The Southern Company (SO) Q1 2011 Earnings Report, Transcript and Summary

Good afternoon. My name is David, and I will be your conference operator today. At this time, I would like to welcome everyone to the Southern Company First Quarter 2011 Earnings Conference Call. [Operator Instructions] I would now like to turn the call over to Mr. Glen Kundert, Vice President of Investor Relations. Please go ahead, sir.

Thank you, David, and welcome to Southern Company's first quarter earnings call. Joining me this afternoon are Tom Fanning, Chairman, President and Chief Executive Officer of Southern Company; and Art Beattie, Chief Financial Officer. Let me remind you that we will make 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 filings. We'll be including slides as part of today's conference call. The slides provide details on information that will be discussed in today's call. You can access the slides on our Investor Relations website at www.southerncompany.com if you want to follow along during the presentation. Now at this time, I'll turn the call over to Tom Fanning, Southern Company's Chairman, President and Chief Executive Officer.

Good afternoon, and thank you for joining us. Our first quarter results show we're off to a good start in 2011. In addition, as you can see from the materials released this morning, the economy, as shown by sales to industrial customers, continues to gain strength and momentum. The year-over-year increase in industrial sales in 2010, compared with 2009, was 7.7%. In the first quarter of 2011, we've already seen a 6.7% increase in industrial sales compared with the first quarter of 2010. This momentum is reflected in the results of a recent Southern Company survey of our top industrial customers in Georgia. In that survey, 60% of those customers said they expect production increases over the next 6 months. In addition, 1/3 of those industrial customers told us that they anticipate employment increases, and 28% expect increases in exports. The result of this survey serve to reinforce our own confidence about the near-term and long-term future of our region. So our businesses are performing well, and we are on plan. Turning now to an event which has focused the world attention on nuclear energy. I'd like to offer some comments on how we believe that event at the Fukushima plant in Japan might impact the nation's existing and future fleet of nuclear power plants. First, the supporting commitment for nuclear energy remains strong at the grassroots level here in the Southeast among key members of Congress on both sides of the aisle and within the Obama administration. No doubt, there will be lessons learned from the tragic events at Fukushima that will almost certainly apply to the current fleet of nuclear generation in America. Certainly, we expect there'll be a thorough, thoughtful review of those facilities located in seismically sensitive areas, plants along coastal zones and perhaps other design modifications particularly with older plants. We believe any mandated changes will not significantly impact the operations of our existing fleet or be cost prohibitive. Finally, we believe that any potential impacts to our Vogtle 3 and 4 units should be minimal. Recall that the Vogtle site is not in a seismically sensitive area. We are not on a coastline. We are some 130 miles inland and are 220 feet above sea level. Finally, the AP1000 design is robust, and its passive safety systems should preclude many of the problems, which occurred in Japan. Our current fleet is safe. Our proposed new units are even safer. With respect to units 3 and 4 at Plant Vogtle, we are still on track to receive the combined construction and operating license, or COL, by the end of this year, we had no indication that the issuance of the COL will be delayed as a result of the NRC's review of the events [ph] in Japan. My final business update concerns the potential for adding a risk sharing or incentive regulation mechanism into our current rate mechanism for Vogtle 3 and 4. Our position is that we are always open to constructive agreements that benefit customers. We believe the current Georgia law with respect to new nuclear construction is very clear from a cost-recovery standpoint. Therefore, any agreement must be an improvement on the existing law and must include a formal recognition of the work that has already been done to reduce the cost to customers of the new units by specifically including the benefits of conditional federal loan guarantees, production tax credits, changes made in the EPC contract and CWIP in rate base. We believe, in the aggregate, that since the certification approval, Georgia Power has brought to the table additional benefits to our customers of more than $1 billion. Georgia will file its testimony today. A decision on whether to adopt an incentive plan is expected on August 2. Let me say again, we are satisfied with the current rate regime for Vogtle 3 and 4. Any changes would have to improve on that structure. At this point, I'll turn the call over to Art Beattie, our Chief Financial Officer, for a discussion of our financial highlights for the first quarter and our earnings guidance for the remainder of 2011.

