SCANA Management Discusses Q4 2013 Results - Earnings Call Transcript

Feb.20.14 | About: SCANA Corporation (SCG)

SCANA (NYSE:SCG)

Q4 2013 Earnings Call

February 20, 2014 3:00 pm ET

Executives

Byron W. Hinson - Director of Investor Relations

Jimmy E. Addison - Chief Financial Officer and Executive Vice President

Stephen A. Byrne - Senior Vice President

Analysts

Travis Miller - Morningstar Inc., Research Division

James D. von Riesemann - CRT Capital Group LLC, Research Division

Andrew Levi

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Andrew M. Weisel - Macquarie Research

Operator

Good afternoon, ladies and gentlemen. Thank you for standing by. I will be your conference facilitator today. At this time, I would like to welcome everyone to the SCANA Corporation Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded on Thursday, February 20, 2014. Anyone who does not consent to the taping may drop off the line.

At this time, I would like to turn the call over to Byron Hinson, Director of Financial Planning and Investor Relations.

Byron W. Hinson

Thank you, and welcome to our earnings conference call, including those who are joining us on the webcast. As you know, earlier today, we announced financial results for the fourth quarter and full year of 2013. Joining us in the call today are Jimmy Addison, SCANA's Chief Financial Officer; and Steve Byrne, Chief Operating Officer of SCE&G. During the call, Jimmy will provide an overview of our financial results, economic development in our service territory and regulatory activity. Additionally, Steve will provide an update on our new nuclear project. After our comments, we will respond to your questions. The slides and the earnings release referred to in this call are available at scana.com.

I would also like to mention again that we now post new nuclear project-related information directly to our website at scana.com. On SCANA's Home page, there's a yellow box containing a link to the new nuclear section of the website that contains a link to project news and updates. It is possible that some of the information that we will be posting from time to time may be deemed material information that has not otherwise become public. In connection with this process, we have discontinued our prior practice of furnishing on Form 8-K the quarterly reports that SCE&G submits to the Public Service Commission of South Carolina and the South Carolina Office of Regulatory Staff for SCE&G's new nuclear projects. Instead, the company now posts copies of these reports in the new nuclear section of the SCANA website.

Finally, before I turn the call over to Jimmy, I would like to remind you that certain statements that may be made today on the call are considered forward-looking statements and are subject to a number of risks and uncertainties, as shown on Slide 2. The company does not recognize an obligation to update any forward-looking statements. Additionally, we may disclose certain non-GAAP measures during this presentation, and the required Reg G information can be found on the company's Investor Relations section of the website.

I'll now turn the call over to Jimmy.

Jimmy E. Addison

Thanks, Byron. And thank you all for joining us today.

I'll begin our earnings discussion on Slide 3. Basic earnings in the fourth quarter of 2013 were $0.73 per share compared to $0.79 per share in the same quarter of 2012. Higher margins from base rate increases and customer growth were more than offset by expected increases in operation and maintenance expenses and CapEx-related items, including depreciation, property taxes and share dilution. You will also note in the footnote at the bottom of the slide that other income in Q4 of 2012 included the impact of some tower sales at our telecom subsidiary, as we do in the normal course of business from time to time. There were no such sales in 2013.

Please turn to Slide 4. Basic earnings per share for the full year of 2013 were $3.40 versus $3.20 in 2012. Increases in electric margin due primarily to base rate increases and customer growth, as well as higher gas margins, were partially offset by increases in O&M and higher expenses and dilution related to our capital program. Results in the upper half of our guidance are consistent with our message on the Third Quarter Call in October.

For the year, our O&M increased approximately 2.5% over 2012 principally due to specific rate-case-related expenses and the amortization of previously deferred items. The additional O&M increases that we had projected at the beginning of the year were largely mitigated by cost-control efforts such as lower labor cost due to attrition. These cost-control efforts, along with other items such as lower incentive comp accruals, resulted in relatively flat O&M growth year-over-year, except for the regulatory amortizations.

Now on Slide 5, I'd like to briefly review results for our principal lines of business. South Carolina Electric & Gas Company's full year 2013 earnings were up $0.13 compared to 2012, driven largely by higher margins from an electric base rate increase as well as increases under the Base Load Review Act and the gas rate stabilization act, along with customer growth. These increases were partially offset by increases in operation and maintenance expenses, property taxes, interest and depreciation expenses and share dilution. For the fourth quarter, SCE&G's earnings were $0.03 lower than the same period last year due mainly to dilution.

PSNC Energy's earnings for 2013 were $0.37 per share compared to $0.38 per share in 2012. Increased margins from customer growth were offset by higher operations and maintenance expenses, depreciation and dilution. Similar to the full year, the fourth quarter was down $0.01.

