美國南方電力 (SO) 2003 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the third-quarter 2003 earnings conference call. (OPERATOR INSTRUCTIONS). I would now like to turn the conference over to Allen Franklin, Chairman and Chief Executive Officer.

Thank you, operator and thank all of you for joining the Southern Company third quarter earnings call. As usual, I am very pleased to be with you for the earnings call, and as usual, joining me today is Thomas Fanning, our Chief Financial Officer.

Let me remind you as usual that we will be making forward-looking statements in addition to providing historical information. As you know, there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements, including those matters discussed and our form 10-K and other SEC filings.

As you can see from the earnings materials we released this morning, we had a very solid quarter. Our businesses are performing well. We are on track to exceed our financial targets for the year.

At this point, I will turn things over to Thomas Fanningfor a discussion of our financial highlights for the third quarter and our earnings guidance for the rest of this year.

We are very pleased with our performance in the third quarter. Obviously our results were ahead of guidance. I will review the specific reasons why in a few minutes, but first let's discuss our numbers compared to third quarter actuals a year ago. We earned 85 cents a share in the third quarter of this year. This compares with 84 cents a share in the third quarter a year ago for an increase of 1 penny a share. For the first nine months of this year, our earnings are $1.75 per share, excluding the Dynergy settlement. That is an increase of 12 cents a share over the earnings we reported for the first nine months of 2002.

Here is the breakdown of our earnings for the third quarter compared with the same period last year. First, the negative factors. Mild weather across the Southeast, particularly in July, reduced earnings in our retail business by 7 cents a share. The additional shares outstanding had a negative impact of 2 cents a share.

Now for the breakdown of the positive factors. The retail regulated retail business was able to largely offset the negative weather impacts with three positive factors. They were customer growth, reduced nonfuel O&M and taxes. Customer growth added 3 cents a share to our earnings. The reduction in nonfuel O&M was lower than the same period last year by 2 cents a share. In addition, the impact of manufacturing tax and job retraining credits added a penny a share to our earnings.

Reduced cost of the parent company and other business units, primarily from lower interest expenses, also added a penny a share to earnings in the third quarter. Our competitive generation business added 3 cents a share to our earnings in the third quarter. This contribution was driven largely by a combination of higher gas prices and mild weather, which allowed us to optimize our coal-fired units, plus the margins we received from additional units we brought online at Southern Power. So overall our quarter came in at 85 cents a share compared to 84 cents a share in the same period last year. Our earnings guidance for the third quarter was 77 cents a share, so we exceeded our guidance by 8 cents a share.

Here is the breakdown. Our retail business was 3 cents per share above guidance. When we gave guidance for the third quarter last July, we were experiencing historically mild summer weather which obviously shaped our projections. However, as it turned out, the weather ended up being slightly better than we thought it would. So the 3 cents above guidance in the retail business was comprised of a penny a share from marginally better than projected weather and 2 cents from lower operations and maintenance expenses. Our competitive generation business added a total of 4 cents a share to our earnings above guidance. The breakdown includes a 3 cents per share contribution from opportunities sales and a penny a share from tax credits in the state of Georgia.

As we have seen throughout the year, we were able to sell coal-fired energy into the wholesale market where gas set the clearing price for electricity. There are two reasons why we were able to do this. First, it is important to remember that this quarter's mild weather helped to reduce demand by our retail customers. Of course, our retail customers always receive the benefit of the lowest cost retail generation available. To the extent that additional low-cost capacity, primarily coal-fired, was available, we were able to sell the energy into the wholesale market.

The second contributing factor to this better-than-expected wholesale performance was the excellent operating performance of our generating unit. Our fossil fleet set a record this year with an all-time low peak period equivalent forced outage rate of 1.68 percent. Further, you may recall that part of the weather story for this year was a historically wet summer. As a result, our Hydro production for the quarter was 76 percent above budget.

Finally, our nuclear units had an outstanding quarter, showing production levels approximately 2.5 percent above budget. As you can see, the outstanding performance of our generating fleet contributed significantly to our ability to sell energy profitably into the wholesale market in the Southeast.

In concluding the discussion of factors that caused us to exceed guidance, we had an additional penny per share at the parent company from the resolution of outstanding tax issues in the state of Alabama related to the 1999 tax year. So overall we were 8 cents a share over guidance for the quarter.

