Duke Energy Corporation (DUK) Q4 2011 Earnings Report, Transcript and Summary

Good afternoon, and welcome to Progress Energy's Fourth Quarter and Year-End 2011 Earnings Conference Call. [Operator Instructions] For opening remarks and introductions, I now turn the conference over to Beau Pratt of Progress Energy. Please go ahead.

Thank you, Roxanne. Good afternoon, and welcome, everyone. Joining me today are Bill Johnson, Chairman, President and Chief Executive Officer; Mark Mulhern, Chief Financial Officer; and other members of our senior management team. We are currently being webcast from our Investor Relations page at progress-energy.com/webcast where we've also included a set of slides, which accompany our speakers' prepared remarks this afternoon. Today, we will be making forward-looking statements, as well as reviewing historical information. There are numerous factors that may cause future actual results to differ materially from these statements, and we outlined these in our earnings release, Form 10-K, 10-Q and other SEC filings, as well as the risk factor discussion also found in our Forms 10-K and 10-Q. For your information, we plan to file our Form 10-K by the end of the month. This afternoon, following opening comments from Bill and Mark, we will open the phone lines to address your questions. Now, I'll turn the call over to Bill Johnson.

Thanks, Beau, and good afternoon, everyone. Thanks for being on the call. This morning, we released our fourth quarter and year-end financial results for 2011 and also provided a stand-alone ongoing guidance range for 2012. As you can see on Slide 3, I will open with a few comments on earnings and then update you on our merger status, Crystal River 3 and the Florida settlement agreement. I'll also point out our priority focus areas for 2012, and then Mark Mulhern will provide more details on our financial results and 2012 guidance. We thought it appropriate to give stand-alone guidance here, given that the targeted closing date for the merger is not until May or June at the earliest. Now if you turn to Slide 4 for the fourth quarter and year-end results. For the fourth quarter, we reported ongoing earnings of $114 million, compared to $133 million for the same quarter a year ago. Our earnings were down $0.06 per share. For the full year 2011, we reported ongoing earnings of $871 million, down $18 million from 2010. Our ongoing earnings per share were $2.95 compared to $3.06 per share for 2010. There were a number of moving parts and unusual items in the financials this year. You might recall our third quarter ongoing earnings including a negative $0.08 for the impact of storm costs and replacement power disallowances in the Carolinas, net of a positive litigation award related to spent fuel. And we're confident that our results did not fully reflect the true earnings power of this company or the solid groundwork our employees are laying for our strong future. And to that point, we're announcing a 2012 stand-alone guidance range of $3.10 to $3.25 per share of ongoing earnings. And in a moment, Mark will provide more perspective on our drivers for both 2011 and 2012. Turning to Slide 5. You'll see where we stand in terms of securing all the approvals for the Duke Progress merger announced early last year. Later this quarter, we expect to file our joint response to the Federal Energy Regulatory Commission addressing the issues in its mid-December ruling. We will file a summary of the mitigation plan first with the North Carolina Utilities Commission because of its 30-day notification requirement before we formally file with FERC. We expect to make the notice filing with the North Carolina Commission next week. And the merger closing date will ultimately depend on the timing of these regulatory approvals. The proposed FERC mitigation plan consists of permanent mitigation involving the construction of new transmission and the upgrade of existing transmission to improve the import capability into both the Duke and Progress control areas. We expect to file the details on this specific transmission projects, which will take approximately 3 years to build and, in total, cost up to about $100 million. In addition, we will propose a short-term bridge mitigation plan to cover the period while the transmission projects are being completed. This bridge mitigation plan will involve firm power sales to new market participants in sufficient size to address the screen failures FERC identified in its response to our last mitigation plan. We expect the cost to the combined company of these power sales will be determined as part of the FERC and state regulatory approval process. We believe this proposed mitigation plan is a response to the FERC's concerns, and we still believe in the value the merger will create for customers and shareholders. As noted on this slide, we also will make new Hart-Scott-Rodino filings with the Department of Justice, given that the initial filings expire in April, which is before we expect to close the merger. Next, turn to Slide 6. As we discussed on our January 23 call, we have entered into a settlement agreement in Florida that provides more certainty on cost recovery related to Crystal River 3 and the Levy nuclear project as well as more rate stability for the next several years. I'm not going to cover all the details on this slide and we've included it here, as a reference summary, of the key points. The Florida Public Service Commission will hold a hearing on the settlement agreement this Monday, the 20th. Commission staff will give its recommendation at that time and other interested parties will be able to address the commission as well. The commission is expected to issue a bench ruling on February 22. The different parties of the agreement worked in a constructive way to develop this fair comprehensive solution. We found common ground in our desire to ease the growing rate pressure on customers while providing a more predictable path forward. Meanwhile, at Crystal River 3, we are focused on getting the engineering analysis to a point that we have reliable cost and schedule estimates for repairing the containment structure. And we continue to work with NEIL, our insurance provider, for recovery of applicable repair costs and associated replacement power costs. We have not yet received the definitive determination from NEIL about our insurance coverage related to the March 2011 delamination, and our negotiations with NEIL continue. We believe that all applicable costs associated with bringing Crystal River 3 back into service are covered. In a minute, Mark will review the status of our spending and receivables related to CR3 and explain the change we have made in our accounting for these costs. I want to briefly review 4 areas of focus for our company in 2012 shown on Slide 7. These enterprise priorities are in addition to our daily emphasis on excelling in the fundamentals such as safety, operations and customer satisfaction. Our first priority is to continue to improve our nuclear performance. This year, we will build on the substantial progress we made last year in the performance of our nuclear fleet. In 2011, our 4 nuclear plants in the Carolinas had a combined capacity factor of 95.2%, which was among the top in the industry. And those 4 units, together, achieved an all-time generation record. Now we still have work to do to get our nuclear program to the consistently high level of performance we expect. And this year, we need to execute well in our 3 scheduled outages in the first half of the year. Our second priority is to accelerate Continuous Business Excellence, or what we call CBE. This is a systematic effort we began several years ago to analyze our work processes, improve efficiency and eliminate waste. It's a way to involve those closest to the work to help us be safer, better, faster and more cost-effective. And CBE, we'll be an important in helping us deliver on synergy opportunities in the merger. Third, optimize our balanced solution strategy. This is our ongoing effort to prepare for the future in the most responsible way, ensuring a diverse portfolio of assets and initiatives to meet our customers' needs and emerging public policies. Our extensive coal and gas fleet modernization is part of this balanced approach, and we continue to make good progress on these projects. And Mark will give you an update on these in a moment. Our fourth priority is to achieve effective integration planning and merger approvals. In partnership with Duke, we've done an excellent job of integration planning for the merger and we're on track with merger approvals until the FERC decision in mid-December. Given the extra time, we'll be even better prepared to operate as one company after the merger closes. The new organizational structure is designed and 3 levels of management have already been named. Let's now ask Mark to provide a little more detail on the financial results.

