Earnings Call: Q4 2010

Feb 17, 2011

Good day, everyone, and welcome to the Duke Energy Quarterly Earnings Conference Call. Today's call is being recorded. At this time, for opening I would like to turn the call over to Mr. Stephen Denay. Please go ahead, sir. Thank you, Marisi. Good morning, everyone, and welcome to Duke Energy's 4th quarter year end 20 10 earnings review. Leading our discussion today are Jim Rogers, Chairman, President and Chief Executive Officer and Lynn Goode, Group Executive and Chief Financial Officer. Jim and Lynn will review our Q4 and full year results, discuss our performance in 2010, provide an update on key strategic matters and provide financial guidance and our outlook for 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 in today's materials. Note that the appendix to the presentation materials 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. We are extremely pleased with our financial and operational performance during 20 10. We delivered on our commitments: 1, by increasing earnings and the dividend 2, by operating our fleet and grid exceptionally well at record levels 3, by continuing our cost control efforts and 4, by delivering excellent customer service. To begin today's discussion, let's take a quick look at the Q4, then I'll spend most of the time reviewing last year's accomplishments. Today, we reported 4th quarter adjusted diluted earnings per share of $0.21 That compares to $0.28 last year. The favorable impacts of rate increases in weather were offset by 3 factors. 1, increased cost related to plant outages 2, a discretionary donation to the Duke Energy Foundation of $1,000,000 or $0.02 and without this pre funding of the foundation for future years, we would have met the consensus for the Q4. Thirdly, the continued impact of customer switching in Ohio. For the full year, we announced adjusted diluted earnings per share of $1.43 an increase of 17 percent over last year's $1.22 Our full year results fell within the $1.40 to $1.45 earnings range we forecasted in the 3rd quarter and significantly above our original guidance of 1 $1.25 to 1 $0.30 Even without the favorable weather, which contributed around a net of $0.13 we would have landed at the high end of our original guidance. We continued growing our quarterly dividend to shareholders, increasing the per share dividend from $0.24 to $0.245 a 2% increase. Our total shareholder return of 9.5% exceeded the 5.7% return of the Philadelphia Utilities Index. Despite the demands on our fleet and grid due to extreme weather, we delivered record performance in 20 cost per megawatt hour among domestic fleets for the 3rd straight year as reported by the electric utility cost group. Our non regulated Midwest coal and gas generation fleet also performed well generating power at record levels while staying focused on controlling cost and being available. We continue to diligently control cost. Our O and M expenses, net of deferrals and cost recovery riders were held flat from 2,007 to 2,009. In 2010, the modest cost increases we experienced were primarily due to weather related demands on our system as well as increased cost associated with Duke Energy Retail. The bottom line is we held O and M virtually flat 4 years. We also continue to deliver superior customer service. J. D. Power's 2010 residential customer satisfaction study ranked Duke Energy Carolina's best among large utilities in the among business customers in the South, moving up from 3rd last year. Despite challenging record temperatures and high demand, our employees consistently delivered exceptional commitment to serving our customers as well as our investors. We also made progress on our 4 major fleet modernization projects in 2010. I will discuss these in more detail next. Turning to Slide 5, you can see the status of Edwardsport, Cliffside, Buck and Dan River. These projects are the centerpiece of our plan to modernize our fleet, positioning us to us to deliver efficient, reliable and increasingly clean power well into the future. In total, these projects represent investments of approximately $7,000,000,000 and about 2,700 megawatts of capacity. By 2015, the completion of these projects will enable us to close about 1200 megawatts of aging less efficient coal units and reduce our emissions footprint, better positioning ourselves for more stringent environmental regulations. Buck is scheduled to be in service later this year and Edwardsport, Cliffside and Dan River are expected to go online in 20 projects into service in 2010, ending the year with more than 1,000 megawatts. Each project was completed onetime and within budget and is underpinned by long term power purchase agreements. Additionally, during 2010, we executed more than $500,000,000 of project financings in our renewable energy portfolio. Now let me spend a few minutes on Edwardsport project in Indiana, which is approximately 80% complete as of December 31. It is expected to be in service in 20 12. We continue to work to resolve the issues addressed in our April with the Indiana Commission. In it, we requested approval of an increase in the project's estimated cost from the to both the plant and its revised cost estimate. Last month, Duke Energy Slide 6 includes a summary of the key dates in our proposed schedule. Although estimated construction cost have increased over the original estimates, our IRP analysis confirm that we need additional capacity and completing the plant is the best solution for our customers. Progresses, we continue to monitor potential