced and as I mentioned or indicated that we did pay a great deal of attention to our VAR during this quarter and during that price spike and we were rigorous in -- in our risk management practices during the period, I want to emphasize that and to some extent, that may have relatively dampened our performance compared to others.

Understood. The one thing that you guys broke out that I haven't seen in other reports is a -- two pieces to the charge of $28m and the $9m. Now, the one piece that we've seen is the January 1st of 2003 write down of the previously mark-to-market positions. How do we -- what is the $9m other piece?

Well, most all of that is in trading but Frank Ault, our controller will speak to that.

Basically by adopting 02-3, we have a cumulative effect that takes care of all the positions that existed at the end of December 2002. By using the new accounting pronouncement, we have some impact in deals that we did in the first quarter in the storage, the transportation, inventory areas, that last year had been mark-to-market. This year we could not mark-to-market those. Have we done so, we would have in fact had 9m more of net income. So, to have comparability for comparison of data, we basically showed what the impact was, of the new accounting rule for the first quarter that basically reduced our margin for the quarter by $24m and our net income by $9m.

Let me emphasize for everybody on the call that what we're talking about here in these accounting changes is not an economic change; I mean, the business is just as it ever was. These are -- we're going to report, for financial purposes, somewhat different outcomes and some of these can be because of this change, anomalous. For example, if we have a gas-in-storage as a long position, and we have a derivative, which flattens that position on the other side, that is, we have sold the gas forward, you're going to mark that gas storage position to the lower cost-to-market until it unwinds and, but you're going to mark that derivative position every quarter as low-to-market, higher or lower. That can produce results, which are anomalous to previous methodologies and so, I would, I am just going to tell you flat out, we'll try to explain these things as they occur, so that you can understand them. There is no economic difference between those things, but you could have wild swings and results as a result of always having the storage and inventory positions at the lower cost, and marking the derivative position up or down.

Let me just repeat, what I guess, Frank said to make sure I understand it correctly. The $28m is the actual EITF-related charge as of 12/31/01. The $9m is what the mark-to-market value of certain contracts would have been, had 02-03 not been implemented?

That's correct. We had a total cumulative effect adjustment $29m, $28m of which applies to the trading company and then the impact in the first quarter of the new accounting rule for transactions during the quarter was the $9m.

Great, thanks very much, everyone.

The next question comes from Donato Eassey from Royalist Research.

Hi Steve.

Hi Donato, how are you?

Fine. I have got three questions. The -- and I don't mean to sign flippant here , you mentioned by the 1,500 megawatts going to come online in June of this year, contract with the CDWR. Do you have a lot of confidence in them sticking with the contract rates and if you could address the security of the contracts from where you sit with the folks in California where they seem to pay bills only when they want to? And again, I don't mean to be flippant, hopefully these are --

Shall I take that first, Donato.

Yeah, sure.

Let me deal with that. We've been pretty confident all along that that contract would be upheld and that the state would perform. And as I've said numerous times in the past, if you cut through to the actual economics of the contract, I believe it's so close to what cost-of-service rates would be, remembering that the state has the gas risk, the co. doesn't, and that's up to the state to either to mitigate that or to take the spot price. But what we're responsible for is in fact the capital capacity charge and operating charge, but excluding fuel, and that charge is very comparable to cost-of-service. Even if the FERC were to go to a position that yes, just in reasonable rates had to be the standard applied to these contracts and they went back and reviewed them, and applied that standard, we would pass. So, I've had confidence all along, just on the economics of this contract. Now, quite beyond that, I think we have a, I've said, I predicted flatly we would win the legal case, and I believe that to be true. So I have, we have great confidence that that contract, our contract will be upheld. And albeit, I mean said all that, we've been willing right along to talk with the state, have had many conversations in the past to reform the contract in a way that would be mutually beneficial. And you know, as you know the state has given this, our contract to Southern California Edison for administration for its loan. And it would be useful to change the contract from a take or pay energy contract to a capacity dispatchable energy contract. We've been willing to do that all along, we remain willing to do that, although there are some legal problems for the state in terms of the authority it has to make major changes that would have to be reached, giving a kind of a long answer to the question. The short answer is, we remain even perhaps, they have become even more confident if that was possible, that the contract is good and will be performed.

Great, I mean, just to thank, you said it almost the same as Calster (ph) service, that's great.

Yeah, that's the fundamental thing here. It's the basic economics.

Exactly, the other to deal with the recognition of earnings on the awards pending, the $106m, is any of that in, none of that's in earnings, yet?

No, the only thing we got was $4m, but there's a $106m remaining. And you know, we've been waiting for these awards for a while. They're all earned. But we are not able to predict with any great accuracy when the Commission will act to allow us to put into rates these or into our earnings these awards. And we just haven't been able to predict that and I'm not going to try now. PB (ph) has indicated, the President of PB has indicated his desire to move the agenda, and we see evidence of that, but again I can't predict.

Very well, my final question. You indicated that the trading is, you have confidence in it, obviously this year, liquidity has shrunk. It seems to have shrunk with so many players exiting the business; players like yourself are probably finding more opportunities. I just wanted to, when you say that things are going fine, obviously, despite fall-off in liquidity is not a concern to you? And I appreciate your response to it, thanks.

