Dan Tucker – VP, IR Tom Fanning – Chairman, President and CEO Art Beattie – EVP and CFO

Dan Eggers – Credit Suisse Steve Fleishman – Wolfe Trahan Greg Gordon – ISI Group Jonathan Arnold – Deutsche Bank Julian Dumoulin-Smith – UBS Paul Ridzon – KeyBanc Michael Lapides – Goldman Sachs Carrie Saint Louis – Fidelity Ali Agha – SunTrust Mark Barnett – Morningstar Andrew Levi – Avon Capital Ashar Khan – Visium Dan Jenkins – State of Wisconsin Investment Board Paul Patterson – Glenrock Associates

Ladies and gentlemen, good afternoon. My name is Elaine and I will be your conference operator today. At this time I would like to welcome everyone to the Southern Company First Quarter Earnings Call. (Operator Instructions) As a reminder, this conference is being recorded, Wednesday, April 24, 2013. I would now like to turn the call over to Mr. Dan Tucker, Vice President of Investor Relations and Financial Planning. Please go ahead, sir.

Thank you, Elaine. Welcome everyone, to Southern Company’s First Quarter 2013 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. Various important factors 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. In addition, we will present non-GAAP financial information on this call. Reconciliations to the applicable GAAP measure are included in the financial information we released this morning, as well as the slides for this conference call. Please note that today’s call and webcast are audio only, which means we will not be displaying slides during the presentation. You can follow along by accessing the slides posted on our Investor Relations website at www.southerncompany.com. Tom will open today’s call with an update on Plant Vogtle and the Kemper project and Art will then provide an overview of our first quarter financial results, as well as a discussion on sales and the economy. After closing remarks from Tom, we’ll move to Q&A. At this time, and I’ll turn the call over to Tom Fanning.

Good afternoon, and thank you for joining us. During the first quarter of 2013, Southern Company continued to fulfill our primary mission of providing clean, safe, reliable and affordable energy and doing what’s best for customers in the communities we serve. An important component of this work is the progress we’re making with our major construction projects. At Plant Vogtle Unit 3, we’ve recently completed the placement of basemat structural concrete for the nuclear island, pouring approximately 7,000 cubic yards of concrete in 41 hours. At Unit 4, the nuclear island foundation is now complete and column setting is underway. The full outlines of both nuclear islands have been completed to grade level and overall construction on the units is more than 40% complete. As you can see on the slide over the next quarter, we expect to install rebar for Unit 3 auxiliary building walls and also set the containment vessel bottom head and structural steel for Unit 3. We further expect to complete installation of the upper mud MATS and begin nuclear island rebar for Unit 4. Georgia Power also received unanimous approval from the Georgia PSC on its seventh construction monitoring report and recently filed a date report, which included the following: a request that the PSC verify and approve all costs, totaling $209 million, incurred between July 1 and December 31 of 2012. I requested the PSC amend the existing certificate to reflect revised commercial operation dates the fourth quarter of 2017 and 2018 for Units 3 and 4 respectively. And a request that the PSC amend the existing certificate to reflect an increase in the projected total capital cost from $4.4 billion to $4.8 billion, with the associated increase largely driven by schedule related costs, as opposed to brick-and-mortar costs, which remained stable. A projection of total impact on customer rates of between 6% and 8%, once the units are in service. And finally, a determination that the extended construction schedule will not increase costs to customers. Meanwhile, progress continues at the Kemper project in Mississippi, as we continue with startup activities. Last month, consistent with the settlement agreement we reached in January, the Mississippi Public Service Commission approved a two-step rate increase associated with the Kemper project. The settlement agreement contemplated a seven year plan with no further changes to base rates for Kemper project, through 2020. And Mississippi Power recently made its necessary filings with the Commission. This rate mitigation plan is expected to be addressed by the Commission this fall. We continue to make tremendous progress at the Kemper site. With most of the major components in place, the combined cycles, gasifiers, massive gas absorbers and Ignite dome, as well as, the 75-acre reservoir, the facility’s appearance reflects our progress with start-up activities, which are now 40% complete. With the final engineering almost complete, the activities leading up to commercial operation include the very meticulous work of bringing the installed components together through sophisticated piping, cabling and control equipment. Our current cost estimates for the project has increased, based primarily on matters related to piping. We’ve improved the quality and increased the quantity of the pipe and increased the amount of labor needed to achieve our in-service dates. Art will speak to the financial implications of the current estimate, in a few minutes. While disappointed with the estimated cost increases, we remain accountable to customers. In light of our agreements with the Mississippi Public Service Commission, we will not seek recovery of these increased costs, which exceed the $2.88 billion cost cap, established in the Commission’s 2012 certification order, net of the DOE grants and cost cap exceptions included in that order. Our current plan is only to seek recovery of the capital and variable cost components already reflected in the seven year rate plan, recently filed with the PSC. The revised construction cost estimate reflects the company’s current analysis of the cost to complete the Kemper project. We continue to believe that the scheduled in-service date is achievable. As with any project of this magnitude and complexity, we will continue to evaluate the estimated project cost and schedule as we proceed towards completion over the next year. We are proud of the trig technology being implemented at the Kemper project. This facility is expected to produce energy, with a variable cost approaching the cost of nuclear, and with a carbon footprint less than a similarly sized natural gas plant. We remain focused on bringing this 21st century coal project to successful completion for the long-term benefit of our Mississippi customers. We will keep you posted as startup activities continue. Meanwhile, we continue to expand our use of renewable energy sources with two major announcements taking place just this week. The first of these is the acquisition by Southern Power and Turner Renewable Energy of our largest solar installation to date, the 139-megawatt Campo Verde Solar Project, the partnership’s fifth solar acquisition and its first in California, Campo Verde more than doubles the Southern Company’s system solar capacity. The project will be built, operated and maintained by First Solar, a leading global provider of thin film photovoltaic systems and is expected to begin operation this fall. The second, is an announcement by Georgia Power that it has entered into an agreement to purchase energy from two wind farms in Southwest Oklahoma, with capacity totaling 250 megawatts, beginning in 2016. All of these projects represent key elements in our ongoing effort to build a truly diversified generation portfolio, all for the benefit of the customers and communities we serve. I’ll now turn the call over to Art for our financial and economic review.

