桑普拉能源 (SRE) 2003 Q4 法說會逐字稿

Good afternoon. My name is Jeff, and I will be your conference facilitator. At this time, I would like to welcome everyone to the Sempra Energy fourth quarter and year end, results conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer period. If you would like to ask a question during that 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. Thank you.

I would now like to turn the conference over to Dennis Arriola, Vice President of Communications and Investor Relations. Please go ahead, sir.

Thank you. And good afternoon and thanks for joining us to discuss Sempra Energy's 2003 full year and fourth quarter financial results. A live webcast of this teleconference and slide presentation is available on our website at www.sempra.com, under our Investor section. With us today from the company are several members of our management team, including: Steve Baum, Chairman, President, and CEO of Sempra Energy; Neal Schmale, our Executive Vice President and Chief Financial Officer; Don Felsinger, Group President of Sempra Energy Global Enterprise; Ed Guiles, Group President of Sempra Energy Utilities; and Frank Ault, our Senior Vice President and Controller of Sempra Energy.

Before handling the call over to Steve Baum for today's presentation, I'd like to remind you that this call contains forward-looking statements that are not historical fact 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 assumptions. 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. In addition, some of the financial information we will be discussing today may contain non-GAAP financial measures. In those cases, we will reconcile those financial measures to the most directly comparable GAAP figures. The reconciliations are included in our slide presentation today and are available on our website.

With that I'd now like to hand the call over to Steve, who will begin with slide 3.

Thanks, Dennis, and thanks to all of you on the call for joining us today.

I'm very pleased to report that Sempra Energy had a record year in 2003 with strong results in the fourth quarter. Earlier this morning, we reported net income of $649 million for the full year of 2003, or $3.03 per diluted share, compared with 591 million in 2002, or $2.87 per diluted share. Excluding unusual items in both years, earnings per share increased 7% to $2.93 from $2.73 in 2002. In the fourth quarter of 2003, we recorded net income of 234 million, or $1.03 per share, up 43% over fourth quarter 2002 results of 148 million, or 72 cents per share.

There were one-time adjustments in the fourth quarter that I would like to discuss briefly now and in more detail on subsequent slides. The first item is a benefit of $18 million resulting from favorable tax settlements with the Internal Revenue Service. The settlements relate to claims dating back to 1989 and positively impacted the earnings of SDG&E, SoCalGas, and the parent. The second item relates to the adoption of FASB interpretation number 46 which requires the consolidation of variable interest entities.

The adoption of FIN 46 increased earnings at Sempra Energy Resources by $9 million due to the consolidation of the synthetic lease at the Mesquite power plant. It also increased expenses at the parent by $26 million related to our minority interest in Atlantic Electric & Gas, Limited, a U.K.-based retail marketer. FIN 46 also required the Company to consolidate the assets and liabilities of these entities. At December 31, 2003, Mesquite had 643 million in assets and 630 million in liabilities; and Atlantic Electric & Gas had total assets of $180 million and liabilities of $251 million.

Next is a $21 million impairment charge related to our investment in Atlantic Electric & Gas. Lastly, in the fourth quarter, we recorded 6 million in litigation costs arising out of the California energy crisis of 2000 to 2001, while 13 million was recorded in the fourth quarter of 2002. Also in the fourth quarter of 2002 we had a $14 million gain related to acquisition of the Metals business.

Now let's turn to the individual business units, starting with slide 4. Sempra Energy utilities had an excellent year in 2003 and made substantial progress from a regulatory perspective. For the full year, San Diego Gas & Electric and Southern California Gas, on a combined basis, recorded net income of $543 million compared to $415 million in 2002. Earnings, excluding unusual items in both periods, increased to 413 million in 2003, from 403 million in 2002.

Now let's turn to slide 5. Let me explain the unusual items at each of the utilities starting with SDG&E on slide 5. In 2003, SDG&E had net income of $334 million compared with $203 million in 2002. Fourth quarter earnings for SDG&E were positively impacted by a $79 million settlement of income tax issues. The tax settlement derived principally from the IRS's revised treatment of utility balancing account based on the precedent-setting Houston Industries case.

SDG&E's 2003 results also were affected positively by a third quarter $65 million gain related to the settlement of our intermediate term contracts dispute, partially offset by $11 million related to the California energy crisis litigation costs. SDG&E's 2002 net income included a one-time gain of $25 million related to other tax settlements and 6 million of costs for California energy crisis litigation issues. Adjusting for these unusual items, net income for 2003 was 201 million versus 184 million in 2002, up 9%.

SoCalGas had a 2003 net income of 209 million compared with 212 million in 2002. In the fourth quarter of 2003, SoCalGas's net income was affected positively by 29 million related to the tax settlement. In the third quarter, we had a $32 million reduction to net income related to California energy crisis litigation costs and a one-time charge for sublease loss. SoCalGas's 2002 net income included 7 million of expenses for California energy crisis litigation. Earnings at SoCalGas, excluding these unusual items, were 212 million in 2003 compared with 219 million in 2002. The decrease in 2003 was due primarily to the end this shared merger savings in 2002 and higher O&M expenses in 2003, partially offset by gas cost incentive mechanism awards.