Thanks, Tom. As Tom has already pointed out, 2011 is off to a good start. In the first quarter of 2011, we earned $0.50 a share compared with $0.60 a share in the first quarter of 2010 or a reduction of $0.10 a share. Let's now turn to the major factors that drove our first quarter numbers compared with the first quarter of 2010. First, the negative factors. The impact of more normal weather in the first quarter of 2011 reduced our earnings by $0.07 a share compared with the first quarter of 2010. As you may recall, unusually cold weather in the first quarter of 2010 added $0.09 a share to our earnings in that period when compared to normal weather. Increased depreciation and amortization reduced our earnings by $0.06 a share in the first quarter of 2011 compared with the first quarter of 2010. This increase, primarily due to the expiration of the Georgia Power cost of removal accounting order at the conclusion of 2010 and to increased environmental transmission and distribution investments. A decrease in wholesale revenue in our traditional business reduced our earnings by $0.05 a share in the first quarter of 2011 compared with the same period in 2010. This reduction is primarily a result of a portion of the capacity at plant Miller in Alabama returning to retail service in May of 2010 after the expiration of a long-term wholesale contract. Non-fuel O&M reduced our earnings by $0.03 a share in the first quarter of 2011 compared with the first quarter of 2010. This reduction is due primarily to increased scheduled outages and increased maintenance costs for our fossil hydro fleet, as well as increased maintenance on our Transmission & Distribution system. The recognition of certain state of Georgia tax credits in the first quarter of 2010 compared with the first quarter of 2011 reduced our earnings by $0.02 per share. Other income and deduction and taxes, other than income taxes, reduced our earnings by $0.02 per share in the first quarter of '11 compared with the first quarter of 2010. Finally, an increase in the number of shares outstanding reduced our earnings by $0.01 per share in the first quarter of 2011 compared with the first quarter of 2010. Now let's turn to the business positive factors that drove our earnings in the first quarter of 2011. Other revenue effects in our Traditional business added a total of $0.12 per share to our earnings in the first quarter of 2011 compared with the first quarter of 2010. This was primarily the result of regulatory actions at Georgia Power. Other operating revenues, primarily related to increased transmission revenues, added $0.01 per share to our earnings in the first quarter of 2011 compared with the first quarter of 2010. Finally, improved results at Southern Power, due primarily to new contracts, added $0.03 per share to our earnings in the first quarter of 2011 compared with the first quarter of 2010. In conclusion, we had $0.26 of negative items compared with $0.16 of positive items or a negative change of $0.10 per share over the first quarter of 2010. So overall, our core came in at $0.50 per share. Before I discuss our earnings estimate for the second quarter, I'd like to update you on the economy and 2 other important matters. First, total weather-normalized sales for the first quarter of 2011 increased by 1.4% over the first quarter of 2010, driven primarily by stronger sales to our industrial customers. The improving economy saw industrial sales increased by 6.7% in the first quarter of 2011 compared with the first quarter of 2010. Quarter-over-quarter, the most significant increases were in primary metals, up 18%; pipelines, up 17%; transportation, up 11%; and chemicals, up 10% compared with the first quarter of 2010. In the primary metals group, ThyssenKrupp is reporting increased demand for its high-quality flat-rolled steel from its new facility in Alabama. The increased demand by pipeline customers is largely attributable to increased demand for home heating oil and natural gas in the Northeast due to colder temperatures in the first quarter of 2011 compared to the first quarter of 2010. Auto production at manufacturers within our territory remained strong, and low natural gas prices continued to stimulate chemical production in the U.S. Adjusting for weather, residential sales declined by 0.9% in the first quarter of 2010 compared to the first quarter of 2010. Total personal income continued to strengthen, but higher food and energy prices, primarily gasoline, eroded income gains in the first quarter. However, both regional and national initial claims for unemployment are falling to levels that would suggest the beginnings of job growth. As expected, commercial sales remained weak, declining 0.8% on a weather-normal basis in the first quarter of 2011 compared with the first quarter of 2010. In spite of limited growth in sales in the first quarter, there are positive signs: The Institute of Supply Management's Non-Manufacturing Index has been above 50 for 16 months in a row. In this particular index, any score above 50 indicates economic expansion in the commercial sector. Additionally, office vacancy rates have remained flat at around 23%. Also during 2011, sales tax collections in Alabama and Georgia grew by 6.8% in the first quarter, suggesting an improvement in consumer spending, which should bode well for a pickup in commercial usage. We continued to see new announcements of industrial and commercial expansions in our service territory. In addition to those we had mentioned in previous calls, the following have been announced recently: Chevron is planning a $1.4 billion expansion of its refinery in Pascagoula, Mississippi, which is expected to be completed in mid-2013. Kia Motors, which will begin producing its popular mid-sized sedan, the Kia Optima, at its West Point, Georgia plant in 2012. The new production line is expected to add 1,000 new jobs, bringing total employment at the plant to nearly 3,000. ThyssenKrupp is accelerating work on a stainless steel remelt facility with production expected to begin in 2012 that is expected to add approximately 700 jobs, bringing total employment at that facility to 2,700. Finally, 2 major military base realignments should have positive net impacts on Georgia Power and Gulf Power of approximately 2,500 new jobs. In summary, the economy in the Southeast continues to be driven by a steady, worldwide demand for exports as evidenced by the Port of Savannah, which reported an 8% increase in container volumes in the first quarter of 2011. As we move forward in 2011, barring any unforeseen shocks to the economy, we still believe that the steady expansion in the industrial sector, as well as military base realignments, will help drive growth in our Residential and Commercial segments. Before I discuss our dividend, I'd like to briefly review our current thinking on capital expenditures and equity requirements. As we outlined at our analyst meeting last month, our base estimate of capital expenditures for our Traditional business for the 3-year period 2011 through 2013 totals $13.3 billion. In addition, we have provided a range of $700 million to $2.9 billion of potential compliance capital over the same 3-year period to address evolving environmental regulations. If the EPA's proposed utility MACT rule is finalized as proposed, we expect that our capital budget would be closer to the upper end of that range for the 3-year period that we've described. The primary driver that leads to the upper end of the capital expenditure range is the assumption that compliance with the proposed rule is only achievable through the installation of backhouses at coal units that we continue to operate or other capital-intensive operations such as new gas generation capacity and/or transmission upgrades. We have not changed our outlook on our equity requirements that will be needed to support our capital budget. Consistent with our assumptions on capital expenditures, we have provided a range of equity issuances of $900 million to $1.8 billion over the 3-year period. We expect to raise approximately $500 million of new equity through our internal programs, the dividend reinvestment plan, the employee savings plan, Southern Investment Plan and the employee stock option plan in 2011. We have already raised approximately $200 million of new equity in the first quarter of this year through these plans. We expect these same plans to provide sufficient equity for the remaining 2 years, even near the top end of the equity issuance range. Once the final EPA rules are in place, we should be able to provide more detail on both our capital expenditure forecast and our financing requirements. Now I'd like to take a few minutes to discuss our dividend increase. As you may have seen last week, we announced a $0.07 annual dividend increase effective with our second quarter dividend payment in June of this year. The dividend is now $0.4725 on a quarterly basis and $1.89 per share annually. This marks the 254th consecutive quarter that Southern Company has paid a dividend to its common stockholders and the 10th year in a row that we've increased the dividend. In fact, every year for the past 63 years, Southern Company has paid a quarterly dividend equal to or higher than the previous quarter's dividend. Our dividend and long-term earnings per share growth assumption, coupled with strong financial integrity, are key components of our overall value proposition. Turning to our earnings guidance for 2011. We are certainly off to a good beginning in 2011. Our first quarter results exceeded our estimate by $0.03 per share as we experienced a colder-than-normal January, which benefited both our Traditional business and Southern Power. However, as you know, the majority of our earnings are derived in the summer months of the second and third quarters. Therefore, our guidance will remain at $2.48 to $2.56 per share. Finally, our estimate for the second quarter is $0.62 per share. At this point, I'll turn the call back to Tom for his closing remarks.

