Executives
Byron Hinson – Director, Financial Planning & IR
Jimmy Addison – SVP and CFO
Kevin Marsh – President and COO of SCE&G
Analysts
Michael Lapides – Goldman Sachs
Mark Declasit [ph] – FBR Capital Markets
Jim Van Riceman – UBS
Chris Ellinghaus – Wellington Shields
Jairo Chung – Oppenheimer & Co.
SCANA Corporation (SCG) Q3 2010 Earnings Call October 27, 2010 2:00 PM ET
Operator
Good afternoon, Ladies and Gentlemen. Thank you for standing by. My name is Towanda, and 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 Wednesday, October 27, 2010. Anyone who does not consent the taping may drop off the line at this time.
I would now like to turn the call over to Byron Hinson, Director of Financial Planning and Investor Relations. Please proceed.
Byron Hinson
Thanks, Towanda, 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 third quarter of 2010 and in a minute, Jimmy Addison, SCANA's Chief Financial Officer and Kevin Marsh, President of SCE&G will review those results and respond to your questions. Slides and the earnings release that we’ll refer to in these calls are available at SCANA.com.
As a reminder, certain statements that may be made during today's call, which are not statements of historical fact, are considered forward-looking statements and are subject to a number of risks and uncertainties, which are shown on Slide 2 and discussed in the company's SEC filings. The company does not recognize an obligation to update any forward-looking statements.
I will now turn the call over to Jimmy.
Jimmy Addison
Thanks Byron, and good afternoon. I’d also like to welcome each of you to our call. Let’s start on Slide 3, which reflects SCANA’s third quarter basic earnings per share of $0.80 compared to $0.84 per share in 2009. The decline in third quarter earnings was due primarily to the resolution of a State income tax issue which contributed $0.11 per share in 2009.
Other major variants for the third quarter were improved electric margins resulting from electric base rate increases under the Base Load Review Act, and the Retail Electric Rate Case, which more than offset higher net interest expense, higher property taxes, slightly higher O&M expenses, and share dilution.
With regard to the state income tax issue, SCANA recognized the benefit of a favorable decision from the South Carolina Supreme Court, in the third quarter of 2009. This decision related to state investment tax credits earned during construction of our co plant in 1996. Prior to this Supreme Court decision, and pursuant to the relevant accounting literature concerning income tax uncertainties, the value of the contestant credit had not been reflected in our income statement.
The multi-year catch-up resulted in $0.11 per share impact in the third quarter of 2009.
Additionally, in the third quarter of 2010, we implemented the Electric Weather Normalization mechanism beginning with bills rendering in August. The mechanism applies to residential and commercial customers and resulted in a residential credit of $24 million or $0.12 per share and a commercial credit of $4 million or $0.02 per share during the quarter. As a result of the W&A mechanisms at SCE&G, both electric and gas, and the PSNC Customer Utilization Tracker, our prospective regulated earnings which comprise over 90% of our total, are more predictable for our shareholders and the effects of abnormal weather on customers’ bills are mitigated.
Let me briefly comment on the presentation of basic and diluted earnings per share as mentioned in Note 2. As you’re aware, in May we entered an equity-forward to provide for the balance of our equity needs for 2010 and 2011 to support our construction program.
Basic earnings per share reflect the shares we have actually issued during the year. In contrast, diluted earnings per share include the effect of a calculated number of a potential, or incremental shares that would have been outstanding if we had issued the shares under the forward contracts.
That small incremental number or additional share and the denominator results in diluted EPS being marginally lower than basic EPS. In this quarter, the difference amounted to $0.01 per share. If our stock price stays above contract forward price, we expect similar small amounts of potential dilution over the next few quarters.
Basic earnings for the first nine months of 2010 were 225 per share compared to 223 in 2009, which again, included $0.11 per share related to the state income tax issue. The year-to-date increase in earnings was driven primarily by improved electric and gas margins due to regulatory outcomes and customer growth.
I’ll comment more on customer growth later, but it’s important to note that each of our four major retail businesses continue to add customers compared to last year. These margins improvements were offset by higher interest expense, higher property taxes, slightly higher O&M expenses, and share dilution.
We’re pleased to see continued signs of economic recovery in our service territory. As shown on Slide 4, kilowatt hour sales of electricity to our retail customers in the third quarter were up 8.4% compared to the same quarter in 2009. The residential class showed an increase of 10.8%, while industrial and commercial classes followed with increases of 8.4 and 5.9% respectfully.