Yeah, this is a question that comes up a lot, Donato. I'm asked this question fairly often by investors, what about the shrinking liquidity as players; that is counterpart liquidity, that is the ability to trade with another trader. Has that influenced our business? And I have to say, sure. I mean Enron used to make a market in virtually anything for any length. And when that went away, liquidity went away. But there have been other players that have entered the business, and particularly financial players who are providing additional liquidity from, on the financial side. And so that the only, the real impact has been a something of a reduction in physical volume liquidity. And that has affected the business, and continues to affect the business, but we still remain confident our trading co. is kind of offset some of that through actually a larger market share.

Thanks Steve, see you next week.

Sure.

The next question comes from David Maccarrone from Goldman Sachs.

I can't hear you.

Steve.

Hi, David.

Hi, David Maccarrone. I wanted to ask you on the trading business, the risk adjusted return on capital came in, I imagine that's because of the higher [Inaudible] expected to come in? Do you expect that to..?

A direct result.

Okay, and then on separate issues in talking about the tax rate. In my notes, I have this Frank talked about the '03 tax rate in February call going to more of the historical 29% or so rate in '01. And going to 17% to 20% rate in '03 from that guidance, looks substantial to me. I was wondering if you can you go into that a bit more?

Yeah, this was a pleasant surprise for us, okay? And the result, it was the result of getting trading at two of these coal transformation machines, and last year only one was operating, this year both are operating, and they are operating at much higher rates. And so our productive capacity from a Section 29 perspective has increased dramatically. And that's a good thing. And so we've generated more credits than we have previously anticipated, and I am kind of the Ben Franklyn school of a things where a penny saved is a penny earned. So I'm very pleased with our ability to keep our tax rate low. Frank, I don't know if you want to add anything.

So, I think that the key thing, basically we have got four units that we have a 20% interest in. And first part of last year we only had two operating, all four of those started operating late in the year. They're doing extremely well. We have two units that we have a 100%, only one operated last year, we took conservative position when we were talking earlier that we wouldn't necessarily have that. Second one relocated, up and operating, which we now do, and based on the performance of all six units, you saw now expectations of the credits this year will drive the tax rate down from last year when we were just over 20%, probably into the 17% to 20% range for this year.

How sustainable over the long-term is this tax rate?

I believe that it is going to continue for the next few years and you'll see the effective tax rate creep up first of all on the Section 29 credit they have a life, basically they end of 2006. But also we have the Section 42 affordable housing credit; [Inaudible] we got 1,300 different projects they were entered into over a series of years, and they have a cash credit life of about 10 years. We're going to start to see those dropping off over the next several years. So I think we will see a little trailing off in the next three, four, five years, then we'll see a larger drop in 2006 from the Section 29's fee.

Okay, and just two follow-ups. What is the expected dollar impact to trading this year from that change in the anticipated tax rate?

We, it's probably, the $9m will be probably, I believe that the largest quarterly hit that we expect. Frank, I don't have if you the run-out on that for the full year, but?

Well, as far as the impact on the adoption of 02-3, we had the $9m net income impact in the first quarter, we're anticipating, if prices -- if volumes stay relatively constant, the impact would be in the $4m to $5m range negative for the next two quarters turning around in the fourth quarter should probably offset what occurs in the next two quarters. So, the $9m maybe, be around $10m at year-end. No significant change for the rest of year, in total.

I will give you the caveat, David that if prices and volumes stay relatively constant, which is an interesting caveat.

I think I asked the wrong question actually; I was more -- trying to get a sense for the dollar impact in trading from the tax credits? It would just seem like a significant and more predictable element of their earnings.

Yes, right now it is based on the higher performance that we had in the quarter. I would have to say that from an earnings impact, we're going to continue to see something in the range of margin perspective in the fairly $15m margin range per quarter. That margin range in translating into earnings is probably, I would say in the $5m range to $7m something like that per quarter of that income and then it should probably run through the rest of the year.

Okay and the final question is why not raise your guidance with that significant a change in the outlook?

Well, I think there is a lot of uncertainties out there with the utilities as it relates to the timing of recognition in some of the incentive awards. I think that, if we don't get any of them, we are probably going to be on that lower end of the range. If we are successful on getting a number or more, we'll be going to be in the higher end of that 260-280 range. I think we also have still some uncertainties around the trading, as we always do. They have higher quarters, they have lower quarters. We have to be a little bit more unpredictable. Although, I'm very comfortable staying within that range right now and I don't think this is the time to change that prediction.

Okay, thanks very much.

Your next question comes from Paul Patterson with Glenwalk Associates.

Hi.

Hi.

In terms of your depreciation, it looks like its flat year-over-year on a quarterly basis?

Excuse me, I am sorry, could you try to speak a little louder because it's not coming through here.

Depreciation, could you hear me now?

Yes.

It seems like its flat for the quarter-over-quarter.

The depreciation, full corporate depreciation. Yes go ahead, Frank.