Thank you, Art. In closing, I'd like to offer a few words about the Environmental Protection Agency's proposal for a new Maximum Achievable Control [Maximum Achievable Control Technology] Standard or MACT for the utility industry. Earlier this month, I had an opportunity to discuss this issue in a speech before the United States Chamber of Commerce and, later that week, to appear before the House Subcommittee on Energy and Power and testify on the proposed regulation. Both of these presentations are on our Investor Relations website and provide a detailed explanation of our concerns. In summarizing our position on the EPA MACT, we have 4 key concerns: First, no matter how you look at it, the timeline for this rule is unreasonable both for providing comments and for complying. Second, its accelerated 3-year timeline for compliance could put the reliability of the nation's electric generating system at risk. My third point is that the rushed timeline will also impact electricity affordability. My fourth and final point is that the industry needs a realistic compliance schedule, a schedule that is based on historical experience, a schedule that allows us to retrofit existing units and begin work on additional capacity at the same time. As I've said before, we are already transitioning our generating fleet. We don't need an overly complex and unworkable set of new regulations to hurt our customers by decreasing reliability, increasing costs, reducing job growth and burdening an already challenged economy. Finally, I'd like to reiterate that we are off to a good start in 2011. Our businesses are performing well and the industrial side of our economy is nearing prerecession levels of production. We continue to believe that a resurging industrial sector will drive an improvement in our residential and commercial classes as we move forward this year. Our primary focus remains, as it has been for the past 63 years, to provide a reliable and affordable supply of energy, to meet the needs of our customers and the energy requirements of this growing region. At this time point, Art and I are ready to take your questions. So operator, we will now take the first question.

[Operator Instructions] And your first question comes from the line of Andy Levi of Caris & Company. Andrew Levi - Caris & Company: Just a quick question. On the COL, I guess I remember -- I mean, obviously, you've stated that the schedule is for the end of the year. But at your conference in March, you talked about possibly getting it earlier. Is that still a possibility?

Yes, I suppose. But I think the more realistic expectation we'd like to keep out there is just by the end of the year. Andrew Levi - Caris & Company: Okay. That's all I had.

Your next question comes from the line of Paul Ridzon of KeyBanc.

Just looking at your guidance, it looks like you're -- for the second quarter, it looks like you're planning on being flat with last year. But we still have one more quarter of the accounting order as a headwind, right?

Which accounting order are you referring to, Paul?

The Georgia depreciation?

That basically ended at the end of last year. There is still about $7 million a quarter that will be amortized against depreciation. But as you compare to last year, it will be a lot less this year. So depreciation expense will go up in comparison on the second quarter as compared to last year.

So the headwind comment is true?

Yes, that's true.

And we still expect to be equal?

Yes.

And you indicated that the first quarter of '11, Southern Power had some new contracts that added $0.03. What are the contracts signed, and how long do we have that tailwind?

Well, last year, we had Plant Wansley that went off contract at the end of 2009 and was off contract for the first 6 months of 2010. They were -- they are on contract in 2011, so you got about 0% coverage to 65% coverage in the first 6 months of the year. And then I think at Plant Dahlberg, which was not covered last year, and it's more than 100% covered this year. I'm not sure about the length of those contracts, but we can get back to you with that if you need it.

Okay.

Super. Thank you.

And your next question comes from the line of Steve Fleishman of Bank of America.

A couple of things. First, on the -- your kind of take on complying with the EPA HAP MACT rule. Just could you give some flavor on the -- one of the things in that proposal was the reliance on dry sorbent injection. I'm wondering if you could give your point of view on -- from your experience in Utah and how reasonable that is. And did you incorporate that at all in your plan, or are you assuming you can't do it?

