美國南方電力 (SO) 2003 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Southern Company fourth quarter 2003 earnings conference call.

During the presentation, all participants will be in a listen-only mode. Afterwards we will conduct a question-and-answer session. At that time if you have a question, please press the 1 followed by the 4 on your telephone.

As a reminder this conference is being recorded today, Thursday, January 29, 2004.

I would now like to turn the conference over to Mr. Allen Franklin, Southern Company's Chief Executive Officer. Please go ahead, sir.

Thank you very much. And good afternoon and, of course, thank all of you for joining in today. I'm very pleased to be with you to give you our fourth quarter earnings call.

Joining me today as usual is Tom Fanning, our CFO. In addition today, David Ratcliffe is also joining Tom and me for the call. As you know, David will become CEO of Southern Company in July when I retire. During this transition period, one of the things David will be doing is meeting with lots of you folks, many of you know him, some don't, to get better acquainted with you.

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

As you can see from the material we released this morning, we had an outstanding quarter and a very strong year. In 2003, we delivered across the board on our financial, customer service, and operational goals. In all respects, 2003 was a very good year. In particular, we take pride in the fact that our earnings for 2003 are an all-time record for Southern Company. Including the period prior to the spinoff of Merit. Since the spin of Merit, in April of 2001, we've completely replaced the earnings that were associated with Merit. This achieved and, I believe, shows that our strategy has benefited our investors, and with our prices 15% below the national average, is also benefited our customers as well.

At this point, I will turn things over to Tom for a discussion of our financial highlights for the fourth quarter and for our guidance for earnings for 2004. Tom?

Thank you, Allen.

As you mentioned, we had better-than-expected results for the quarter and an outstanding year. Obviously, our results were well ahead of guidance. I will discuss the specific reasons why in a few minutes, but first, let's review our numbers compared to the fourth quarter of the prior year.

In the fourth quarter of 2003, we earned 17 cents a share. That's a decrease of 6 cents per share from the fourth quarter of 2002. The 2003 amount included a one-time after-tax expense of 5 cents a share, to record a regulatory liability at Mississippi Power related to plant Daniel. This expense offsets a one-time gain realized earlier in the year by Mississippi in conjunction with the settlement of a power sales contract with Dynegy. Excluding this charge, our fourth quarter results were 22 cents per share, or a decrease of a penny versus the fourth quarter of 2002.

For the full year, we earned $2.03 a share. That's up 17 cents a share above the results we reported for the year 2002. The $2.03 per share includes a positive 11 cents per share impact of the Dynegy settlement in the second quarter. As I mentioned earlier, the negative 5 cents per share impact from the regulatory action with Mississippi related to plant Daniel offset a portion of those effects. Excluding the net effect of the Dynegy settlement and the regulatory action in Mississippi, our earnings were $1.97 a share.

Now, let's turn to the major factors that drove our fourth quarter numbers compared to the same period in 2002. For consistency purposes, the numbers for the rest of my discussion will exclude the impact of the Dynegy settlement and the regulatory action in Mississippi.

First, I will cover the negative factors. Here is the break down. Normal weather across the southeast reduced earnings in our retail business by 3 cents a share. You may remember that we experienced abnormally cold weather in the fourth quarter of 2002. We had lower tax credits and additional expenses at the parent which negatively impacted our earnings in the fourth quarter by a total of 5 cents a share. The first was related to tax benefits which applied to dividends paid to employees on shares in their 401(k) savings plans. As you may recall, a tax law which took effect in 2002 allowed companies to receive a deduction for dividends paid to employees on shares in their savings plan. In 2002, we also had the benefit of taking an additional credit for the year 2001. Therefore, the credits in 2003 were 4 cents less than 2002. In addition, the redemption and open market purchases of trust preferred securities reduced our earnings by a penny a share. So the total negative effects impacted EPS by 8 cents per share.

Now, on the positive side, we had several factors that added to our earnings. Here is the break down of the positive factors. Continued customer growth and an improving economy added 2 cents a share to our earnings in the fourth quarter. Lower nonfuel O&M added a penny per share to our earnings during the fourth quarter. Job retraining tax credits also added a penny a share to our earnings. In addition, a transmission tariff settlement added 2 cents a share to our retail business in the fourth quarter. Finally, our Synfield business contributed a penny per share during this period.

So, the cumulative effect of these positive factors impacted EPS by 7 cents. Overall, excluding the regulatory action in Mississippi, our quarter came in at 22 cents compared to 23 cents in the fourth quarter of 2002.

