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 there will be a question and answer session. 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 Q1 2013 earnings call. Joining me this afternoon are Tom Fanning, Chairman, President and Chief Executive Officer of Southern Company and Art Beatty, 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 ks 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 web cast 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 atwww.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 Q1 financial results as well as a discussion on sales and the economy.
After closing remarks from Tom, we'll move to Q and A. At this time, I'll turn the call over to Tom Fanning. Good afternoon and thank you for joining us. During the Q1 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 and 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 recently completed the placement of base mat 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 now 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 mat and begin nuclear island rebar for Unit 4.
Georgia Power also received unanimous approval from the Georgia PSC on its 7th construction monitoring report and recently filed a date report, which included the following: a request that the PSC verify and improve all costs totaling 209 $1,000,000 incurred between July 1 December 31, 2012. I requested the PSC amend the existing certificate to reflect revised commercial operation dates for the Q4 of 2017 2018 for Units 34 respectively and a request that the PSC amend the existing certificate to reflect an increase in the projected total capital cost from $4,400,000,000 to $4,800,000,000 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% 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 start up activities. Last month, consistent with the settlement agreement we reached in January, the Mississippi Public Service Commission approved a 2 step rate increase associated with the Kemper Project.
The settlement agreement contemplated a 7 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 lignite dome as well as a 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 estimate 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 date. 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 $2,880,000,000 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 7 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 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 start up activities continue. Meanwhile, we continue to expand our use of renewable energy sources with 2 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 5th solar acquisition and its first in California, Campo Verde more than doubles the Southern Company 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 2 wind farms in Southwest Oklahoma with capacity totaling 2 50 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 a financial and economic review. Thanks, Tom. For the Q1 of a decrease of $0.33 per share. Included in these results is an after tax charge against earnings of $333,000,000 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 $2,880,000,000 cost cap net of DOE grants and exceptions to the cost cap.
Also included is an after tax charge of $16,000,000 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 Q1 of 2012, an increase of $0.07 per share. Earnings drivers for the Q1 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 Q1 of 2013 added $0.05 per share to our earnings compared with the Q1 of 2012.
Weather is actually $0.01 per share below normal for the Q1 of 2013, but that was compared with $0.06 below normal for the Q1 of 2012. Heating degree days during the Q1 of 2013 were 54% higher than the Q1 of 2012. The other significant driver for the Q1 of 2013 was retail revenue effects at several of our traditional operating companies, which contributed $0.04 per share as compared to the Q1 of 2012. Turning now to a discussion of our retail sales results for the Q1 of 2013. Total weather normal retail sales for the Q1 of 2013 decreased 0.9% compared the Q1 of 2012.
Weather normal residential sales decreased 0.9%, weather normal commercial sales increased 0.4% and industrial sales decreased 2.1% compared with the Q1 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 Q1 of 2013. About half of those new customers were new connects, further evidence of a rebounding housing market and a strengthening economy across our 4 state service territory.
Our economists have produced a recent analysis suggesting that 88% of any shift in residential usage is accounted for by 3 factors: weather, the price of electricity and changes in personal income. In the Q1, we saw 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 Q1 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 Q1 of 2013 compared with the Q1 of 2012. This result is consistent with reports indicating that exports from the region declined during the Q1 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 1500 back office jobs in Pensacola, Florida and Median, which is building a new $90,000,000 movie studio in Savannah, Georgia that will employ more than 1200 workers. Sales results for the Q1 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 of 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 2,002, our dividend has increased a 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 Q2 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 a 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. That'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 generation, 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 creation 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 an 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 and a better country. We are now ready to take your questions. So operator, we'll now take the first question.
Thank And our first question comes from the line of Dan Eggers with Credit Suisse. Please go ahead. Your line is open.
Hey, good morning, guys. Hey. Listen, I guess, it's going to be the topic of the day for
a little while, but just on Kemper, can we discuss a little bit more what caused the 20% increase effectively in project cost 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?
Yes, sure. So as we approach these last 12 months essentially, we were looking over our estimates of what it's 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's customers for decades to come.
So we improved that. Secondly, we misestimated 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.
And Tom when you think about I guess first question on that. Is there any ability for money to come back from the E and 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 yes, 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.