Let me spend a moment on the status of several utility regulatory proceedings. On December 19th, we filed settlements of our cost of service rate cases with the California Public Utilities Commission, or CPUC. The SoCalGas settlement is an all-parties settlement, and the SDG&E agreement is a multiparty settlement that includes the CPUC's Office of Ratepayer Advocates. The final resolution of these cases is likely in the second quarter of 2004.

Last year the utilities also filed for a continuation of performance-based rate making, or PBR mechanisms. The CPUC issued a decision on January 8 extending the 2003 service and safety targets through 2004, but deferring action on the application of any awards or penalties until later in 2004. The gas cost incentive mechanisms for SoCalGas -- mechanism, excuse me -- for SoCalGas remains in place as part of the settlement agreement reached last year.

In November 2003, SDG&E filed a long-term electric resource plan covering its anticipated procurement needs from 2004 through 2023. The CPUC has approved SDG&E's plan for 2004, and we expect the commission to address the longer term procurement requirements in the next several months. This will include the proposed 2006 addition to rate base of the 550-megawatt Palomar power plant being constructed by Sempra Energy Resources.

In December SDG&E also received final order from the Federal Energy Regulatory Commission approving an 11.25% return on equity for electric transmission assets and full recovery of our abandoned cost related to Valley-Rainbow Transmission project. The transmission rate formula will allow SDG&E annually to true up incremental investments. Later today we will be making a filing with the CPUC on the gas market order instituting rate making. The proceeding addresses gas supply and infrastructure issues going forward, including the introduction of liquefied natural gas into California.

Now please turn to slide 6, and I will cover Sempra Energy Trading. When we acquired the Trading Company in 1997, it was primarily a marketing company that focused on physical natural gas transactions in the U.S. Since then, Sempra Energy Trading has broadened and diversified its business to include other physically and financially traded commodities, including petroleum, power, and metals. Sempra Energy Trading has recorded 20 consecutive profitable quarters, excluding the negative cumulative effect of EITF 02-3 implemented in January 2003.

For 2003, Trading reported net income of 98 million which included the 28 million negative accumulative effect of EITF 02-3 in the first quarter. Excluding this adjustment and a 2002 gain related to the acquisition of the Metals business. Tradings earnings for 2003 were 126 million, up from 110 million in 2002. Trading also had a strong fourth quarter in 2003 with net income of $59 million compared with 2002 fourth quarter earnings of 53 million, which included a $14 million gain on the acquisition of the metals business. The increase in net income was due to strong results in crude oil and products, as well as in metals and a solid performance in natural gas.

The fundamentals of this customer-based business remain strong. We have profitably grown this business without changing its risk profile. Although North America continues to be our primary market and represented about 68% of our trading margin in 2003, we grew our business in both Europe and Asia. Marketing natural gas remains one of the strongest parts of our business, and in 2003, represented 26% of our trading margin. In 2003, we traded an average of 13.2 billion cubic feet a day, making us one of the top five physical gas traders in North America. Oil and crude products represented 24% of our margin in 2003, while metals contributed 18%.

Our diversification by product line and geography is one of the factors that differentiates Sempra Energy Trading from competitors in the market. We focus on shorter term transactions in business where we can validate market prices. Over 45% of our unrealized revenues, as of December 31, converted into cash within the next 12 months and over 80% within the next 24 months. This is a consistent strategy we have followed and on average, over the last three years, 84% of our unrealized revenues converted to cash within 24 months.

Also, we carefully manage the credit quality of our counterparties. At year end, nearly 80% of our outstanding unrealized trading assets were associated with investment grade companies or commodity exchanges. Our strategy remains customer focused. In the last quarter and last year trading daily value at risk, or VAR, the 95% confidence level averaged 4.4 million and 6.5 million, respectively, consistent with our low historical VAR numbers.

Let's now turn to slide 7 and Sempra Energy Resources, our generation business. Resources had a strong 2003 with net income of $94 million, compared with 60 million in 2002. The fourth quarter net income results of 46 million included 9 million positive, one-time adjustment related to the adoption of FIN 46. The increases in net income in the fourth quarter and full year are primarily related to the increased electricity sales under our contract with the California Department of Water Resources. In 2003, we were successful in bringing on line 2000 at 125 new megawatts. We have over 80% of our annual energy production sold forward through 2010. This generates stable earnings and cash flow into the future.

Sempra Energy Resources has other opportunities for growth. These include the proposed Palomar power plant that will be built by resources and sold to SDG&E in 2006. In addition, Resources continues to evaluate new market opportunities. The Company has other potential sites for generation that can be developed, but we will not commence construction unless firm contracts for the power are identified.

Now let's turn to slide 8. Net income for Sempra Energy International in 2003 was $1 million versus 26 in 2002. Now, results for 2003 included a charge of $50 million in the third quarter related to the impairment of Frontier Energy, a North Carolina-based gas utility subsidiary. Absent the impairment, Sempra Energy International's results for the year were 51 million, compared with 2002 earnings of 26 million. In the fourth quarter of 2003, Sempra Energy International earned 8 million, compared with 4 million loss in the year earlier period.

