Southern Co (SOMN) 2015 Q3 法說會逐字稿

Good afternoon. My name is Julian and I will be your conference operator today. At this time I would like to welcome everyone to the Southern Company's third-quarter 2015 earnings call. As a reminder today's call is being recorded, Wednesday, October 28, 2015.

(Operator Instructions)

I will now turn the call over to Mr. Dan Tucker, Senior Vice President and Treasurer. Please go ahead, sir.

Thank you, Julian. Welcome, everyone, to Southern Company's third-quarter 2015 earnings call. Joining me this afternoon are Tom Fanning, Chairman, President, and Chief Executive Officer of Southern Company; and Art Beattie, Chief Financial Officer.

Let me remind you that we will make forward-looking statements today in addition to providing historical information. Various important factors could cause actual results to differ materially from those indicated in the forward-looking statements, including those discussed in our 2014 form 10-K and subsequent filings.

In addition, we will present non-GAAP financial information on this call. A reconciliation to the applicable GAAP measure are included in the financial information we released this morning as well as the slides for this conference call.

Slides we will discuss on today's call may be viewed on our investor relations website at investor.southerncompany.com. At this time, I'll turn the call over to Tom.

Good afternoon and thank you for joining us. As always we appreciate your interest in Southern Company. As you can see from the earnings materials we released this morning and the announcements we made last night, we have a lot of good news to share today.

First, our traditional operating companies continued to operate superbly in the third quarter of 2015, and they are on track to deliver on their financial targets for 2015. Second, Southern Power also performed exceptionally well in the third quarter, exceeding our expectations.

So far this year Southern Power has announced 12 new renewable projects with an ownership stake in these facilities of just over 1,000 megawatts. Third, we've entered into an agreement to settle the commercial litigation associated with Vogtle Units 3 and 4, and better position the project for the remaining months of its construction.

And fourth, we achieved a major technical milestone in our Kemper facility with outstanding initial results in the fluidization testing phase of [Stardust]. In a few moments Art will discuss the drivers of our third quarter performance in more depth and provide our earnings estimate for the remainder of the year.

Let's now discuss the project -- the progress on Vogtle and Kemper in more detail. First, an update on Plant Vogtle Units 3 and 4. As you may have seen in our disclosures, we have agreed on terms to resolve the outstanding litigation with our EPC contractors.

As we have shared previously on these calls, we believed the main obstacle to resolving these issues outside of court was the disagreement that existed among and between the contractors themselves. In a major move to resolve these disagreements, Westinghouse has agreed to purchase Stone & Webster, the AP1000 construction arm of CB&I and consortium partner in our EPC contract.

Under the proposed transaction, Westinghouse and its affiliates would serve as the prime contractor for the project. Not only is this expected to make activities more efficient at the work site, it would also remove a lingering concern about contractor financial stability.

Contemporaneous with that transaction's closing, we will agree to settle our commercial dispute. The proposed settlement contains the following key terms.

First, all open claims, including any potential extension of those claims as well as future claims that could have been asserted under the original terms of the EPC agreement, will be dismissed. This includes the ongoing litigation in Augusta, Georgia.

Second, the EPC agreement will be amended to restrict the contractor's ability to seek further increases in the contract price by limiting changes which constitute NRC changes in law. Third, the guaranteed substantial completion dates in the EPC agreement will be extended to June 30, 2019, for Unit 3 and June 30, 2020, for Unit 4, consistent with the current project construction schedule.

In exchange for these benefits, Georgia Power has agreed to pay approximately $350 million. The cash impacts of this amount are as follows. $121 million has already been paid as Georgia Power's share of disputed invoices.

$114 million is to be paid upon the finalization of the agreement. And $114 million has been structured as milestone and incentive payments heavily weighted to fuel load in December of 2018 and December of 2019.

We are very pleased with these terms, as they would achieve several key very important objectives. First, these terms reaffirm our current schedule and incentivize the contractor to meet it.

Second, the terms streamline resource deployment by removing inefficient contractor interactions. Third, they should reduce the risk associated with potential future claims.

And fourth, these terms reinforce how well the EPC contract protects customers. In fact, customer rate impacts for Vogtle Units 3 and 4, even with this settlement, are projected to be well within the previously disclosed range of 6% to 8%.

In fact, our current projection, including the settlement, is less than 7%. With 4.5% already in Georgia Power's rates, this suggests that the rate increases through the completion of the project will be less than 2.5%.

Moreover, the proposed settlement amount is significantly less than the amount of the contractor's claim in the current litigation which only includes their estimated cost for approximately 21 months of delay. Without a settlement, the contractors could have asserted additional claims, including their estimated cost for all or some portion of up to 18 months of further delays.

As a part of the settlement, we also sought additional protections from similar lawsuits in the future. We believe the proposed amendment to the change in law provisions of the EPC contract are perhaps the most significant element of the agreement.

So again, we are gratified to have reached this agreement which, with a proposed settlement cost of approximately $350 million, we believe that this proposed settlement is exceedingly favorable for customers and for the overall success of the project. The Georgia PSC has been briefed on key terms of the agreement.

Their initial reaction was positive and they understand that it removes a significant overhang. Georgia Power will submit the ultimate settlement agreement and related amendments to the EPC agreement to the PSC for a more detailed review.

Finally, as anticipated on our last call, we achieved several major milestones this last quarter for Vogtle Units 3 and 4. The most notable was the placement of the CA01 module in Unit 3.

Located inside the containment vessel, this module will have the steam generators at 2.3 million pounds. This was the heaviest lift to date on the project.

We also began installing the first of many shield building panels for Unit 3, and we installed the CA04 module for Unit 4. This module will ultimately have the reactor vessel for Unit 4, which is already on site.