Overall, total kilowatt hour sales of electricity which includes sales to other utilities were up 7.6%. As you may remember, our W&A and cut mechanisms normalized margin and not kilowatt hours or therm sales, therefore, weather certainly impacted residential and commercial kilowatt hour sales. But industrials, which have minimal weather impact, continue to show a strong recovery compared to 2009.
On Slide 5, consolidated therm sales were up 20.6% over the third quarter of 2009, driven by higher industrial sales primarily attributable to power generation customers, which more than offset a decline in residential and commercial and sales for resale, principally due to a warm September.
Now, on Slide 6, I’d like to review third quarter results for our principal lines of business. South Carolina Electric and Gas Company, our largest subsidiary reported basic earnings per share of $0.87 compared to $0.89 per share in the same quarter last year. The decrease is attributable primarily to the state tax benefit recorded in 2009. Electric and natural gas margins were higher due to regulatory outcomes in our Base Load Review Act, and Natural Gas Rates Stabilization Act filings, and the successful completion of the Retail Electric Rate Case in July of this year.
These improved margins were offset by higher interest expense, higher property taxes, slightly higher O&M expenses, and share dilution.
At September 30, 2010, SCE&G was serving approximately 660,000 electric customers and approximately 309,000 natural gas customers, both up approximately 1% from the same time last year.
PSNC Energy, our retail natural gas distribution company in North Carolina, reported a seasonal loss of $0.04 per share the third quarter of 2010, unchanged compared to the third quarter of 2009. This result is due to a slightly higher gas margin offset by higher depreciation of property taxes.
At September 30, 2010, PSNC was serving approximately 468,000 natural gas customers, an increase of 1.6% over the last 12 months.
SCANA Energy, our retail natural gas marketing business in Georgia, reported a seasonal loss of $0.02 per share in the third quarter of 2010; also unchanged compared to the third quarter of 2009.
At September 30, 2010, SCANA energy was serving more than 445,000 customers. SCANA Energy has worked very diligently on customer retention and acquisition, and as a result, we have gained over 4,000 net customers over the last 12 months in a fairly flat overall market.
SCANA’s Corporate and other businesses reported a loss in the third quarter of 2010 of $0.01 per share compared to earnings of $0.01 per share in the same quarter last year.
I would now like to touch on our financing plan and cash flow.
As you may recall in the second quarter, we discussed a change in income tax accounting for capital maintenance. This change in tax accounting affects certain types of calls previously treated as property additions and deducted through depreciation over the related asset’s life.
With this change, all such maintenance will instead be treated as current expense for income tax purposes. This strategy is expected to provide even more than our initial estimate of $100 million in cash flow in 2010 and 11.
Additionally, we were able to take advantage of the recent extension of bonus depreciation, which allows 50% of qualifying assets to be expensed for tax purposes, and results in an incremental estimated $50 million in cash flow.
Combined, these changes eliminate our taxable income on our 2009 return, and substantially reduced our 2010 estimated payments. In total, these actions provide us an estimated 150 to $175 million in near-term cash flow.
This improved cash flow will be used to mitigate external capital requirements.
As mentioned earlier, in May we completed a $300 million equity transaction with $240 million in a forward structure. We have planned to draw in an additional $90 million under the forward, later this year, and the balance of $150 million in 2011. Based on the improved cash flow provided through these tax strategies, we do now not anticipate needing to make those draws until late 2011, allowing us the flexibility to efficiently match our equity needs with the timing of capital requirements for our nuclear project and to reduce financing risk, all while minimizing real share dilution.
The exact dates of additional draws are subject to our actual operating results and additional sources of cash, but ultimately, our intentions are that these tax strategies will reduce plan debt offerings. We’re very pleased with the flexibility the forward structure has provided.
Finally, we’re very pleased to report that earlier this week we successfully completed this indication of an expanded credit facility.
Please see Slide 7. The additional liquidity is important to our nuclear construction, and the five-year tenure expends substantially all of the plan construction period of the first new unit.
The committed lines of credit now total 1.5 billion, have terms of five years, and replace the prior committed credit facilities which total 1.1 billion. The new lines of credit consist of 300 million for SCANA, 100 million for PSNC, 400 million for South Carolina Fuel Company, and 700 million for SCE&G.
As part of this new expanded facility, we have also arranged for SCANA to operate a commercial paper program providing us even more financing flexibility.
