Duke Energy Corporation (DUK) Q3 2010 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to the Duke Energy 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 Investors Relations and Treasurer. Please go ahead, sir.

Thank you, Lisa. Good morning, everyone, and welcome to Duke Energy's Third 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 review our third quarter results, discuss our outlook for the remainder of 2010 and provide an update on certain matters related to the business. After their prepared remarks, Jim and Lynn will take your questions. 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. Note that the appendix to the presentation materials includes additional disclosures to help you analyze the company's performance. 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 third quarter results. They were excellent. The weather remained hot, the economy continued to show slow but steady signs of improvement, especially in our industrial class and our employees executed extremely well. As you saw in our news release this morning, we announced adjusted diluted earnings per share of $0.51 for the third quarter of 2010 versus $0.40 for the third quarter of 2009. This is a quarter-over-quarter increase of around 28%. If you remove the impact of weather from each of these quarters, the quarter-over-quarter increase was approximately 7%. Let me highlight the more significant drivers of our results for this quarter. First, favorable weather. We experienced well above normal temperatures in all five of our regulated jurisdictions during the third quarter. In the Carolinas, the quarter was the hottest third quarter in nearly 50 years. Additionally, we continued to realize higher revenues from our base rate increases approved in 2009 in North Carolina and South Carolina. And our employees and fleet continued to deliver excellent performance throughout the third quarter's unusually hot weather. Our year-to-date nuclear capacity factor was 96%, while our fossil fuel fleet had a commercial availability of 89%. This strong operational performance through the end of the third quarter puts us on target to achieve our operational metrics for 2010, some of which are outlined on Slide 18 in the appendix. Based upon our results for the third quarter, usually our most significant quarter, we are increasing our 2010 adjusted diluted EPS outlook. We're going to increase that range to $1.40 to $1.45 per share. To put this in some perspective, at the start of the year, our 2010 adjusted diluted EPS outlook range was $1.25 to $1.30. After our second quarter results, we increased the outlook range to $1.30 to $1.35. Assumptions underlying this revised outlook include: normal weather for the rest of the year, continued costs control, continued strong operational performance and a stable economy. Before I turn the call over to Lynn to discuss the quarterly results, let me spend a few moments on Indiana. On November 3, I will have an opportunity to reaffirm our need for Edwardsport in a technical conference at the Indiana Commission and to answer any questions that the commission, its staff or any of the parties in the proceeding may have. Edwardsport is the cornerstone of our modernization strategy in Indiana. It helps us reduce the environmental impact of our existing coal generation fleet and prepares us for the inevitable retirement of some of our older coal plants, renew environmental regulations for coal-fired plants are issued in the coming years by the EPA. Our IRP, our Integrated Resource Plan, supports our need for Edwardsport, even at the higher costs estimates of $2.88 billion. Based on this analysis, it is the best long-term economic solution to meet the needs of our Indiana customers at this time. Edwardsport is currently around 74% complete and is scheduled to be in service, 2012. As you may know, questions have been raised related to the recent hiring of an attorney formerly with the Indiana Commission. In response, we have retain an outside law firm to conduct an independent investigation. We're also cooperating with Indiana Commission and the Inspector General in the reviews of this matter. Once the investigations are concluded, we will take whatever actions are appropriate. Because these investigations are ongoing, I cannot comment at this time, on the investigations or any actions we may take. However, this matter is a top priority for me, as well as my management team. Now let me turn it over to Lynn.

