Duke Energy Corporation (DUK) Q2 2010 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to the Duke Energy Second Quarter Earnings Conference Call. [Operator Instructions] At this time for opening remarks, I would like to turn the call over to Mr. Stephen De May, Senior Vice President of Investor Relations and Treasurer. Please go ahead, sir.

Thank you. Good morning, everyone, and welcome to Duke Energy's second quarter 2010 earnings review. Leading our discussion today are Jim Rogers, Chairman, President and Chief Executive Officer; and Lynn Good, Group Executive and Chief Financial Officer. Jim and Lynn will begin the call with prepared remarks that review our second quarter results and discuss the outlook for the remainder of 2010, and then we will open the lines to your questions. Note that the appendix to the presentation materials includes additional disclosures to help you analyze the company's performance. Today's discussion will include forward-looking information and the use of non-GAAP financial measures. You should refer to the information in our 2009 10-K and other SEC filings concerning factors that could cause future results to differ from this forward-looking information. A reconciliation of non-GAAP financial measures can be found on our website and in today's materials. With that, I'll turn the call over to Jim Rogers.

Thank you, Stephen. Good morning, everyone, and thank you, all, for joining us today. We appreciate your interest and investment in Duke Energy. I'll start with the bottom line for the quarter. It was an excellent quarter. The economy is showing signs of improvement, the weather was hot and our team's performance was excellent. As you saw in our news release this morning, we announced adjusted diluted earnings per share of $0.34 for the second quarter of 2010 versus $0.26 for the second quarter of 2009. This is a quarter-over-quarter increase of around 31%. On a weather-normalized basis, the quarter-over-quarter increase was approximately 20%. Our reported results for second quarter 2010 also included non-cash charges of $500 million, reflecting the write off of the remaining goodwill related our Midwest non-regulated generation fleet and the $160 million related to the impairment of certain non-regulated unscrubbed units in the Midwest. Lynn will discuss these charges in more detail during her presentation, and I will update you in a few moments on pending environmental regulations. These charges resulted in reported diluted net loss per share for second quarter 2010 of $0.17 compared to reported diluted earnings per share of $0.21 for the second quarter '09. Let me highlight three of the more significant drivers of our results this quarter: First, higher revenues from our base rate increases approved in '09 in North Carolina, South Carolina, Ohio and Kentucky; second, favorable weather. We experienced above normal temperatures in all five of our regulated jurisdictions during the second quarter, and in the Carolinas, we experienced the hottest June on record; third, signs of economic recovery. During the quarter, we realized increased weather-normalized sales volumes, mostly due to improved industrial sales. We will continue to remain cautiously optimistic about the future. Lynn will provide more color around sales volumes and our outlook for the latter half of 2010 in her presentation. I want to highlight that our employees delivered excellent performance to the unusually hot weather. Our year-to-date nuclear capacity was over 95%. Similarly, our fossil fleet had a commercial availability of approximately 87% on a year-to-date basis. In the latest J.D. Power and Associates annual customer satisfaction survey, Duke Energy Carolina has ranked number one in the South. This demonstrates our commitment to providing outstanding customer service. Our strong operational performance in the first half of the year has us on target to achieve our operational metrics for 2010. Based upon our results today, supported by favorable weather and stronger-than-expected weather-normalized retail volumes, we are increasing our 2010 adjusted diluted EPS outlook range from $1.25 to $1.30 per share to $1.30 to $1.35 per share. Before I turn the call over to Lynn, I want to say that I am very pleased with where we are through June 2010, and I'm very proud of the performance of our employees who have remained focused on our objective to safely provide low-cost electric and gas services to our customers, while earning reasonable returns for our investors. Let me now ask Lynn to provide more details around our second quarter results.