The earnings for SCANA Energy, our retail natural gas marketing business in Georgia, in green, showed an increase of $0.09 over last year primarily due to a return to normal weather during the first quarter of 2013. For the quarter, SCANA Energy's earnings were $0.06, equal to the same period of last year.

SCANA's corporate and other businesses reported flat earnings in the fourth quarter compared to a gain of $0.02 in 2012 related to the 2012 tower sales noted earlier. For the full year, these businesses reported basic earnings per share of $0.04 in 2013 compared to $0.05 in 2012.

I would like to touch on economic trends in our service territory on Slide 6. We continued to see new business growth and expansion of existing businesses. During 2013, companies announced plans to invest approximately $2.5 billion with expectations of creating approximately 10,000 jobs in our Carolinas territories. We're excited about the continued economic development in the region. At the bottom of the slide, you can see that the national unemployment rate, along with the 3 states where SCANA has a presence and the SCE&G electric territory. While all these states continue to show marked improvement, the Carolinas are benefiting greatly from the industrial expansion. Specifically, South Carolina's jobless rate dropped below the national average for the first time since 2001. South Carolina's unemployment rate is now 6.6%, and the rate in SCE&G's electric territory is estimated at 5.4%.

Another positive data point on the economy is the recent United Van Lines' annual migration study. South Carolina and North Carolina ranked second and third, respectively, in terms of domestic migration destinations, corroborating our realized customer growth. These are all very positive signs for our territories.

Slide 7 presents customer growth in electric sales. On the top of the slide are the customer growth rates for each of our regulated businesses. We continue to see strong customer growth in our businesses and in the region. SCE&G's electric and gas growth rates for the year are 1.2% and 2.1%, respectively. Our regulated gas businesses in North Carolina added customers at a 2.3% rate.

The bottom table outlines our weather-normalized kilowatt hour sales for the quarter and the full year. Overall, weather-normalized total retail sales were up 1.9% for the fourth quarter and down 0.5% on a 12-month-ended basis. We are particularly encouraged by the industrial expansion, which has been mitigated by the efficiency and conservation into residential and commercial markets.

Now please turn to Slide 8, which recaps our regulatory rate base and returns. The pie chart on the left presents the components of our regulated rate base of approximately $8.2 billion. As denoted in the 2 shades of blue, approximately 85% of this rate base is related to the electric business.

In the block on the top right, you will see SCE&G's base electric business, in which we are allowed a 10.25% return on equity. The 2013 earned return in the electric business is approximately 9.5%, well within our stated goal of earning a return of 9% or higher to prevent the need for non-BLRA-related base rate increases during the peak nuclear construction years. Control of O&M and non-new nuclear CapEx, while monitoring and responding to margin fluctuations, is essential to achieving this goal. We're very pleased with the execution of our strategy.

Continuing down the page on our new nuclear business, we are allowed an 11% return on equity. The South Carolina PSC approved our request for revised rates under the BLRA, which added incremental CWIP of approximately $570 million to our rate base and increased rates just under 2.9% in November. Our regulated gas businesses in the Carolinas continued to perform well. We're allowed a return on equity of 10.6% and 10.25% in North and South Carolina, respectively, and we continue to operate these businesses close to those returns.

Along the bottom of the page is our regulatory schedule, exclusive of BLRA filings. These items are fairly routine annual filings.

Slide 9 presents our updated CapEx forecast. The CapEx at new nuclear reflects Westinghouse and CB&I's projected cash flow estimates supporting the current in-service ranges for Units 2 and 3. The projected cash flow reflects changes made by the consortium and the timing of certain payments. These projected cash flow estimates do not include the estimated $200 million in-service delay cost. The previous cash flow estimates were SCANA's internal estimates with input from Westinghouse and CB&I.

Forecasted CapEx in SCE&G, outside of the new nuclear deployment, increased slightly due to increased projected capital expenditures in our generation, transmission and distribution categories. Capital expenditures at remaining subsidiaries remain largely consistent.

Along the bottom of the slide, you can see our anticipated incremental CWIP from July 1 through June 30 for each period, on which the BLRA increase is calculated.

Now please turn to Slide 10 to review our estimated financing plan through 2018. The slide is consistent with the forecast from our last calls, other than the addition of 2018. To summarize our financing for 2013: We successfully settled our equity forward, resulting in the issuance of 6.6 million shares in early March and executed on-plan the equity financing through our 401(k) and reinvestment plans. SCE&G also issued $400 million in first mortgage bonds in June.

The financing plan, CapEx plan and in-service dates for Unit 2 and 3 reflect the current assessment of our new nuclear construction project as well as other projects. Of course, the amounts and timing could change due to inflation, construction schedule or other factors.