Thanks, Jim. Let me begin with an overview of our financial performance for the quarter. As you can see in the table on Slide 4, our total adjusted segment EBIT increased approximately $200 million compared with the third quarter of last year. The results for each of our business segments were strong, driven principally by favorable weather in all five of our states and in the Carolinas, increased pricing. The competitive environment in Ohio continues to be challenging, but we are extremely pleased with the efforts of our competitive retail arm, Duke Energy Retail, in defending and capturing margins. Let me briefly review the significant drivers of results for each of our business segments. Adjusted segment EBIT for U.S. Franchised Electric and Gas, our largest segment, increased $230 million over the prior-year third quarter. The significant drivers of this segment were the following. First, we experienced unusually warm summer weather, resulting in increased segment earnings of $157 million. The number of cooling degree days in the Carolinas during the third quarter was 27% above normal, while our Midwest service territory experienced total cooling degree days 32% above normal. Secondly, the impact of rate increases in the Carolinas approved in 2009 resulted in increased segment earnings of approximately $90 million. These rate increases reflect the recovery of prudently incurred utility investments and will continue to positively impact results in future periods. Thirdly, higher allowance for funds used during construction, resulting from Duke Energy's ongoing construction program, increased segment earnings another $20 million. Partially offsetting these increases to the segment's adjusted EBIT was an impairment charge of $44 million, recognized in connection with the September settlement agreement we reached with the Indiana Office of Utility Consumer Counselor and certain industrial customers related to the cost of the Edwardsport IGCC project. The impairment charge resulted from the settlement provision, which lowers the return on equity for amounts expended in excess of the currently approved project cost of $2.35 billion. The settlement agreement is subject to approval by the Indiana Commission, which will hold hearings on the matter on November 29 and 30. Next, I will discuss our Commercial Power segment. As we expected, Commercial Power's adjusted segment EBIT for the quarter was lower than the prior-year third quarter. However, as a result of strong energy margins from our Midwest gas-fired assets and the success of Duke Energy Retail in defending and capturing margin, Commercial Power has already exceeded its original 2010 adjusted segment EBIT expectations of $315 million. In fact, despite competitive pressures in Ohio throughout 2010, Duke Energy Retail has responded quickly and aggressively by pursuing customers not only inside Duke Energy Ohio's service territory, but also in other service territories within Ohio. Importantly, switching pressures in Ohio have stabilized. We are also pleased with the operational performance of Commercial Power's generation fleet and its continued focus on containing costs. Midwest generation is ahead of its safety and commercial availability targets for the year. They have accomplished these results while significantly reducing non-fuel O&M, principally labor costs. Turning now to our International operations, adjusted segment EBIT increased $10 million over third quarter of 2009. The primary drivers of this increase include favorable pricing and foreign exchange rates in Brazil, offset by lower dispatch of our thermal generation in Central America due to strong hydrology. Finally, two additional drivers impacted Duke Energy's overall results. The first was an increase in interest expense of $12 million, due to higher debt balances resulting from planned financings of our capital expansion program. The second, a positive driver, was a decrease in the adjusted effective tax rate from 33% in the third quarter of 2009 to 31% in the third quarter of 2010. We are now targeting a 32% effective tax rate for 2010, excluding the effect of the second quarter goodwill impairment charge, which is non-deductible for tax purposes. This targeted effective tax rate for 2010 is slightly higher than our original target of 31%, primarily as a result of the increased pretax earnings we expect, resulting from the strong weather experienced to date. For detailed quarter-over-quarter drivers for each of our segments, please refer to the appendix. Now I'll turn our attention to volume trends. For the third quarter in a row, we experienced an increase in overall weather normalized sales volumes compared to the same period in 2009. Our weather normalized electric volumes rose approximately 1% this quarter, driven primarily by increased industrial sales activity across a broad range of major industrial classes. We continue to closely watch our sales volume trends, are cautiously optimistic about the continued industrial recovery in the near term. As industrial indicators point to continued expansion, the rate of growth has slowed. Earlier in the year, the Industrial recovery began in the primary metal sector. As the year has progressed, the recovery has spread to other Industrial sectors, including chemicals, textiles and automotive. However, primary metals growth has recently slowed primarily due to reduced commercial and residential construction activity. Additionally, our commercial and residential weather normalized volumes were essentially flat compared to third quarter of 2009. However, we continue to see modest growth in the total number of residential customers we serve in both the Carolinas and the Midwest. We remain optimistic in residential sales will see growth in the future. At the same time, we are experiencing improved sales. Certain macroeconomic indicators cause us to remain cautious in our outlook for the future. Economists remain concerned about slow growth, as national and global economic challenges persist. Unemployment rates remain at or above the national average in all of our service territories. Single-family building permits have somewhat stabilized, remain at historical lows in both the Carolinas and the Midwest. Balancing all of these factors and weighing them against our recent experience, our outlook for 2010 continues to assume an approximate 2% increase in average weather normalized retail sales volumes for the full year versus 2009, with the increase largely coming from our industrial customer class. Nevertheless, recent discussions with our large industrial customers confirm that uncertainty remains the dominant theme for 2011. The next few months will give us a clear picture regarding next year's volume forecast. Next, we'll look at cost control. Slide 6 summarizes our year-to-date results for our cost control measures. Our cost objective for 2010 is to hold O&M, net of deferrals and cost recovery riders, flat to 2009. This will require us to sustain the O&M cuts we achieved in 2009, as well as absorb the impacts of inflation and other cost increases in 2010. Through the third quarter, we are on track to achieve our cost objective as our year-to-date costs are relatively flat to the prior year. However, we continue to experience modest cost pressures, resulting from the impact of the unusually warm weather that we've seen in 2010. These cost pressures require us to stay focused on cost control throughout the remainder of this year. We will continue to execute on the voluntary separation and office consolidation plans we highlighted earlier this year. We are targeting a two- to three-year payback period for these costs. However, based upon additional cost reduction efforts identified as part of these plans, we have the potential to achieve a two-year payback. Even though we are committed to our cost control program, we also remain firmly focused on providing reliable, high-quality service to customers. With that, I'll turn it back over to Jim.