But I guess with Vogtle, there's some debate over whether the E and C providers are responsible for some of the cost overruns and the delays. Is there a similar recourse or a debate of recourse with Kemper that you guys could try and get some of the $500 ish million covered by E and C guys other 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 a commercial relationship with the consortium. Further, when you consider the cost impacts on Vogtle, it's pretty clear it's a different manner. When we originally certified the plant, we thought it would be 12% increase.
Now with the additional costs, but moreover, the overwhelming additional benefits, we think that price increase now is reduced to somewhere between 6% and 8%. And while in VCMA, 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.
Okay. Thank you for clarifying that. I guess one last question on Bell. Somebody else talk about that. 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?
Yes. We kind of outlined on the last call that we had plans for $100,000,000 to $300,000,000 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 7 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 establish 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 Amana shares right away, which we don't intend to do right away. So and just recall last year we had negative 0.11 dollars of weather. I think when Art says that we're committed to our annual guidance and our long term growth aspiration, I think we can manage this circumstance quite well. Got it. Thank you, guys.
You bet. Thank you.
And our next question over the phone lines is from Steve Fleishman with Wolfe Tryon. Please go ahead. Your line is open.
Hello, Steve. Hi. Hey, Tom. How are you? Great.
So just same topic. Just in the event that Kemper comes on after May of 2014, is there any issue if it doesn't meet its targeted startup with your settlement or anything like that? Yes, Steve. This is Art. There are yes, certainly the issue around investment tax credits is time sensitive.
So that represents roughly $133,000,000 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 $2,880,000,000 where we would not continue to accrue AFUDC 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. Okay. And is it this is just any time after May of 2014 these questions come up?
Or is it a certain time after that? No, we think it would be that. I mean in other words, the structure that we have will probably accretive UDC up to $2,880,000,000 Beyond $2,880,000,000 with 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 that you would see kind of ratably over the 7 year period.
And within that structure, there's a true up provision and a variety of other things. So we'll just have to see how that would work out. Okay. And just Hey, Steve, the ITC would be reflected over 30 years. So there would be the annual effect of that over 30 years.
So we think it would be kind of small. Okay. And then in terms of the remaining kind of risks in terms of the current budget, is there a certain area that we should be most watchful of where there still could be risk of cost pressure in these last 12 months? Well, I mean, 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 startup activities. Those startup activities have been mostly focused on the combined cycle units and some of the other ancillary areas around the plant. So the big effort is going to be start up around the gas ifier and the carbon capture equipment. It'd be those issues.
I would say instrumentation and control will be the biggest single issue. 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 kind of variable cost of the plant to be in the future? No. Either good or bad?
No. We think on a gas equivalent basis, you're going to be somewhere between $1.25 per 1,000,000 BTU, high capital cost, but cheap energy. And recall, the energy is influenced by the value of the CO2, which is indexed to 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 mouth operation. So low quality. Great. Thank you very much.
You bet. Thank you.
And 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? Yes, I'm here. Sorry about that.
No problem. I had two questions, but you answered the first one on the financing costs of the write down. The second one is just looking at the appendix. When you show your generation portfolio capacity factors and mix. Natural gas prices have run up quite a bit in the Q1.
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 PRB 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 or rest of the year based on where gas and coal prices are now? Yes, sure. Look, me and Arnold tag team this one.
The way to think about kind of our coal to gas energy is really this. PRB is going to come into dispatch somewhere in the $3 range, dollars 3 to $4 So at 4.25 spot gas, you're running your PRB units now, right? So that's Shear, that's Miller. And interestingly, as we evaluate other kind of mixing of PRV in with regular coal that will happen. Now the other thing is we're moving away from Central App coal more to in Illinois Basin coal.
When you look at those units, the Illinois Basin coal, they're going to start dispatching in 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. Mark, do you have anything to add there? Yes.
I'll just point out Greg that right at the end of the month, if you look at our dispatch curve, all the Miller units and at least 3 of the Scherer units were ahead of our most efficient gas units. So that gives you an idea about how sensitive those PRB units are to the gas price in the marketplace. And the other thing that's real oh, go ahead, Greg. I'm sorry. I was going to ask, how do your coal piles in relation to finishing up the answer to this question, how do your coal piles look and how flexible are your contracts such that you can have the practical ability to cycle as these prices move against each other?