The deprecation is in fact flat, but if you do recall in the earnings release, we talked about the fact that we do have higher depreciation at the California utilities, particularly at SDG&E. Basically, what's happened, they've grown their rate base and that of course results in higher depreciation there. On that higher rate base, will be recognized in earnings when we get across the service decision next year. Offsetting that is appreciation has decreased at the corporate center. At the time of the merger we had a number of IT related assets that went into service to accommodate the merger and they had relatively short lives and they're now basically amortized. So, we've had a decrease in depreciation that is apparent and an increase at our utility center SDG&E. As a result of that for the quarter, we're sitting pretty flat.

What were those assets, was those IT assets?

Information Technology software. PCs we got, certain free things that have a three to five year life.

Okay and then on the 02-03 question that was asked previously, the $0.14 and I guess the $0.04 as well will show up later on. I want an idea about how much might be coming back this year, as you go through this change?

Well, there is two things to keep in mind. First of all, the $0.14 and the $0.04 per share you are talking about, relate to transactions in place today. As we do new transactions, moving forward: our storage, or inventory, or capacity type things that are not eligible for mark-to-market accounting, we're going to have an ongoing impact every quarter of new deals and a delay in recognition of that revenue. So even though these two items that we talked about, will turn around over basically the next three years and they will be replaced with some new transactions that invariably will have a timing on earnings recognition. More specifically, we are talking about what these items in isolation; the $0.14 basically will turn around in 2004 and 2005. The $4m again will pretty well turn around this year, but we will be having some new transactions occur this year that will have a delay in revenue recognition. So I would think, in essence, that will stay pretty flat. The only part that we're excluding from our earnings estimates is the $0.14 and that's not going to have much of the turnaround this year, those capacity contracts that are behind that, basically are 2004, 2005 type contracts.

Given the fact that your book is so short, it would seem that your [Inaudible] so you'd catch up with everything in that. You know you'd be recognizing what you transacted, I guess, in the previous year pretty soon? Is that right?

The books are very short and when you look at the Table D, where we talked about the unrealized revenue, that's only the items that are mark-to-market. We do not include the items that are still on the cost basis under EITF 02-3 because that has no unrealized revenue today.

And no cash effect?

No cash effect. I'll give you one of these; there will be, obviously when the deal is complete is when the cash comes in and it is not affected by the accounting change.

Thank you. With FAS 143, one of your companies have had an impact associated with that, I was surprised that you guys didn't seem to have any?

Well basically, we have a very interesting thing as it relates to that particular situation. We had a very very robust plan, as far as the, going for the retirement of our nuclear power plant. And basically we have a trust in place that actually has more in it than what our accumulated obligation would be today. You'll see when the 10-Q is filed that basically when you take that trust into consideration, we actually are over-funded and having the liability back to the customer, if in fact we not to have to go any further. Clearly since you accrue it over the line by the time you get to the end, we'll be in balance but on customer rates, we have done an excellent job of reflecting in advance for that retirement. We're in great shape, so we didn't have any big effect.

Okay great. And then finally I guess you mentioned, I just want to clarify, about $25m a year is coming from syn fuels on an ongoing basis, is that right?

The --

You said $5m to $7m per month or per quarter, I thought in earnings.

That basically is at the trading company, to have some additional synthetic fuels credit at our Sempra Energy Financial unit as well, which is sitting in the vicinity of about $8m on a quarterly basis.

On a quarterly basis, that would be $8m in addition to the $25m, roughly speaking?

The $25m is roughly an annualized number and $8m is a quarterly figure to look at it on a comparable basis. It would be 24 or so, we are probably somewhere in the 45-50, on a combined basis.

Okay. And then for affordable housing, how much is that?

Give me just a quick second, and we will see if I can't come up with it. A little closer to what that number is.

Okay.

Yeah, the credits on the affordable housing are running right now about 14 of so a quarter. So, that would be somewhere in the 50 to 60 range, probably on an annualized basis for the pure credits themselves.

Not for the tax effect?

No. But we also have to remember that with the housing, these are limited partnerships and we have to pickup our share of the operating losses as well. So, the pure credits are running about 15 a quarter, but we do have operating losses as well to go with that. So, that's why when you look at the net income for the Sempra Financial Group, it is not a size you'd might otherwise expect.

So it means if you were to net those two out what kind of [Inaudible] ?

If you net those two out, the operating losses are running around 12. We probably are netting something right now in the 2 to 3 per quarter from that.

For net income?

Yeah. But don’t forget that one runs through operating expense and the other one runs through the tax line.

I follow you. That's very helpful. Thank you.

Our next question comes from Teresa Ho from Banc of America Securities.

Hello. I just had one question on the Utilities and then another one on Solutions. First on the Utilities, let me ask a procedural schedule. It looks like it could be a dragged out process with the evidentiary hearing. You know, that will not begin until the fall of this year, October cost-of-service, December for incentive mechanism. And I understand that in your comments you said that you're hoping to expedite the process. I guess, could you speak to that? You know, what makes you think you could actually accelerate the process and when you would expect a decision to be made for the cost-of-service?

Yeah, let Ed Guiles, you take this one.