Thank you, Lynn. I would like to conclude our prepared comments with a brief discussion on our Ohio business, as well as an update of our major construction projects. First, let me turn to Ohio, where we have non-regulated generation that is dedicated to serve the native load. Customer pricing is governed by the Electric Security Plan, or ESP, that expires at the end of 2011. The market in Ohio remains challenging due to continued low commodity prices and significant customer switching, even though it has slowed in the last several months. In the near term, the ESP regulatory framework under which we operate today in Ohio, creates more downside risk than potential for upside in today's markets. This framework makes it difficult for us to earn consistent and appropriate risk-adjusted returns for investment. This does not fit well with our value proposition for shareholders nor our overall risk profile. We continue to consider a full range of strategic options for Ohio generation portfolio for our upcoming standard service offer filing sometime in mid-November. This filing will balance the need to provide our investors with an appropriate risk-adjusted return and our customers with affordable and reliable electricity. We've outlined three potential options for our next standard service offer filing on this slide. We don't have specific details to share with you today. But we intend to work hard to reach constructive outcomes for both customers and shareholders. After we file our plan in the coming weeks, we will host a webcast to fully discuss the filing. On another Ohio matter, we were pleased last week when FERC conditionally approved the transfer of our Ohio and Kentucky transmission from MISO to PJM effective January 1, 2012. Additionally, FERC approved the participation of our mostly coal-based generation in Ohio and at Kentucky transmission from MISO to in PJM effective Jan [January] 1, '12. Additionally, FERC approved the participation of our mostly coal-based generation Ohio and Kentucky in PJM's May 2011 base residual option for the 2014 and '15 delivery period. There are remaining milestones we must meet related to this transfer, but FERC's approval is a strong first step. We are also seeking approval of the transfer from the Kentucky Commission. Next, I'll provide an update on our major construction projects, which are the centerpiece of our fleet modernization strategy. As I said earlier, in Indiana, our 618-megawatt Edwardsport project is 74% complete with approximately $2 billion spent to date. The project remains scheduled to go online in 2012. As Lynn mentioned, we entered into a settlement agreement with intervening parties regarding the increased costs of the Edwardsport project from $2.35 billion to $2.88 billion. This settlement is subject to commission approval. A public hearing is scheduled for November 29 and 30. The settlement balances customer rate impacts with the need to modernize our fleet and reduce our environmental footprint in Indiana. Further details of the settlement were discussed during our September 20 webcast, which can be found on our website and are included in the appendix to today's presentation. The commission has delayed hearings on our IGCC 5 semi-annual CWIP Rider related to Edwardsport from October 26 to December 2 after the hearings in late November on our recent settlement agreement. Meanwhile, we continue progressing on time and on budget with our three major North Carolina construction projects, which are outlined on this slide. Our 825-megawatt Cliffside supercritical pulverized coal plant scheduled to go online in 2012 is now 72% complete, with more than $1.5 billion spent to date. Additionally, the scrubber for Cliffside Unit 5 has been successfully tied in at the plant site. Our 620-megawatt Buck combined-cycle gas-fired plant scheduled to go online in 2011 is now 15% complete with $350 million spent to date. And last week, we broke ground on our second new combined-cycle gas-fired plant in North Carolina, our 620-megawatt Dan River facility scheduled to go online in 2012 with about $225 million spent to date. We've also made significant progress with our non-regulated renewable projects, which are underpinned with long-term power purchase agreements. Our 200-megawatt Top of the World wind farm in Wyoming went online earlier this month under budget and is selling all of its output to Pacific Corp. under a 20-year power purchase agreement. Our 51-megawatt Kit Carson wind farm in Colorado is expected to go online by the end of this year. The project will sell all of its output to Tri-State Generation under a 20-year power purchase agreement. These two projects, once online, will bring our total operating wind generation to nearly 1,000 megawatts by year end. In addition, our 14-megawatt Blue Wing commercial solar project in Texas is expected to go online as early as next week. The project has a 30-year power purchase agreement with CPS Energy. Let me close with an update of our NSR cases. Earlier this month, we received a favorable ruling from a federal appeals court, which reversed a jury's finding that three of our coal units at Wabash River Station in Indiana had violated the Federal Clean Air Act. As a result of the initial jury decision, we had taken these three units out of service in 2009. This favorable ruling effectively ends over 10 years of litigation around EPA enforcement actions with respect to our Midwest generation fleet. We are pleased to have it behind us, although we are taking necessary steps to bring the three Wabash units back into service. We continue to evaluate whether more stringent upcoming environmental regulations will require their early retirement within the next several years. In conclusion, I am extremely pleased with our results this quarter and year-to-date. We remain focused on achieving an outstanding year. Our long-term strategy to modernize our fleet and grid continues to be an important part of what we're doing both for our customers, as well as investors. On the earnings front, we had a strong third quarter and are increasing our 2010 adjusted diluted EPS outlook range to $1.40 to $1.45 per share. On the dividend front, we increased our quarterly cash dividend, about 2% this year, the 84th consecutive year we paid a quarterly cash dividend on our common stock. Next week, several members of our executive team will attend the EEI [Edison Electric Institute] Financial Conference. I'll be in Indiana for the commission hearing on Edwardsport and thus unable to attend a conference. Additionally, I want you to know that the management team and I plan to conduct our 2011 Analyst and Investor Meeting in New York in February 2011. At that time, we'll provide an overview of our fourth quarter and 2010 earnings, as well as a strategic summary of each of our businesses. Further, we will discuss our 2011 adjusted earnings per share guidance range and financial outlook for 2011 and beyond. Details on the date and time will be sent to you shortly. Now let's open up the phone lines for your questions.