Thank you, Bill, and good afternoon, everyone. On Slide 8, I have some topics I'll cover today. Besides the 2011 financial results, I will review the drivers for our stand-alone ongoing earnings guidance range of $3.10, $3.25 per share. So if you'll turn to Slide 9, several highlights for 2011. Our 2011 ongoing earnings were slightly below our guidance, but keep in mind that this number includes the unusual $0.08 charge for replacement power disallowances in the Carolinas. Much of the work on crafting the comprehensive rate settlement in Florida began in 2011. And if approved, this settlement will give us a period of regulatory certainty and stability through 2016. Besides the regulatory certainty and the rate stability for our customers, it also permits greater flexibility in the usage of cost of removal amortization in the years after 2012. And finally, with the strong surge last year in utility stocks and the positive reception to the merger with Duke Energy, we posted a total shareholder return of 36.4% in 2011. So now I'll turn to Slide 10, which presents the results for the fourth quarter and the full year of 2011 compared to 2010. The Carolinas were down sharply in the fourth quarter, primarily due to unfavorable weather as we experienced 30% lower heating degree days compared to that same period in 2010. That negativity resulted in $0.10 of lower earnings. Florida posted a positive increase for the quarter, primarily due to lower O&M expenses. And this was partially offset by 71% lower heating degree days as Florida's weather was significantly milder in the quarter compared to 2010. So for the full year, weather was the key negative driver in both the Carolinas and Florida. Weather contributed to a $0.22 decline in the Carolinas and $0.23 in Florida. In Florida, the greater use of the cost removal amortization was a key offset compared to 2010. I flip to Slide 11. Slide 11 is our waterfall for the quarter. And as I mentioned, lower O&M and increased use of cost removal amortization were the positives for the quarter, but significant weather impacts and reduced wholesale revenues offset those positives. On Slide 12, we show the ongoing EPS drivers for the full year. So the 2 biggest drivers were approximately $0.31, or $250 million, of cost removal amortization in Florida and the $0.45 negative impact of mild weather compared to 2010. And as I discussed in detail on our third quarter call, we had several adjustments, which netted to the $0.08 negative impact on the bottom line, which again primarily reflects a disallowance of replacement power costs resulted from extended outages at the Robinson Nuclear Plant in 2010. Slide 13, we've given you the retail sales data, so it presents the actual and weather-normalized retail energy sales for 2011 compared to 2010. You see here Florida recorded a 0.6% increase in growth and usage against the forecast of 0.7%. Carolinas ended the year with a negative 0.9% against the forecast of a positive 0.8%. So as noted previously, both jurisdictions were strongly impacted by weather during 2011 compared to 2010. Slide 14 gives you our growth and usage information and the low usage residential customer information that we traditionally give you. It appears the Carolinas have finally established a bottom, and we're starting to see some hopeful signs in the local economy. So far, in 2012, it appears weather-normalized sales are showing positive trends, and in Florida the customer growth is also showing some stability. As you'll see in a minute, our 2012 guidance has assumed a 1.5% increase in kilowatt hour sales at PEC and a 0.4% decrease in kilowatt hour sales at PEF, so roughly about a 1% increase if you net the 2 of those. The optimism at PEC is based on projected new customer additions of 10,000 in 2012 versus approximately 6,000 new customers added in 2011. Our commercial and industrial sectors are seeing some early encouraging signs of new building and business expansion, and the key area of the military base's related construction continues to be an important sector for Progress Energy Carolinas. On Slide 15 show the details on the Crystal River Unit 3 nuclear outage, so the cost in recovery that Bill referred to. The comprehensive settlement agreement we filed last month provides the regulatory recovery framework with regard to Crystal River 3. So we are continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs. And we have not yet received a definitive determination from NEIL about the insurance coverage related to the second delamination. In addition, no replacement power reimbursements were received from NEIL in the second half of 2011. These considerations led us to conclude that as of December 31, 2011, it was not probable that NEIL would voluntarily pay the full coverage amounts we believe they owe under the applicable insurance policies. Given the circumstances, the accounting standards require full recovery to be probable to recognize an insurance receivable. Therefore, we have suspended recording any further insurance receivables from NEIL and reclassified the $222 million NEIL receivable