Our earnings guidance for the fourth quarter was 16 cents a share. So we exceeded our guidance by 6 cents a share. Here is the breakdown. Our regulated retail business was 3 cents a share better than expected. As you recall, we were under for the year in O&M spending heading into the fourth quarter. Our guidance assumed we would make up part of the difference in the fourth quarter. However, our spending was right on budget for the fourth quarter. As we've said in the third quarter call, some of this O&M spending will be completed in 2004. Our competitive generation business was a penny a share better than expected, due primarily to asset optimization. Finally, the settlement of a contractual issue at Southern Telecom and better-than-expected performance at Southern GAS added 2 cents a share above guidance.

Now, before I discuss our earnings outlook for 2004, I would like to briefly review our progress on several other key indicators. The balance sheet. As you may recall, one of our important financial goals was to improve our balance sheet by raising our equity ratio to at least 38% by the end of 2003, taking into account imputed debt. I'm pleased to note that at the end of 2003, our equity ratio was 40%. For the next few years, we expect to maintain a common equity ratio of at least 40%, without issuing new shares.

Cash flow. Over the next three years, we expect cash flow to average about $3 billion per year. About half of that comes from margins and about half from depreciation. Dividends will require about $1.1 billion and capital expenditures related to the retail regulated business, about 2 billion. So as you can see, we anticipate our investments for the regulated retail business, and dividends can be funded with our cash flow from operations. Investments associated with our other businesses, primarily Southern Power, will require approximately $300 million per year over this time frame.

Now, I would like to turn to earnings guidance for 2004. Starting this year, we are providing guidance at a 5 cent range, which we believe is a more realistic projection of our business. While this is a departure from the point estimate we've used in the past, it still reflects what we view as the low-risk and low-volatility nature of our business. As well, our range of earnings guidance will continue to reflect our long-term growth objective of 5%.

For the full year 2003, we reported $2.03 per share. Which includes the Dynegy settlement and the regulatory action in Mississippi. Then, after adjusting for these two items, our earnings per share are $1.97 per share. The $1.97 per share included the effects of weather on our competitive generation business, excellent performance of our generating plants, and one-time items that, when netted against the 7 cent negative impact of weather on our retail business, add up to 10 cents a share.

Here is the specific break-out. The combined impact of mild weather, high gas prices, and the excellent performance of our generating fleet added approximately 7 cents per share to our earnings in 2003. These are clearly earnings from operations, but they may not be repeatable in their entirety in 2004.

Lower-than-expected operations and maintenance expenses added 3 cents per share to our earnings last year. In addition, the impact of several one-time items totaled 5 cents a share. The remaining 2 cents came from the settlements of the telecom contract and the transmission tariff we mentioned earlier.

So when we strip out the impact of weather, high gas prices on a competitive generation business, and the impact of one-time items, our earnings to establish a basis for growth, were $1.87 a share. The $1.87 per share represents growth of 6.9% over the comparable number in 2002.

In looking at our 2004 guidance, we are making several key assumptions about our business.

Sales growth. First, we were assuming energy sales growth at 2%. This sales growth assumes that we have some pickup in industrial sales and that customer growth is approximately 1.5%.

Competitive generation. As I mentioned earlier, our competitive generation business benefited from an unprecedented combination of excellent free operation, high gas prices and mild weather. Our 2004 budget does not anticipate a continuation of this unusual level of performance from our competitive generation business. We expect to earn approximately 26 cents per share from competitive generation in 2004. Of this amount, approximately 35 million dollars, or 5 cents a share, will be derived from asset optimization. Southern Power will not bring online any additional generation during 2004. Now, we do have an additional power sales contract which starts in June of this year with Georgia Power. This contract is for the Harris Two unit which was completed in 2003. Our next competitive generation facilities, the McIntosh unit, totaling 1240 megawatts will be added in 2005.

As a result of the financial and business assumptions I just discussed, and the impact of one-time items mentioned earlier, we are comfortable with a 2004 earnings estimate of between $1.94 and $1.99 per share. Again, our earnings guidance for this year is a range between $1.94 and $1.99 per share.

One last point on earnings guidance. For the first quarter of this year, our estimate is 34 cents a share. So overall, our earnings guidance for 2004 is driven by what we believe will be the strong performance of our regulated retail business, and a continued positive contribution from our competitive wholesale generation business. These projected results are consistent with our objective to provide 5% growth in earnings per share over the long-term. Now, it's important to remember that we are achieving these results with what we believe is one of the lowest risk profiles in the electric utility industry. Going forward, we will continue to emphasize a low risk approach in all of our businesses.