cost pressures with the project, primarily related to labor productivity, aggressively explore appropriate measures to mitigate these cost pressures and deliver the project within our $2,880,000,000 cost estimate. As we step back, it's important to remember the sound reasons for the project. The reasons we started the project continue to exist today. As environmental regulations are implemented, we expect as much as 1 third of U. S. Coal plants to shut down by 2020. Due to the long lead times required to build baseload plants, we cannot wait until our older coal fired units in Indiana are closed to begin replacing them. We're building the next generation of power plants now to provide reliable energy to our customers for the next 50 years or more. From an environmental standpoint, Edwardsport is expected to produce 10x the power of the existing plants with less environmental impact. When completed in 2012, Indiana will have one of the cleanest coal plants ever built and most importantly, it will meet the long term growth needs of our customers in the state. The new 6 18 Megawatt plant will replace natural resource in the state, which supports local Indiana jobs. We believe Edwardsport is a sound investment in Indiana's energy future. Next, turning to Slide 7, I'll update you on our progress in Ohio. You all are aware of the challenges we've experienced there and some of the shorter term and longer term strategies we generated in response. For example, the rapid deployment of our competitive retail supplier, Duke Energy Retail and the recent filing of our market rate offer. First, let me update you on customer switching, which began in 'nine and began to stabilize in the Q3 of 2010. By year end, customer switching was running about 65%, only a slight increase from 64% in late September. For the year, we recognized about 0 point 0 $6 negative pressure, Duke Energy Retail has quickly and effectively pursued customers both inside Duke Energy Ohio service territory and in other utility service territories within Ohio. We have been pleased with the performance of our retail arm. It has acquired approximately 60% of our total Ohio switch load. As we think about Ohio in the long term, our generating assets currently serve an essentially regulated function in that they must stand ready to serve our retail customers. However, under the current ESP structure, we are not adequately compensated for this obligation. In November, we proposed a market rate offer to the Ohio Commission, which would eliminate some of the asymmetrical risk we experience under the ESP framework. Our MRO is designed, 1st, to give us flexibility to deliver competitive and fair rates to customers secondly, to provide provide more long term clarity for our Ohio generation business. We weighed all the options and believe the MRO is the best solution under the current rules. The filing which is subject to approval by the Public Utilities Commission of Ohio, meets the Senate Bill 2 21 requirements and positions our generation for the long term. The statute in Ohio requires the commission to issue an order on our MRO filing by late February. In the coming weeks, we also expect to file a request for approval to transfer the the the is broken. Without provisions in place to assure a competitive and fair return on our investments, it is difficult for us to justify future power plant investments in the state of Ohio. This is not good for Duke Energy or for Ohio. We will continue exploring options to maximize the returns from this business. On Slide 8, you'll see our 2011 adjusted diluted earnings per share will fall within a range of $1.35 to 1 $0.40 This is consistent with our adjusted earnings. Our growth is anchored adjusted earnings. Our growth is anchored by the investments we are making in the regulated business as we continue to modernize our fleet. We also maintain our focus on cost control and strong operational performance. Now I will turn it over to Lynn for an in-depth look at our financial results in 2,000 and 2 as well as our earnings guidance for 2011. Thank you, Jim. Today, I'll give you a brief overview of our 20 10 results, then I'll discuss our outlook for 2011. As Jim reported, our adjusted EPS for $10 was $1.43 a 17% increase from adjusted EPS of $1.22 in 2,009. This growth was supported by weather, higher rates in the Carolinas and strong operational performance of our fleet and grid. We experienced favorable weather in both the summer and winter seasons. For the year, our cooling degree days in the Carolinas and Midwest were more than 30 percent higher than normal, and our heating degree days were also favorable to normal by 16% in the Carolinas and 7% in the Midwest. Because of higher generating volumes from our fleet, our O and M costs, net of deferrals and cost recovery riders, were slightly higher than 2,000 and 9. We worked diligently during the year to control costs at a level consistent with the prior year. However, the increased cost of plant outages and the operating costs of Duke Energy Retail made this objective challenging. We continue to grow the quarterly dividend from 0.24 dollars to $0.245 per share. At the same time, we maintained the strength of our balance sheet and our credit ratings, which were affirmed by both Moody's and S and P in January 2011. More detailed information on the earnings drivers for each of our segments for both the quarter and the year is included in the appendix to this presentation. The table on Slide 9 shows the 2010 full year results for each of our business