The Southern Company (SO) Q1 2012 Earnings Report, Transcript and Summary

Good afternoon. My name is Sarah, and I'll be your conference operator today. At this time, I would like to welcome everyone to be Southern Company First Quarter 2012 Earnings Call. [Operator Instructions] I would like to turn the call over to Mr. Dan Tucker, Vice President of Investor Relations and Financial Planning. Please go ahead, sir.

Thank you, Sarah. Welcome, everyone, to Southern Company's First Quarter 2012 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 Forms 10-K and subsequent filings. We'll also be including slides as part of today's conference call. These slides provide details on the information that will be discussed on this call and 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.

Thanks, Dan. Good afternoon, and thank you for joining us. Before we turn to Art for a review our first quarter performance, I'd like to take a few moments to update you on our recent progress on several important strategic fronts. On February 10, we received the combined construction and operating licenses for Plant Vogtle Units 3 and 4, the first new nuclear units licensed in the United States in more than 30 years. Our nuclear development team has done an exemplary job in satisfying the requirements for these licenses, and I have every confidence that they will continue to provide strong leadership as the project moves forward. We are making significant progress at Vogtle 3 and 4 as those of you following along on the slides can see. Work is already underway on the Nuclear Islands and cooling tower, and our heavy-lift derrick, one of the largest in the world, is being assembled. With the new licenses in hand, we have made a smooth transition into the next phase of the project and I look forward to sharing further updates with you in the future. Meanwhile, the state regulatory process for Vogtle 3 and 4 continues to move forward in a constructive manner. The Georgia Public Service Commission has improved $1.7 billion of project costs through June 30, 2011, and is currently reviewing the company's sixth semiannual construction monitoring report, which reflect an additional $300 million of cost through December 2011. In testimonies filed with the commission, Georgia Power has outlined up to $2 billion of potential additional benefits related to Vogtle 3 and 4 that we believe further enhance the value of this project for our customers. The commission's decision in this proceeding is expected in mid-August. With any project of this magnitude and length, commercial disputes are to be expected. Discussions between the owners and the consortium are ongoing regarding a number of matters, including issues related to the timing of the receipt of the design control document, or DCD, and the combined operating licenses, or COLs. As you may be aware, the construction of Vogtle 3 and 4 will proceed under a new licensing framework that is significantly different from the one used previously. In the past, nuclear plant operators designed and built their units first and then sought licensing approval for what they had already built. Under the new process, the nuclear units are constructed according to the COLs and the underlying DCD. There are processes in place to assure compliance with the design requirements specified in the DCD and the COLs. One process we have discussed with you before is ITAAC, which stands for inspections, tests, analyses and acceptance criteria. An additional oversight process is rigorous inspection by Southern Nuclear and the NRC that occurs throughout constructions. As an example of this process, a recent routine NRC inspection revealed that limited details of the rebar construction in the Unit 3 Nuclear Island were not consistent with the DCD. We expect to receive official notice of this finding from the NRC. In the meantime, we are engaged in constructive discussions with the consortium to identify appropriate action. We can reasonably expect to encounter additional inspection issues between now and the time the new units are completed as they are a normal part of the nuclear construction process. Our goal is always the same: to build the safest, most reliable and most cost-effective nuclear generating units possible and to achieve our targets with regard to schedule and cost to customers. Elsewhere, on April 24, the Mississippi Public Service Commission finalized a new certificate of public convenience and necessity for the Plant Ratcliffe in Kemper County, Mississippi. This became necessary after the Mississippi Supreme Court's recent reversal of the commission's previous order. In the interim, construction continued on the Kemper County site under a temporary authorization granted by the PSC on March 30 and will now proceed under the authority of the new permanent order. Initial startup and testing are now only 14 months away, and we remain confident that this project will provide the best value to customers over the long term. Targets remain achievable for both the Vogtle and Kemper County projects with regard to construction schedule and cost to customers. As important as these projects are, they are only part of our all in "arrows in the quiver" strategy for building a 21st century energy portfolio. Georgia Power is making significant progress on 3 new combined-cycle natural gas units at Plant McDonough. The first of these units came online in December and with a nameplate capacity of 840 megawatts, and has actually been generating at significantly higher levels with an extremely efficient heat rate. The second unit is scheduled to begin operation later this month with the third unit expected to follow in November. Southern Power is also nearing completion of the nation's largest biomass generation facility near Nacogdoches, Texas. This project, which is scheduled to begin commercial operation in June, will provide needed power for the city of Austin through a 20-year contract. These projects are consistent with our ongoing commitment to maintain a diverse and balanced generation portfolio, thereby enabling customers to benefit from the best available combination of low energy costs and system reliability. During our last earnings call, we reported that our energy mix in the fourth quarter of 2011 was about 40% natural gas and 40% coal, with the rest coming from our lowest cost resources, nuclear and hydro. Compare that to 2007, where the mix was only 16% natural gas and 70% coal. As natural gas prices have remained low relative to other fossil sources, we have seen these fourth quarter trends continue. We now project that our mix for the full year of 2012 will be 47% natural gas and only 35% coal. Given the high level of interest in this topic across our industry, here is a quick summary of what we're seeing here at Southern Company. During the first quarter of 2012, our natural gas combined cycle fleet achieved an average capacity factor of 70%. Based on today's forward curves, we estimate we could burn more than 600 Bcf for the full year 2012 or about 1.7 Bcf per day, almost 3x what we burned in 2007 when natural gas was only 16% of our generation mix. Southern Company's gas purchases now account for more than 2% of all United States natural gas consumption, making us the third-largest user of natural gas among United States utilities. Even with natural gas prices below our forecast for 2012, we are well-positioned for managing coal inventories and passing lower energy costs on to customers. To accomplish this, we've taken several proactive steps, which include increasing our ability to match coal purchases and burn through reduced volumes of contracted coal, maximizing and expanding on-site and off-site storage, working with our coal suppliers to defer, buy out or renegotiate existing contracts, and conducting managed burns when necessary. Our current expectation is that we will burn less than 45 million tons of coal in 2012 compared to the nearly 80 million tons we've burned at our peak in 2007. That said, we continue to maintain our operational flexibility to increase our use of coal in the event of a sharp reversal in the price of natural gas. There remains excellent optionality in our generation fleet. As an illustration, by 2020, assuming a scenario of low natural gas prices and relatively high coal prices, our energy mix could be 57% gas and 22% coal. If fuel prices change to a high-gas, low-coal environment, the energy mix could be 34% gas and 45% coal. Under all scenarios, nuclear would remain in the 16% to 17% range. This level of flexibility will continue to be an important part of our operational planning philosophy going forward. As always, our ultimate goal is to benefit customers, and here, we continue to succeed. As an example, earlier this year, Georgia Power filed a request to lower fuel rates. As proposed, this would reduce average fuel prices by 19% and average residential retail prices by 6%. We think achievements of this sort are the very best validation of our business model, that everything we do is based on providing the best value for customers served by our operating system. I'd like to turn now to Art Beattie for a discussion of our financial highlights for this quarter, as well as an update on first quarter sales, the economic outlook for our region and our earnings estimates for the second quarter.