In 2003, International had a full year of earnings contribution from our Gasoducto Bajanorte Pipeline. The current capacity for the pipeline is contracted for the next 20 years. We recently went through an open season to assess the interest of liquefied natural gas shippers in an expansion of the pipeline. The market response has been positive. Our gas distribution companies in Mexico continue to grow and add customers. In South America, earnings from our distribution investments increased over the prior year.

Please turn to slide 9, and I'll give you an update on LNG activity. Let's start on the West Coast. Last year we received the three major permits needed to go forward with our Energia Azul receipt terminal. The project has positive support from the Mexican, Federal, State, Local, and Governments. We have had a small number of injunctive actions by local landowners. We have prevailed or expect to prevail in all of these actions. In December we made two major announcements concerning this project. We and Shell announced our intent to form a joint venture to build and operate a single LNG project at our Energia Costa Azul site. Under the agreement, we will -- each will have ownership of 50 % of the total 1 billion cubic feet of natural gas per day capacity of the receipt terminal. In the future, the receipt terminal can be expanded to double the capacity or 2 billion cubic feet per day.

We also signed a preliminary 20-year LNG supply agreement with the government of Indonesia and British Petroleum, representing the Tangguh Partners. The supply from this agreement will cover our half of the terminal's capacity at 500 million cubic feet a day. We're in the process of finalizing the sales purchase agreement with pricing tied to a discount to a California border index. This pricing agreement will ensure that Sempra does not take fixed gas price risks.

In Louisiana, at our Cameron LNG site near Lake Charles, we've received the necessary federal, state, and local approvals to build a 1.5 billion cubic feet per day receipt facility. Our proven ability to market natural gas through Sempra Energy Trading makes us an attractive option for many suppliers. We're in discussions with several potential suppliers and hope to make an announcement soon. By commencing construction on both of these facilities later this year, we can begin operation in the latter part are 2007.

Please turn now to slide 10 for summary of our business unit results. The 2003 net income of our retail marketing group, Sempra Energy Solutions, was 16 million compared, with 2002 earnings of 21 million. In the fourth quarter, Solutions generated net income of 9 million, compared with 10 million in the same period last year. For 2003, Sempra Energy Financial reported net income of 41 million, compared with 36 million in 2002. For the fourth quarter, net income was 9 million, compared with 13 million in 2002. The fourth quarter decrease was primarily due to lower earnings from our Section 29 investments.

The total net income contribution from both our Section 29 and Section 42 tax credits was in line with what we presented in May at our last analyst conference. For the full year, Sempra Energy Financial's net income from Section 29 credits was $22 million, and Section 42 investments contributed 19 million. The net income contribution for Sempra Energy Trading's Section 29 tax credits was 23 million. Next year we expect a slightly lower contribution from Sempra's tax investments, translating into an overall effective tax rate for Sempra Energy next year of approximately 20%.

2003 expenses at parents and other were 144 million, compared with 93 million in 2002. Fourth quarter expenses were 86 million, compared with 22 million in the same period last year. The expense increase in the fourth quarter and full year is primarily due to the $21 million impairment and the $26 million FIN 46 expense for Atlantic Electric & Gas.

Turning now to slide 11, Sempra Energy completed the year with a stronger sheet. Total debt to total capital was reduced from 60% in 2002 to 57% in 2003. In 2004, we expect our total debt to decrease from 5.3 billion to just over 5 billion, and our total debt to total capital ratio to decrease to 53% by year end. We completed 2003 with over 400 million in cash and 2.1 billion in available bank lines. We are committed to maintaining our strong credit ratings.

Capital expenditures and investments totaled 1.25 billion in 2003, of which nearly 300 million was related to construction of our generation plants. In 2004, we expect capital expenditures and investments to be approximately 1.1 billion, with approximately 750 million allocated for the utilities and 170 million for our LNG projects. We plan to fund all these programs internally.

Now, I'd like to focus on our outlook for 2004 on slide 12. Based on our current plan, we've updated our 2004 guidance to a range of 2.70 to $2.90 per share. We will provide you with additional information by business unit at our upcoming analyst conference in June. Let me close by saying that I'm very pleased with our success at Sempra Energy in 2003. Our financial results demonstrate that our strategy is working. We have increased earnings per share an average of nearly 20% annually since we formed Sempra Energy in 1998. As I've said in the past, we pride ourselves in delivering results, not promises. In the five years of Sempra Energy's existence we have achieved performance that few in our industry can match.

And, now I'll open the call for questions.

At this time, I would like to remind everyone, in order to ask a question press star then the number 1 on your telephone keypad. We'll pause for a moment to compile the Q & A roster. Your first question comes from [Michael Goldenberg with Luminous Management].

Morning, guys. Congratulations on a strong year.

Thank you.

I know you guys haven't given breakdown for 2004, but is there a way you can tell us main drivers that caused you to increase the lower end of the guidance from $2.60 to $2.70?