Let us now turn to our earnings guidance for the fourth quarter and the remainder of the year. Our guidance on the call last quarter of $1.86 implied that we expected to earn 19 cents a share in the fourth quarter of this year. In looking at our nonfuel O&M for the fourth quarter, we are projecting to catchup much of our spending for the balance of the year. Thus far in 2003, we have underspent our planned O&M initiatives by approximately 4 cents a share. We are projecting to makeup approximately 3 cents per share of the 4 cents per share variance in the fourth quarter. Therefore, the 19 cents projection should be adjusted downward by 3 cents, equaling 16 cents per share for the quarter.

So with a fourth quarter earnings estimate of 16 cents a share, our guidance for the year is now $1.91, an increase of 5 cents per share over our previous guidance. Again, our new guidance for the year is $1.91 per share.

At this point, I will turn things back over to Allen for his closing remarks.

Thank you, John. In looking at the broader industry front, I know a number of you are following the progress of the energy bill which is being debated in Congress. The bill currently before a conference committee is the plus major energy legislation since 1992. This is the third straight year that Congress has attempted to pass a national energy bill, and it is a major legislative priority of the Bush administration.

While the proposed bill has several major provision, the most significant for Southern Company is clearly the electricity toggle. With any electricity toggle, the most important issues for us are those related to transmission, specifically standard market design, the establishment of regional transmission organization, native load priority and the use of the transmission system and funding for new transmissions.

As most of you know, the FERC has attempted to mandate a standard market design. States in the Southeast and the West have opposed this effort by FERC. An agreement was reached in the definitive version of the energy bill to impose a three-year delay on FERC's SMB proposal. The agreement would allow those desiring to move forward on a voluntary basis to form RTOs that would prohibit FERC for mandating RTOs for three years. We support this language on RTO and SMB as due state regulators, governors and others in the Southeast and the West.

Related to the SMB delay language, there are provisions authorizing state regulators and utilities under their jurisdiction to continue to allow native load customer priority use of the transmission system. In the SMB proposed rules, FERC determined that under its equal access mandate native load priority was discriminatory. It was on this basis that FERC asserted jurisdiction over bundled retail transmission. The native load provision of the bill would make it clear that such use of transmission is not discriminatory. The significance of this provision is that it will continue our ability to provide priority service to our native load customers both wholesale and retail at the lowest cost and the highest degree of reliability.

The other major transmission issue concerns the funding for new transmissions. As you know, it has been our view from the outset that this debate that the cause for new transmissions should not be socialized. In other words, retail customers should not have to pay an unnecessary portion of the costs for transmissions built to wield power for long distance wholesale transactions. We believe that costs should be assigned to those who stand to benefit from this transaction, most commonly known as participant funding.

At present, both the House and Senate version of the energy bill would repeal the Public Utility Holding Company Act. While the holding company act has not proven to be a major barrier for us at Southern Company, we believe that the legislation is no longer relevant in today's more competitive electric utility industry and should, in fact, be abolished.

While there are many other elements to the energy bill, the ones I have just described are the key issues for Southern. At this present time, we believe the prospects for passage of an energy bill, which includes an electricity title in this session of Congress, are quite good.

This concludes our formal comments. At this point in time, we will be happy to answer any questions you might have. Operator, can we have the first question, please?

(OPERATOR INSTRUCTIONS). Paul Patterson, Glen Rock Associates.

I noticed that there was a reduction of depreciation. I was wondering if you could describe what that was and what the outlook for 2004 and beyond is with depreciation?

Okay. Let us see. We are scratching our heads right now to make sure we understand that.

I think it's really not related to depreciation. It is more amortization of its regulatory assets for PPAs at Georgia Power. That was reduced by 12 million for the third quarter. Further, we had a reduction due to debt retirement of $6 million in August of 2002. So that has offset the normal increase in depreciation resulting from additional plant.

So we should -- going forward, we should expect a normal increase of what you have seen with property taxes kind of increase?

Yes.

The second question I have is on the syn fuel increase and outlook for 2004, do you guys have an idea about what you think it will be? Do you see it contributing considerably more in '04?

No. My sense is it is going to stay pretty flat at around 7 cents.

Okay. Thanks a lot.

Fritz Van Karp (ph), Sage Asset Management.

I was wondering if you could give a quick update of pending rate cases and similar type regulatory issues?

Sure. As you probably know, Georgia Power Company is almost in the final year of a three-year rate plan; we call it an accounting order, which is an agreement between the state of Georgia and the Georgia Power Company to have a certain set of rates fixed for a certain period of time. In this case, three years. That is the third three-year plan they have had. They have all worked out quite well.

