Southern Co (SOMN) 2006 Q4 法說會逐字稿

Good afternoon. My name is Casey, and I will be your conference operator today. At this time, I would like to welcome everyone to the Southern Company fourth-quarter 2006 earnings conference call, hosted by David Ratcliffe, President and Chief Executive Officer, and Tom Fanning, Chief Financial Officer. (OPERATOR INSTRUCTIONS).

Thank you. Mr. Ratcliffe, you may begin your conference.

Thank you, Casey. Good afternoon, and thank all of you for joining us. I am pleased to be with you for our fourth-quarter earnings call. Joining me today is Tom Fanning, our Chief Financial Officer.

Let me remind you that we will be making forward-looking statements today in addition to providing historical information. There are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements, including those discussed in our Form 10-K and subsequent SEC filings.

As you can see from the materials we released this morning, we had a good quarter and another very strong year. Before Tom reviews the results of 2006, I would like to take a few minutes to cover what our priorities will be in 2007 and where we will focus our energies.

First will be the continued commitment to our core principles of high reliability, customer satisfaction and low price -- key elements in what we frequently refer to as the circle of life. Capital investments to help ensure reliability, a constant focus on customer service, and our low fuel cost mix are foundations of our commitment to our customers.

We will focus on the efficient execution and management of our major construction program, which for the next three years, includes $3.8 billion for transmission and distribution projects and approximately $4.6 billion for environmental controls to further reduce emissions and help insure the continued availability of our low-cost generation fleet.

Our secondary focus is maintaining constructive external relationships, both at the state and federal levels. The rate case to be filed by Georgia Power later this year will be a priority for us. In addition, participation in the national debate over how to responsibly balance the nation's environmental and economic policies with its energy needs will continue to be very high on our agenda.

Our third major priority for 2007 is ensuring continued development within our leadership team. Southern Company is fortunate to have a deep bench. That includes some of the best and most capable talent in the industry.

My goal is to ensure that we continue to develop the next generation of managers. As part of that effort and by way of preview, we plan for Kim Greene, our Senior Vice President of Finance, to handle the review of our financial performance for Tom in April.

At this point, I will now turn the call over to Tom Fanning, our Chief Financial Officer, who will review our financial performance for 2006 and provide earnings guidance for 2007.

Thank you, David. As you mentioned, we had a very strong quarter and another year of solid financial performance. In the fourth quarter of 2006, we reported $0.25 a share; that is an increase of $0.04 a share from the fourth quarter of 2005. Excluding our synthetic fuel investments, we earned $0.25 a share in the fourth quarter, an increase of $0.05 a share from the fourth quarter of 2005.

For the full year, we reported $2.12 a share. That is a decrease of $0.02 a share over the prior year. This change is driven by a $0.09 per share reduction in synfuel earnings when compared to 2005. Excluding our synfuel investment, our earnings for the full year are $2.10 per share, an increase of $0.07 a share over the prior year.

Now, let's turn to the major factors that drove our numbers for the full year compared with 2005, excluding synfuels. First, I will cover the negative factors.

Here is the breakdown. Non-fuel O&M and depreciation and amortization reduced our earnings by $0.05 a share in 2006 compared with 2005. This is due primarily to recovery of prior-year storm and environmental costs and the expensing of stock options. You may recall that we expensed stock options for the first time in 2006, which had a negative impact of $0.02 a share.

Higher interest expenses, primarily related to overall rate base growth for our traditional operating companies, reduced our earnings by $0.06 a share compared with the prior year.

Finally, parent company and other expenses reduced our earnings by $0.04 a share in 2006 compared with 2005. This reduction was due primarily to the defeasance of trust preferred securities and interest costs at the parent. So total negative factors reduced our earnings by $0.15 a share in 2006.

Now, let's turn to the positive factors that drove our earnings. The regulatory recovery of environmental and storm costs and continued customer growth added $0.14 a share to our earnings in 2006 compared to 2005. We continued to see strong inward migration, adding more than 70,000 additional customers in 2006, an increase of 1.7% over 2005. And indications show that this trend will continue. In addition, Georgia and Florida are among the leading states nationally in attracting new residents.

The impact of warmer weather in 2006 compared with normal weather in 2005 added $0.03 a share to our earnings for the full year in 2006. Our competitive generation business added $0.05 a share to our earnings in 2006 compared with the prior year. This increase was due primarily to additional wholesale contacts and contributions from our recent acquisition. So total positive factors added $0.22 a share, a net increase of $0.07 a share excluding synfuels.

So overall, we increased -- we exceeded our guidance range of $2.03 to $2.08 per share, and our year came in at $2.10 compared with $2.03 in 2005 -- again, excluding synfuels.

Before we turn to guidance for 2007, I would like to update you on several key business and financial issues. As you may have seen in the business outlook section of the earnings package, we have released an updated capital budget for 2007 through 2009. We are entering a period of significant capital investment in scrubbers, SCRs and baghouses at our larger coal-fired units. During the three-year period through 2009, we are planning to invest approximately $4.6 billion in these and other environmental controls.

As an additional part of our environmental commitment, Georgia Power is also planning to replace a coal-fired facility near Atlanta with a new gas-fired combined cycle unit. This unit would be built in conjunction with two additional units being proposed to serve growing territorial demand. The proposals will be submitted with the Company's 2007 integrated resource plan, which is expected to be filed with the Georgia Public Service Commission on January 31. If approved, the first unit could be online late 2010 and the entire project completed by 2012.

Another significant area of capital investment continues to be transmission and distribution, with a projected expenditure of $3.8 billion for the three-year period. This investment will help ensure continued reliability and to meet customer growth in the region.

Turning now to our competitive generation business, I would like to discuss the new organizational structure we will be putting into place and the outlook for this business going forward. As you are aware, last year, the Federal Energy Regulatory Commission issued an order proposing a modified settlement regarding the Southern Company Intercompany Interchange Contract, or IIC. The order reaffirmed Southern Power's participation in the Southern Company power pool.

Consistent with the settlement agreement, we will be providing more separation between Southern Power and the wholesale generation business within our operating Company. This physical separation, which includes separate staffs for planning and business development functions, will add costs of approximately $9 million per year over the next three years.

