Southern Co (SOMN) 2017 Q2 法說會逐字稿

Southern Company's second quarter earnings call will feature slides that are available on our Investor Relations website. You can access the slides at www.investor.southerncompany.com/webcast.

Good afternoon. My name is Beatrice, and I will be your conference operator today. At this time, I would like to welcome everybody to the Southern Company Second Quarter 2017 Earnings Call. (Operator Instructions) As a reminder, this conference is being recorded Wednesday, August 2, 2017.

I would now like to turn the conference over to Mr. Aaron Abramovitz, Director of Investor Relations. Please go ahead, sir.

Thank you, Beatrice. Welcome to Southern Company's Second Quarter 2017 Earnings Call. Joining me this afternoon are Tom Fanning, Chairman, President and Chief Executive Officer of Southern Company; and Art Beattie, Chief Financial Officer.

Let me remind you that we will make forward-looking statements today in addition to providing historical information. Various important factors could cause actual results to differ materially from those indicated in the forward-looking statements, including those discussed in our Form 10-K and subsequent filings. In addition, we will present non-GAAP financial information on this call. Reconciliations to the applicable GAAP measures are included in the financial information we released this morning as well as the slides for this conference call. The slides we will discuss during today's call may be reviewed on our Investor Relations website at investor.southerncompany.com.

At this time, I'll turn the call over to Tom Fanning.

Good afternoon, and thank you for joining us. As always, we appreciate your interest in Southern Company. Our premier state-regulated electric and gas operating companies performed well during the second quarter and they remain on track to deliver on their targets for 2017 on an adjusted basis. Art will provide a complete overview of our financial results in just a moment, but I'd like to first provide updates on the status of the Kemper and Vogtle projects.

First, Kemper. Let me provide you with a brief review of key events over the past 12 months. In July 2016, as we worked to fulfill our obligation under the PSC certificate order, we fully transitioned out of construction with the first production of syngas from the gasifiers. While the startup of the gasifiers and gas cleanup systems took longer than anticipated, substantial progress was made towards in-service. Along the way, we demonstrated every major facet of the TRIG technology at a commercial scale, including the gasification of lignite, the capture and sale of carbon dioxide and the production of electricity with syngas.

This past February, Mississippi Power filed an updated economic viability study, which indicated that operating the IGCC on lignite would be less economic than operating the combined cycle on natural gas in most future scenarios. The primary factor driving this result was an updated natural gas price forecast reflecting lower sustained prices of almost 25% over the long term. Recall, Kemper was conceived at a time when natural gas prices were approximately $10 per million Btu and had significant market volatility.

In May of this year, it was determined that a critical component, the super heater section of the syngas coolers would need redesign and replacement over the next 2 to 3 years. Replacement of the superheaters would require significant lead time for design, fabrication and installation and add significantly to costs above the cost cap. Even though we all felt we could achieve commercial operations in the near term, this issue hurt the sustainable operating profile of the plan.

On June 21, the Mississippi Public Service Commission made its expectations clear with public statements and a subsequent order on July 6 establishing a docket to encourage a settlement reflecting no gasifier-related customer rate increases and operation of the Kemper plant as a natural gas combined cycle. During this period, Mississippi Power suspended operations and startup activities for the gasifier.

Recall that since 2014 in August, operation of the Kemper combined cycle has provided Mississippi Power customers with clean, safe and reliable low-cost energy. The plant has operated at availabilities well surpassing industry norms. While operating the Kemper facility solely on natural gas for the long-term is far from ideal, however consistent with current and long-term projections of natural gas, we believe it is in the best long-term interest of our customers, investors and other stakeholders.

Mississippi Power continues to actively negotiate with the public utility staff and other intervening parties with the intent to have a proposal filed that meets the conditions of the PSC July 6 order on or before August 21.

Our second quarter financial statements reflect a pretax charge of $2.8 billion to write down the remaining investment in the gasification portion of the facility that is no longer improbable of rate recovery. Not included in the charge are any future cancellation costs, which are currently estimated to range between $100 million and $200 million. There is $500 million of the combined cycle investment not currently in rate, which is subject to recovery through the settlement docket established on July 6. We will provide updates as appropriate as the settlement process continues.

And now for an update on Vogtle Units 3 and 4. The Vogtle owners have made great progress since our last earnings call in preserving all available options, and Georgia Power is in the final stages of forming its recommendation to the Georgia PSC. As a reminder, Georgia owns 45.7% of this project with the rest owned by MEAG, Oglethorpe Power and the City of Dalton. Combined, our ownership group represents a state-wide partnership that has served Georgia electricity customers for decades.

As we contemplate the future of this project, our interests must remain aligned to assure the best overall answer for the customers, communities and economy of the State of Georgia. Ultimately, the final decision will rest with the Georgia Public Service Commission. Georgia Power has kept the PSC informed of the process related to estimating the cost to complete Vogtle 3 and 4 and other related activities over the past several months. We expect to file our recommendation in late August.

Before providing a summary of our cost to complete the estimate, I'd like to take a few minutes to discuss the agreements we have reached with Toshiba on the parent company guarantee and with Westinghouse to provide ongoing services to the project.

First, we finalized an agreement with Toshiba in June regarding their guarantee obligations under our original EPC contract. The agreement fixes Toshiba's obligation to the project owners whether the project is completed or not at $3.68 billion or approximately $1.7 billion to Georgia Power company. There is a monthly payment schedule which begins in August of 2017 and ends in July 2021. The $920 million letter of credit or $420 million to Georgia Power remain outstanding as collateral.

Payment of the guarantee obligation could be accelerated as Toshiba also agreed to contribute a portion of the proceeds from its claim in the Westinghouse bankruptcy to the Vogtle owners. This could include proceeds from international subsidiaries if those entities are part of a combined sale of Westinghouse and Toshiba's energy services business in Europe, the Middle East and Africa. Ultimately, while Toshiba's financial condition is uncertain, the Toshiba guarantee agreement puts the Vogtle owners in a better position. The first payment in October totaling $300 million is the largest individual payment and will be an important signal regarding Toshiba's financial viability.

The Vogtle owners also recently finalized the services agreement with Westinghouse. This agreement took effect on July 27, having been approved by the bankruptcy court and the Department of Energy. While this agreement reduces the project scope for Westinghouse, they will continue as an important partner providing engineering, licensing support, procurement services and access to intellectual property. This contract extends until the units are operational or it can be canceled after a 30-day notice if the project does not move forward.

The effectiveness of the Westinghouse services agreement also officially signaled the orderly transition of the project site to the control of Southern Nuclear. Southern Nuclear, which operates all of Southern Company's nuclear plants, is the licensee for Vogtle 3 and 4. Southern Nuclear has held significant presence on-site from beginning of the project with a focus on safety, compliance and oversight. Over the past several months, Southern Nuclear has moved personnel into key Westinghouse and subcontractor roles in anticipation of taking the lead role on-site, which has allowed for a smooth transition and for construction momentum to continue.