At this point, I will turn it back to Allen for a few closing remarks and an update on key regulatory issues.

Good. Thanks, Tom.

As you can see, we had a very strong year in 2003. And looking at 2004, I think we have the right plan in place, and I know we have the right team to execute it. So I believe we will have another positive year in 2004. Nearly all of our earnings are produced from franchise businesses and from our long-term wholesale power contracts.

Our strategy is very straightforward. It is a strategy that we believe will produce positive results in both positive and negative economic and energy market environments. We'll continue to focus on executing the basics of our business, providing value in a high standard of service for our customers and a solid investment for our shareholders. We plan to deliver in 2004, as we have year in and year out, what we view as the best risk-adjusted returns in our industry.

In looking at the broader industry front, I know that a number of you are interested in what is happening in the policy arena in Washington concerning, among other things, the Energy Bill, as well as activities at the FERC. While passage of the Energy Bill this year is still uncertain, we are continuing to work with the administration and with members of Congress on this very important piece of legislation.

As you probably recall, we announced last year, the suspension of plans to proceed with the establishment of the C Trans RTO here in the southeast. We reached a point where we would begin incurring significant additional expenses to proceed with C Trans. Since our state commissions were not supportive of the concept, and we didn't see this changing any time soon, we thought it was in the best interest of our customers and our investors that we not proceed further. The other C Transmission owners for their own reasons came to the same conclusion and work was suspended. We'll continue to work very closely with federal regulators and with our state public service commissions in our four states to ensure that discussions regarding these issues go forward, in a positive and constructive manner.

Finally, as you are aware, FERC is conducting a review of two wholesale contracts between Southern Power, our competitive generation subsidiary, and Georgia Power and Savannah Electric. The two contracts were filed with FERC in April of last year. FERC accepted the contracts for filing subject to refund pending a hearing. The competitive bidding for these power purchase agreements was conducted in a state-sanctioned process that selected the most cost effective, reliable supply option from the proposals that were received. This is not our conclusion, but the conclusion of the Georgia public service commission, which held hearings and issued an order to that effect. First precedent indicates that affiliate contracts selected in such a manner should be approved, and we believe that should be the ultimate outcome of this case. The administrative law judge decision is expected in the case sometime in the late spring or early summer. From a financial standpoint, these contracts take effect in June of '05, so they have no immediate impact on our earnings.

This concludes our formal remarks at this point. We'll be happy to answer any questions that any of you might have. Operator, we'd like now to have the first question.

Thank you. Ladies and gentlemen, if you'd like to register a question, please press the 1, followed by the 4 on your telephone. You will hear a three-tone prompt to acknowledge your request. If your question has been answered, and you would like to withdraw your registration, please press the 1 followed by the 3.

If are you using a speaker phone, please lift your hand set before entering your request. One moment, please, for the first question.

The first question is from the line of Carrie Stevens, Morgan Stanley. Please proceed with your question.

Hi guys, good afternoon.

Hi, Carrie.

A couple of questions. First, I wanted to just walk through the adjustment between the 197 and the 187.

Sure.

I wanted to make sure I got the buckets right. I think it was pretty clear the 7 cents, but then the 3-cent part, you mentioned something about telecom being in there and I just wasn't sure how that 3 cent kind of laid out.

We had -- let me just get there, too. Hold on a second. We had a settlement with a telecom contract that was worth about a cent. We will not repeat. And 2004, had to do with a difference of opinion in a contract matter between us and ISN.

Okay. And the other 2 cents related to lower-than-expected O&M?

Yeah, remember in the third quarter earnings call, we talked about how we were underrunning nonfuel O&M.

Yes.

And we were expecting to make that up in the fourth quarter. In fact, we didn't.

Okay.

And so what we will do is carry that amount over to 2004.

Perfect. Separate question,C&A for the year was down and I was just curious what was driving that.

G&A?

C & A.

Let's see. We had an amortization of a regulatory asset for some purchase power agreements at Georgia Power reduced by 49 million in 2003. And then we had -- you may remember in 2002, we had about a $16 million write-down for energy solutions. Those reductions were offset by some increases in depreciable plant. But that's why.

Okay. And then lastly, regarding competitive generation, do you have the split on this year's -- the 236 net income, what came from plants and what came from wholesale sales?

Yeah, sure. The way -- if the total number was 224, I kind of break it out like this. Long-term contracts provided about 152 of that. With what I would call power marketing, asset optimization, which includes opportunity sales, both Southern Power embedded, and some variable portions at Southern Power, amounting to $72 million.