Prior to the settlement order from FERC, our competitive generation business was comprised of two distinct segments that were managed as one organization. These two segments are the wholesale contracts that reside within our traditional operating companies, what we call embedded wholesale, plus Southern Power.

As a result of the proposed FERC agreement, we are separating these two segments. The embedded wholesale income will be recorded with our traditional operating companies. Our traditional operating companies and Southern Power will serve as our two distinct major businesses.

Southern Power Company, which was established in 2001, owns 6698 megawatts and manages another 2880 megawatts. Approximately 82% of the megawatts owned by Southern Power are covered by contracts through 2015. Southern Power has 25 customers, including municipals, co-ops, and investor-owned utilities.

As you know, we had a goal to earn $300 million in net income for our competitive generation business by 2007. And as you saw from the results we issued today, we earned $305 million from this business in 2006, achieving the goal a year ahead of schedule.

For 2006, Southern Power earned approximately $125 million. For 2007, we project that Southern Power will earn about $115 million. And given the current state of the wholesale market in the Southeast, our financial plan reflects Southern Power earnings at or slightly above this level through 2009.

Now as we have said in past calls, in 2010 and beyond, the earnings for Southern Power will be bolstered by already-signed contracts for capacity from our Rowan, DeSoto, Franklin and Oleander facilities. And as in prior years, Southern Power's capital budget for the next three years includes placeholders for new projects.

Let's turn now to our earnings guidance for 2007. Our long-standing objective is to grow our EPS guidance range of 4 to 6%, consistent with our long-term goal of 5% average annual growth in earnings per share. To support this goal, our financial plan assumes a corporate return on average common equity of 13.5% for our traditional operating companies, which was both the target and the actual result for 2006. Added to the earnings of our traditional operating companies would be the net income contribution from Southern Power.

Excluding earnings from synfuel, our guidance range for 2007 is $2.13 to $2.18 per share. This is consistent with growing our 2006 range of $2.03 to $2.08 per share by our target of 5%. It is also consistent with the current financial plans for our traditional operating companies and Southern Power.

Including earnings from synfuel, our estimated earnings per share range in 2007 is $2.18 to $2.25 per share. As we have stated in previous calls, we have greatly reduced our downside exposure related to synthetic fuel tax credit. This expected incremental contribution of $0.05 to $0.07 per share is evidence of these accomplishments.

To emphasize, our earnings guidance for 2007 is consistent with our 5% growth plan. Without synfuel, we project our earnings per share to be between $2.13 and $2.18 per share.

Finally, to complete our discussion of earnings per share for this year, our estimate for the first quarter of 2007 is $0.33 per share, excluding synfuel. Including synfuel, our estimate is $0.34 per share.

At this point, I will turn the call back to David for his closing remarks.

As you've just heard, our businesses are performing well. Population and economy here in the Southeast continue to expand. As a result, we look forward to another excellent year. The priorities I have outlined for 2007 include effectively managing and executing our large complex capital program, maintaining constructive external relationships at the state and federal level, and ensuring that Southern Company continues to develop the next generation of leadership.

They are all directly fundamental to our number one priority. That priority is to provide our customers outstanding reliability, superior customer service at low prices and our shareholders with attractive risk-adjusted returns.

At this point, Tom and I will be happy to take any questions you might have. And Casey, we will now take the first question.

(OPERATOR INSTRUCTIONS). Paul Ridzon, KeyBanc.

A few questions. The first is year-over-year, O&M is only up $9 million. Is that really just a function of '05 being extraordinary because of storms?

That has an influence. I think also in '05, we had more outages associated with our fossil/hydro fleet. That will have an impact.

But otherwise, yes. We had, I think, effective cost control, especially in the retail side of the business this year. So we were able to do that and produce outstanding operational performance.

Just a clarification on separating Southern Power for the FERC settlement. Costs are going to go up $9 million a year. Is that $9 million this year an incremental $9 million for $18 million total up to $27 million? Or is it just $9 million, $9 million and $9 million?

$9 million, $9 million and $9 million.

It is --

Actually, it is a little uneven. But yes, that is about the right way to do it.

And then just as you prepare to file in Georgia with a higher CapEx budget, have you maybe seen some on the shortsighted knee-jerk reaction that might upset the balance -- the circle of life?

No, I don't think so. Remember, when you think about the issues that we face as a system, we see tremendous economic growth in our area. We see this influx of customers and the attractive growth rates therefore. So as a result, T&D continues to go up. If you look at distribution particularly, it reflects this increased growth in customers.

When you think about the kinds of expenses that we are associating with our generating fleet, for those of you that don't follow us all the time, remember that about 70% of our energy is generated by coal, about 16% by nuclear. In a normal year, 4% or so with hydro. Of course this year, we generated less than that, because we had less rainfall. The balance normally around 10% being gas.

When you think about the environmental expenses that are required, not only is that a good thing to do for the environment, but it also protects and enhances the fleet that enabled our customers to enjoy rates that are significantly below national averages.

So I think having told the story that way, while there are always -- being mindful of keeping rates as low as we can, we think these expenses not only are justified, they are attractive.

Nathan Judge, Atlantic Equity.

I just wanted to follow up on the embedded portion of the history of the Southern Power business that is being split up. I guess if we deduce that that means it is $180 million, what would that tend to do over the next several years? What do you expect to get from the embedded portion of that business over the next several years?

Let me just clarify one thing. If you just did the math, you would come up with 180. Actually, the number was about 171. The other nine -- you may remember we had a very small fuel services business associated with an outside customer that we actually ran on their fuel procurement program for them. That will essentially cease this year.

So when you think about it, embedded wholesale 171 this year, we think that is actually going to go down a bit, maybe in the 155 range or so. The reason for that largely is going to be tied up with the allocation of allowance credits. Allowance credits in '06 were significantly higher than we had projected them to be for '07. That really accounts for the difference.

Just a broader question on allocating resources and looking at what your service territory needs for the future. There has been a wave of coal builds and I know you've had varied opinions on it. But if you look out and look at your opportunities for -- you were mentioning a new coal -- gas plant. How does that fit into your new potential for growth?

And if you could just update us on the nuclear options and where we stand with that? And when you probably will see some type of approval, will it be in this Georgia rate case, or will it be something separate.