Yes. Good morning. Let me just give you a quick rundown. We filed the cost-of-service in December of '02. We received what we call a scoping memo form the assigned commissioner in early April. We took a look at that and that would have put a decision as best we could calculate, it's sometime in June of 2004. Obviously, that's late from our perspective. So, we actually have filed the petition with the commission and we went through kind of area-by-area whereby we thought that the schedule could be accelerated closer to the beginning of 2004. We've proposed in that, a timeline for the CPUC staff testimony. The hearings would be in August and September, and could yield a decision in February. In addition to that, as they've done with other utilities, we suggested that interim rates could be put into effect, subject to a memorandum or balancing account until the decision is made. And you know, for example, let me give you a quick example, one of the things in the scoping memo had to do with filing of electric resource plans and that whole issue is not even connected to the cost-of-services filing. So, we were able to propose in our petition that there were a number of items that were really inappropriate and that a more expedited schedule is in fact, possible. And so, we're working with the commission on that right now.

Any sense of where the commission is coming out on this?

You know, we don't know for sure, but we're optimistic that we can move the cost-of-service schedule up to the first quarter and then get interim rates to be put into effect beginning of the year.

Second on the Solutions, it is actually for awhile Solutions is getting a lot of momentum, really generating profit, you know, for the past, not this quarter, but the four quarters proceeding in '02. What happened this quarter? What made it so challenging?

This is Don Felsinger. If you take out the effect of EITF, they essentially broke even for the quarter, which is, it's indicative of what's happening in the retail markets. As we look round the various states we operate in, when wholesale prices are above retail prices it's difficult for us to get customers interested in buying commodity from us. We're seeing that change and so we still are optimistic that they will be on their plan for the year.

When you say on plan, you mean breakeven for the year, or actually posting profits?

Well, they've broke even for the first quarter.

Okay.

I would say that you're seeing the change to the --

Change to the year?

No, let me come back again. For the first quarter, removing effects of EITF they broke even, we're now seeing a change in the retail market where wholesale prices allow us to do business with customers.

Okay.

So, we're optimistic for the year they'll be on-plan.

Okay. And just one saying for the retail. What is the mark-to-market impact of retail?

That was $1m.

That was the $1m. That's all of mark-to-market?

The $1m was the cumulative effect adjustment. There is nothing reportable I don't think on that for the quarter.

Thank you.

Our next question comes from Bob Sullivan from UBS.

Hi, just going to ask, I am still kind of unclear on the SynFuel credit and the housing. When did the housing expire?

The housing are basically, you get the credits for 15 years, which gets [Inaudible] over the first 10, so there is actually a recapture position out there. So, you have to hold the project for 15 years but the actual tax credit recognition occurs in the first 10 years. Now, the timing of those, we have 1,300 individual projects. So, they all have their own 10-year life from the day they were initiated. They basically started in the early 1990s, which means they start expiring in this current time frame. We didn't do very many in the first few years, but the last one was entered into, can't remember, that was 1999 or 2000, something in that time frame. So, the credits will work their way down over time until the end of the 2009 or something like that. On the Section 29, it's actually misquote, they actually expire at 2007 not 2006 when the program ends. . So...

What's the total positive from the Section 29 for '03? What is the total earnings contribution between all segments?

The bottom line for all of the Section 29 credits is about $60m. So, that's the bottom line.

Okay, and how much do you have in awards in your earnings guidance for the utilities?

Well, that's part of the reason we have the larger range because there is so much uncertainty. We've kind of looked at, on high-end, we may get it maybe not get these, and then we don't get much more than what we have right now. So, that's part of the reason why we have the ranges, because that is so unpredictable at this point in time.

Although, I believe we have said in our Q that you'll see that we now are, because the GCIM award for, I think it is period eight, is that right Ed?

Seven and eight.

Period seven and eight, have been entrained with the order price spike OII at the commission, that schedule would appear not to be likely to be completed in 2003. That we now are doubtful the GCIM awards with those two periods will come in 2003. We don't have, we have less information about when they may come out with the other awards. And that's about $30m or so of that $106m.

Have you seen improvement in trading during this first month, when you were to look at it that way?

Market conditions have improved.

They have, so you would expect a stronger second quarter, based on this?

We're not.

Well, I guess, what I'm trying to get here is....

I'm not going to make quarterly predictions for any, per trading and I've said repeatedly that we look at trading as an annual operation and I'm just not going to go there.

Okay, thanks.

Your next question comes from Lasan Johong from Blaylock and Partners.

Neal, a quick question on the credit and the tax rates. If you have a book tax of between 17% and 20%, going forward, that implies to me that you guys are probably A&P on the federal taxes. Is that correct?

Yes.

Okay, that means that you are not getting the cash tax benefits, so are you guys booking deferred tax assets as opposed to deferred tax liabilities?

Yes.

How big is that deferred tax asset? Or how much are you booking per year or per quarter?

We are looking for numbers here.

Okay.

Can we defer that? If you have another question, we are going to have to search for that one.

Okay.

If there's another question, I don't want to hold everybody up while we flip papers here.

That's fine. On your California contracts, I believe temporary set aside from reserves for that?