Thanks, Tom. In the first quarter of 2012, we've reported earnings of $0.42 per share compared with $0.50 a share in the first quarter of 2011, a decrease of $0.08 a share. Let's turn now to the major factors that drove our numbers for the first quarter of 2012 compared to the first quarter of 2011. First, the negative factors. Weather effects reduced our earnings by $0.08 a share during the first quarter of 2012 compared with the first quarter of 2011. Weather was actually $0.06 a share below normal in the first quarter of 2012 compared with $0.02 a share above normal in the first quarter of 2011. Increases in non-fuel O&M expense for our traditional operating companies decreased our earnings by $0.01 a share in the first quarter of 2012 compared with the first quarter of 2011. Increased depreciation and amortization, representative of our growing rate base, reduced our earnings by $0.02 a share during the first quarter of 2012 compared with the first quarter of 2011. The expiration of long-term capacity contracts for Southern Power reduced earnings by $0.01 a share during the first quarter of 2012 compared with the first quarter of 2011. Finally, an increase in the number of shares outstanding reduced our earnings by $0.01 a share during the first quarter of 2012 compared with the first quarter of 2011. Retail revenue effects in our traditional business were a positive factor, adding a total of $0.05 a share to our earnings for the first quarter of 2012 compared with the first quarter of 2011. In conclusion, we had $0.13 of negative items compared with $0.05 of positive items for a negative change of $0.08 a share. Moving now to a discussion of our first quarter sales and the economic outlook for the remainder of 2012. Sales growth was driven by the continued recovery of industrial sales, which grew by 1.9% in the first quarter of 2012 compared with the first quarter of 2011. Industrial sales were 97% of pre-recession levels for the quarter and 99% for the month of March. This growth was led by pipelines, up 8.3%; transportation, up 7.3%; primary metals, up 7%; and chemicals, up 2%. In our territory, manufacturing job growth outpaced overall job growth in the first quarter of 2012. Unemployment rates in the region have fallen to an average of less than 9% and the level of confidence in our current outlook has been strengthened. The growth in jobs likely contributed to the addition of some 15,000 new residential customers in the first quarter of 2012, a significant increase over the 2,000 customers added during the first quarter of 2011. This growth was the largest such gain in customers since the first quarter of 2009 and was broad-based, meaning that each of our traditional operating companies experienced growth. Reflecting some of the improvements in customer growth, residential sales growth grew by 0.6% for the first quarter of 2012 compared with the first quarter of 2011 on a weather-adjusted basis. Commercial sales declined by 1.3% in the first quarter of 2012 compared with the first quarter of 2011, also on a weather-adjusted basis. Meanwhile, new economic development activity announced in the first quarter of 2012 is expected to bring another 5,000 jobs to our region, which would be a 36% increase over the same period a year ago and another $1 billion of capital investment, a 52% increase over the same period a year ago. Chief among these was the announcement of a new Caterpillar manufacturing facility that will bring 1,400 new jobs to Georgia. More recently, Baxter International announced that it will create more than 1,500 jobs with a new production center outside Atlanta. Before I discuss our earnings estimate for the second quarter of 2012, I would like to update you on one other financial item. Earlier this month, we announced an increase of 3.7% in our dividend, thereby increasing the annual dividend rate to $1.96 per share. This marks the 11th consecutive year that we have raised our dividend. Over the past decade, fewer than 10% of S&P 500 companies have raised their dividend more than 2% each year, and during that time, Southern Company raised its dividend an average of 3.5% per year. We also delivered an average annual total shareholder return of more than 11% with a low level of relative risk to the market. We are particularly pleased that our continued focus on providing superior value to our customers has enabled us to provide sustained value to our shareholders. Now I'd like to move to a discussion of our earnings estimate for the second quarter of 2012. Our earnings estimate for the second quarter of 2012 is $0.65 per share. As a reminder, during our January earnings call, we shared that annual guidance for the year 2012 was $2.58 to $2.70 per share. Now I'd like to hand it back over to Tom for his closing remarks.

Thanks, Art. In closing, I'd like to take a moment to address an emerging issue that has direct implications for American investors: the tax treatment of dividends and capital gains on investments. Historically, dividends have played a pivotal role in the financial well-being of American investors. In fact, over the last 80 years, dividends have driven nearly half of the value of the S&P 500. If you look at just the last 30 years, dividends account for nearly 60% of the index's total returns. And over the last 3 years, dividend income has represented nearly 18% of all personal income growth in the United States. Over time, dividends have provided an important source of investment income for American investors, older investors in particular. And with baby boomers retiring in ever-increasing numbers, it is reasonable to expect that the need for that income will only expand in the coming years. Our position is clear. First, we believe that the tax treatment of dividends and capital gains should be linked. Second, to encourage capital formation and, therefore, capital expenditures, and as a result, growth in jobs and the incomes of Americans, these tax rates should remain low. This is an issue that we are following closely and we'll continue to do so in the months ahead. As always, we will engage constructively with our elected government representatives, seeking an outcome that preserves the ability of dividends to continue to fuel our country's economic engine and ensure a stable financial future for its citizens. At this point, we are ready to take your questions. So operator, we'll now take the first question.