Let me let David speak about the future of nuclear. Let me comment kind of quickly on what we see about the rollout of next generation.

When we think about new generation capacity, we kind of see it in three phases anyway. At least between now and the end of the decade, you are really still in the realm of gas-fired capacity. Starting kind of in the 2010, 2011 timeframe until maybe 2015, 2016, you'll start to see the advent of new coal.

Now in our opinion, we are very excited about our integrated coal gasification technology that we developed jointly with Kellogg, Brown, Root. So we think technologies like that, which will be directed at preserving this nation's most plentiful source of energy, coal, will still be important, along with gas. Kind of in the 2015 to 2016 timeframe and beyond, now I think we will start to see the advent of the new nuclear industry in this country.

Let me just add to that. I think the first indication of the details of that will occur with the filing as we referenced earlier of the integrated resource planning process -- certification process in the state of Georgia at the end of this month. That will give you an indication.

It looks like the predominance of the needs that we have over the next 10 years will occur first in Georgia. So you will get a sense that, as Tom said, the plan will anticipate additional gas capacity that we talked about in the modification of a site here in the Atlanta area.

And then, where you have made clear our intent to try to add additional nuclear capacity in the 2015, 2016 timeframe at our Vogtle facility around Augusta, Georgia, but we have filed the early site permit with the NRC. It has been well-received, and has been designated as complete, meaning that they are now moving to the stage of analyzing it and we are in the process of holding the required hearings.

So all of that is moving forward. We are also moving forward with the vendor, Westinghouse-Toshiba, to negotiate terms and conditions that would allow us to achieve a 2015/2016 kind of startup.

So we are moving with deliberate steps towards adding new nuclear capacity. I think that is being well-received as part of the ongoing energy supply for the country.

Would you need an explicit approval by the Georgia Commission, or will an implicit approval of a rate case or some type of plan be sufficient when you start building on that?

No, the certification process is designed to give an explicit -- a very definitive certification of a particular technology choice and particular construction program associated with that.

Yes, in fact, there was legislation passed in the state of Georgia that put in place that structure that takes away a lot of the uncertainty that many utilities face in adding supply resources to meet demand requirements.

I would just remind you, too, that last year the Georgia Public Service Commission passed an accounting order which allowed the Georgia Power subsidiary to recover the preliminary costs associated with filing and doing all the preliminary work to make the filings associated with moving in this direction.

The amount there was $51 million -- was what they approved.

Greg Gordon, Citigroup.

I know that you set your earnings guidance range off of prior-year range, which you did as you usually do, come in slightly above the high end of that. I know some of that (technical difficulty). But are you adjusting for back (technical difficulty) weather? What are the adjustments to get you back (technical difficulty) that range from once you've set your new guidance?

When we think about -- let me make sure I understand you. You want to know the underlying assumption as far as --

Why aren't we growing 5% off of what we actually earned this year?

Okay. Because we think -- when we consider the long-term business model for Southern Company, we are generating earnings per share growth out of the retail businesses of about 4% a year. And we add to that about 1% a year out of competitive gen. So that gets us our 5% year-over-year.

We always do that on the basis of normal weather. We tend to take rather conservative estimates in terms of what we call our energy trading business. Remember, the way we are structured here in the Southeast is that given our low-cost energy structure -- given predominantly coal, nuclear and hydro -- our retail customers get the benefit of that first. So if there's anything left over, we are able to sell that into the wholesale market. We typically take a relatively conservative view as to what the exposure is there.

The other thing that we highlighted in the opening remarks was essentially, it is easy to take a simple formulation of how to project Southern's earnings. And that is if you think about the traditional operating companies, earning an ROE at the corporate level of about 13.5, and then you add the projection of Southern Power, you come up and then divide through by the number of shares, you will come up with an earnings per share estimate for the system.

Okay. You guys have been absent from all the hubbub over the last several weeks around carbon. They're clearly a huge potential player at the impact of carbon regulations. Should they be implemented in the U.S., would have a material impact on the way you do business. Could you articulate from Southern Company's perspective what is going on in Congress and how you are preparing or taking that debate?

Sure, let me talk a little bit about that. We certainly have not been absent. We may have been silent, but we have not been absent from the discussion. I want to reassure you that we are actively engaged in the debate and the discussion.

We've said for a number of months and maybe a couple of years now that our view is that as the science continues to evolve and as the concern over climate as an issue continues to evolve, one of the most important things we should do as a nation is to work on developing technologies and delivering those technologies to a commercially acceptable and available viewpoint so that we have the means and wherewithal to actually reduce CO2 emissions.

And when you begin to understand what is required to do that, first, it is a very expensive proposition and it will take a number of years to do. We have been actively engaged not in just that discussion, but we have invested a significant amount of money in projects like Future Gen, IGCC development. We are also participating in carbon capture and sequestration technology demonstrations. So what we are trying to do is to focus more on the technology development and evolution and commercialization.

As we debate in the Congress the actual policy formation, one of the most important things that needs to happen is that the Congress itself needs to have a much better and more thorough understanding of the reality we face as a nation in terms of what technology is available and when is it likely to be available and how much it will cost to deploy. When you engage in that discussion with most congressional members, you find that there is a rather meager awareness of exactly what we are talking about and the economic impact potentially on this nation.

I think as we engage in a more vigorous debate, which is entirely appropriate, and we welcome and we will be actively engaged in, that level of understanding will certainly grow. I hope as a part of that, that the Congress has the fortitude to appropriate the money required to incent the technology and make it commercially available. And it also has the good sense in making policy to recognize the timeframe required before we set premature targets and timetables. We have been very cautious about embracing targets and timetables without the understanding associated with technology being available and the time it takes to deliver that and the economic impact.

So we are anxious to continue to participate in the debate in the Congress. I think we have tremendous credibility by virtue of the integrity and the knowledge that we have around this issue. So we will be as involved as anybody in the debate. We might not be as public as some people, but we will certainly be involved.

Steven Rountos, Talon Capital.

I wanted to ask you a couple more on the [detaily] side questions, one of which was -- it seemed like the other income year-over-year was a fairly significant swing just in the quarter itself. And I wonder if you could talk about that for a second.

