Earnings Call: Q3 2010

Oct 28, 2010

Good day, everyone, and welcome to the Duke Energy Earnings Conference Call. Today's call is being recorded. At this time, for opening remarks, I would like to turn the call over to Mr. Stephen DeMay, Senior Vice President of Investor Relations and Treasurer. Please go ahead, sir. Thank you, Lisa. Good morning, everyone, and welcome to Duke Energy's Q3 2010 earnings review. Leading our discussion today are Jim Rogers, Chairman, President and Chief Officer and Lynn Goode, Group Executive and Chief Financial Officer. Jim and Lynn will review our 3rd quarter results, discuss our outlook for the remainder of 20 10 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 measures. You should refer to the information in our 2,009 10 ks 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 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 Q3 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 dollars for the Q3 of 2010 versus $0.40 for the Q3 of 2000 and 9. 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 quarter in nearly 50 years. Additionally, we continue to realize higher revenues from our base rate increases approved in 2,009 in North Carolina and South Carolina. And our employees and fleet continued to deliver excellent performance throughout the 3rd quarters and 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 20 10, some of which are outlined on Slide 18 in the appendix. Based upon our results for the Q3, 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 dollars per share. To put this in some perspective, at the start of the year, our 20 10 adjusted diluted EPS outlook range was $1.25 to 1 point $3.0 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 cost control, continued strong operational performance and a stable economy. Before I turn the call over to Len to discuss the quarterly results, let me spend a few moments on Indiana. On November 3rd, 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. Edwards Port is the cornerstone of our modernization strategy in Indiana. It helps us reduce the existing coal generation fleet and prepares us for the inevitable retirement of some of our older coal plants when new environmental regulations for coal fired plants are issued in the coming years by the EPA. Supports our need for Edwardsport even at the higher cost estimates of $2,880,000,000 Based on this analysis, it is the best long term economic solution to meet the needs of our Indiana customers at this time. Edwards Port 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 cooperating with the Indiana Commission and the Inspector General in their 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 can see in the table on Slide 4, our total adjusted segment EBIT increased approximately 200,000,000 dollars compared with the Q3 of last year. The results for each of our business segments were strong, driven principally by favorable weather in all 5 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. Franchise electric and gas, our largest segment, increased $230,000,000 over the prior year Q3. The significant drivers of the segment were the following. First, we experienced unusually warm summer weather, resulting increased segment earnings of $157,000,000 The number of cooling degree days in the Carolinas during the Q3 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 $90,000,000 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 20,000,000 dollars Partially offsetting these increases to the segment's adjusted EBIT was an impairment charge of $44,000,000 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 Edvard sport 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 $2,350,000,000 The settlement agreement is subject to approval by the Indiana Commission, which will hold hearings on the matter on November 29th 30th. Next, I will discuss our commercial power segment. As we expected, year Q3. However, as a result of strong energy margins from our Midwest gas fired assets and the success of Duke Energy Retail and defending and capturing margin, Commercial Power has already exceeded its original 2010 adjusted segment EBIT expectation of 3 $15,000,000 In fact, despite competitive pressures in Ohio throughout 20 10, Duke Energy Retail has 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 and M, principally labor costs. Turning now to our 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, 2 additional drivers impacted Duke Energy's overall results. The first was an increase in interest expense of $12,000,000 due to higher debt balances resulting from planned financings of our capital expansion program. The second, a a positive driver, was a decrease in the adjusted effective tax rate from 33% in the Q3 of 2009 to 31% in the 10, excluding the effect of the 2nd quarter goodwill impairment charge, which is nondeductible for tax purposes. This targeted effective tax rate for 20.10 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 Q3 in a row, we experienced an increase in overall weather normalized sales volumes compared to the same periods in 2,009. Our weather 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 and are cautiously optimistic about the continued industrial industrial Earlier in the year, the industrial recovery began in the primary metals sector. As the year has progressed, the recovery has spread 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 Q3 2,009. 