Okay. And so then the guidance for next year would be that that $72 million drops to 35?

About that, that's right. That's exactly right.

Okay. Great. Thanks. That is really helpful.

Sure. Thank you. Appreciate you beng on.

No problem.

Thank you. Our next question is from the line of Jim von Riesemann, with J.P. Morgan. Please proceed with your question.

Hey, Tom. Hey, Allen.

How are you, Bub?

Doing pretty well. Just a couple of questions on the Georgia Power rate case.

Could you refresh our memories what the interest rate environment was the last several rate cases that you had there? And then the second follow-up question is can you again refresh our memories on the key differences between the regulated books, and the financial books and what the typical adjustments are there?

Yeah, interest rate environment is pretty interesting.

The -- what we've done is kind of evaluated 30-year treasuries over time, and I don't have today's quote, but roughly from the time that I guess when I was CFO there, about the last accounting order that was renewed, treasuries had only dropped about 40 basis points.

In that environment, we actually raised the ceiling of the range from 12 and a half to 12.95. And that interest rate environment is consistent also to the accounting order that was extended back in 1998. So I guess my summary of that is our current interest rate environment is a little bit lower, but not materially lower than the last two renewals, extensions of the accounting order.

With respect to your other question, all of our, you know, regulatory jurisdictions have little nuances. One of the rules of thumb you can kind of use in Georgia based on their regulatory structure is that corporate returns will be probably -- or let me say it this way. Retail returns will be somewhere in excess of 140 basis points lower than the corporate return.

We had not yet calculated Georgia's retail return to the for the end of 2003, but it will be somewhere in the low 12% range.

Okay. Thanks. Just one follow-up. How are they going to treat the Southern Power contracts that are sold back to Georgia Power in this rate case, do you think?

Those are purchased power agreements, and they're part of regular O&M for recovery in the rate case.

Okay. And on a year for year basis, right?

That's correct.

Great. Thank you.

Yes, sir.

Thank you. Our next question is from the line of Paul Patterson, Glenn rock associates. Please proceed with your question.

Good afternoon, guys.

Hey, Paul.

Just a little bit of clarity on the $35 million of asset optimization. What drove that? I'm sorry if I missed that. What was -- why is it going to go down?

Let's go back to '03. And we talked a lot about this. This is -- this is obviously a moving target for us.

What combined to produce the 72 million in '03 were a number of factors that may not be repeatable. We had very high gas prices. We had weather. And I would say the weather has kind of two elements to it. One is that it was relatively mild, which allowed us to have less demand on our system. And remember, that our native load customer, our retail customers, get the benefit of our regulated generating unit, the cheapest energy first. So to the extent demand was down, due to mild weather, we had more energy, generally fired by coal, available to offset the higher-priced gas energy.

Further, the other part of the weather, the other element, was the fact that it was very rainy, especially from kind of the June, July time frame. That caused us to have a significant, in fact, historically good performance out of our hydro unit. And of course, when you consider that our generating unit, all of them had record years, in fact, let me just kind of give a quick burst on that.

Our generating unit in the fossil hydro area had record low equivalent adage rate. 1.68%, all time record. All time record commercial availability. Our nuclear assets had record peak season E4 of 0.2%. Our goal typically is around 2 1/2. So nuclear, hydro, coal, all produced at record availability levels.

So you had excellent operations, you had mild weather that was not only temperature mild, but also wet, which enabled more hydro production, plus high gas prices. All those things worked together.

Now, in evaluating what the number may be for 2004, we just couldn't count on all of those factors coming together. We believe, taking into account more normal environments, we think that 35 million is a decent projection.

Okay. That makes sense.

Let me ask but the -- just to clarify Jim's previous question, you suggested that you probably would be in the low 12% in Georgia and I guess it's about 140 basis below that for the regulatory adjustments, so we're talking about somewhere in around the 11% range?

Yeah, maybe a little higher than that but I'm just using round numbers.

Okay. And then finally, when do you think we're going to get some clarity on this FERC review of the wholesale power contract?

The corporate -- let me make sure that I didn't misspeak here. The retail return -- the retail return at Georgia is 12. That formulation I just used would say that their corporate return was 13.4.

Okay. So -- okay, so in other words it was more like 12% that was earned at Georgia?

No, no, no. I'm just saying 140 basis points would essentially be added to the retail return. To get the corporate return.

The corporate return is traditionally about 140 basis points --

Higher than the retail return.

Than the retail return that's used in rate cases.