Yes, actually, thanks for that question. As all of you may know, I think Southern Company is the leader in compliance with these types of equipment modifications. In fact, we’ve led our industry by adding, I think, so far about $8 billion of environmental control equipment, and by the 2013 timeframe, we will have added somewhere between $10 billion and $12 billion in total. So I think we've got a great deal of experience. Further, we've been able to put this CapEx into place at a timeframe that makes sense for reliability in the Southeast. We've done everything on schedule, under budget and has performed at above industry standards. So I believe we know what we're talking about here. Further, you may know that Southern Company also is the only company that remains significantly engaged in proprietary research and development, and we've had a lot of people working on these issues, frankly, for decades. With respect to the dry sorbent injection issue, dry sorbent injection is typically used and has had some success in dealing with things like SO2 and SO3. But when you consider the consequential effects on the PM standard that's being proposed, which is frankly a new standard, when you take into account not only filterable PMs but condensable PMs, there is a consequential problem that is introduced by dry sorbent injection and popularly trona. So our view is that there may be very selected instances where that might work. But in fact, we believe it will not be a widespread solution. It's one of the reasons why we really disagree with the proposal put forward in the EPA regulation. I think their estimate was you would only need to add around 26,000 megawatts of scrubbers. We think the number is going to be way more around 80,000 megawatts of scrubbers.

Okay. And just I guess separate topic on the issue of the COL. Just from the simple issue of like NRC personnel resources. Is that something you're concerned at all about in terms of the NRC being able to come out on the timeline that you'd hoped for?

Well, listen, as a healthy matter, we're always concerned. But we've received assurances from the NRC that they had staff dedicated to our process. I think it's easy to complain about Washington from time to time, but when you consider the support that we've gotten from the Obama administration, from Congress, from our regulators with the priority that's been placed on moving forward with this next renaissance of nuclear, we've been pretty gratified with the response and feel like we're getting the attention we deserve.

And your next question comes from the line of Michael Lapides of Goldman Sachs.

Tom, just following up a little bit on Steve's question regarding the HAP MACT rule. Does the law give you or give the industry leeway in terms of the timeline for implementation of that rule? I understand it does for 316(b). I understand I think it does for their Clean Air Transport Rule. But do the Clean Air Act amendments actually give the EPA any flexibility or if they granted it, would they wind up -- likely wind up in court being sued by some of the NGOs?

The consent decree that the EPA voluntarily entered into with justice provided that the justice recognize this was an enormous complex and potentially costly issue. And that if EPA needed more time in which to evaluate the potential effect that, that they would be willing -- they'd be inclined to grant it. And it was interesting. After I gave that speech at the U.S. Chamber, I had a very constructive conversation with Lisa Jackson, administrator of the EPA, and we certainly offered our help to her.

But it sounds like -- and I may have misinterpreted this and my apologies if I did, it sounds like there's leeway in terms of the review and the comment period. Once there's a final rule, do the Clean Air Act amendments give leeway for the timeline for implementation?

Three years plus a possible one-year extension from the final rule. So there's really -- there's 2 timeframes there, right?

Okay. I'm not sure I follow you.

One timeframe to comment and analyze the bill and everything else and another timeframe to comply.

Your testimony mentioned kind of trying to get another 60 to 90, 60 to 120 days of incremental comment period. It doesn't strike me that, that's enough to really solve the issue, meaning the issue is really you need 5 years to implement.

Yes, we agree. I think what I said in the congressional testimony is -- and let me tell you something, be very careful. I'm giving you Southern Company's reality. Our reality is that if we could get kind of a 2018 timeframe, we would feel a lot more comfortable about being able to run our portfolio. Other people have put forward timeframes that are really incomplete in their scope. They don't take into account the fact that we've got to deal with a portfolio of generation across a wide part of the United States. All these things must be taken into account, including vendor supplies, including craft [ph] labor. That's going to be needed to be brought to bear in an orderly way that is economically sensible. All of this is for the benefit of our customers.

Has anybody that you're aware of done work around what the pricing impact or the cost impact on pollution control equipment with the -- if it's all being done in kind of a 3- to 5-year timeframe?

Yes. Listen, there's a lot of people running around with estimates, but one can only speculate. The obvious answer is that it will go up.

Understood. Much appreciated, guys.

You bet. Thank you.

And your next question comes from the line of Ali Agha of SunTrust.

Tom, in your last round of visits out to Washington, have you gotten any sense on any activity going on there in the congressional level with regards to these rules? It looks likes obviously the Senate has tried a few things. House has been trying. Votes are not there. Are you seeing anything there to give you more optimism that things could move? Or is that one-year flexibility really the maximum that's out there?

Well, remember, there's a one-year flexibility that the EPA could grant, and we would want them to grant them immediately, frankly. Secondly, there are provisions where the executive branch could grant an additional 2 years. So there is some flexibility out there. In respect to the first part of your question, there are lots of shall we say initiatives and constructive thinking about legislative ways to attack this problem. One of the issues that I made a point of raising in my U.S. chamber speech is that energy policy is a purview of Congress, which is accountable to the electorate. Some of the outcomes of this regulation could eliminate, for example, in a practical way, coal being used in the future and on any new sources of generation. That to me strikes at the heart of national policy, and that is the purview of Congress.