Productivity on-site has improved significantly over the first half of 2017. This improvement can be attributed to several factors, including improved leadership in the field, improved work package management and continuous monitoring and communication of performance. Southern Nuclear expects further improvements in these areas if the decision is made to complete the project. In that event, Southern Nuclear will hire a prime construction contractor, which could be a single firm or a combination of firms.

With all major equipment on-site, with the engineering nearly complete, the primary success factor going forward would be productivity. The prime construction contractor would be provided with appropriate incentives and rigorous oversight to drive achievement of the construction milestone.

Let's turn now to our estimate to complete. The process to get to this point has been robust. Our team was granted access to all the work that Westinghouse and its subcontractors have previously done on cost and schedule. Our own personnel combed through the information, went out into the field to verify quantities firsthand and confirm work reflected as completed. We also brought in external expertise, including individuals with recent nuclear construction experience and multiple consulting firms to vet our scheduled assumptions and uptake and validate our inputs.

Our current assessment results in a range of potential schedule to complete both units, with Unit 3 expected to be placed in-service between February 2021 and March 2022 and Unit 4 between February 2022 and March 2023.

Net of the Toshiba guarantee obligation, the schedule is estimated to result in $1 billion to $1.7 billion above the previous cost estimate of $5.68 billion, which included contingency of $240 million. Based on the preliminary spending curves, Georgia Power is not projected to exceed $5.68 billion until 2019. Assuming periods -- I mean, assuming proceeds for claims in the Westinghouse bankruptcy proceeding are received by 2019, this crossover point could extend into 2020.

Through June 30, Georgia Power has invested approximately $4.5 billion in the project and has recovered approximately $1.4 billion of financing cost under the NCCR tariff. If a decision is made to cancel the project, we have estimated Georgia Power's cancellation cost at approximately $400 million. The PSC will determine the appropriate process in which to consider our upcoming recommendation. We will continue to work with our co-owners and the PSC to reach the decision that is best for all stakeholders. In the meantime, Southern Nuclear will maintain momentum at the site.

I'll turn the call over now to Art for a financial and economic overview.

Thanks, Tom, and good afternoon, everyone. As you can see from the materials released this morning, including the charges associated with Mississippi Power's Kemper project, we reported a loss for the second quarter of 2017 of $1.38 per share compared to earnings of $0.67 per share in the second quarter of 2016.

For the 6 months ended June 30, 2017, we reported a loss of $0.73 per share compared with earnings of $1.20 per share for the same period in 2016. Excluding the charges associated with the Kemper project, wholesale gas services and other items described in our earnings materials, earnings for the second quarter of 2017 and the 6-month period ended June 30, 2017 were $0.73 and $1.39 per share, respectively. This compares with $0.75 and $1.34 per share for the same periods in 2016.

Major earnings drivers to our adjusted results for the second quarter of 2017 included retail revenue effects at Southern Company's state-regulated electric businesses, offset by milder weather, increased interest expense and increased shares. As for our earnings estimate for the next quarter, we estimate that we will earn $1.06 per share in the third quarter of 2017.

Moving now to an economic review for the second quarter. The U.S. economy continues to expand at a moderate pace, real GDP rose by 2.6% in the second quarter of 2017, driven primarily by consumer spending and fixed investment. Real GDP growth is expected to be 2.3% in 2017 and our service territories generally reflect these economic trends.

Weather-normal retail electric sales for the quarter and year-to-date periods were down year-over-year by 0.4% and 0.8%, respectively. These results were primarily attributable to lower sales in our industrial class with paper, primary metals and transportation segments accounting for the biggest negative year-over-year results. However, a number of our industrial customers are pointing to stronger orders in the second half of this year.

Economic development activity in our territory remains reasonably strong and forward-looking indicators suggest that energy demand should be within expectations of being flat-to-slightly positive for the remainder of this year.

Within our service territories, we are encouraged by a variety of positive indicators. Year-to-date residential customer growth continues to exceed expectations with 15,000 new customers added in our gas service areas and almost 25,000 added in our electric territories. Employment and population growth in our combined electric and gas territories remain solid. Total nonfarm employment is up by 1.6% year-over-year in May, and we continue to see faster population growth in the rest of the nation, boosted by net in migration to Georgia and Florida.

Let me now update you on our financing plans. In late June, Southern Company contributed $1 billion to Mississippi Power in anticipation of potential charges associated with the gasifier portion of the Kemper project. Consistent with our commitment to preserving financial integrity on a consolidated basis, Southern Company has an equity need of approximately $1 billion. There are several moving parts in our business, which also impact funding needs that are still underdeveloped.

The Vogtle go or no-go decision certainly has potential implications to our long-term financing plans. Under a go decision, we would require more debt and equity to maintain Georgia Power's regulatory capital structure. Considering potential proceeds under the Toshiba guarantee agreement and the proceeds from a Westinghouse reorganization or sale, this is primarily a longer-term need. Under a no-go decision, our financing needs would be greatly reduced. Under either scenario, we do not anticipate Vogtle further changing our equity needs in 2017.

As we alluded to in our last earnings call, we are actively evaluating opportunities to modernize our basic business operations as our customers' needs evolve. Our objective, as always, is to improve the way we serve our customers while maintaining affordable prices. These initiatives would have the benefit of strengthening our longer-term EPS growth, contribution from our state-regulated facility. While these modernization opportunities could increase our long-term funding requirements, we do not anticipate any changes this year, 2017.

Another moving part is Southern Power. As we continue to evaluate and develop our pipeline of opportunities at Southern Power, we are evaluating the use of third-party tax equity to fund renewable projects. Southern Power is working to secure tax equity for the Cactus Flats wind project announced this week and will likely explore the same for projects in its 3,000 megawatt joint development pipeline. While our CapEx forecast for Southern Power is unchanged, the use of third-party tax equity could significantly reduce the amount of debt and equity deployed over our 5-year forecast horizon.

We plan to refine our long-term capital and financing plans over the next several months and provide an update on our third quarter earnings call. Our slide deck for this call includes an updated financing plan for 2017, which reflects the previously mentioned need for approximately $1 billion of additional equity. We remain committed to high level of financial integrity, strong investment-grade credit ratings and our objective of a longer term 16% funds from operation-to-debt ratio.