Yeah. Well, let me repeat of what I said in my prepared remarks that we will certainly give a much greater detail, business unit by business unit, that go into that forecast at our analyst conference in June. But let me say that the principal reason that we have narrowed the range comes from our expectation of approval of the settlements that we've reached at the utilities which significantly strengthened our view as to the utilities earnings prospect for the next three or more years.

What about the effect of weak dollar on your international operations? Could we expect to see further benefits from that?

Actually, there's very little effect through F X in our international operations. The strength in oils and so forth, which are dollar-denominated, doesn't do much, and a good deal of the metals trading is also denominated in dollars, so actually it's relatively minor. As far as your LNG is concerned, not that you have a contract, of course, could you maybe update us on how you view ROEs for this business? What should we expect for ROEs, and what capital structure should we expect on these types of investments? You could -- our target range for ROEs in these investments, and we've been public about this in our discussions with suppliers, is in the range of 12% unleveraged.

And just one final question. I'm sorry to take up time on the LNG. The $170 million, does that include both projects? Do you expect -- in your 170 did you embed the Louisiana project even though you don't have a contract right now?

I'm sorry, the 170 came -- I missed it.

170 million of cap ex for LNG. You don't currently have a contract for your Cameron plant.

Oh, right. I understand. Yeah, the -- we would -- it's our expectation that we will have the necessary contracts in place to meet our construction schedule. I said publicly and I'll repeat it here, that we will not go forward with these projects unless we have an assurance of at least a return of our investment through our contracting strategy, and we would fully expect to be there on our construction schedule.

Thank you very much and congrats again.

Thank you.

Your next question comes from Anatol Feygin of J.P. Morgan.

Hi. Good afternoon, everyone. A couple of questions. In terms of the cap ex, the guidance for 750 for the utilities end, 174 the LNG. Can you give us a sense for the remaining 200 million or so, or is that allocated, or is that things that you potentially see coming down the pipe?

Well, maybe I should ask Don Felsinger to address this question. But I will say, in general, and as I have discussed publicly, we are looking at other assets in the country that fit with our LNG strategy. And as many of you know, we have expressed an interest in the ADP auction, so we do have a fair confidence level with respect to the capital expenditures beyond -- up to the 1.1 million, beyond the total that we expressed. But are not currently specifically identifying project unless, Don, you want to --.

I think that covers it. The 170 that we have allocated for LNG is based on our estimate of starting construction, both sites midyear. We have some additional capital allocated to a gas storage project that we informed you about that we call Bluewater located in Michigan, and the rest of the capital is basically unallocated. We have several opportunities, as Steve mentioned, that we're pursuing, but at this time we've made no commitments.

So would it be fair to characterize the remainder as most likely to be spent in investments, as opposed to green field opportunities?

That's correct.

Great. And in terms of the BP Indonesian supply contract, you guys have mentioned a couple times that you see that structure as being a discount to index. Can you talk about the volumetric commitments that that contract has embedded in it? Do they to have provide 500 million a day? Is that their responsibility at index minus, or is that something that's still under discussions?

The answer is "yes." I mean, that's kind of the flip side of take or pay. It is 500 million a day of through-put, and to give you a little more flavor on the pricing terms, we're talking about a split discount. That is, one which would have a fixed portion, and one that would have a variable portion, a percentage portion. So that we're, in effect, allocating the risk with BP and a risk or opportunity with BP and Indonesia on price movements, and those -- the fixed and variable discount is -- will be to a defined California-related index price.

So just to clarify, you're saying that a portion of the gas will be pure fixed price -- kind of take or pay contract?

The full supply of 500 million a day, which they must deliver, will be priced -- the whole supply will be priced through a mechanism that is part fixed and part variable, fixed being the number of cents discount to the index and the other being a percentage discount to the index, so that we allocate risk and opportunity with respect to price fluctuations between ourselves and the shippers.

But the full 500 million is at a discount to index?

Yes.

Just a question whether fixed or percentage?

Yes.

Great. And the last question. February 19th we're supposed to see a decision or recommendation out of the ALJ. That's obviously been postponed. Has there been a new date set for that phase of the rate proceedings?

I'm going to give this to Ed Guiles.

Hi, Anatol. In the schedule, with filing of the settlements, the judge in this case, Doug Long, we basically have completed our brief filing in the settlement filings and reply comments on February 19th. So now the decision on the cost of service is in the judge's hands. We would expect a PD from him within the next two months. So look for a decision in May to June, June at the latest, from our perspective. So we're looking by the end of the second quarter.

Great. Thanks very much, everyone.

Your next question comes from John Edwards of Deutsche Bank.

Yeah, good morning.

Good morning.

Good quarter. Could you repeat the VAR limits that you gave out? I missed that.

Yeah. Hold on a second. I've got to go back and look at it.

Four million for the quarter and six and a half for the year.

A little more than four million for the quarter. Let's see if I can find it. Yeah, it was 4.4 million for the quarter, at average, and 6.5 million for the year.