Okay. That's helpful. I appreciate that.

Okay. Good. Sorry about that.

No problem. And then finally, the time frame with respect to the FERC review of the wholesale power contract, I mean when do you think we will get some clarity as to what is actually going to happen there with FERC?

It is of course, the process has started already, and a good bit of activity on FERC on the quote McIntosh contract, and we would expect the judge to actually take this up seriously in March.

March 1.

Yeah, March 1. So you know, late spring, early summer, we should be able to have a good idea of where this is going.

Okay.

Let me say one other thing. I was thinking while were you asking the question, about the earnings, the 70-plus million dollars we earned from asset optimization. We spent a lot of time trying to project that for next year.

To put that in perspective, a couple of years, if you take two or three years of average earnings before 2003, it is more like $20 million. Maybe a little under $20 million. And then we had what appears to be this aberration in 2003 where the earnings more than tripled.

So if you look at the 35 million projection, based on a trend going back several years, it looks very reasonable. If you just consider the idea of '03, then it looks low, then we think it is a reasonable number.

Great. Thank you.

Thank you. Our next question is from the line of Jay Yanello, UBS. Please proceed with your question.

Good afternoon, first, a micro question and then some -- a macro question. Can we have any flavor on how the gas marketing performed in the quarter? My usual question.

You mean Southern GAS?

Yes.

Yeah. They actually did pretty well. Gosh, we've spoken about them, I guess, in every call now. At one time, we were looking for Southern GAS to have a worse than expected performance relative to last year. Last year they made about 2.5 million bucks, and one time we were saying that because of a variety of factors, they may hurt us by around negative two cents, that would be 14 million dollars or so. They ended the year, only losing, instead of 14 million, around 9.7 million or so. They made that up.

Remember, one of the issues involved with the deteriorated performance was their customer service systems, billing systems, all that sort of thing. We made tremendous improvements in that, and we did it better and cheaper than we thought we would.

The other major issue, you may remember, were essentially nonpaying customers, we've reduced that number down significantly. And the other issue was just kind of a loss of customers, given a tougher credit scoring system that we were using. Actually, the number of customers relative to where we thought we would end the year, which is like 175,000, when it is now about 192,000 or so, for the end of the year. So we had pretty good performance there.

Okay. Now, bigger ticket item.

I realize there is a pending changing of the guard and there is uncertainty with the RTO and uncertainty with energy legislation and all the various things that entails, but can you give us an idea, because of all those moving variables, does that mean M&A activity whether it be asset, material asset, or company, any considerations like that? Is it effectively off the table now for the company? I realize the usual answer is "Oh, we're always considering things," but can you help us think aloud of what Southern might do down the road in addition to its embedded earnings growth to kind of boost the growth of the company? Is that kind of discussion off the table now?

I would say it this way. We've said all along, our earnings target is 5%. And we believe as far out as we can see, that we can produce 5% organically without acquiring companies or merging or acquiring assets. So our growth is not depending on a M&A strategy, and we've also said, all along, we're opportunistic, but that any merger acquisition has to be truly accretive, and accrete in a hurry.

I think probably the only thing that has changed is some of the recent positions that the FERC is taking regarding the purchase of assets specifically, the old G and E case, and the -- they've taken similar positions in some other cases where they basically seem to be saying, if a company, especially a vertically integrated company, attempts to purchase generation, regardless of whether it is used to serve retail or wholesale markets, and that generation is in their area, in their region, then FERC is going to take a dim view of that, and almost defacto say there is a market power problem.

I think if that -- first of all, I think that's -- that is not good policy. And I'm hopeful that FERC will change its view on that. And we will certainly be talking with FERC as many others will, to try to explain why that -- that doesn't make sense.

But if that policy stays in place, I think the acquisition of assets within your region is going to be more difficult, regardless of what it is used for. And I think that hurts investor-owned companies that are trying to purchase lower cost assets, maybe even distressed assets and pass their benefits on to their retail customers. They'll be hurt. The retail customers will be hurt.

And I think the current owners of generation that would very much like to sell that generation will have a tougher market to sell into, because some of the major potential buyers, like us and others, would be frozen out of the market. So that's a change and it makes it tougher to make those kind of purchases, but our growth projections really don't depend on much of that.

And remember, too, our strategy is that we don't do merchant generation. That we don't put assets out there, and from generation standpoint, unless we have long-term bilaterally contracts with credit-worthy parties. Said another way, we believe the real asset in the transaction is the customer, not the generating unit. So that strategy point hasn't changed at all.

Okay. Thank you.

Sure.