I would now like to discuss our 2014 weather-normalized earnings guidance and related assumptions, as shown on Slide 11. Our 2014 guidance is $3.45 to $3.65 per share, and our internal target is $3.55 per share. Due to the cyclical nature of our business, we expect to earn approximately 30% of this amount in each of the first and third quarters, approximately 25% in the fourth quarter and the remainder in the second quarter. Additionally, we are resetting our base year to 2013 based on 2013 GAAP basic EPS of $3.40 per share. In computing this guidance range, we have included the impact of base rate increases from our new nuclear filings under the BLRA. This guidance also incorporates the CapEx and financing plans we presented earlier.

Additionally, while we anticipate the number of customers will continue to increase, our assumption of customer average use of electricity is slightly lower next year to reflect current energy efficiency trends. We anticipate overall retail sales growth for 2014 to decline by approximately 0.2%. We forecast customer growth to be similar to 2013.

We expect operating and maintenance expenses to be approximately 3% higher in 2014 compared to 2013 actuals. We also expect continued growth in the CapEx-related costs of property taxes, depreciation and interest. Our effective tax rate for 2013 was approximately 32%, and we estimate the rate for 2014 will be similar.

Keeping in mind our internal target of $3.55, let's discuss potential upside and downside variables to our 2014 earnings range. There are several factors that could cause us to trend towards the lower end of our guidance. We continue to see fluctuations in average use. There continues to be industry uncertainty around electricity consumption, and as a result, we have forecasted average use to be slightly lower. Average use could come in lower than forecast due to higher efficiency adoption rates or simply conservation.

Customer growth continues to be a bright spot in our service territory. We are currently forecasting an increase for 2014. However, if customer growth comes in lower than expected, this could negatively impact earnings. Additionally, if nuclear spending were to shift to later years, it would impact our earnings. In contrast, there are several factors that could push us towards the upper end of our guidance. If average use were to increase or come in better than in 2013 or customer growth accelerates beyond 2013 levels, we could have potential upside.

Finally, as we reported last year, the pilot weather-normalization program in the electric sector ended as of December 2013, and we will see the impact of weather in our financials prospectively. Hopefully, this should provide you with a line of sight into our view of 2014 as you update your models.

I also wanted to mention that, earlier today, we announced an increase to our annual dividend rate for 2014 to $2.10 per share, a 3.5% increase. The results of 2013 and confidence in the long-term strategy were key considerations. We are not -- now back within our stated payout policy of 55% to 60% and expect to grow dividends fairly consistent with earnings prospectively.

Please turn to Slide 12. On January 27, we announced plans to increase our ownership in the V.C. Summer new nuclear units by 5% in the future. I will comment on a few financial matters related to this transaction, and Steve will comment later on the incremental capacity. As noted on the table, each incremented ownership interest will be funded with internal cash flow, driven largely by depreciation associated with the 2 new units. As a result, we do not expect to access the capital markets to fund this increase.

This transaction will not occur until Unit 2 is complete, and therefore, no change in the base load review formulaic increases will occur. Additionally, the estimated $500 million purchase will add to SCE&G's rate base incrementally with each annual purchase. And we will work to develop a plan to mitigate and possibly eliminate any upward pressure on customers' rates due to this purchase in the future.

In summary, we're very pleased with this transaction as it will add to base load generation for the long-term benefit of South Carolinians. We plan to file a petition with the Public Service Commission of South Carolina for approval of the transaction later this year.

I'll now turn the call over to Steve to further describe the impact of the transaction on our reserve margin and operations, as well as an update on our nuclear project.

Stephen A. Byrne

Thanks, Jimmy.

I'd like to continue the discussion on the agreement with Santee Cooper. In looking at our future generation needs in the integrated resource plan, the company decided that purchasing additional nuclear power was a great fit to help us replace a portion of the older coal-fired plants we expect to retire over the next few years, and delay our need to build new gas-fired capacity after the year 2020.

The structure of the 5% acquisition will happen in 3 stages. The first stage is triggered by the commercial operation date of the first new nuclear unit, which is currently anticipated to be late 2017 or the first quarter of 2018. At the time of commercial operation of the first new nuclear unit, we will acquire 1% or approximately 22 megawatts, with an additional 2% or 44 megawatts to be acquired no later than the first anniversary of the commercial operation date and the final 2% or 44 megawatts being acquired no later than the second anniversary of the commercial operation date. This approach keeps our reserve margins within our committed targets of 14% to 20%.

Now I'd like to outline the impact of the additional 110 megawatts on our generation mix as we dispatch our plants. On Slide 13, you can see our generation mix by dispatch and capacity. This is then updated to reflect the effects of the additional 5% share of the new nuclear generation through 2020. This additional phased increment still maintains our balanced approach to capacity, keeping nuclear, coal and gas at roughly 1/3 each, with the remainder of our generation in hydro, biomass and solar. From an operational perspective, this non-emitting base load generation will fit nicely into our system and allow us to forestall the addition of peaking generators while satisfying Santee Cooper's needs to divest of some of their share.