Thank you, Jim, and thank you for joining us. Let me begin with an overview of our financial performance. As you can see in the table on Slide 4, our total adjusted segment EBIT increased approximately $175 million when compared with the second quarter of last year. The results for all of our business segments taken as a whole were higher than our expectations, principally driven by favorable weather and strong industrial sales. The competitive environment in Ohio continues to be challenging, but we have been successful in executing in our plans to defend margins in that business. Let me quickly review the significant drivers of results of each of our business segments. Adjusted segment EBIT for U.S. Franchised Electric & Gas, our largest segment, increased $171 million over the prior-year quarter. Approximately $70 million of this increase was due to the impact of rate increases in the Carolinas approved in 2009. These rate increases reflect the recovery of prudently-incurred utility investments and will continue to positively impact results in future periods. Another $56 million was the result of unusually warm weather. Weather impacts way driven by above-normal temperatures in all five of our service territories throughout the quarter. In the Carolinas and Midwest, cooling degree days were approximately 50% above normal. Other positive drivers to the segment's results were higher allowance for funds used during construction from Duke Energy's ongoing construction program and increased weather-adjusted volumes, most notably in the industrial sector. Partially offsetting the increases to the segment's adjusted EBIT were higher operation and maintenance costs, primarily due to the timing of planned outages. And in our Commercial Power segment, customer switching and competition continue to highlight the market in Ohio, resulting in lower adjusted EBIT of approximately $25 million versus the second quarter of 2009. Despite lower results, to date, Duke Energy Retail Sales, our competitive retail arm, has acquired approximately 60% of Duke Energy Ohio's switch customers. Other drivers affected Commercial Powers' results as well. These included higher O&M costs resulting from an arbitration decision, lower gains from coal sales and a 2009 deferral of operation and maintenance costs to the Beckjord plant under our Electric Security Plan. Offsetting these drivers were favorable PJM capacity payments earned by our Midwest gas assets. In fact, we continue to be pleased with the performance of our Midwest gas-fired fleet, which for 2010 is on track to exceed the level of adjusted segment EBIT which was experienced in 2009, driven not only by increased capacity payments but also by higher energy margins. Now let me take a few moments to discuss the non-cash impairment charges related to goodwill and certain unscrubbed units in Ohio. You will recall that similar charges were recorded in the third quarter of 2009 as a result of depressed current and forward power prices, and reduced customer load due to the recession. Customer switching has also continued to increase from approximately 30% at September 30, 2009, to approximately 56% at June 30, 2010. As well, power prices are projected to remain low through the next several years impacting our evaluation of possible outcomes from our upcoming ESP extension in Ohio. In addition, we have more clarity around proposed environmental regulations from the EPA, and expect further environmental regulations in 2011 on hazardous air pollutants such as mercury, as well as more stringent air quality standards. Although not yet issued a final form, these regulations are expected to result in significant capital and O&M expenditures for the affected coal-fired generation plants or the shutdown of certain units. In light of these uncertainties, we wrote off the remaining amount of goodwill associated with the non-regulated Ohio generation, and recorded impairment charges related to certain unscrubbed coal units in Ohio. These impairments are non-cash charges and do not impact our liquidity or compliance with any of our debt or credit facilities. These charges totaled $660 million. Returning now to a review of our segment drivers, adjusted segment EBIT for international increased $32 million over second quarter 2009. The primary drivers of this increase include favorable foreign exchange rates, favorable hydrology in Brazil and an increased contribution from National Methanol, principally due to higher commodity prices. Finally, two additional drivers impacted our overall results. The first was an increase in interest expense of approximately $26 million due to higher debt balances resulting from planned financing of our capital expansion program. The second positive driver was a decrease in the adjusted effective tax rate from 36% in the second quarter of 2009 to 32% this year. We are still targeting a 31% effective tax rate for 2010, excluding the effect of the goodwill impairment charge, which is non-deductible for tax purposes. For detailed quarter-over-quarter drivers for each of our segments, please refer to the appendix. As Jim and I previously mentioned, weather was a significant contributor to our results for the second quarter. But more importantly, the quarter also saw positive trends in weather-normalized sales, most notably to our industrial class of customers. For the second quarter in a row, we experienced an increase in overall sales volumes compared to the same periods in 2009. Our weather-normalized electric volumes rose approximately 3.6% this quarter, primarily driven by increased industrial sales activity. On a weather-normalized basis, commercial volumes were essentially flat, which we attribute to the fact that this class tends to lag the overall economy. In the residential sector, traditionally a very stable class, normalized volumes were also flat compared to the second quarter of 2009. On a year-to-date basis, Residential volumes are up approximately 1% over 2009. We are still seeing modest residential customer growth in both the Carolinas and the Midwest, and we remain optimistic that residential customer sales will see growth in the future. Although we are pleased by these volume trends, we must carefully consider how to factor them into our outlook. As we entered 2010, you will recall that we expected a slow economic recovery and forecasted overall weather-normalized load growth to be flat to 2009. We had a good reason to feel that way. Our largest industrial customers were cautious in their outlooks, and the unemployment rate in each of our state jurisdictions had climbed to levels that did not support historical levels of sales growth. Despite improved sales for each of the last two quarters, certain macroeconomic indicators caused us to remain cautious in our outlook. Double-digit unemployment levels above the national average persists in all of our service territories. Single-family building permits, though somewhat stabilized, are also at historical lows in both the Carolinas and the Midwest. Based on recent discussions with our large industrial customers, the second half of 2010 is expected to be consistent with the first half. However, uncertainty remains the dominant theme for 2011. Balancing all of these factors and weighing them against our recent experience, our outlook for 2010 now includes an approximate 2% increase, an average weather-adjusted retail sales volumes for the full year versus 2009, with the increase