Thank you. Our next question is from the line of Leslie Rich, Banc of America. Please proceed with your question.

Hi, Tom. I don't see a breakout for the products and services business in your segment breakout. Is that lumped into parent and other?

Yeah, Leslie, how are you?

Good, thanks.

Yeah, that's right. I think we chatted about this before. And it is just a slight nuance, I guess, really, since I've come into this job, but when I think about Southern, it's really two major businesses, it is the retail regulated business, and it's the competitive generation business. We are still committed to our products and services businesses, we're happy with what they deliver, but in terms of magnitude, it doesn't come close to the other two business units. So what we've done is put it in with parent and other.

Do you -- would you disclose what it actually earned or lost for the full year? I mean you said gas marketing loss is about 10 million.

Yeah, --

The majority of it.

Yeah, for the fourth quarter -- well, wait, for the year, let's just do the year. For the year, we earned right under 35 million bucks.

Okay. Great. And then separately, do you have any thoughts on -- FERC did a technical conference on supply margin assessment, and it seems that they're focusing a lot of their discussions on the west and the southeast, and just wondered if you had any thoughts on the likelihood of that going through in its current form, or sort of what the implications would be longer term for Southern.

I don't think I can really predict any better than probably you can where FERC will ultimately land on that issue.

In my judgment, and we've made numerous filings and contacts, and attended technical conferences with FERC, the logic behind that approach is just not valid. And one of the most obvious problems with it is attempting to test market power in the wholesale market. And in that test, it considers all generation, even generation that is fully committed to retail, even though it is not available to sell in the wholesale market. That test pretends that it is. And in essence, I think it creates market power problems using that erroneous test for almost any sizable company in any region.

So it just doesn't -- it make no, sir sense to me, and I -- I have to believe in the long-term FERC doesn't want to take that many players out of the market, that many really substantial real players that could produce in the market when the test is flawed.

That's -- that's my view. Again, where FERC will ultimately land on that issue, I couldn't predict.

Okay. Thank you.

Thanks, Leslie. We appreciate it.

Thank you. Our next question is from the line of Paul Ridzon, McDonald Investments. Please proceed with your question.

Good afternoon. I had a couple of questions.

The first was what was driving the deferral of the fourth quarter O&M into next year? Was there a good market for the units, and you didn't want to take them offline?

And then secondly, wondering if you have yet applied for license extensions at your new plants and if so, are we seeing the benefit in the D & A line yet?

And then thirdly, I think you had a previous goal of hitting 50 million of net income out of products and services. I'm wondering if kind of the new treatment of it, you know, if [inaudible] excuse me, suggests there is something different there.

And lastly you commented a little bit about it, but one of your neighbors seems to be having a generation yard sale.

[ Laughter ]

Wondering to what extent are you going to be kicking tires.

I will answer the easy one and Tom can figure out how to answer the harder ones, if I can remember all of those.

I think in the case of a yard sale on generation, we have pretty much answered that. We've said that we're interested in generating plants, only if we have a market, a nonmarket under a long-term contract for a preponderance of the output. So you're not likely to see us scooping up speculative plants unless we know where to place that capacity because it doesn't fit our low risk profile.

On the question of the deferral of O&M, that came about primarily because, as we went into the fourth quarter, it was a pretty mild quarter. The first couple of months was very mild, we didn't stress the units all that much, our revenue was a little bit lower than we would have for normal weather. And it simply made sense.

We had the opportunity, because the units hadn't been stressed quite as much, plus the revenue made it advantageous, the lower revenue advantageous to defer some of that maintenance into next year. It made sense from an operating and financial standpoint, so we did that.

What was your other questions?

Relicensing, I got that.

Let's see. Hatch has been -- is done essentially, and then just kind of round numbers, in 2002, that represented a reduction in depreciation of about $9 million at Georgia Power, okay? Vogel it is too new to see any kind of near-term activity. We expect to file for extension of the licenses in Farley in 2004.

And how long does that process usually take?

It hedge -- I don't recall exactly when we filed it, but it doesn't take that long. And I think for the companies that have filed, assuming there is nothing unusual, it has been fairly routine. Especially if there is no opposition. Which we haven't had any material opposition. So I don't recall that it is -- you know, it hasn't been that long. They have been fairly routine.

Okay. Thank you very much.

Oh, one more, products and services.

Oh, right.

Yeah, 50 million. What we have said in the past, remains true, when we put that goal out originally, we put forth a very stretched goal of $50 million from that segment. Our planning case is financially only calls for a $35 million achievement. So we feel like essentially, according to our financial plans, we've achieved what we wanted to do.