At the end of that three-year plan, or at least six months before the end of the three-year plan, Georgia Power is required to file another "rate case" or another three-year plan or maybe even a longer plan. This three-year plan ends at the end of next year, which means in the middle of the summer I think about July the 1st of next year, Georgia Power must file a new rate plan or a rate case. The expectation is the Company will file some kind of rate plan similar to what we have had in the past. We are in the process now obviously of developing that plan, developing the strategy, developing the case, and, again, expect to file that about July the 1st with a decision before the end of next year.

Of course, the effective date would be January 1st, '05.

That is the major rate case issue at the state level for us.

So at this point, you are expecting to file something in the 5-ish neighborhood, and it is too early to tell what the chances are? Is that the correct way to look at it?

I did not hear the first part of the question. What was the first part of the question?

You expect to file something with a rate structure similar to what exists now flat with what is now? Is it too early to tell, or can you have some read on what the chances are for that becoming the final outcome?

It would be too early to say what we need or what we would ask or exactly what kind of plan we would file. Our history has been to try to have multi-year agreements. I think if that is possible, we would still like that because it gives us stability. The level of rates, we still need to do some work before we determine that.

I think all I can say about the likelihood of the outcome is to look at history. We have had three of these three-year plans. They have all been most acceptable to both the company and the state where there is no reason to think that we would not do well again. The same factors that helped us before, the highest customer satisfaction in the country by independent surveys, some of the lowest cost in the country. Georgia Power is about 20 percent below the national average and a very reliable system. If you put all those together and look at the history, it would indicate that we have done pretty well in the past, and there is no reason we won't do well this time. But you cannot predict obviously the outcome of regulatory proceeding.

If I could add just one more point. I think one of the major issues in terms of cost structure for the filing will likely be expenditures associated with transmission and distribution. I think given what we have seen throughout the Midwest and the Northeast, I think as a backdrop, we have always had good experience, but I think the prudence of investing in reliability of our transmission distribution system makes a lot of sense. So we don't expect that part to be controversial.

Thank you.

Jim von Riesemann, J.P. Morgan.

I am doing well. Can you reconcile your 5 percent earnings growth forecast going forward off this revised base of $1.91 in light of a consensus number of $1.94 for 2004? Is it off of this $1.91 base?

Jim, we have not yet put in place what our base is going to be. What we want to do is evaluate the $1.91 in terms of what we believe are continuing factors and then we will do that. But we will do that at the end of the fourth-quarter call. The long-term, we have not changed one bit the long-term strategy of delivering 5 percent earnings per share growth. That is the objective.

Despite the fact that you have these off system sales, which are variable to begin with, you still think you can grow 5 percent otherwise?

Yes.

Again, what Thomas is saying, when we say 5 percent, that is generically year after year over a long period of time. We have got to do a lot of thinking and looking at what the appropriate base is for this year. So don't read too much in.

We are not trying to send you any kind of a signal for the number next year. We need to look at what happened this year -- how much of it is continuing, how much of it is onetime, what can we count on? So the long-term 5 percent is still good, but we are really not prepared to say anymore about next year than that.

The second question is on the energy bill. Can you talk a little bit about some of the provisions that are buried in there regarding the tax issues and maybe some of the syn fuel credit?

Well, I can talk about the tax issues. I don't think syn fuel is really an issue with the energy bill at least at this point. There are a couple of provisions that we think may be an energy bill.

As you probably know, there have been weeks of intense discussion between the House and the Senate, primarily by Chairman Dominic and Chairman Tossain (ph) Post who have been the prime negotiators. A lot of that has been done just for those two folks in with their staffs. We understand that they now have completed the electricity title. It is in a lockbox basically. That is my word, not theirs. But they are finished with it, and there are some ongoing tax incentives related to ethanol and some other issues that are holding the bill up. Supposedly the electricity title is finished.

We cannot know for certain what is in it. What has been proposed and seemed to have received a good deal of support was tax incentives related to transmission, where they were shortening substantially the depreciation rate for transmission to encourage investment, and they were also making the tax effect of selling transmission much more favorable to a sale to encourage independent ownership of transmission. Those are the two primary tax issues related to transmission.

I have some stuff here. This is an estimate based on some drafts that were floated around. I want to underscore what Alan is saying. We don't know what is in the lockbox at this point. But one of the provisions relating to the tax depreciation of transmission was to change the current 20 year MACRS schedule to a 15 year schedule. We think for us it would have a present value worth over a 23-year timeframe of about $36 million. On a gross dollar basis over the next four years, it would be just under $25 million. There again, that is an estimate. We don't know what's in the final bill.