Let's turn now to an update on the Kemper County facility. During our earnings call one year ago, we announced that the combined cycle was in service and that the remaining construction schedule for Kemper had been extended into the first half of 2016, and that we planned to take a very methodical approach at the completion and start up of the remainder of that facility.

Today those decisions are benefiting the entire project. The combined cycle has been performing exceptionally well for more than a year, providing some $23 million in energy savings for Mississippi power customers.

The gas plant has been operating with an equivalent forced outage rating of less than 1%, compared with an industry average of more than 6%. We are also well under way with major start-up activities.

Last week we began fluidization trials on the first of the two gasifiers. As a reminder, the fluidization test is the process in which sand is used as a substitute for lignite in order to test the flow of solids through the gasifier vessel.

Not only does this process validate a critical component and scale up of the technology, but it also allows the operations team to test and fine-tune control systems beyond what is possible with simulators. We are extremely pleased with the results so far.

In fact, the tests are going even better than what we expected, and we will take valuable lessons learned into the testing of the second gasifier later this year. In addition, we plan to conduct final commissioning of our lignite preparation systems over the next several weeks and begin the cure out process for the gasifier refractory in preparation for the first production of syngas.

As we closed yesterday on our 8-K, we have increased the estimated cost subject to cost cap by approximately $150 million. Approximately $60 million of this amount has been incurred to address issues identified through our start-up and checkout process as well as to help prepare the plant to operate more reliably with either lignite or natural gas.

These efforts have positioned the project for the success we are experiencing today with the major start-up activities. The remainder of the increased cost is for additional scheduled contingencies we expect to incur, with an in-service still scheduled for the first half of 2016 consistent with our previous and current disclosure.

As we have said many times in the past, we will not take shortcuts or sacrifice safety in order to expedite completion of the plant, and we remain committed to providing a world-class generating facility for customers. Finally, with respect to regulatory matters in Mississippi, our immediate focus is on getting permanent rates in place for the assets already placed in service.

Hearings are scheduled to begin November 10, and we expect a decision from the public service commission on or before December 8. I'll now turn the call over to Art for a financial update.

Thanks, Tom. For the third quarter of 2015 we earned $1.05 per share compared to $0.80 per share in the third quarter of 2014, an increase of $0.25 per share. For the nine months ended September 30, 2015, we earned $2.30 per share compared to $1.88 per share for the same period in 2014, an increase of $0.42 per share.

Earnings for the three and nine months ended September 30, 2015, include after tax charges of $93 million, or $0.11 per share, and $112 million, or $0.13 per share, respectively related to increased cost estimates for the construction of Mississippi Power's Kemper County project. Earnings for the three and nine months ended September 30, 2014, include after tax charges of $258 million, or $0.29 per share, and $493 million, or $0.55 per share, respectively related to the Kemper County project.

Earnings for the three and nine months ended September 30, 2015, also include after tax charges of $12 million related to the proposed acquisition of AGL Resources. Earnings for the nine months ended September 30, 2015, also include a $4 million after tax charge related to the discontinued operations of Mirant and the March 2009 settlement agreement with MC Asset Recovery LLC.

Excluding these items, earnings for the third quarter of 2015 were $1.17 per share, compared with $1.09 per share for the third quarter of 2014, an increase of $0.08 per share. Earnings for the nine months ended September 30, 2015, excluding these items, were $2.45 per share compared with $2.43 per share for the same period in 2014, an increase of $0.02 per share.

Earnings for the third quarter of 2015 were driven by positive retail revenue effects in our traditional operating companies, partially offset by increased operations and maintenance expenses. Quarter over quarter, earnings were also positively impacted by Southern Power's recent project development and acquisition success.

A more detailed summary of our quarter-over-quarter earnings drivers can be found in the slide deck posted on our website. The southeastern economy continues to grow, supported by robust employment growth, a steady recovery in the housing sector, stronger than expected consumer spending, and continued in-migration into our region.

As a result we experienced positive growth in retail sales in the third quarter, as total weather-adjusted retail sales increased 0.2% over the third quarter of 2014 and 0.6% on a year-to-date basis. Weather-adjusted residential states were up 0.1% over the third quarter of 2014 and 0.5% year to date.

This growth has been driven primarily by customer growth, which is approaching historical norms for the first time since the recession. For the first nine months of 2015, nearly 28,000 residential customers were added across the Southern Company system with 38,000 added in the last 12 months.

Weather adjusted commercial sales were up 1% during the third quarter of 2015, compared with the same period in 2014. Growth in commercial sales has been consistent across all three quarters this year and reflects improved in-migration, growth in the residential customer base, modest income improvement, increased consumer confidence, and spending.

Consistent with this data, the Atlanta office market absorbed almost 2.2 million square feet in 2015, driving the vacancy rate below 17%, the lowest level since the end of 2008. While industrial sales are up 0.5% year to date, they fell 0.6% during the third quarter.

A strong dollar, low oil prices, and weak global growth conditions continue to constrain growth in the industrial sector. Exports remain on a downward trend, although our region continues to fare better than the rest of the nation.

While the performance of industrial segments such as chemicals, primary metals, and paper has lagged, those results had been at least partially offset by improved performance in the transportation segment and in construction related segments such as lumber and stone, clay, and glass. Our economic development pipeline remains robust and on a positive long-term trajectory.

In September, Mercedes-Benz announced that it will be producing a new hybrid SUV at its Vance, Alabama plant. This $1.3 billion project will result in the expansion of its SUV assembly shop and the creation of 300 new jobs in 2017.

Tuscaloosa-based SMP group and Birmingham-based Magna International, both suppliers to Mercedes-Benz, plan to add 600 and 350 jobs respectively. You will recall that Mercedes-Benz is moving its headquarters to Atlanta.

It's recently been announced that Lincoln Financial Group will also relocate to Atlanta, adding 600 jobs in 2016. In addition, Norcross, Georgia-based Suniva, a manufacturer of solar panels, has also announced it will add 500 jobs in the immediate near term.