segments compared to our projected segment EBIT. As shown, each of our 3 business segments exceeded our original projections. The strong results of franchised electric and gas compared to plan were principally driven by favorable weather. Our regulated businesses also experienced weather normalized customer load growth compared to our original expectation of flat load growth for the year. Our weather normalized customer load increased approximately 2% in 20 from for the year. Even though we've seen some improvement from the 2,009 decline in our total customer load, we have not yet returned to 2,000 and 7 pre recessionary levels. In fact, we do not project returning to those levels until about 2015. Commercial Power's results for the year were down about $100,000,000 compared to the prior year, largely due to customer switching in Ohio. However, these results exceeded our original segment projections by more than $80,000,000 or around 25%. Commercial Power mitigated some of the customer switching pressures in Ohio by effectively deploying Duke Energy Retail, our competitive arm, allowing us to recapture some of the margins lost from switching. Our 3,600 Megawatt Midwest gas fired generation fleet also performed well with record volumes and higher margins due principally to favorable weather. Overall, our strong results for the year gave us the ability to make a discretionary $40,000,000 contribution to the Duke Energy Foundation in the Q4 in support of our local communities. This contribution was in addition to $15,000,000 we had made earlier in the year. Our adjusted effective tax rate for 20 of bonus depreciation, which eliminated the manufacturing tax deduction. In 2011, our focus remains on increasing earnings, growing the dividend, successfully managing our upcoming rate cases and maintaining a strong balance sheet. Slide 10 shows our key assumptions for impacted by favorable weather. Excluding weather, our adjusted results would have been around 1 point $3 $4.0 guidance range. Taking a $1.30 as $1.30 as the normalized starting point, we expect U. S. F. E. And G to contribute an incremental $0.14 toward our spending program. The second driver of FE and G's year over year growth is the expected economic expansion. As As of increases in our weather normalized load. Our industrial customers tell us they expect growth to continue into 2011, but at a modest level. Specifically, the automotive industry is expecting to continue the recovery that began in 2010. According to recent projections by JD Power, domestic auto sales in 2011 are expected to increase over 2010 levels by approximately 10%. Our remaining industrial classes are expecting more modest increases. Our industrial load grew at 7% in 2010 over 2,009, and we expect an additional 2% increase in 2011. In 2010, the average number of residential customers increased by about a 5% over the prior year. Due to continued high unemployment and a difficult housing market, we project residential growth in 2011 will be slightly less than 1% on a weather normalized basis. In the commercial sector, office vacancy rates in our principal metropolitan areas remain high at about 20%. While vacancy rates did stabilize during strengthen. Similar to the residential class, we expect the commercial sector to grow less than 1% in 2011. Our final FENG driver for 2011 is increased operating costs due to the Buck plant coming online and additional planned nuclear outage, increased employee benefit costs and normal inflationary impacts. These cost increases will be somewhat mitigated by cost reductions from our voluntary separation plan and office consolidation efforts. Moving to our commercial power segment, we expect a negative impact of around 0 point $9 Approximately 0 point 0 $5 to 0 point 0 $6 of this change is expected to come from annualizing the impact of the level of switching in 2010. We do not expect a significant change in switching levels in 2011. The balance of the year over year change in commercial power is primarily due to lower expected on more normal weather. Moving now to our International segment, we expect an approximate 0 point be approximately $100,000,000 higher due to increased debt balances and higher anticipated interest rates. Our adjusted effective tax rate is projected to be approximately 32% in 2011. Before I discuss our capital expenditures, let me mention our expected operating costs for 20 11. Our total company O and M, net of deferrals and cost recovery riders, is projected to grow between 3% and 4% in 2010 compared to 3,400,000,000 10. Since 2,007, our costs have increased an average annual rate of approximately 2%. We're pleased with our efforts to control our costs and we will remain focused as we anticipate additional cost pressures over the next several years from new plant additions. Next, I'll walk you through our capital expenditure projections. As you can see on Slide 11, we expect to spend $4,500,000,000 to $5,000,000,000 in 20.11, which is consistent with the $4,900,000,000 spent in 2010 and includes approximately $1,400,000,000 4.3 $1,000,000,000 per year for 20 122013, reflecting the wind down in capital spending associated with our modernization program. Over this period, we also anticipate that environmental spending will increase. As you know, the potential pending by the EPA could require us to install additional environmental controls and could result in the retirement of additional older coal fired units. Our system modernization efforts and related committed retirements have positioned us well