For an update on our EPS growth rate -- now for an update on our EPS and our growth rate and our dividend. We've accounted for probable outcomes of the Kemper Project, which assumes no return on or return of gasification-related investments. Recognizing that we don't yet have a final regulatory solution for the Kemper project, we forecast an ongoing reduction to annual EPS of approximately $0.08 to $0.10 per share. The resulting long-term trajectory still reflects growth of approximately 5%, beginning in 2018. We will formally update our long-term EPS guidance after we have a go or no-go decision for Vogtle. The base financing plan was developed before the Westinghouse bankruptcy and essentially reflects a go scenario and approximately a 5% long-term EPS growth rate.

Most importantly, our dividend trajectory remains intact under either a Vogtle go or no-go scenario. The Southern Company Board of Directors has increased the dividend every year for the past 16 years and for nearly 70 years, the company has paid a quarterly dividend that is equal to or greater than the previous quarter. Our dividend objective is to provide regular, predictable and sustainable growth. In turn, the board's dividend decisions have been predicated on a robust review of our long-term financial plan, including risk assessments for a variety of different outcomes. While purview over the dividend decision remains with our board, we believe annual dividend increases of $0.08 per share are sustainable. Our strong operating cash flows provide additional support to this belief.

Over the next several years, we expect that cash flow from operations will average over 3x the size of our common dividends and this ratio is approximately 10% higher than the past 16 years as a result of our current tax position.

I will now turn the call back over to Tom for his closing remarks.

Thanks, Art. July 1 marked the 1 year anniversary of our merger with the former AGL Resources, now Southern Company Gas. As you know, this acquisition was a major step in a broader strategy to further expand our business in a meaningful way across the energy value chain. In fact, earlier this week, Southern Company Gas placed the Dalton pipeline in-service. With all of its capacity under contract for 25 years, Dalton represents 1/3 of Southern Company Gas' newbuild mainstream infrastructure and is expected to contribute approximately $10 million per year to income.

The integration of Southern Company Gas into our business has gone extremely well and the combined companies now serve more than 9 million customers nationwide, with a portfolio of premier, state-regulated utilities. Southern Company Gas is a great addition to our company and should contribute positively towards fulfilling our shareholder value proposition for a very long time.

Before we open the call to your questions, I would like to respectfully remind everyone that we do not want to get ahead of the regulatory processes in any of our states, including the ongoing negotiations in Mississippi and the filing and consideration of our Vogtle go or no-go recommendation in Georgia. Thank you in advance for your understanding.

Operator, we are now ready to take your questions.

(Operator Instructions) Our first question comes from the line of Greg Gordon with Evercore.

Couple of questions. First, I just want to make sure I've got the baseline cost estimate to complete the plant sort of right, as I know I'm sure people are trying to benchmark that against the $18 billion cost that SCANA articulated in their decision not to move forward. If I take your $8.4 billion to $9.1 billion range, which is obviously before the guarantees, and I gross that up, that gives me sort of $18.3 billion to $19.8 billion total plant cost. But I also know that, that might not be apples-to-apples because you have included in your cost estimate costs in excess of what the Westinghouse was obligated to deliver the plant for, that was like a little over $2.6 billion. So am I right that the apples-to-apples cost is somewhere between $15.6 billion and $17.2 billion? Those are a lot of numbers, I apologize if that's not clear.

Let's first do this and I know people are going to be interested in comparing our situation to SCANA's. There are a host of differences between our project and the summer project that SCANA and Sante Cooper recently canceled. It really is apples and oranges. For example, the commercial terms for the projects were very different, the EPC cost, the guarantee, the different regulatory processes they went through the cost cap over there. So it's really -- I really want to resist kind of a reconciliation of where SCANA is relative to where we are. Stick with our numbers. The other thing that's important about our numbers, I really don't know the process SCANA went through in developing their estimate. I can tell you that not only did our on-site people work very hard to develop estimates, we brought in a variety of external parties, including folks that had been involved in the recent nuclear completion project at TVA as well as estimates from both Bechtel and Fluor. We feel confident in our estimates.

Okay, so I should just stop with the -- knowing that I grossed it up, the total plant cost.

That's right. I think that...

It's $18.3 billion to $19 billion -- $19.8 billion and not try to read through further from that.

Yes.

Okay. The second is, I heard your -- I heard you on your -- what you said about the regulatory process, but can we just...

However.

However, I'm going to ask you a question. When you file -- when are you going to file your plan? What do we think the time horizon's going to be until we get some sense of where the commission is leaning? And should we presume that the plan will lay out options, such as, and I'm theorizing here, we either abandon, we build 2 units, we build 1 unit. These are the different costs associated with each of these choices. Which choice do you think is the right choice? Is that -- or are you not willing to even go that far?

Yes, Greg, I think what we're doing is working very closely collaboratively. I've often said in past years that our relationships with the staff, the commissions, is a continuous rather than discrete kind of relationship. So they've been briefed along the way. Further, we've been working hand in glove with our co-owners as we evaluate the different scenarios that we will consider. You should assume that we have considered the entire waterfront of options available to us and we've been pretty creative in pushing a lot of different ideas. I would expect that the results will converge on a single idea and we will provide that idea as a recommendation to the Georgia Public Service Commission sometime this month.

Okay. And then is there any sense of how long the process might take to come to a mutual decision?

Yes, that's part of the process I'd rather not get into. Let the commission decide how they want to handle that.

Fair enough. And then one quick question, the base case forecast has revised to take into account the Kemper costs, again that assumes -- the 5% growth off the lower base assumes a go decision as the base case?

That's right. It assumes -- the base case assumes that we're building Vogtle. That's the case that was provided back in October.

Okay. Final question. If you were theoretically in a no-go posture, the amount of dollars that you would dare be -- would seek to recover under the Georgia legal framework would be whatever the QUIP balance is as of that point in time? Or would it be the QUIP balance plus the cancellation costs?

Both of those, Greg.

But the financing costs are not. Those are costs that have already been recovered, so it would be...

That's correct.

And of course, we wouldn't have the Toshiba guarantee against that.

Right. And whatever tax benefits you got from an abandonment, correct?

Correct.

That's it.

You got it.

Our next question comes from the line of Anthony Crowdell with Jefferies.

I just wanted to follow-up with Greg. On Slide 8, you talk about go and no-go decision. I just -- in one of the footnotes or the only footnote there was allowed recovery should you go no go. And I know -- just what does carrying cost mean, I guess, is my question?

Full cost of capital.

So both in equity and in debt return?

Yes.

Has there been any other like projects or something that have already gone through this procedure?

Not to my knowledge.

Okay. And then just lastly, the timing I guess with Greg, the decision -- the utility's going to make a decision in August of a contractor and then also in August make a decision on what they believe and then that gets pushed to the commission and then October is the first payment from Toshiba and then some time after that, the commission will make a decision.

Yes. I mean, you should view the commission to decide how and when it wants to make a decision. So let's be flexible there. I mean, conceivably, they could make it really quickly or it could take time. The October payment, I think, from Toshiba is an important milestone.