To date more than 12,000 new jobs have been announced in our service region this year. This represents an increase of more than 250% compared to the first nine months of 2014.

The projected investment for new projects announced year to date is $4.8 billion, a 95% increase over the same period in 2014. Before I share our earnings outlook for the remainder of 2015, I'd like to provide an update on Southern Power capital expenditures resulting from the recent successes that Tom noted earlier.

In February of this year we provided a forecast for Southern Power capital investments totaling $1.4 billion, with $600 million of that set aside for placeholder projects. Southern Power's success in finding value-accretive projects has exceeded our expectations.

Strong relationships, tax appetite, and a proven ability to close transactions have made Southern Power an attractive partner for acquisitions in the renewable market. As a result, Southern Power is now projected to have capital investments totaling $2.3 billion for 2015.

Similarly for 2016, Southern Power has already secured project investments consistent with our earlier forecast of $1.3 billion, with even more projects still under consideration for that year. We are optimistic that Southern Power will exceed its current forecast for 2016 much as it has surpassed its 2015 forecast.

Since 2010 when Southern Power made its first investment in utility scale solar with the Cimarron Solar Facility, Southern Power has developed one of the nation's largest contracted renewable portfolios, with more than 1,600 megawatts of generating capacity announced, acquired, or under construction. Key attributes of this portfolio include long-term contracts averaging more than 20 years in length, high credit-worthy counterparties, and a long-term low-volatility cash flow profile that is an excellent complement to the rest of Southern Power's generation portfolio as well as to Southern Company's overall financial objectives.

Turning now to our fourth quarter estimate or earnings per share guidance for 2015, our fourth quarter estimate is $0.43 per share. This implies a year-end result of $2.88 per share, excluding charges associated with Kemper, AGL, and Mirant related items, which is at the very top of our annual guidance range of $2.76 to $2.88 per share. I'll now turn the call back over to Tom for his closing remarks.

Thanks, Art. As evidenced by our discussion today, the third quarter of 2015 was indeed a remarkable quarter. However, I would be remiss not to mention that the most significant measure of our performance is always customer satisfaction.

With that in mind, I am pleased to report that our four traditional franchise utilities have once again ranked in the top quartile for customer satisfaction for the 14th consecutive year in our annual customer value benchmark survey. Among three national peer utilities, Alabama Power, Gulf Power and Georgia Power, are the only utilities to rank in the top quartile for all three customer classes: residential, general business, and large business.

As always, it is our customer-focused business model with its emphasis on outstanding reliability, best-in-class customer service, and rates below the national average, that remain the cornerstone of our business and a key driver for long-term value to Southern Company's shareholders. We are now ready to take your questions. Operator, we'll now take the first question.

(Operator Instructions)

Our first question today comes from the line of Anthony Crowdell from Jefferies. Your line is open. Please, go ahead.

Good afternoon.

Anthony, how are you?

Hey, man.

Never been better. How about yourself?

Thanks. Doing great.

Just two quick questions. First on Southern Power, what is the Company seeing in the market right now for a price of like utility-scale solar?

Well, Anthony, this is Art. It depends on the PPA contract and how old it might be. More recent contracts are priced a lot lower than the older ones, and that's a function of the time frame of when that original PPA was established. So I have a hard time giving you an answer about -- that wouldn't be very meaningful to you.

The general trend is newer contracts are cheaper than older contracts. Prices are coming down.

Okay. Moving to Kemper, you guys seem like you're making some great headway at Kemper in start up. But earlier this month the Mississippi staff had filed a recommendation or I guess their view of the project.

And they're looking at something I guess a start-up date much different than what the Company is forecasting. Are there any big differences or things you think maybe the staff has missed and why you're more optimistic on a first half 2016 start up where I think the Mississippi staff engineer put it somewhere like a 30% likelihood of a 2016 start up?

Yes, Anthony, it really goes to people's assessment after the technology risk. This is a first-of-a-kind technology.

And if I had to segment the four big tests we've been going through, the first one I think was a test of I'm going to call it the structural integrity when we pressurized the whole facility. The second test really went to first fire of the boiler.

The third test is the fluidization test. The fourth test will be essentially turning lignite into syngas.

And when I think about that, the most important of these tests I think from a technical standpoint was this fluidization test. Recall the scale up from Wilsonville to plant Ratcliffe in Kemper County is about 100 to 1.

I think different people saw our ability to do that differently. In fact, I know there were some people that were very dubious of our ability to achieve that kind of performance with scale-up.

Just as serendipity would have it, I was at the plant walking the plant site and in the control room on the day that we passed the first test. It started at midnight and went through -- and actually they're still going through it right now.

But I can tell you once we hit the fluidization process, it was amazingly stable, even in, say, the first eight hours of the test it was amazingly stable. Obviously there's always little fine-tunings, and that's one of the things that they're working on through the balance of the fluidization test for Unit A.

But I would just say that outsiders looking at this technical process would have put a lot more risk associated with that. The fact that -- you know, look, I should say that we expected to be successful. We didn't expect it to be as good as it went, so we're very happy with it.

Great. Thanks for taking my questions.

You bet. Thank you, bud.

Our next question comes from Dan Eggers from Credit Suisse. Your line is open. Please, go ahead.

Good afternoon, guys. Tom, just on the renegotiation on Vogtle, you have long said that your contract was a fixed fee contract, and you had a lot of protection, and it seems like you renegotiated that contract in exchange for money. Can you lay out for me what pieces got better in the contract from what you had before to justify the extra money going to the EPC guys?

Yes. Dan, if you think about what gave rise to the commercial disputes and the litigation, the original agreement resulted in disputes that arose from field interpretations of a broad range of NRC regulatory requirements. In other words, the contract said you've got to do it if the NRC regulator requires you to do it.