[Operator Instructions] Our first question comes from Jonathan Arnold with Deutsche Bank.

I have a question on your comments on Ohio and switching having stabilized in line with your expectations, and if I remember rightly, last quarter you had suggested that you'd see another $0.05 or so of pressure in 2011 on top of what you saw in '10. Is that what you mean by your expectations? Or has it stabilized to something better than that?

Jonathan, I think that's still a reasonable expectation for '11. What we have seen in the latter couple of months in the third quarter is a real stabilization in the level of switching, and that's what we were referring to in our remarks.

So had that not occurred it might have been something less, but $0.05 is a good number base. I mean, you were expecting it to do this, anyway?

That's correct.

Obviously, you've showed us how much weather you're carrying in the numbers so far this year. Can you just help remind us how much currency gains there'd be in 2010 year-to-date? Or if it's that powerful help so far this year?

Jonathan, it's a net help of about $18 million at the net income line year-to-date.

Our next question comes from Ali Agha with SunTrust Robinson Humphrey.

The $1.40 to $1.45 range for the year, the revised range, could you remind us what would be sort of the implied average ROEs embedded in that for your utility portfolio? And whether that would compare to sort of having authorized ROEs?

Ali, we've begun to look at that. And in the Carolinas, we will be above 10%. Our allowed ROE in the Carolinas is 10.7%, you may recall.

And other fleets?

I don't have the other jurisdictions in my mind. We can certainly discuss that with you on a follow up.

And on the weather front, you highlighted $157 million benefit. If I read correctly, that's the delta year-over-year. What is that versus normal, sorry, first, just to clarify that?