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

Now -- okay, so I think the -- no, look, we all saw the estimates from SCANA and then we're trying to compare them to yours, but from the perspective of your shareholders and the potential for the multiple expansion on your stocks, so we're talking about spending additional $1 billion to $1.7 billion over the next couple of years. This is your best estimate right now, but you never know where -- what the final amount will be and then for a similar amount, if not much less, you could build a gas plant. So how do you try to appease investors about the risks that you are undertaking by continuing the project if you continue versus just building a gas plant instead, especially as the load growth numbers seem to be coming below the prior expectations.

Well, now there's a variety of issues underlying that and you should know that we evaluated building gas on the site relative or instead of finishing the new. So there's a whole host of issues. For example, it's not clear to me that were we to not go and pursue gas, that you would build gas at that site, we would need to build a rather lengthy pipeline. There may be other sites around Georgia that may be more suitable for that. Adding the nuclear units give a much desired quality to the state's integrated resource plan that is fuel diversity. It is resilience to future carbon potential outcomes. I think there's a host of factors that would cause us to consider. If we decide to go forward building new, we can feel very good about it. It's an important process to follow. I think the commission has been very vocal about their desire for a reasonable outcome on nuclear. We already have a strong framework for recovery. We entered into that when we had the settlement agreement and the prudence proceeding. So we have a process that works. That process does not provide a cost cap to the extent that the capital costs are prudent. It only addresses return levels, cash, AFUDC and then of course, once we clear those plants into service, they would leave that kind of settlement regime and revert back to the Georgia Power base rates. A lot of these things have been contemplated already and I think from a political standpoint, from an operational standpoint, fuel diversity, a variety of other things, I believe that the state planning processes as evidenced by the integrated resource plans that was discussed in 2016, I guess approved in July, believe from the State of Georgia that nuclear is important. So while it is an option to build gas, I think on a lot of scenarios, going forward with nuclear may make sense. Of course, we may decide not to and we'll see, but don't think about replacing the units with gas there. And one last point, and this is a point, frankly, I want to throw some kudos out to the current administration and Congress. Boy, people don't say that very often these days, but let me tell you, as we have traveled around the globe, making sure that we get the best outcomes possible associated with the Toshiba guarantee, with the Westinghouse portion, scope of the project, the Trump administration cabinet has been fantastic, whether it's been Rick Perry, Wilbur Ross, Mike Pence, any of those guys have been exceed -- and their staffs have been exceedingly helpful in having us prosecute our interest here. Further in Congress, I'll say very clearly, folks like Kevin McCarthy, Kevin Brady were very helpful in getting a bill, bipartisan bill, Jim Clyburn, Nancy Pelosi in getting a bill out of Congress, out of the house anyway, and we'll see where we'll go elsewhere in the Senate. So look, I'm sorry, Angie, I kind of rambled around on you. I think the issue really goes to, besides just straight economics and we think economics still favor -- at least the economics we present will favor whatever we decide to do, don't consider gas at the site as the right replacement. If we go -- if we do a no-go, you'll build gas, but it'll be elsewhere.

Understood. I'm just -- again, I'm just trying to understand you're adding 2 years of the nuclear construction risks and yes, I understand regulators want the plant to be finished, at least that's what it seems like to me from their public statements, but I'm just trying to see if there's a way to get some additional assurances for shareholders just in case this is not 2 years, but say, 3 years, and if that original estimate turns out to be too low.

Yes. I would argue that what investors, owners should look towards is: number one, the generally constructive environment in Georgia; number two, we have a framework in place that will provide for rates of return during the construction period, however long it is, and assuming you have a prolonged scenario, as you suggest, that once you finally complete, that these assets will return to the normal Georgia rate regime for decades to come. It's interesting, you could make a short-term decision or you could make a long-term decision here. I think we're all trying to balance those 2 things in coming up with a recommendation with the commission.

Angie, it's Art. I think it's also important to remember, and Tom addressed this a little bit in his script, was that this is going to be an owner-led process through 1 or 2 major contractors, where we're going to control the metrics of performance, and we'll have immediate responsiveness to however that performance is going around the productivity of the asset. It's also important to remember where we are in construction. The scope going forward is very clear. All the equipment and most major equipment is on-site already and so it's a matter of constructing the equipment that's already there on-site. So it merely becomes a construction performance metric as we move forward. And that gives us a little more confidence as we look forward as to these time frames.

And the data supports that we have been hitting just about the targets we want on cost and schedule here very recently as we've taken over the site.

Our next question comes from the line of Steve Fleishman with Wolfe Research.

So just to clarify the -- in terms of the growth rate and the earnings, you could just take $0.08 to $0.10 off of the base and grow 5%? Is it kind of as simple as that?

Yes or -- yes, it's virtually the same math. I would have grown it 5% and then reduced it $0.08 to $0.10 and that's where we are and then grow 5% thereon.

Great. And then in terms of the Toshiba guarantee, couple of questions there. First, as you get the money, how should we think about it being applied? Is it effectively applied as an offset to the investment and not needing that recovery in rates?

Yes.

Okay. And then I assume the October date is important just to make sure Toshiba actually pays it.

That's right, and recall, the way we've structured this agreement with Toshiba with respect to their guarantee, when you think about this draw schedule, we think the riskiest payments are the ones further out, right? So what we've done is provided for the normal draw of ELC to backstop the furthest draws away from us right now. To the extent they defaulted on this $300 million payment in October, we could accelerate the draw on ELC and take care of it that way.

Okay. And then on the equity needs, you mentioned, Art, a lot of factors. Most of those, you talked to them being equity beyond '17. The one I'm not sure was clear was on the Southern Power changing and how you're financing things there with -- could that impact the '17 equity? Or is that also further beyond?

Yes, we don't think so, Steve. The $1 billion that we've outlined we think will cover the waterfront, including all the businesses and use of third-party tax equity for Southern Power.

It could have an impact.

And one last question is, does the summer abandonment have any kind of practical impacts, good or bad, on kind of workforce availability, just the -- all the -- I assume there's a lot of resources up there that might be applicable for your site. PTCs, does it do anything there? Is there any just high end for your project that is worth talking about?

Yes. I mean, I think you started to suggest, am I right, that (inaudible) will be available. And no, you're not going to stretch personnel resources, whether that's skilled craft labor, whether that's leadership in either Fluor or Bechtel or anybody else that maybe brought to bear to the site. Certainly, with respect to the availability of PTCs, I expect that we'll be successful ultimately in Congress. They've all indicated a willingness to help. And we just got stuck up procedurally with, frankly, Obamacare in the Senate. So I think all those things will work to our benefit.

I had one last question, I forgot. The existing rate agreement on the $5.7 billion, my recollection is that when a -- when you -- a plant had to be running by 2020. Or once you hit the $5.7 billion, you went to like a lower ROE.