And I think in all those areas -- well, first of all, Tom said it right, it is not very material, it certainly short term, so we don't want to focus too much effort and attention on it.

But at the same time, in all of those areas, we still feel good about where we are. The Southern Link, the telecommunication business, really provides telecommunication for our companies as well as in a niche market here in the southeast for other businesses. We're very happy with that. It is profitable.

Southern GAS is just getting off the ground good. We did find that the customers we bought out of this New Power bankruptcy situation weren't nearly as good a customers as we thought. It was a much higher percentage of nonpaying customers that than we estimated, so that was a little bit of a set-back, but they -- I think they've got that company rolling in the right direction now. And new products and services was profitable this year, and we expect it to be profitable in the future.

So don't read anything into it, de-emphasizing the numbers, it's just the realization the numbers are not that large, but nothing has changed.

Okay. Fair enough. Thanks.

Thank you. Appreciate it.

Thank you. Our next question comes from the line of Shar Kahn, Foresight Investments. Please proceed with your question.

Good afternoon, and congratulations on a great year. I just wanted to clarify, Tom, you mentioned for the competitive generation business, the earnings from long-term contracts were about 152 million, if I heard it right.

That's right.

And if I'm right, some of your plants entered in in June of last year, and as you mentioned, the Georgia Power contract picks up this year. So what are you forecasting for that portion for '04?

I think it would be a half year, and I think -- and I'm just going round numbers off the top of my head, somebody can correct me here, it's like -- I'm going to say it is going to matter about a half a year, $5 million or something like that. Maybe for a full year. Something like that.

So the long-term contract portion of --

I'm not sure we -- is your question what compares to the $155 million for next year? Or for this year?

Yeah, what does that compare to 2004?

Yeah, it is about the same.

It is about the same?

Yeah.

Okay. Okay. I appreciate it. Thanks.

Sure, yeah, absolutely.

Thank you. Our next question is from the line of Matthew Neil, Reed Global Advisers. Please proceed with your question.

Hi, good afternoon.

Good afternoon.

Could you guys please provide the year-end balance for notes payable, CMLTD, and long-term debt?

Sure.

I can't, but Tom can, and he is rigorously digging through his numbers.

Okay. Here we go. Notes payable is $568 million. You wanted long-term debt?

Yup.

That would be $10 million -- $10.2 billion, sorry 10.2 billion.

What about current maturities?

Current maturity, 752 million.

Great. Thanks a lot of appreciate it.

Yes, sir.

Thank you. Our next question is from the line of Dan Jenkins, State of Wisconsin Investment Board. Please proceed with your question.

Hi.

Hey, Dan.

Just a couple of things. I was kind of curious what you're projecting your financing needs for 2004, given, you know, CAPEX and maturities and so forth?

All right. Just a second. I will get my hands on that. Just a second. Wait a minute. I will get it for you in two seconds. Here we go.

Okay. 2004, we are projecting to have new financings of about $230 million. We -- if total -- if interest rates kind of remain where they are now, we may have refunding opportunities of around $400 million. There are about $739 million in maturities.

So if you add all that together, you get about $1.4 billion. Now, we just completed some financings that we think is very attractive rates in Georgia, 200 million trust preferred, 100 million senior note and 100 million senior note refunding that will save Georgia about 5 million bucks this year. So we've already done some of that.

How much did you do, did you say?

We did about $400 million total. Already in January.

Okay. I was also wondering what your cash flow from operations was for '03 and '02.

Well, what we said, it is generally speaking about $3 billion, about half from margins and about half from depreciation.

So what in '03, it was 3 billion, and it was the same in '02?

Yeah, probably a little bit less, but yeah, a little bit less in the same proportions.

Okay. And I -- just kind of on your merchant construction, you know, given the fact that, you know, a lot of people are saying there's a lot of overcapacity in the southeast, if you could kind of explain why you continue to build in that environment?

Well, now, remember, we don't do merchant generation. We -- merchant generation means you build the assets, and settle the demographics of a market. We do right the opposite of that. That is, the asset is really the contract with the customer, not the generating plant. So we don't build plant until we got a contract.

The contract that we're currently building towards is the -- both Georgia Power and Savannah Electric and power contracts that commence June of 2005. That'd be the McIntosh 10 and 11 units.

Given that there is overcapacity wouldn't it make more sense to maybe buy instead of build?

Well, we went through a solicitation process in Georgia where any and all comers bid into it. It is a state-sanctioned process. In my opinion, it is very transparent. And those were the best bids.