Which contract? I'm sorry.

The California contract for the past.

We set aside some reserves?

Yeah.

I don’t think so, I mean; we have no reason to take a reserve on that contract.

Okay. Let me move on to the Bolivian gas contract.

Wait a minute let me make sure that I understand which contracts you are talking about. There is no reserve on the CDWR contract.

Okay.

Is that the one you are talking about?

Yes.

Okay.

We have the answer now, I think on your deferred tax question.

Okay.

I think we have a partial answer. As of March 31, the aggregate amount of unused tax credits to-date was $159m. That is those that we expect to utilize in the future.

Okay. And how fast has that been growing for the year? By the full amount or $60m in 29 credits, and I think, it was $30m to $40m on the 42 credits? Is that right?

No, getting to the rate is a little trickier than that. I'm reluctant to do a back of the envelope around that issue right now.

The bottom line is the credits are not growing at same rate. We're using some of the credits as we go forward. One of the things that has slowed down our use of the credit was the fact that, bonus depreciation was approved and is now in effect. Bonus depreciation has a relatively short life; it was something we were not cognizant about [Inaudible] we entered into these transactions. So that has delayed a little bit the usage, but we're confident, based on the earnings streams going forward, and the lives of these credits, they will be fully utilized.

Okay. On the gas contracts in Bolivia, has there been any progress made from your perspective?

No.

No, we are still having conversations with the PLNG Group in Bolivia, but there's been nothing to announce.

Okay, on Cameron LNG facility, where is Sempra looking to source the LNG from?

Lasan, we're having discussions with a number of producers. The issue really exist is as producers around the world look at US gas prices, it's only been in last two-three years where there's been this trend upwards. And I think the events of last year, and the events of this year, because we're in a very dire position from the gas storage this year. While we enforce the fact that North America is a great gas market. So we're having discussions with a number of producers, that are having interest in signing up capacity both at the facility in Mexico and in Louisiana. And without getting us into specifics, let me just say, we're having numerous discussions with a variety of different gas suppliers.

Okay, if I'm not mistaken the Cameron facility is half a BCF a day?

One and a half.

One and a half BCF a day. Okay. And Costa Azul is one BCF a day?

That's correct.

Is that, the Cameron facility on a per unit basis is a bit more expensive because Costa Azul also has a power plant associated with it. Could you comment on that?

I'm sorry, I missed the question. Could you repeat it?

It sounds like, well, it looks like the Cameron LNG facility is a little bit more expensive to build than the Costa Azul, given that the Costa Azul has an associate power plant with it.

It's a bigger facility. It's 50% bigger than the facility in Mexico.

But Costa Azul has a power plant, right?

That's not correct; there's no power plant. These are both strictly LNG receiving facilities. We do have a power plant in Mexico that will eventually be a customer, but it's not associated with that project.

Okay, so then they are two separate. [Inaudible] thank you very much.

I think we have a further comment on the tax question.

We've been able to, on the rate of the growth of the unused tax credits, as of year-end; there was a $148m in unused tax credits. As of the end of the first quarter there is a $159m, so that means that, that grew at about $11m. I wouldn't quite expect that rate of growth for the rest of the year, so my estimate would be somewhere in the $35m to $40m number perhaps, for 2003.

Your next question comes from Michael Lawrence with DKM.

Thank you. Just to clarify the trading thing a little bit more, if you could. Could you explain what the major differences were between fourth quarter operating environments and when you earned $53m in trading in the first quarter of this year, when it was down to $19m?

The major change was the acquisition of Metals that we had that came through in the fourth quarter of last year. That was an amount of about $14m.

That was a one-time pickup from that Metals acquisition.

So, that $14m is not reoccurring?

No, and we announced as nonrecurring at that time.

And I think you had indicated at one point that the Metals business you're purchasing will add $25m annually to net income.

That's right.

Is that still on target?

Yeah.

Thank you.

But now, you got to be careful because, you know, again, it is hard exactly to predict the effect of the accounting change on a quarter-to-quarter basis with respect to that. Over time, economically, that will be the result, whether that those will be the reported numbers in recorded period in shorter term is in doubt.

Okay, thank you.

Your next question comes from Mike Heim from A.G. Edwards.

My questions have been answered.

Your next question comes from Craig Shere from Standard & Poor's.

Simple question, you know, as others, obviously in the last several months have pulled back quite a bit from the energy marketing, a question arises, how much are you all prepared to build a vacuum during the window of opportunity and I guess, I wonder if you are pulling back because your VAR was rising with higher energy prices? Does that mean that you desire to limit size of the trading exposure would also limit your longer-term growth there and does that also mean that we should expect less as we go forward through this year if we expect higher energy prices? And then I have got a couple others.