associated with the second delamination. So we recorded a corresponding $154 million addition to our deferred fuel regulatory asset and a $68 million addition to construction work in-progress. So our negotiations continue with NEIL regarding coverage associated with the second delamination, and we continue to believe that all applicable costs associated with bringing CR3 back into service are covered under the insurance policies. Going to Slide 16 and going through the 2012 ongoing EPS drivers that support our 2012 ongoing guidance range of $3.10 to $3.25. I start with a consideration of the net $0.08 of the identified items from the third quarter, so I start with a $3.03 number. And the adjustments from there are $0.08 of above normal weather, so we basically reconcile to normal weather. We expect $0.09 of growth and usage between the 2 jurisdictions, another $0.09 from increased wholesale sales in both jurisdictions and the wholesale increase actually results from contracted sales and reflects a significant boost in our wholesale business in 2012. We'll see another boost in 2013 in the Carolinas as a new full requirements contract with North Carolina Electric Membership Corporation begins. In '12, we will also get a pickup from AFUDC equity resulting primarily from our new combined cycle gas plants that are under construction. Also, we will benefit from increased transmission revenues from our OATT tariffs and higher cost recoveries in both jurisdictions. Pension expense is expected to be approximately $0.04 higher in 2012 versus 2011 due to lower discount rates and investment returns below the projected rates. Higher depreciation expense and share dilution will also be negative offsets in 2012. If you take step back and look at the picture in summary, the earning range -- the earnings range for 2012 is supported by visible drivers that I've highlighted here, and we have some information in the Appendix to help support those as well, but also the flexibility we had in the cost removal amortization in Florida and our ability to manage the overall O&M costs of the company. Just a little more granularity on Slide 17 in the wholesale base revenues, that Slide 17 graphically illustrates the pickup in revenues that Progress Energy Carolinas and Florida from new contracts. The city of Fayetteville will start its contract in mid-year, and Florida will add a new contract with Seminole Electric this year for 150 megawatts. Slide 18 just gives you our rate base growth. So it just shows you the rate base growth through 2014. Carolinas is obviously benefiting from the scheduled completion of the 2 combined cycle natural gas plants, one in early 2013 and the second one in late 2013. Florida's growth is driven primarily by construction projects at CR3 and continued steady investment in transmission. On Slide 19, we presented the status of the major construction projects that are underway. The Lee plant and Smart Grid programs are approximately 70% complete and both are on track for a timely completion within the next year. The capital expenditures page does not include any costs related to the CR3 containment repair or the CR3 upgrade work. On Slide 20, the projected capital expenditures, on a consolidated basis through 2012 through '14, shows you that expenditures are basically flat over the period, totaling approximately $2 billion per year. There is an increasing amount of environmental capital budgeted. The early years reflected significant investments in a 0 liquid discharge project at our Mayo coal plant, and the increase in 2014 relates to early estimates on mercury compliance work at our Carolina coal plants. Given the pending merger with Duke, we would expect to provide further estimates for the various proposed EPA rules as a combined entity when appropriate. Slide 21 gives you the projected cash flow. The increase in operating cash flow reflects expected receipts from NEIL for replacement power and the timing of fuel recoveries through the fuel adjustment costs. It also reflects $175 million pension contribution in 2012, which is down from the $334 million we contributed in 2011. On Slide 22, our financing plan is shown there. We have refinancing at the corporate level and for each utility, so Progress Energy Carolinas is expected to raise an incremental $750 million to support the completion of the Lee and Sutton combined cycle units. The financing needs in Florida will be determined after a course of action on the Crystal River plant repairs is decided. So I won't review the slides, but in the Appendix of the presentation, there is additional forecasted information that we'll be happy to discuss with you if you have questions. So I realize I covered that material quickly and expect to have some detailed follow-up questions that Investor Relations will help you get answers to. But overall, we've had a very solid 2012 stand-alone plan, but we also have great flexibility around a May-June merger closing, which should allow us to demonstrate the significant financial benefits of our merger with Duke very quickly. Now I'll turn it back to Bill for questions.