Did you say 36 and 25 in the numbers?

That is correct. 36 is the present number. I have 24.7, but I should not be that precise. Under 25 nominal dollars between '04 and '07.

I think we should really caveat that for you because there has been a lot of discussion of only providing those additional benefits to companies that put their transmission in an RTO, so we don't know we would qualify from that standpoint. There has been a lot of discussion about the timing and went to start those benefits because of the budget scoring problem. So all of that is up in the air, but if it happens and we are eligible, it would be significant.

Jay Yanello, UBS.

Good afternoon. I realize it is not a large part of the business, but can we have an update on Southern Company GAS please?

Yes. You are right. It's not a large part of the business, but it is a part we are interested in. As you remember, when we bought the customers that later became Southern Company GAS, we did it for two reasons. One is because we thought we could ultimately make money -- not a lot because it's not a big investment. The other was to learn how to operate in a competitive retail energy business.

We are learning a lot. It has been quite in experience here in Georgia for all the gas marketers, and you may have seen recently another one has folded their tent and left the state. So there are not many left.

I think we made, what, $2.5 million last year, I believe that is about right. This year we had continuing problems with the customer service using the outsourcing entities that we were using, the systems we were using. We were not able to do as good a job on billing as we are used to in our electric business. Our ability to get bad customers, that is customers who don't pay cutoff, was not as quick as it should be. Just our customer service was not up to Southern standards.

We thought long and hard and finally bit the bullet and said if we're going to stay in this business, which we are, we have got to improve customer service. As a result, we spent a good deal of money this year changing, basically getting rid of a group of vendors. We did not bring it in-house, but we brought it to one vendor, Accenture, who is doing a good job. Getting these software systems fixed and getting these bad customers off. As a result of that, I don't know what we have said, but we will lose a few million dollars this year, maybe $10 or $12 million. You may have an actual number.

Yes. Sure. What we provided in our last conversation was a 2 cent looking number. Actually since the end of the third quarter, our guys have been doing pretty well over there. They seem to be beating to some degree what we projected for the year.

For example, we expected a net loss in the third quarter of $7.2 million. It actually came in at about 5.3 million. I know we talked about this notion of reducing the number of bad customers. At the end of June, we had a little over 20,000 what we call bad customers; these are people who had not paid over 60 days. That number has been reduced now to about 11,200. We hope to get that number down further by the end of the year. We are happy with the progress we are making, and we continue to focus on it.

Of course, we bought these customers out of Bankruptcy Court, and when you buy something out of bankruptcy, you buy it as it is and where it is. Where it was was that we had a lot more customers that had not paid in 60 days and some that had never paid, while new power was operating that gas business. So it took us awhile to figure out that some of the customers we bought were not customers at all; they were just taking gas but not paying. And we have had to fix that, and we've gotten very aggressive in getting that fixed. So maybe as Thomas said, maybe 1.5 cent to a 2 cent loss this year. Should probably be a little bit negative next year, and then getting back into the black pretty quickly.

I still feel good about it. I think for all the same strategic reasons it is important for us to be in there taking our lumps and learning how to operate in the retail energy business, especially right here in Georgia. Because I don't think anytime soon, but someday, that may come in very handy on the electric side.

Paul Ridzon, McDonald Investments.

Can you talk about what you have seen thus far in the quarter with regards to selling excess capacity, getting the strong gas pricing, and whether we could see some upside there or not?

Yes. Sure. Basically we had another good quarter. Let me give you be general ballpark numbers, and I think we can guide in as much detail as you want. You know, the notion is that you want to have a margin to sell into and then you want to have product to sell. So what we had was a margin we think between kind of -- gas continued to set the kind of regional wholesale price. That was, again, around $40 per megawatt hour.

In terms of our ability to sell into that, our (inaudible) was something like $30 on the average. So there was about a $10 margin between largely coal-fired energy and gas-fired energy to sell into. I mentioned before that we had a really good performance by our operational people. I think sometimes we get in these financial conversations; we take that for granted. But to the extent that we were able to run our nuclear plant, to the extent that our coal was available, and, of course, we had good rainfall; therefore, our Hydro was up. We had product to sell. So I think that is kind of -- we had about 3 million megawatt hours when you consider all of those factors of product to be able to sell into that market.

Did that answer your question? Did you want to follow on there?

Of what you have seen so far in the fourth quarter, you mentioned the $40 per megawatt hour clearing pricing in your local market, where does that stand now? I assume you've gotten even more free capacity given that we are in the summer months, so we are in even cooler weather.