They would dispute a field interpretation of a requirement, okay. The revision in the language, which is much tighter, says that going forward only new regulations or guidance documents, these are actual pieces of paper, that are officially issued and acknowledged by the NRC as changes to the agency's previous positions will be considered owner's responsibility.

It is a very much narrower definition as to what is eligible for a change order. That's a really big deal.

I guess Toshiba certainly had other problems in the press. How did you get comfortable with concentrating your performance needs on them? And did they make any financial guarantees to put collateral credit aside to cover if they end up running overruns that are on their tab versus your tab?

Oh, my gosh, I think we're in so much of a better shape. Dan, you could phrase the question that way or you could phrase the question about CB&I and all the concerns there.

Basically we put Westinghouse right in the front seat. And you may recall from the issues you raised about Toshiba, Westinghouse had taken its accounting charges I think around 2013, somewhere around that time frame.

And they were not subject to their business -- Westinghouse's business was not subject to a lot of the concerns that Toshiba entered into in its accounting problems. So Westinghouse itself did the hard work earlier in time.

They are not impacted directly, and we think that going forward the balance of risk is much improved for the project for Westinghouse to take the prime contractor role and not have to deal with a co-dependent role with CB&I. We're much better off.

I'm sorry for belaboring this. I just want to make sure that I understand the pieces.

You guys and SCANA are now targeting the same in-service dates, or guaranteed in-service dates for your units. Is there enough trade labor to be executing the same finishing work at the same time?

Yes. We have all of the labor we need on site, and let's be very clear that labor now transfers from CB&I to Westinghouse largely, for the most part. And we believe -- while whatever you say about the schedule dates, we think we're about two months ahead on a schedule basis, at least than they are.

We believe we've got plenty of personnel. You may have also seen that Westinghouse has entered into some conversations with Fluor about augmenting personnel on the site. So we feel great about where we are there.

Very good. Thank you, guys.

Yes, sir.

Thank you.

Our next question comes from the line of Steve Fleishman from Wolfe Research. Your line is open. Please, go ahead.

Hey, Steve.

Tom, hello. Good afternoon. A couple of questions. First, just kind of a technical question on your financing slide in here.

So you have I think $2.12 billion of equity over the next three years in here. And the last time you did this slide after the AGL deal, there was none. Is that just that you're now including the equity to fund the AGL deal in the plan and that's the only difference?

Yes, sir, that's correct.

Okay. That's what I thought. Secondly, on Southern Power, maybe just overall, what kind of returns are you earning on these projects that you've won over the last year? Or what kind of expected returns?

Every project is a little different. We have been over this on calls in the past. We use the same methodology that we used in the past.

In other words, we use a whole rate that looks like a yield curve. And the shape of the yield curve, or the requirement, where you are on the yield curve, is based on a variety of factors including the term of the contract, any of the project's specific risks, things like that.

In general what we have said is that the ROE, the book of ROE of Southern Power is expected to exceed our regulated book ROE by some amount. We've used -- and again it depends. A longer-term contract will resemble a utility return.

If in fact there are greater risks in a utility project, then we can see 150 basis points higher. That would be the general range that I would be looking for.

That's good for not just the whole, so that's good for the new investments that you've been making.

Absolutely.

And are you doing these -- and how generally are you levering these projects? 50/50?

Southern Power is about 45% equity, 55% debt. That's the way we've financed that organization for years now.

Yes, we think that corporate financing is much more effective, more flexible, and cheaper than project financing.

Okay. And then just --

Excuse me, Steve. One more thing, just to be clear, when we look at these things, they're all on an IRR cash basis. You asked for a book return. But same thing.

Okay. So it's low, low teens, low to mid-teens IRRs? Or, excuse me, levered IRRs?

Yes, for an unlevered IRR it would be 6% or 7%, depending on -- it would be just identical, just like I said, either identical to or slightly higher than what we would see out of the core utility business.

Okay. And then just so I understand the -- based on this kind of new -- what's locked up for Southern Power and the update that you've given, roughly what level of ITCs do you expect to have in 2015 and 2016 or at least in 2015? Could you give us that number?

I'll get somebody to do that. Or I'm digging for the specific number now. We're assuming in everything we're looking at 30% ITC goes away in 2017.

So it's just 2015 and 2016 left. Frankly, our relationship that we've developed with people like First Solar and others, our ability to execute quickly, our tax appetite, have all given us I think this kind of flow of feel our way.

Steve, the number that -- I can't find the number. The number I recall is about $55 million this year. That probably compares to $45 million to $48 million last year, somewhere in that range.

We'll get it for you later.

Okay. Then lastly, it looks like based on the fourth quarter projection you're going to end up the year at about the higher end of your range for 2015?

Yes, it was very top.

If you were to say what's driving you being at the higher end, is it primarily the higher Southern Power investment? Or something else?

With our operating companies performing as we thought they would plus what we know is going to happen with Southern Power -- if you look at our past three fourth quarters it's about $0.43 a share. Somewhere around there.

If you look at -- our fourth-quarter earnings have run across the board. It depends on what kind of weather year we've had. But as I look for the year end, Steve, I'm looking year over year.

I expect maybe $0.05 of the accretion year over year to come from Southern Power, maybe $0.06 from the operating companies, $0.01 from our parent, and maybe minus $0.04 on shares. And that would account for the $0.08 increase from $2.80 to $2.88.

If you look at our past three years' performance of earnings per share, in 2012 through 2014 we went $0.44, $0.48, $0.38. We feel very confident about our ability to hit our numbers.

Okay. Great. Thank you.

Thanks.

Our next question comes from the line of Michael Weinstein from UBS. Your line is open. Please, go ahead.

Hi, Michael.