And also remind us, Tom, let's say, the timeline does not change and the number of companies, perhaps you included, don't need that timeline. What is the penalty? Do you need to shut down or are there fines? Can you just remind us what's the penalty for not reaching the timeline?

I think what you would do is enter into a set of individual consent decrees with Justice, company-by-company.

Okay. And so that would lead to what, some kind of fines on your part?

Who knows? Certainly, and in my constructive conversations with Lisa Jackson, she, I think, recognizes that the EPA, the last thing they want is to create a reliability crisis. And so I think this whole issue goes to developing a constructive outcome on this very complex issue. My sense is that I remain reasonably confident or optimistic, perhaps, that we've been able to work through some tough complex issues in the past and in order to preserve a sensible economic outcome for our customers, in order to provide a reliable source of electricity for the United States, people will have to come to grips with reality on this issue.

And last question. You guys have been talking about on Southern Power relatively flat earnings profile for the next couple of years. When you look at the strength that you saw in the first quarter and the contracts you alluded to, have you factored that into your thinking? Or is that incremental? How should we be thinking about Southern Power over the course of, let's say, this year and next?

Ali, I think we're still talking flat for the next year or 2 for Southern Power. Yes, there were some additional contract coverages in the first quarter and probably be some in the second quarter. But as we look out in time, there are other contracts moving in and out, and that's all factored into our numbers.

One of the attractive features of Southern Power's portfolio is they have several sites that are expandable. When you consider that their strike zone is gas [ph] in the Southeast, we feel that they're going to be able to play a central role in relieving some of the problems that may arise as a result of this proposed regulation.

And your next question comes from the line of Mark Barnett of Morningstar.

Thanks for all the interesting commentary on the situation with the EPA there. I have a couple of other questions here. First, you mentioned that you're still looking for a relatively minor positive in commercial and residential usage this year. Is that correct?

That's correct.

So I'm just wondering overall what were your sort of usage -- total usage forecast that's in your estimates for this year? Do you have the overall number?

For the whole year, we're looking at 2.2% growth in the retail side, 2.9% growth in industrial, 1.5% on commercial and 2.3% on our residential -- in our residential sector.

Okay. That's helpful. And the second unrelated question. I just saw either today or yesterday that there was a biomass facility in Georgia that was looking for buyers. And just sort of in that vein, have you been looking at projects like that? And then sort of renewables elsewhere, how does the landscape look for maybe acquisitions or new build?

Well, we're always in the hunt. Renewables are attractive to us. Renewables have certainly their limitations, specifically with solar and wind. You know we've invested -- and I think it's the nation's second-largest currently operating solar facility, we invested with our partner, Ted Turner, in New Mexico. And I think we're building the nation's largest biomass facility in Texas for the benefit of the customers of the city of Austin. So we continue to look. We're looking at other solar facilities in Alabama and in Georgia and in the coastline of Florida. As well, we're on record as being not very bullish on wind. But even there, we continue to look at some applications off the Georgia and Florida coasts. With respect of new biomass, the industrial boiler standard has really put a hold on those economics and has really chilled any further development there.

Okay. Great.

You bet.

And your next question comes from the line of Angie Storozynski from Macquarie Capital.

Two questions. I want to go back to the issue of the timeliness of the COL issuance. I understand that so far you haven't heard of any potential delays. But don't you think that at least there should be some safety review following the Fukushima accident and there could be some modifications of the reactor design requirements? And how is this possible that you would not have -- you shouldn't anticipate any delays? I mean, it seems logical or likely. Is it?

No. Let me kind of explain why I feel that way. I think a lot of the questions that are being asked have already been answered. Remember, there are 2 processes in place here. One is was we call the DCD, that's the design control document, which is essentially an independent review of whether the technical design features of the Westinghouse AP1000, in fact, was in the public interest. Was it, in fact, safe? It is the safest design of any generation of nuclear technology that's ever been introduced. And we think that its design features are substantially better than anything in place right now. And so that process goes forward. This independent committee and the staff has recommended to the NRC to begin its rule making on the DCD. The COL is a process which essentially completes the complete application with the NRC. That is, it takes the Westinghouse AP1000 design and puts it on our site and takes into account any adjustments that are site-specific, including balance of plant issues. All of those are what's anticipated to be complete by the end of this year. Now your point about is there more interest, are there going to be more comments? We think absolutely. But in substance, we think a lot of the comments and questions that are being raised have been asked and already answered.

Okay. Now about Southern Power and what's happening in the Southeast, given current Central Appalachian coal prices and natural gas prices. I'm a little bit surprised that you do not expect much more upside or some upside to your earnings power at Southern Power given its gas blends and given that power from gas light [ph] facilities does seem to be cheaper than from coal plants using Central Appalachian coal at this point.

So remember, our business model is kind of the anti-merchant, right? We pride ourselves on securing the vast majority of capacity with long-term contracts typically divided into 2 segments. One segment is associated with the capacity side of the equation, so it's brick-and-mortar with a fixed profit stream associated with those plants whether they run or not. The second segment of those contracts deals with energy, which is largely fuel and some variable O&M. And there is some small profit potential associated with that, largely availability, profits and some other kind of small things. We did see some of that in the first quarter.