largely coming from our industrial customer class. Through the second quarter, volumes have increased approximately 3% over 2009. However, we do not expect that rate of increase to continue for the remainder of the year since the rebound in industrial activity began in the second half of 2009. Let's move on to competition in Ohio. As of June 30, the gross switching rate of our Ohio customer load was around 56%, while the net switching rate, net of load acquired by Duke Energy Retail Sales, was about 23%. These are in-line with our expectations. Our outlook for the full year includes a gross switching level that is at the top end of the average 50% to 55% range we communicated to you after the first quarter. We expect the financial impact to be at the upper end of the negative $0.04 to $0.07 EPS range we provided at our February analyst meeting. As expected, the focus of customer switching in Ohio has moved from our industrial customers, and to a lesser extent our commercial customers, to the residential class. This shift toward residential switching is being met by our retail strategy at Duke Energy Retail Sales. As government aggregation efforts and individual mass marketing efforts have increased, Duke Energy Retail Sales has aggressively pursued current Duke Energy Ohio ESP customers that are at significant risks of switching to other providers. One measure of our success is the fact that Duke Energy Retail Sales acquired around 80% to 90% of individual residential customers to switch from Duke Energy Ohio during the second quarter. In part, due to the success of our retail strategy, Commercial Power remains on track to achieve its 2010 estimated adjusted segment EBIT of $315 million. Our Ohio strategy for 2010 is mostly one of blocking and tackling, with an emphasis on Duke Energy Retail Sales aggressively acquiring customers who leave Duke Energy Ohio's ESP rate structure and selectively acquiring Ohio-based load from outsider service territory. At the same time, we are considering how to best position our Ohio business for the near and longer term. As you know, the current ESP expires at the end of 2011, and we are currently evaluating various strategic plans to carry us into 2012 and beyond. As a first step, we expect to make an initial filing with the Ohio Commission by the end of this year. This will give us sufficient time to negotiate a new plan that will be constructive for both Duke Energy Ohio and its customers. The illustration on this slide gives you a perspective on the various options that are available to us. But we currently believe that another ESP is the most likely outcome for post-2011. Obviously, each of these options has positive and negative implications, which we are carefully evaluating. As we approach renegotiation of the ESP, our proposals will strive to achieve a balance between ensuring fair returns on our assets, including compensation for dedication of our assets to serve the native-load customer, and maintaining stability rates to our customers. Our proposals will also address inherent risks in our business such as future environmental compliance costs and customer switching. As we progress through this year and into 2011, we will continue to keep you apprised of developments in this area. As long as customer choice exists in Ohio, Duke Energy Retail Sales will continue to target customer classes susceptible to switching from both within and outside of our service territory. Duke Energy Retail Sales will continue to participate in competitive options and will evaluate other strategic options within Ohio, including extensions of customer contracts for customers who remain interested in market rates. The Duke Energy Retail Sales may expand its supply relationships with Ohio-based customers to include their out-of-state operations. We do not currently expect to broadly participate in markets outside of Ohio. To further position the company for success in the Ohio markets, in May, we made a filing in support of a proposed transfer to PJM. The filing requests FERC's approval to change the membership of Duke Energy Ohio and Duke Energy Kentucky from MISO to the PJM regional transmission organization effective January 1, 2012. Joining PJM will bring long-term benefits for our Duke Energy Ohio customers because it puts all Ohio utilities in the same wholesale market, where customers will benefit from the same wholesale and retail market rules, which are designed to facilitate operations in a competitive market such as Ohio's. Because our Kentucky system is connected to our Ohio transmission system, the move to PJM also benefits our Kentucky customers. We co-own six non-regulated power plants with other Ohio utilities that are also members of PJM. Having all power plant owners in the same RTO, subject to the same price and market signals, will assist in outage and maintenance planning. We expect to incur MISO exit fees as well as obligations for legacy MISO and future PJM transmission expansion costs. However, we are still having discussions with MISO and other parties to determine the magnitude of these costs. We will provide you with further details when reasonable estimates can be made. MISO and other parties have intervened in our FERC application. Most of the interveners comments focus on the rationale for our transfer, and fail to recognize that RTO membership is voluntary. Additionally, these filings fail to recognize the competitive challenges facing our Ohio business and the value of joining the other Ohio utilities in PJM. We will be responding to these filings shortly. Slide 8 summarizes our year-to-date results from our cost-control measures. Our cost objective for 2010 is to hold O&M down, net of deferrals and cost recovery writers, flat to 2009. As a result, we must sustain the O&M cuts we achieved in 2009 as well as absorb the impact of inflation to our cost in 2010. Through the second quarter, we are on track to achieve our cost objective for 2010. However, we expect modest cost pressure from the impact of the unusually warm weather that continued into this quarter. The bottom line is that we are running our plants more than we had expected. We will stay focused on cost control throughout the latter half of this year. Additionally, we continue executing on the voluntary separation and office consolidation plans that I highlighted less quarter. We continue to target a two to three-year payback period for these costs. Our focus on cost control and operational excellence is important given our active regulatory calendar. We must control costs and efficiently operate our plants to lessen the impact of price increases on our customers. We remain committed to cost-control measures and to the continued reliability and quality of our service. In closing, we are encouraged by our strong performance during the first half of 2010. As Jim told you, we are increasing our 2010 adjusted diluted EPS range from $1.25 to $1.30 to $1.30 to $1.35. Achievement of this increased EPS range assumes normal weather during the second half of 2010, continued success with our cost-control efforts and maintaining our strong operational performance. We're off to a good start for the third quarter as all indications are the July weather was favorable to normal. However, it is important to remember that our annual performance will be largely dependent upon our third quarter results, typically, our most significant quarter. And with that, I'll turn it back over to Jim.