Ali, I would refer you to Slide 19 in the deck, which gives you a good breakdown of weather to normal in both 2010 and 2009, which should give you the information you need to compare.

Jim, as you look at the overall environment in the market, we are seeing more M&A activity. You talked about that wave a couple of times in prior comments. Again, where is Duke's focus right now as far as that potential activity? Or are you just comfortable with your current portfolio at this time?

Well, Ali, as you know, we really don't comment specifically on mergers or acquisitions with respect to our company, but I will say you are right. The wave seems to be continuing to build with consolidation in our industry. And as we look at the need to retire and replace plants, the need to modernize the grid and the fact that over the next two decades, the real price of electricity is going to rise as compared to the last 50 years where the real price has been flat, I think there's going to be increasing pressure on companies to look at ways to mitigate these cost increases. And obviously mergers is one way to do it. So I think more to come on that, so thank you.

We'll now go to Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG: I guess my first question is, if I look at the supply business, the commercial office business, how much EBIT contribution have you guys gotten from CCGTs out of that total contribution for the year?

Dan, if you look at the slide for the quarter, Midwest gas is about $33 million. For the year, it's close to $70 million, year-over-year delta. Dan Eggers - Crédit Suisse AG: Year-over-year delta, so it's up $70 million year-over-year from where we were. And your long-term targets for earnings contribution from that, was it $100 million of EBIT at some point in time?

Dan, we haven't talked about a long-term target. Certainly, we were pleased with capacity prices early in the auction cycle for PJM. As you know, those recent clearing prices have not been as good. And we did experience this quarter higher energy margins really driven by low gas prices and weather. Dan Eggers - Crédit Suisse AG: And I guess, as we look out to the filing for whatever you're going to do in Ohio and I guess there's been some talk of different decision trees as far as Ohio generation assets, can you maybe, Jim, frame how you would go through the decision process of making different offers to the commission? And how you would layer in the sensitivities to what to do with that generation fleet?

Sure. I think the way to put the stage is to say for the past nine years, the customers have benefited from a five-year rate freeze and a negotiated rate that was below the market price for four years. It worked for both customers and investors during that period. Today, the situation is very different. Prices have dropped dramatically in PJM, and we've experienced significant switching to the benefit of consumers, but not investors. At the heart of the problem, in my judgment, is that customers have a free option. Said another way, they have the ability to get the lower of market price or a negotiated rate. And the commission has been unwilling to permit a non-bypassable charge for standing ready to serve our customers when they return. As you know so well in truly competitive markets, there are no free options. Consequently, the way I view the situation in Ohio, we are neither regulated or allowed to completely to market today. So we are taking a very close look at the MRO, because that is a way to transition to market. It seems to be emerging in our analysis as the appropriate way forward, with respect to getting the appropriate returns for investors and continuing to provide to our customers reliable and affordable service. The way I would say it is, is that we're continuing to think our way through this. We're continuing to examine the pluses and minuses of the ESP approach that's been so beneficial to customers and investors in the past. And we're continuing to drill down on all of the implications of the MRO. As you know, FirstEnergy's MRO request was rejected several years ago, and we've looked closely at the basis for its rejection. And if we go that route, we will make sure that we address the issues that were raised by the commission there. So on balance, we believe that we have to make a very difficult decision between now and mid-November. But if you had to say, well, where are you leaning? I would say we're leaning toward the MRO at this point, but that's not a final decision. We have more work to do. Dan Eggers - Crédit Suisse AG: But Jim, just to kind of round out that conversation. How are you guys thinking about your hedging exposure for the generation fleet, given the uncertainty of whether you'll be at market under some sort of some version of the costs to certain mechanism or something else? I mean, do you feel comfortable as a manager selling forward power today for '11 and '12? Or do you have too wait until you get permission from the commission one way or another before you're willing to let go of that full polar obligation?

There's a couple of important points. First of all, under our ESP which will still be in effect in '11, we have dedicated that capacity to our customers under the terms of the ESP. What we do beyond '12, it's my understanding, even with the MRO, there will be a commitment of this capacity to the retail load. So the issue of hedging out the capacity is not an issue that's in front of us in the short or medium term. I think that's a longer-term consideration. The other point I want to make to kind of bring clarity to this. Our Duke Energy Retail grew, which has picked up roughly 60% of the load to switch. What they have done is gone into the market and hedged the load as they picked it up to lock in the margins. So I draw those two distinctions, both with respect to next year and beyond, with respect to our generation and with respect to our door approach and whether or not we do ESP or MRO or some variation with respect to our existing generation. Is that clear?