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 that residential sales will see growth in the future. At the same 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, though somewhat stabilized, remain at historical lows in both Carolinas and the Midwest. Balancing all of these factors and weighing them against our recent experience, our outlook for 20 10 continues to assume an approximate 2 percent increase in average weather normalized retail sales volumes for the full year versus 2,009, 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 from our cost control measures. Our cost objective for 20.10 is to hold O and M, net of deferrals and cost recovery the impact of inflation and other cost increases in 2010. Through the Q3, 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 continue to execute on the voluntary separation and office consolidation plans we highlighted earlier this year. We are targeting a 2 to 3 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 2 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 Ohio, where we have non regulated generation that is dedicated to serve the native load. Customer pricing is is governed by the electric security plan or ESP that expires at the end of 2011. The market in Ohio 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 consistent and appropriate risk adjusted returns for our investment. This does not fit well with our value proposition for shareholders nor our overall risk profile. We for with an appropriate risk adjusted return and our customers with affordable and reliable electricity. We've outlined 3 potential options for our next standard service offer filing on this slide. We don't have specific 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 Jan 1, 'twelve. Additionally, FERC approved the participation of our mostly coal based generation in Ohio and Kentucky in PJM's May 2011 base residual auction 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 6 18MW Edwards Fort project is 74% complete with approximately $2,000,000,000 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 cost of the Edwards Fort project from $2,350,000,000 to 2.8 $8,000,000,000 This settlement is subject to commission approval, a public hearing is scheduled for November 29th 30th. The settlement balances customer rate impacts with the need to modernize our fleet and reduce our environmental footprint in Indiana. Further details on the settlement were discussed during our September 20th web cast, 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 V semiannual QIP rider related to Edwardsport from October continue progressing on time and on budget with our 3 major North Cliffside Supercritical pulverized coal plant scheduled to go online in 2012 is now 72% complete with more than $1,500,000,000 spent to date. Additionally, the scrubber for Cliffside Unit 5 has been 20 in 2011 is now 15% complete with $350,000,000 spent to date. And last week, we broke ground on our 2nd new combined cycle gas fired plant in North Carolina, our 620 Megawatt Dan River facility scheduled to go online in 2012 with about $225,000,000 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 Pacific Corp under a 20 year power purchase agreement. Our 51 Megawatt 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 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 3 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 3 units out of service in 2,009. 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 3 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. 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 $0.45 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 Financial Conference. I'll be in Indiana for the commission hearing on Edwards Court and thus unable to attend the conference. Additionally, I want you to know that the 2011. At that time, we'll provide an overview of our Q4 and 2010 earnings as well as a strategic summary of each of our business. Further, we will discuss our 2011 adjusted earnings per share guidance range and financial outlook for 20 11 and beyond. Thank you. The question and answer session will be conducted Our first question comes from Jonathan Arnold with Deutsche Bank. Please go ahead. Good morning. Good morning, Jonathan. 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 20 10. Is that what you mean by your expectations? Or has it stabilized to something better than that? Jonathan, I think a reasonable expectation for 11. What we have seen in the latter couple of months of Q3 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 worse, but $0.05 is a good number based on and you were expecting it to do this anyway? That's correct. Okay. Thank you. And then can I obviously, you've showed us how much weather you're carrying in the numbers so far this year? Can you just remind us how much currency gains have been in 2010 year to date? Or if it's a net help or hurt so far this year? Jonathan, it's a net help of about $18,000,000 at the net income line year to date. Our next question comes from Ali Agha with SunTrust Robinson Humphrey. Could you the $1.40 to $0.45 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 where that would compare to sort of average authorized ROEs? Ali, we've begun to look at that. And in the Carolinas, we'll be above 10%. Our allowed ROE in the Carolinas is 10.7%, you may recall. Right. 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 the $157,000,000 benefit. If I read that correctly, that's a delta year over year. What would be or is that versus or is that versus normal? Sorry, first to just clarify that. Ali, I would refer you to Slide 19 in the deck, which gives you a good break down of weather to normal in both 20,102,009, which should give you the information you need to compare. Understood. Last question, Jim, the the overall environment in the market, we are seeing more M and A activity. You've talked about that wave a couple of times in prior comments. Again, where is Duke's focus right now as far as that specifically on mergers with our 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 2 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 Akers with Credit Suisse. Good morning. 