Thank you, Lynn. Now I will provide an update of our major construction project. We continue progressing on time and on budget with our Cliffside 825-megawatt supercritical pulverized coal project in North Carolina, as well as our Buck and Dan River combined cycle gas-fired projects in North Carolina. Additionally, our two non-regulated wind projects now under construction, Kit Carson and Top of the World, are both on time and under budget and expected to be operational by the end of this year. The 618-megawatt Edwardsport IGCC project in Indiana is approximately 65% complete, with final engineering over 90% complete. The project is expected to be in commercial operation in 2012. Through June 30, we have spent approximately $1.8 billion of the $2.35 billion previously authorized by the Indiana Commission. As I outlined in our first quarter call, we are seeking authorization from the commission to raise this cost estimate by $530 million to $2.88 billion. This matter has been put into a separate sub-docket from our semi-annual quip writer updates. While we're not happy with having to raise the cost estimate on Edwardsport, we feel believe that have managed this large and complex project as prudently as possible. Many of the challenges we have faced stem from the first-of-a-kind nature of IGCC technology at this scale, and equally important, issues arising from the engineering, design and procurement phase of the project. The good news is that this phase is now essentially complete, and we're building momentum as we work through the construction phase. As with any complex project of this size, there are uncertainties. However, we have captured our best estimate of these uncertainties in the revised cost estimate. Recall that in addition to our own assessments, the commission is being advised on the status of the project by Black & Veatch, an independent engineering contractor. This has given the commission independent insight into the nature and extent of our challenges with the project. We continue to believe that the Edwardsport project meets our customers' future electricity needs in a manner that prudently balances reliability, affordability and environmental stewardship. Our testimony is supported by the continuing need for the project; the cost effectiveness of the project, even with the increased cost; and the economic importance of the project to the Indiana economy, local jobs and the region's coal industry. To accommodate the commission's busy regulatory calendar, we have agreed to extend the procedural schedule. Interveners filed testimony last week, and our rebuttal testimony is due September 2. The IURC will conduct a hearing on this issue in September. As we prepare for the hearing, we continue to review testimony filed last week by several intervener groups. These interveners have recommended various courses of action for the project such as establishing cost caps, halting construction and changing the rate-making mechanisms related to the project. It's important to note that several of these arguments have been previously advocated and rejected by the Indiana Commission. Nevertheless, we will respond vigorously to these arguments in our rebuttal testimony and at the hearing. We have been holding informal discussions with many of our stakeholders to give them greater transparency into the project and will continue to look for ways to address their concerns, and all of these conversations may well lead to a settlement with respect to this expansion. Over the coming weeks, we will update you on the status of this important proceeding. Pending resolution to this matter, we continue to file for quip recovery on costs incurred to date. In June, we filed for our fifth writer. Additionally, the IURC recently approved our fourth IGCC quip writer filing, allowing us financing cost recovery on capital costs spent through September 2009. Before I close, let me spend a minute discussing pending environmental regulations from the EPA. As I previously mentioned, our fleet modernization strategy is driven by existing and proposed environmental regulations, principally focused on coal generation. Over the past few months, the EPA has moved forward with proposals to tighten regulations around emissions from coal-fired generation. Our focus on providing new, cleaner generation has us well positioned to comply with these new environmental regulations. We have been working for more than a decade to reduce emissions to the installation of environmental control equipment, and we are recovering through rates or costs to make those retrofits. We're currently evaluating recent EPA proposals regarding coal combustion residuals and the Transport Rule [CATR] to replace the CAIR rule. We also expect the EPA to issue a proposed MACT [maximum achievable control technology] rule on hazardous air pollutants, such as mercury, in early 2011. While the exact effects of pending environmental regulations are unknown, we're planning for different scenarios and the potential impact on our stations. This may include additional cost due to the installation of air emissions control equipment as well as additional or accelerated unit retirements beyond what we are currently planning. Over the past decade, we have spent about $5 billion to comply with federal and state clean air regulations. Our modeling suggests future investment could be in the same range, phased in over a long time period and likely beginning after 2012. We were disappointed with the recent news of the Senate shelving their efforts on comprehensive energy and environmental legislation. We believe an opportunity was missed to develop an energy and environmental policy for our country, including a program that will lead to a cleaner, low-carbon economy. We will continue to work with these issues in the weeks and months ahead asking the next Congress to provide our industry with the regulatory clarity that we seek. Regardless of congressional action, the EPA will begin regulating greenhouse gases, such as carbon, on January 2, 2011. We will continue to fight for reasonable outcomes that help minimize the cost impact of these regulations to our customers over time. I will close with a summary of our progress in fulfilling the short and long-term commitments we made at our February analyst meeting. First, our commitment to grow earnings and dividends. We have had a strong first half of 2010, and are increasing our 2010 adjusted diluted EPS outlook range from $1.25 to $1.30 to $1.30 to $1.35. We recently increased our quarterly cash dividend by about 2%. This increase is consistent with our objective to continue growing the dividend, but at a slower rate than the long-term growth in our adjusted diluted earnings per share. It marks the 84th consecutive year that Duke Energy has paid a quarterly cash dividend on its common stock. As you may remember, our second commitment is to allocate capital efficiently and earn competitive returns. We are modernizing our fleet and have allocated significant capital to these projects. We expect to earn reasonable, regulated returns in the jurisdictions of which we operate, while meeting our customers' future electricity needs in a manner that prudently balances reliability, affordability and environmental stewardship. Our renewable projects, both wind and solar, are under budget and on schedule. We have demonstrated an ability to produce attractive risk-adjusted returns and to finance and efficiently operate a utility scale renewable portfolio. Finally, our third commitment is to maintain a strong balance sheet. S&P recently reaffirmed our A-minus corporate credit ratings with a stable outlook. We intend to maintain our current credit ratings, which have given us strong access to the capital markets and supported our ability to issue debt at historically low coupons. These low-cost financing help us manage the cost increases to our customers during this period of significant reinvestment. Our long-term focus on modernizing our fleet and grid continues to offer a solid value proposition for our investors. Now let's open up the lines for your questions.