Thanks, Mark. Now I'll ask the operator to open the line so we can get to your questions.

[Operator Instructions] We'll go first to Jonathan Arnold with Deutsche Bank.

From the -- you just made a comment that in the cash flow forecast, it includes NEIL recover -- replacement power insurance receipts. So is that based on this $55 million number that you've showed in the update on the NEIL insurance situation generally, or it's some other number?

No, it's a bigger number than that, Jonathan. So 2 things in there that I'd say. You know that starting adjusted cash flow number that you look at on Slide 21 that shows about $500 million or $600 million increase from '11 to '12 is really split in 2, so about 1/2 of it is catching up to the full amount, so the $490 million limit on replacement power from NEIL it paid us $162 million or so of that. The remainder to that we would expect to receive at some point here and hopefully in 2012. And the rest of that is actually in the fuel rates for customers. So if you remember, we had expected Crystal River 3 to come back in service in 2011 so we had some catch-up to do through our fuel adjustment clause that's actually in the customer rates currently. So those are the 2 factors that would drive that variance.

So the NEIL piece is the difference between $490 million and $162 million?

Correct.

And is there anything in this cash flow forecast for repair costs?

No.

Does that extend to the CapEx or something?

No, no, no.

Okay. And then if I may on a second topic. When you think about the merger proposal you had with the states and with FERC and the joint dispatch agreement savings, which had a pretty defined dollar amount around them, to what extent is that a different number now that we have much lower fuel costs in the market? And then how do you see that discussion with the states going in terms of maybe making up for some of that in other ways? Just give us some way of thinking about that back and forth.

Jonathan, this is Bill -- excuse me, I think the only thing we can say there is that we are in settlement agreements with both those states and promising them the benefits of joint dispatch in fuel. You've pointed out the elements of that have moved around a little, and so we're looking at what elements are. But at the moment, where we are is that we are on the record with those folks.

Can you give us a bit of a sense of what a little might be, Bill?

No, no. I'm just say things change everyday in the business. Fuel prices change, coal usage goes up or goes down, so variables change. But no, I can't give you any more specifics than that.

We'll go next to Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: I guess kind of my first question just on the NEIL process. You said these negotiations are going on, but you're not recognizing recovery of more fuel costs. What is the actual process between negotiation and some form of litigation to try and resolve what you guys incurred relative to what they're willing to pay?

Yes, let me try that one. So we are in a process with them on the biggest and most complex claim they've ever had and they've had a lot of questions, and we've had a lot of discussion. And so I will say we have not approached the second part of your question is what is the dispute resolution mechanism because we're not at a dispute yet. There is a requirement for some form of voluntary dispute resolution in the policy, but that's not where we are at the moment. We're still working positively and engaged with them on explaining what happened, what the repair plan is and to make sure that it's covered. Dan Eggers - Crédit Suisse AG, Research Division: Is there a feel for -- is it a technical issue they're having a challenge with? Or what is going to be the process to get to a maybe pass this negotiation point to either your resolution or having to go to the dispute resolutions side of the option?