Our next question comes from Brian Chin with Citi.

Can you give us an update on the plans to switch on Ohio over to PJM? Just where do those stand?

Brian, this is Lynn. We have received conditional approval from FERC on the transfer. We still are waiting commission approval from Kentucky and are targeting the transfer to be effective January 1 of 2012.

And if I understand it right, there's not going to be any transitional auctions, like what FirstEnergy did with the Yatzi [ph] region? You guys will elect the fixed resource requirement election, is that right?

That's right.

And then one last question on the Gallagher Unit, on the slide that you have, Slide 15, that shows the status of environmental controls on coal fleet. You mentioned that there's 280 megawatts that you may convert to gas or retire. If you were to choose the conversion to gas option, how much would that cost? And could you go into a little bit of if you were to convert that to gas, just what technologically would that involve?

Actually, it's simpler than what we had originally thought. The cost is roughly $70 million. It would require a pipeline to be built to the plant to be able to supply the gas.

So the $70 million is really the cost of the pipeline more than anything else?

$40 million is the pipeline, the remainder is modifications within the plant.

And one last question on this. When you're looking at the remaining $30 million, is the cost of converting that coal to gas something that is $1 per kilowatt conversion cost? Or is it more of a fixed cost regardless of how big the units sizes are?

It is primarily fixed cost.

Our next question comes from Hugh Wynne with Sanford Bernstein.

I have a question regarding the outlook for Duke Energy Ohio. I understand from the slide that you're seeing maybe $0.04 to $0.07 EPS in this year. In answer to Jonathan Arnold's question, you're seeing perhaps additional $0.05 of erosion next year. Would that get us to a point where virtually all energy sales, Energy Ohio at or close to market, so that the transition to a MRO or the transition to an ESP in '12 would have very little incremental effect? Or will there still be some residual risk of retail prices slipping further beyond '11?

Hugh, I think it's premature to talk about '11 to '12, with the early stage of our negotiations and setting of prices that we talked about in terms of the filing we're predicting or planning for the end of the year. The one thing I would point to in the slide deck, if you look at Slide 7, there's a distribution of who serves Ohio's customers today and you'll notice that 36% are still being served by Duke Energy Ohio, and those customers are still paying the Electric Security Plan price.

Are these the customers that are expected to go away in '11 they're bringing you're EPS down to -- eroding the EPS by a further $0.05?

No, you should think about the '11 impact as being annualization, Hugh, because switching has occurred over time in 2010. And so you'll see an annualization impact in '11.

Okay, so I guess one way to think about it would be that this 36% of the customer base is still at risk in '12?

Yes, what I would say to that, it certainly, they're Duke Energy Ohio customers, and they could certainly choose to switch. But they have remained with us throughout this entire period and we have seen a stabilization in switching.

They've remained with you, but in '12, you would have to offer them an MRO or ESP that would be at market, right?

Yes, DE Ohio would offer that to all customers.

And then just one other quick question regarding capital structure and equity strategy. I see the company continuing to dribble out equity. I think we're sort of seeing an annual rate of dilution of about 1.5%. The dividend growth rate is modest. It's about 4%. And I guess my question is whether the dilution of equity continues to be necessary, given the strength of the balance sheet, the strength of the ratings of the utility companies, and I guess the gradual completion of some of the larger CapEx projects. Could that be dispensed with and might we enjoy somewhat more rapid EPS growth as a result?

We have issued about $200 million of equity this year. We would forecast that to be about $300 million by the end of the year. We will update our equity plans when it comes in the Street in 2011. The only equity that we have announced publicly is the DRIP for 2010. And as you can imagine, we are in a position of stronger cash than we predicted coming into the year. So we'll consider all of these factors, our capital plan for next year, et cetera and setting expectations for the future.

We'll now take our next question from Michael Lapides with Goldman Sachs.