That's it.

Is that as simple as that?

Yes. And that's only during construction and what you would expect to see, if we drew the line out for what we expect out of earnings per share and this 5% growth trajectory, that's a long-term growth trajectory. To the extent you're in one of those periods where you hit the 7% ROE or whatever, you would have kind of a drop in the earnings power of those assets for a period of time. But once you cleared the in-service, they would return back to the regular rate regime at Georgia Power. We believe that circumstance, should it occur, would only occur post 2020 and would be like a year or 2 or whatever the circumstances warranted at the time.

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

So first question, just to clarify, the $1 billion equity that you need this year just from a timing perspective, do you need to have that Kemper settlement filed by August 21? Were any of the Vogtle documents filed before you can issue that equity or are those 2 things unrelated? How should we think about that?

Ali, it's a good question. At this point, we haven't detailed what timing will be, and we think they're unrelated.

I think you want to make sure you have appropriate disclosures at that point.

That's right, that's right. And we got a lot of disclosures going around, but we just have to pick the right time, sometime in the second half.

We certainly would prefer quieter waters to issue into.

Yes. But there's no -- as you said, on the disclosure front, there's no requirement that you need to have that out there. I mean, I'm just talking from an SEC legal requirement point of view.

No. As long as you had appropriate disclosures, I think you'd be okay.

And we're in an open window.

Okay. Okay, got it. And then coming back to the growth rate scenario. As you said, that's baked in a go scenario, but does that factor in this potentially higher cost at Vogtle? And then the incremental equity need, Art, that you were talking about, how would that sort of change that trajectory? Or is that already baked into the new line that you're showing us?

Well, it accounts for all the capital requirements that a go decision would require. And obviously, that's going to be spread out over time.

If you think about the $1 billion to $1.7 billion, it is additional. And if you think about the time frame in which that'll be realized, it's going to have a really modest impact.

Well, and it's -- really, it's not till post 2020 before you're even looking at spending over and above what our current plan already took into account.

And our sense is you would finance that with the same mix of capital we always do.

That's right, yes.

And the timing would be such as well in terms of when that additional equity would show up basically.

That's right. That's right.

Yes.

Yes. And then on the -- as you're going through this process on the Vogtle front, as you mentioned, the -- there's the ROE and there may be a timing issue for a couple of years. What about your partners' ability to fund those additional costs? As you said, you'd want everybody to move together. At the end of the day, if it is a go decision, is the thought there, Tom, that the current ownership structure stays as is? Or is there a possibility that, that changes?

Yes. We believe it will stay as is.

In terms of percentage ownership of everybody.

That's it. We worked under this kind of relationship for really decades and it's worked great.

Okay, okay. And then last question, as the Toshiba payments start coming through, as you said, those -- that's a multiyear process and you've got some backstop with the LC, but to the extent that there is -- the LCs are covered and there's still space left, is there a scenario where the commission could revisit whatever the new numbers are today? Or is the thought that whatever those numbers are, are pretty much set over the duration of the project?

Well, yes, let's add to the security package this notion of -- so you have the LCs. We have a share of whatever proceeds come from the sale of Westinghouse out of bankruptcy. There also is a non-subordination agreement that would essentially preserve, under many cases, our subordinate position relative to the bank credit that already exists at -- or that existed at Toshiba as of the date of the agreement. So we kind of had those 3 features. But you're right. There is an element that is uncovered in which we're essentially taking Toshiba credit risk. Now our idea was to front end load those exposures, so that in the near term, we think we'll know very quickly and get those behind us. So strategically, that's how we thought about the draw schedule and the rights to the sale of Westinghouse and the LC. There are always opportunities for the commission and the company and the co-owners to evaluate off ramps if conditions change materially. Say, for example, Toshiba doesn't pay its $300 million, say there's an extreme force majeure event, the commission always has the opportunity to evaluate that course forward.

Right, okay. And then last question, Tom, coming back to Kemper and the amount of investment that's not in rates. If you run the math on that amount, the EPS impact comes out much larger than the $0.08 to $0.10 you've talked about. And in that $0.08 to $0.10, I presume you've also put in the $1 billion of extra equity. So can you just help in the math? I mean, was there some -- these amounts that you originally assumed in your recent numbers that gives you that cushion? Or how does that math work to get us to that $0.08 to $0.10 from Kemper?

Yes. When we gave you the financial plan way back in October when we had our Analyst Day, we intentionally crafted our long-term growth rate on a conservative basis. And we allowed for, under a variety of circumstances, wherever it may occur, some cushion, if you will, in terms of adverse impact that may occur and still provide the long-term 5% growth rate. And that's what gave rise to this notion of resilience. So that has always existed. We believe that taking the gasifier off the playing field, so to speak, really leaves the commission with pretty clear kind of evaluations. That is, they're not dealing with the gasifier anymore. They're dealing with the combined cycle unit that has run among the best of any combined-cycle unit in the United States, E4, less than 1% average E4 for combined cycles 6 or whatever it is. And it has served a tremendous amount of energy for the citizens of Mississippi since 2014. So what we're left with, I think, in Mississippi is how does the commission want to treat the company on a sustaining basis. We believe we should be treated fairly there.

Our next question comes from the line of Paul Fremont with Mizuho.

Listen, I just want to clarify and follow-up on Ali's question. Does the $0.08 to $0.10 explicitly include the dilution from the $1 billion? Or does it not?

Yes.

It does.

It does, okay. And then is the apparent $500 million junior subordinated notes new in terms of financing? And will you get equity credit for that with the rating agencies?

Yes, we do get equity credit. And I believe that we have already issued a good amount of that. I can't remember the dollar amounts earlier this year.

Okay. And then also, I guess, following up on a question that might have been asked previously. The -- are you going to wait for the Vogtle go, no-go decision before issuing equity? Or is it possible that you could issue in 2 pieces?

Yes, Paul, we -- yes, we did answer the question before, but they're unrelated. Remember, we said the Vogtle need, if it's a go, would create more longer-term equity needs than shorter term. So we view those as unrelated, whereas the equity need this year would be addressing the Kemper write-offs.

And all you're asking, really, I think, comes down to having appropriate disclosure and everything else. So I mean, theoretically, you could issue equity before you have the decision in Georgia or not. You just have to make appropriate disclosures.

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

Tom, I want to change the topic. You made some commentary about potentially some programs at the core electric utilities, where you might find ways to serve customers more efficiently. But then you didn't go into a, hey, we're going to implement some kind of major O&M reduction program. That doesn't seem to be what you're talking about. I may be wrong there. It almost seems that it's more of a capital opportunity, meaning an investment in the infrastructure. Can you just talk a little bit about this size, scale, decision, time line, all that kind of good stuff?