Yes. Well, they're higher than we want. But we have plans in place to work them down by certainly 2014 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-60s. It varies by plant to plant to plant. But we have plans to get it all down in place by the right time. And with gas where it is now that's going to bring your PRB files down pretty fast, right? It sure will.
It will help us manage them faster, that's for sure, relative to where they were last year. Very interesting data, interesting data. In the Q1 of 2012, average gas price was $2.50 In the Q1 of 2013, average gas price was $3.50 Spot price 4.25 Remember our cautionary kind of 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 that 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, so I don't know, 35% wait a minute, 45% coal, 35% gas, if coal gets cheap relative to gas. So we can swing significantly here. Thank you, guys. You bet.
And our next question comes from the line of Jonathan Arnaud with Deutsche Bank. Please go ahead. Your line is open.
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 Q4 was that sort of kind of what you had in mind or more severe as in less good than the outlook you gave 3 months ago.
I'll shoot first and let Art fill in. Look 2%, I think adjusting for leaf year is 1%. If you adjust for the outages that we saw with a 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. Yes. And that's true.
There were some other impacts we had with cogeneration going on at some of our paper 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. And I guess 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.
She was 4 projects with 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 look forward to seeing how it unfolds. If I had to say is there a weakness, I would watch out for the global economy and exporting.
Okay. Thank you. Thank you, Tom. And then just on the way you presented the numbers generally, I mean, you obviously have this item you excluded on a leverage lease. Can you just talk us through why you're pulling that out?
I mean, in the past, you've generally typically there's been a pretty high bar for Southern Company to exclude a one time item from numbers.
Well that was I'm sorry Jonathan. Sorry. Go ahead.
No. You I've stated the question. Okay.
That was a leverage 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 Q, I think as long as a year ago describing our 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 $16,000,000 or so. And that's basically the long and short of it.
It. Okay. Thank you. Can I just throw one more issue?
Yes, absolutely.
On there was I think there was talk before of some securitization angle around Kemper. Is that still something you're contemplating? And can you just remind us what's going to happen there?
Yes, sure. That was part of the regulatory settlement we reached earlier this spring. So in essence, additions to rate base are $2,400,000,000 of the plant, the mine and the CO2 pipe. Beyond the $2,400,000,000 of the plant up to $2,880,000,000 of the plant is plus AFUDC and some other items goes to securitization. And we have estimated that amount to be between $700,000,000 $800,000,000 Recall, we had legislation passed that provided for an amount of about $1,000,000,000 So we currently contemplate using somewhere between $708100 of the $1,000,000,000 securitization available to us.
Right. And then obviously as you're eating everything above $2,880,000,000 on the plant that's not part of our 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 majeure change in law, beneficial capital or project development allowances, essentially actions we take on the plant site while we're building it to improve its performance. Those things remain exceptions to the cap.
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 2 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 7 year plan as well as prudence hearings. Given all of that work, when we came up with the increased estimate, we 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.
Okay. So even if they could technically fall under the exception, you're choosing not to?
Not with these. These costs we are talking about don't fall under any of those exceptions. To the extent something arises in the future,
And our next question comes from the line of Julien Dumoulin Smith
Hey, it's Julian here. Can you hear me? Oh, absolutely. 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 DC?
So 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 we'll be able to adjust to whatever new regulations, we'll have some time to do that well into the future. There are some significant capital costs associated with whatever EPA has us do with coal ash.
At one time that was in our 3 year budget. Our sense is now that there won't be any significant capital in the 3 year period that we disclosed 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 compliance costs that exceed our incremental costs for MAX. We just believe these costs including coal ash, effluents and 316B will likely be outside the 3 year estimate period now. Great.
And then does the what came out here on the affluent side, does that change what you're talking about at all? Or just in terms of the timeline, you talked about 3 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. Great. Thank you very much. You
bet. And our next question comes from the line of Paul Ridzon with KeyBanc. Please go ahead. Your line is open.
Good afternoon, Paul. Hey, Paul. 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 7 year rate plan, which was contemplated in the settlement. And the other thing still in front of us are prudence questions, okay? So we'll do a prudence review of building the plan. It's asking what engineering has not done. I mean, could you like other piping issues that could arise?