Thanks, Tom. For the first quarter of 2013, we earned $0.09 per share, compared to $0.42 per share in the first quarter of 2012, a decrease of $0.33 per share. Included in these results is after-tax charge, against earnings, of $333 million or $0.38 per share, related to the current cost estimate for the Kemper project. As Tom mentioned, Mississippi Power will not seek recovery of these estimated costs to complete the facility above the $2.88 billion cost cap, net of DOE grants and exceptions to the cost cap. Also included is an after-tax charge of $16 million or $0.02 per share for the restructuring of a leveraged lease investment. Excluding these items, we earned $0.49 per share compared to $0.42 per share in the first quarter of 2012, an increase of $0.07 per share. Earnings drivers for the first quarter of 2013 can be viewed in detail on this slide. However, two factors in particular influenced our year-over-year adjusted earnings. Weather, and retail revenue effects at some of our traditional operating companies. Weather in the first quarter of 2013 added $0.05 per share to our earnings, compared with the first quarter of 2012. Weather is actually $0.01 per share below normal for the first quarter of 2013 but that was compared with $0.06 below normal for the first quarter of 2012. Heating degree days during the first quarter of 2013 were 54% higher than the first quarter of 2012. The other significant driver for the first quarter of 2013 was retail revenue effects at several of our traditional operating companies, which contributed $0.04 per share as compared to the first quarter of 2012. Turning now to a discussion of our retail sales results for the first quarter of 2013. Total weather normal retail sales for the first quarter of 2013 decreased 0.9% compared to the first quarter of 2012. Weather in normal residential sales decreased 0.9%, weather normal commercial sales increased 0. 4%, and industrial sales decreased 2.1% compared with the first quarter of 2012. If total weather normal retail sales were adjusted to reflect one less day in the first quarter of 2013 due to the leap year in 2012, overall retail sales growth would have been closer to flat. If applied to each of the respective customer classes, residential sales growth was essentially flat, commercial sales growth was more positive than reported and industrial sales growth was roughly half as negative as the reported results. Residential sales were affected positively by 13,000 new customers added in the first quarter of 2013. About half of those new customers were new connects, further evidence of a rebounding housing market and a strengthening economy across our four state service territory. Our economists have produced a recent analysis suggesting that 88% of any shift in residential usage is accounted for by three factors: weather, the price of electricity and changes in personal income. In the first quarter, we saw a weakness in personal income and we believe the biggest contributor to that may have been the increase in federal payroll taxes. We believe this factor could have limited growth in our first quarter usage per customer metrics. The increase in commercial sales represents the strongest growth in this customer class in a number of years, and yet another signal that the economic recovery continues. This is also consistent with retail expansion activity in the region. As previously noted, industrial sales declined in the first quarter of 2013 compared with the first quarter of 2012. This result is consistent with reports indicating that exports from the region declined in the first quarter of 2013. However, a number of declines in sales resulted from temporary outages associated with new plant investment as well as unplanned maintenance and other short-term factors. Some customers have indicated to us that they expect to return to normal operating levels of production for the remainder of the year. The outlook for future industrial sales and growth in the industrial economy are supported by a number of factors. For instance, manufacturing employment in the Southeast, thus far in 2013, has grown at almost twice the national rate and regional indices of manufacturing activity are much stronger than they were just a quarter ago. Additionally, our pipeline of economic development projects remains robust. Recent job announcements of greater than 1,000 jobs include Home Depot which is creating 2,200 customer service jobs in Kennesaw, Georgia. General Motors which is creating more than 1,000 high-paying IT jobs in Roswell, Georgia. The Navy Federal Credit Union, which is adding 1,500 back-office jobs in Pensacola, Florida and Medium which is building a new, $90 million movie studio in Savannah, Georgia that will employ more than 1,200 workers. Sales results for the first quarter of 2013 were consistent with our expectation that GDP growth in 2013 would be 2% and would occur primarily during the second half of the year. Despite the headwinds, we’ve mentioned earlier, we continue to see positive signs of emerging economic growth, such as increased expansion of retail stores, continued renovation and expansion of food service locations and continued growth in sales tax collections. However, the uncertainty in the overall economic outlook continues. Turning again to company financial news, our Board of Directors voted earlier this month to increase Southern Company’s common dividend to an annual rate of $2.03 per share. This marks the 12th consecutive year that our dividend has increased. In fact, since 2002, our dividend has increased total of 51%. This 12-year trend is a direct reflection of the positive outlook we continue to maintain for our business and the region that it serves. We remain steadfastly confident that the business fundamentals of the Southeast provide a solid foundation for a promising future and Southern Company is proud to be a part of it. Finally, I’d like to share with you our earnings per share estimate for the second quarter of 2013, which will be $0.68 per share. As a final note, in light of the Kemper charge, we remain committed to our annual guidance range and our long-term EPS growth target. I’ll now turn the call back over to Tom for his closing remarks.

Thanks, Art. In closing, I’d like to talk for moment about our nation’s economy and the great opportunity our industry has to help make things better. As you know, Southern Company’s business is all about doing what’s best for our customers. It’s a philosophy that goes all the way back to our founding and it’s an area in which we continue to excel. In fact, Southern Company was just named the top-ranked major electric utility in the 2013 American Customer Satisfaction Index. Down through the generations, Southern Company employees have always focused on making life better for the families and communities we serve. Our customers deserve that commitment. It’s central to our legacy and it’s an especially crucial role for us today given the difficult economic climate faced by many of our customers. By now, everyone knows the issues with the economy. Low sustained growth and unacceptably high unemployment. The problem isn’t solely tied up with reduced spending or higher taxes, the real solution lies in promoting sustainable economic growth, that will support more job creations and personal income growth, and make American lives better. Our industry is uniquely suited to support that outcome. In fact, since 1970, nearly 80% of the growth in energy consumption has been driven by the electrification of the American economy. Energy producers are central to the economy and central to the lives of American families. In short, energy is growth capital and we need to do everything we can as a nation to ensure a clean, safe, reliable and affordable supply. With that in mind, we have been promoting in industry initiative across the energy complex, which includes oil, natural gas and electricity to address the issue of North American energy security. The goal is to develop and market our vast supply of energy resources so that by the end of this decade, North America can become a net energy exporter, and perhaps later, the largest producer of energy worldwide. Think about it. Our current energy policy is predicated on the concept of scarcity. In fact, we can turn that premise to one of abundance. Southern Company is committed to playing a leadership role to help North America, and particularly the United States, achieve that aspiration. I will keep you apprised of our progress. In the meantime, Southern Company will continue to excel at the fundamentals of our business, finding the best ways to serve our customers in the Southeast, while building better communities in a better country. We are now ready to take your questions so, operator, we’ll now take the first question.

Thank you. (Operator Instructions) Our first question comes from the line of Dan Eggers with Credit Suisse. Please go ahead. Your line is open.

Hello, Dan. Dan Eggers – Credit Suisse: Hey. Listen I guess this is going to be the topic of the day for little while, but just on Kemper, can we discuss a little bit more what caused the 20% increase effectively in project costs from where you guys most recently thought it was going to be to where you are today? Just maybe explore what’s driving that a little more than just a piping comment?

Yeah, sure. So as we approach these last 12 months essentially, we were looking over our estimates of what it is going to take to complete and to make the in-service date. There were kind of a number of different issues we outlined broadly, but with respect to the piping, we made the decision to essentially improve the quality of it, improve the thickness, improve the metallurgy. We think that will provide the best long-run answer to the reliability of the plant and serve Mississippi customers for decades to come. So we improved that. Secondly, we miss-estimated the amount of piping that we would need so we increased the amount of piping that was associated with this project. And then I guess finally, we have added another shift, essentially an overnight shift, to getting the work done by the in-service date. So it really is kind of a function of more labor and a revision of our labor productivity estimate. Dan Eggers – Credit Suisse: And, Tom, when you think about, I guess the first question on that, is there any ability for money to come back from the E&C guys so you’re not going to take the full tab on this? Or is this kind of thing to sit on your cost level?