I’d like to thank our banks for their enthusiastic support of our liquidity needs and supporting our nuclear expansion plans. We are pleased that we received an excellent response from equity investors, debt investors and now our banks.
From a financial standpoint, we’ve had a solid quarter and are pleased with implementation of our new electric base rates and the renewal of our credit facilities. The tax strategies mentioned only strengthen our plan, especially when combined with the flexibility of the equity forward.
I’ll now turn the call over to Kevin Marsh, President of SCE&G for a regulatory and construction update.
Kevin Marsh
Thanks Jimmy. Beginning on Slide 8, I am very pleased to report that our new nuclear project remains on schedule and on budget.
On August 16, we filed our quarterly status report with the PSC and the Office Regulatory Staff, as required under our Base Load Review Order. This report provides a detailed update of our capital cost incurred, and updated milestones for our new nuclear project and is available on our website. Due to the following deadline, the figures in this report include the 438 million contingency fund, which in early August the South Carolina Supreme Court, determined should be excluded from the capital cost projections approved under the Base Load Review Act.
Adjusted figures will be supplied in future quarterly BLRA filings. Updated gross construction cost of June 30, 2010, including escalation and AFUDC are $648 million below the revised scheduled forecast. This production is largely to lower estimates of projected escalation rates, which have been impacted by the recession.
Let me expand on the South Carolina Supreme Court opinion and its impact on the treatment of contingency funds.
As initially authorized by the PSC in 2008 and 2009, the capital cost schedule for the new nuclear project included a pre-approved contingency reserve of $438 million.
On August 9, South Carolina Supreme Court ruled this contingency reserve could not be pre-approved as a component of construction cost by the PSC. Instead, the company is now required to submit all cost for approval by the PSC as they are identified to specific budget items. The projected contingency fund that was initially approved by the commission was less than 10% of the total nuclear project budget. All of the portions of the Base Load Review Order, remain intact, and construction of the new units is continuing as planned.
I want to emphasize that this decision does not delay the actual construction of the new unit, nor does it change the certificate of environmental compatibility and convenience issued by the Commission to construct the new unit. The Supreme Court ruling, merely changes the steps in the regulatory process, and it should not change the outcome as long as the cost incurred remain proven.
I would like to direct your attention to Slide 9, which shows on the total project basis that the current projected nuclear plant construction cost, including estimated escalation is approximately $1 billion under the forecasted file cost included in our initial BLRA filings from 2008. Additionally, you will note on the slide, in the red dash circle, we have approximately $6 million in the committed category compared to the projected total project cost of 9.6 million.
Earlier this week, we disclosed that the company plans to file an application with the PSC to update the approved capital cost schedule for the new nuclear project. The requested update will be for an amount between 150 and $200 million and $2,007. We anticipate making the filing within the next 30 days.
The cost in question will be incurred over the course of construction project, which is scheduled to be completed in 2019. The company still anticipates completing the project within the original budget estimate that included the contingency projection of 438 million and is simply responding to the court’s decision, seeking commission approval to reclassify these costs in contingency fund to specific budget categories.
As you can see on Slide 10, on August 10, SCE&G, acting for itself and its agent Santee Cooper, agreed with Westinghouse, and Stone Webster to shift significant additional portions of the EPC contract components from the target category to the fixed cost, and fixed cost with escalation categories.
As a result of this agreement, approximately 2/3 of the total EPC contract call are now in these fixed-cost categories. We are very pleased with this development and believe these shifts serve to further insulate us for cost overrun and lower overall risk of the project.
Continuing on Slide 11, if you may recall, on May 28, SCE&G filed for the increase on its annual revised rate adjustment filings with the PSC under provisions of the South Carolina and BLR rate. The BLRA allows for annual adjustments to rates during construction of the new nuclear units as means of recovering financing cost related to CWIC.
On October 1, 2010, the PSC improved an increase of 47.3 million or approximately 2.3% in the retail electric rates of SCE&G under the Base Load Review Act. The new rates are expected for bills rendered on and after October 30.
Several media articles in the past few months have stated that Santee Cooper, the stated utility, involved in our nuclear project may seek a partner to share and it’s 45% ownership in the construction of EC Summer Units 2 and 3.
Their decision does not affect our ownership stake of the project.
As we have discussed with you over the last two quarters, SCE&G has been advised by Santee Cooper, and in light of recent development it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of this participation in the two units. If Santee Cooper’s ownership interest and one or both of the units changes, SCE&G believes that one or more of this additional parties will be available to participate as joint owners.