Yes, sure. Well, every company is working through it right now, but the idea is kind of a modernization kind of thing. And what we would do is put greater intelligence in the wires, greater resilience into the transmission system, generating plants, more technology involved in customer service. For example, one of the things we've done recently at Georgia, just as an example, we did close down some human interfaces in some of the local towns, but we manyfold increased the customer touch capability through technology, kiosks and other things. So frankly -- and we found that customers frankly love that stuff. And in fact, I want to say Georgia Power this year was voted the #1 most trusted utility, even after all of these rather profound changes in the way we approach customers. Likewise, all of our companies generally set the bar across the United States in terms of customer satisfaction. So the big trade I would argue is one in which we are likely, and this will probably take the form of capital for the most part, putting way more technology out there and making whatever adjustments we need to, operating-wise. The other one, Michael, I would add, and this kind of goes to my hat that you know I have for all the electric utility industry, co-ops, munis and IOUs, on this whole cyber and physical security realm, I think it's really important and this even reaches EPA, and I made these arguments in the last administration. It's very clear that the resilience of our systems, whether its resilience to physical attributes or cyberattacks, we really need to think differently about how to make sure that electricity flows and electronic commerce and the digital age is able to be undertaken. And my sense is we need to think about resiliency, not just in N minus 2 transmission standards, but in standards that will provide cyber protection that nobody's even thought about 3 years ago. And certainly, we are leading the way along with some of my other peer companies in things like machine-to-machine capital additions as opposed to human-to-machine defenses in the cyber realm. So there's a lot going on there. I think there's lots of opportunity to improve the delivery of our product and make it more resilient on behalf of our customers.

Have you had an opportunity to vet this yet with either commission staff or intervenors or others or even the commissioners themselves? And at what point in the coming months or years do you think you might actually, I don't know, put -- quantify some of this when you're thinking about your capital budget updates?

Yes. I would argue this is kind of an ongoing discussion. When we think about -- I guess, the next rate case in Georgia will be 2019. Alabama has an annual process. Mississippi has TAP. Gulf just went through a process. These are the kinds of discussions that we have along the way. So you should view this again as a continuous process rather than discrete.

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

So let me just follow up a little bit here on the go, no go because it looks when you look at the slide that the no go has the cost of financing and that doesn't seem to be -- I mean, you'd have a footnote about it in the slide, but I just wanted to touch base. So if I look at it, would it be appropriate if you were to include financing in the good to go way? You take $3.1 billion to $3.5 billion, subtract $1.4 billion, which you've already spent, and then add that to the $1.0 billion, $1.7 billion to come up with something like $2.7 billion to $3.8 billion. Does that make sense?

You lost me in all those numbers.

That's basically right, yes.

Okay. And then with respect to the Toshiba payments, you're looking forward to about a $300 million payment, my understanding is, in October. And then you mentioned that you'll drawdown the LOC if you don't get that. If you do get it, does the LOC change at all? Is it still -- I think it's around $920 million. Am I right about that?

Yes. And there's a reduction at some point, $200 million or so, but the $700 million would remain outstanding for the balance of the draw schedule.

That's right. And remember, $3.7 billion is 100%. It's $1.7 billion for Georgia Power.

Yes, that's right.

And so when I'm thinking about that, though, the -- I guess, what I'm trying to figure out here is the staff and -- as -- just as recently as Friday believed that the Toshiba guarantee is really your problem, so to speak, whether you get it or not. Is there anything else we should think about as being potentially exposure to, I guess, in sort of Angie's question, exposure ratepayers if, as we go forward with respect to any exposure that might happen or contingencies we should think about that...

Yes. Without going beyond kind of we already have a rate settlement regime in place that established recovery of the settlement cost plus a prudence evaluation. That remains in place and will cover, I think, all of these questions. With respect to any of the details, the gives and takes along the way, let's not get ahead of the -- any kind of discussion we will have at the commission. Let that process play out.

Okay, fair enough. And then...

Paul, it is Art. Let me make sure you're clear as well. We got the LOC as a mitigant. And we also have the proceeds from the sale of Westinghouse out of bankruptcy that could potentially be a mitigant to that exposure as well. We have no idea what that will be, but it's another piece of the pie.

I got you. And then the 5% growth is with the go scenario. What would the growth be without the go scenario?

It depends on what that looks like, how much recovery we had, all that other stuff. It really gets into the regulatory settlement process. So if you'll bear -- give us forbearance here, let me defer that one.

Our next question comes from the line of Stephen Byrd with Morgan Stanley.

I just wanted to follow up on Ali's question on partners. And I just want to make sure I was clear. Should we presume that you all will be going sort of arm-in-arm together in terms of the path that you want to take later this month?

Yes.

Okay, understood. And then just a small clarifying question on the go, no-go pace. It's gotten so much interest. On the right-hand side on the no go, the benefit from the guarantee obligations, was there a reason that wasn't -- I know it's in the note below, but was there a reason that wasn't shown in terms of the net impacts of no go?

No. We've already beaten up the accountants on the presentation.

Our next question comes from the line of Andy Levi with Avon Capital Advisors.

Obviously, all the questions have been asked. The only thing I have is just on the balance sheet. So after you issue your equity, this is again specifically on the parent level, so when you're going to do all this financing that you've outlined, what will the estimated equity ratio be at that point?

Andy, I'm going to guess. It's going to be in the high 30s, and that's -- that would be my guess right off the top of my head. But the...

But the math we're solving to is not the equity ratio. It's the FFO to (inaudible)

Right.

No, no, no. I know how the ratings agencies look at it, right? But like, after you do the billion and you do the $435 billion and the $158 million, and I don't know, I guess, the junior subordinated wouldn't be included. But you'll be around 37%, 30 -- or 38%, I'm sorry, you said.

Yes. That went off the top of my head. We can get back to you in the boiler room, if you want.

That's all right. And then where would you like to be a year or 2 from now?

Well, as we go a year or 2 from now is we're going to have the kind of credit quality that we're solving to, so go to your coverage ratio. As we produce on the 5% earnings per share growth rate, we have a dividend payout ratio that continues to improve. The growth rate of dividends at $0.08 a year, assuming the board stays with it, we believe there's every reason they will, but it's their decision at the end of the day, would suggest that our payout ratio falls reasonably quickly into the mid-70s and that's kind of what the company looks like. Because of the good old Gordon model, we've talked about that one in the past, cash flow over K minus G, we're taking Kemper off the table. We are moving forward in, I think, a reasonably transparent way with Vogtle. So I would argue that K might drop a bit. G remains its size. And cash flow and the numerator looks like a pretty steady increase in the dividend growth rate over time. Remember what we did in '16 and why that was so important. That really gave us a steady ship in which to ride through sometimes these turbulent waters.