Yes. What you're going to see there, I think, is related to synfuel. Remember the model for synfuel is essentially a normal synfuel operation will generate an operating loss. And so, that would show up as a negative. And then what you would see is tax credits down in the tax line that would (technical difficulty) -- a, offset the loss, and b, give you ultimately net income.

So to the extent you scale back synfuel production, you have less losses and therefore more income at that level. That is what you're seeing at that level. You'll also see -- look down the income tax line, you'll see an increase there.

Okay. And then on the other side of the P&L, the depreciation was pretty restrained year-over-year. Is that just a function of the spending, or was there something else -- was something else happening with the lives of the assets?

No, I think it was pretty normal. I don't see any major story there.

Okay. On the capital side, when you talk about the sources and uses of cash over the next three years, the $1.5 billion of common equity, that is in contrast to the '06 to '08 $500 million of net equity. Can you kind of explain what form that might take and what it might look like over the three years?

Yes, sure. In fact, thanks for pointing that out. It is something we want to chat about a bit. We have been thinking -- and in fact, our financial plans had called for resuming issuing new equity in our plans, if you will. That would be our savings plan, employee savings plan, employee stock ownership plan, and our DRIP -- our dividend reinvestment plan -- kind of in '09.

When you think about what has gone on here, we at Southern Power's level have accelerated in timeframe and increased in total amount the projected investment in competitive generation facilities. We announced a lot of that last year, Rowan, DeSoto, Franklin 3, Oleander 5. So that increased.

As well, we have a growth plan in place that probably calls for about $1 billion over the next three years. As well, you see some increases in T&D to support the growth, environmental to support the low-cost generating fleet.

When you add all that up, what we have decided to do is to turn on the plans now in '07 and in '08. So in 2007 and in 2008, you'll see us issue new equity through our plans that I mentioned before. Those plans will deliver each year a little over $450 million. So if you just call that $1 billion, that is the difference between the $500 million we forecasted last year and the projections of $1.5 billion in this three-year period.

Last quick question -- when you talk about the embedded wholesale versus Southern Power, I think the numbers I was coming up with for '07 was $115 million for Southern Power, and then $155 million for embedded wholesale.

Yes, that's right.

So when I add the two together, I am like 270 for what used to be the non-reg business --

That's right.

-- in total? Okay, I wanted to make sure I had that number.

I just might add, even with that, we feel very confident in our financial plan going forward. So everything we do contemplates that.

Andrew Levi, [Brencourt].

I apologize. Someone was talking to me when the last question was answered. So the bottom line on the equity was DRIP, ESOP yes/no or new equity yes/no?

That's right. We are turning it into three plans -- DRIP, ESOP, ESP are being turned on in '07. When before, we had projected to turn them on in '09. And that simply given the increase in CapEx, it supports our credit rating.

You know, financial integrity is a major driver of our financial strategy, not only our simple, low-risk business model, but also a good credit quality. So we want to keep our equity ratio in the 40% range.

But no new equity as far as it being put in the market or anything like that?

No, no public issuances (multiple speakers) --

And I don't know if it was discussed; how many shares does that end up being? Or did you give a dollar amount on how much the DRIP and ESOP and all that would be annually?

Yes, it is a little over $450 million a year. Depending on what the price of Southern stock is, it is going to be 13 to 16 million shares.

Vikas Dwivedi, Morgan Stanley.

A quick question on -- you know, a lot of the regions around the country are worried about reserve margins declining very quickly. And I know the [circ] area broadly had a lot of capacity.

But can you guys give any comments on how you view it shaping up, and how that might affect your off-system sales profits going forward? Because I think it was in '04, I know there were a lot of weather issues there. But it seemed to really accelerate then. But kind of on a weather-adjusted basis, how does that look in your guys' opinion right now?

No, I think you are hitting the nail on the head. When you think about what we have said about the various regions and our areas of interest for competitive generation broadly, we talk about the Carolinas and our own territory in Florida.

What we have said is that we believe Florida may be pretty much in equilibrium from a supply-and-demand standpoint. Perhaps right now, we think that the Carolinas pretty much now, maybe '08 something like that. And in Southern's territory, around 2010.

You know that we have made several investments and we have some placeholders in the plan to make further investments. But otherwise, this comment on Southern Power's net income contribution being slightly positive over the next three years of this equilibrium coming into balance in 2010.

Got you.

That is kind of where we are.

Okay. On that same note, though, is there any potential for accelerating CapEx on certain parts of the dispatch curve? Because well, the reserve margin numbers don't capture any of that.

You are right. No, I think we are in pretty good shape there. I think the next -- if you look at excess capacity around us, it's probably in the [CT] area. So I don't see any accelerations there. So you are really looking in the kind of intermediate to base load as being the next big CapEx commitments. Those will be further into the future.

Hey, one more thing I just want to add to this whole notion of wholesale, because it did impact fourth-quarter results. Just a statistic I want to get out -- you know, there is a lot of discussion right now about the future of the nuclear industry, and we are very proud of the way we run our business.

In the fourth quarter, our nuclear fleet had an equivalent forced outage rate, E4 of 0. And what that did, that helped us make higher-than-expected margins in the trading area of our business.

So one of the strengths that I think Southern can bring to bear is that if we continue to run our business as well as we can -- and remember, too, our fossil/hydro fleet had a peak season equivalent forced outage rate of 1.1% versus an industry average of 6 to 7%. I think that will put us in good stead in the years ahead

Daniele Seitz, Dahlman Rose.

I just was wondering if -- is there any danger at all that the expanding embedded of system sales will become some softer than offset to future rate increases, or do you feel that they are totally safe in supplementing your income?

I think we feel confident in their current treatment. In fact, when we think about wholesale sales, those are generally tied to non-jurisdictional assets, assets that otherwise -- perhaps in a historical proceeding were removed from rate base or never part of rate base. So we feel confident about the current treatment staying in place.

Okay. And as far as the -- I understand you are going to present your plan to the Georgia Commission. I was wondering, are the other states going to participate also in the cost of the new units? And do you have to file similar plans in the other states, or do they have their own safe plate sort of construction budget?

I was wondering if the old standard of an automatic rating traces, etc. that you have entered in the past in Alabama and Mississippi, does those continue even if you expand your budget much more.