Well, this is our best estimate of what it’s going to take in order to complete by the in-service date. To the extent we under-run then yeah, there would be an adjustment at the end of the process. Likewise, if it takes more, there would be another adjustment over, but that is our best estimate currently. Dan Eggers – Credit Suisse: But I guess, you know with Vogtle there’s some debate over whether the E&C providers are responsible for some of the cost overruns and delays. Is there a similar recourse ordebate of recourse with Kemper that you guys could try and get some of the $500-ish million covered by your E&C guys rather than you guys paying for it?

Well, remember, Kemper and Vogtle are completely different, right, so let’s think about Kemper. Remember, this is our technology, our design, our construction effort, certainly have subcontractors but this is our responsibility. And recall we already have a settlement agreement in place with the Mississippi commission that provides for in total about a 19% net increase. When you look at Vogtle, we have a completely different arrangement. That is we have a turnkey contract with the consortium that’s Toshiba, Westinghouse and Chicago Bridge and Iron. And while we have made modifications to that contract over time to the benefit of our customers, we feel that it is a completely different relationship than in Kemper where we are solely responsible for executing on the project. We are responsible for Vogtle, but we have commercial relationship with the consortium. Further, when you consider the cost impacts on Vogtle, it’s pretty clear it’s a different matter. When we originally certified the plant we thought it would be 12% increase. Now with the additional cost but moreover the overwhelming additional benefits, we think that price increase now is reduced to somewhere between 6% and 8%. And while in VCM 8 we did increase the schedule, there will be no costs that will show up in rates to customers associated with that change in schedule. And further, when we think about the remaining price increases associated with completing Vogtle to in-service, we believe those price increases are somewhere less than 1% per year. So it’s a totally different ballgame. Kemper we already have a settlement agreement, Vogtle we have a process in place at the VCM hearings and a variety of other things, a different commercial arrangement, a different price impact. We just think they’re completely different. Dan Eggers – Credit Suisse: Okay. Thank you for clarifying that. I guess one last question on Vell and I’ll let somebody else talk, but Art, on the – with the charge do you guys need to change your equity proceed expectations for this year and next year just to balance out your balance sheet?

Yeah, we’ve – we kind of outlined on the last call that we had plans for $0 to $300 million but that was kind of contingent upon Southern Power’s projects. Let me say first off that we’re committed to the credit quality that our customers enjoy the benefits of. We will support Mississippi Power in their – getting their cap structure in a shape that it was contemplated in the seven year rate plan that they filed. So how we finance that, how we downstream cash to Mississippi Power is a function of what we – how we do it at Southern. And our intention is to address that over a period of time such that we’re not going to issue a slug of equity immediately to make up that delta. And when you look at Southern Company’s ratio, it would drive our ratio down a little bit below 43%, so we’re not that far away from the target ratios that we established for Southern Company. So we’ll get back to that over a period of time.

And even the ongoing net impact of additional shares whenever we decide to issue shares is really pretty minor. I think the sustaining cents per share impact is like $0.03 per share associated with this if we sold all the amount of shares right away, which we don’t intend to do right away. So – and just recall, last year we had negative $0.11 of weather. I think when Art says that we’re committed to our annual guidance and our long-term growth aspirations, I think we can manage this circumstance quite well. Dan Eggers – Credit Suisse: Got it. Thank you guys.

You bet. Thank you.

And now our next question over the phone lines is from Steve Fleishman with Wolfe Trahan. Please go ahead. Your line is open.

Hello, Steve. Steve Fleishman – Wolfe Trahan: Hi. Hey, Tom. How are you?

Great. Steve Fleishman – Wolfe Trahan: So just same topic, just in the event that Kemper comes on after May of 2014, is there any issue if it doesn’t mean it’s targeted start-up with your settlement or anything like that?

Yes, Steve. This is Art. There are, yeah, certainly the issue around investment tax credits is time sensitive. So that represents roughly $133 million and it’s contemplated in our 7-year rate plan that has been filed with the Mississippi commission. There may also be some issues around the AFUDC especially with the certainly the portion that would exceed the $2.88 billion where we would not continue to accrue AC/DC on that portion but then a question about the remaining balance of AFUDC and whether or not you’d be able to continue to accrue on that balance as well. Steve Fleishman – Wolfe Trahan: Okay. And this is just any time after May of 2014 these questions come up or is it a certain time after that?

No. We think would be that. In other words, the structure that we have crack AFUFC be up to $2.88 billion. Beyond $2.88 billion given the higher cost increase that could occur earlier than say May. So you could see that effect going on. As Art mentioned the ITC effect would be something you would see ratably over the 7-year period and within that structure there’s a true provision and a variety of other things so we’ll just have to see how that would work out. Steve Fleishman – Wolfe Trahan: Okay. And just...

Hey, Steve. The ITC would be reflected over 30 years so there would be the annual effect of that over the 30 years so we think it would be kind of small. Steve Fleishman – Wolfe Trahan: Okay. And then in terms of the remaining risks in terms of the current budget, is there certain area that we should be most watchful of where there still could be risk of cost pressure in these last 12 months?

Well, recall this is a first of its kind technology although we’re confident of our ability to deploy it. What we have said before probably the larger risk in front of us right now goes to the instrumentation and control equipment. Harmonizing the operation of the plant from the fuel intake of lignite to the gasification to the stripping out of the CO2 to the remaining synthesis gas going on to the combined cycle units and producing electricity. Harmonizing the operation of the plant I think is probably what we are most focused on. Now we have put in place for some time now a simulator where we have modeled how this is supposed to work. We mentioned before that we’re already 40% through start up activities. Those start up activities have been mostly focused on the combined cycle units some of the other ancillary areas around the plant so the big effort is going to be start up around the gasifier and the carbon capture equipment. It’d be those issues. I would say instrumentation and control would be the biggest single issue. Steve Fleishman – Wolfe Trahan: Okay. And then one last question just on the variable cost of the plant in the future based on any of these changes, does that affect whatever you expected the variable cost of the plant to be in the future? Either good or bad...

No, we think on a GAAP equivalent basis you’re going to be somewhere between $1 and $1.25 per million BTU. High capital cost but cheap energy and recall the energy is influenced by the value of the CO2 which is indexed the price of oil which pays for substantial portions of the lignite fuel. The net effect is a very promising energy cost for decades to come for Mississippi’s customers and we have great certainty. We don’t think there’s going to be much volatility at all in the fuel price because we own the mine and it’s right there. This is essentially a mine now operation. So low volatility... Steve Fleishman – Wolfe Trahan: Okay. Great. Thank you very much.