On June 15, SCE&G submitted its quarterly filing to the CSC as required under the Rate Stabilization Act, for the gas distribution business. In that filing, the company reported its return on common equity for the 12 months period, ended March 31, 2010, was 12.92% compared to an allowed return of 10.25%. This was largely due to the significant capital expenditure reduction and O&M cost control measures, and response to the recession.
[Inaudible] equity with more than 50 basis points above our allowed return of 10.25%, SCE&G requested a decrease in its retail natural gas base rate in order to restore the return on equity to the 10.25% authorized level.
October 15, 2010 following a required audit of the company’s filing of the ORS, the PSC issued an order approving a decrease in retail gas rates of approximately 10.4 million or 2.31%. The rate adjustment will be effective with the first billing cycle in November.
That concludes our prepared remarks, and Jimmy and I will now be glad to respond to any questions.
Question-and-Answer Session
Operator
(Operator Instructions) Your first question comes from the line of Michael Lapides with Goldman Sachs. Please proceed.
Michael Lapides – Goldman Sachs
Hey, guys. I just – a lot of moving parts regarding the BLRA and the summer build. I just want to make sure I understand one of the basics. What are you now saying the cash cost of construction will be between today and the end of the project, and then the total cash cost?
Kevin Marsh
Let me flip to that slide. I think that was Slide 8 or 9. You see the gross construction cost on that slide? This is Slide 8. We expect the total cost based on what we know today, including installation would be $5.8 million, the five being 896,976 in the second column which excludes AFUDC.
Michael Lapides – Goldman Sachs
Okay. And then less escalation, I’m just trying to make sure I'm following the bridge because some of these has changed since the original filing - follow the bridge from that total project cash flow done to the capital cost in ’07 dollars?
Kevin Marsh
When we made the filing with the commission, it was in ’07 dollars and included projected escalation, but ’07 dollars just references back to the actual contract and then building the escalation on top of that to give you the total cash we expect to expend.
Michael Lapides – Goldman Sachs
So if I think about your rate-base addition over the life of the project, excluding AFUDC, it’s the 5.9 and then you add in the AFUDC which is limited amounts given the fact you had a two-time a year rate increase?
Kevin Marsh
That’s correct. The budget dollars, we show that we work to that 5.9 billion.
Michael Lapides – Goldman Sachs
Got it. Okay. Thank you. One other thing, can you disclose what are the kind of items that are still left unfixed in your contract with, you know, with Westinghouse and with Shaw? You know, kind of –what comprises the red bar?
Kevin Marsh
The majority of that is labor, time and effort on the labor aspects of actually constructing the project.
Jimmy Addison
Yeah, the parts and labor on site. Obviously, a lot of it is done modularly, but the labor on site.
Michael Lapides – Goldman Sachs
Got it. And isn’t that, given what’s happening in the economy, isn’t that kind of moving your direction in terms of cost?
Kevin Marsh
Well, I think with the recession we’ve had a good time here, but unfortunately all of those calls could be down. And certainly we’ve got a long time to go, but everything we’re expending now is coming in under budget because we’re enjoying the low escalation rates. Just yearly costs are lower in the industry right now.
Michael Lapides – Goldman Sachs
Got it. Okay, thank you, guys.
Kevin Marsh
Sure.
Operator
(Operator Instructions) Your next question comes from the line of Mark Declasit [ph] with FBR Capital Markets. Please proceed.
Mark Declasit [ph] – FBR Capital Markets
Thank you very much, and good afternoon. Two questions. The first is, as you consider the recent contractual and regulatory changes to New Nuclear, your project here, would you say that the risk of the project has gone up or gone down at this point? And if so, what is the basis for that answer?
Kevin Marsh
Well, in my it’s really unchanged at the present time for a couple of reasons. First, the level of contingency calls we had include in the initial base-load review filing were less than 10% of the total cost of the project. When the Supreme Court decided that those costs could not be included in the pre-approved amount set forth by the Commission, they did not say we couldn’t recover those costs. They simply said, before we could include those in the base-load review recovery provisions we would have to go back to the Commission and we specifically identified where those dollars would be spent and then the condition could include those in the base-load review cost.
And that’s what we’re doing in this filing we expect to make in the next 30 days. We’ve made our projections and we’ve identified a level of certain costs we know we’re going to be spending and we’ll simply be taking that back to the Commission and presenting it to them for their consideration.