Jim, just a question for you on renewable development post-2010 or kind of after the wind plants you have under construction right now. How do you think about that in terms of where commodity prices are right now? Where various markets are in terms of meeting RPS requirements outside of the regulated business, meaning the plants you would do within Commercial Power?

I think that -- here's my thinking about it. This, in my judgment, has been a good business because we're primarily building our wind and solar in states that have renewable portfolio standards. So they are mandated to purchase. Secondly, we are in every instance before we start construction put in place at least a 20-year PPA. And thirdly, the tax incentives associated in this business are very attractive. As you know, we're able to recover 38% of our investment in the first year. And coupled with that, we've been able to do project financing, so we've been able to get attractive returns on these investments. But our current sense of the market is that it is softening. And so the opportunities that are available may not be as great as they have been in past years. And I believe that's consistent with sort of the perception that FP&L has, which is really the leader in the industry in terms of developing wind. And I think we've all seen a softening in the demand for renewable energies, even in the states with the mandates to meet certain targets in future periods.

One follow up, a little bit unrelated. In the Carolinas, specifically North Carolina, when do you expect to go to the legislature or go to the commission for potential changes, meaning to get whether it's to get trackers or forward test years, or a nuclear rider of some sort, kind of when and how does this process play out?

We have spent significant amount of time talking to other parties in the state and really working in a collaborative way to develop proposals for the next session that starts in January, I believe, in North Carolina. And so we will be prepared to kind of rollout a legislative plan. And clearly, the ability to get regular adjustments equipped without filing a rate case will be on that list. There will be a number of riders specifically tied to environmental expenditures. I mean, those are two for sure that would be on the list. And there maybe other ideas that will be attached to it. But again, I think the important point, Michael, for you to take from this, is that we're spending a lot of time building a coalition of support for legislation that really will allow us to address these issues in front of us and to be able to do it in a way that over time will allow us to close the gap between our earned and allowed return.

And I wanted to make sure, because when someone else earlier in the call had made a comment, or had asked a question about earned ROEs and I think, Lynn, you may have commented that you expect to earn north of 10% in the Carolinas, are you expecting, following on Jim's last comment, are you expecting regulatory lag to become a bigger issue in the Carolinas going forward if you don't get a legislative fix?

Michael, as we've shared with you even dating back to our Analyst Day, we've been very focused on trying to close the gap. What Jim is talking about legislatively is certainly a piece of that. You will also see us file ongoing general rate cases. We're planning to file in the Carolinas in 2011. So it's a combination of things that we'll be working with to close that gap.

And we'll go to our next question from Paul Patterson with Glenrock Associates.

I apologize if I missed this, but I didn't hear really much about you guys talking about Duke going into maybe other service territories on the retail side. I mean, you guys seem to be obviously gaining a lot of experience in your own service territory. What's the opportunity maybe to go somewhere else? And if so, if you have looked at that, what areas might you guys be looking at?

Paul, our focus has been Ohio and will remain Ohio predominantly. The only business that we have really entertained outside of Ohio is based on industrial or commercial customers who have operations in adjoining states where we understand the market, et cetera. So strategically, we're not trying to build a national footprint or even a super-regional footprint on retail. We're working through the environment in Ohio and trying to address that competitive environment in a very proactive way.

Any particular service territories in Ohio that look attractive to you?

I think one thing that we have done is we participated in the FirstEnergy auctions and that's really the extent of our activity in the state. Paul Fremont - Jefferies & Company, Inc.: The FERC notice of proposal rulemaking on the demand response in the energy market regarding full locational marginal pricing, have you guys done any modeling on the potential impact? And if you have, could you share with us what you think the impact might be if this NOPR is adopted?

Paul, that's something we're not prepared to talk about today. I think we'd like to take that one on offline.

We'll now take our next question from Ashar Khan with Visium Asset Management.

Just going back, so if I understand, if you go to the MRO, then the generation asset sale is out of the question, right, under that scenario?

Ashar, the generation asset sale is a strategy that is many steps down the chess board, I'm trying to develop the ongoing strategic positioning of Ohio. What we are focused on initially is the next 2012 to 2014 positioning of these assets and the pricing MRO is one option that we're looking at.

But under that option, you would retain generation, right?

Not necessarily. You should think about generation asset as something that we could either leave in the utility or request to move outside of the utility in an ESP structure or an MRO structure.