You have pluses and minuses. Let me go through some of that. The fourth quarter is traditionally a time to take plants off-line and do maintenance outages. So that will negatively impact, and I already adjusted for this, but our nuclear plants, if I just did not adjust the numbers, actually were up 5 percent to budget.

But part of that production level was due to a timing of an outage we had originally scheduled for the third-quarter associated with Plant Vogel we moved into the fourth quarter. So to some extent, just because of regular maintenance outages, we will have less available. Further, you have got to make a projection, and we are not very good at it, of gas prices. So we will see about that and what happens to demand in our retail business units. Obviously our retail customers get the cheapest energy first from the regulated assets that we have. So we will see.

Also, it may be that if weather is down, it maybe from an electricity standpoint, gas may not be on the margin. We saw that actually happen for a brief period in May this year. So there are a lot of factors that have to come together.

Is gas currently on the margin?

Yes.

Carrie Stevens, Morgan Stanley.

I was hoping maybe you could update us on the split of net income earned from the wholesale sales year-to-date versus net income earned from the powerplants at Southern Power for the gas-fired generation? I think you gave that on the second-quarter call.

Let's see. Just a second. If I see this right, at Southern Power, we made for the three months ended September about $40 million. For total wholesale, it would be about $79 million, so the difference is that wholesale associated with the retail slide. The other way to think about it is if you consider our total wholesale number of 79.7 million, about half is associated with retail, half is associated with Southern Power.

Is that the trend for the year to see it half and half?

I think that is a good rule of thumb.

Obviously you guys have targeted earning about 200 billion in net income from this business by '05, and you have hit that number already this year. Is there any way we can think of how you may reset that expectation?

Well, you know that is a great point. We have looked at the number ourselves. Remember we are showing year-to-date September from the competitive wholesale businesses. In fact, let us to exclude mark-to-market about $195 million. 199 -- 198, if you include mark-to-market, so it is somewhere in there. We essentially achieved the goal by the third quarter.

We do expect to exceed the goal going into the fourth quarter. The implication I think would be at $1.91, we originally projected about 25 cents a share coming from competitive wholesale generation. That number will be more like 31 cents a share by the end of the year.

Now the question I think that everybody I think puzzles about, and we do to and we will be focusing on this when we give our guidance for next year's earnings, is how much of that overperformance is repeatable? Remember we have had many vagaries this year that have come together to give us an awfully good environment -- weather, rainfall, demand, gas prices. So we will have to reassess and figure out how to roll that in. We will certainly discuss that in January when we talk about our 2004 guidance.

I think we can say that just the contract part of the business is at or above where we expected. Even without the opportunity sales, we were going to be ahead of schedule. It is a question of how far ahead of schedule and how much of this opportunity sale net income can we count on going forward.

Referring to Georgia Power, I was hoping you could remind us of whether or not the rate (technical difficulty) historical or (inaudible) last year?

It is a forward-looking test year.

Certainly Georgia Power is certainly going to file it on a forward-looking test year. I think the commission has some latitude and often looks at both historical and forward-looking periods. But I think certainly Georgia Power will grow as the minimum filed on a forward-looking test year and make the case that that is the appropriate period to consider for setting rates.

Do you have the ROE impact and the --

You were cutting out. We did not hear the question.

The ROE entity at the end of September, the latest 12 months ROE?

For Georgia Power?

Yes.

No. We don't have that in front of us.

I will follow-up off-line then.

Paul Fremont, Jefferies.

Thank you very much. Really two questions. The first relates to your construction schedule in '05. That 1240 megawatts looks like it excludes Franklin III (ph). If we could get an update on the status of Franklin III and whether it is likely to move forward.

The second is my recollection of the projected earnings per share breakouts that you gave in the second quarter looked different than what appears on page five of your release. If I look at the major differences, is it looks like the regulated retail is 3 cents higher, title generation is a penny lower, and the products and services are 2 cents lower than the breakouts that you gave second quarter, and can we get an update of this now that you have increased guidance for the year?

Let me talk about Franklin III, and we will look at the numbers. The Franklin III, we have postponed the completion date of Franklin III. We have not set a new date. We are doing some additional work to make sure that we leave the site in a state that it could be resurrected fairly quickly. But with the settlement with Dynergy, the economics delay Franklin III. We have a number of potential places to put Franklin III down the road. Some contracts they already have in place and some that we anticipate. So it is delayed definitely for more than a year or two. But we will see when we crank it back up. But you're right; it has been delayed.