Improvement in capacity factors went up by 4% quarter-over-quarter.

So that accrued to the benefits of some of these energy margins that I talked about. But it wasn't an enormous number. Where you will see us make substantially more net income is as we either cover the rest of our uncovered capacity or agree to build new capacity that is currently available to be done on certain expandable sites. That's where we make all our money.

And your next question comes from the line of Jonathan Reeder of Wells Fargo.

Quick question. Looks like you guys tweaked around the usage projections for the full year and I kind of understand where you're going with industrial and commercial. But I was a little surprised to see residential move up. Can you, I guess, articulate if that's due to more customer growth? Or is it, I guess, household usage just based on the economic forecast?

A little bit of both. We forecasted an increase, maybe 18,000 customers in 2011. We picked up 15,000 last year, so we'll have some increase in usage on a per-customer basis as well. In the economy, we keep looking at these other indicators. And on our one slide, I think it was Slide 10, we pointed to a number of new industrial announcements with job -- increases in jobs. One of the -- one particular are these BRAC realignments, which will start moving some people into some of our residential markets. One in particular will be at Fort Benning, which will happen by September of this year. There'll be about 10,000 families moving into that particular area and a lot of that cannot be handled on, on-based housing, so there'll be some pickup on the residential side there. So our forecasts pick up some of those trends, and that's what we're looking at.

And our housing data continues to show steady improvement.

I think our unsold vacancies are 2.8%, normal is 2.3%.

And we had been as high as around 4%, 4.4%. So we continue to get down. And as we consume that inventory, I think, what you're seeing with some of the usage data is unoccupied houses.

Okay. So once -- kind of grow into that a little bit, the trend of weather normalizing as residential usage decreases, we should see a second half turnaround there?

That's -- and our forecast kind of contemplated a second half pickup.

And your next question comes from the line of Brian Chin of Citi.

In your conversations with Lisa Jackson and other folks at the EPA, did you ever get the sense that they might be a little bit less willing to extend the commentary period for the toxins rule as we get closer and closer to sort of the election cycle in 2012? I mean, you're not the first -- you guys certainly aren't alone in suggesting that the commentary period's a little bit too brief. I'm just wondering if you've gotten any sense -- are they feeling a little bit more pressure to try and get this thing wrapped up quickly?

Our conversation was -- I'll just say it was very engaging and very constructive. It didn't go to politics. But I think the statements that we're able to make here are really pretty clear and compelling. It's 1,000 -- roughly 1,000-page proposed rule, 1,000-page reporting documentation, some of which we haven't seen. And typically, on these MACTs, there's been like 9 of them done in the past, we've gotten kind of a minimum of 120 days and a maximum of a 180 days in order to respond. This is arguably the most complex, costly and biggest scale MACT that's ever been put in place. And so I think that those facts stand on their own. Listen, I think Administrator Jackson's heart's in the right place. We'll see what happens.

Great. And then one completely unrelated question. I remember at the end of last year, you guys got a very interesting reserve mechanism for operating and maintenance in Alabama. Is there a sense of at what level that reserve amount is at right now? Or can you comment on whether that reserve amount has grown over the last quarter?

Brian, at the end of the year, it was $48 million. And no, it did not grow at the end of the first quarter, so we're still standing at $48 million.

And your next question comes from the line of Nathan Judge of Atlantic Equities.

Just wanted to follow up on the actual implementation to spending on the additional environmental controls for the EPA’s HAP MACT rule. Just as it relates to how this gets put into rates, I believe this would be coming through an environmental writer, but in Georgia -- can you just remind me of do you have to actually ask permission to spend the money and what's the mechanism for that to happen? Do you book AFUDC, cash flow, et cetera?

All of the operating companies have environmental clauses. At Georgia, Georgia has an environmental clause as well, and my understanding of that is it does go through the 3-year rate-making process in order for it to be recovered under rates. If it's put into place before the rate hearing takes place, it's simply deferred until the next case.

Or in excess of what's allowed currently in the current 3-year plan. It would just be deferred until the next rate case. And I think our experience is in Georgia, we've never had a dollar of environmental spend not allowed.

In the interim, would you book some type of AFUDC? Or how would that actually -- or do we need to -- would we actually not see anything until the next rate case?

AFUDC is booked for any of the construction of environmental, if that was your question.

Okay. But you don't get any cash until after...

You know that's not true for Vogtle, but...

Yes, right. But back on the environmental, it's my understanding as you look at your CapEx and your rate base and things of that nature, that your 5% to 7% growth is not taking into consideration of additional spend on additional CapEx things such as the environmental area. Could you give us idea of how we can reconcile what you're looking for as additional spend on environmental and your long-term growth aspirations?

Well, as we outlined in our prepared remarks, the CapEx range over the next 3 years is $700 million to $2.9 billion, and those scenarios are all captured by our 5% to 7% growth estimates that we have outlined on earnings per share. So...

It's just [indiscernible] be higher in the range than lower in the range. But the range kind of adequately describes what we believe the future to be.

Yes. So at the $2.9 billion, we wouldn't see necessarily an increase in that growth rate.

That's correct.