[Operator Instructions] Your first question comes from the line of Daniel Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Just real quick, make sure I understood the 2012 guidance comment. You guys are reaffirming 2012 guidance as you provided on the fourth quarter call and you're comfortable with that number still. I didn't misunderstand that.

We only give guidance once a year and we give it in January and then we re-address it at the end of the summer peak season in October. Dan Eggers - Crédit Suisse AG, Research Division: Okay. With your O&M, you had flexibility the last 2 years of good weather to, I guess, for lack of a better word, bank a little bit of O&M. O&M was up in the quarter year on year, even with the volumes down. Are you guys looking for opportunities to help manage O&M over the course of this year to stay in line with that guidance span?

Sure. It's what we always do. When I looked at the weather this quarter and I looked at our O&M and I'll let Art comment on this later. But we feel completely confident of our financial plan. No reason to get exercise at all about what we did in the first quarter. Remember, most of our net income comes in the third quarter, and as a result, that's really the time in which to exercise the flexible portion of our operating budgets.

That's exactly right, Tom. And just to give you a little more color on the first quarter, we actually did understand what we expected to spend on the nonfuel O&M side. But on a year-over-year basis, it was a bit more, and a lot of that was related to pension and other employee benefits. Dan Eggers - Crédit Suisse AG, Research Division: Got it. And I guess, Tom, with gas prices low and coal prices showing a little more resilience and the mix you guys are seeing from a dispatch perspective, are you rethinking in the environmental CapEx plans you guys have laid out in the sense of maybe pivoting more away from some of the upgrades on the coal plants just because it's harder to justify them against some of the gas options today?

Not really, although it's a very interesting kind of question. As we've looked at the variety of variables that go into our decision-making process with how to comply with HAPs MACT or Cross State or CO2 or anything else, 316B, ethylene standards, you name it, we go through kind of a probability-weighted analysis and try and look at the kind of range of outcomes that could potentially impact our customers. And ultimately, I think what we see is the path that we have chosen or are choosing currently and it'll be final probably by the July call maybe. We think that our plans are driven more by the timing of the regulations rather than necessarily any change in the short-term fuel markets.

Your next question comes from the line of Jonathan Arnold with Deutsche Bank.

Could I just ask, in your discussion of coal and gas, you talked about working number of different options on contracts and then some forced burn and some deferral. Can you give us a sense of is most of what you're doing deferring? Is it sort of equal amount of all of the different ways of managing the coal contracts? Or do you have any kind of sense of what's the most fruitful area for you?

Well, it's a mixture of all, and if you look at the word we put them in, it's is really driven by the economics. To the degree we can find additional external storage and internal storage of coal, we'll certainly do that first. We'll work with our coal companies to try to find optionality in the contracts or opt out of tons. That would probably be our next choice, and the last choice would be burning the coal in a planned burned gap or planned burned sense.

And the sense of it is, right now, the planned burn is exceedingly minor in terms of kind of the overall fuel cost to customers at this point. We think it's like less than 1%. And the other thing that really impacts us here, we started working on the switching strategies very early last year and even before because we could see kind of the clouds on the horizon with respect to HAPs MACT and what that might mean to marginal units. And given that we saw then, at least, a 2015 time frame, we started taking actions not only on our coal contracts, but also on our railroad contracts. And we think we have a very orderly process in place in which to accommodate the optimum fuel results for our customers.

Okay, and can you frame -- you gave us a sort of benchmark of tonnage in 2007 and tonnage in '12. How does this -- can you just remind us how many tons of coal you burned in '11? How '12 is going to look versus '11?

56 million tons.

So 56 million goes to 45 million on that year-over-year basis.

Yes.

And then if I can just ask one other thing. When you give your growth numbers, the weather-adjusted, are you making a leap year adjustment in there as well? Or is that just kind of 1 extra day versus 1 less day last year gross?

I'll tell you a funny story. Actually, we didn't adjust it but some years ago, we talked about leap year being an explanation as to an earnings variance. And I made some goofy story about a crazy earnings call. We left that out this time.

So we've kind of -- underlying is probably 1% or so less than what you showed.

1%, yes.

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

Can you just talk about some of the drivers you're seeing in the second quarter relative to the second quarter of '11?

Yes, the second quarter of '11, you might remember we had $0.07 of weather, positive weather last year. So you take that off, and we would've been at $0.64 adjusting for nothing else in that result. So the drivers this year would be some revenue effects from new rates and various of our operating companies across the system and expectations around load growth.

Is that $0.07 versus normal?

Yes.

Your next question comes from the line of Angie Storozynski with Macquarie Capital.

I have a couple of questions. First of all, the load growth. You mentioned a couple of the big industrial projects that are going to bring jobs into your region. I wanted to know about the timeline exactly when those jobs are coming. And I also wonder, I understand that you have some O&M flexibility, but you're going against a pretty significant negative versus your guidance. You're assuming 1.3% year-over-year load growth for now. The weather and then underlying growth are going against you. I mean, could you also tell us basically, should we basically assume that's it's a lower number in general? I mean, is the economy growing at a slower pace than what you have originally assumed?

Let me get the last one first. I'm going to hand it over to Art for the economic development stuff. What's interesting about our earnings profile as we were driving through our preparation for the call, one of the things we noticed in our financial plans for this year, especially if you consider the pace of capital investment, so we're spending around $6 billion a year, $18 billion if you add it all up over the 3-year period, and how we're earning CWIP on Vogtle and Kemper County. The seasonality of our earnings is becoming more back-end loaded. So what you see is, what you all should expect is more back-end loading of our earnings performance. So you kind of have a momentum that builds as we have more invested capital throughout the year. So I would kind of caution you with that one. The second one is, we are completely confident that we have the flexibility giving normal variances of weather to do what we need to do in order to achieve our targets. With respect to economic development, let me turn that back over to Art.

Yes, Angie, you had asked about Caterpillar and the dates around that. 2013, that's expected to be complete and started, and the Baxter Labs is going to be a little bit longer in its runway. It's going to be about 2018 before you get to that 1,500 job scenario.