Let me, if I could, give you -- this will be posted here after the call is made -- but let me give you the earnings per share projection that we have by the segment of our business associated with the $1.91 guidance now. Here we go.

Regulated infrastructure will be $1.54. Competitive generation is 31 cents. I think I mentioned that. Products and services will remain at 02, so 2 cents a share. Syn fuel will remain at 7 cents a share. The leasing business will remain at 4 cents a share. And then holding company will be -7 cents a share. So I think $1.54, 31, 2, 7, 4 and -7 adds up to $1.91.

And I guess the changes in the press release versus the second quarter, for instance the change in outlook -- do some of these basically reflect the changing guidance that you provided today?

Yes.

Okay. Thank you very much.

Greg Shultz, FAC Capital.

Two questions, please. The weather versus normal?

It was -7 cents for the quarter.

What about for the nine months?

I have got that. Hang on. For the nine months -- yes, it is negative -- let me go through that. (multiple speakers). The 7 was year-over-year. 2002 was actually +1. That is how you get to - 7. Versus normal weather, it was -6. Is that clear?

For the quarter?

Yes, sir. Year-to-date is -7 versus normal.

Okay. So going into next year, I know you guys have not started talking about all the different aspects that could affect the base, but obviously that 7 cents would be a big thing that would affect the base.

That is right.

Offsetting that, you had this quarter 2 cents of tax credits, and I think, if I remember right, you add another 2 last quarter? Would those come out of that base do you think rolling into next year?

Yes. But listen -- let us go back, and we will give you the appropriate guidance at the end of this year. We will go through all that and explain our logic. Let's not try and prejudge where we're going to end up.

Is my 4 cent number right in terms of the tax credits? (multiple speakers) Then I will apply my own judgment on that.

Yes, it is.

One other point. Keep in mind that weather was very mild this third quarter, which that among other things allowed us to defer some O&M of about 4 cents. So you have to take into account that we were able to offset the weather by a significant amount of O&M reduction. So you have to be careful how you use that weather number.

And let me add another caveat in our course of meteorology here. When we talk about weather, I do it myself. I always forget to talk about the rainfall we had. Because certainly as we had an increase in Hydro, that certainly helped to improve our performance this year. So when you talk about weather, I think everybody goes right to temperature, but there are other affects we've got to take into account.

Steve Fleishman, Merrill Lynch.

I guess with respect to this issue of a retail sale versus an opportunity or wholesale sale, with the wholesale sale as you have said in the $40 area -- I am sure it has been give or take a little bit -- do you make more money on a wholesale sale than you would have if you had normal weather and had more retail sales or is it relatively similar?

It depends on -- that is not a simple question to answer. It depends on who the customer is, what time of year it is. For example, in the summer, you typically have higher rates than you do in other times of the year, different customers and different pricing. That is just not a simple answer. We would be glad to explore that class by class with you.

I would also say that for a one degree drop in temperature, I certainly think the experienced this year has been that you don't make up the lost revenue from retail and wholesale sales. You certainly don't make up the net income piece. But it is a significant offset. That is not saying anything about the relative margins of the sales. But when you take into account the margins and the volume, I think our experience is we makeup a significant amount of the net income loss from mild weather on the retail side rather than wholesale. But I don't know -- maybe half or actually more than half.

A ballpark number would be -- if you wanted to use a ballpark number, but know that as soon as you use it you will be wrong -- it will be about two-thirds. Remember the other major story here in our earnings for this quarter was cost control and also good strong customer growth.

Okay. Secondly, you gave us this number of 198 million of year-to-date competitive generation. I think you said that is roughly 50/50 between the two?

Yes. Sure.

Okay. Finally, maybe this is for Allen in general, that the company has been able to make the 5 percent growth or better since this plan was put in place, and a lot of that uptick was driven by the competitive generation. When you look out over the next, let's three year period, five-year period, it almost seems like something some other segment has really got to pick up the slack to keep that up. I guess I would like to get some sense of how you will look at the next three to five year period in keeping up this kind of growth, even off of some kind of adjusted base of this year.

I think for the next two or three years, the current wholesale contracts, assuming that we continue to get good performance on retail, that the existing contracts -- the contracts that are in place are going to generate significant growth for the wholesale piece. So the 5 percent -- again, assuming everything works -- looks very clear for the next two or three years, which is a good ways to look out and be able to see high confidence levels for growth.