You bet. Thank you.

And now our next question comes from the line of Greg Gordon with ISI Group. Please go ahead. Your line is open.

Hey, Greg. Greg? Greg, are you there? Greg Gordon – ISI Group: Yeah, I’m here. Sorry about that.

No problem. Greg Gordon – ISI Group: I had two questions but you answered the first one on the financing cost of the write-down. The second one is just looking at the Appendix when you show your generation portfolio past through factors in mix.

Yes. Greg Gordon – ISI Group: Natural gas prices have run-up quite a bit in the first quarter.

Yes. Greg Gordon – ISI Group: I’m surprised to see that you saw such a dramatic increase in Powder River basin coal burn. I’m not necessarily surprised that your non-CRB coal burn is about the same. Can you talk about what the dynamics were in the quarter that led to that and then maybe extrapolate out into the next quarter – the rest of the year based on where gas and coal prices are now?

Yeah, sure. Look, me and Art will tag team this one. The way to think about kind of our coal to gas energy is really this. PRB is going to come in to dispatch somewhere in the $3 range, $3 to $4. SO at $4.25 spot gas you’re running PRB in a sense, right? So that’s Shearer, that’s Miller. And interestingly as we evaluate other kind of mixing of PRB in with regular coal, that will happen. Now the other thing is, we’re moving away from Central App coal more to Illinois basin coal. When you look at those units, the Illinois basin coal, they’re going to start dispatching at about the $5 range. Central App will still be kind of in the $6 range. So that would be the spread in which you should look to see coal and gas switching. Art, do you have anything to add to that?

Yeah, I’ll just point out, Greg, that at, right at the end of the month if you look at our dispatch, curve all the Miller units and at least three of the Shearer units were ahead of our most efficient gas unit. So that gives you an idea about how sensitive those PRB units are to the gas price in the marketplace.

And the everything is – go ahead Greg. I’m sorry. Greg Gordon – ISI Group: I was going to ask how you’re coal piles in relation to finishing up the answer to this question. How you’re coal piles look? I mean how flexible are your contracts such that you can have the facts to be able to look at this cycle as these prices move against each other?

Yeah, well they’re higher than we want but we have plans in place to work them down by certainly 2014 and into 2015. We have plans in place. We’ve done all sorts of different things to manage this situation. Normally, we would be about kind of a 40-day supply right now and we’re kind of in the mid-60’s. It varies by plant, to plant, to plant but we have plans to get it all down and placed by the right time. Greg Gordon – ISI Group: I would guess where it is now that’s going to bring your PRB pile down pretty fast, right?

It sure will. It’ll help us manage them faster, that’s for sure, relative to where they were last year. Hey, interesting data, interesting data. In the first quarter of 2012 average gas price was $2.50. In the first quarter of 2013 average gas price was $3.50, spot price $4.25. Remember our cautionary kind statements about gas and while we’ve made the big bet to gas we remain convicted that it was more volatile than other fuel sources. I think the data just bears that out. And one of the things I was going to add was one of the other blessings we have by the people who came before us was deploying a lot of combined cycle technology so that we have great flexibility in being able to move between coal and gas in a short amount of time. When we think about it we could go as high as something like 57% gas and 22% coal and as high as, oh I don’t know, 30%, 45% wait a minute, 45% coal 35% gas if coal gets cheap relative to gas. So we can swing significantly here. Greg Gordon – ISI Group: Thank you, guys.

You bet.

And now our next question comes from the line of Jonathan Arnold with Deutsche Bank. Please go ahead. Your line is open.

Hi, Jonathan. Jonathan Arnold – Deutsche Bank: Hi. Good afternoon, guys. My first question on demand. I know you’ve been saying that you anticipated the first half of the year would be slower than the back half. But the 2% decline you saw in industrial having seen an up quarter I guess in the fourth quarter. Was that sort of kind of what you had in mind? Or more severe, less good than the outlook you gave 3 months ago?

I’ll answer you first and then Art fill in. Look, 2% I think adjusting for leap year is 1%. If you just the outages that we saw with variety of kind of big guys like Mercedes-Benz, like Chevron like others, we were probably nearly flat on industrial which is not far off of what we thought.

Yeah, that’s true. There were some other impacts we had with cogeneration going on at some of our large paper customers. So that has an impact year-over-year as well. And that’s still a function of gas price and where that goes.

The other thing I would say is going back to this kind of economic development and the new announcements, those are really the headlights on kind of where we see our industrial sales going. That’s awfully bullish. Gee whiz. Four projects at 6,000 new employees, good jobs. When you look at our manufacturing employment being 1.8% versus the national average of 1%, it looks bullish to us. So I would just say look, adjusting for all these things, it’s generally in line with our expectations and we look forward to seeing how it unfolds. If I had to say, is there a weakness? I would watch out for the global economy in exporting. Jonathan Arnold – Deutsche Bank: Okay. Thank you. Thank you, Tom.

You bet. Jonathan Arnold – Deutsche Bank: And then just on the way you presented the numbers generally, you obviously have this item you excluded on a leveraged lease. Can you just talk us through why you’re pulling that out? I mean in the past, you’ve – typically, there’s been a pretty high bar for Southern Co. to exclude a one-time item from numbers.

Well, that was. I’m sorry, Jonathan. That was a – go ahead. Jonathan Arnold – Deutsche Bank: No. You go on, I’ve stated the question.

Okay. That was a leveraged lease that we were the equity and tax owner of. We entered into that lease back in 2002. The lessee had significant operating performance problems with the plant and was unable to get cash flows high enough to make the debt payments. So we had disclosed this in the 10-K, I think as long as a year ago, describing our options here. We could’ve written off the entire investment at about $90 million or get the bondholders to agree to a restructuring, which is what we’ve done. We’re actually going to put some additional investment into the plant. We are going to act as a general contractor to the new lessee and we believe that the accounting rules required us to book a restructuring charge of – after-tax of $16 million or so, and that’s basically the long and short of it. Jonathan Arnold – Deutsche Bank: Okay. Thank you. Guys, sorry, one more issue?

Yes. Absolutely. Jonathan Arnold – Deutsche Bank: Of the – on – there was a – I think there was talk before of some securitization angle around Kemper. Is that...

Yes. Jonathan Arnold – Deutsche Bank: Still something you’re contemplating? And could you just remind us what was going to happen there?

Yeah, sure. That was part of the regulatory settlement we reached earlier this spring, so in essence, additions to rate base are $2.4 billion of the plant, the mine and the CO2 pipe. Beyond the $2.4 billion of the plant, up to $2.88 billion of the plant is plus AFUDC and some other items, goes to securitization. And we have estimated that amount to be between $700 million and $800 million. Recall, we had legislation provided for an amount of about $1 billion, so we currently contemplate using somewhere between $700 million and $800 million of the $1 billion securitization available to us. Jonathan Arnold – Deutsche Bank: Right. And then obviously as you’re eating everything above $2.88 billion on the plant, that’s not part of that discussion.