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 the CCGTs out of that total contribution for the year? Jan, if you look at the slide for the quarter, Midwest Gas is about $33,000,000 For the year, it's close to $70,000,000 year over year delta. And the year over year delta, so it's up $70,000,000 year over year from where we were. And your long term target for earnings contribution from that, was that $100,000,000 of EBIT at some point in time? Dan, 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 talk of different talk of different decision trees as far as biogeneration assets. Can you maybe Jim frame how you would go through sensitivities to what to do with that generation fleet? Sure. I think the way to put the stage is to say for the past 9 years, the the customers have benefited from a 5 year rate freeze and a negotiated rate that was below the market price for 4 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 customers have a free option. Said another way, they have the ability to get the lower of market price 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 go 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 our 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 the implications of the MRO. As you know, FirstEnergy's MRO request was rejected 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 or 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 our final decision. We have more work to do. Not to be piggish on the call, but Jim, just to kind of round out that conversation you had about hedging out exposure for the generation fleet given the uncertainty of whether you'll be at market under some sort of some version of a cost to serve mechanism or something else. I mean, can you do you feel comfortable as a manager selling forward power today for 11 2012 or do you have to 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 'eleven, we have dedicated that capacity to our customers under the terms of ESP. What we do beyond 12, it's my understanding even with an MRO, there would 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 Group, which has picked up roughly 60% of the load that switched, what they have done is gone into the market and hedge the load as they picked it up to lock in the margins. So I'd like to I draw those two distinctions both with respect next year and beyond with respect to our generation and with respect to our DIR approach and whether or not we do ESP or MRO or some variation with respect to our existing generation. Is that clear? Yes, I think I got it. Thank you for all your time. I appreciate it. Thank you. Our next question comes from Brian Chin with Citi. Good morning. Can give us an update on the plans to switch 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 approval from Kentucky and are targeting the transfer to be effective January 1, 2012. And if I understand right, there's not going to be any transitional auctions like what FirstEnergy did with the ATSI region. You guys will elect the fixed resource requirement election, is that? That's right. Okay. 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 2.80 option, how much would that cost? And could you go into a little bit of if you were to 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 we had originally thought. The cost is roughly $70,000,000 It would require a pipeline to be built to the plant to be able to supply the gas. So the $70,000,000 is really the cost of the pipeline more than anything else? $40,000,000 is the pipeline. The remainder is modifications within the plant. And one last question on this. When you're looking at the remaining $30,000,000 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 unit sizes are? It is primarily fixed Our next question comes from Huynh with Sanford Bernstein. Go ahead please. Hi. Good morning. Good morning. Good morning. I had a question regarding the outlook for Duke Energy Ohio. I understand from the slide that you're seeing maybe 0 point 0 $4 to 0 point 0 $7 EPS in this year. And in answer to, Jonathan Arnold's question, you're seeing perhaps an additional $0.05 of erosion next year. Would that get us to the point where virtually all energy sales, EnergyOhio are at or close to market so that the transition to a MRO or the transition to an ESP in 2012 would have very little incremental effect or would there still be some residual risk of retail prices slipping further beyond 'eleven? 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 customers that are expected to go away in 11 to bringing your EPS down to eroding EPS by the further 5¢? Dollars No. You should think about the $0.11 impact as being annualization, Hugh, because switching has occurred over time in 2010, and so you'll see an annualization impact in 2011. Okay. I guess one way to think about it would be that this 36% of the customer base is still at risk in 2012. Yes. And you know what I would say to that, it's certainly they're Deep 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. DEO Ohio would offer that to all customers. Right. DEO Ohio would offer that to all customers. Right. Okay. 