If you mean, given that after that additional capacity comes up for sale, we do look at that.

Until recently, and maybe we're not even seeing as much price decline as we would expect recently, but until recently, the prices being offered for this excess capacity, much of it under construction, was not that attractive. In many cases, it was in the wrong location.

But we -- we have continuously looked at supply these power sales contracts by purchasing capacity, as opposed to to building these units, but it's not -- these are not fungible-type assets. They have to be at the right place. They have to be where they're needed. They have to be where there is transmission available.

We look at that continuously. If we ever find a case where it makes more sense to buy and not finish a plant, we would certainly do that.

And one final point, there those contracts were signed in 2001. And so that preceded, to some extent, a lot of the glut coming to bear into the market.

Okay. Thank you.

Thank you. Ladies and gentlemen, as a reminder, to register for an audio question, please press the 1, followed by the 4 on your telephone. Our next question is from the line of Danielle Sites, Maxcore Financial. Please proceed with your question.

Hello. I'm wondering, I guess the answer is no, but I just had to answer -- ask the question, is there -- are there any other contracts that are you understand might be recognized by FERC in the existing contracts, or do you feel that those totally are secured?

I don't want to offer a legal opinion, but I don't -- there is no indication, I don't think there is any reason to believe at all that there would be any other contracts that FERC would look at related to the issues raised in McIntosh, in the McIntosh case. So I can just give you sort of my personal opinion. I see no indication that there is any interest in looking at existing contracts.

Okay. I just decided to ask. Thanks a lot.

Thanks, Danielle.

Thank you. Our next question is from the line of Vic Cadeian, Deutsche Asset Management. Please proceed with your question.

Yes, thank you. Tom, just looking at the sources of cash flow, your CAPEX program, for the next three years, you have $6 billion coming up on the other side of the business, so what kind of rate-based growth will that be, because have you 3 billion dollars of depreciation, I guess.

The rate-based growth, based on our CAPEX, --

And depreciation.

Yeah, and depreciation, so --

I mean I'm looking at rate-based growth in terms of, is it growing at 2%, or 3%, what is the growth of rate-base?

Could I get back to you on that? Because it really depends -- could we just get back to you on that one.

Sure.

I would want to give you a good calculation there.

Yeah, because I'm trying to understand this earnings growth of 5%, is coming from based on rate-based growth or improvement in margins or what is the source of earnings per share growth rate of 5%.

Well, certainly, some of it is rate-based growth. Some of it is assuming that we continue to get, as we have, constructive regulatory environment, which will permit us to earn fair return, et cetera. But we can -- we can shape that up and get that back to you.

That would be good. And one follow-up question on this. I assume that in this sources of cash flow where you show dividend increases built into that dividend column of 3.2 billion.

Right.

So would we be seeing now that we are getting close to 70% payout ratio that the dividend might grow in line with earnings?

Well, of course what we've said, and as we put in place a target payout ratio of 70%, and as we have the past two years -- in fact, let me just back up and say that our former goal was 70-75%, payout ratio. Once we entered that range, we increased dividends per share at roughly half the rate of growth of earnings per share. At least rate of growth of our target.

The past two years has been 3 cents each year. And that was about 2.2% growth.

Until -- so I would assume that until we reach the 70% target on a sustained basis, we would be looking at the same sort of strategy as what we would recommend to the board of directors for ultimate approval. Once we reached 70% below on a sustained basis, would we consider increasing dividends per share, at the normal earnings per share growth rate.

And if you look at our projected payout ratio for the next couple of years, it is actually a bit -- a little above 70%. So we're sort of on that -- on that ragged edge, and we're going to be there a little while as far as hitting our 70% number. And we did -- if you will recall, after the spin of Merit, when we were at about 83% payout ratio, after the spin, we set a 70-75% target, and I told you then that I really preferred to be at the lower end of that range, not the upper end.

That's where we are now. And I think when we were convinced we are going to stay there and maybe get at 70 or below, we will make some recommendations to the board, and of course they will make the ultimate determination. But we're -- you know, we are at 70% now, but we're going to drift a little above that with our current budget for the next couple of years.

Okay. Thank you so much.

All right. Thank you.

Thank you. And there are no further audio questions at this time.

Terrific. Well, great.

Again, we all appreciate you tuning in. Appreciate your interest in the company. If you need anything else, or any time, now or any other time, if have you questions, give us a call and we'll track down the right people to answer those questions.

And again, thank you for your interest, and we're terminating the call. Thank you very much.

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