I think beyond that, I think the wholesale piece can still be a major driver. Keep in mind that we have generated most of this growth in the wholesale business in a very small geographic area. The majority of the sales we have made in the wholesale business have been to especially -- or they have only have to our own operating companies. We are beginning to have more and more success with co-ops and municipals and entities outside of our footprint but still in the Southeast. So I think we have a number of years to go before the market share, the penetration of market, really are a significant limiting factor on growth of the wholesale business.

Let me just refresh your memory because I think Allen is exactly right. I just want to reinforce something he said. In the roughly the past year or so, we have signed three new deals -- Piedmont Municipal Power Association; an entity called AMC 11 (ph), which is essentially 11 cooperative companies that were formally part of Oglethorpe (ph); and NCMPA1 (ph), North Carolina Municipal Power Association. These are three new contracts that we have signed during the past year. Those don't have specific assets tied to them just yet; rather they are being served as a portfolio. But I think the fact we're able to execute these new sales is pretty positive.

Just to give you a sense of what we are seeing in the market here, just as investors are interested in companies with some stability and sticking power, we are certainly seeing that in the wholesale market as well especially for these long-term contracts. But the co-ops and municipals are really looking for companies that are going to be there, that have a balance sheet, that can live up to their end of the deal. So even though there is more generating capacity than is needed here in the Southeast, the same factors that have made us attractive investments have made us attractive counterparties in these long-term contracts. So it is really a pretty good time for us, and I don't see that been a limiting factor for a good while.

(OPERATOR INSTRUCTIONS). Scott Engstrom, Hamilton Investment Management.

Hello? I must be a real utility geek because I find this conversation about weather and its on retail and also earnings to be quite fascinating. I was wondering if you could entertain one more question on the subject. When you get to the 7 cent figure you're using, then given all the various factors you have discussed, is that mainly a regression equation where you take cooling degree days and look historically at how that has impacted demand? And you are estimating at 7 cents? How do you actually come up with that 7 cents given all the factors?

You hit the nail on the head. The period of time we use is about the past 15 years. Of course, that is arbitrary. We have devaluated using periods shorter and longer, but that is what we do.

So it does not take into effect weather or any of the other factors that you have talked about?

It is purely weather statistically.

Weather relates to cool degree days.

Yes. In this case or heating degree days or whatever is relevant.

Is there a way for us to think about the trade-off between a high-priced wholesale market in a low usage environment or below normal as a trade-off in a low price wholesale market with a high demand period? Is there a way or some sort of sensitivity for us to think about as those factors change?

Allen and I have been chatting about that. We have drawn three-dimensional curves. It is something we are very interested in evaluating. So far, we have not been able to develop a very clear relationship other than to say directionally what happens. Because of all the moving pieces, it is a pretty complex equation. (multiple speakers).

Keep in mind, the price of gas is a major component. I think the only data point we have is this year with the gas at about $5.00. It is not on the margin all the time. It's on the margin a fair amount of time. So gas prices at $5 and weather throughout the year milder than normal and the summer, drastically milder than normal.

We were able to makeup the 60 to 70 percent of our lost net income from retail. That is just one data point. To be perfectly honest, this phenomenon is new. We can develop probably mathematical models that in theory would give us a good answer whether in practice they do or not. But the combination of events with very high gas prices and low demand is sort of a new combination.

We have not daily, but weekly discussions with Southern Power about what we can really expect. There is a lot of pressure on them to try to predict their number accurately. We are all trying and struggling with that. It's a very happy situation, but we are still working on how to make that prediction.

How about if we just looked at the two extremes? I think you might have been referring to an analogy. Would you say it is a more profitable situation to be in a low gas, i.e. low wholesale price environment with high usage, would be more profitable than a high wholesale high gas market and lower usage?

We would say yes. I think simply saying that if you look at the wholesale business, most of our net income is not sensitive to demand. It is contract business that we get paid our profit and our fixed costs whether the units are run or not. So our contract business is not demand sensitive. Our retail business is highly demand sensitive. We already know that for a degree that we lose on the wholesale side, we make up like Thomas said about two-thirds, maybe 75 percent that we lose on the retail side we make up on the wholesale side. So I think you can deduce from that.

Still hot weather is good for us regardless of what the gas prices are. But if you are going to have mild weather, it sure is nice to have high gas prices to go with it.

I just want to underscore the costs around that two-thirds because it depends upon a lot of factors. There could be some ratio to use.

You can keep in mind for a long time to come, Southern Company is going to be coal- based, nuclear-based company even though we have built a good bit of gas. So anything that makes wholesale prices high compared to our coal prices, which tend to be stable, is all the margin going to help us. So high gas prices, which affect the wholesale market but don't affect our base load cost much, is going to increase the margin.