[Operator Instructions] And we'll go to Daniel Eggers with Crédit Suisse. Dan Eggers - Crédit Suisse AG: I was wondering, first question and, Lynn, just talking to the demand outlook or the recovery story, at the Analyst Day, you guys talked about fairly muted your five-year plan for recovery, and this year since well above, you went through revisions today. What would give you guys confidence that the sub-1% growth you talked about earlier this year has changed to something more meaningful, and kind of what do you see underlying that's driving the better numbers right now?

Dan, I would point, first of all, to Industrial. We had a very strong rebound in the first quarter, really led by Primary Metals in our service territories. Textiles have also performed well. As we look at the second quarter, that strength has broadened beyond Primary Metals into Automotive and Chemicals as well. So we see, as you noticed on the chart, 12.4% increase. As we talk to this Industrial customers, they are confident about the back half of 2010. Where the confidence starts to weakened a bit, though, is when they talk about 2011. So I think we feel good about where we are for '10, but I think are still cautious about the strength of the rebound into '11. The other thing that I would note is that Residential and Commercial had been roughly flat for the quarter. Residential is up about 1% for the year, but that is still a bit of a challenged growth rate, and we'd like to see a bit stronger turnaround in these two segments as well. Dan Eggers - Crédit Suisse AG: And then I guess, Jim, your thought process when you guys are making decisions on infrastructure coal plant closures in response to EPA action. What kind of rules do you need to, say, see? And what kind of time line do you think you're going to have to start talking about closing down some of those units?

Dan, we really get a head start on this process with the building of Edwardsport, Cliffside and our two combined-cycle gas plants. The combination of the building of those will allow us to retire roughly 1,300 megawatts of about 4,500 megawatts that we believe will be retired by the end of this decade. So in a sense, we've already started down the road because we think reinvesting in new plants with the low cost of capital and lower rates for consumers and by starting now, it will smooth out the cost increases for consumers over the decade. It's difficult to make further decisions until we get greater clarity with respect to the EPA regulations. We have modeled it many, many different ways, and we're waiting to see the proposed rule before we move forward. But we think most of the major decisions will really lead up to 2015.

We'll go to Greg Gordon with Morgan Stanley.

On Commercial Power, and I apologize if you said this in the script and I missed it, can you describe in a little more detail what drove the higher results for the Midwest gas assets, the $23 million improvement?

Dan, we had stronger capacity payments this year over last year as a driver. Volumes were roughly comparable to last year, but our margins were a bit stronger. Those are the two things I would point to.