But going back to what Jim said in the beginning, am I right or wrong, you said it is hard with the way the current ESP is structured, or just even looking at MRO, I don't know, that it is hard to have a growth rate of like 5% to 6%, with commodity prices where they are currently? Is that the way I correctly understood Jim's comments in the beginning that the profile and the risks, they are hard to achieve with commodity prices and for similar ESP, was to continue on or going to an MRO?

I think there are a couple of points, and I'll ask Lynn to amplify on my answer. But the first point is that if you did an ESP by definition, the price would probably less than it is today going forward and that's after 2012, because the negotiated price has to reflect the market price. And obviously, we're all well aware that there's been a dramatic drop in the price of PJM over the last year. The MRO feature, which is in my judgment could be a positive is the way you're permitted to blend your existing generation with purchases in the market to come up with a negotiated price for your customers. So the amount of the blend from your existing generation or from the market is something that would be negotiated as you go down the MRO path. But again, we need to be realistic about this as all the merchant guys in the Midwest who are in PJM appreciate the margins have been squeezed dramatically for all the merchant players. I don't see that letting up in the next several years. However, if you look out five years or more, you can see the prices rising again. And the wild card in this is how many coal plants will actually be shut down and there have been estimates of between 20% and 30% of all the coal plants in the U.S. will be shut down in the next decade. I suspect the lion's share of these assets will be in the Midwest. Is there anything, Lynn, you'd like to add to that?

No, I think our comments on earning a fair return in the environment in Ohio where commodity prices are low, we've experienced switching, just a more volatile market, which does make it difficult to earn a consistent predictable return on the assets. And so that's the key area focus as we think about the future.

In essence, if I can sum up, Jim, what I'm understanding is that if commodity prices continue where they are right now, there's no way we can forestall the earnings decline in '12. But what it does is with an MRO is it gives us an opportunity in the later years to benefit from EPA coal closing and pickup in commodity prices in the later years. But in '12, we are facing a hit, which ever way we go?

The one comment I would make about the MRO is it does have an opportunity or the way the statute is written, you actually transition to market. So there's a blending concept with the price to customers is established as a part percentage, your former ESP price and part percentage market prices. And so it does give you an opportunity to keep the prices at a higher level than what a strict reduction to market would result.

And I think that is really a very important point in the transition. But to be realistic about this, once the transition's complete, that we would not have an obligation other than through an auction process or a bidding process to serve our load. And that would give us the option to make a decision as to whether we want to keep the 4,000 megawatts we currently have dedicated to the load or to sell them. But that's a decision that is far down the road.

And then if I can just sum up, Lynn, if I'm right, you said if you strip out the weather impact for the year, you said it's like $0.12, $0.13, we would still be like around $1.31, $1.32.? Is that right for the year?

If you started at $1.45.

If I start off with $1.45, is that correct?

That's right. On the midpoint, about $1.30 weather adjusted.

Your next question comes from Ivana Ergovic with Jefferies. Ivana Ergovic - Jefferies & Co: I'm wondering whether you put out any estimates regarding on transmission costs that you might have once you transfer your assets from the PJM.

We have not disclosed this exit fees, but will as we complete our receiving all the approvals and get closer to the date of that occurring. Ivana Ergovic - Jefferies & Co: And another unrelated thing, I noted that the plant generation in your Commercial Power segment was basically flat year-over-year, and the weather was much more warmer. And the industrial that has pickup, so I'm just wondering why?

I'm sorry, I couldn't follow that question. Could you maybe speak... Ivana Ergovic - Jefferies & Co: The generation levels in Commercial Power segment were flat quarter-over-quarter, and this quarter was much warmer and there was Industrial pickup. So I'm just wondering why the levels were flat?

I think generation in 2009 was particularly strong and what I would also suggest is that Bill Currens and our IR team would be available to have further discussions on that topic.

That concludes the question-and-answer session today. At this time, I would like to turn the conference over do Mr. Stephen De May for any additional or closing comments.

Thank you, Lisa. And let me thank everyone on the call for joining us today. As always, our Investor Relations team is available to take your follow-up questions. We look forward in meeting with many of you during the upcoming EEI Financial Conference. Thank you, and have a great day.

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