I'll now provide an update on our new nuclear construction project. Please turn to Slide 14. The company is reaffirming that we expect Unit 2's in-service date to be between the fourth quarter of 2017 and the first quarter of 2018. This date is still within the Public Service Commission's 18-month schedule contingency window for the currently approved in-service date, which is March of 2017. In-service date for Unit 3 will be similarly delayed, or roughly 12 months after Unit 2. The company is also reaffirming the previously reported estimate of approximately $200 million of additional costs associated with this schedule change. While we continue our discussions with the consortium, we believe SCE&G's responsibility for any portion of the $200 million estimate should ultimately be limited to substantially less once all of the relevant factors are considered.

I'll now provide a brief update to the on hook dates for some of our structural modules. As I previously mentioned, the on hook date is when fabrication of an assembled module at our V.C. Summer site will allow it to be placed on the hook of the heavy lift derrick. Module CA-20, see on Slide 15, is an auxiliary building module that will be located outside and adjacent to the containment vessel. All CA-20 structural submodules have been received on-site and 2 of the 4 major subassemblies uprighted and set into place on the assembly platen in the Module Assembly Building, as well as parts of the third and fourth subassembly. The remaining few components of the subassemblies are being inspected, repaired on-site and are being prepared for installation on the platen. This module is scheduled for an on hook date of the fourth -- first quarter of 2014.

Module CA-01, on Slide 16, is a steam generator and refueling canal module that will be located inside the containment vessel. Here, you can see a photo provided by Westinghouse of CA-01 at one of the China sites. On-site fabrication of this module should begin soon. This module has an on hook date of the third quarter of 2014.

Module CA-03, on Slide 17, is the southwest wall of the in-reactor water storage tank located inside the containment vessel. Fabrication of module CA-03 is progressing at Pegasus Steel's fab facilities in North Charleston, South Carolina. Here, you can see a photo provided by Westinghouse of a portion of this module at a similar AP1000 plant being lifted for placement. This module has an on hook date of fourth quarter of 2014.

The Unit 2 containment vessel Ring 2, shown on Slide 18, is the second ring of the containment vessel. This structure has an on hook date of the fourth quarter of 2014. The first ring of the Unit 2 containment vessel, which I will show you in a picture shortly, is scheduled to be placed during the second quarter of 2014.

On Slide 19, you can see a summary that outlines the on hook dates for these 4 module structures.

I would now like to discuss some recent activities at the site. Slide 20 presents an aerial view of the new nuclear site. In the center of the picture is the MAB or Module Assembly Building. To the right of the MAB, you can see Unit 2, and to left is Unit 3. Well, we are also making progress on the low-profile cooling towers along the bottom of the picture. I'll discuss the site in more detail shortly, but here, you can get a feel for the layout of the site, and you can see that things are really starting to take form.

On Slide 21, you can see the picture of Unit 2 Nuclear Island. As previously mentioned, during 2013, we completed the over-50-hour continuous pour of the Nuclear Island basemat, also referred to as first nuclear concrete. Then using the heavy lift derrick, we set the 500-ton CR-10 module on the basemat, as well as the containment vessel bottom head on the CR-10 module. The containment vessel will house numerous reactor system components, such as the reactor vessel, tightening steam generators and pressurizer. As you can see on the bottom right of the slide, work continues to form the concrete walls and other structures that comprise the Unit 2 Nuclear Island.

On Slide 22, you can see a picture across the top of the slide showing the successful pouring of the Nuclear Island basemat for Unit 3, which took place in November. Again, this basemat provides a foundation for the containment vessel, shield building and auxiliary building that make up the Nuclear Island for Unit 3. On the bottom left side of the slide, you can see the finished product of that pour. Currently, construction of the CR-10 module is taking place on the Unit 3 Nuclear Island basemat, as you can see on the bottom right of the slide.

On the top left of Slide 23, you can see a picture of the Unit 3 containment vessel bottom head. Similar to Unit 2, this bottom head will be placed on the Nuclear Island, on top of the CR-10 module for Unit 3. On the top right of the same slide, you'll see the first containment vessel ring for Unit 2. As I mentioned earlier, this ring should be placed on top of the Unit 2 containment vessel bottom head during the second quarter of this year. Two pictures along the bottom of the slide show cooling towers 2 Alpha and 3 Alpha. Both of these cooling towers are now structurally complete. All 4 of the low-profile forced draft cooling towers continue to progress as anticipated.

On Slide 24, you can see the schematic of the turbine building that illustrates how the various turbine building modules will look when complete. The modules that are highlighted in green have been placed in their final locations, with work continuing to progress for modules CA-81 Charlie and CH-82.

On Slide 25, you can see a picture of the Unit 2 turbine building. Comparing the schematic from the previous slide, you can see all of the previously mentioned modules in place on the turbine building basemat.