That’s right. We’re very clear though that there are exceptions to the cap which remain in place. And remember those are force measure change in law, beneficial capital or project development allowances, is essentially actions we take on the plant site while we’re building it to improve its performance. Those things remain exceptions to the cap. Jonathan Arnold – Deutsche Bank: So you’ve talked about in the answers to what’s going on at Kemper that some of these things were improvements designed to enhance performance, so how much – can you give us a number of what the exception piece is likely to be your view of it?

Well, we don’t – anything that we’ve talked about so far, it does not apply to the regulatory agreement that we struck so far. So when we struck that settlement agreement, remember there was a settlement agreement and there were two pieces of legislation passed through the Mississippi House and Senate and there was a vote by the commission to approve all of that. And then we have remaining in front of us the approval of the seven-year plan, as well as prudence hearings. Given all of that work, when we came up with the increased estimate, we’ve felt bound by the settlement agreement we reached and all the agreements we reached with the parties involved, and elected ourselves not to charge customers for any of these cost increases. Jonathan Arnold – Deutsche Bank: Okay. So even if they could technically fall under the exception, you’re choosing not to.

Not with these. These costs we’re talking about don’t fall under any of those exceptions. To the extent something arises in the future, conceivably they could, but not the cost were talking about today. Jonathan Arnold – Deutsche Bank: Right. Thank you, Tom. Sorry to be slow on that.

Oh, no, no, no, no, no. Thank you.

And now our next question comes from the line of Julian Dumoulin-Smith with UBS. Please go ahead. Your line is open.

Hey, Julian. Julian Dumoulin-Smith – UBS: Hello?

Hello? Hello? Julian Dumoulin-Smith – UBS: Hey. It’s Julian here. Can you hear me?

Oh, absolutely. Julian Dumoulin-Smith – UBS: There we go. So I wanted to ask you guys about coal ash here and what your expectations are as far as it goes with respect to the latest that came out of D.C.?

So you know we’ll see. There’s still a lot of work to go. Our expectation is that at the end of the day they’ll find it nonhazardous would be my simple answer, and that the kind of effective period in which will be able to adjust to whatever new regulations we’ll have some time to do that well into the future. You know there are some significant capital costs associated with whatever EPA has us do with coal ash. At one time that was in our three-year budget. Our sense is now that there won’t be any significant capital in the three-year period that we disclose in our estimates to you guys. In the aggregate, however, depending on how these rules come out and we’re going to be as engaged as we always are, these could easily result in compliance costs that exceed our incremental cost from that. We just believe these costs including coal ash, effluents and 316-B will likely be outside the three-year estimate period now. Julian Dumoulin-Smith – UBS: Great. And then does the – what came out here on the effluent side, does that change what you’re talking about at all? And just in terms of the time when you talk about three years, in what kind of timeframe are we ultimately talking here?

Well, it’s way early to assess kind of where we are. We’re still evaluating all that stuff. We think we have something that is workable and it’s a 400 page rule and we’re going to just dive through it as we do here at Southern and we’ll respond back to EPA in due course. Julian Dumoulin-Smith – UBS: Great. Thank you very much.

You bet.

And now our next question comes from the line of Paul Ridzon with KeyBanc. Please go ahead. Your line is open. Paul Ridzon – KeyBanc: Yeah, hey, there.

Hey, Paul. Paul Ridzon – KeyBanc: I just had a question kind of what’s still open at Kemper? And if there were further escalation where could we see that happen?

It’s kind of what we chatted about already. The regulatory process I described still in front of us is approval of the seven-year rate plan which was contemplated in the settlement. And the other thing still in front of us are prudence questions, okay. Paul Ridzon – KeyBanc: Okay.

So we’ll do a prudence review of building the plant. Paul Ridzon – KeyBanc: I guess I was asking what engineering is not done? I mean could you – are there like other piping issues that could arise?

I really think the issue there goes to kind of what I described before. It’s going to go to as we complete startup activities, recall we’re 40% complete right now so what startup remains goes to the I&C question, instrumentation and controls; and then recall one of the big cost drivers going forward here that gave rise to our new estimate had to do with labor and productivity and meeting our in-service dates. So we’ve got to hit our productivity levels. Paul Ridzon – KeyBanc: Okay. With regards to the ITC, when does the plant have to be up to qualify for that?

Well, there are several phases of ITC involved here. Phase I is a time sensitive phase and it has to be in service by I think May of 2014 in order to qualify for those. The second phase relates to the amount of carbon capture that we’re successful with, and those I think expire some time in 2016, April of 2016. We have also, Paul, applied for some additional Phase III credits but that would require that we exceed 70% carbon capture, and we’re just not sure that we’re going to qualify for those particular credits, but we have applied for them. Paul Ridzon – KeyBanc: And then can you just talk, you gave second quarter guidance kind of the drivers to think about, the ins and outs of what’s going to happen between the two quarters?

Well, if you think about just the revenue effects, you’ll see more revenue effects in the first quarter than you will in the second because you had some increases in the second quarter of last year related to McDonough primarily and some issues I think at Gulf Power. So those will probably reduce somewhat. It’s mostly based on our low growth and our experience around what we expect on the O&M side. That’d be the drivers that I can think of off the top of my head. Paul Ridzon – KeyBanc: What was weather like last year, do you recall?

I think weather was $0.01 positive in the second quarter of last year.

But of course, the second quarter is not a big weather month anyway.

No.

And the weather’s been sort of screwy. We actually had more revenue in March than we did in January for the first time in anybody’s memory around here. It was really weird looking. Our 80-degree days, January was warmer than February, which was about equal to March. It was a very strange quarter, even though in the aggregate it was normal probably. Paul Ridzon – KeyBanc: Got it. Thank you very much.

You bet.

And our next question comes from the line of Michael Lapides with Goldman Sachs. Please go ahead, your line is open.

Michael, how are you? Michael Lapides – Goldman Sachs: Hey, guys. Just a quick update if you don’t mind. I remember last year there was some litigation or, I think, mediation regarding the contractors, the Shaw/Westinghouse Consortium...

Oh, sure. Right. Michael Lapides – Goldman Sachs: And Vogtle. Can you just give an update where that stands in the resolution process and, kind of, what investors should be looking out for that going forward?