for these compliance requirements. However, under certain scenarios, our capital expenditures for these environmental rules could total approximately $5,000,000,000 over the next 10 years. While very little environmental capital is expected to be spent in 2011, for planning purposes, we have included approximately $250,000,000 in $12,500,000,000 in 2013. This level of environmental capital is based upon a reasonable estimate of potential remediation needed for compliance with our current understanding of these anticipated rules. Our expectations primarily involve costs to update some of our current emission controls, mostly in the Carolinas and Indiana. We expect significant rate based growth in our regulated utilities as we finalize our modernization projects and look to recover our investments in customer rates. Rates. Depending on the timing of rate case activity, our system wide rate base of approximately $22,000,000,000 has the potential to grow to around $28,000,000,000 by the end of 20 13, principally in the Carolinas. Rate base beyond 2013 will be driven by future environmental expenditures and any new nuclear and natural gas generation investments. Finally, we continue to maintain a level of discretionary growth capital in both new renewable investments, smart grid development or opportunities in our international business. If we do not find return expectations, we will not invest this discretionary capital. Before we move on, I'd like to update you on our progress in exploring new nuclear development opportunities. In 2013, we anticipate receipt of our commercial operating license for the Lee Nuclear Station in South Carolina, targeting a potential in service date in the early 2020s. Last week, we finalized an agreement with Jacksonville Electric Authority, giving them an option to acquire up to 20% of the lease station, a demonstration of interest in new nuclear generation in our region. This agreement is consistent with our measured approach to reduce risk. We continue to pursue legislative frameworks in North Carolina such as cash quip, which is a must have for us to move forward with new nuclear plant investments. The modest amount of nuclear capital included in the Slide 12 reflects our anticipated rate case activity between now and 2013. In 2011, we plan to file in North and South Carolina to update our rates for additional capital investments made since our last rate case filings in 2,009. We are evaluating the potential for filing rate cases in Ohio and Kentucky during 11. The recently enacted bonus depreciation rules, which I'll discuss further in a moment, may diminish the immediate need for these rate cases. We will make that decision later this year. We also expect to file rate cases in 2012 as we complete our base load generation facilities. The timing of our filings in Indiana will depend on the outcome of our Edvard Sports proceedings. Slide 13 shows our anticipated operating and investing cash flows for 2011 as well as our anticipated sources of financing. Our estimated 20 11 CapEx of around $5,000,000,000 and the approximate 1,300,000,000 dollars required to fund the annual dividend are expected to exceed our cash sources. This deficit will be net by new debt issuances of around 2.2 $1,000,000,000 Scheduled 20 11 debt maturities are relatively low and most of our required funding will be satisfied through utility company and holding company financings. We will also evaluate pre funding of 2012 maturities if market conditions are favorable. During 2010, we raised approximately $285,000,000 from our internal equity plans. Because of the strong cash flows in 2010 and the strength of the balance sheet, we do not expect to issue equity through 2013 topics during this earnings season. 1st, bonus depreciation. Many of our current capital expenditure projects, including system modernization and renewable investments, qualify for bonus depreciation. Our best estimate is that over time, we could generate cumulative cash benefits between $1,500,000,000 $3,000,000,000 from these provisions. This is a broad range and reflects uncertainty over how the bonus depreciation rules will be applied. We are waiting for clarification from the U. S. Department of Treasury to determine which projects will qualify for 50% or for 100% bonus depreciation deductions. As we learn more, we will refine our estimates and share them with you. Of course, the timing of these cash benefits will depend on future taxable income. Even though bonus depreciation related to our regulated projects reduces rate base, the cash benefits will decrease our need for financings over time and help to mitigate future customer rate increases. Now I'll turn to pension funding. We expect to make contributions to our pension plans of $200,000,000 in 20.11. In 2010, we contributed $400,000,000 We pension protection act requirements. In closing, I'm very pleased with how we delivered financially during 2010, and we are positioned to achieve our targeted long term adjusted diluted earnings growth of 4% to 6% and our targeted dividend payout ratio of 65% to 70%. Now I'll turn it back over to Jim. Thank you, Lynn. Before I give you all a brief overview of our focus for the upcoming year, let me update you on our pending merger with Progress Energy, which we announced on utility unprecedented in size and scale, but size is not the only consideration. This transaction gives us the ability to more effectively manage the challenges we face today and the transformation now occurring in our industry. This will result in