On Slide 26, you will see a few of the components that have arrived on-site. On the top left, you'll see a picture of the Unit 2 reactor vessel. This vessel is a thick-metal-clad stainless steel and houses fuel assemblies. On the top right, you will see Units 2 and 3 accumulator tanks on-site. These accumulator tanks are safety-related tanks that hold water and would be used to inject that water into the reactor vessel if they were -- if there happen to be a loss of pressure effect.

On the bottom left, you see 1 of 2 moisture separator reheaters being lifted with the heavy lift derrick. And moisture separator reheaters take steam coming out of the high-pressure turbine and super-heat that steam before it enters the low-pressure turbines to ensure that all -- that it's all steam and no water. On the bottom right, you will see the Unit 2 and Unit 3 core makeup tanks. Core makeup tanks contain boiled water and are a component of the passive cooling system that assists in safely shutting down the plant.

On Slide 27, you will see the new nuclear CapEx over the life of the construction. This chart shows the CWIP during the years 2008 to 2018 and has been updated using the fourth quarter of 2013 BLRA quarterly report, which we filed on February 11 of this month. As you can see, the next several years are considered the peak nuclear construction period. The green line represents the related projected customer rate increases under the Base Load Review Act. As Jimmy stated earlier, the 5% future acquisition will not affect these projected BLRA increases.

Please now turn to Slide 28. As we mentioned in our Third Quarter Call in September, the Public Service Commission of South Carolina approved an increase of $67.2 million. The new rates were effective for bills rendered on or after October 30. Our BLRA filings for 2014 are shown at the bottom of the slide.

On Slide 29, you will see a breakout of total new nuclear project costs. On the far right, you can see our current projected costs as filed in the fourth quarter 2013 BLRA quarterly report. Project costs are down approximately $633 million from the original approved -- approval received from the Public Service Commission of South Carolina. As you can see, this change is largely attributable to lower escalation.

That concludes our prepared remarks. We will now be glad to respond to any questions you might have.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question will come from Travis Miller of Morningstar.

Travis Miller - Morningstar Inc., Research Division

Wondering at the SCE&G, you talk about the non-nuclear. What's the primary thing that's holding back that earned return from the allowed return, that 100 basis points or so?

Jimmy E. Addison

Yes, Travis, it is the kind of headwind of just general consumption, non-weather-related consumption, really what's going on across the industry, occurring with us too with more efficient lightbulbs, more efficient HVAC, et cetera. So that's the -- that's kind of the large headwind that we're working against and offsetting it with cost control.

Travis Miller - Morningstar Inc., Research Division

Okay. Is there any point -- you've talked about customer growth, obviously, but demand growth slowing. Is there a point at which you see that demand growth stop slowing and perhaps start picking up again? Is there a trough point that you see in that region?

Jimmy E. Addison

Well, it certainly does in the mid term. I don't have a point, a calendar point, to put on that now. But to draw you 2 points in time: In the short term here, we're expecting it about flat, slightly less than '14, 0.2% down, whereas in our longer-term IRP that's out there now, we're expecting something over 1% growth over a 15-year period. So I can't tell you exactly at what point that turns and in what year, but it -- we do see it turning in the long run.

Operator

Our next question will come from Jim von Riesemann of CRT Capital.

James D. von Riesemann - CRT Capital Group LLC, Research Division

Before we get run over on all the nuclear questions, a couple of questions on my end. Jimmy, would you mind explaining this interest rate derivative, the uncollected fuel issue in a little bit more detail and kind of walk us through the geography on the income statement in the fourth quarter of '13 so we can think about our models in the future a little bit more clearly?

Jimmy E. Addison

Yes, I'll be glad to. So what happens there, if you want to kind of gross the income statement back up absent this accounting, you basically need to add $50 million back to margins and remove $50 million from other income. So we took these interest rate hedges that were substantially in the money and went to the regulator and said, "Hey, core to our strategy over this next nuclear -- 3 nuclear peak construction years is not having any other increases to bear on customers' rates, like fuel." And we are substantially in the money on these hedges because interest rates have risen. And instead of the customer getting the benefit over the next 30 years in lower interest rates related to the bonds where we've amortized the hedges, we'll cash them in and take all of the benefit back to the customer now by offsetting under-collected fuel costs, avoiding a potential fuel increase. So the regulator agreed to that. And there's a net $50 million of that that netted down margins and increased other income.

James D. von Riesemann - CRT Capital Group LLC, Research Division

Okay, super. On Georgia retail, I know you guys have had some significant cold weather down there. Can you talk about what you've been experiencing in the first quarter thus far, and how your contracts work down there? Are you guys variable or fixed?