I think I said in the call in January when we talked about the settlement is that one of the -- there are 2 paths here: One is the completion of the design and repair selection work; and the other is continuing with NEIL to a resolution. Those passes are linked, right, because the repair option from their perspective has to be within the terms of the policy. And so until we get to that final decision on those things, I don't think we'll get to a final resolution. And then I would hope sometime in the mid-second quarter that's a process that we'd get to. Dan Eggers - Crédit Suisse AG, Research Division: Okay, and I guess, Mark, maybe just kind of help resolve the 2011 results. You guys obviously came below the range because of the $0.08 Carolinas fuel refusal but you also had $0.08 of better-than-normal weather, but you still fell out of the range. Is there anything else that meaningfully varied from expectations or some sort of cost structure reset that did or did not happen that caused that number to be lower than planned when you guys started the year?

Yes, Dan, I would point to 2 things. You knew -- already put your finger on the weather, but the second one is when you look at the complete year waterfall chart on Slide 12, you see $0.15 of wholesale. I think in our original forecast for the year, we've probably had a negative $0.07 or $0.08 so we're probably $0.06, $0.07, $0.08 higher in negativity in wholesale than we projected in the beginning of the year. And some of that relates to low off system sales opportunities given the prices of commodities, so very low off system sales compared to what we had forecasted. And then we also had some impact of these fuel disallowances on our wholesale customers. So some of that added to that. And then the only other thing I'd say is we did expect a bigger contribution from O&M, so on that same slide on Slide 12 you see a $0.13 positive for O&M. We actually had in our original forecast, if you'll remember, it had about $0.25 of positive that we thought was going to show up in O&M in 2011 because we had known [indiscernible] outages from nuclear. But there were a couple of items that I would point to that would say why we didn't get all the way to the $0.25 and they would be primarily related to we had a Robinson Nuclear Recovery plan that we helped fund for the year so we needed to do some things there to get the performance at the Robinson plant back on track, which has been successful here so that cost us some money. We also accelerated some vegetation management expenditures at both utilities. So I would kind of point to those items as contributing to not getting all the way to the positive variance in O&M. Dan Eggers - Crédit Suisse AG, Research Division: Now the miss in O&M or the shortfall in O&M, does that reverse in the '12 numbers? I don't know that I see a line note, which is showing that reverse explicitly or is that just kind of missed opportunity to say it pulled some costs out?

Yes, what I would say about the '12 O&M numbers, Dan, to your point, it's not on the chart because obviously we've got outages, so we've got nuclear outages that are going to raise up some of the O&M expenditures in '12 compared to '11 and then we've got some, Bill referred to it earlier, some efficiency and some cost management efforts that we're doing. You see we have the pension number on there, a little higher number in '12 versus '11. And then the only other thing I'd point to is we do have -- we're having some significant attrition. Obviously, we're going into the merger so we're probably down headcount-wise about 250 positions year-to-year. So that will help offset some of that higher nuclear O&M in '12.

We'll go next to Ashar Khan with Visium Asset Management.

Can I just go back, this mitigation plan, which you're going to file, can I just understand it better? So what you're proposing is that you're going to build some transmission lines and could you just tell us what that does to, I guess, alleviate FERCs problems that they had with initial filing?

Yes, one of the tried-and-true methods of mitigating market power at FERC is the creation of new transmission paths that bring greater import capacity into the market. So to think about real simply, that you've increased the size of the market, so that your concentration of generation is less than it was. That's the simplest way to think about it, I think.

Okay. So where's -- where are you going to build a transmission in which areas? Could you just a little bit more elaborate to increasing...

I think we would prefer to file that with the regulators first and then talk about it.

But we do expect, Ashar, to give some detail to those projects, but we're not -- we will do -- we will lay that out in a regulatory filing here very shortly.

Okay, in a week's time, okay. And then Mark, I guess I was just doing a "back of an envelope" calculation based on what you have come out with your guidance today and what Duke has come out with their guidance today. I guess, if one just mathematically put those numbers the midpoint of the ranges, it implies that you need something like $250 million in O&M or synergies to be accretive. Is that -- am I in the right ballpark? Is that what was anticipated when you kind of came out and said that the margin was going to be accretive in the first year, last year, 12 months ago?

Ashar, what I would say is it probably had a number of factors in that analysis, right? So we both have had, excuse me, rate proceedings, both some that have gotten concluded, some that have gotten proposed. We got a Florida settlement. Duke's had a rate case resolved in the Carolinas. We got one coming up. So I wouldn't attribute it all to that very simplified math equation.