Okay. I mean, I think, in the past, you've said you've kind of wanted to be around 40% of the parent. But I guess, that the -- as the rating agencies don't seem to care that much about the parent equity ratio. They seem to care, as you said, about FFO to debt. And I guess, that's what your main focus is. It's not the equity ratio as much.

Andy, the other thing that's just kind of fun to think about here is how much of our earnings are coming from our state-regulated utilities, something like 96% came this quarter, 93% roughly of the -- of this mix between state-regulated utilities came out of our electric side. We are still, as we were, a state-regulated dominant company. On the balance, $0.09, so if you say $0.60, $0.70 kind of state-regulated, $0.09 came out of long-term energy infrastructure deals. So average contracts, I don't know, 14 years or so. So the nature of who we are, even after all of the stuff we did in '16, remains a very kind of low beta proposition.

Okay. And then the other question I have is just last year was -- or 1.5 years, last 1.5 years, you were pretty aggressive on the acquisition front. And I guess, you did make an acquisition yesterday on the wind side, I believe it was. But whether SONAT or whether it was AGL, after many years of really not being aggressive, where would you say Southern is headed at, at this point when it comes to corporate/assets beyond renewables M&A?

Yes, I would give you the same answer I've given in years past. Corporate M&A is extraordinarily hard. And you really have to have the right mix of chemicals in the sea in order for something to crawl up on the beach. We've always taken a disciplined approach. It would have to be accretive in a manner of months, not years. It would have to be at an acceptable credit profile. It would have to be consistent with our long-term strategy. I've been talking for years. Gosh, I could remember even back when I was CFO, that we needed more exposure to gas infrastructure. I've never wanted exposure to the commodity. I want exposure to the things that move the commodity. And that's what we were able to execute. When you think about the risk return profile of AGL Resources and then the Kinder Morgan SONAT transaction, boy, those are write-downs or strike down. And as you can see, not only they have performed well, they've exceeded our expectation. But if we remain a state-regulated, integrated utility with regular, predictable, sustainable earnings that give us regular, predictable, sustainable dividends per share. And you can see a follow through on that.

Our next question comes from the line of Ashar Khan with Visium.

I guess, from the conversations we've had to present, it's pretty much clear that it is a go decision. I don't know what else to make of it because otherwise, Tom, if I'm correct, right, and I wanted to run that because you didn't mention it in your slides. SCANA had $1.5 billion of tax benefit. And so if you do the no-go decision, there should be a lot of tax coming in backwards. And liquidity should be improved. And you might not need this equity, the amount you are doing, the $1 billion in the no-go situation. That's why they can go ahead and buy back their stock the next 2 day -- years. And I would assume a similar scenario would occur to you is that there would be a lot of cash benefits on abandonment case, which would flow back to the enterprise and should reduce your equity needs, even the present one. So am I wrong in that assumption? Question #1.

So let me just kind of answer it holistically. In our view, when you think about abandoning Vogtle 3 and 4, there's really 3 moving pieces. One deals with the potential for stranded cost. That is our investment to date. The second deals with the value of the Toshiba guarantee. And the third, as you mentioned, deals with potential tax benefits. The other thing that remains is your long-term relationship with the state general assembly, the regulators, everything else. Because when you abandon, you have nothing to show for the amount of money you've spent. If we go forward, we have a nuclear plant that will serve us for decades to come. But please understand, there has been no decision made. And that decision will only be made when we reach a recommendation in conjunction with and collaboration with our co-owners and in collaboration with the PSC that has the final say.

Okay. No, I understand that. My only point was, Tom, that why would you not delay your equity offering till that final determination is made because it could be beneficial. You might not need to issue this equity because equity dilutes us permanently. You know what I mean?

Well, here's the issue. You should think about the equity we're talking about associated with Kemper, okay, that any incremental equity associated with finishing Vogtle 3 and 4 is well into the future.

No. But I'm thinking of the equity refund we might get in case we decide to abandon. Are you with me? That's the way I'm looking at it, that if you do the no-go decision, there should be -- because of the income tax benefit and also from the guarantee, there should be things coming back to you. This should be -- do you...

Yes, Ashar. The other issue that I think you have to consider with Southern is we're in an NOL position. So to the extent you get a tax benefit from cancellation, you won't see the incremental cash until after the NOL is expunged.

Okay. And when does that happen?

All these things happens in the future.

Look, you could -- Ashar, you could push it out another year, 1.5 years before you actually get some cash, all of the cash associated with the no-go decision.

But I've been kind of pedantic, and then I hope I'm not driving people crazy, but the decision to go or no go goes way beyond the presence of cash in the next few weeks. It's going to go into a host of economic factors and qualitative factors that really take effect for decades. So this is not a year or 2-year decision. This is a decades decision.

Our next question comes from the line of Praful Mehta with Citigroup.

I guess, most of the questions and a lot of questions have been addressed. We appreciate it. I guess, just on the tax impacts on the no-go part. Does that impact rate base? Will that come out from deferred taxes? And how much is that to hit the rate base in a no-go situation?

Yes, Praful. There are -- you're really getting ahead of the regulatory situation there as well as to how that would be treated. I think under a normal framework, it would be a reduction to rate base. However, there could be a number of different ways that you could go about treating that. And so I think it's a little early to be asking that question for us to give you any kind of direct guidance as this depends on the regulatory environment.

Got you. Fair enough. And then on the tax equity that you mentioned, where you're going into renewables or buying more projects more from a -- with a tax equity partner, I guess, what's the leakage associated with that as an -- IRR is impacted given the tax equity? Investor obviously needs some kind of return. And will that reduce the ability to invest capital? Or do you still see enough opportunities out there, even with the -- a tax equity partner coming in?

I'd be kind of surprised, if I may jump in. What's different is the shape as opposed to the actual quantum of IRR.

Yes, that's true. And the accounting for third-party tax equity, we would still capitalize the amount of the $1.5 billion a year, but we would have the third-party financing provide a good portion of that upfront. So it would mean less debt and equity from Southern's perspective. It would mean correspondingly less income. But the structure and framework of the income over the first 5 years is actually richer and actually contributes to our 5% EPS growth. So you're issuing -- you're earning less income, but you're issuing less equity. But it still performs on our 5% growth path.

Got you. But then, I guess if I break out that 5% and exclude the impacts of these kinds of projects, which we most -- more look at, at least when we evaluate it, more look at it from an IRR or cash flow perspective, is -- are you saying that the underlying utility business profile is a little weaker and is boosted by the tax equity benefits? So the way the tax equity, I guess, is accounted for and the benefits, I guess, achieving or hitting your 5% target growth rate.

No. No, they still all have to meet the hurdle rates that we established for that business given the risks associated with each specific project and including the impacts of third-party tax equity. That's the way we evaluate it.