Okay. And second question is about -- you mentioned in your prepared remarks about the issues with the rebar and CDC [ph]. Should we expect that it's going to have any impact on the delays, for instance, construction works?

So what we said before is, our belief is that all targets are achievable with respect to schedule and cost of customers. The thing I just want to point out is, you will, and what we're trying to, is get people used to the idea that as we proceed through this complex, long-term expensive project, you will hear about lots of things. This one we highlighted this quarter is just another one of what we believe will be many. And in fact, there's already been several license modification applications made. So we're just trying to get everybody used to the idea that these things will occur over time. With respect -- if, in the future, we ever decide to readdress schedule or cost or whatever, we do that in conjunction with our PSC. We have an ongoing relationship, and it's been a very constructive relationship today. I have no reason to believe it wouldn't be in the future.

And the last question, what's the heat rate of the new plants, Plant McDonough?

The first unit has been operating beautifully. In fact, it's nameplate rating 840. We hit a number like 960 at one point. Now you can't count on that all the time. Remember, it operates more efficiently during cold weather, which is what it did. And its heat rate was around 6,500.

Your next question comes from the line of Brian Chin with Citigroup.

I hate to beat a dead horse on this, but with the $0.66 guidance for 2Q, so does that incorporate the weather as we've seen it up to this point in 2Q? Or is that assuming a normalized weather pattern for 2Q ?

It assumes normal weather, Brian. You can try to make some judgments on weather, but you got very little bit of the quarter in there. And my admonitions are all of our people who have input into that is let's assume that we're going to be normal for the quarter.

Your next question comes from the line of Mark Barnett with Morningstar.

A quick question on a couple of just timing issues. With the DOE loans that you expect to start for Vogtle and Kemper this year, could you just give me an update on when you expect those to sort of be finalized or where you are in the process? And then second quick question, when does the quip [ph] start to show up from Ratcliffe? Has that already started in the first quarter?

So I'll hit the loan guarantees, and I'll let...

The quip [ph] has begun in Mississippi. Well, are you talking about cash collection of the financing cost? Is that what you're referring to, Mark?

Yes.

No, that has not begun. There has been a request for that to the Mississippi Public Service Commission, but that has been preempted time-wise by the other issue that they've addressed around the certification order. So the time line is probably going to be midyear or so.

It's good we got the order out. That was a good thing to get behind us. With respect to this loan guarantee thing, remember, we got our conditional loan guarantee with the DOE, I don't know, some 2 years ago now, and there were a few ends to tie up before we thought we can make the first draw. We still remain hopeful that we'll have loan guarantees. But as a matter of course, really since Cylindra [ph] and reasonably recently, the DOE has proposed some new conditions that really relate to, we believe, more project finance conditions rather than a corporate credit, which is underlying the obligation to repay the loan guarantee that we have. We're working through those issues and we're very hopeful that we'll be able to reach a successful conclusion. But rest assured, we will always act in our customers' interest. And when they ask us to do something that's not in our customers' interest, we won't go forward. I must say that the value that we are bringing to customers since certification has been rather extraordinary, in my view, and we'll be successful whether we have them or not.

Your next question comes from the line of Ali Agha with SunTrust.

Just to be clear on the remarks you've made, particularly as you've looked at the full year, if I'm hearing you right, obviously, when you initiated the guidance back in beginning of the year, you wanted to assume normal weather and you highlighted how weather has played out. So in terms of your offsets, should we really look at that nonfuel O&M as being the largest tool available for you to work against this unseasonably mild weather? Are there other tools or other offsets that you're seeing that could also be positive incrementally?

Ali, we've done this before on other calls, but that's obviously the biggest one and what we've talked about in depth before is the notion that we have a dynamic budgeting system. We essentially have some projects that are approved and funded. We have other projects that are approved and unfunded. So if we get better-than-expected weather, we can do more stuff than we thought we would. And we always have the ability to cut back if things don't work out well. And over time, and I'm talking like over a decade now, this has worked exceedingly well. To wit, look at our reliability numbers that lead the industry on so many different fronts. So we've been able to provide for the care of our assets for the benefit of our customers in a very effective way. Given the periodicity of our earnings, you should expect that the flexibility, the optionality within the nonfuel O&M regime will occur once we see what the kind of summer revenues will bring. So we're not going to exercise a lot of flexibility and optionality in O&M right now. We're going to wait until we see a little more income, and then we'll be able to respond as we need to. And we're completely confident of our ability to continue to do that. Let me also turn to Art here.

Ali, one additional thing to think about is, last 2 years, 2010, 2011, we've had better-than-normal weather. And we've been able to use that to, in some degree, to do some things. "Fix the roof while the sun's out," is Tom's favorite phrase. So we've been able to do some things, and we think gives us a bit more flexibility going into '12 than maybe a normal year would have. So yes, we still have flexibility and time available to utilize it.

Second question, Tom, coming back to the EPS, is it fair to say that the rules, particularly on math [ph] as they've laid out are now pretty much set and you and others are working around that? Or are you still thinking there will be significant changes to the time line, to the rules? And as far as the CSAPR rule is concerned, obviously you're in front of the coach, but are you assuming it's back to square one there? Just an update on your current thoughts on the EPA rules.

Well, so remember, when we think about the rules and our compliance, we've got to consider the whole succession of EPA proposals, some of which are out there, some of which are still in the offing. That's HAPs MACT and it's 316b, and its ethylene, and it's co-combustion byproducts, and it's Cross State, and it's ozone and everything else, CO2. Look, what we do is represent the interest of our customers as effectively as we can. We think we are uniquely qualified to do that given that we are the only company in our industry with a deep proprietary research and development effort, and we think we were particularly effective in the HAPs MACT rule. If you recall, there are 11 issues that we were largely responsible for calling out, one of which related to schedule. The other 10 were of a technical nature. We believe that we got some accommodation on some of the 10 issues. That has given rise to, as Art has talked to you before about, a variance in the capital budget. With respect to HAPs MACT, we kind of estimated, what, up to $2.7 billion over the 3-year period and we have suggested that as a result of the final rule, that we may spend somewhere between $0.5 billion to $1 billion less, depending on the number of bag houses, the extent to which we'll have to expand transmission systems, gas pipelines and a variety of other issues. We still need more flexibility with respect to schedule. And so what you have seen is either us or people of a like mind continuing to effort a change to the HAPs MACT rule, all again, to benefit cost and reliability.