Let me, at the highest level, I have said and continue to say that, I think, this is, sort of, a kind of an intuitive kind of conclusion but I believe that our trading company has been taking space. 2002 is an example, is about the right size for Sempra and really, we will not disproportionately grow the trading company, use of capital and risk exposure with respect to all of Sempra except in concert with Sempra's growth. So, as some of these other facilities come online like LNG and we may grow in some of our other businesses, trading can grow but its use of capital, which is averaged in 2002, just under $1b of capital seems about right. Now, you will have perturbations in the results that come from that depending on market conditions. In my comments in the first quarter was with this very, with ten standard deviations change in gas prices in a very short period of time did result in our, they are paying very close attention to our VAR limit. I consider that to be, that's an extraordinary excursion, we don't necessarily expect, we don't expect that kind of excursion over that period of time on any kind of a regular basis. So, I want to come back and say that you shouldn't infer anything from the first quarter and from that exercise of control to mean that we have a decline in or some depression in our results expected from trading but at the higher level, what is the sort of a size of the business comparably in the size of the risk that it represents in all of Sempra's, that's about, 2002 is about, the sort of a baseline for that.

Just to clarify the first question, no question that there was huge volatility in the first quarter but the next, yeah the last three quarters, I think everybody expects higher energy prices than last year and having the same position, the prior prices as you said obviously meaning a higher VAR. So, I guess my question to clarify is should we construe anything outside of this huge center deviation movement in the first quarter. Outside that unusual phenomenon, just the higher energy prices, would that naturally reduce activity and your profitability.

Well, you know, this is -- it is kind of a push-me pull-you effect here. High prices generally lead to higher margins, albeit they do lead to higher VAR and so, we are going to take a look at the totality of the business and its liquidity demand and its overall risk profile and I just had a very general level, I wouldn't want it to, very much to exceed what we saw in 2002 and we would expect to have substantial earnings as we have said coming from that kind of a position. So, you get benefits from higher volatility generally unless the standard deviation was an excursion, you get from higher prices and higher volatility, you tend to drive higher earnings. On the other side, it does tend to result in higher VAR and higher capital requirements, which we keep a very close eye on.

Okay, if I could revisit, because in a lot of conference calls, there is a lot of confusion about the whole EITF issue and the accounting change from mark-to-market to accrual. There has been a lot of good questions on the call about, there is a $0.14 come back this year and I’ve heard this on other calls, it is further complicated when one company is going to be reporting operating profits from asset sales are all profits because they wrote them down with EITF change but my question is, is your guidance this year ex the $0.14, a good launching pad for future years and as a just a good starting point without all the other shenanigans to think about and in going forward, can you give us again what you expect the longer term growth rates to be?

It is a good benchmark ex the one-time cumulative effect and so the answer to that is yes and we're going to deal with more detail on the future segment information at our analyst conference. I have been informed that we got a lot of people waiting on the calls. I would ask that each person limits themselves to two questions so we can accommodate everyone.

Thank you

Your next question comes from Brian Shin from Smith Barney.

Hi, just one question. With regards to the current and other section the comment was given that higher interest costs, I thought that was to be expenses before financing costs. I just want to clarify that?

[Inaudible] basically has a couple of things in there. It has the financing costs, interest incurred by the office center in the Global Unit. That's by far the largest component. We do have certain overhead costs at the corporate center that we do not allocate out to the business units. It's a relatively small number. And we have some small wind-down companies that are not active businesses but still have some cleanup transactions with them. So, there is a few minor in there other than just interest.

I noticed sequentially, last, the prior quarter was also around $30m. Should we just go ahead, going forward, is 30m closer to a level that you guys are including in your forecast in the quarter?

I think, right now, we issued the $400m as debt in the first quarter, so you will see, some increase for that, because we don't have a whole quarter's work in the first quarter. Last year, we had the equity units were issued in the second quarter, and they are here in the first. We had a little bit of an increase for that. Probably somewhere in the $25m-$30m per quarter would be a good run-rate because we do have these other small things that will cause us to be a couple of million, higher or lower.

Great, thank you.

Our next question comes from Paul Debbas from Value Line.

Hi, can you discuss your financing plans for this year?

Well, at our current business, our capital expenditures in investments are covered by our cash flows. Now, that's not to say that if we were to find a target of opportunity that we thought was worth pursuing that we would not need to finance around that. But that will, if we do that, that will be transparent and you will understand exactly why we're incurring debt or issuing equity. I am not meaning to project anything by saying that, that's just an observation. Our base plan is that our current cash flows cover our capital expenditures.

Have you switched on the dividend reinvestment program? What was the increased shares just exercising options, thanks?

No, there has been no exercising options, and yes, it is turned on.

How much do you expect to raise annually?

[Gap In Audio] DRP?

A few million shares a year [Inaudible] .

All right, thank you.

Our next question comes from Fadulah Murphy (ph) from SAC Capital.

Good afternoon.

Hi.

Wondering, in term, you mentioned to have capital expenditures of $1.3b will be met by internal sources by cash flows for 2003. What is the current outlook for '04 CAPEX, given that you will be finishing up to three large plants here at the end of this year and the free cash flow outlook for '04?