Every jurisdiction has their own treatment for such facilities. Alabama's would be called certificated new plant rate, CNP. Georgia goes through an IRP process. So every jurisdiction has their own way to treat.

I must say from our own financial policy, we absolutely believe in credit segregation from jurisdiction to jurisdiction. So we do not believe very much in jointly-owned plants across jurisdictions.

So each of them will have a different program.

Yes.

It will not contribute to the Georgia program, for example?

That's correct. It will be distinct on their own.

And you feel that this system as it is now will continue over the next four years at least?

Yes.

Okay. In terms of new power plants you are planning on over the next four years, are the units you have just mentioned, is this the only additional unit that you feel will be necessary? Or do you anticipate that you may add additional units from there?

It is the only one currently on the drawing boards. We certainly have studies involved and we go through this constantly to look at our generation expansion plan, given where we see the dynamics of customer demand going. Certainly, we have other resource options available over time throughout the system. So we will evaluate those. But in the three-year period, this is the one that is most important.

Daniel Eggers, Credit Suisse.

I don't know if I am front running the Georgia filing or not, but with the new CapEx program and a lot of things going on in Georgia, can you give a little extra color on how much the capital on the $11.4 billion plan is going to go to Georgia Power versus the other utilities and move some color around the differentiation in the categories?

Yes. Of the CapEx budget that we are showing right now of $13.2 billion, something like over the next three years $5.6 billion is associated with Georgia Power -- if that's what you were looking for.

That gets most of the way there. The $700 million is going to be for the new power -- the new gas plants, right?

Yes.

Can you tell us (multiple speakers) --

There is just a smidgen of cost creeping into '09 that is related to a projection on the new nuclear unit. That is about $100 million there. So that would be the second one. But it is a small amount of the total.

How big is the -- capacity wise and cost wise are going to be the new Georgia plants outside of Atlanta?

It is 600 megawatts, we think, is kind of the targeted amount right now. But of course, that is all subject to the full hearings of the integrated resource plan that we engage with with the Georgia Commission.

Okay. We have heard other folks who have been looking at IGCCs, talking quite a bit about cost overruns or expected cost overruns. Can you just tell us how the process is going for your plans and confidence level as far as building something bigger than the 250 megawatt facility into the future?

We will just see. I guess there has been a lot of talk in the public right now about what is going on with comp escalations for coal units and IGCCs and a variety of other things. And we are certainly looking over our hand in the same respect.

So I guess what I would say is right now, you know we have -- in fact, we are very proud of our research and development facility in Wilsonville, Alabama. In fact, you know, the DOE has named that as one of the nation's premier clean coal research facilities. So we're actually putting our money where our mouth is. At that facility, we have in place a facility that runs our integrated coal gasification technology, albeit at a rather small level.

The scale-up to the Orlando unit, 285 megawatts, we believe is absolutely feasible. From a cost standpoint, we are faced with everything everybody else is facing right now in terms of commodity increases, labor, and a variety of other things.

Hey and then let me --

I would just add to that that the cost increases we see, as Tom pointed out, are not unique to IGCCs. For the large part, they are driven simply by commodity cost increases -- steel and valves and concrete and those kinds of things. So it would be pretty generic to coal period or nuclear period. It's just the cost of commodity materials.

And Dan, let me add one more thing. Let me make sure I am clear on this, because I might not have been.

When I think about replacing -- I'm thinking about the McDonough unit now -- so replacing the coal unit plus the new gas, we're talking about 3 times 800 or about 2500 megawatts in total.

So that total project will be 2500.

About that, yes.

And so, only a small piece of that is actually in that -- the new plan than the '07 to '09 plan then.

Well, no. In the '07 to '09, the numbers in them amount to about $611 million. So certainly, when you think about -- and it ramps up significantly into '09. The '09 number is around $424 million. So certainly, in '10 and '11, they are also significant.

Okay. One last question, and I will let somebody else go. But on the environmental side, how much of that $4.6 billion have you guys locked in via contract or equipment procurement or signing people up? Or is that going to be again subject to some of the cost inflation that the industry has seen?

I don't know the answer. My view is when you think about our total environmental plan, I think we have looked over our hand pretty carefully there. In the near-term, we feel pretty good about being able to deploy that technology at those cost levels.

But in terms of what is absolutely under contract right now, just I know the answer. We can certainly get back to you. I will get Glen Kundert or Jimmy Stewart to give you a call back.

Scott Engstrom, Satellite Asset Management.

Some more follow-ups on this sources and uses page. Just thinking on -- you were going through some of the details there, but if I was thinking at the high level, your page from the last quarter had $10 billion total CapEx. This was $13.2 billion. If you think about it at the high level, how much of that is sort of putting in the '09 budget and taking out the '06 budget? And how much reflects higher costs from your former budget?

Let's see. When I think about the difference between the two, environmental is going to be about $1.5 billion between the two. So if the difference between $13.2 billion and $10 billion is $3.2 billion, environmental is about $1.5 billion. When I think about environmental expenditures totaling about $4.6 billion or so, the run-out on the numbers is something like $1.7 billion or $1.65 billion and then $1.3 billion over the three-year period.

Let's see. Just thinking about the change in years, another way to slice this up. Because one of the major impacts is just removing a relatively lower CapEx year, '06, and adding a relatively more expensive CapEx year, '09. That is $1.3 billion just by itself.

That's from environmental or across the whole budget?

Across the whole budget and I will break that down for you real quick. Of that amount, the difference between '06 and '09, about $500 million is environmental. About $500 million is associated with new generation, about $200 million with transmission and distribution, and $100 million from a variety of other places.

Let me give you one more comment on the environmental going up. I think one of the things that is important here is that we have added new scrubber projects to our environmental plan. Now one of the areas we are looking at is the [sheer] units. There is four units there. Entering into this three-year CapEx budget would be a scrubber at Sheer 3, as well, a smaller unit and Gulf Power would be [Crisp] units 4 and 5.

We have also accelerated some scrubber projects that would be [Berry] 5 and Alabama, Crisp 6 and 7 at Gulf, Daniel 1 and 2 at Mississippi. And then of course, you would add to that the combined cycle unit that will replace the coal unit at McDonough. So the only other thing that is kind of helpful there might be that we are adding automated metering equipment, which over the period is about $250 million.