Okay. Last question, can you remind us, Art, what's the expected equity, incremental equity, that you've planned for 2012?

Yes, we've outlined, I think, last call, $400 million this year, maybe up to $500 million next year and about $1 billion in 2014. If we look at the first quarter, we raised about $115 million. So that $400 million will seem to be right in line with our expectations for the year. Now those amounts could be less if we decide from the MATS perspective that we spend less money in the compliance side of that equation. So just keep that in mind.

If MATS is $500 million to $1 billion less, we would spend something like 45% to 50% in that less in equity.

Your next question comes from the line of Marc de Croisset with FBR Capital Markets. Marc de Croisset - FBR Capital Markets & Co., Research Division: How many days of coal burn you have in inventory at the moment? And could you give us color on how that's trended since the beginning of the year?

About 60, and it's about what we expected. So what you see typically in terms of coal inventory at Southern would be a trending up going into the peak season and then drawing down through the summer. That's what you would normally expect to see. Marc de Croisset - FBR Capital Markets & Co., Research Division: And back in September '09, when you were hitting very high levels of inventory, were you slightly above 70 days in that period?

It depends on the plant and really the physical dimensions of the coal pile. Really, what you get into there is the physical limitations driving your need to enter into a planned burn program. We are way less on any plan for a planned burn program this year than we have in the past. Particularly, we've taken all the proactive steps that we mentioned earlier. Marc de Croisset - FBR Capital Markets & Co., Research Division: Terrific. And generally, you've got a lot of fuel flexibility, and that's played itself out over the years. Other than just having gas capacity around, what is it about your system that has made that possible?

I have this expression, since I've come on, is honor the past and build for the future. And I would go back to probably the timing which Allen Franklin was running the Traditional Utilities. This is actually before he became CEO. He was COO and ran all the Alabama, Georgia, Gulf and Mississippi. At that time, we decided to balance our portfolio away from coal to gas. And at that time, you may remember, there was this notion that boy, if you could get some CTs, you could make a lot of money all over the place. Interestingly, the way the market evolved during the '90s, we found it to be a much more kind of long-term play. CTs were way more expensive on a unit basis relative to kind of the value, including the option value, that we saw in combined cycles. So what we did, instead of arraying a bunch of combustion turbines all across the system, we tended to buy the more energy-intensive machines and it has worked so well to our benefit today. Marc de Croisset - FBR Capital Markets & Co., Research Division: But the CTs are not what's lighting up now. Or am I mistaken?

That's my point. We bought a lot more CCs [ph], not CTs, and therefore, we have the excess capacity factor capability that's really worked to our benefit.

Your next question comes from the line of Michael Lapides with Goldman Sachs.

Actually a couple of questions, a little bit unrelated to each other. First, could you comment about what you're seeing in small commercial demand? I mean, a pretty big discrepancy between what you're seeing in residential, what you're seeing in industrial and small commercial. That's first. Second, Southern Power, I would expect for the portion of Southern Power that's uncontracted, 20% or so, you'd actually be benefiting substantially from some of the coal to gas switching that's happening in the Southeast. Surprised just a little bit at kind of year-over-year decline at Southern Power in the first quarter just due to the commodity price. And third, could you give a little bit more insight at Vogtle, the rebar-related issue? I don't know kind of dive in a little further about what's happening, what did the NRC see, what does that really mean?

Michael, this is Art. I'll go after the commercial questions. Commercial always lags growth from the residential side. So to the degree we start seeing growth in residential, you'll begin to see at some point growth in commercial as well. You asked about small retail, and there was an article in the Atlanta paper a week or so ago that talked about the resurgence of small retail. And beginning to see space in retail shopping centers being occupied more so than they had been in the past. So it's beginning to bottom out, I would say. We do have some other trivia about tourism and the coast is way up over where it was in the past, and that a lot of that is on the commercial end of the equation.

Let me jump in. This is pretty interesting stuff. So it's a lagging indicator, just as Art said, and in fact, the number that you would point to would be office vacancies are kind of like 20%, where they would normally be 15%. So they are in fact lagging. But a really interesting leading indicator, if you will, in commercial is that sales tax collections are up 5.8% year-over-year. What that tells you is that the velocity of purchases coming through things like Wal-marts and Costcos and a variety of other things are increasing. That's also a function of improved job situation. Personal income is up 4.0% for the Southeast. So you're seeing a decent leading indicator even inside of a negative lagging indicator. This all kind of fits together and we think has a reasonably bullish story for the future.

Got it, okay, then the other 2 items.

Southern Power? You're right. We do have some more uncovered this year as we've had some contracts roll off in the first quarter of this year. And uncovered margins have increased, but they haven't offset the loss of the capacity revenues or the energy margins produced by those units that were under contract, say, a year ago because volumes had just been down. Load is down across the board and the opportunity to sell those units into the market just hasn't been as great as they were, say, a year ago.

I mean, some of the weather effect again. And the last thing was Vogtle, the rebar situation. What did you want on that?

Just a little bit more detail, what was it that the NRC saw during the inspection? Is it something that's a short-term fix; meaning, contractor comes in. It takes couple of days to fix it. Is it something that could balloon into a larger-term, longer-term item? Just whatever detail you can provide, Tom.

So it deals with a very limited part of the rebar structure only in Unit 3 and it deals with the configuration of the rebar as it meets the wall structure. It's that finite detail and it has to deal with does it terminate directly into the wall or does it turn up. There is a solution that we're working through. I don't want to jump ahead of the NRC kind of finally ruling in on this. But all I can say is, it's not going to be anything that, in my opinion, materially impacts any of the schedule or materially impacts any of the cost. And otherwise, it's just this limited part of the rebar in Unit 3. For example, the steam turbine island and the rest of the rebar and everything else continues elsewhere. So it's not like there's a giant work stoppage on the site. It's just with respect to a limited part of the structure. But Mike, the point is, these things will happen, and what we're trying to convey to everybody is these things will happen, you'll hear about them. Certainly, if there's a material impact, we will certainly let people know.