I really think the issue there goes to what I described before. It's going to go to as we complete start up activities, recall we're 40% complete right now. So what startup remains goes to the I and 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 date. So we got to hit our productivity levels.
And with regards to the ITC, when does the plant have to be up to qualify for that? Well, there's several phases of ITC involved here. Phase 1 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 sometime in 2016, April of 2016. We have also Paul applied for some additional Phase 3 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. And then if you could just talk, you gave 2nd 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 Q1 than you will in the second because you had some increases in the Q2 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 and M side are be the drivers that I can think of off the top of my head.
What was weather like last year? Do you recall? I think weather was $0.01 positive in the Q2 of last year. But of course, Q2 is not a big weather month anyway. No.
And the weather has been so 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 heating 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 roughly.
Got it. Thank you very much. You bet.
And our next question comes from the line of Michael Lapides with Goldman Sachs. Please
Just quick update, if you don't mind. I remember last year there was some litigation or I think mediation regarding the contractors, the Schall Westinghouse Consortium 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?
Yes. I'm afraid it's going to be a short answer. I wouldn't think there's going to be more here. I just can't update it a whole lot. I would argue that there has been positive developments.
And I one of the positive developments has been that within the consortium, right? So the consortium is Toshiba Westinghouse and it was formerly Shaw. Now Chicago Bridge and Iron has essentially bought Shaw. We think that is marginally a We looked at a variety of different things. We went through mediation.
And after mediation, we go through litigation. We filed losses. We still have determined venue whether that is Washington D. C. Or Augusta, Georgia.
So that remains in front of us. But look, we have we've met with management of both Westinghouse, Sean, 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.
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, etcetera, when do you start seeing a need for new gas fired generation?
Yes. That's a great question. I'm going to guess what you think are 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.
Got it. So in other words, the McDonough plants as well as the Vogtle and Kemper plants kind of meet your really your baseload and intermediate load supply needs for 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 got Bogle, you 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 2020s.
Got it. Okay. Thank you, Tom. Much appreciated.
You betcha.
And our next question comes from the line of Carrie St. Louis with Fidelity. Please go ahead. Your line is open.
Hey, Carrie. Hi.
How are you?
Hi. How are you? Hi.
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 cost at Kemper County and some of the slide.
We're still evaluating the timeframe slide. We're still evaluating the timeframe around which those dollars will be spent. So we will probably address that in the 10 Q and you'll see some more detailed information there.
And in terms of Southern Power, you a number of $900,000,000 Do you think that is it's going to be higher than that this year? Or is that still a good number for all of 13?
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 are 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.
Okay, great. And then I was just wondering if you had spoken to the rating agencies with respect to the Keumper County overruns and had any updated views from them?
We have spoken to all 3 of the rating agencies. We have reviewed the situation with them and they've given us a response that yes 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.
Just so I 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 to ask this before, but kind of a limit on how low you would like the Opcos to be rated? Like would you like them kind of all in the A category or you're indifferent? Just how should we think about your credit quality commitments for the operating companies?
Yes. We'd like from all of them in the A category. So A3 is kind of as low as we want to go with Moody's.
Okay. And so just the
way I understood that commitment, so your discussion is the parent will push funds down into Mississippi Power to get it back up to its regulatory capital structure?
Yes. So as Art described earlier, we'll make a capital contribution down there to preserve their financial integrity. How we do that at the Southern level, we'll see over time.
Okay. But you would envision doing the infusion down in the Mississippi Power sometime soon or this year. How have you thought about that?
Well, that's a function of the CapEx when they spend it. Okay. And so that will over the next by the time it goes into service, we'll be back to a closer level.
Okay. What is their allowed equity or structure down at Mississippi Power?
It's basically a fifty-fifty and that's consistent with what they filed for in their 7 year plan.
Okay, great. All right. Thank you very much.
Thank you. Nice talking to you.
And our next question comes from the line of Ali Agha with SunTrust. Please go ahead. Your line is open.
Ali, how are you? Good. Good afternoon. How are you? Super.
Good. Hey, Tom, if you look at the 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? And I mean
Yes, absolutely. Thanks. It still is terrific. Now obviously, we're disappointed. Nobody wanted to have this overrun and 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 camper 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, there are about a third coal, a third Kemper, a third natural gas. And recall the energy equivalent, dollars 1 per 1000000 BTU of Kemper is going to be somewhere between $1.25 per 1000000 BTU with very low volatility.