Hey, how you doing? Quick question on Kemper. Are you saying the first half of 2016 for commercial and service, how about the deadline for tax credits and I think it's April? Is that right?

That's right.

Are you going to -- are you thinking -- I guess does this successful test give you any confidence about trying to meet that deadline?

Well, by taking the contingency for the next three months, we're suggesting that the probable outcome is not to make that but we'll only --

There's still an opportunity that we could. There's still an opportunity to hit that date.

Right. In terms of the $350 million, how does that compare to the press numbers that we had earlier seen about the lawsuit? There was a $900 million I believe I recall, plus extra growth on top of that for other items. Does the $350 million represent basically -- is that a resolution of the entire $900 million plus?

It's actually bigger than $900 million plus. If you think about it, our share, if you gross up our share in disclosures, the current litigation was around $1.5 billion, something like that. That's total.

And then what we also -- that was for the first 21 months of delays. Recall also we're wiping away potential extension of current litigation for the next 18 months. That would carry us through to in-service dates in the middle of 2019 and 2020.

Then we also tightened up, recall Westinghouse taking over for CB&I. Plus we tightened up in a very significant way the ability for the contractor to provide change orders that would be agreed upon. So when you add all those up, we think that the settlement is very attractive.

Does this mean that the contractors are picking up the other part of the $1.0 billion something above the $350 million in their lawsuit?

If that's the real number.

Yes, if it was a real number.

We always disputed that.

Okay. Thank you.

Yes, sir. Thank you.

Our next question comes from the line of Jim von Riesemann from CRT.

JVR.

Tom Fanning, how are you? How are those Yellow Jackets doing?

After last weekend they're doing great.

Exactly. A couple of questions. The first one I guess is on -- the first of several questions are on Kemper. When do you get to run the lignite through for the syngas test?

Right around the end of the year, could be early January. And I got to tell you, like I say, I was walking around the plant. I was in the control room, met with plant management later that day.

The general belief is we're going to be able to manipulate lignite a lot easier than sand. Sand is a denser material.

They all felt that if we could pass this test the way we were doing, they really felt they're going to be able to handle the lignite pretty well. They're feeling good.

Okay. And then the second question on the whole Kemper thing is do you need to see the whole plant operational before you can file the second rates case in Mississippi?

I think that's the intention. The whole plant, it needs to be COD.

That's what I mean.

Yes.

Switching over to the settlement, I know there's a lot of -- congratulations on getting that done, but there's just, I'm just having a tough time still understanding how the risks are bucketed now that it's done. So let's just say you get to 2020, 2019 and everything else and you're going to start seeing some delays, how does all that work? And who bears what risk I guess is the question I'm really asking longer term?

So let me operate in the world of 100% dollars as opposed to Georgia Power dollars. We've guided installment payments on this last $114 million, such that fuel load now becomes the operative target in the contract.

In 100% dollars, $35 million is tied to fuel load on year end 2018 and $35 million is tied to fuel load on December of 2019. And to the extent they miss, I think it's about $10 million a month, something like that, that that number would be reduced.

So not only is this third $114 million staged to milestones over time, it also is heavily weighted as an incentive to hit fuel load when we said it would. Now, here's my other editorial comment. You remember when the consortium changed their schedule?

There was a lot going on behind the scenes, and you heard the probable angst in our voice about that these problems were being driven not really by the performance of the project, but by arguments and disputes among and between the contractors. It was our belief that they gave us a schedule that they could improve on. We believe, given what everybody has agreed to here, that they're going to be able to hit this schedule.

Okay. So but in the unlikely event, what you're saying is let's say this thing slips into 2020, 2021 or something for the first unit, who is responsible for the -- who absorbs the PTC in the absence of the PTCs?

Well, there would be $10 million reductions in the incentive payment. There would be liquidated damages.

Okay, I get it. That's what -- I just wanted to make sure I was reading it correctly.

Yes.

Super. Thank you.

Thank you, buddy.

Our next question comes from the line of Ali Agha from SunTrust. Your line is open. Please, go ahead.

Ali, how are you?

Hello, Tom. How are you? A couple of things. One is, Tom, if I look at your weather normalized retail sales, we saw the slowdown in the third quarter and you're at 0.6% through the nine months. So how does that 1.3% for the year target look now, and what's realistically the target we should be looking at for the year and looking beyond that?

Yes, it's less. You know what, Ali, I mean not to wear the fed thing out, but we're seeing the same things the fed is seeing. Especially when you look at the leading and lagging nature of these indicators.

Industrial sales are a leading indicator. Commercial sales are typically your lagging indicator. Well, it looks as if the leading indicator is flowing and the lagging indicator is what's really carrying the day. So that's kind of interesting.

I think the fed is wrestling, and Art went through a litany of the data, I think the fed is wrestling with those same things, that they now begin lift-off and communicate a trajectory. What does that say about the confidence of the continued recovery given all the exogenous factors like malaise in Europe, event risk, Russia, Middle East, lack of transparency in China.

These are the things we're all wrestling with. The good news, as Art said, is it's kind of Atlanta, for example, top five in the United States in job creation and in in-migration. In fact we were fourth in job creation, I think only to Houston, Dallas, and Phoenix.

So that's all good stuff. If you look at our economic development pipeline, 15,600 jobs announced -- 12,000.

12,600 jobs announced in the year 2015. That will take place from 2015 through 2018. Almost $5 billion in capital.

The economic development arm looks pretty good. And so we say to ourselves what is this? Is this a permanent flattening?

Is this a secular change in the growth of the United States economy? Or is this a pausing in which now as we adjust to a different export environment and monetary environment, we'll catch up. What would you add to that?

Ali, I think if you look at the numbers, industrial is really the one that is lagging the most. And as you remember from a revenue perspective, that is the least impactful to our Company.