Your next question comes from the line of Greg Gordon with ISI Group.

I'm just wondering, as you guys think about this incredibly dynamic energy market that we're in with how gas has moved versus coal and different types of coal have moved versus each other and you look at the spending you did. I know you've kind of answered a bunch of questions that relate to this. But when you look at your overall capital spending plan over the next several years, I mean, do you still feel like the aggregate of what you will be compelled to spend to provide reliable service to customers still puts you firmly in sort of a capital intensity level that corroborates your earnings growth expectations? I mean, how do we think about how capital is going to move from coal to gas no longer need to spend on environmental. Maybe there's incremental spending on pipeline infrastructure. And how does this all coalesce? Do you guys feel comfortable that you've got the same earnings growth prospects that you had 2 years ago?

Well, that's a heck of a question. You know what, here's what I'd say. We're very confident in our 3-year projection which is what we're about. You're asking kind of the broader question, what does it look like. Let me give you an estimate at optionality in 2020. And if natural gas could move from, as low as 34 to its high as 57, with coal being as low as 22 and as high as 45, we see nuclear and hydro and other perhaps renewables and other things being around 21. What you're really asking that I think fills in the gap that we haven't talked about is -- and I think we're pretty well set for new capacity probably through the end of this decade, right? So we've done McDonough, we're doing Plant Ratcliffe at Kemper County, we're doing Vogtle 3 and 4; McDonough; we brought back Miller from wholesale to retail in Alabama. And there may be some other expansion of gas assets, I think, particularly in Georgia that we will see. Now there may be some other things that we start to pick up that we really haven't talked about very much, and the reason we haven't talked about it is because, in fact, they are unknown. For example, it may be we're very happy, frankly, with our experience so far on Vogtle 3 and 4. It may be that we have future nuclear expansion. To the extent we need to have more nuclear units in sight to keep this portfolio balanced, say, we need that by the middle of the next decade. Well, that would presume you start spending money the middle of this decade. The other issue that we will see potentially is more CapEx associated with this litany, this continuing succession of other environmental matters, ash, 316b and you name what else. So it seems like there's always something out there. The only thing that we comment on specifically is our 3-year growth projection, but we see lots of other things going. One last item, and that is, when we think about Southern Power going forward, we always think to ourselves, what a wonderful gas-oriented option that is. It's something like 98% gas-fired in the Southeast. We have great relationships. They've entered into a lot of what we call full requirements customers that not only picks up current loads, but also allows them to build for future growth in the co-ops and munis markets where they specialize. So as the economy picks up, we think there will be greater contributions from Southern Power. For all those reasons, we follow the dividend policy that we do, regular, predictable, sustainable increases in earnings per share permit us to increase dividends per share at a rate well above the rate of inflation, and that's what we've done; it's what we plan on doing.

So the next 3 years, things haven't -- despite really things have shifted all that much under your feet and beyond 3 years, there's a lot of different levers to pull depending how the economy looks, but they're there.

Yes, exactly. The only thing that we've noted has been the HAPs MACT and the potential for $0.5 billion to $1 billion less on that, whatever it was $18.4 billion aggregate number and that was most in '14.

Your next question comes from the line of Steven Fleishman from Bank of America Merrill Lynch.

And just a little more detail on some of the coal to gas data. Do you have handy just this quarter of 2012 versus the first quarter of 2011 the changes, what your gas capacity factors were and what your coal capacity factors were?

Do you have it versus '11?

I don't have it versus '11.

I'll go from memory there. We'll get back to you on that. I'm going to say that a normal kind of capacity factor in the past was in the 30s. And then we saw it start to creep up a little bit last year, and we need to come back and check this, all right? So this is memory. I want to say we got into the 40s and we even bumped into the 50s a couple times last year. Nothing like where we are now. We can get you absolute detail there.

Okay. And then just on your -- I know this has been brought up a little bit, I think, but just on your -- kind of when you're looking at your sales plan for the year, weather-normalized, how are you feeling on how that's tracking? And I know it's just 1 quarter.

Well, look, absent weather, the economy's better than we thought it was. Remember, I guess we were projecting a GDP growth rate of around 2.6% and normally, electricity follows at about 60% of that growth rate. We've talked about that in the past. We ratcheted that down to about 1.3%, so 50%. So there are some other effects. Other people are estimating GDP growth this year to be 3%, not 2.6%. And if we continue to have 60%, not 50% kind of relationship, you could see an upward bias on the economy this year. But we'll see. Time will tell. The only thing I can say right now is we're off to an awfully good start.

Your next question comes from the line of Kit Konolige from Konolige Research.

So I wouldn't want to leave coal to gas with just 10 questions or so. Could you give us a little sense of -- I'm sure your folks are starting to think about what new contracts might look like with coal suppliers. Can you give us any sense of what you're seeing or thinking or anticipating about trends in coal pricing over the next 2, 3, 4, 5 years?

I wouldn't want to comment too much on that, but there are some very interesting dynamics that are going on. As we have suggested in the script, we believe that our flagship units will be robust energy providers well into the future. And so to the extent we make trades in term length of contracts, I think we can have more assurance that those units will be in place. So if you think about kind of a term structure, we'll shorten up obviously on the marginal units and go longer potentially on the flagship units. So you could see that, right? The other thing that we have seen is, obviously, when we think about our flagship units, you have Sheer [ph], Miller and some other PRB potentially blending operations. So more of an orientation towards western coal rather than certainly eastern coal. The other thing that would be a trend, I suspect, would be this -- we've always used kind of imported coal as a check against Central App, particularly and perhaps others. You may see a little bit less of that only because Central App seems to be less of a viable solution going forward. But with respect to price, there's all sorts of things at play that are really unknowable at this time. One of the things we've suggested in that whole HAPs MACT issue is, if the objective of certain parties was to reduce the consumption of coal in the world, our coal is probably going to be exported to people like China and others and it's going to get burned. It just won't be burned here. So if exporting markets do open up, as we think they might, and in fact, I want to say if somebody's got the statistic here, where the exports of coal was as high as it's ever been, and at least in the quarter or for the year or something like that, pretty high exporting of coal. You're going to see prices be a little stronger than otherwise you would think if all you were looking at was domestic demand. So interesting stuff all the way around, hard to predict what the future will hold. That's why it's so important to play to a portfolio as we do.