And that's consistent -- I mean, the annual one is quite consistent with what we've been doing year in and year out, and I've said to investors that one of the things you want to look at with a trading operation is whether, you know, as you get absolute price changes or volatility changes is there a -- is there a departure from the VAR. In other words, as the VAR increase, is the company trying to chase something, and that's not the case with us. It is reflective of the rather steady customer business that we have that our VAR doesn't change even as some of these other factors do.

Okay. Then, you know, on the Cameron facility, you're in a joint venture on your Baja facility. I'm just wondering, is that something you're also looking at for the Cameron facility as well?

Not that we would particularly desire it, but in some of the negotiations there have been interests expressed in ownership of the facility, and we're still in discussions, but I don't mean to telegraph that we're going to enter into additional partnerships.

I would just add to that, that as we have discussion with a large -- with a lot of the large shippers, obviously, they have a lot of interest in how these facilities are designed and operated. And to them a way to have a chance to have input is to have equity. So if we have these discussions, they invariably lead to equity. That's not our preferred outcome, but we would consider it if we had the right partner.

What's the timing now that you're looking at for the Palomar and, you know, the Calpine contract -- power purchase contract that has some sort of rate-based mechanism?

I'll give this to Ed Guiles.

Yeah. We have, as I covered in the last call, made a filing with respect to our generation needs going forward. That's -- the two principal plants are Palomar, then the power purchase agreement with OTI. Hearings have been ongoing, they've been essentially complete with respect to our request for proposal at the PUC, and we would expect a decision out of the commission by around May of this year. The schedule we're looking at is completion of those two projects, first Palomar by the June 2006 time period, and roughly a year later for the OTI Mesa facility, and, of course, it's dependent upon us getting our local electric transmission infrastructure projects built to accommodate that project. So that gives you the full picture.

Okay. Great. Thank you very much.

Your next question comes from David Maccarrone of Goldman Sachs.

Thanks. You previously disclosed a $1.3 billion average annual cap ex over '03 to '07 at the May conference, and you've lowered here with the release cap ex outlook for '04 again. What accounts for this? And is this '04 level sustainable? And how might that affect the way you look at the dividend going forward?

David, I mean, I think it's probably pretty obvious by partnering with Shell we've reduced our cap ex requirement at Costs Azul by 300 million, and that's the principal reason for the reduction. And, no, it doesn't alter our current policy on dividends.

And could you just review again the Section 29 and 42 tax credits' impact in '03 and specify the time period and rate over which the Section 42 credits decline.

Yes. Frank Ault, our controller, will give that you breakdown.

In the current year we made net income about $64 million from both Section 29 and the Section 42 credits. About a third of those were for the Section 42 credits, kind of about two-thirds of it for the Section 29s. The Section 29 credits will end in the year 2004. The section 42 credits --.

Seven.

Seven. Sorry. Said the wrong year. The Section 42s decline over time. We entered into those on varying dates, and you get the credits over the first ten years, and you keep maintaining the operations for 15 years. So we'll see a slight decline in the 42s over the next few years. On the Section 29s, they will continue pretty much at the current level, down maybe just slightly until we get to past 2007.

Okay. So there's no expected decline, no significant decline in the 42 credits over the next several years?

No, I would say over the Section 42s, they're going to go down probably two, three, four million a year as the deals hit their ten-year mark.

Okay. When will that be?

They'll start -- I think we'll probably see a slight decline starting in 2004, then out over the next seven or so years from there.

Okay. Thank you very much.

Your next question comes from Paul Patterson of Glenrock Associates.

Good afternoon, guys, or good morning there. How are you?

Just fine. How are you?

All right. Maybe I'm missing something, but I'm looking at shareholder equity year-over-year, and it seems to have grown pretty substantially, more than perhaps retained earnings would suggest. Is that OCI? Am I missing something or just reading it wrong?

We've made several securities offerings which have contributed to Equity [partners]. The increased retained earnings most recently to 500 million of Equity that we issued I guess it was in October. And, of course, prior to that, a year or more earlier we issued convertible units that will convert in 2005.

That explains it. I just needed to be reminded. Thank you. And then in terms of Solutions -- I'm sorry if I missed that because I had to go on and off the call -- is there anything -- could you describe what's caused that decline? I'm sorry if I missed that.

Well, Don, do you want to talk about Solutions for us?

I'm sorry, Paul. What was the question again?

Well, looks like it's declined year-over-year and quarter over quarter, and I was wondering if you could just give us a little bit of an update there on what you think it might do in '04.

Probably the biggest thing is we look at has been the shrinking margins in this business. As you know many states have put on hold or curtailed retail competition, and so those of us that are out there still in the business are basically fighting each other for customers and margins are shrinking.

But also in 2002, we had a rather extraordinary year, given the commodity contracts that were available in California, and you may recall that whole exit fee question, and when the exit fees were set at reasonable rates, a number of the customers did renew those contracts, and Solutions got a big chunk of that business. Now, there's less of that in 2003, so some of the year-to-year decline is as a result of that contracted commodity business in California, just not being there, given that the contracts were signed for several years forward.