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 seeing an annual rate of dilution 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, or could that be dispensed with and might we enjoy somewhat more rapid EPS growth as a result? Yes, it's a good question. We have issued about $200,000,000 of equity this year. We would forecast that to be about $300,000,000 by the end of the year. We will update our equity plans when we come to the Street in 2011. The only equity that we have announced publicly is the DRIP for 20 those factors, our capital plan for next year, etcetera, and setting expectations for the future. Okay. Thanks very much. Thank you. We'll now take our next question from Michael Lapides with Goldman Sachs. Tim, 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 markets are in terms of meeting or not meeting RPS requirements outside of the regulated business, meaning the plants you would do within it. This in my judgment, 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 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 with this business are very attractive. As you know, we're able to recover 38% of our investment in the 1st 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 and 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. Got it. One follow-up, a little bit unrelated. In the Carolina, 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? Sure. 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 roll out a legislative plan and clearly the ability to get regular adjustments of QIP without filing a rate case will be on that list. There will be a number of riders specifically tied to there may be other ideas that will be attached to it. But again, I think the important point, Michael, if you could take from this is that we're putting we're spending a lot of time building a coalition of support for legislation that really will allow us to address choose 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. Got it. Okay. And just 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. 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 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. Got it. Okay. Thank you. Much appreciated. Thank you, Michael. We'll go to our next question with from Paul Patterson with Glenrock Associates. Good morning. Good morning, Paul. And 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, I mean, 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, etcetera. 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. Okay. Any particular service territories in Ohio that look attractive to you? I think one thing that we have done is we've participated in the first energy The FERC notice of proposed 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 the snoper is adopted? Paul, that's something we're not prepared to talk about today. I think we'd like to take that one offline. Okay. Thanks a lot. Thank you. We'll now take our next question from Azar Khan with Visium Asset Management. Good morning. Good morning. Just going 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 chessboard in trying to develop the ongoing strategic positioning of Ohio. What we are focused on initially is the next 2012 to 2014 positioning of those assets and the pricing, MRO is one option that we're looking at. Okay. But under that option, you would retain generation, right? Not necessarily. You should think about generation assets 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. Okay. 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 the 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 if a similar ESP was to continue on or going to an MRO? I think there are a couple of points and I'd ask Lynn to amplify on my answer. But the first point is that if you did an ESP, by definition, the price would be 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 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 to be realistic about this as all the merchant guys in the Midwest are pretty who are in PJM appreciate the margins have been squeezed dramatically by all for all the merchant players. I don't see that letting up in the next several years. However, if you and there have been estimates that between 20% 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 make it difficult to earn a consistent predictable return on the assets. And so that's a key area of focus as we think about the future. So 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 2012. 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 2012, we are going to be we are facing a hit whichever 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 transition to market. So there's a blending concept where 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 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 is complete that we would not have an obligation other than to 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 are to sell them, but that's a decision that is far down the road. Okay. And then if I can just sum up, Lynn, if I'm right, you said, if you strip out the $1.3 for the year? If you started at $1.45 Yes, if I start off with $1.45 is that correct? That's right. Okay. Thank you. So from the midpoint about $1.30 weather adjusted. Weather adjusted. Okay. Thank you so much. Thank you. Our last question comes from Urvana Yegovitch with Jefferies. Please go ahead. Hi. Good morning. Good morning. Good morning. Hi. I'm wondering whether you put out any estimates regarding the transmission costs that you exit fees, but will as we complete our receiving all the approvals and get closer to the date of that occurring. Okay. And another unrelated thing. I noticed the plant generation in your commercial power segment was basically flat year over year. And the weather was much warmer and the industrial there was industrial pickup. So I was just wondering why? And I'm sorry, I couldn't follow that question. Could you maybe speak 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. Yes. I think generation in 2,009 was particularly strong. And what I would also suggest is that Bill Curran and our IR team would be available to have further discussions on that topic. Okay. Thank you. Great. Thanks so much. That concludes the question and answer session today. At this time, I would like to turn the conference over to Mr. Stephen DeMay 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 to 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.