Your next question comes from the line of Jay Dobson with Wunderlich Securities.

Just a quick question again on coal to gas. You indicated you might burn 600 Bcf in '12 and we're making a comparison to '07. I wonder what that comparison was for '11.

We actually have that. Somebody's got that. It was -- we actually do have it. Unbelievable. I'm eyeballing a chart, 430.

And then to the coal side, just sort of thinking more about the rail component of that, can you talk a little bit about sort of what contract flexibility you have? And how much you're going down the road of sort of renegotiating those contracts? And sort of how flexible the rail will be in with you?

Yes, Jay, this is Art. Most of the rail contracts we have are full requirement contracts that don't require minimum values. So when we look at terms, they're from 1 to 6 years, and we try to match up our coal, coal contracts and our other commodity contracts that we have for our plants. Longer-term contracts are tied obviously, as Tom mentioned earlier, with our flagship units which are going to be burning a lot of Powder River Basin coal over that timeframe. So it depends on the contract and where the coal is needed and what kind of coal they're going to burn.

And even when you consider all the fuel switching that's been going on in the United States, we remain an important coal consumer and an important customer of the railroads. And I know I did this, gosh, back when I was CFO when rail delivery issues were of paramount importance. One of the things some other people did in the past was to build these short line railroads, and that's given us a great deal of flexibility in working constructively with our friends in the railroads.

Got you. So the full requirements nature of the contract essentially gives you the flexibility I'm talking about. So there really isn't a lot of renegotiation going on.

There's an ongoing level of renegotiation. It's nothing that is extraordinary.

Okay, perfect. And then onto Vogtle, and I'm speaking specifically, Tom, of the dispute you've mentioned regarding COL and DCD timing. Can you give us sort of a sense of the aggregate dollars that are in dispute?

I don't think that's been disclosed, so let me kind of beg off on that. We'll get to it later. You should just know, so here again. There've been lots of commercial claims back and forth and all that already. We don't talk about those as a matter of course, only because they need to get viewed as kind of a basket. If we got into disclosing every commercial claim, whether it was sensible or not, and time frames and everything else, as a practical matter, that's just not a good thing to do. So as we get significant commercial claims. Obviously, if it's material, we'll let you know. It will be disclosed. But otherwise, until things are in the form of a formal claim, probably not good to talk about.

I absolutely appreciate how these things work, I guess maybe a better way to ask the question is, how closely are you coordinating with your neighbor in South Carolina, who basically already had these issues and settled them? So they did talk about the numbers and that's why I was trying to get it, I'm not forcing you to give a number. I'm just trying to say they've been through this. Do you guys coordinate with them or talk with them?

They have a completely separate regime. In other words, they have a completely separate contract. I can't speak at all to the nature of their contract. All I can speak to is our experience. They obviously settled a claim. We don't have a claim yet. We do know that there's a dispute around schedule. But we don't have a claim. And so therefore, we're not in a position to talk about it, other than to mention that there is one.

Okay, fair enough. And then last question on Vogtle back on the rebar issue. This was a issue versus the DCD, so the Shaw Westinghouse didn't install it properly or was there a problem with the DCD?

I don't want to get too far into this one either. There will be a time for this when they come out. But it really deals with -- it's, "did the rebar as it was installed near the wall section meet the DCD requirements?" That, I think, is the question.

Your next question comes from the line of Paul Patterson with that Glenrock Associates.

I just wanted to touch base with you, just to make sure I understood the load growth Steve was asking. It sounds like you guys are on a weather-adjusted basis, still sort of sticking with a 1.3% low growth, but then it looks like it might be better because of stronger economic growth. Did I understand that right?

You said it perfectly. We're off to a good start.

Okay, and then the second thing I wanted to ask you was the dividend policy. You mentioned about the potential for dividend tax change and your efforts to communicate investors' concerns. What if the taxes were to be broke to the pre-Bush tax cuts, which is one of the potentials we see here with the less than perhaps cooperative Congress? If that happens, does that change the Southern Company philosophy on dividends and payouts, and what have you?

Not in the near term. One of the hallmarks of our dividend policy is one that is regular, predictable and sustainable kind of characterization to it. It is so important in financial signaling theory to be consistent with your approach. We would have to believe that there was a fundamental long-term change in order for us to deviate and we would only do that with extreme care. We really like the track that we're on. In fact, we've got all kinds of interesting statistics. I'm just dying to do one here. Companies that have increased their dividend over 2%, that has a yield over 2% and increased their dividend over 2% over the last decade and have a positive TSR. There's only 2 companies in the S&P 500. We're one of them. We feel like this really inures to the value accretion to our shareholders. With respect to the public policy point here, we've got to stay away from partisan politics and go to what's right for America and we shouldn't be pulling levers to increase our national revenue, if you will, when there are other more effective levers. Recall, that if we tax capital formation, we actually hurt the ability of the economy to grow CapEx and, therefore, grow jobs and, therefore, grow personal income and, therefore, grow taxes. This is exactly the wrong policy to take at this time. One last point: When you consider stocks that have high dividend yields, those are particularly attractive during periods of low economic growth or high relative risk. That is exactly the global economic environment in which we are in. Why in the world we would incent investors to be pushed into riskier capital gains-oriented investments and away from lower-risk, dividend yield-oriented investments is beyond me.

Okay, we'll see what happens. Now the other thing I wanted to ask you was just on the market response rates that impacted you guys a couple years ago in sort of a significant way. Is there any impact that we're seeing associated with that sort of unusual gas versus coal or anything like that, that we should be thinking about?

Yes, Paul, they amended those in the last rate case such that they tied the fuel costs associated with the marginal fuel cost of whatever hour that energy was demanded. So the volatility that we saw several years ago around those RTP rates is no longer there. And if you look at it now, it's just not enough to talk about.