Our next question comes from the line of Michael Weinstein with Credit Suisse.

I really appreciate the extended time frame here. The Page 8, the cost estimates for Vogtle go, does that include the nuclear PTCs? Does that make an assumption that those are going to be -- go forward with that?

No. It doesn't include -- those are credits back to fuel, Georgia Power and aren't reflected in the capital cost at all, as there -- as you have nuclear generation, you get a credit for the amount of nuclear generation in the particular year up to a limit. And that's how that's accounted for as a benefit to customers. So it would be reflected in the ultimate price that your customer would pay. And that's why they're important to us.

Got you. So it affects the final rate increase at the end.

Yes, absolutely.

Right. And then one more question about the tax equity. Does -- how does that affect the 16% targeted FFO to debt if you -- as you take on more tax equity in the beginning?

Well, we're working with the rating agencies around all that. And right now, they see -- they don't see any real problem with that. But discussions will continue as we move along. As we always have discussions with rating agencies as things evolve.

Yes, they've been supportive.

Okay. And I think -- I understood that the 5% growth rate on EPS is -- assumes that a Vogtle go decision is made, it's unclear -- I guess, you weren't really quite sure how much it might get reduced in a no-go situation. But I think if I heard you right, you're -- you did reiterate a dividend growth of 8% increases or $0.08 increases is sustainable, even under no go. Is that a correct statement?

That's correct. And what we said -- remember, we weren't presuming a current state go. What I suggested was that was the assumption back in October when we gave you the financial plan. So I mean, the answer is the same, but I didn't want to prejudice anybody's judgment as to what we were saying here. We've not made the call on go, no go. But even on a no-go situation, the current dividend policy is robust.

Our next question comes from the line of Dan Jenkins with The State of Wisconsin Investment Board.

So I hate to keep beating this dead horse, but I just want to make sure that I'm thinking about Slide 8 in the way that I expect that certain parties to the proceeding will -- at least the staff and commissioners and the intervenors. So if I want to make sure I'm thinking about the economic piece of this correctly, would it be appropriate to include the quip and the cancellation cost, minus the guarantee obligations, minus any tax benefits of the write-off if they've ruled that all of that has prudently occurred to come up with the net no-go cost?

Yes, you're right on target.

And then I would need to add in whatever the cost would be for replacement generation and then compare that to the $6.7 billion to $7.4 billion, correct?

Yes, that's one way to go about it. Certainly, those will be factors that we would help present to the commission and helping them in our recommendation.

Okay. And then I just wanted to verify what sounded like from SCANA that one of their -- one factor that drove their decision was the decision of Santee Cooper to not go forward. I just want to verify that your partners are pretty much -- they're all on together in terms of where you're at on the decision-making process there.

Yes, we work very hard. Georgia Power makes very hard as a co-owner. We've had a relationship with these folks for decades. And we have a terrific relationship, among and between Oglethorpe and [Niag] and Dalton. And we work very hard to stay together on these issues. And I feel confident we will.

And then the last thing I wanted to ask about you, you mentioned how you continue to see the productivity improvements. I was wondering if you could give us a little more granularity in the type of improvements you've been able to achieve and the confidence you have that those would continue if you do decide to go with the go decision.

Yes. And what we'll do, we're going to have a lot more transparency. Obviously, we had to rely on our turnkey contract at Westinghouse. And so we didn't get complete transparency. They had their own books and records they kept. Now that we've been able to get in the middle of that, we've actually plotted out what we think their productivity rates were versus what we believe we're achieving now and what we think we can achieve. We have washed those assumptions through our external consultants, Bechtel, Fluor, others. TVA personnel had recently finished a nuclear plant. So we've already seen pretty dramatic improvements. I want to say it was something like 25% improvement this year in productivity and really ramping here. The best improvement has been the most recent improvement, the last 4 weeks for -- and we'll provide a way to talk to you all, our owners, as to how to communicate that productivity performance, obviously, as we're effective on schedule. That certainly has a bearing on being effective on cost and that will have an overall kind of aspect as to our success in hitting these numbers. Our near-term experience tells us that we can do a better job than Westinghouse should we decide to go down that road.

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

Just a quick -- you presented these new numbers on Slide 8 as preliminary estimates. And I think you also said, Tom, that you expect, when you file with the commission, that it'll -- instead of being a range of options, it'll be more like, I think you said, converging on a single point. Should we also expect the estimate to be narrowed in that filing? Or are these kind of the numbers and you're just doing more analysis?

Yes, Jonathan. We haven't put together a filing yet. We haven't got a recommendation yet. But to answer the hypothetical, my sense is the single point would be a recommendation and as a dominant belief among us, the co-owners. And I think that it won't surprise the commission, the staff and everything else. Like I say, we have an ongoing kind of conversation about where we're going. It will include now the input of our major contractors. We'll have moved down the road with people like Bechtel, Fluor, however we decide to construct that relationship. And I think we'll be more refined. I will not be prescriptive on this call, but I would estimate. I'm going to guess that we would still go with a range, but it might be a tighter range. We'll see.

Okay. And obviously, it'll probably surprise you if the number was outside the range.

That will surprise me.

Okay. And then -- and can I just recheck on equity. I think you've said a couple of times that you think equity for Vogtle purposes would be well into the future. Is there a scenario where '18 looks a bit like '17? Or is it more likely '18 looks like '17 used to look?

'18 looks like '17 used to look because, remember, the incremental equity we're talking about is Kemper-related. Any additional equity to the plan, assuming we do a go, occurs later.

Okay. And does that carry you out into '19 as well? Or is that a little too fuzzy at this point?

It could be somewhere in between, but we'll update that when we outline our plan going forward. I think it'll be a little more clear to everybody.

Okay. But the well into the future does -- probably means beyond '18. That sounds like it's -- you are saying that.

Yes. And remember, Tom talked about exceeding the $5.68 billion, I think, is what we -- there's $1 billion to $1.7 billion over that, we're not going to cross that line until '19, '20.

'19 or '20, yes, as we draw on the guarantee.

So incremental needs would be in line with that.

Yes. So it'll be kind of '20 and beyond assuming the guarantee numbers are there.

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

Yes. I just want to thank everybody for the phone call. These have been tumultuous times for us all here. We appreciate you hanging with us through this turbulence. But we are moving through it. We built a plan that, I think, is robust into the future. The premise of this investment remains a low beta, regular, predictable, sustainable. And we're able to, I think, deliver long-term earnings growth with an attractive dividend proposition for years to come. Thanks, everybody. We'll continue to work hard to get the best result possible. We appreciate your attendance.

Thank you, sir. Ladies and gentlemen, this does conclude The Southern Company Second Quarter 2017 Earnings Call. You may now disconnect.