But the deal is still expected, though this was going to be the first year, right, after the merger if everything had gone smoothly. But there's nothing changed, is that correct? That the deal would still be accretive, the first full year which would have been 2012?

Yes. And here's how I look at it, Ashar. I mean obviously, things have moved around here and we're developing a lot of different things related to getting the approvals done and timing. So I actually will look probably that -- I would describe 2013 is the first full year of measurement here and I don't believe anything has changed from what we were looking at, at the time we entered into the transaction.

We'll go next to Paul Patterson with Glenrock Associates.

I wanted to ask you guys just to sort of follow-up on Jonathan Arnold's question on the joint dispatch savings. Does this mitigation -- I know that he was talking about fuel, I think. But just in general, does this mitigation, this revised mitigation plan at FERC, do you expect to it -- for it to change the joint dispatch savings that you guys were contemplating previously?

We're not quite done with all the analysis around that. But based on what we know today, the mitigation plans shouldn't change that.

Okay, so -- okay. And then with respect to the wholesale upside in 2013, could you guys give us a little bit of -- I'm sorry if I missed it, sort of quantify what the financial impact of these -- all these contracts that are moving around would be?

I'm staring at Drennan, Paul, just because I -- we made an announcement when we signed this extension, so there's a new, I can't remember it if it's 1,000 megawatts, something like it will grow to 1,000 megawatts of new load with NCEMC over a period of years. You're probably best off calling him after this call. So we really haven't given those numbers out for '13 just because it's further out in time.

Okay, and then just on Slide 25, the weather, you guys broke it down sort of nicely, so the weather adjusted but I'm just sort of wondering sort of what's going on here? I mean it looks a little volatile, I guess, in the Carolinas and it looks I mean, aside from, I guess, what happened in 2011, it kind of looks pretty dismal still in Florida. So just was wondering if you could share with us sort of what's the tale of 2 cities, I guess, or whatever the story is.

Yes, to give a little color on both utilities, I think that, that's right. In the Carolinas, you've seen those numbers are jumping around a little bit. Growth is an important element to us. New customer growth in Carolinas is important. So if you look at that 1.5%, I would say about 1% or maybe a little less than 1% of that is related to this assumption that we're going to have 10,000 new customers added in 2012. You're right, the numbers are bumped around here. You see that 2% number that happened between '09 and '10 and so there's a little bit of volatility here and I think some of it's economic driven, so the state of the economy, unemployment rates, just business activity in general. But I do think we are seeing some signs in the Carolinas. We've got a couple of major industrial announcements, kind of selected this site in South Carolina. So there'll be some momentum around some of this expansion that will help us in the Carolinas. And Carolinas has got a -- also has, as I mentioned, the military base expansion at Camp Lejeune and Fort Bragg have been significant for us just around the peripherals, so not only just the basics expansion but the peripheral around commercial activity and housing activity to support that expansion has been significant. So those are the 2 things I'd point to in the Carolinas. In Florida, we don't really have any industrial base to speak of in Florida. It's really a commercial and residential story. And the story in Florida, a lot has to do with housing and the only point I'd make with respect to the financial impact to that, in Florida we do have some flexibility around this cost of removal element that we don't have in Carolinas. So we've been able to kind of manage some of the negativity in Florida, again, as we believe the economy will continue to recover slowly over an extended period of time.

Okay, and just -- that's very helpful, but just in general, just sort of elasticity or usage per customer, have you seen any trends there in terms of either efficiency or elasticity that you've seen? I mean, I guess primarily the commercial and residential customers that -- I don't know...

We have, we have. I would say that our forecasting guys would attribute maybe 2/10, 3/10 of a percent of negativities related to our demand-side management and energy efficiency programs potentially, something like those numbers. So I wouldn't call it overly significant, but when you're talking these numbers, maybe it is.

We will go next to Brian Chin with Citi.

Going back to the merger and the bridge mitigation plan, can you provide any precedents in which FERC has approved a bridge mitigation plan such that it will alleviate market power concerns once the lines are completed, like any time were they've given approval of that before the lines have been completed?

I think there is. We have certainly studied the FERC precedent and all mitigation plans hard over the last month or so. And we think that what we're proposing here is squarely within their precedent. I can't give you the citations now, but I think when we file, you will find them listed there.

And the only thing I'd add, Brian, is if you look at the response we got to our last mitigation plan, we got some very specific feedback from FERC about firm power sales and control, about interested buyers that would take the product, about conditions around what we'd ascribe to that. So I actually think when you see this, you will go through a checklist of things that were pointed out in that filing and meet the -- the short-term bridge mitigation plan would meet those requirements.