But if you have them at 1% growth rather than 0.5% growth, we'd be up to close to a 1% growth year over year on a year-to-date basis. Almost at your 1.3%, but we're really pleased with the commercial end of the business.

We've been waiting for a number of years for that to come around and it has. Customer growth has been very strong; that's again a reflection of in-migration.

Use per customer is still eating away at that. That's a bit of an the efficiency gain that we're seeing through natural occurrence with appliance replacement and those kinds of things.

Not only energy efficiency, but also this kind of we think again a secular shift away from single family housing to multi-family housing. And that's really driven by just new, tougher credit guidelines as well as it may be with the millennials, they like being flexible and living in apartments rather than undertaking big fixed investments like owning a house. So we want to see how that shakes out, too.

So at this point, embedded in your [holier] numbers, Tom, what would be the normalized load growth we should be looking at?

Well the normalized numbers for retail sales, about 0.7%. That's just a pure guess, but seeing what we're seeing in the industrial market and we expect the commercial market to do well. That's about what we think.

And you talked about 1.2%, 1.3% longer term as well [anyon] growth. Is that still what you feel is the right number?

We're going to relook at that and we'll update you on that on the next quarter's call when we look at the full year 2016 through 2019.

Separate question. Tom, coming back to Southern Power for a sec. So given that you've obviously exceeded your targets and you've got a bigger portfolio, what is the underlying annual net income run rate that this portfolio is now running for you, obviously higher than you were previously thinking?

It was fascinating when you break down where we were into 2015. We knew just because they had contracts in place they were kind of below $150 million in net income.

Then we gave them kind of a stretch target to hit that would get them up to about $180 million. When we thought about developing the financial plan, we had a number in there about $180 million.

With everything we know now, we're going to be over $200 million, more likely $210 million. So we'll see. So we've done better.

My sense is we're going to see similar performance, even though we haven't set all these numbers yet. I'm just telling you what I think. I think we're going to see similar performance next year.

Okay. And then in the past you talked about the headwind that would be created by the ITC going from 30% to 10%. How should we now think about that as we're thinking about 2017?

You bet. Well, this is kind of fun to think about. Because we've been very public.

And I hope you guys give us credit for this. We're very transparent in how we see growth rates and everything else.

And when we tell you what we believe about growth, it's because we can see it with reasonable stretch targets. We think we can do what we say we're going to do.

When we reduced our growth rate to 3% to 4%, it was because of all these factors. And we were very transparent in telling you about -- I think the funny word I used was divot in 2017.

That would be represented by the loss of 30% investment tax credit and likely fewer projects for solar in that. Maybe wind helps fill that in. And then we said that we would resume a growth rate.

It would be more attractive once we saw more environmental spending at the end of the decade and into the 2020s, as well as a response to the clean power plan. And then we did the AGL merger. So let's think about the slugs of kind of EPS growth.

2015 and 2016 you're seeing Southern Power outperform our internal targets. And so you're seeing growth there.

From 2017, 2018, 2019 because AGL has very predictable and transparent earnings range resulting from safety-related pipeline replacement programs that are under rate riders, we already know Georgia, Illinois, potentially other states, we can see, and I think we suggested that you would see, something like $0.10 a share or so in the 2017/2018/2019 time frame. So we bump up there on top of whatever Southern Power can produce.

And then some of those projects continue into the 2020s. Then you see in the 2020s now you have time to get to the ramifications of environmental spending plus new generation required by the clean power plan.

So not only will that be more renewables, it will be more combined cycles, probably displacing coal as well as more combustion turbines needed to respond to the intermittency of greater penetrating renewable resources. So if you look at it the first slug is going to be Southern Power. The second slug will be Southern Power plus AGL.

The third slug will be Southern Power, AGL, plus clean power plan and environmental spending. So I think we'll give you more guidance about our growth rate in January. Suffice to say we did say that our new longer term trajectory, assuming we close AGL, will be in the 4% to 5% range.

That's very helpful. Last question on AGL financing, have you gotten the credit rating agencies completely on board with your financing plan, or is that still being worked on?

Well, we had discussions with the agencies prior to the announcement, and we outlined our plan to -- the financing plan for them issuing equity over a three-year time frame. And that we believe that our metrics will be consistent with where we are before -- where we are today by the time we get to 2019. Now we'll issue a lot of debt up front, but over time we'll get our metrics back to a point where they're consistent with where we started.

Thank you.

Thank you, sir.

Our next question comes from the line of Paul Patterson from Glenrock Associates. Your line is open. Please, go ahead.

Hey, Paul.

Good morning. Good afternoon.

Whatever.

Just to follow up on -- I was a little unclear about Mike Weinstein's question about the Kemper tax credit. You guys do expect to get the plan up by April to get it? Is that what you were -- I wasn't completely clear.

We think that we might or might not. We've added three months of reserve contingency to be conservative to say that we might not make March 31. It might be as late as June 30.

So that's the financial charge we made. Obviously we've got to hit the date in April in order to get the ITC. If we don't it has a cash impact.

Its book impact is about $3 million a year, somewhere like that. And we could finish it. We could supplant it with other available tax credits that we're seeking to get from the IRS due to the nature of the plant.

Okay. And then with respect to the -- when do you expect the gasifier I guess, I got an idea where you expect the lignite testing, but after the lignite testing, which I guess is the end of this year, when do you think that it will be as a milestone in terms of when will it actually be commercially able to produce synthetic gas I guess?

When will we know that? What's in between the lignite testing and the actual commercial operation of the gasifier?

Well, so what will be going there -- you're going to get really good indications on reliable syngas to turbines, okay? So that's a big deal. The other things that you're going to get that just need to be tested along that time frame will be acid gas removal.

Let's think about this for a minute. Recall that we're going to take the syngas, we're going to take out 65% of the CO2 and we're going to also take out sulfuric acid and also ammonia.