Unlike natural gas and we pointed out before a quarter ago, 2.50 per 1000000 BTU, 1st quarter, 3.50 per 1000000 BTU at 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 say all 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 Economic dispatch, Kemper looks like a nuclear Economic dispatch, Kemper looks like a nuclear plant.
High capital cost, cheap energy, we think it makes sense.
Okay. Fair enough. Second question, I wanted to clarify. I know for planning purposes you talked about 2% UDB growth and 1.3% or so weather normalized demand growth. I wanted to be clear is that what you're assuming in your 2013 guidance as well that demand growth number?
Yes.
Okay. And my last question and you talked a little bit about some of the additional projects that are coming in within the Southern Power footprint, renewables, etcetera. But also I thought Tom you've 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 model for you guys?
Yes. It is where it was. I would just pick it just a couple of words. We're not expecting the business model per se. The business model for us would be essentially long term bilateral contracts, creditworthy 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. The second contract typically we associate would be essentially energy, which is mostly fuel. And there's some upside in those contracts, but very 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 flushed with capacity and we have been approached by other people. We've gone outside the Southeast really in order to do renewables, right? So the biomass deal at 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 try to do these long term contracts.
I don't know specifically what the latest kind of 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 at the expiration of a long term kind of 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.
Okay. Okay. Fair enough. Thank you.
Yes, sir.
And our next question comes from the line of Mark Barnett with Morningstar. Please go ahead. Your line is open.
Hello, Mark. Hey, good morning. Hey, how are you? Great. 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 kind of big kind of structural changes that you might be looking at maybe a change from a 3 year cycle in that filing? Or is it too early to comment? Yes. 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 1 year rate filing. And then we file we've been under since 1995 a series of 3 year accounting orders, which generally have a much more fluid structure. So what we've been what we had with the Georgia regulatory process, the Georgia commissions 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 Georgia's customers. Okay. And just one quick question on the Boeing 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 would just want to get a little clarity on what's happening around that unit. So we don't have any filing associated with the Bowen problem there. What we have the filing that was made was a sale of a CT associated with Unit 6. Here's the issue.
We're really not prepared to talk very much about Boeing yet. Any event like that we do what's called a root cause analysis. That root cause analysis has not yet been complete. And we're very careful even internally talking about that until we see what the facts are. That 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 Unit 34 to in service Unit 1 and what to do about repairs associated with Unit 2. Okay. I appreciate that. Yes, I had seen that finally and I 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 Boeing 1 through 4. Thanks. You bet.
And our next question comes from the line of Andy Levi with Avon Capital. Please go ahead. Your line is open.
Hey, Andy. Hey, how are you guys? Great. I don't really have any I guess I have 1 or 2 questions left. Just clarification, I guess, if you could ask this to IR.
But just on the sales growth forecast that you gave, did that they gave on the Q4 call and gave guidance. That includes the effects of leap year or did it include I'm just not clear on that. Yes. It contemplated the leap year effect. Okay.
So the sales that you're showing here for the quarter are really versus your guidance and we wouldn't strip that. They're actual to actual. I would say, but that's year over year. Right, right. But we compare it to your guidance, not stripping out the LEAP year and going back to flat, right?
Well, we're just giving you color on the year over year comparison is all we've done. Yes. And Andy, when you think about it, so the leap year effect really occurs in the Q1 and then it diminishes as the year goes on. So you have essentially 1.90th which is about 1.1% difference. Afterwards, once you get to 360, the leap year effect almost washes out on any year to date comparison.
So kind of washes out by the year. That's why you got to kind of account for it in the Q1. Yes. Got it. Okay.
Thank you. And then is there a way to get a breakdown on Kemper as far as the $5,000,000 $50,000,000 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. Got it. Okay. And let me see here. I guess that's it.
Thank you. All right. Thanks, Steve.
And our next question comes from the line of Ashar Khan with Visium. Please go ahead. Your line is open.
Hey, Ashar. How are you? Pretty good, Tom. How are you doing? I'm sorry I was off
a little bit. I don't
know if 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 are there going to be some kind of ITCs that are going to be recognized as part of earnings? So I don't know if you discussed this already or not.