The cash flow outlook is essentially within that range or slightly higher in '04. Again we can give some discussion of that at the analysts' conference. But you are right to observe that the capital program dropped significantly and so we'll have discretionary capital budget. The utilities take some place between $700m and $800m. I forget exactly what we put in to the filing. So that, if you subtract that from the $1.3b or $1.3b plus, you come up with the amount of capital would be available for our other projects. Now, we've identified two capital projects, that Costa Azul and Cameron, that will over the next four to five years, expend $1.1b or $1.2b, $1.3b I guess, yes, it's $1.3b. And there are other projects that we have from time to time, but there is essentially a fairly significant discretionary piece and one of the reasons that the ratings agencies are comfortable with us is that money is, if not expended on a transparent project, is available for reducing our leverage. And so, we're in a declining leverage mode over the five-year horizon.

And one last thing, in terms of all the questions about trading and everything like that. My recollection is in the past you've indicated that during the periods of high volatility it's very hard to come up with the customer-backed type of transactions, which is pretty much, you know, the core of your business. That when things calmed down if we have lower volatility period regards commodities prices in fact this recent period of volatility, probably should help in terms of creating future business? That's been my understanding in the past. Do you tend to see things like that?

Yeah. Let me, I think this past quarter is an interesting example. Customers don't respond necessarily immediately to market conditions. There is a certain amounts of soak time that occurs. And so, sustained higher volatility does result in customers seeking to flatten out their exposures. The 10 deviation price spike did not have, at that moment, an immediate customer impact, however, I'll, I believe that we will see and I think we are seeing increased customer interest in mitigating gas exposure particularly subsequent to that event. And if you note that there are record low storage condition, so, you've combined record low storage conditions and a 10 standard deviation price spike in natural gas and believe me there is considerable customer interest. I am skirting on my promise not to take about quarters, but the market conditions are very good now for increased customer interest.

Okay. One last thing. No one has talked about the California and the western power markets and the outlook here going into the summer. If you could comment on kind of your observations?

This is Don Felsinger. I'll just say what these data say and that is that they expect to get through the summer assuming that we've got decent hydro conditions in Northwest. I think the issue for California is longer term, which is going to be determined by how people view this state and its business climate for making capital investments. And so, I think the decision by the FERC in the next couple of months on the long-term contracts, I think will say something about the future of investments in California, in this region, but I don't expect any promises from.

Thank you very much

I was just going to add to what Don has said that you may be aware that the California Public Utilities Commission asked each of the three investor on utilities to file a 20-year electric resource plan. That was done on April 15th and there will be lots of discussions through the summer with an expected decision later this year that deals with both the shorter term and longer term with respect to resource editions in the state.

Okay. Next question?

Our next question comes from Jeff Gildersleeve from Argus.

Yes, thank you. Very helpful conference call. Quickly, was there any currency impact in the quarter?

Yeah, there was a positive OCI adjustment with respect to Argentina and I believe that the rest of it is relatively minor, not in any sense, sort of noise. But we've got a positive OCI impact in Argentina.

Okay. But nothing from Europe as far as trading that would be material?

No, that's not material, no.

Okay. And then if I understand correctly, on that last question. It seems like if volatility would provide opportunities, but it seems that your comment suggests that volatility we're seeing now in the market is more attractive for your business than what we saw in the first quarter?

Let me just say, volatility is good for our business. Extreme spikes cause pressures on our risk management and don't necessarily translate instantly in the customer business. So, you have to kind of consider the effects in time of the volatility and you can, I think, make the appropriate inference.

This is Don Felsinger. I would add on what Steve is, we like volatility because it's not just customers that take action, but when you see extreme volatility, customers tend to freeze up. They don't know what to do. And when you have 10 Standard deviations of volatility, which we did this past quarter, customers are loathed to sign long-term contracts for gas or take some action when prices were so extreme.

Great, thank you.

Our next question Ms. Jones from ABN AMRO.

My question, well a couple of them have already been answered. But I wanted to clarify with regard to the trading. You had indicated that you would book a one-time $14m, I think, it was adjustment to the Metals positions that you acquired in the course of acquiring Metals trading business?

Yeah, that was the fourth quarter plus, that was nonrecurring, fourth quarter 2002.

Right. Was there or is there anything that's going to be booked along those lines so far and that you know of for '03?

Not of that type, not of that sort of. We're looking at a number of books to the extent that we might buy some books. You'll see, those will be, I guess I shouldn't say that one-time. They're kind of part of our continuing business they produce. They produce a one-time trade effect.

Okay. Then a follow-up question. How would some of the books that you may be looking at compare in size to the Enron metals trading book?

Much smaller.

Okay fine.

And generally we were looking for books of business that roughly fit our duration. We've rejected a number of opportunities that have long-dated positions in them and again this is part of our risk management philosophy.

When do you think you might have an announcement about something?

I can't say.

Could be at any time?

Yes.

Okay. Thank you very much.

The next question comes from Paul Joy with Citibank Financials.

Hi, could you hear me?

Yes.

I just have one question on the EITF document. I understand the $29m --

Speak a little louder please.

For the EITF document, you have it in two piece. The first one is the $29m.

That's the one-time cumulative effect.

Which is where you take the -- whatever contracts you had that didn't qualify, then you sort of?

That's a 2002 question.

Right.

It was booked on January 1 --

2003.

Yeah, right.

Could you explain again the $9m charge? Because it doesn't come under accounting charge, right?