Yeah, and I’m afraid it’s going to be a short answer. I would give you more here, I just can’t update it a whole lot. I would argue that there has been positive developments, and I think one of the positive developments has been that within the consortium, right, so the Consortium is to Toshiba, Westinghouse, and it was formerly Shaw, now Chicago Bridge and Iron, has essentially bought Shaw. We think that is marginally a positive development in working through the commercial issues related to this. We’ve looked at a variety of different things. We went through mediation. And after mediation we go through litigation. We’ve filed lawsuits. We still haven’t determined venue, whether that is Washington, D.C., or Augusta, Georgia, so that remains in front of us. But look, we’ve met with management of both Westinghouse/Shaw and Toshiba, all of them, and we have a great relationship. And so we’ll see how it goes. I can’t update you with any specificity as to when we’re going to resolve it or whether we’ll go to litigation or whatever, but that’s where we are. Michael Lapides – Goldman Sachs: Okay. And one follow-up totally unrelated to Vogtle. When you look around the system, I mean you’ve got Kemper coming online next year, you’ve got Vogtle coming online in the back end of the decade. But when you look across the system, whether it’s Alabama, Georgia, Mississippi, et cetera, when do you start seeing a need for new gas-fired generation?

Yeah, that’s a great question. I’m going to guess – what do you think, Art? About 2023? That’s what our models would say. Of course, a lot of that depends on economic growth and a variety of other things. But assuming, kind of what, 2% GDP growth, 1.3% electricity sales growth, you get a number like 2023. Michael Lapides – Goldman Sachs: Got it. So in other words, the McDonough plants as well as the Vogtle and Kemper plants kind of meet your, really your base load and intermediate load supply needs for a better part of a decade.

And throw on there, I think it’s easy to forget about, but Alabama brought in from wholesale sales out of its Miller units, which is one of the most efficient coal units in the United States, and is now using those units to serve retail in Alabama. So I would argue you’ve got Vogtle. You’ve got McDonough. Georgia has procured some PPAs from competitive generation providers. We have Miller. We have Kemper. We have some megawatts out of a solar initiative in Georgia. I think that will all speak to our needs through the end of this decade and perhaps into very early the 2020s. Michael Lapides – Goldman Sachs: Got it.3 Okay. Thank you, Tom. Must appreciated.

You bet.

And now our next question comes from the line of Carrie Saint Louis with Fidelity. Please go ahead, your line is open.

Hey, Carrie. Carrie Saint Louis – Fidelity: Hi. How are you?

Not bad. How are you? Carrie Saint Louis – Fidelity: Good. Good. I just, I had a couple of questions to go through. First of all, I didn’t see in the slides any updated CapEx numbers, and with the higher costs at Kemper County and some of the activity at Southern Power, I was just wondering if you could address that.

Yeah, Carrie. This is Art. We did not update that slide. We’re still evaluating the timeframe around which those dollars will be spent, so we will probably address that in Form 10-Q and you’ll see some more detailed information there. Carrie Saint Louis – Fidelity: And in terms of Southern Power you had a number of $900 million. Do think that is going to be higher than that this year? Or is that still a good number for all of 2013?

I think that is still a good number. It contemplated some placeholders and we’ve announced the acquisition of the Campo Verde project. So there’s also some other elements in there from a capital perspective around maintenance capital and things like that. So I’d still stick with that number. Carrie Saint Louis – Fidelity: Okay. Great. And then I was just wondering if you had spoken to the rating agencies with respect to the Kemper County overruns and had any updated views from them?

We have spoken to all three of the rating agencies. We have reviewed the situation with them and they’ve given us a response of concern but again, our commitment to the Mississippi to maintain their ratings and we’ll address the southern ratio over time as we spoke a few moments ago.

And you know that’s part of our Southern Company financial dogma. We believe that financial integrity is as important as return. That’s what really drives value. We’ll maintain that posture. Carrie Saint Louis – Fidelity: Well, just so I could follow up. So I believe that Mississippi power is A3 negative outlook at Moody’s. Do you maintain – I don’t know if I’ve ever had asked this before, but kind of a limit on how low you would like the OpEx to be rated? Like would you like them kind of all on the A category? Or you’re indifferent? Just how should we think about your credit quality commitment for the operating companies?

Yeah, we’d like for them all to be in the single A category. So A3 is kind of as low as we want to go with Moody’s. Carrie Saint Louis – Fidelity: Okay. And so just so I understood that commitment, so your discussion is the parent will push funds down into Mississippi Power to get back up to its regulatory capital structure?

Yeah. So as Art described earlier we’ll make a capital contribution to preserve their financial integrity. How we do that at the Southern we’ll see over time. Carrie Saint Louis – Fidelity: Yeah, okay. So do you envision doing the infusion down in the Mississippi Power sometime sooner this year? How have you thought about that?

Well, that’s a function of the CapEx and when they spend it. So that will over the next – by the time it goes into service we’ll be back to a closer level. Carrie Saint Louis – Fidelity: Okay. What is their allowed equity structure down at Mississippi Power?

It’s basically a 50-50 and that’s consistent with what they filed for in their 7-year plan. Carrie Saint Louis – Fidelity: Okay. Great. All right. Thank you very much.

Thank you. Nice talking to.

And now our next question comes from the line of Ali Agha with SunTrust. Please go ahead. Your line is open.

Ali, how are you? Ali Agha – SunTrust: Good. Good afternoon. How are you?

Super. Ali Agha – SunTrust: Good. Hey, Tom. as you look at Kemper County today as an investment given the cost overruns and where the budget is coming out versus where you thought it would when you went in, how do you see the economics of this project?

Yeah, absolutely. Thanks. It still is terrific. Now obviously we’re disappointed. Nobody wanted to have this overrun and certainly for our account. We take that very seriously and we’re disappointed with that. That being said, it is so important to serve the long-term interest of our customers to provide a balanced portfolio of generation resources. Failing to do Kemper would have put a much bigger bet in natural gas for the account of Mississippi’s customers and that doesn’t make sense. When you think about the energy production profile of Mississippi Power going forward with Kemper, they are about a third coal, a third Kemper, a third natural gas. And we call the energy equivalent dollar-per-million BTU of Kemper is going to be somewhere between $1 and $1.25 per million BTU with very low volatility. Unlike natural gas and we pointed out before a quarter ago, $2.50 per million BTUs, first quarter $3.50 per BTU and spot $4.25. And if any of you live in the Northeast, especially New England, you can see how volatile gas can be still. Now I sale that to say we’ve already made a big bet in natural gas. We have great optionality to swing between coal and natural gas. We are very bullish on natural gas. But that does not mean that we put all our eggs in that basket. Economic dispatch Kemper looks like a nuclear plant. High capital cost, cheap energy. We think it makes sense. Ali Agha – SunTrust: Okay. Fair enough. Second question I wanted to clarify – I know for planning purposes you talked about 2% GDP growth, 1.3% or so weather normalized demand growth. Wanted to be clear – is that what you’re assuming in your 2013 guidance as well – that demand growth number?

Yes. Ali Agha – SunTrust: Okay. And my last question, and you talked a little bit about some of the additional projects that are coming in within the certain power footprint renewables et cetera but also I thought Tom, you talked about expanding the Southern Power business model. Maybe I thought you were talking also about more Greenfield projects outside the Southern footprint. Can you just give us an update on your thinking on Southern Power’s model for us?