Okay, great. And then a second question, I know that your timeline has coincided pretty well with what Jim said on the Duke call. But in between the calls, I guess we picked up a little news headline that said the FERC decided against revising its policy in U.S. utility mergers. Just any sort of updated thoughts on that, how does that affect your timeline, if any, given that they're now not going to be changing their definition of market power?

I don't think it affects it at all. They've sort of defined what they mean in our case, by their prior orders and so we're just sticking to what they've said. But I don't think that announcement changes anything significant for us.

Okay. And then last question, going back to the bridge mitigation plan. What happens if it takes longer than expected to site the transmission lines? Is there any sort of contingent fee on the approvals that could be given or how would that work?

I think you're a little ahead of our thinking on that question, Brian. But we do know that you can't go in with a mitigation plan that promises to have transmission there later. So the transmission has to show up before you can take credit for it. So you have to figure out how long the mitigated bridge last before you get the transmission built.

We will go next to Greg Gordon with ISI Group.

Mark, I apologize, I dialed in a little bit late. Can you explain again what's going on with NEIL and with the reclassification of the $222 million from receivable to deferred fuel regulatory asset?

Yes, I'm going take you to your CPA course for a minute because when you record insurance receivables, the probability standard is a high bar. You have to be confident that you can collect 100% of that receivable and convince yourselves and then your outside auditors that, that's affordable. So what we've done here is be given our pending Florida regulatory settlement. We still -- we have not changed our opinion about the collectibility of these dollars from NEIL. But for accounting purposes, we have re-classed what was in receivables from NEIL effectively to a regulatory asset for the replacement power piece and into construction work-in-progress for the repair piece.

Okay, but these are all related to the first delamination event, correct? Or are these dollars related to the first and the second?

No, no. They would be related to the second one, Greg, because on the first delamination, we've actually received proceeds.

Okay, so this money is specifically and solely related to the second delam?

Correct.

At what point in this process of thinking about or negotiating with or arbitrating with NEIL do we start to hear what your sort of cost-benefit analysis is on whether it's even the right decision to repair the plant in lieu of an alternative like a gas plant with sort of the C change we've had in the structural cost of gas? Is it -- is there a scenario where we ultimately -- you've already taken the rate base essentially out of the, at least temporarily, out of the Florida rates? At what point do we know whether you're actually going to rebuild this plant or build a gas plant?

So Greg, the settlement gives us clarity on the regulatory path for that decision, right? It lays out a framework for repair and lays out a framework for retirement and that's a fairly straightforward analysis, which is what the benefit to the customer is over the life of the asset compared to alternatives. And so to get to the definitive sort of conclusion you've described, we have to get to a higher level of engineering completion and understanding on the repair options, so that when you make the judgment you've described you have a good basis for doing it. And I said I think sometime in the second quarter, we'll be at that spot. We'll have a good number and we will do that analysis. We have done it on the back of the envelope. We actually did it last summer when we made a filing with the Commission, but will do that in detail once we have a number that we think is reliable and realistic.

Okay, and is that decision dependent on, or independent of, whether the event qualifies for insurance recovery?

I think the answer to that question depends. I don't think we can answer that question today until we have more certainty about both of the variables we're discussing here.

Yes, I guess what I'm wondering is it may or may not -- let's assume that's it's a fully covered event. It may still be in the best interest of the customer and the shareholder to use the proceeds to build a gas plant. Is that a reasonable or unreasonable statement? As one of many scenarios.

It is feasible to say -- you could theorize, let's say this, that even with full recovery you had options that were cheaper for the customer.

That's my point. That's what I'm asking you.

Yes, I think that's exceptionally unlikely. Yes, I think that's very unlikely. But we have to get to a better number -- not a better, a more refined and complete number on what the repair costs before we can do that calculation.

We'll go next to Michael Lapides with Goldman Sachs.

Just I want to make sure I follow something and I apologize for staying on Crystal River 3 a little bit here. But when we look at your capital spending for the year, if we had to think about what your net capital spending would be including Crystal River and backing out recoveries that are Crystal River related, how different is it from what's being shown on the slide? I'm struggling a little bit to true up one versus the other, meaning comparing Slide 20 to what real CapEx would be if you include some Crystal River CapEx as part of what's happening in incremental to what's on Slide 20?