Yeah, it is an accounting charge. It comes from the same accounting change but it results from. It's not a one-time charge. It results from the change in accounting and that will be an ongoing effect.

The new rule went into effect January 1. We had to do a cumulative effect change that's the $29m for the two business units. Basically when we are applying the principal, going forward that's now GAAP, through GAAP. What we said was that if we adjusted that back, to marking everything to market as we had in the prior year and how we actually run the business, which is all mark-to-market, the delta between that was $9m. So, the ongoing impact in the quarter was $9m. Let's say the rule had changed on April 1, the cumulative effect change then would have been $37m because we would have had the $29m from before, plus the $9m from the current, or $38m in total or $37m for the trading company.

Okay. When I look forward to your second quarter earnings release, are you going to say, will you also break out the adjustment for what our earnings would have been under mark-to-market?

I think that's going to depend a little by being over time, as we get into next year, you compare two years, you'll have both years on the same set of accounting and we certainly wouldn't do it. If the number turns out to be very material expended maybe next time we won't, if it's a material number to have comparability to see how we did quarter-to-quarter; we would in fact break it out.

We have got time here for two more questions.

Okay just to clarify that the $9m is as if you were still on the mark-to-market basis?

Yes.

Okay thanks.

Your next question comes from Zack Schriber from UKV Capital.

Hi Zack.

It's been asked and answered, thank you very much.

We have a follow up question from Michael Goldenberg from Luminous.

Hey guys, thank you for getting me back into the line. Just wanted to follow up, on your DWR contracts, I think you kind of mentioned that you're still open to a settlement? I guess, I am not understanding, if you've won the contracts, what's the point of talking to DWR?

What we've said to the state is that we're willing to re-form the contract in a way that's useful to Edison and to the state. That doesn't do us any harm economically. So we've talked about taking a take or pay energy contract, in which the energy has to be taken whether it's needed or not, in two blocks. A peaking block and a base-load block, and converting that into a payment for capacity and then dispatching the energy. The state is our customer' we'd like to accommodate the customer as best we can and that we can do. It would allow the state to avoid significant fuel costs because they don't have to provide the gas or pay us for the gas. We've calculated that change alone, without changing our economics, would save the state in excess of $1.2b. The only disappointing thing is there would have to be some further assurances about the state's legal ability to make a significant change. I do want to add that there are no current discussions going on with the state on this subject. I think our position; actually we had come to the point where we had completely provided an agreed re-drafted contract. If they'd like to go in that direction, we can go in that direction. We just need legal assurance that they have the capacity to enter into significant change.

Okay just one more question. Can you talk what's going on with trading and also SoCal gas, gas capacity withholding situations that are further looking at?

You are talking about in the.

There's the trading part. That we heard at the end of March and I guess you guys have 45 days? Then the SoCal gas portion, which I am just not sure where it stands at all?

Well there's two pieces. trading has been ordered within 45 days to report as to its certain changes its required to make. For example it has to show it's in full compliance with market information and show it's got a plan in place to assure that reporting of trade data is accurate. That discipline is imposed on anyone who gives inaccurate data. That appropriate trading is taking place etc. We've done all those things, that's not going to be a problem. The other part of the refund case is a staff recommendation that orders to show cause be issued to certain market participants, including trading and SDG & E to show they didn't, those entities did not engage in any prohibited market activity. That staff recommendation has not yet been adopted by the Burke (). We don't know how that will come out. We've said categorically and under oath we didn't participate in any of those market manipulations. We don't expect that to be a difficulty.

Is that in relation with El Paso, which you have just said the whole SoCal El Paso relation?

Sorry, I didn't get your question.

I am sorry; I am just saying SoCal gas has been mentioned to some extent with El Paso. I just wanted what you just said relates to that?

No, that's another case altogether. There were a series of litigations that have been instituted relating back to period in the mid-90s, having to do. It's not at the Burke. I wanted to say regarding my last answer that the Burke, in regard to the staff recommendation for orders to show cause, the Burke has asked for briefs from all of the parties because a basic consideration here is whether California market rules have sufficient specificity to put market participants on fair warning as to what would be prohibited behavior and there is a real question about that the rules are vague and refers to gaming, but one is not sure what that mean and in order the hold the market participants to a reasonable standard, for which there could be adverse economic penalties, you got to have enough specificity. That issue is going to be argued.

[Inaudible].

Yeah.

At this time there are no further questions. Mr. Arriola, are there any closing remarks?

I think, just want to remind people that on May 7th, we're going to have our analysts' conference. It will be webcast live sort on 8 o'clock San Diego time. So, you can go through our Web site for those of you who'll be [Inaudible] . If you have any further questions regarding the quarter or anything else, you can give our staff a call. Thanks for joining.

Thank you for participating in today's Sempra first quarter 2003 earnings conference call. This call will be available for replay beginning at 2 P.M. Eastern Standard Time today to 11:59 p.m. Easter Standard Time on May 8, 2003. Conference ID number for the replay is 959 9599. The number to dial for the replay is 1 800 642 1687 or 706 645 9291. You may now disconnect.