Is there anything you can provide? Ashar, this is Ark. You'll see more information on that in our 10 Q. We have an agreement with the purchase agreement where we agreed not to disclose the purchase price until we have an obligation to do so. 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 will be recognized and our guidance contemplated the projects. This is one of those placeholders I was referring to. So we filled 1 of the placeholders. Okay.
And the plant does come into operation, right, at the end of the year? Yes. Okay. Thank you so much. You bet.
Nice talking to you.
And our next question comes from the line of Dan Jenkins with State of Wisconsin Investment Board. Please go ahead. Your line is open.
Hey Dan, how are you? Good. How about you? Great. You mentioned that you'll provide more info on the revised CapEx in the Q, but would it be the same for the financing?
Can you give us any color on how financing plans would change given the higher tempered costs and so forth? Well, the financing cost, we talked about this earlier. Mississippi's additional cost to for the $540,000,000 will be financed with a mix of capital. We'll download some capital from Southern to support the equity side and they'll 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.
Of course Southern it's a much smaller impact on the Southern level than it is at Mississippi. So we'll deal with that equity issue over time. 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 don't have a feel for exactly when they're going to spend that money. So we can update you later on that. Okay. And then going back to your appendix where you show the capacity factors and generation mix, Just wondering if you could give us what the capacity factors were for the nuclear in 12 to 13 with Q1? Yes.
Can you hold on just a second? I'm going to have to look that one up. And then somewhat related to that, just the generation mix declined in nuclear. I assume that's related to additional outages. Is that correct?
And what would that be? That's correct. Yes. What would that average stays in each quarter? Do you know?
I don't have the outage. We'll get that for you, Colin. The capacity factor in 2012, I think it was Q1 was 93% and 2013% was 85%. Okay. Thank you.
That's it, I had. All right, Dan. Thank
you. And our next question comes from the line of Paul Patterson with Glenrock Associates. Please go ahead. Your line is open.
All right, Paul. Hey, how are you doing? Can you hear me? Yes. Yes, sure.
Pretty quick. Just there's this footnote that says also reflects reclassification of January 2012 kilowatt hour sales among customer classes consistent with actual advanced meter data and the use of the advanced meter data, I guess, was implemented in the Q1 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 last end of the Q1 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 disrupt the reporting numbers so we normalized for those effects. And that didn't have did that have an impact on the year over year weather normalized numbers?
Well, it did have an impact, but it normalized them in a way that we think is more meaningful. 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 changed. I got you. Okay. Okay.
Sorry, we said slow. Okay. And then in terms of just if I understood anything, the GDP forecast and sales force and cats and everything hasn't changed from last quarter. Is that correct? That's correct.
Okay. And then just I guess at Kemper, it does seem that I mean, I'm just wondering, is there some specific design issue with IGCCs that we should know about or that you guys have I mean, it just seems that this thing is such as you guys, I mean Duke 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 we've sort of what you guys have learned in this process as to what this what's going on or Yes. Paul, I would argue this. Our circumstance is completely different than what Duke has experienced.
Duke is buying a very different kind of gas ifier. They're buying it with a contractor 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 did the FEED study, the final engineering and economic design of Kemper County, for everything that we did the FEED study 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. Okay. Just with respect to the you guys mentioned that you thought that the costs 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 being cautious, but I mean, can you give us any sense, I mean, is there I mean, you mentioned that there were several other steps that still have to be taking place. I mean, is there a potential for another big I mean, 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 or? 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. Now 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, would that what kind of exposure would we be talking about?
Well, it's IPC that would be ratably given to customers over 30 years. So, what would you say $133,000,000 over 30 years that would be the annual effect. The other thing that Art mentioned just to add back is this 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 an additional 90,000,000 dollars So that could serve to offset if we missed some of the other.
So we'll see. Okay. And that goes to customers. Is that right? Yes.
Ratably over time. Okay. Thanks so much. Yes. And all of that is in our plan that we filed.
Okay. Great. Thank you. Yes.
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 performance that 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 $20,000,000,000 of a gas generation fleet in an environmental control fleet under budget on time and better functionality than what we expected. This is unusual performance for us and 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 First Quarter 2013 Earnings Call. You may now