Jimmy E. Addison

So our customers' contracts with us are both. And I would say a slight majority of them now are in the fixed area compared to variable, which is consistent with the entire market based upon our understanding of it. So more customers are in fixed contracts with marketers that are in variable contracts. We -- if they're in a fixed contract, we have a financial hedge in place based on any contracts entered into in any 1 month that aggregates all of those contracts and plans for normal weather. So when there's more -- abnormal weather, abnormally cold, of course, we've got some financial risk associated with that, but we're very comfortable. I'm not going to get into forecasting January's earnings, but we're very comfortable that January will be a good financial month for the Georgia business.

James D. von Riesemann - CRT Capital Group LLC, Research Division

Okay. And then let me kick off the nuclear stuff. Your friends are a few miles to the south. Are you thinking about doing a nuclear loan or at -- get a loan guarantee? Or at least, that's what every press is -- press report is telling us. How are you guys thinking about nuclear loan guarantees from the government?

Jimmy E. Addison

Yes, nothing's changed on our side. We continue to provide our information to the DOE on a periodic basis to keep them updated on our information since we initiated the application several years ago. And if ultimately we believe there is some benefit for the customer in that arrangement, we'll -- we would examine possibly doing it, but at this point, we've not seen the benefits.

Operator

Our next question will come from Andy Levi of Avon Capital.

Andrew Levi

Your guidance for this year, the $3.45 to $3.65, that's I guess based on kind of year end. Does it incorporate any weather in that pro-or-con?

Jimmy E. Addison

That's correct.

Andrew Levi

Like, whether it's upside or storms or anything like that.

Jimmy E. Addison

Right. The only thing I would say is that in our operating forecast, on the electric business, we do have in our operating cost a $2.5 million of potential costs that is basically deductible, if you will, before we can use our storm damage reserve. And based upon the experience to date, I can assure you we've exceeded that amount. So I'm glad we had that in our forecast.

Andrew Levi

Okay. So just explain that, I guess, real quick. So you have this $2.5 million deductible, which is in your forecast, but any incremental storm cost in South Carolina is covered through a clause or through insurance vote?

Jimmy E. Addison

Yes, so we have a storm damage reserve that we ceased adding to effective with the new base rates in the beginning of '13. But it has about $25 million in it at this point. So anything related to storms above the $2.5 million annually would go against that reserve. If we were to exceed the amount in the fund at this point, then we would simply defer that and go back to the regulator. Our agreement is, through the last settlement, we would go for some type of mechanism to get that recovered.

Andrew Levi

Okay. And then I think, clearly, there's upside from the weather as far as temperatures and things like that, but then also I guess you had some outages as well. But net-net, would you think you're on the plus side there weather-wise?

Jimmy E. Addison

Yes. We did have outages. We had at the peak probably 140,000 customers out. That did not last very long, probably less than 1 day. We had them all back on within about 5 days or so. But we made a rough estimate of the actual revenue loss, and that's less than $1 million.

Andrew Levi

Okay. So net-net, weather should be a positive, and that's not incorporated in your guidance for 2014...

Jimmy E. Addison

Well, financially, it's a positive. It's a heck of a way to get there with all that the states have been through in last week, though.

Andrew Levi

Right. No, no, I get that. It's not good for the customers at all. And then just on the Georgia side, how should we kind of think about that just at a very high level? I just remember, when we had the warm winter, there was a financial hit. Now we've had a really cold winter. So how should we kind of think about that business relative to what's the norm? Because your earnings are fairly consistent there.

Jimmy E. Addison

Well, what I would say is January is 1 of about 5 important months for the Georgia business. We're in the middle of February now. It's 82 degrees today. So we're not selling a lot of gas in Atlanta and the surrounding areas. So we -- I think we'll have a very good month in January, my gut feel. February, with part of it cold in the early part of the month, and now it's in the 80s, we'll have to wait and see what the rest of the month brings. But there are really 5: January, February, March, November, December all are key to that business. So we're only 20% of the way through the real earnings season for 2014 for Georgia.

Operator

Our next question will come from Mike Weinstein [ph] of UBS.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

It's Julien here, actually. Could you elaborate a little bit on the service delay costs, what the latest is there? And perhaps to the extent of which timing, do have any sense as to when this all might come to a head, if you will?

Jimmy E. Addison

You're talking about new nuclear?

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Yes, on the new nuclear, the $200 million.

Stephen A. Byrne

$200 million? Yes, I think what you heard us say today was that we're reaffirming that we still think that value is good and that that's still our number, not a consortium number. But we are anticipating that the consortium is going to go through another estimate at completion through this spring and summer. And sometime perhaps third quarter- or fourth quarter-ish of this year, I would anticipate that they will give us an estimate that will include anything that they see from that delay from receiving the modules, and that will start our negotiations at that point.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Great. And how long would that take just so you could kind of continue running out the...