Yes. Right now, we're at 5% to 7%. That is our guidance, long-term estimate.

Your next question comes from the line of Marc de Croisset of FBR Capital Markets. Marc de Croisset - FBR Capital Markets & Co.: Tom, thanks for all your commentary on the EPA rules. A quick question. You mentioned in your prepared remarks, I believe, 80 gigawatts of scrubbers potentially required from the proposed toxics rule. And that actually struck me as a large proportion of unscrubbed capacity in the U.S., and I'm wondering what it applies, if anything, about your views on national level or Southeast level coal generation retirements.

Yes. In fact, let me -- it would represent about 1/2 of the total U.S. coal because 1/2 of it is going to get closed down as a result of this rule, rough numbers. I think 70,000 megawatts nationally, and there's estimates around that. But 70,000 will be retired as a result of this rule. And therefore, the remaining scrubbers would be added to those that remain. Marc de Croisset - FBR Capital Markets & Co.: Got you. And when you look -- as a follow-up, as you look at your CapEx for forecast, and I understand it's hard to be very specific at this point, but you mentioned some pieces of equipment. I heard backhouses. I may have missed this, but with scrubbers in there, replacement gas generation? Did you have any sense for what the basket of CapEx might be composed of?

Yes, let me -- that is a wonderful question. But I've got to describe it this way: It's going to be one or 2 things, right? We are either going to control and therefore add a lot of environmental equipment. Now remember, we've got -- let's just say, round numbers, we have 20,000 megawatts of coal. 12,000 is what we consider our flagship units. All of our flagship units will have scrubbers, SCRs in place by 2013. And some of those have backhouses. Now with respect of the other 8,000, we have to make a decision on a unit-by-unit basis because of the complexity of the rule, and we will only know that until we have a final rule. Then we must make an assessment on a unit-by-unit basis. We must take into account transmission alternatives. We must design it, we must procure it, and then we must build it. That's why you need to build a scrubber. Our experience -- and we're more experienced at this than anybody in the industry, about 54 months from beginning to end to make those assessments. That's why the 3-year doesn't work. For those units that we do not control, we must replace, and therefore, we've got to make some assessment as to where that generating capacity will be. One of the problems that people are tending to wash away here is the fact that there is this belief that there's lots of molecules of gas in the ground, and it's at a reasonable cost. Well, we agree with that fact. The problem is that gas needs to get to where we need it in terms of generating capacity. And the pipe infrastructure does not exist to do that in this timeframe. Therefore, there has to be a build-out of gas infrastructure in order to support this evolution of our generating fleets across America. We think that is another critical issue that has not been taken into account in addressing these timeframes. So the final point I want to make here, too. This is not some theoretical national issue we are dealing with. These issues get brought to home in the localities that we serve, and there are potential enormous social consequences. When you shut down a coal plant or a similarly sized gas plant, you lose jobs on about a 6:1 ratio. And these typically are high-paying jobs. Remember, too, that these units are located in rural areas of the United States, largely, and that they may represent significant portions of the tax base of the communities that they are located in. And in fact, introduced some testimony in Congress a couple of weeks ago now, where for -- I think it was Putnam County in Georgia, the branch units represented about 19% of the tax base for that community. There are other examples in our territory where its number is far bigger than that. When you shut down those plants, what do you say to those communities and how they're going to run their business just to serve the public at large? These are enormous consequences and really reach to the heights of policy level issues, not just environmental issues.

And your next question comes from the line of Ashar Khan of Visium Asset management.

Tom, if I heard you correct, you expect 70 gigawatts to be retired as part of this law, higher than what the EPA has come up with? Is that correct?

Absolutely.

And then just, I guess, as I kind of look at it, and I discussed it a little bit at your analyst meeting, the easy way is to go to the President and get a 2-year extension and you don't have to go through this whole legislative process and everything. So why haven't you -- or I guess because it might lead to divided views among the sector, why haven't you guys just focused on that aspect of it, which seems to be the easiest way in terms of implementation? Is that really hard to achieve?

Yes. Listen, we've got a long track record of dealing with these kinds of issues. I know people are kind of amped up about all this. But here's our view. For any major kind of body of legislation, regulation, what-have-you, we always consider how to engage constructively, to get the best solution for reliability and a sensible economic impact for the benefit our customers. We will certainly engage in the regulatory process. We will certainly engage in a regulatory process. And if need be, we will undertake litigation if that helps clarify the issues at hand. So we're going to be doing all 3 in a parallel path.

But isn't getting the 2-year extension from the President the easiest way to achieve your objective?

It certainly is one way. The issue here, though, is we need to have -- remember what I said, you're going to have to go unit-by-unit, you're going to have to design, you're going to have to procure equipment and you're going to have to secure a source of craft labor, okay? So you need to know, in order to schedule that work, you need to know that you have sensible timeframes involved rather than trying to pancake control efforts and new capacity requirements, new pipeline requirements, everything on top of each other. There has to be a sensible way to do this. Even NRC, there's a whole national effort under way to get arms around this issue. If we were to get an extension from EPA and 2 years from the administration, that would be plus 3, gets it to 2018. That starts to make sense for us, but we would need to have that knowledge at the outset.

Your next question comes from the line of Dan Jenkins of the State of Wisconsin.