But then in terms of what you're seeing in terms of the competitive market now, going forward into '04, you know, do you feel that margins are going to continue to shrink, or do you think it's stabilized here? Any thoughts on that?

I think when we share with you our '04 estimates at our analyst conference we'll give you some more details, but we still have a view of '04 having tight margins in this business.

Okay. Then just finally on syn fuels, you mentioned that they're declining slightly. I just was wondering, doesn't sound like it's that material, but just why is -- why are the syn fuels declining? And also, when I look at your tax rate --.

It was the 42s that were declining because of the aging of the real property investments. The investments we have in syn fuel tax credits have not -- or businesses are not in decline.

Okay. Then when -- I'm calculating your tax rate, and maybe I made an error here. But when I calculated it for '03 it looked like it was about almost 21%, and I just wanted to get an idea as to, you know, are you planning on that declining I guess to about 20%? Is that about right?

This is Frank Ault. Our -- actually our effective tax rate for the year 2003 is 6.3%. The largest element that caused this to drop from last year's 20.2% was the settlement of the $118 million with the IRS. About half of that was tax-related. So had we not had that, we would have had an effective tax rate of about 18.5%, and we're looking at something in the 20% range for next year.

Okay. And then just -- I'm sorry if I missed this, but in terms of the LNG cap ex numbers, what are they for '05? Are they the same or are they higher?

For '05?

Yeah.

We're on a trajectory to spend by 2007, approximately 1. -- excuse me, 1.1 to $1.2 billion. So you will see an escalation of those capital expenditures during the peak construction period in 2005 and '06, and then declining in 2007.

Right. I was wondering -- I mean, you mentioned that at least I think for 2004 you guys can finance this internally, and you also mentioned that, obviously, with contracts and whatever you can finance quite a considerable amount of this. Do you see any need to issue equity perhaps in '05 or what have you? I mean, what are your -- or is that -- or do you think you can, with internal cash flows and with financing, handle it?

The projects that we've identified, and the level of capital expenditure that we've identified generally through the period is financeable internally. The reasons for issuing equity -- let me correct one thing I said -- 1.1 or 1.2 -- it's actually $1 billion for the two plants, considering the partnership with Shell, 700 million at Cameron, and 200 million at Costa Azul. But having -- the identified project we have are fully financeable internally. The reason, if there would be one that we might issue equity during this period, would arise either from further pressure on our ratings, which we do not anticipate, but I can't -- I have given up trying to predict or speak for S&P and Moody's. If we get pressure on our ratings, we will defend them, and that could lead to additional equity issuances for that purpose.

The other would be if we did some large unanticipated acquisition of assets in this market, which are -- some of which are currently available, and we might be interested in. If it were large enough, we would go to the market to help finance it. Now, having said that, I want to repeat that we don't have any particular project in mind that would require such a financing. And it is very likely that we will project-finance the LNG facilities, and possibly any other acquisitions that we would make that would be associated with off-take agreements with good credits, and so they would be financeable. All of this would contribute to our liquidity and enable us to meet our -- whatever construction obligations we had without additional stand alone equity financing.

Thank you.

Your next question comes from [David Thicken of Deep Haven].

Good afternoon. Couple of questions. Can you address the converts that come due next year? Exactly the mechanism of how it works as the stock price moves, and any plans you have to offset the dilution from it.

Well, you know, we're -- as long as the stock price is where it is or higher, we are effectively at the low end of the range of numbers of shares that would be issued. I thing at 20 -- between 25 and 31 it's about 24 million shares; above 31 or so it's 19 million shares. And so we would be at the least dilutive aspect of that offering, but, Neal, I don't know if you want to go into the mechanics of how the convert works.

Well, Steve's right, it's, rough numbers, 20 million shares would be issued. But you have to remember that these particular instruments are really misnamed as a convert, because what they do constitute are two instruments. One, is an obligation on the part of certain people to purchase equity, and then there's also a debt instrument. And there's part of the transaction in 2005, the debt side of this is remarketed and extended for a certain time period, and that's basically the way the mechanics work. In terms of what we might do with respect to these shares, no, we've taken these shares and the proceeds from these shares, and so forth, into account in our capital structure, and so forth, and I think you should see the equity that results from this transaction as part of our permanent capital structure.

Okay. And what month do they come due?

May.

May of '05.

All right. Can you also talk about levels of drip we should look at going forward?

Is that DRP?

Yeah.

Yeah, we're currently in new share offerings, and, of course, don't fully -- we don't fully control that but, you know, it's in the order of 50 to 60 million a year.

I think it's more.

Yeah, yeah, that's right.

Okay.

That's dollars.

Dollars, not --.

Right.

It would be awful big if it was shares.

All right. Jumping to the Section 42 tax credits, is it simply just a business choice to not continue to reload there, or has the ability to make those investments gone away?

Really kind of a combination of the two. Right now with the section 42 credits that we have, and 29s combined, we're in a position where we don't believe that we need to enter into new transactions at this point in time. As we get further out in the year, remembering the Section 29s have gone out to 2007, and the 42s extend beyond that. As we get closer to that time frame, we can look at our tax situation in the out years and decide if we need to put any more investments or tax leverage, things of that nature or not, but this part of the year we are not doing that.