Yeah, it is where it was. I would just pick at just a couple of words. We’re not expanding the business model per se. The business model for us would be essentially long-term bilateral contracts credit-worthy counterparties, little or no fuel or transmission risk. We earn our money based on the brick-and-mortar investment that we get in a capacity price that we put in our contracts – a second contract typically we associate would be essentially energy which is mostly fuel and there’s some upside in those contracts but very little downside. That’s the way we structure Southern Power so that it has a risk profile similar to our retail regulated business and we’ve been awfully successful. So the idea was we’ve been able to do that in the Southeast. The Southeast is pretty well flush with capacity and we have been approached by other people. We’ve gone outside the Southeast really in order to do renewables, right? The biomass fuel in Nacogdoches, the solar deals we’ve done now in New Mexico and Nevada and now California. So those are the reasons why we ventured outside the Southeast. We have maintained the same business model. Along the way we have been approached by people particularly our target customers which I would say are particularly focused on munis and co-ops and maybe other large IOUs outside the Southeast to do other business. So far we’ve been turning that business down. What we have suggested in prior calls is that maybe that’s some business we could do effectively. We would keep the same business model in place in pursuing anything if it’s outside the Southeast. And to the extent at the expiration of the contract recall that we tried to do these long-term contracts. I don’t know specifically with the latest average tenure is – 12 to 14 years for Southern Power but I would say that if you’re taking risk on re-upping a contract that the expiration of a long-term contract we would probably price in a risk premium to the return to make sure that we were covered on that risk. But that’s our thinking. It remains. Ali Agha – SunTrust: Okay. Okay. Fair enough. Thank you.

Yes, sir.

And now our next question comes from the line of Mark Barnett with Morningstar. Please go ahead. Your line is open.

Hello, Mark. Mark Barnett – Morningstar: Good morning. Hey. How are you?

Great. Mark Barnett – Morningstar: Just a couple of quick questions. I know it’s a little bit early and you can’t get too in detail about it but with the Georgia filing – the rate case filing that you’ll be doing a little later, are there any big structural changes that you might be looking at? Maybe a change from the 3-year cycle in that filing? Or is it too early to comment?

Yeah, it’s really very early to comment. Until we file we’re not going to have a whole lot to say about that. But what we’ve done in the past – we typically file a traditional one-year rate filing and then we’ve been under since 1995 a series of three year accounting orders which generally have a much more fluid structure. So what we’ve had with the Georgia regulatory process – the Georgia commission particularly is a constructive relationship in which we can evaluate and manage regulatory structures to accommodate the needs of the day. And I think that has served Georgia Power’s customers so well for so long. So we’ll file a traditional rate case and we’ll file probably some other alternatives to that and we’ll see what makes sense for George’s customers. Mark Barnett – Morningstar: Okay. And just one quick question on the Bowing explosion. I saw that you had a filing to close one of the units there. Is that related to the generator incident? Or are you going to be fully repairing? I mean I just wanted to get little clarity around what’s happening around that Unit?

So we don’t have any filings associated with the Bowing problem there. The filing that was made was the sale of a Certain associated with Unit 6. Here’s the issue. We’re really not prepared to talk very much about Bowing yet. Any event like that we do what’s called a root cause analysis. That root cause analysis has not yet been completed, and we’re very careful, even internally, talking about that, until we see with the facts are. There is a very disciplined, rigorous process that we follow. And so once we see that, we’ll evaluate what to do now, in terms of returning Units 3 and 4 to in-service, Unit 1 and what to do about repairs associated with Unit 2. Mark Barnett – Morningstar: Okay. I appreciate that. Yeah, I had seen that filing and I just didn’t open it. Just wanted to make sure it wasn’t related.

No. It’s really a minor issue and really doesn’t apply to Bowing 1 through 4. Mark Barnett – Morningstar: Thanks.

You bet.

And now our next question comes from the line of Andy Levi with Avon Capital. Please go ahead, your line is open.

Hey, Andy. Andrew Levi – Avon Capital: Hey. How are you, guys?

Great. Andrew Levi – Avon Capital: I don’t really have any, I guess I have one or two questions left. Just a clarification I guess if you asked this to IR, but just on these sales growth forecasts that you gave, could that, that you gave on the fourth quarter call, you gave guidance. Does that include the effects of the leap year or didn’t include? I’m just not sure on that?

It contemplated the leap year effect. Andrew Levi – Avon Capital: Okay. So the sales that you’re showing here, for the quarter, are really versus your guidance and we wouldn’t strip?

No, they’re actual to actual. The way I would think of it, it’s year-over-year, so Andrew Levi – Avon Capital: Right. Right. But we compare it to your guidance, not stripping out the leap year going back to flat? Right, so?

Well, we’re just give you color on the year-over-year comparison, is all we’ve done.

Yeah, and, Andy, when you think about it, so the leap year effect really occurs in the first quarter, then it diminishes as the year goes on. So you have essentially 190, which is about 1.1% difference. You know afterwards, once you get to 360, the leap year effect almost washes out on any year-to-date comparison. So it kind of washes out by the year. That’s why you’ve got to kind of account for it in the first quarter. Andrew Levi – Avon Capital: Got it. Okay. Thank you. And then is there a way to get a breakdown on Kemper as far as the $550 million, how much was for piping, how much was for labor, productivity, whatever.

No, we don’t have that. Well we have it, but that’s for our account. Andrew Levi – Avon Capital: Got it. Okay. I guess that’s it. Thank you.

Thanks, Andy.

And now our next question comes from the line of Ashar Khan with Visium. Please go ahead. Your line is open.

Hey, Ashar. How are you? Ashar Khan – Visium: Pretty good, Tom. How are you doing? I’m sorry, I was off a little bit, I don’t know this question got addressed or not. The announcement that was made yesterday on buying the solar facility, is there any more information regarding the purchase price attributable to Southern? And if I’m right, the plant comes into operation, if I’m right, end of this year, so there is going to be some kind of ITCs that are going to be recognized as part of earnings? Sir, I don’t know if you discussed this already or not, is there anything you can provide?

Ashar, this is Art. You’ll see more information on that in our 10-Q. We have an agreement with, in the purchase agreement where we’ve agreed not to disclose the purchase price until we have an obligation to do so, and that’s when we’ll do it, in the 10-Q. So we’re going to honor that agreement. But there are ITCs associated with it that, that will be recognized and our guidance contemplated the projects.

This is one of those placeholders I was referring to. It fills one of the placeholders. Ashar Khan – Visium: Okay. And the plant does come into operation right? At the end of the year?

Yes, sir. Ashar Khan – Visium: Okay. Thank you so much.

You bet. Nice talking to you.

And now our next question comes from the line of Dan Jenkins with State of Wisconsin Investment Board. Please go ahead. Your line is open.

Big Dan, how are you? Dan Jenkins – State of Wisconsin Investment Board: Good. How about you?

Great. Dan Jenkins – State of Wisconsin Investment Board: You mentioned that you’ll provide more info on the revised CapEx in the Q but I was – would it would be the same for the financing? Can you give us any color on how financing plans would change given the higher Kemper costs and so forth?