Let me give everybody for reference our budgeted energy for this year was coal 72 percent, nuclear 16 percent, Hydro 3, and then gas made up the balance 9.

Jessica Rutledge, Lazard.

Could you give us a quick update on your cash flow and balance sheet metrics?

Cash flow and what?

Balance sheet?

Cash flow, yes. It is pretty much the same as it has been so far. Basically what we project is from a cash flow standpoint we expect to have about $3 billion a year on the average operating cash flow. About half of that comes for depreciation; about half of that comes from margin. We have CapEx. It ranges from the low 2 billions to about 2.5 million over the '04 to maybe '03 to '07 timeframe. So after CapEx, we are positive cash about 800 million to a 500 million. We certainly view our dividends as a fixed obligation. That is about a billion a year, so cash after dividends, you know is somewhere in the kind of 0 to 200 million negative to about 500 million negative.

Now we certainly are looking very hard at those numbers. We would love to be more cash flow positive or less cash flow negative, but that is something we continue to pay attention to.

Any details on cash flow for this quarter particularly?

No. That is just consistent with what you would expect based on what I told you. Thanks for calling.

Paul Ridzon.

Earlier you mentioned that there is about 4 cents of deferred O&M. 3 cents of that is caught up in the third quarter, so basically next year we will have a 1 cent catchup. Is that the right way to think about it?

Perhaps. We will see. That would be one way to think about it.

I think that is consistent with our thinking. It is not that precise. The (inaudible) companies have done a very good job in this milder period, and you have more flexibility to defer O&M in a mild period. They have done a great job I think deferring O&M out of the peak period. And precisely I could not say for certain they will spend every penny of it. They may or may not. They believe they will. The operating people and the operating companies certainly think that they will and they need to.

They are rescheduling and scheduling those projects now. I think most of that will get done in the fourth quarter. I think it's very reasonable to expect some, not a lot, some to spillover into next year. But the truth is when we start the budgeting process next year, getting our earnings number will drive a lot of things, including our O&M expenditure. So that will be part of the equation when we do the budget for next year.

Let's make sure just to give you a context, our non-fuel O&M is around 3 billion a year, and when you think about a cent, that is maybe pretax worth $1 million. So that is the magnitude of difference you're talking about there. So little differences can cause big swings.

Would it be reasonable to expect that for reliability purposes you will have caught up by the end of the first quarter of '04?

I would say it would be too precise. As Thomas said, 10 million or 20 million out of 3 billion, there would not be any near-term reliability effect from moving those kind of numbers around a few quarters. So I think you're getting to a level of precision beyond what exists in the way we operate the system.

Everyone, I appreciate your questions. We are running late. We have time for one more question. Certainly if there are more questions beyond this, we would love to entertain them. Of course, you can call me or Glen Kundert or Jimmy Stewart whenever.

(OPERATOR INSTRUCTIONS). Gwen Chen, ABN AMRO.

I was just wondering how you do finance that 200 million shortfall in cash flow?

Well, we sell a variety of securities over the year. You know, in fact, we believe this company trades is much on its low-risk posture as we do its return profile. So really we take goals in place for equity ratio following the spend to achieve an equity ratio of 38 percent. In fact, Allen and I chatted this summer, and in fact, we decided to move that equity ratio up. We will end the year at around 40 percent.

One of the things that we continue to chat about is even thinking about taking it North in the years ahead. We will see. So as a result, we just think about the sale of new shares out of our plans, and we get about $400 million a year. So what we expect right now is to turn off the issuance of new shares in November. So in the foreseeable future, if we just left equity ratio at 40 percent, there would be no issuance of new shares going forward. We would finance it either through retained earnings or debt securities or something like that. Certainly we anticipate a rate change at Georgia. So there are a variety of mechanisms in the years ahead.

I guess what I was asking about was after you ran through the 3 billion operating cash flow and what it covers. It sounded like there was another 200 million that needed to be funded from (inaudible)?

Well, it would be kind of as I described. It would be debt securities. It may involve changes to rates in the companies going forward. Remember, our revenues are a little over 10 billion for the year.

Okay. Thank you very much.

Well, we really do appreciate your questions. If you have anymore, certainly get in contact with Glen and I.

Yes, it has been great questions. Obviously we had another good quarter. We look forward to having just as positive a conversation with you at the end of the year. Thanks a lot for your interest in Southern Company.

Ladies and gentlemen, that does conclude your conference call for today. We thank you for your participation and ask that you please disconnect your lines.