And if you look at the customers that have not switched, the customers that are still taking power under the ESP, and you look at the all-in rate there relative to, let's say, a market rate, do you think you have further gross margin exposure as you negotiate, going to negotiations for new ESP? Clearly, there's an opportunity to get lower prices if people would be switching.

Yes, and I would say that's true. Because when I look at the margin that existed in our ESP that we negotiated at the height of the commodity boom in 2008, those prices were much higher. So I think as you think about 2012 and forward, you should be thinking about resetting those prices to a more market-based rate. The other thing we will be...

So the bad news is there might be some further pressure on margins, but the good news is those customers will therefore be at market, and you wouldn't have to worry about switching?

I guess that would be one way to look at it. The other thing I was going to say though, Greg, is as we look at entering the ESP, we will also be addressing a number of other things. Environmental costs will be one. We're very focused on compensation for dedication of assets that we end up with dedicated assets to the load. So we will be looking at a variety of things in addition to what I would call pure-market energy prices that would be reasonable forms of compensation for the assets. So more to come as we enter those negotiations.

So to sort of put that another way, you feel like there are other ways that you need to be compensated for the assets that served the State of Ohio that could be offsetting revenue drivers?

Yes.

I think one way to add to that is simply to say you can easily see a bypassable charge that's tied to the capacity that's being dedicated to serve the load in the future, a non-bypassable charge.

But are you saying one that doesn't exist today or one that is higher than the one...

One that doesn't exist today that as we look at proposing ESP beyond the notion of a non-bypassable charge that compensates us for the POLR [provider of last resort] responsibility is something, in my judgment, makes a lot of sense.

We'll now go to Jonathan Arnold with Deutsche Bank.

My question's more on the next year impact from switching in Ohio as you're seeing this year come in towards the upper end of that range of $0.04 to $0.07 you gave us. When you think about the timing where that's occurring during this year, should we be thinking about the number of cents of follow-through into '11 as -- because you had the full year impact of the switching that happened in '10? Or was it predominantly front-end loaded and less of an issue?

Jonathan, our incremental switching impact from '09 to '10 is about $0.05. You might recall in '09, we were at $0.02, the upper end of the range and '10 is $0.07. So I would look at that $0.05 delta, and I think a reasonable planning assumption will be to annualize that into '11.

So are you saying there's another $0.05 in '11? Or am I mishearing that?

No, I think that's a reasonable assumption. And as you think about the rest of Commercial Power though, you also have to make assumptions around wholesale prices. You have to make assumptions about what we will accomplish with the gas assets, et cetera. And we'll give you a more complete picture of Commercial as we finalize our guidance for '11.

We'll now go to Steve Fleishman with Bank of America.

A couple of questions on the goodwill write-down. Should we assume that pretty much all this write-down was related to the Ohio coal assets?

It's all related to the Midwest generation. That's correct.

And what are those assets now on the books for?

Steve, I would say roughly $3.8 billion, $4 billion book value.

And then I guess from the standpoint of -- I know the goodwill write-down was non-cash, but I guess it does impact your equity ratio. Is there any change in your thinking on financing plans, equity issuance plans over the three- to five-year period, given the write-down? Or is it still just the DRIP at the level that you had said?

Yes, Steve, no impact to financing plans. As we look at our metrics, and we're very comfortably positioned in our ratings, and those metrics are largely driven by our coverage ratios, FFO to debt and interest, which, of course, will not be impacted at all by this view.

We'll now go to Hugh Wynne with Sanford Bernstein.

I think back over the last decade, and I don't think I can remember a time when Duke Energy wasn't nursing along some fleet of unregulated generation assets that ultimately culminated in some large write-down. And the historic tendency, and it seems to be playing out again, is that these assets absorb an undue amount of sort of management attention and analyst attention and ultimately, have very little potential upside. And I was just -- wanted to get your views about alternates to continuing to own those assets. Is it something that you've explored? Or do you feel that you're completely bound in to ownership, given the PUCO's [Public Utilities Commission of Ohio] restrictions on transfer?