benefits for all our stakeholders, our customers, investors, employees and the communities we serve. Specifically, customers in the Carolinas will benefit from fuel and joint dispatch savings day 1. All of our customers will benefit over time from cost efficiencies as a consequence of the combination. Our investors will benefit from earnings accretion in year 1 and the strength of the combined balance sheet and dividend policy. Slide 15 contains a merger scorecard we will use throughout the year to provide you with updates on the status of our various filings and approvals. We expect to file our initial S-four with the SEC in March after the Form 10 ks is filed. Meetings to conduct shareholder approvals of the merger will be scheduled later in the year after we receive clearance from the SEC on the S-four. We are also finalizing various state and federal regulatory filings related to the merger and expect to file most of these beginning in mid March. In addition to state regulatory filings in the Carolinas, we anticipate filing with the Kentucky Commission for merger approval. Our merger teams have begun initial integration planning. To achieve earnings accretion in 2012, we must aggressively and relentlessly identify and pursue cost savings opportunities this year. Clearly, completion of the merger and integration planning with Progress Energy will be top priorities for us in the business and delivering for our investors, customers and communities. To do so, we'll maintain exceptional operational performance and efficient cost management. We delivered on our financial commitments in 20 continue this momentum and remain focused on our financial and operational performance during 2011. In our regulated business, in 2011, we will file rate cases in up to 4 of our jurisdictions driving for constructive regulatory outcomes. We'll maintain focus on our long term legislative agenda to effectively reduce the gap between our allowed and earned returns over time. In the short term, we are pursuing cash quit provisions for new nuclear investments in North Carolina. Our major construction projects are nearing completion with the first of these projects, the 6 20 Megawatt Bulk Combined Cycle Gas Unit, expect to come online in 2011. In Indiana, we're managing costs related to Edwards Board and working towards a a workable and constructive outcome with the Ohio Commission on our standard service offer, which would establish generation rates for 2012 and beyond. And Duke Energy Retail will continue to pursue customers and protect margins our international operations. Finally, we will continue to support the communities in which we operate, helping to drive economic development activities during these challenging times. 20 10 was a very successful year. As we look forward to our merger opportunity, our modernization projects and our commitment to both customer service and shareholder value, Duke Energy is poised to deliver superior long term performance in 2011 and the years beyond. With that, let's We'll go to Dan Akers with Credit Suisse. Jim, one of your other brethren in Ohio has been talking about the idea that potentially reevaluating SB221 from a legislative perspective later this year. I don't know if you have any thoughts on that issue and if that could potentially reshape how you guys are thinking about pursuing the MRO option? I think it is clear to us that the regulatory model in Ohio is broken. It in a way that's fair to both our customers and our investors. As I mentioned earlier, there's asymmetrical risk in Ohio today with respect to the impact it has on our investments and generation there. So I believe the time has come or is coming to make a change in the regulatory regime in Ohio. And you still believe that the Amaro route is the best option or it's just the best option available given the construct of SB221? I would consider it the best option available given the allows us to earn a fair return on the generation that we're required to stand by and provide if and when customers come back. In a sense, Dan, customers in Ohio have a free option. And as you know, in commercial markets, there are no free options. So we need to get the rules right so that we have an opportunity to earn a fair return on our generation. Okay. And then I guess there was a call recently and some talk potentially about reevaluating Edwards Port to the sense of just turning into a CCGT and stopping the full coal gasification process. Can you share your thoughts on that alternative and kind of the economics of that versus completing the project as designed? Well, I think the call you may be referencing, we weren't involved in, I think that was by the Sierra Club. Correct. And the fact of the matter is, we've done detailed analysis of a variety of options from shutting it down to on that track. We've done updated IRPs and virtually every one of them continue to say we need the capacity and that this is the best option for customers going forward. Okay. Just one last question. Just on the industrial demand outlook for 2011, the 2% growth, I mean, it seems like a lot of that 2% growth has already occurred just at the momentum of how 2010 played through. How would you handicap the likelihood of demand looking better than where you guys are for the year? And you get indications from your customers that would suggest 2% is the right number? Or is it more in the range of being conservative today? Dan, it will be interesting. I think we'll have more to say on that at the end of the first and second quarter. We