Are you making the main point, Tom, that the bulk of this higher number comes from '09 being a much bigger number than '06 as opposed to cost creep within the budget that has existed?

Certainly, that is the case. Certainly, there is some cost escalation as David mentioned. But we just take off a lower year and add in more expensive year. That is $1.3 billion.

How much of the $1.6 billion for Southern Power is sort of placeholder at this point? Is that a number you can talk about?

Sure, yes. About -- the base plan of Southern Power, which I would argue is associated with the build-out of Franklin 3, some other items would be about $600 million. So therefore, the growth plan of Southern Power -- this is the placeholders -- is just about $1 billion. And that rollout is virtually nothing in '07, $300 million in '08, and about $700 million in '09. So that adds to $1 billion. You add the current construction program as $600 million, you get the $1.6 billion.

Okay. That leads into my last question, which is if you have the $450 million of equity coming from plans, which is $900 million of the $1.5 billion you have on this page, does that mean the last $600 million is linked to the leftover portion of the Southern Power that is not accounted for?

I suppose you could do that. I am reluctant to trace dollars that way.

And just -- let's be very clear with everybody. The difference in the $900 million or $1 billion or whatever, we have always had in the plan -- our stock plans being on in '09. So the $1 billion is just the delta. It is turning plans on in '07 and in '08.

Okay, so it is likely that you'll issue that $1.5 billion regardless of what happens with the placeholder amount at the Southern Power?

Well, we will see. To the extent the Southern Power growth plan turns out to be zero, that would require less equity. And we would make according adjustments.

Remember that as a strategy, we preserve what we believe is arguably the highest financial integrity in the utility industry. And part of that is to preserve not only with our low-risk business model, credit ratings that are in the strong A category. Part of that involves keeping equity ratios at the 40% level. So keep your eye on that.

Okay. And the common equity relative to the amount of net debt and preferred issued plus around, say, $3 billion plus of retained earnings makes that a -- almost a 50/50 capital raising -- not raising, but capital distribution? Is that a fair way to look at it?

I think so. Let me just look at something real quick. When I think about '07 -- hang on just a second; I just want to look at something real quick -- '07 through '09 -- yes, that looks about right.

Vic Khaitan, Deutsche Bank.

One question I have that with all this capital spending program, what kind of rate increase would we anticipate needed for customers?

Well, that is certainly under review at the Georgia Commission -- at Georgia Power. And certainly, as we get closer to the rate case, you will see that. That depends on a whole host of factors, so I'm really reluctant to talk about potential rate increases. As we get closer, we will see.

I think if I were to just think about math, it is CapEx less depreciation, growth and rate base. And then you think about some estimate of what your O&M projections are, etc., etc. I mean I would go through that kind of math.

Yes, but you are not looking for any kind of rate shock or something like that?

Oh, heavens, no.

That is what I was trying to get to that. Is it pretty much in line with slightly above inflation, maybe, but nothing significant?

Yes, and remember, the nature of this investment is to support growth and protect our low-cost generating fleet. We believe over this timeframe we will still maintain our substantial discount to average utility prices. So we actually feel very good about this.

Steven Gambuzza, Longbow Capital.

On the environmental CapEx, I was wondering if you could update us on what you expect the total cost of the program to be when you look at what is economic under current market conditions. What is the '07 to '09 span represent as a percentage of what is left to do?

What is left to do is a term of art, because it involves long terms and changing regulations. So I guess what I would express is what we have laid out here over the three-year period we have a great deal of confidence in. Certainly, it may change as we deploy it. But over the next three years, we feel pretty good.

When you start getting into, say, over the next 10 years, the years '06 through '10 indicate probably a much greater deal of uncertainty in the estimate. As someone mentioned before, I am pretty sure we would not have those things under contract today, and we do know what the economy is going to do in terms of commodity prices and labor availability and a variety of other things.

The one thing we are benefited from is because Southern Company has scale, we are able to attract and retained craft labor to keep them employed in the system over a long period of time. So I think that is an advantage we do have.

So I am a little reluctant to say just because I don't know what is or is not the confidence about price increases over the next 10 years going to be.

Well, I think, historically, I recall you talking about kind of a $7 billion number for the total program. Is that still in the range of estimates?

Remember I mentioned in one of the prior answers we adding some scrubbers to Sheer units 1 through 4. Yes, I would assume that number is going to go up. I mean what it is going to be, I just don't know. It could be a -- it just could be a significant number.

Okay. And then I was wondering if you could just comment on in terms of the generation additions in Georgia, just so I understand, you have 2500 megawatts of gas-fired capacity coming online by 2012, $700 million is in the forecast period. I was wondering if you could just provide some color on what you expect the entire project cost for that to be.

We have not disclosed that. We would like to keep within the three-year period if that is okay.

Okay, and then finally in terms of the competitive generation guidance that you provided in terms of $115 million for Southern Power and $155 million for embedded wholesale, is there any optimization included in that? Or could you give us a sense for what is asset-based versus optimization included in that number?

Yes, it is interesting. One of the things I mentioned in the script is that Southern Power has I think something like 82% of its assets covered through 2015, which I think is really an attractive number.

When we did the Rowland, DeSoto and Franklin 3 transaction, one of the things we did was kind of balance the line. We used to talk about being in the 90%, 95% coverage between now and say 2010.

What we have done is kind of level that line out. We have a few more megawatts of uncovered capacity in the near-term, maybe 500 or so, 600 or so that will be added to what is otherwise contract versus what we call trading for profit.

Let me give you the breakdown right now. In 2006, about 81% of our net income came from contracts, and about 16% came from the trading floor, the balance being that fuel of services. Factoring fuel services out, the split was like 83 and 17.

Are these competitive gen or Southern Power numbers you're giving right now?

That is competitive gen. When I think about adding more to our uncovered capacity and therefore adding more to our trading floor as a percent of total profits, I kind of look back at a year like 2005. And there, we had kind of a 76 and 22% number -- 76% of contracts coming from -- 76% of profits coming from our contracts and about 22 from our trading floor. So I would look for that kind of relationship.