We believe these costs, as with all the other costs in the project are prudent and there are no surprises in these costs. We fully expect to be using this contingency fund in this manner. We’ve just got the additional step at this point of having to go back to the Commission as a result of the Supreme Court’s decision.
Jimmy Addison
And Mark, in addition to that I’d say the move that Kevin talked about earlier with the contract now, it was slightly over 50% was fixed – fixed, with an escalator now is 2/3s, so outside of the contingency discussion, I’d say that that is a downward pressure on risk.
Mark Declasit [ph] – FBR Capital Markets
Right. I mean, my gut reaction, which is not a legal one, is that you – I think you have a little bit more risk on the regulatory front, a little less risk on the contractual front with Westinghouse. But I understand your characterization of what’s happening.
Kevin Marsh
And to follow Jimmy’s comment, you know, a portion of the dollars identified we’ll be spending from the contingency would be a risk treatment we paid to move of some these variable costs to the fixed categories. We think that’s good for us, we think that’s good for customers and that we certainly are confident the Commission will look at that once they’ve heard our testimony and the information we provide them to include that was proven. So that would be another reason we feel confident of the recovery of those dollars.
Mark Declasit [ph] – FBR Capital Markets
Right. And regarding Santee Cooper, you indicated that they might be interested in lowering their ownership interest. What is the process by which that happens? How is this interest exchanged from one party to the other? Is it sold, is it – how does that happen?
Kevin Marsh
It’s covered by the terms of the agreement between us and Santee as part of our partnership arrangement. The first step in the process would be for them to complete the evaluation of what they believe their needs will be long term, and then if they decide to reduce their level from the original estimated 45% which they signed up for, we would work with them to go through that process.
Mark Declasit [ph] – FBR Capital Markets
And how would you identify another suitable party? Do you have a right of refusal to a party that you may not deem creditworthy or do you have some say in the other party that could join you as a partner?
Kevin Marsh
What I think is, as part of the agreement we would have to take that ownership change back to South Carolina Public Service Division for them to Review. That was part of the base-load reorder. We certainly had plenty of interest from other parties that have said they would like to talk to us if that time comes.
Mark Declasit [ph] – FBR Capital Markets
Thank you very much.
Operator
And your next question comes from the line of Jim VanRiceman with UBS. Please proceed.
Jim Van Riceman - UBS
Good afternoon everyone.
Kevin Marsh
Hello, Jim.
Jim Van Riceman - UBS
A couple questions, more modeling type. If I look at your trailing 12 months earnings, there’s 290 a share, and I know your guidance is 290 to 305. The first question is, what – can you explain what would keep us down in that 290 range and then the second part of the question is obviously, what would get us up to the 305 range?
And then the follow-up question. How should we think about share counts for 2011 and 2012 given the delay in the forward pull down of shares? Maybe talk a little bit more about effective cash rates and effective cost of debit if you would please.
Jimmy Addison
Yeah, Jim, first of all, let me start with the second one, and you may have to remind me of the first one by the time I finish with this answer. We’re not going to be complete point specific about what we’re modeling today, but we really believe with these tax rates in place, it will be late in 2011 before we’ll need to take any of the additional shares down under the forward. So we feel pretty good about not taking any of those down until the later part of 11. Of course, you know, we’re bringing down 90 to 100 million a year in our dividend reinvestment and 401(k) shares each year. So effective tax rate, I think we still feel pretty good about it around 29% or so for our effective tax rate. Debt levels, you know, the debt carrying cost, not a lot of volitility there because we have a very high percentage of our dept is in fixed rates. Everything at the utility operating company is fixed and are all over long terms. We’ve not done anything over 5 or 10 years at the operating company and none of its variable other than just, you know, short-term commercial paper.
Back to your first question about what might influence from one end of the range to the other. Probably the largest volatile factor would be what happens in the balance of the year with the weather as it relates to Georgia. So now with this weather normalization in electric, weather normalization in gas in South Carolina, utilization in Tracker in North Carolina, which wraps the weather inside of it. The only thing we really have subject to weather is the Georgia business. So the October through December months, the fourth quarter, if it’s cold in that business, that’s going to obviously help us move above the middle of the range or so. And if it’s very mild it would move us towards the lower end of the range. That’s our primary variable left here in the fourth quarter.