think it's a reasonable estimate based on what we believe is happening in our territory as well as the discussion with our industrial customers, but more to come. Okay. Thank you, guys. Thank you. Thanks. We'll take our next question from Jonathan Arnold with Deutsche Bank. Hi, good morning. Good morning, Jonathan. A couple of questions. My first was in the Q3, you had numbers that implied about $0.13 above normal for weather through the Q3 and then another $0.03 or so in the Q4, but your annual factors show that as 13, but talk about it being net of a mechanism. Can you just explain how that works? Jonathan, what we did on the slide, I guess, Slide 10, is we actually netted the weather impact with the impact of incentive short term incentive payments that put us from target to maximum. Because as we look forward, we, of course, would plan that our incentives would be paid at a target level. So that difference between the 16 of weather that you're referencing and the 13 is the incentives. And the incentives that were related to weather sales or these are? Related to the fact that we went to maximum on our incentive payout and that was largely driven by weather. These are employee incentives. Sorry for not putting those together. And then how have you treated weather in 2011 because you obviously have had this very strong start to the Q1, I would guess? You're reflecting on that Northeastern weather, Jonathan? Something like that. We've had a little bit of that down here. We always plan for normal weather, which I think is the only thing to plan for. And so that's the planning assumption going into the year, and we'll update on how that looks as we progress. So the guidance has no where is weather normal for the year? It is. Okay. Thank you. Yes. And Jonathan, the other important point is, as you remember last year, we started out at a $125,000,000 $130,000,000 and as the weather kept improving and we were holding our costs down, we increased our guidance twice actually until ultimately to the $1.40 $1.45 that we will probably do the same thing if we're blessed to have the same weather this year as we did last year. Okay. Thank you for that. Can I on a sort of related guidance topic, I was wondering if you could provide some more granularity around the $0.14 growth you expect out of the utilities because we you say that net that costs are likely to be higher? And on my math sort of 1% sales growth maybe adds $0.02 or $0.03 at best of a $0.10 ish billion revenue number. So that kind of and you did say that the modernization program would be the largest piece of this. And it seems to imply a couple of 100,000,000 or more of EBIT coming out of the program. So can you talk through what specifically are the mechanisms that provide those revenues in 2011? Yes. And Jonathan, you need to think about a couple of things. Allowance for funds would be a part of that as one of the ways we recognize earnings for capital investments that's not yet in rates. And then we also have riders for Edwardsport. We have Quip Cash coming into the picture in 2011 for Cliffside. So Cliffside, it's Edwardsport, it's Buck and Dan River. We also have investments in our nuclear fleet. We have smart grid. We have energy efficiency. It's all of the programs that generate rider or allowance for funds revenue. And the I read the slide that the AFUDC might have been in the other category, but It is not. It's listed as other information, but it's actually reflected in FENG. Well, that's helpful. Thank you. And can I just finally, I didn't hear you specifically reiterate, but I'm wondering if you are reiterating the 4% to 6% growth target post merger off the 11 base? Yes. That's our long term growth aspiration, Jonathan, and we would be using 2011 as the base for the new company. Long term meaning? What do you think long term should mean? I'm not saying it. Yes. It's a really good point. Jonathan, I make the point of long term because it will vary from year to year as we have rate increases coming into effect, etcetera. And I know there is a lot of interest in us giving more specifics around 12. We're not prepared to give more specifics around 12 because all the activities that we have to accomplish here in 2011, including rate cases, MRO, closing of the merger, etcetera. But 4% to 6% is a very good planning assumption for us as we look forward. Okay. Thank you for that. Thank you, Lynn. Thank you, Jim. Thank you. We'll take our next question from Leslie Reich with JPMorgan. Thank you. I wondered if you could just touch on the international segment for a minute. You have projection growing 13% and wondered if you could talk about the drivers of that. I know you mentioned increased pricing in Brazil. Is that driven by an inflation adjustment? And sort of the earnings growth potential there? Because the earnings growth potential there? Because I see you're not really investing all that much capital in that area. Good questions, Leslie. We have actually some repricing in Brazil impacting 11 where we run a very contracted business in Brazil but have the opportunity to update prices over time. And so the single largest driver year over year is updated pricing in Brazil. We do expect our national methanol entity to continue to contribute about 20% of the earnings. That would be the other point that I would make. In terms of capital growth, we continue to designate capital. We have a few projects underway in our international business, one of which or a couple of which we would expect to come online in 2011. But that capital