Okay, and that is embedded in the numbers that you have provided?

Yes, absolutely.

[Annie Sow], Alliance Bernstein.

Several questions actually. One regarding to your -- the same environmental spending, can we assume the $4.6 billion for the next three years are mostly scrubber installations?

Yes. You know, the relationship for that has been over the long-term, scrubbers kind of represent a little over two-thirds of our CapEx spend associated with environmental, with SCRs being, let's say, 65 to 70% -- let's say that SCRs are 25%, and the balance might be represented by baghouses for mercury control.

So I think that is a reasonable estimate.

So as you install these scrubbers, can you comment whether in terms of coal procurement there is any changes going forward for the next three years for you guys?

No, I would not anticipate that. You know that we secure predominantly 40% of our coal anyway from the West -- Powder River Basin, Colorado, that sort of thing. Maybe 29% from the Appalachian region, we import now maybe 19% or so -- 18%. So I would assume that that is going to remain constant over time.

Separate on the transmission CapEx of $1.5 billion, is there any way you can break it out like how much is maintenance and how much is for extension or do you need to build new transmissions?

Well, we have had a long-standing program in place on the transmission side. You know, that is one of the things we talk about our circle of life. So long as we are able to deliver reliability, low prices and customer satisfaction, we have been treated in a constructive manner with our regulators. And so therefore, we have tended to have an environment which attracted capital formation.

When you think about kind of Southern versus the industry trends, say, over the past 10 years, Southern has invested about 40% more intensively in transmission than say other companies in our industry. I would say now, it is projected with some data that I have seen that other companies are going to start catching up to our rate of spend.

Now, let's think about this for a minute. The big project that is facing Southern right now -- I am kind of giving you a broad view -- is what we call our Northern Arc. This will be a transmission system that will be built in North Georgia -- gives us a greater ring of reliability surrounding the Atlanta load sink. That's a big deal. That is long-term growth.

When you look at distribution, what is really driving that is the very near-term or short-term growth, the 70,000 customers that enter into our region every year.

In terms of maintenance capital, we could get back to you on that. I do not have a breakout at my fingertips on that.

My final question has to do with your kilowatt sales to retail customers. You pointed out it is up 1.4% in '06 -- '05. If you break it out, the residential is up 2.5%; commercial is also up 2.5%. Can you also comment industrial?

Oh, yes. That is really an interesting story. The kilowatt-hour sales that I see show it being kind of -0.2% -- essentially flat. There is a couple of impacts going on there. Let me just comment on two of them and then I will give you kind of more the longer-term broad view.

There are kind of two tactical impacts on that. One is related to hurricanes. You know, you think about it, 2006 represented a remarkable year at our Mississippi Power subsidiary. You know, it is easy to forget, but that company was -- and that whole region of the United States was under significant reconstruction following that natural disaster we saw.

So for Mississippi Power to perform as it has with its reliability, its own customer satisfaction and just rebuilding is just terrific. It is a terrific nod to those men and women.

What's interesting is I think the industrial segment would be adjusted by about 0.2% had the hurricane not occurred. In other words, the difference between '05 and '06, you are probably losing about 0.2% there.

Further, gas prices were much higher in '05. Alabama Power particularly, but other companies throughout the system have some cogeneration loads. With high gas prices, they tend to shut down their cogen facilities and just by electricity directly.

What we saw in '06 was gas prices moderate, and many of those customers turned their cogen facilities back on but didn't buy electricity directly. That is accounting for another -- I don't know -- round numbers, 0.3%.

So what you kind of get still -- even with that is that industrial does not seem to keep the pace of the rest of our load. Another interesting impact is when you think about Southern's industrial load, we have a great deal of low diversity relative to, say, other companies in the industry.

We follow about 19 different standard industrial classification segments. The one segment that, frankly, we probably ought to just recalibrate is textiles, particularly the low end of textiles. I would mean yarn manufacturing, apparel manufacturing. That has lost significant amounts of load over the time, and in fact has largely been outsourced overseas.

The high end of textile is actually doing fine. That would be, say, carpet manufacturing and say the polymer-oriented part of textile manufacturing; you could associate with automobile industry.

So if you think about excluding textiles, let's just do that. If you recalibrate it that way, the rest of our 18 of the 19 industrial segments actually grew at a rate of about 2%.

So we actually feel pretty good. Our economic development organization at Georgia Power in 2006 had its best year ever, and that's something like 80 years' worth of performance.

We have continued growth, and I would say the bright stories around the system, starting in the West and moving East -- in Mississippi, we see growth in petroleum refining and pipelines. In Alabama, we see a continued growth story with the automotive sector in the first, second and third-tier suppliers therein. I would say in Georgia, we've talked about the Kia plant that's now going to be located there, as well as continued growth in the data center businesses that are terrific consumers of electricity.

So overall, we feel very good about our industrial sector, despite the kind of flattish-looking performance in '06.

What kind of numbers do you assume in your '07 guidance?

2% growth in total sales.

Paul Patterson, Glenrock Associates.

Quick questions here. What was the regulated return at Georgia Power I guess for 2006?

Yes, it has not been filed yet. But we think it is going to be in the 12% range.

You are going to be filing this in the summer; is that right again?

July.

Okay, and the test year you are going to use?

It's a split year between 6s and 7 -- six years in '06 -- in '07 and '08; I am sorry. It's six years in '07 and six months in '08. 6 months each year, sorry.

I got you; no problem. And then just to make sure I was right on this. Weather was normal in 2006; is that right?

It was $0.03 better than normal. Let me just add to that real quick. When we talk about the test year, the nature of the accounting order is such that we use a test year to file a conventional kind of case. What we have done since 1995 is enter into a succession of three-year accounting orders which contemplate future circumstances.

So certainly, if there were important future circumstances like environmental spend, we would take those into account. We would propose to.

Ashar Khan, SAC Capital.

Hey, Tom, I am going to do a little bit of math from your guidance. What you said -- you used like a 13.5 ROE?

If I am right, if I look at what you provided, the common equity at the operating companies in Southern is pretty similar to like $11.3 billion. And then, if I add the $1.5 billion of common equity that you planned and then -- I think so there is like 500 or so of retained earnings every year. So I come up with a $3 billion addition in common equity by the end of the three-year forecast.