Well, the financing cost, we talked about this earlier, Mississippi’s additional cost to – for the $540 million will be financed with a mix of capital. We’ll then load some capital from Southern to support the equity side and then issue more debt to support some other expenditures. In terms of how we handle that at Southern again is something that we’ll deal with over time. For Southern it’s a much less – much smaller impact on the Southern level that it is at Mississippi. So we’ll deal with that equity issue over time. Dan Jenkins – State of Wisconsin Investment Board: How about on the debt side, though, so you’d expect more debt issuance on – for Mississippi Power I would assume?

Well, it depends on the timing of the expenditures and right now we’re – we don’t have a feel for exactly when they’re going to spend that money so we can update you later on that. Dan Jenkins – State of Wisconsin Investment Board: Okay, and then going back to your Appendix ratio, the capacity factors and generation mix, just wondering if you could give us what the capacity factors were for the nuclear in 2012 and 2013? What Q1...

Yeah, can you hold on just a second? I’m going to have to look that one up. Dan Jenkins – State of Wisconsin Investment Board: Sure. And then somewhat related to that, just the generation mix, the decline in nuclear, I assume that’s related to additional outages. Is that correct in line with...

That’s correct. Dan Jenkins – State of Wisconsin Investment Board: What would that be in each quarter, do you know?

I don’t have the outage.

Will get that for you. That’ll be factored in; 2012 I think it was first quarter was 93 and 2013 was 85. Dan Jenkins – State of Wisconsin Investment Board: Okay. Thank you. That’s all I had.

All right, Dan. Thank you.

And now our next question comes from the line of Paul Patterson with Glenrock Associates. Please go ahead. Your line is open.

All right, Paul. Paul Patterson – Glenrock Associates: Hey. How are you doing? Can you hear me?

Yes.

Yeah, sure. Paul Patterson – Glenrock Associates: Pretty quick, just there’s this footnote that says also reflects reclassification of January 2012 kilowatt hours so among customer classes with – consistent with actual advanced meter data and the use of the advanced meter data I guess is implemented in the first quarter of 2012. What does that mean? Does that have any impact on any of this data or anything that we should know about?

No, it’s merely a way to make the data more comparable and more meaningful. Basically it’s an improvement in the reporting results. At the end of 2011 we were using a much more rough estimate of what the allocation of unbilled would be between classes whereas at the end of the – end of last – end of the first quarter last year we were using a much more accurate – using the AMI meters to calculate, which was a much more accurate. So we didn’t want that to do – disrupt the reporting numbers so we normalized for those effects. Paul Patterson – Glenrock Associates: And that didn’t have – did that have an impact on the year-over-year of what are normalized numbers?

Well, it did have an impact but it normalized them in a way that we think is more meaningful. Paul Patterson – Glenrock Associates: Okay. So I guess it’s more meaningful but I guess – in that it’s more accurate, but I mean does it – would the numbers be substantially different I guess if that hadn’t happened?

Let me say it this way, the total number that we reported, the 0.9% for total retail sales, would have stayed the same, the allocation between the classes would have altered. Paul Patterson – Glenrock Associates: Gotcha.

Okay? Paul Patterson – Glenrock Associates: Okay. And then in terms of just if I understood the thing the GDP forecast and sales force caps and everything hasn’t changed from last quarter. Is that correct?

That’s correct. Paul Patterson – Glenrock Associates: Okay. And then just I guess at Kemper it does seem that – I mean I’m just wondering, is there some specific design issue at IGCC that we should know about? Or that you guys have – I mean it just seems that this thing is – especially if you guys, I mean you had a problem as well with the cost overruns and what have you. I’m just sort of trying to get a sense as to what you guys have learned in this process as to what’s going on.

Paul, I would argue that our circumstance is completely different than what Duke has experienced. Duke is buying a very different kind of gasifier. They’re buying it with that contractual relationship. This is our own technology. The gasifier behaves differently. You may remember I went through a protracted explanation as to why we were different than Duke. Look, when we do the feed study, the final engineering and economic design of Kemper County for everything that we did the feed steady on which is all the kind of electricity side and the proprietary technology, the gasifier, the fuel handling and all that stuff? We are right on the money in terms of that estimate. Where we missed it, just to be clear, is on the piping. And you think about the piping associated with a plant like this, it really is a pretty big effort. Because remember, we’re taking gas off of the gasifier, we have all these byproducts including CO2 and a variety of other chemicals and by improving the quality, quantity and then by adding more labor including adjustments to productivity on the site, to deploying that piping, that’s what’s given rise to the big increase. That’s a different situation than what Duke raised and probably has nothing to do really with the technology associated with the IGCC itself. It’s the piping coming out of the IGCC. Paul Patterson – Glenrock Associates: Okay. Just with respect to – you guys mentioned that you thought that the cost, this is your best estimate at this time. And obviously that could change. But it would seem to me that as you guys get closer there should be less variation. I mean I know that you’re obviously being cautious. But can you give us any sense, I mean you mentioned that there were several other steps that still have to be taking place. Is there a potential for another big – is there something significant potentially that could happen here with this? I mean in other words, could we see another write off like this potentially?

I certainly hope not. Listen, you know how conservative we are. This is our best estimate with everything that we know right now. So that’s what we’re doing. Paul Patterson – Glenrock Associates: The ITC that you were talking about with Paul Ridzon that would mean that the plant would have to be available by 2014? If for some reason it wasn’t available in commercial operation by 2014 what kind of exposure would we be talking about it?

Well, with ITC there would be ratably given to customers over 30 years. So what would say, $133 million over 30 years that would be the annual affect? The other thing that Art mentioned just to add back is that additional ITC that’s associated with a 70% capture, we can’t guarantee we’re going to get there or not, but if we got that, that would be additional $90 million. So that could serve to offset if we missed some of the other. So we’ll see. Paul Patterson – Glenrock Associates: And that goes to customers. Is that right?

Yeah, ratably over time. Paul Patterson – Glenrock Associates: Okay. Thanks so much.

And all of that is in our plan that we filed. Paul Patterson – Glenrock Associates: Okay. Great. Thank you.

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

Well, let me just close out by saying I appreciate everyone’s participation on the phone today. Look, this Kemper situation is something that we’re disappointed in. I do want to say to you all and also to the thousands of employees that are involved in this, this is not representative of the kind of performance The Southern Company delivers year in and year out. When you think about our engineering and construction services group we have engineered, constructed and put into service well over $20 billion of a gas generation fleet and an environmental control fleet under budget, on time and better functionality than what we expected. This is unusual performance for us and it’s something that we’re going to work very hard not to repeat. So I just want to say to you all we’ve got our heads down. We are focused on this and we’re going to do everything we can to improve performance going forward. Thank you very much for your attention this afternoon. We appreciate it.

Ladies and gentlemen, this does conclude The Southern Company’s First Quarter 2013 Earnings Call. You may now disconnect your lines.