I was wondering if you could give a little detail, you gave the plan for 2011 on CapEx and debt issuance and so forth. I was wondering if you could update us on what you've done so far in 1Q, first quarter?

First quarter, we've issued about $1 billion of new debt. And the equity side, we've issued $193 million. And CapEx, we have spent right just over $1 billion on CapEx. I think our budget for the year is $4.9 billion.

So then based on that, what was the total debt balance at the end of the quarter?

I think we're around $20 billion. Yes, that's right.

Okay. And then I had a couple of questions just related to comparisons of the earnings. You mentioned that $0.01 of the other revenues is related to transmission, increased transmission revenues. Is that something that'll continue throughout the year or...

Yes, we expect that to continue. The UPS [ph] contracts, which expired in association with the Miller plant that I described, all of the transmission cost of revenues were recorded in one line item there as wholesale revenues. As those contracts were replaced with other plants, the revenue will be recorded as transmission revenue. So it will be picked up in that particular line item going forward.

And then the $0.05 on the wholesale revenues that you mentioned, is that also showing up then in the results for Alabama Power on the last stage of the release?

Yes, that's correct.

Would there be any sort of -- since that return to the retail jurisdiction, would you see some sort of a gain then on that side as that goes into retail rate base or...

Well, the allowed retail rate base -- allowed range of returns in Alabama are 13% to 14.5%. So it depends on the operations of that particular rate and how that particular plant impacts the operation of that rate.

And then the last thing I was wondering, you mentioned on the $0.12 was primarily on the retail revenue impacts was primarily Georgia. How much of that was Georgia? And will that be continuing as the quarters go on?

I believe all of that was Georgia Power. There were no operations at Alabama Power of RSC this year. There's a little bit of Alabama Power, excuse me, from their environmental clause, but it's very small. Maybe $0.01 of the $0.12. But no other operations at Mississippi or go [ph].

So will that Georgia impact continue on a quarter -- year-over-year comparison basis?

Yes.

Your next question comes from the line of Vedula Murti of CDP.

I wanted to make sure -- following up on what Jonathan Reeder was asking about in terms of particularly residential sales growth, I want to make sure if I thought about -- if I heard the numbers properly. If you're down 0.9% in the first quarter on weather-adjusted basis, and for the full year, you're expecting a positive 2.3% on a weather-adjusted basis, I know you indicated we're going to see a significant acceleration in the second half of the year, and you cited some examples. Given the other aspects that you cited such as gas prices and other things like that, am I thinking that we really need to see 3%, 3.5% the rest of the way in order 2.3% or am I comparing apples and oranges here?

Well, when we prepared that forecast, it was probably mid- to somewhere around mid-2010 when we prepared that forecast. And we obviously didn't pick up any of the $100 price of oil in our forecast at that time. There's also other noise and weather data that we experienced that it's just very difficult to extract all that particular noise. So -- but we still feel like the growth in the sales will come the second half in both sectors, both residential and commercial.

And even if it doesn't, I mean where we've been off on our forecast has been in industrial. It's been way outstripping what we thought. What was our original industrial estimate?

2.9.

And it's been 6.7.

Right.

So I mean that happened all last year. It looks as if that'll happen also this year. And then remember, if you want to weight average the sales, substantial part of our sales occurred June through first 2 weeks in September, so we'll see what happens there.

So maybe just so let's put in context, a 1% differential on weather-adjusted residential growth, what type of gross margin differential for a full year would that kind of roughly amount to?

That's about -- if you spread it across all classes, a 1% increase is about $0.075.

That's against all classes.

Then, residential would be like maybe 1/3 of that or something?

Yes, that's right.

And you have a follow-up from Andy Levi of Caris & Company. Andrew Levi - Caris & Company: Vedula kind of brings up a good point. And I guess, is there any flexibility if the sales don't come around to cut costs as far as O&M or other areas of the company?

Sure, absolutely. We have that flexibility, and that's all buried into our range as well. That's why we give you a range in earnings per share growth. Andrew Levi - Caris & Company: Okay. And then one other question. On an earlier call, one, I guess, it was not your competitors, but another large utility was talking about EPA rules, and they were discussing power prices looking forward. And I'm just wondering what you guys view as -- again I know you're mainly regulated. But I guess their view was that power prices in the $14, $15, they got as far as $16. But the power prices weren't reflecting the new EPA rules. And so I was wondering what your views are on that.

Well, listen, I'm going to speak to our markets. Interestingly, just letting all this happen in a disorganized way actually serves to accelerate our net income. But we think that is bad for our customers. Our interest is in providing a long-term view and providing the best reliability at the lowest prices with the best customer satisfaction possible. That is what we are for. Andrew Levi - Caris & Company: But again you have no view on long-term wholesale prices?

No view on their markets.

And at this time, there are no further questions. Sir, are there any closing remarks?

Well, listen. I just want to say thank you all for joining the call. It's an exciting time at Southern. We got a lot going on and a lot to be positive about in the future. This industrial growth, we think, will sustain and we think eventually, residential and commercial will follow with it. And we'll continue to follow through on our disciplined approach to our business with our conservative outlook and our focus on customers. Thank you very much.

Ladies and gentlemen, this does conclude the Southern Company First Quarter 2011 Earnings Call. You may now disconnect.