And then if I take a 13.5% ROE and I have like nearly 40 million higher shares and I give your Southern Power 115, some leasing business, and take off for corporate and other, I get earnings power in the 255 range or so. So, I am saying to myself, hey 6.5 -- just taking your 13.5, 6.5% growth rate simplifies to nearly a 6.5% growth rate from 210.

Then I am saying to myself, well, what am I missing over here? I guess your projections are slightly softer. Is it that there could be more growth in the later two years because the CapEx is higher? Or what am I doing wrong in my -- I guess it's pretty elementary math I am using. I guess I might have some variables wrong or somewhere.

No, I would argue your math is fine. I guess the only thing I would caution is that this year, you are really seeing a half-year effect of this increased CapEx. So what we need to do is have a successful, constructive treatment in the Georgia rate case. We need to continue to have successful treatment elsewhere. But otherwise, looking into '08, '09, your math is reasonable.

Okay. My second question, which you alluded to, is we have got flat earnings and then we get a pickup, because all of these contracts have come back which you purchased. Could you give us some kind of a magnitude as to what that pickup could be?

Well, what we have said before is that we think the contributions from Rowan, DeSoto, Franklin 3 entering into the early part of the next decade will be pretty substantial. I've talked in terms of kind of half the net income of Mississippi Power.

So when you look out in that timeframe, kind of those contracts, those transactions taken in the aggregate, you are in the 35 to $40 million range in the next decade.

And they all hit in 2010 you said, right?

Yes. For example, Rowan is in place right now, but there is kind of different pieces. One of the pieces we assumed in the near-term was some transactions that we had entered into already. So the real increase will be in 2010. Some of that is covered in the near-term under lower margins.

Dan Jenkins, State of Wisconsin Investment.

A lot of my questions have already been answered, but I still have a couple left. First of all, I was wondering what is the refueling outage schedule in '07 compared to '06? Is it about the same, or is there more or less?

Just a second.

What kind of impact will we see from that on O&M?

Okay, let's see. Our refueling outage scheduled for '07, let's just go through them. Farley 1 has an outage start date in the end of September. We think it will come back at the beginning of November.

Farley 2 has an outage that begins early April and ends mid-May. Hatch 1 has no refueling in '07. Hatch 2 has a refueling early February, ending early March. Vogtle 1 has nothing in '07. Vogtle 2 has a refueling early March, ending mid-April.

And how does that compare -- so four outages, how many did you have in '06? Do you recall?

In '06, we had one, two, three.

So probably a little higher O&M then from outages in '07 versus '06?

Yes, but remember, the regulatory treatment we use is we normalize our outage expenses for the year period. So we tend to levelize those bumps out.

Okay. Going back to your business outlook and the CapEx schedule, that coal/gas conversion that you talked about, would that be included in new gen or is that included in the retrofits?

New generation for Southern Power. No, new gen.

New gen for operating companies.

Yes.

And you said that is pretty much back-end loaded it sounded like, right?

Yes, let's be clear. You were talking about McDonough there. For a second, I thought you were talking about Orlando. For McDonough, it is included in new gen for the op cos and that is back-end loaded.

Okay. What is the fossil retro, was that fairly evenly spread or what (multiple speakers) that.

Yes, it is really constant over time. That is a regular program that we employ. It looks like it is in the $350 million range every year.

Okay. And then transmission, is that fairly evenly spread as well?

Yes, accelerating a little bit. Because remember, one of the things I mentioned was this notion of a Northern Arc around Atlanta. We think land value is probably increased over time. It's pretty desirable piece of real estate. So it escalates a bit.

Okay, and then you have a fairly large maturity schedule in '07. I just wondered if you could give me a little color on what your financing plans are for '07? (indiscernible) over $1 billion, 3 or 4 coming due and then combined with the CapEx and so forth?

Yes, sir. What we are showing for '07 is $400 million of maturities. Those maturities will show up -- let's see -- I am just looking off the schedule here. Hang on just a second. Heck, before I give that to you, we have new money of about $212 million. And then we have refundings of almost $300 million.

That is just first quarter, or --

No, that is the whole year. So total was about 900 -- 400 are new maturities; new money, 212; refundings, 288.

Okay.

If you want more detailed breakdown, you can call Glen or Jimmy -- will be glad to give that to you.

Okay. And then just if you could give a little more color on the big jump in wholesale sales in the fourth quarter. It was up about 12%. Is that (multiple speakers)?

Yes, it was really interesting. We saw an increase in volume of more than 300,000 kilowatt-hours, something like that. And when you think about the different sectors we sell to, the increase was mostly to our West. So I would say the Entergy region.

That number in the past -- in a normal year, looks like it was about 18, 19% of our total off-system sales from an opportunity sales standpoint. This was more like in the 30 -- 33%. So that was a big move to sell energy to the West.

One of the other reasons I think that we were able to do well in that business I mentioned before -- was the terrific performance of our nuclear fleet, an E4 of 0. That had the effect of reducing our bottom-of-stack lambda. That is the price having satisfied our native retail load requirements, we start selling into the wholesale market. In a kind of a theoretical margin, that is, the bottom-of-stack lambda less the average market price, about $14. That had the effect of contributing about $2 in margin.

So you add that kind of margin times an increase in volume of over 300,000, you get the increase performance of a little around $5 million.

Okay. Is that -- would you characterize that as unusual performance, or what can we expect going forward? Is that--?

A lot of our off-system sales program in that respect of opportunity sales is just that. We are taking advantage of market opportunities. So there may be circumstances completely exogenous to Southern.

All we can do is run our fleet as well as we can and making sure that we have peak season E4s in the range in which we had this year, 1.1% versus industry average of 7, running our nuclear fleet as well as we can, praying for good rainfall and hot weather. All that good stuff contributes.

In terms of reasons why people may be buying from us, it is hard to predict. That is why we tend to be relatively conservative in our projections in that regard.

Paul Ridzon, KeyBanc.

My question has been answered. Thank you.

And we have no further questions at this time.

Well great. Thanks again to all of you for being on the call with us. If you have any follow-up questions, don't hesitate to give us a call. We will be back with you in the first quarter. Thanks, Casey, for your help.

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