Hugh, let me take a shot at your question. I think a couple of things to keep in mind. The assets that we're really talking about in the Midwest were deregulated in 2000 and then dedicated to our customers for five years. And then we entered into an RSP, which I always referred to as a regulatory light approach. And during that period, our market price was equal to -- I mean, our RSP price was equal to or below that market price at the time. And when we entered into this ESP, we expected to continue to operate in this regulatory light world with that 4,000 megawatts of generation. Now that we have -- the prices had dropped so dramatically in PJM, it's obviously forced us to think differently about these assets. Because at the end of the day, we have roughly 4,000 megawatts of gas-fired generation that was left over from DENA [Duke Energy North America] in the Midwest. And so in a sense, if you see this regulatory light assumption that we operated in morphing to where we have 8,000 megawatts of merchant generation in the Midwest, we have to kind of rethink do we really want to hold that position and the risk and the volatility of earnings? Or can we structure a deal with the Ohio Commission that allows us this regulatory light approach going forward, primarily with these 4,000 megawatts. So yes, we're thinking about a wide range of options today and have been thinking about them as we watch the market price fall in PJM over the last year. So we are -- our thinking with respect to this is under active consideration, and I'd go a step further. As we look out and you see the market curves, the markets turn up significantly in '16 and '17. And so one of the questions that we ask ourselves, even if we were to stomp out of our position, this is the time in history to do it to get the greatest value. So I think our first priority is to work with the regulators to get a deal that works. Our gas assets are performing better each year. And as demand comes back and the economy recovers, they will only increase in value. So a lot depends on what this ESP looks like that we renegotiate as to what alternative that we actually pursue. But I've kind of been very open in sharing with you the range of possibilities that are under consideration, given where we are today.

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

Just a question for you on Indiana. When you look out after Edwardsport is done in rates, can you talk about where your rates will likely stand versus other Indiana-based utilities?

I think we've historically had some of the lowest rates in the state. I have not done the comparison, but, Michael, I'll be glad to do that. I think we'll be pretty much at the average rate in the state, but let us supply you that information later, if we may.

The other question, any change or any update kind of on long-term development of non-regulated renewable or other non-regulated power assets?

Let me take that one, Michael. We are developing wind, as you know. Our aspiration has been to grow that business at a pace of about 250 megawatts a year. We're on track to do that in '10 with a couple of projects that Jim referenced a moment ago. We've had a couple of very small solar projects that we've announced as well, so a lot of work is going on to identify good projects that meet our returns. And that is probably good summary of where we think we're going with those businesses.

We'll now go to Brian Chin with Citigroup.

A question on retail. Have you seen an increased level of retail competition from providers outside of your service terri [territory], particularly asset-light retail providers?

There has been an increased number of retail providers outside of the service territory of Ohio. In terms of whether they're completely asset light, I'm not sure that I've looked behind the books involving individuals who are participating in the market. But I think just the evidence that we've seen in our territory indicates that competition is picking up in Ohio.

We've seen similar comments about increasing market competition from PEG [Public Service Enterprise Group], from Constellation earlier this earnings season. And then referencing an earlier question that Greg had mentioned about when you guys filed the ESP, you're going to have a series of rates that need to take into account and higher environmental costs. Just thinking a little bit longer term, how do you think this was going to pan out for asset-light retail providers versus asset-heavy retail providers? Just thinking longer term strategically, who do you think is going to be more at disadvantage and more advantaged?

It would be my judgment having lived through the asset-light environment that you're much better to have hard assets in the ground. It's kind of a more predictable capability to deliver and not be subject to the volatility of power prices in the market. So I believe long term -- and when I hear asset light, I think Enron. And if there are Enron-type players, trying to take our customers, then come on in because eventually, you're going to get ran out because you're not going to have the assets to be able to supply the power that our customers need. So my belief is it's the owners of the assets that are going to survive and do best in this environment going forward.

Last question on this. Shouldn't higher environmental requirements temporarily, though, make asset-heavy generators subject to a little bit more cost pressure on their retail side? Or am I thinking about things a little bit too stretched here?

I think there's a couple things to think about, and we're certainly doing analysis as I suspect that you have. As you look forward, not only will there be retrofit costs, but there are going to be retirements. And to the extent people retire units in PJM, that is really going to change the supply-demand equation and in all likelihood, drive up prices overtime. And there's an open question with respect to even gas-fired generation and the dependence on shale gas. Will that shale gas continue to keep gas prices below $5? Or will that price start to move up because there have been many questions asked about the amount of shale gas and availability, but many environmental questions raised. And so in our minds, there's great promise to show gas, but there are a lot of unanswered questions as to whether it will be available and at what price. So I think you have to take into account the retirements, how gas prices are going to move, how coal prices are going to move. If you see retirements of coal plants in the region, you can envision a decline in coal prices. So those with harder coal assets might offset the environmental expenditures on retrofit with lower cost of coal. So it's a very complex equation, and we're kind of working our way through each aspect of it.

We'll go to Lasan Johong with RBC Capital Markets.

Not to beat a dead horse too much but, Jim, if you are correct, and I believe you are, that value of assets are going to go up, particularly on the generation side, why not shop while it's cheap?

I'm not sure. I guess my short answer is I'm not sure everybody shares the view you and I have about how valuable the assets are. And I think that you're going to have to see more volatility in PJM. You're going to have to see the price move up, and the forward curve says it doesn't really happen till '16 and '17. I believe, looking at the fundamentals, the price is going to move up even sooner. That's one person's judgment, but I think most people would mark the value of these assets based on the forward curve and not necessarily on the underlying fundamentals as I described them.