Stephen A. Byrne

Yes, I'd be -- I'm loathe to give you a time estimate. Our experience with negotiating with the consortium is that things take a long time but it's worthwhile in the end. And then we've got an almost completely new management team in at CB&I and a lot of new folks at Westinghouse since the last time we went through one of these kind of negotiations, which would have been with their predecessor, Shaw. So it will take a while. Now whether that's a quarter, 2 quarters, 3 quarters, I don't know what I could tell you that.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Right. And could you just elaborate a little bit more on the shift? It looks like some of the CapEx that you were intending to spend in '13 moved out to '14 and '15. Could you just talk a little bit more about that?

Stephen A. Byrne

Yes, I think what we're looking at now is that, at our last quarterly call, we were estimating spending about $897 million in '14. We're now looking at some of the money from '13 moving into '14, so that's now increased by about $53 million in '14. Then that's largely a compression of the schedule. So when the end date stays the same and they don't spend as much in '13, it's going to push into '14 and '15. So the '14 number looks like about an additional $53 million. So when the consortium doesn't hit milestones, and they get paid based on milestones, we withhold payment.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Got you, excellent. And then lastly, could you just comment quickly? You comment briefly in your remarks about the additional 100 or so megawatts. Is that it in sort of for the time being in terms of ultimate ownership? If you could talk maybe about a long term? Is there a desire for more, or how this negotiation ultimately happened in your mind in terms of desire to take down more of the plant?

Stephen A. Byrne

You know what, it's the -- our desire really was based on the desire of our partner, Santee Cooper, to divest of some of their ownership percentage. I think their appetite to sell off some of their piece has diminished over the last couple of years. At one point in time, I think they were talking about a much higher percentage. And it looks like the 5% that we're going to take is satisfying their desire to divest of some of their ownership percentage. So I don't foresee that changing. I think that the 5% that we've agreed to purchase, pending the regulatory approvals, at least at this point in time, is it.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Great. And then from a seasonal perspective, the approvals, how long is that they're going to take here? I mean, how does that mesh into everything, if you will? Is there any kind of key date we should be bearing in mind there?

Stephen A. Byrne

No, nothing key. The really -- the ball is in the court of us to pull that together and go to the ORS and ultimately to the commission. And we would expect to do that sometime later this year, but there's no key requirement or time frame around it.

Operator

The next question will come from Michael Lapides of Goldman Sachs.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

A couple of just nuts-and-bolts item, and then one for Steve on the nuclear project. Jimmy, just real quick, on the gas RSA, what are you kind of expecting about -- for that in terms of potential rate revenue changes at the back end of the year?

Jimmy E. Addison

Yes, well, as we have on one of our slides there, the business has earned -- at this point, we're earning up in the 10.6%, 10.7% range, something like that. So that's in the upper end of the 50 basis point band. And the real contributor to that is the cost-control efforts we've had across the enterprise. And so -- and as well as really good growth in the gas system. So those new customers using more gas, with the growth, has really helped keep that return up. To me, it's really a kind of a high-class problem to have. We're likely in the situation where we'll not have an RSA increase this fall, but that's because we're earning the returns and we're controlling cost increases. And therefore, the -- we're running the business at the allowed return. So I really don't see a lot changing in that RSA.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

And so you -- basically, you don't assume there's a gas rate increase at SCE&G. And it doesn't strike me there's a general rate case process or much happening on the PSC -- PSNC side. Am I thinking about both of the gas businesses kind of correctly there from a revenue requirement change?

Jimmy E. Addison

Yes, I would certainly say that's the case for the next 12 months.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Okay. And then O&M, I want to make sure I understood. You made a comment about expect O&M roughly up 3% year-over-year. Just curious what's driving that. You all have a pretty good history of, I want to say, giving an initial O&M level and then coming in and beating it, and give credit to you guys for doing that. But just kind of curious what's driving -- given we're in a low inflationary environment right now, what's kind of driving that change in the year-over-year O&M?

Jimmy E. Addison

Yes, I think it's -- if you look at our actual results, they've been basically flat in the last couple of years now, realizing on the face of the financials that '13's actuals are up about 2.5%. But I said in the earlier comments, all of that was really driven off rate case amortization. So despite wage increases, increases from contractors, et cetera, we were able to hold our real costs flat other than those amortizations that flow through. You can only do that so long. If you look across all of our customer base, over the last couple of years, we've added about 30,000 customers in all 3 states combined. We're serving them with 200 fewer employees today outside of the folks that Steve's hiring in new nuclear. So we've done a really good job of holding that back for a while. We got to make sure in the longer run that we balance that against and don't cause damage to the customer service, reliability or safety, and we're just looking at balancing that.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Got it. And now that you don't have weather normalization now at SCE&G on the electric side, you still have it on the gas side. And is it on the gas side for both businesses, or just the SCE&G side?

Jimmy E. Addison

Yes, it's on both gas LDCs.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Got it. And then, Steve, on -- in the BLRA filing, there was a little bit of discussion about issues or concerns, really more issues with the reactor coolant pump and piping. And can you just kind of rehash for us, what actually is a reactor coolant pump and the piping that goes in it? And what are the some of the issues or concerns that you touched on in the BLRA?