Jim Van Riceman - UBS
Is the grass still real green down there and you guys are playing golf?
Jimmy Addison
We’re not playing any golf, I promise you, not the last two weeks. But it’s mid-80s today, but it’s supposed to be very cool by weekend, I think lows in the upper 30s.
Jim Van Riceman - UBS
Okay. Thank you.
Jimmy Addison
You’re welcome.
Operator
Your next question comes from the line of Chris Ellinghaus with Wellington Shields. Please proceed.
Chris Ellinghaus – Wellington Shields
Hey, everybody. How are you?
Jimmy Addison
Good, Chris.
Chris Ellinghaus – Wellington Shields
I believe – I think the in beginning, Jimmy, you were giving us some numbers on weather normalization impact and I didn’t quite catch that. Can you just go over that again?
Jimmy Addison
Yeah. The – for the quarter it’s about $0.12 per share for the residential and about $0.02 per share for the commercial. So $0.14 in aggregate. It was a very hot summer.
Chris Ellinghaus – Wellington Shields
Right. Okay. Can you also just review again for us how the variance process works in North Carolina?
Jimmy Addison
I’m not sure I follow your, Chris.
Chris Ellinghaus – Wellington Shields
You were saying that the weather is sort of –
Jimmy Addison
Oh, yeah, yeah. The utilization tracker?
Chris Ellinghaus – Wellington Shields
Right.
Jimmy Addison
Sure. It’s just – it’s just a usage tracker that separates the rate from the utilization so that it’s meant to – for any reason, if a customer uses less number of therms than the therms they used in the test year that the rates where set on, then it’s adjusted. It’s deferred over a six-month period. It’s meant to encompass more efficient appliances, lower usage per customer so that the utility isn’t constantly losing ground. Once the Commission sets a rate, if a customer has put in more efficient appliances, tankless hot water heather, etcetera, then you’re losing ground in making your margins that it takes to learn your allowed return. So it really encompasses that efficiency and as well as any weather impacts.
Chris Ellinghaus – Wellington Shields
But it should – what I’m trying to get out is how efficient do you think it is in sort of separating out weather versus other sort of usage impacts that you can’t necessarily define?
Jimmy Addison
Well, they’re all wrapped in together, so we don’t attempt to determine what part is due to weather or what part is due to less usage per appliance, but they’re all wrapped in together so that we’re made whole.
Chris Ellinghaus – Wellington Shields
Maybe a better way to phrase it is you feel that mechanism is working effectively?
Jimmy Addison
I do. I really do. It’s a good mechanism for I think, all involved; for the customers, for the company and the Commission. You know, to contrast it to the mechanism in South Carolina, we’ve got the Annual rate stabilization Act and they have their pluses and minuses. You know, the difference in South Carolina with the rate stabilization act is you pick up each year any new rate base. Or in example of this most recent year, we depreciated more than we added so the customers got a small rate decrease. The only way you turn that up in North Carolina is to have a rate case periodically every few years to pick up new rate base. But the North Carolina mechanism, on the other hand, picks up just any efficiency that moves through the system, so it’s positive from that standpoint.
Chris Ellinghaus – Wellington Shields
Okay. And lastly, I don’t know, Kevin or Bill maybe, can you talk some more about the benefits that you’re getting from the Chinese in terms of construction?
Kevin Marsh
Yeah, as a matter of fact, I just got back from a trip a little over a month ago with Steve [inaudible] who heads up or Nuclear Group of our Generation, as well as Jeff Archy, who’s our Chief Nuclear Officer. We’re getting a lot of benefit; one, just from first-hand view of the construction process, which generates questions in our minds about techniques or applications of the actual construction procedures. We have a change to talk to their people first hand to understand what their problems are. We’ve had, you know, good information shared with us about how they take those lessons learned and implement them back into the engineering process through Westinghouse, which ultimately shows up in an improved product on our end when we start our construction. So just from an overview perspective we get to see that first hand and talk to the people that are actually engaged in the process. So those lessons learned are certainly helping us.
We’re also working with them to identify how we might be able to share information with the Chinese in terms of training and development of their staffs to run their nuclear plants. And this is all – all one family. We’ve got all of these plants to operate successfully. I believe from talking to their leadership teams, they’re committed to making those plants run successfully and working with us and others that have significant experience in the nuclear industry to make sure that they all run as designed.