Well, Michael, here's what I would say. What we have, so far, are public estimate around repair at Crystal River 3 is $900 million to $1.3 billion. As Bill said, we're doing engineering work and working with EPC folks to nail that down and make sure that we fully understand the costs related to that. We believe that, that those dollars are recoverable through insurance. So the way I would think about this and the reason they're not on this slide is: Number one, I don't know the timing of when we will actually execute those repairs and how those dollars will flow through this schedule. Number two, I believe I don't know with certainty how those dollars would be recovered in the timing of that recovery. So that's the reason they're not on here. You could imagine whatever you want and add them to these pages, but I would net them against whatever the assumed collection would be.

Historically, when a company had to go to NEIL for recovery of spend on a nuclear plant that had an unplanned outage or had an incident, even spending much, much smaller than this, how much of a lag was there between the time of capital spend on the plant and the time of actual cash inflow from NEIL?

We can't answer that precisely, but it takes months in the best of cases because they always do an analysis. They have their own internal processes so it is not an immediate kind of payment system. It takes months.

Got it. Last item, O&M, can you talk a little bit about what you're doing? Really, it seems like it's more Florida than the Carolinas in terms of O&M management, meaning where did the reductions that you'd gotten to in 2011, that you expect a little bit in '12 and beyond come from?

Well, Michael, the recent history we have had and this is just I think a cyclical thing that happens to everybody is we've had some operational challenges in both nuclear and fossil that we had driven our O&M costs up in 2011 and 2010 and then obviously the timing of outages and how we manage those processes are important to us. But across-the-board, we have been managing costs, trying to be more efficient, do things with less people and less spending, so I think we got the opportunity and I think obviously, realistically, we got 2 things happening in front of us. We've got a pending merger that we're obviously looking to gain efficiencies out of. We probably have the best real time benchmarking that you could get. In other words, we're looking down the navel of each other's operation, 2 very good strong companies that operate their fleets extremely well and we've gotten the benefit of looking at how they do things, and they've gotten the benefit of how we do things. I think we have tremendous opportunities going forward to improve our operations across-the-board and obviously reduce cost and do things as well as we can do them. So I think that's how I would really think about that going forward.

And is that dependent on the merger or is that something you could do independent? Meaning, you're not depending on cost synergies -- solely on merger cost synergies to actually kind of reap some efficiencies?

No, I think it's mixed, Michael. I'd say there are a number of things that we've identified that we absolutely can do on our own better and save money and be more efficient, but there are also some things of economies of scale and supply chain is one example. Our ability to access and be -- and get competitive pricing just mushrooms when we're a combined company.

We'll go next to Raymond Leung with Goldman Sachs.

Mark, just a quick question on financing. I think it's pretty straightforward about the utilities, but can you talk a little bit about what you're thinking at the holding company? I think there's an upcoming maturity. I think there was some thought process and maybe you just use your bank line but with the delay of the merger, does that sort of change your thought process, maybe coming with the bond deal?

It does. We've got a maturity coming due at holdco that we will look to refinance. Ideally, what our plan was, going into the merger, was we would not do any more Progress Energy holding company, that it would be done at the Duke level. But given where we are and timing, we felt and we've been obviously working with the Duke folks on this as well, we thought it was appropriate to go ahead and refinance the holding company maturity that comes due so we will ultimately get to that.

Okay, so you'll probably do a bond deal, is it? I'm sorry.

Yes, that's how it would -- that would -- I think that would be right.

Okay, and could you remind us what the -- for capital spending, just Crystal River uprate cost, what that would be?

Looking around the room here, some of it we've already spent, we've got more to do and it'll likely be in the tail end of this so I'm thinking while we're deciding on repairs that EPU stuff will probably be pushed out a little bit in time, is the way I would think about it. But I'll get you those numbers -- I'm looking about it, we'll get you that number.

Okay, and the last thing is just on the transmission mitigation issue in terms of those expenditures. They're not built into those current CapEx budget, correct?

Correct.

We'll go next to Kunal [ph] Patel with Wells Fargo.

I had a quick question, hopefully it's quick. There have been a couple of media reports done and more Florida local media about a third delamination. Could you elaborate or explain or quell that rumor?

Let me explain. That building, which has now been delaminated and is still tensioned in large part had some minor continuing cracking. This is not something that is unexpected or worrisome. But yes, there have been some other things, but not of the magnitude of the one from last March.

So in that case, will this qualify as a third incident in your request with NEIL?

I don't think so. I think what we're going about is sort of the global repair of the entire building and how that fits into the policy, so I don't think this changes anything one way or the other.

There are no further questions at this time. Mr. Johnson, I'd like to turn the conference back to you for any additional or closing remarks.

Great. Well, thanks for being on the call. We appreciate your interest, and we'll see you next quarter. Thanks.