The last question is: Is there anything in your existing guidance, now that we've got at least more clarity on the utilities, have you built anything in there on the cost containment side? I know that's been kind of talked about but not quantified in the past.

Yeah, it's always an opportunity, and I must say that, you know -- we're -- I think, as I would probably speak for virtually every company in our industry, that you're always looking at ways to be more efficient, and we will do that. But in our guidance for next year, there is no significance to a cost savings number, and neither is there any special tax adder other than the identified 29s and 42s.

Okay. Thank you.

Your next question comes from Tom O'Neill of Lehman Brothers.

Good morning. Steve, I was wondering, you referenced three years or more on the GRC settlements. I was just curious if the duration had been clarified. At one point I think it was three to four years.

Let me take that. This is Ed Guiles. Good morning, Tom. The second phase will really deal with the performance-[based] rate making mechanism and the attrition mechanism, including the term. Kind of our feeling right now, at least as we've had discussions in Phase I of this is, likely to be about a four-year term we think. We filed for five, but at least the discussions at this point have been in the four-year range.

Okay. So the timing of when Phase II would be clarified?

There is a schedule with respect to Phase II, and we think when you look at it, we would expect a proposed decision in about the September time frame when you go through, but let me just give you the current schedule. We have filed our testimony. We're in discovery now. Evidentiary hearings on Phase II will be in the June time frame, with briefs to be completed later on in the summer. We would expect a proposed decision in around the September time frame, and the commission to issue a final decision in the fourth quarter.

Okay. And then just a separate question. I haven't heard much about it recently, but if you could discuss your retail efforts in Texas through Solutions and whether we should view that as at all tied to your interest in the AP auction.

This is Don Felsinger. As you know, there's a very active retail market in [Ercott], and we acquired generation there over a year ago. And as we look forward at the retail opportunities, Texas is definitely something we have an interest in, both because of the market opportunities and because of the fact we have generation.

But bear in mind we sold the TNP plant forward for five years so that would not be available as a source for us until the expiration, if we allowed it to expire, of that contract. And we will not likely buy any other asset in Texas without a take-away agreement associated with it. So don't infer that we depend upon Solutions as a marketing agent for these hard assets without a credit worthy counterpart taking almost -- either all or almost all of the output of those facilities.

Okay. So that wouldn't be an acceptable take-away agreement in your mind?

To our own affiliate would not be.

Okay. Thank you.

Your next question comes from [David Grumhouse] of Copia Capital.

Good morning. Just following up a little bit on the PBRs. Can you review what the amount of PBRs earned in '03 was, what the current backlog is, and what you're sort of assuming, or what would be a good range to assume for your guidance for '04?

Yeah. Let us get the sheet out, and Frank Ault will give you that.

Basically, as it related to the current year, SDG&E had PBR awards of 8 million on the bottom line, and the gas company had some higher numbers because they got 29 million from their GCIM, which was really a two-year -- we got awards for two years, and they were really some of the higher gas-priced years. We would anticipate going forward that for the current year, that the GCIM for 2004 that would be recognized in earnings, and albeit earned last year, is going to be in the 5 to $6 million range, and that we should have PBRs at SDG&E about the same as this year because they were really earned in '03, but we got a commission decision to recognize them in earnings this year.

What Ed has talked about is the commission, perhaps, delaying any financial reward or penalty for the year 2004 which affects 2005 earnings. I did mention earlier that we also have demand-side management awards. They have been backlogged at the commission for a couple of years now. We are working with them to try to get those released, and we're hopeful we'll start seeing some of those come in in the current year. We have about 46 million or so of backlog there. I wouldn't anticipate all of that coming in at once, but we're going to try and see if we can get some of that released.

That's helpful. Thanks a lot.

Your next question comes from [Zack Schreiber of Ducane Capital].

Hey, Steve, it's [Zach] from [Ducane]. Congratulation on a good quarter.

Thank you.

Just a question on the balance sheet and financing. When you talk about your capital program over the course of this year, and you talk about your sort of noted interest in the AP assets, and then, you know, your comment that nothing on your horizon right now would trigger the need for a financing based on the current sort of regime with the rating agencies. I guess -- are we to assume, were you to win the AP assets under the current structure that you're working on, that that would not trigger equity as a specific question? Then as a follow-up, kind of how much sort of financing, incremental firepower do you have before you've got to come back to the market and kind of market test a new acquisition?

Well, let me -- on our interest in the AP auction, we're in that with a partner -- an equity partner, Riverstone, and that is -- so we are not -- we would do that in sort of a fund structure that we've talked to some of you about, or partnership structure.

Right.

And so the demand for capital for that auction is reduced by that partnership. In terms of -- I'm not quite sure how to answer your question.

I guess I just --

It's pretty hypothetical in terms of what we would do otherwise.

In terms of sort of excess balance sheet fire power before we run amuck of one of the covenants or the sort of ratios that the rating agencies --.