That's exactly the reason why the asset prices would be cheap enough to buy.

But we might be a seller, and it's not a good time to sell.

There are some interesting things going on, on tax issues in the Congress. If the dividend does indeed get taxed at 20%, how does that change Duke's dividend policy? And does that make paying out of dividend less attractive? And would that change your payout philosophy?

Our value proposition is really centered around the dividend and centered around the growth of the dividend. And even if the tax rate change, and we hope it doesn't, we think it would be bad public policy, given where the economy is to raise taxes on dividends or capital gains going forward. We do not believe it changes our basic value proposition and our commitment to the dividend and the growth of the dividend.

On MISO, they ask for more information on the PJM transfer, and it sounds like they needed Duke to "justify" the move in a more, how shall I say, acceptable manner probably to MISO. First of all, what exactly are they looking for? And do they have the ability to stop that transfer from happening or at least play havoc on the transfer process?

I think first, when they sent the letter to us are filed with the FERC, they basically forgot that these are voluntary arrangements, first and foremost. And secondly, they don't appreciate the fact that we are -- and they're certainly not valuing the fact that we're leaving all our Indiana generation in MISO, and even though it's a voluntary decision on our part. And I guess the third point really is, is that most of our plants, as Lynn pointed out, are co-owned plants in Ohio where our partners are in PJM. So there is a compelling logic in my mind, if we have co-owned plants, with all of them are in PJM, that it makes sense for our plants' output to be in PJM also. So from our standpoint, there is a strong logic to us making this transition now. And it's simply -- and then I guess one last point is that MISO has refused to establish a capacity market that's meaningful compared to PJM. And they have a capacity market, and that makes a fundamental difference if we find ourselves increasingly in a merchant position with respect to our coal plants. So we feel like that they have, in my judgment, overreacted and they've forgotten the basics, and we were one of the founding members of MISO. So it's with some reluctance that we withdraw something that we helped create. But the world changes, and it's changed in a way that today, it makes sense for us to make this move.

Since the unemployment rate in your service territories are not only higher than national average but have gotten there faster, would we be safe in assuming that the reverse would also be true, that manufacturing-led economy or rebound would then, therefore, help to reduce the unemployment rates in your service territory quicker and below the national average faster?

If we got to bounce back in the manufacturing sector and we have examples of new plants that are being built, we have examples of existing companies expanding their facilities, examples of companies that are going to two shifts. All of that will help reduce the jobless number in our area, but it's very difficult for us to predict what the jobless number will be even as the Industrial sector rebounds.

We'll now go to our last question from Ali Agha with SunTrust Robinson Humphrey.

Jim or Lynn, when you talk about your 4% to 6% longer-term EPS growth, target or outlook, give us on the trend you talked about the ESP repricing, the capacity payment trends that we know are coming the next couple of years. Are you assuming that your existing portfolio can generate that kind of long-term growth? Or are you assuming any additions or acquisitions in there down the road?

We're not assuming acquisitions. We're certainly on track on the growth rate this year. That growth rate is largely supported by our Regulated business and the deployment of capital. And as we get closer to the range of outcomes on the ESP, we'll give you finer view of how we think Ohio will contribute as we go forward. But we're thinking about our growth rate within the context of the businesses we own.

And related question, when you folks took a close look at the utilities in Kentucky, should we assume that was a one-off -- there's some compelling reasons to own them? Or, Jim, as you've talked about before, as you think about the second wave potentially coming of consolidation in the industry, should we also assume that Duke will be an active participant or a looker in that process?

In my judgment, as you referenced, I believe consolidation will continue in our industry, and that we're in a wave that has just started. I also believe that we, obviously, were very opportunistic and took a look at a company that was contiguous to our operations, both in Indiana and our operations in Kentucky and Ohio. And so from an operational standpoint, obviously, it made a lot of sense to us, but we weren't the winning bidder. And the important point you should take from that is yes, we're going to look at opportunities as they present themselves, but we're going to be very disciplined in our approach. And that is going to be the key to any acquisition or merger that we do in the future.

And contiguous territory, generally, would be one of the criteria you would think about, Jim?

Yes, contiguous, there is an advantage to contiguous in terms of reducing operating costs and dealing with things like storms and storm restoration, et cetera. But it's not a -- it is one criteria. It is not a limiting criteria with respect to what we will be looking at going forward.

And this does conclude the question-and-answer session today. I'll go ahead and turn back over to the presenters for any closing remarks.

On behalf of the Duke Energy management team, let me thank you for joining us today. As always, our Investor Relations team is available to take your follow-up questions. Have a great day.

This concludes today's conference call. Thank you for your participation.