So that day-to-day interaction, we talk with the Shaw and Westinghouse team that’s over there on a daily basis to pull that information back to help us is all making our project more real for us. I think the lesson I took away is I visited the plant for my first time and saw the actual construction coming out of the ground. You know, the construction techniques that they’re using, they’ve got the modular assembly system where you put the module together and place those in the plant when they’re ready for those. A lot activity can take place at one time rather than just working on one particular area in the plant at a time. Multiple activities are taking place and you can see that process does work. They’re on schedule with putting those modules in place. So the realization for me is that this new construction methodology is in fact working, which eliminates one of the biggest concerns we’ve got of any potential delays or over runs as we get into that process.
Chris Ellinghaus – Wellington Shields
And in addition to the benefits that you guys have been getting from the recession on the escalation costs, have you done any sort of analysis or any thoughts on how this Chinese relationship is going to end up affecting your cost expectations?
Jimmy Addison
You know, in terms of trying to lower the cost, I don’t see what we’re going to learn there, it’s going to lower the cost we expect to spend –
Chris Ellinghaus – Wellington Shields
I’m just thinking in terms of avoidance of some of the problems that the Chinese has experienced, you know, is that going to end up affecting your escalation; your initial expectations for escalation maybe?
Kevin Marsh
No, I think it just gives us more confidence that the numbers we have are accurate and we can deliver the project within the estimated cost that we present to the commission. You know, all of the lessons learned, whether it’s an engineering issue or when they actually go through to construction or placing these units together, it’s gathered and shared with all of the parties and we’ve already made some changes in terms of our construction plans based on what we’ve seen. For example, when they started their initial construction, assembling the modules, all of that was done outside. We decided from a climate perspective, we built the building on site that will accommodate construction of those modules inside so we can continue to work when it’s raining and we have inclement weather. That will help us stay on schedule in terms of the timing of the work that needs to be done.
The position of some of the modules that are being constructed, they had some that they put together horizontally, then they had to right those and that put some stresses on some of the welds as a result. We’ll be completing our modules in the upright, vertical position so we don’t have to do those lifts that could put some stress on the welds in the project.
So all of those things that we learned, some are bigger than others, but combined together, it just gives us a higher degree of confidence that the plan we’ve got can be executed within the budget as long as we present it to the Commission.
Chris Ellinghaus – Wellington Shields
Great. Thanks a lot for the color. I appreciate it.
Jimmy Addison
And the timeframe, I would add.
Operator
(Operator Instructions) Your next question comes from the line of Jairo Chung with Oppenheimer and Company. Please Proceed.
Jairo Chung – Oppenheimer & Co.
Thank you. Hi, how are you?
Kevin Marsh
Good.
Jairo Chung – Oppenheimer & Co.
I just – I just want to make sure I understood it correctly, in terms of the equity forward sales when you say that it won’t, you know, start, you’re pushing it out to late 2011, does that mean it will trickle into 2012, or will it end in 2011 so we’ll see bigger chunks – chunk of that in the second half of ’11?
Kevin Marsh
Most like the latter part of ’11. I think we have the flexibility under the contract to move into very early 2012, but at this point I would say we’re most likely to take it down in late ’11.
Jairo Chung – Oppenheimer & Co.
Okay. And did you say it was –you guys are expecting about 90 million for the rest of the year and 150 million for 2011?
Kevin Marsh
That was the original plan, was to take down about 90 million by December of 2010 and the remaining 150 in mid-’11. And now we’ll be able to push almost all of that into a later ’11.
Jairo Chung – Oppenheimer & Co.
Okay. And then no changes to the program?
Kevin Marsh
No.
Jairo Chung – Oppenheimer & Co.
Okay. Fantastic. Thank you.
Kevin Marsh
Thank you.
Operator
And with no further questions, I would like to turn the conference over to Mr. Jimmy Addison for closing remarks.
Jimmy Addison
Well, thank you. And to summarize, we’ve had a very successful year this far and we’re optimistic about the remainder of the year. Our financing strategy is proceeding very well with the successful execution of the forward, the implementation of the tax gratitude and the completion of the expanded credit facility. We have successfully completed our retail electric rate case in South Carolina. In addition, our new nuclear project is proceeding on schedule with the BLRA functioning exactly as designed. We continue to seek core growth in our territory and I’m confident for our prospects of a positive year.
Thank you all very much for your interest in SCANA and have a great day.
Operator
Thank you for joining today’s conference. That concludes the presentation, you may now disconnect and have a great day.
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