I wouldn't concern myself at all about that aspect. What we try to do is run a -- sort of a balanced operation in the sense that we want to maintain sufficient liquidity, and we spend a lot of time making sure that we have adequate liquidity to meet market changes that can occur as they may, for example, affect the trading company on margins, that it might, at that sort of at one defensive end of the spectrum to opportunities that would arise on the other. But I'm very satisfied that we don't -- we don't have any difficulty in meeting the present opportunities that we see in front of us with our own resources. And I would only caveat that by saying if some unanticipated event were to occur with respect to our credit ratings, or we were to have an opportunity for a very large transaction, that that would occasion, perhaps, the reference back to the equity markets, but not otherwise. And, Neal, maybe you want to add something to that.

Just keep in mind two points. One, from a credit perspective, we're in really good shape. The utilities generate cash, the resources business generates cash now that the construction is done. The trading company with it's short book generates cash, so we've got a lot of cash-generating businesses. The capital spending program this year is relatively modest, and what this translates into is a lot of financial flexibility, so we can deal with the, you know, little shifts in the capital budget without having any significant change to the fundamental ratios that we look at.

Great, guys. Thank you so much. Congratulation on a good quarter.

Thanks, [Zack].

Your next question comes from [Jay Hatfield of Zimmer Lucas].

Good morning. How are you doing?

Good morning.

Wanted to just follow up on a comment you made about the utilities contributing to raising of the bottom end of guidance for this year. I was wondering if you could give us any more detail about what elements of the rate case is giving rise to that. I was also curious as to whether the push-off in timing, relative to what you're expecting early last year is a positive for '04, in terms of the implementation of the rates.

I don't understand the last part of your comment.

I was saying, does it matter when the decision comes in terms of the timing, or does everything go back to the beginning of the year?

There's a reference back to the first of the year with interest in a balancing account so we're not concerned -- obviously, you like to get these things resolved, but we're not concerned about a regulatory lag issue in the rate case. I think, you know, if you go -- and Ed commented here, too -- you go back and look at our situation. We had principally at SDG&E, essentially five years of capital expenditure that had not been incorporated into rate base, so the biggest change is that the rate base will be trued up in this case, and we will recognize returns on that rate base, and which is -- you know, that is -- it's always a big worry you have in a rate case, are you going to get dinged on your rate base, and that is not the case here. The settlement, in general, for both companies is -- has been sufficient to raise our expectations over the sort of worst case, if you will, or a lower case that we might have shown last spring.

Great. Thank you very much.

Your next question comes from Theresa Ho with Solomon Brothers Asset Management.

Hi, Teresa.

Hi. Congratulations on a good end to -- excuse me -- a good way to finish the year. My question has to do with the LNG. With respect to your West Coast plant and the joint venture, I'm just wondering, what are the prospects for having a similar structure for your Cameron facility?

Maybe Don could comment on that. He did comment earlier perhaps, I don't know if you heard it, the -- obviously, we're -- nothing's obvious -- we're in discussion with a number of very large players in the -- in the business, in the production of LNG. And as Don pointed out, they are concerned if they're going to build, maybe on a ratio of five to eight to one upstream facilities, that when the gas gets to a terminal that it's properly handled, and there isn't a design flaw or something like that, and they see a way of assuring themselves that that's the case by having equity in the project. And as Don pointed out we're not -- we're not anxious to give up -- anxious to sell equity in these projects.

We think they're pretty good projects, and we'd like to make the maximum returns we that can on putting the money into them. So there's discussion with a number of these shippers about these issues, and I don't really have any prediction for you. We would try to be the builder-owner-operator with through-put arrangement and/or taking gas for resale on the market. But it may be that we reach some compromise position with some of these shippers. There's a lot of interest our Cameron facility. I mean, this is not -- we're very pleased with the amount of interest that's there.

Okay. Thank you very much.

Your next question comes from [Mark Lunenberg] of [inaudible] Capital.

Just a real quick clarification. When you mentioned an unlevered return at 12% on the LNG assets, I take that to be a pretax return similar to an EBIT number.

This is -- and Don keeps nudging me and saying 12 to 13. I don't want to sell it short. I know that's an after-tax unlevered number.

Okay. Thank you very much.

Ladies and gentlemen, we have reached the allotted time for questions and answers. I would now like to turn the conference back over to Dennis Arriola for closing remarks.

Well, thanks again for joining us today. There are a couple of upcoming Investor Relations activities I wanted to make you aware of. On March 11th, we're going to be hosting a tour of our trading facilities in Connecticut. We plan to limit the group size to provide ample time for participants. So if you're interested in attending, please RSVP with us as soon as possible by either calling Karen or myself or e-mailing us.

In addition, Steve and others have mentioned that we're going to have our Investor Relations -- our company analyst conference in June. The dates for that are June 2nd, 3rd, 4th, here in San Diego, so we will be sending out something soon. But if you can hold the dates, we'd appreciate it. As always, Karen and I are available after the call for your follow-up questions. And we appreciate you tuning in, and we'll talk to you soon. Thanks.

This concludes today's conference call. You may now disconnect.