Stephen A. Byrne

Sure. The way the reactor coolant system works is that the fuel rods are there really to make heat, and then the reactor coolant system water will move that heat and it carries it to a steam generator where we make steam with a secondary source of water. So our water never boils, it stays liquid, and we will then pump it right back from the steam generator to the reactor vessel. So it just makes a big loop. And on the bottom of the steam generators, in order to pump it back to the reactor vessel, we have 2 reactor coolant pumps. And these are new to the commercial nuclear industry type pumps. So they've been used for decades in military applications, like the Navy. So these are big canned rotor pumps. When they get the bugs worked out, I think they're going to be much, much better than the previous version of reactor coolant pumps, but they are working through some of those bugs. So there's a lot of testing that's going on, particularly for the projects in China. And as they're going through those China checkouts or tests, they're finding some issues...

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

And can you -- and what kind of -- when you say issues, I mean, are we talking operational issues? Or are we talking kind of the stuff like getting the materials delivered to your site on-time and on-schedule?

Stephen A. Byrne

No, no. We're talking about operational issues found during the test. We don't have any issues that we're aware of with the supply chain or getting them delivered to the site. But they've had some issues with some bearings that have been overheating. That's going to entail bearing redesigns and those kind of things. Not overly concerned about those. The do have one issue with some parts of the in-power [ph], which is the motor force on this pump that drives the water. Some repairs were made to some of those for the China project that created loose parts. And we've discovered that we did not go through the same process, so we shouldn't expect the same kinds of loose parts. So there's kind of checkout issues on the reactor coolant pumps. And I believe that the pressure being exerted on the supplier by the Chinese will solve the problems for us.

Operator

[Operator Instructions] The next question will come from Andrew Weisel of Macquarie Capital.

Andrew M. Weisel - Macquarie Research

I wanted to elaborate. I was hoping you could elaborate a little bit on Julien's question about the timing of the nuclear CapEx. I understand that some of the dollars that you expected to pay in '13 spilled into '14. But if I look at the BLRA from last week, it looks like there was also a pretty big pickup in '15 as well as '16, and then reductions in the outer years. So am I right in reading that, that the spending almost got compressed even further into the peak years?

Jimmy E. Addison

Yes. So here is the situation: If you -- let's look at it on the a mid-year basis since that's the way the BLRA filings happen, based on the CWIP that's expended through mid year. So what we forecast is that the -- that through midyear-2014, we'll be down $164 million compared to what we had earlier expected, and we will pick that up in '15, '16 and '17. So it's just kind of a skewing to the right of the same dollars. There's no real change in the dollars overall related to this. But the $164 million lower in '14, add 96 in '15, 43 in '16, 45 in '17 and about $18 million less in 2018. So it's just a change of the distribution.

Andrew M. Weisel - Macquarie Research

Okay, great. And then one other question. This is just sort of a -- maybe I'm misreading something in the press releases, but when I -- every quarter, you detail how many customers you have for the electric and gas utilities. And the numbers I'm calculating are very different from what you're reporting. So when I compare this press release versus the one a year ago, I'm showing about 0.66% increase in the customer count versus you're reporting a number significantly higher. You're basically showing almost 2% on an average basis. Is there anything that would cause the year-ago numbers to somehow be restated? Was there any reclassification?

Jimmy E. Addison

No, there's no reclassification, there's no restatement or anything of that nature. So it should be period-end data compared to the period end a year ago. So we've got -- I'm looking at it here now. We have 675,000 electric, 325,000 gas in South Carolina and just over 500,000 gas in North Carolina. And that yields 1.2%, 2.1% and 2.3%, respectively.

Andrew M. Weisel - Macquarie Research

Okay, maybe I'll follow up offline, but I just want to clarify the -- when you talk about similar growth in '14 that you saw in '13 on the customer counts, you are talking about those numbers that you just described, right, like the almost 2% on average?

Jimmy E. Addison

That's exactly right.

Operator

And ladies and gentlemen, that will conclude our question-and-answer session. I would like to turn the conference back over to Mr. Addison for his closing remarks.

Jimmy E. Addison

Well, thank you.

And to summarize, we're pleased with our results for 2013 and are optimistic about 2014.

And finally, I'd like to mention a couple of opportunities to meet with you in person. Steve and I will be on the road the first week of March in New York and Boston at investor conferences, and we hope to see many of you there. And also, our upcoming Analyst Day event is going to be held in New York on June 5, and we would encourage you to mark your calendars as -- with a placeholder for that and plan to attend.

We thank you for joining us today and appreciate your interest in SCANA. Have a good day.

Operator

Ladies and gentlemen, the conference has now concluded. We thank you for attending today's presentation. You may now disconnect.

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