All of those byproducts have value, and that goes into the total value premise to Mississippi's customers. And recall also that while we'll do first syngas to turbine around the end of the year sometime in order to get CO2, we want to have both trains operational, both trains checked out.

I will -- just a new piece, it's not a new, I guess we told you that also, but we tested out the flushing of the systems of the acid gas removal system. And actually we provided for three complete tests of that and we did it in two.

And I want to say that the benefit of doing it in two was a three-week benefit. It was something like that. That also went exceedingly well.

Look, we've -- I know we're taking a long time and I know we're taking some pain for taking the right amount of time, but what you're getting out of Kemper, and you've seen it already, is that what we have built and tested is working beautifully. The combined cycle is working as good as any combined cycle in the United States, and these major systems of the gasifier are working well. So I know we've all, me particularly, have had to have patience here, but I think we're taking the right approach.

Okay, great. Just to sort of -- last quarter I asked you about the MMBtu operational cost of the gasification process. And I think you guys were around the -- generally speaking around 250 in MMBtu.

Does that number -- do you guys feel better about that number, or is that pretty much where you guys deal fuel now that you've gotten three months more and accomplished so much more with the testing and everything?

Let's review the bidding there. Remember, I -- you remember it correctly. What we were tying that to, that was an estimate based on I think $50 oil, because that's how we priced the CO2.

It's basically index. And we have take or pay contracts in that regard. I've wiped away the variability around ammonia and sulphuric acid. That's kind of correct.

The other thing that's really interesting that we're building the capability to do, we've alluded to it in the comments this afternoon, but it's a quick switching capability between syngas and natural gas. That should help our reliability characteristics in meeting plant performance criteria. So we're going to be able to deliver to Mississippi's customers attractive economic natural gas, electricity, whatever the fuel markets deliver to us.

Okay, great. And then just finally on AGL, you went over the checklist and what have you. Obviously you've had discussions I assume with parties and stuff and others.

Any sort of color you want to give on terms of that and how things seem there? Anything pop up or not?

You bet. Listen, we've met with regulators both in Illinois, New Jersey, other places. Recall we have a real ace in the hole here and that is or Chief Counsel, Jim Kerr.

Jim Kerr used to be a commissioner on the North Carolina Commission. He was also president of NARUC. And I can tell you with personal observation, when you walk into a room with Jim Kerr to the New Jersey Commission or the Illinois Commission and he knows the people and they know him and he already has trust and if you will brand equity, it is a tremendous benefit to have.

The other thing that I don't want to underestimate, when we entered into the merger with AGL, they run a heck of a business in these jurisdictions in which they serve. I can tell you personally talking to the Chairman of the Illinois Commission and all the other commissioners there, it was very clear that AGL when they bought Nicor made several promises about how they would operate that business, and they have followed through and even more so on every promise they've made.

So they have great credibility. Given our reputation, our customer satisfaction criteria, our embracing of an integrated regulated business, our customer focused business model, when you look at our data, number one in the United States, we are getting very constructive responses to everything that we've done so far.

Excellent. Thanks a lot, guys.

Yes, sir. Thank you.

Our next question comes from the line of Michael Lapides from Goldman Sachs. Your line is open. Please, go ahead.

Hey, Michael.

Hey, Tom, you're right, that Georgia Tech ending reminded me of an Alabama/Auburn one I'd rather forget.

No, it was way better than that one.

Got a question for you. What is your outlook, what is Southern's outlook for the potential for renewable development within the utility service territories in Georgia, Alabama, Florida, Mississippi? Which ones do you think have the opportunity to have incremental renewables?

Where do you think that could happen in rate base versus PPA with third parties? And which are the ones that may be a little bit further behind in the process, but have the potential to play catch-up down the road?

Yes, it's a fascinating question. Every one of our companies right now has a solar program in place.

And you want to know something that's even more interesting, I've been a critic of renewable portfolio standards. All of our companies have entered into these agreements without the hammer of a renewable portfolio requirement.

You may know also that we have had a long-standing outstanding relationship with the DOD. And it occurs to us that the DOD nationally -- and this is why we have tried to strike this relationship, that they have had a renewables requirement on their own and a severability requirement on their own.

And we have worked to play offense with these folks to provide them real solutions not only to meet these requirements, but to give them more sustainable operation from a base standpoint going forward. So all of that has worked exceptionally well.

It is clear to me that if the clean power plan goes forward, you're going to see a lot more solar particularly in our state. You might see wind, but you know I've been just a little bit of a critic of wind for the southeast only because the best wind resources are way far away from us.

The three deals we've done on wind for the host utilities really are located in Kansas and Oklahoma. The right long-term electricity design for America is not to rely on long haul transmission networks to move electricity.

You're always better off from a physical design standpoint to locate the generation near the load resource. So solar is going to make more of a penetration than wind in the southeast.

We might be able to do some wind in the southeast. We'll see. The other things that we had some promise about in the past we've done in Texas but we haven't done in the southeast, is biomass.

If we could ever get back in that business, I think the southeast is a good place to go. If you want to think about other resources that are going to be particularly important to meeting clean power plan, nuclear and hydro.

We never count hydro as part of renewable resources; we probably should. And when I think about -- if you add up all the wind, all the solar, biomass, and hydro, we're approaching something like 7,000 megawatts owned or controlled by our companies.

That's where it's going to go. Along with that will be combined cycle gas at base load, the planting cull, CTs to handle the intermittency, and more gas infrastructure, which we've been talking about for some time, that will be able to move the shale gas from where it is to where it needs to be.

Got it. Thank you, Tom. Much appreciated.

You bet. Thank you.

Our next question comes from the line of Mark Barnett from Morningstar. Your line is open. Please, go ahead.

Hey, Mark.