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

First thing I was wondering was related to the financing plan. It looks like you issued about $1.25 billion of debt in the first quarter. And on your financing plan, you mentioned that the DOE loans could be $2.3 billion to $2.8 billion in 2012. So I guess I'm wondering how should we think about the mix between the DOE as a source and the primary bond market as a source of financing for the rest of the year.

Yes, great question. We've got -- actually, we issued $1.4 billion in the first quarter of new debt. And when we look at the rest of the year, we think we've got about $2.6 billion left to hit our almost $4 billion of target. To the degree that we don't get the loan guarantee, then we'll be going to the markets to raise that capital. But the markets have been in terrific shape to be able to handle that. We'll just have to wait and see where these loan guarantees end up from a benefit to the customer perspective.

Okay. I guess one other criteria that would determine the market's a better way to go or the DOE.

Well, it just depends on the terms and conditions that, with inside the Department of Energy might require us to agree to in order to get the loan guarantee. Certain aspects of that we're just not willing to do.

Yes, and Dan, we could fill you up with what that is. I don't think that's productive. We have a negotiation going on. I think we can get through it.

Okay. Then I'm just curious, I might have missed this at the beginning because I didn't get through right away. But on the nuclear construction, what are the main critical path items that we can look for in 2012, so we can, as outsiders, monitor the progress and make sure that we're still on track?

Well, I think, I guess there's several issues going on right now. The shield building and components related to the shield building are probably the most important. But, in fact, we've talked about this on prior calls in terms of helping you all, and I think that's our obligation, to help you all understand kind of the major milestones and how we're moving forward right now. We'll provide that to you. Maybe we will do a special call or maybe we'll do something. But we owe you that, I think, in the future. but I would say in the near term, it's getting the concrete poured, getting the shield building in place and moving ahead. Those are probably the, I would guess, the big items related to steel production are the big critical path issues right now.

Okay and then kind of related to the revenue impacts. I know you had $0.05 in the quarter of positive impacts. How were those spread between the operating units and then how much of that was rate increase versus stronger-than-expected demand?

Well, it's a mix of both, but you've got some interim rates going on at Gulf that went into effect, and Alabama had a rate T correction that took place in the fall of last year. That actually started going to benefit earnings in 2012. That's the majority of it. The rest would be adders from a little bit of growth that we're seeing.

Your next question comes from the line of Michael Lapides with Goldman Sachs.

Real quick, Southern Power, 2 items. One, are you still 80% contracted? I think you disclosed at one point, at the end of last year, you talked about having some contract roll-off of the beginning of this year impacting Southern Power. And two, would you ever -- I mean, Southern Power, 8 gigawatts plus now, getting pretty sizable. Do you ever think about whether there are other alternatives for Southern Power? Whether to monetize it somehow, separating it from the rest of the utility business?

Michael, this is Art. The contract coverage through 2016 were about 80% covered. And yes, we've had some contracts go off. But we've also got some new ones signed up under the Georgia IRP decision. They approved about 1,000 megawatts of Southern Power capacity coming on in 2016.

2015.

2015. So those, you're going to lose some, you're going to add some back. That's the nature of the contract situation at Southern Power.

Now your other question is a very interesting one and we have talked about that a lot in the past. If you remember, there was, I forget what it was, 3, 4 years ago, the multiples on these kinds of contracted assets was really at a very attractive level. When you think about what Southern Power is, a lot of the -- we really would need to be very conscious of our customer impact there. When you think about having a full requirements relationship in our territory with particularly co-ops and munis that we had a long-standing relationship with, it is conceivable that you would consider other potential owners, whether you sold it outright, sold a minority position, did a variety of things. I think those kinds of decisions are more likely with perhaps, if you will, the non-core pieces of Southern Power, whether it is -- particularly those that are outside our territory. Now one other item I would say, and a place outside our territory that we particularly like and we're gaining critical mass in, is in the Carolinas: Low land [ph], and some of the others, Cleveland County. We're developing a very good relationship. When you think about the nature of our service to our customers, it goes more than kind of a one-off hit-and-run strategy. We are built to last. Our assets have an economic life 40 years or longer. And I think one of the hallmarks of our industry is a long-term view. We believe in cultivating a relationship before we need it and we believe that the relationship, therefore, as we continue to grow our business in these areas of concentration, really matters. So we take the how, if you will, into account as much as the what in terms of valuing that business.

Art, just following up on your comment, does that imply you're less contracted now versus kind of that 80% average, meaning, for the next 2 or 3 years and you kind of ramp into that? Or is it kind of a flat annual average over time?

Yes, well, it fluctuates over time. In 2012, we're about 84% covered. 2013 drops to 81%. And then as the numbers kind of move around, you get to the 80% number by 2016. That's kind of the nature of it.

And then, of course, the further out you go, it kind of has a long, slow slope down. But we kind of have that intentionally in order to give ourselves some optionality with the assets we have to sign things up later. So a little bit of flexibility ain't all bad.

Your next question comes from the line of Anthony Crowdell with Jefferies. Anthony C. Crowdell - Jefferies & Company, Inc., Research Division: Just a quick question on Southern Power. I mean, when we're forecasting Southern Power, I mean is the way to go about it assume like you guys view that as maybe like a regulated business, in all the contracts you enter, you look for, say, mid-teens ROE or whatever the asset value is? Or treat that business as like a full merchant portfolio and kind of price it to where are the current forwards are, or something like that?

We don't disclose the internal rate of return of any contract, but we use as a general planning criteria about a 150 basis-point premium on the contracted resources that we have. That's a general kind of statement. And then for the uncovered portion, what you look for is kind of what's a reasonable expectation as to the energy margin. Last year, I think, Southern Power earned $162 million. Somewhere around there. So I mean that's a decent benchmark to use for last year. Use the criteria I just gave you and estimate for this year.

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

No. Listen, we really appreciate everybody's attentiveness. We always enjoy these calls. It's always fun to chat about not only the issues related at Southern, but the issues related to our industry and America. We appreciate your following and look forward to chatting with you in the future.

Thank you, sir. Ladies and gentlemen, this does conclude the Southern Company First Quarter 2012 Earnings Call. You may now disconnect.