Good afternoon, guys. Just a quick -- and you provided a little bit of information on how you see the economic landscape unfolding right now. I know it's not something you typically provide, but on the commercial and industrial load trends that you're seeing, is there any way you could give us a little more granularity on maybe Alabama versus Georgia and how those two large territories are either diverging or moving together?

On the industrial side, Alabama has probably gotten more of their kilowatt hour sales in industrial than Georgia. But actually Georgia's industrial sales are a little bit bigger, but there are other markets that are bigger, too.

But Alabama is predominantly steel, chemical, and a little less paper than Georgia's got. But those two have done less well here in the -- I guess we call it the industrial recession.

Georgia has some steel, not as much as Alabama. They've got more paper, and that has suffered a little more. Some of that paper is down because of low gas prices.

They're co-generating more their needs because of that. So that's a bit of what we're suffering there as long as and as well as I guess lower pulp prices for paper as well.

So if you talk about the commercial markets, it's more fulsome in Georgia I would believe. They've got a bigger commercial market, especially within the metropolitan area of Atlanta.

That's where you're seeing much more robust growth. You're seeing a little bit in Alabama, but not as much as in Georgia.

And much more in-migration in Georgia than elsewhere in the system. The other thing that is a big deal, but we're sworn not to talk about, so let me talk about it is kind of IT jobs and service -- I mean server farms and all that stuff.

Those people are very sensitive about those infrastructure plays. Don't want to talk about where they're located or who they are.

But we're seeing some growth there. That's because of our reliability on price position.

Thanks for the color on that. Just a quick update with the Georgia filing for the merger.

Do you have a rough time frame for that? Any update on that?

Probably next month.

Next month, okay. I'll definitely keep an eye out for it. Thanks.

Yes, sir, thank you.

(Operator Instructions)

We have a follow-up question from the line of Steve Fleishman from Wolfe Research. Your line is open. Please, go ahead.

Good afternoon again. So just one quick question. The $1.5 billion of equity that you plan to do in 2016 for AGL, are you going to wait until the merger closes to do that, or might you look to do some kind of like forward transaction or something like that?

We're still considering those options, Steve, but the base plan is we expect to raise the equity in the manner that we have raised it in the past. And some of the internal programs -- we've already turned our internal programs on beginning in October of this year. So bill issue in that fashion through 2019 is currently planned, but we're also considering other elements of that that could possibly be used.

Like in the past we've done things like discrete issuances, we've done dribble programs, we've done a variety of other things. That's what Art is hinting at. Whatever we do we don't want to impact the market.

Right. Okay. Thank you. That was it.

Thanks, Steve.

(Operator Instructions)

Our next question comes from the line of Andy Levi from Avon Capital. Your line is open. Please, go ahead.

Hey, Andy, how are you?

I'm doing well, thank you very much. Look forward to seeing you soon.

Yes, absolutely.

Glad you moved on from CB&I.

No kidding.

I think that's very positive. Just a question of Southern Power. So can you quantify how much net income and cash comes from solar in 2015?

$51 million.

In cash?

We've got to get that detail for you after the call.

That's fine. And then I guess without giving you a -- giving out a forecast, but you said about -- I'm sorry, are you going to say something, Art?

We were looking at each other. My $51 million was a year-over-year increase.

Okay.

We'll get all that stuff.

How much did you get last year? Do you know?

From what?

That would solve that. Net income from solar, if the $51 million is a year-over-year increase?

We'd have to add some numbers. That would be easier for us to get with you offline on.

I think what we said earlier was $51 million on ITCs.

Okay. And then I guess in 2016 the $210 million, does that have growth in solar, or is it kind of -- again I know you didn't give a forecast.

That's in 2015.

Right, but then Tom I think said that without giving out a forecast, that 2016 Southern Power would be pretty close to 2015, didn't he say that?

What I said was when I think about the kind of projects we see, what we've circled so far, 2015 we're guessing we're going to have a Cap allocation of around $2.3 billion. We already have circled up about $1.3 billion in 2016 and -- which is kind of in our base plan. So we've already circled up our base plan.

And then we think we should expect to see kind of similar performance for the balance. So it wouldn't surprise me at all to see a $2.3 billion number in 2016, but don't know that yet, just what I expect.

Andy, just to be clear the $210 million was a 2015 estimate.

Okay. How much did you invest this year in solar? Capital?

Again, Andy, we're going to have to follow up. We don't have it split. We've got some capital in there for wind and solar. So we -- I just don't have the split.

The majority of it is solar. We'll get it to you.

Okay. But I guess it's not fair to kind of look at it just on the net income basis as far as return of capital, but obviously your return of cash is in some ways more important, right?

It's enormous, yes.

That's why I wanted to get the cash number. Okay. I'll wait until the Jimmy man calls me back. Thank you. (laughter)

The mayor.

The mayor. Good mayor. That's the mayor I like.

Me, too.

Thank you.

Thank you.

And Dan Tucker, congratulations.

Yes, how about that.

Thanks, Andy.

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

Well, look, we've been talking for some time and you all have been so wonderful to be patient with us. I think we're reaching that inflection point in the story.

We've always trade on a risk adjusted basis. The returns are terrific. We're one of just one or two companies like us that we can't promise you anything in the future.

My lawyers always look at me here. But for the last 10 or 11 years we hit our numbers. We hit generally really well within our numbers, even despite duress.

And I think the risk side has been tainted somewhat with some overhangs from the Vogtle litigation and the Kemper project. I think resolving the litigation is an enormous inflection point.

I think the technical test that we've just gone through, while not removing it completely, has really reduced I think significantly the technical risk in Kemper. So I think we're really moving the Company in the right way and I think the days ahead are very bright.

We thank you so much for being with us this afternoon. We look forward to seeing you in a couple of weeks. Operator, that's all.

Thank you, sir. Ladies and gentlemen, this does conclude the Southern Company's third-quarter 2015 earnings call. You may now disconnect.