growth will really depend upon our ability to find projects that meet our risk appetite and return expectations. So, is that recontracting in Brazil sort of a one time thing or that's an annual repricing? There will be an annual feel to it, Leslie, because we have pricing on those contracts. If inflation starts to take off in Brazil, we have inflation protection. Okay. And then separately, if you could just discuss the strategic rationale between for filing to separate your Ohio generation into an affiliate? I think, Leslie, the thought here is it gives us flexibility and it's consistent with the MRO because the way the MRO works over time, you're moving toward and you start with a blend of your existing generation and market and over time it becomes increasing market. So at the end of the MRO period, your generation is free from being committed to the load. And so it's very important for us to move it out from under the regulated utility, so we have the flexibility to make decisions about what to do with those assets going forward. Okay. Thank you. Thank you. We'll take our next question from Brian Chin with Citigroup. Hi, good morning. Good morning. Jumping off a little bit on Leslie's last question. When you mentioned Jim that the transferring of the coal generating assets gives you a little bit more flexibility, I could take that 1 of 2 ways. I could think of it in terms of flexibility to manage your customer load. You don't have that polar requirement. But then I can also think of it as flexibility strategically to potentially separate out that generation fleet into a more merchant affiliate and do something more strategically with that business. So when you think about flexibility, the term flexibility, are you thinking about it in both senses of the word? Are you thinking about it more in one type or another? Can you just give a little bit more clarity on what you mean by that flexibility? Sure. I mean that's Brian, a good question. And let me start out by making the point. We if we had a bias, we would prefer to have our assets dedicated to the Ohio load and earn a fair return on that investment like a 10%, 10.5% or 11% return on equity. That's our first choice. And we've been clear with the commission that was our first choice. But if they're not going to allow us to earn that type of return, then we don't want the assets dedicated and we 1st, and that's why we selected MRO. And second, we want to get them out because the flexibility we're seeking is primarily to, at that point, make a decision with respect to whether we want to be in the merchant business or we want to sell the assets. And I would tell you my bias today is not to be in the merchant business, particularly in PJM. But again, the timing the decision about that will be something that will come in the future. The price of power in PJM is going to rise. Even if gas prices are flat, over time, demand will come back as the economy recovers. And secondly, and this is a fact that's been hard to quantify for many, as you get to see a retirement of the old coal plants as a consequence of the stricter newer regulations on coal plants, if that's going bias is to dedicate to kind of summarize this at a regulated return, but absent that is to free it and at appropriate time make a decision and our bias at the current time is not to be a merchant player and pursue that strategy, but to exit it. That's our current bias, but we won't make that decision until we have clear facts in future periods. Okay, very helpful. And then one separate question on your guidance. On Slide 19, you make the point that you're looking at annualized at that you're assuming that you're only getting the annualized impact of the 2010 switching levels, but you're not assuming any further switching since the switching appears to have levelized out in your 2011 numbers? Brian, we have a modest amount of increased switching, Okay. And then lastly, on the stabilization, what do you think has caused that to levelize out at such a flat rate? I think it's a reflection of the way switching occurred, Brian. So the more savvy energy users, the industrials and the commercials customers switched 1st. And now we're into the residential class. And frankly, we have not seen a lot of government aggregation, and our residential customers have proved to be sticky. We'll use that technical term. We'll take our next question from Steve Fleishman with Bank of America. Yes. Hi, good morning. Thanks. Good morning. Hi. Just a quick question on the bonus depreciation. So in the 20 11 cash flow forecast that you've included your current estimate? Yes. And the deferred taxes, okay. And when you talk about rate base, I think you've Are you encompassing the impact of dollars Are you encompassing the impact of the deferred taxes in that from bonus depreciation? We are. Okay. So that's a good net number of Aldis. Yes. And Steve, what I would say is the low end of the range would be included in that rate base adjustment. So when I talked about cash flow benefits of $1,500,000,000 to $3,000,000 we used the low end of the range for an estimate of the rate base. I'm sorry, I'm not sure what you mean by that. Yes. So let me try again. So we have a range of expectation of what can happen on bonus depreciation. If things qualify at a level of 50% or things qualify at a level of 100%. And there would be an associated impact to deferred income taxes at those two levels. Okay, got you. So you're using the low end in the when you talk about the rate base forecast? That's correct. Got you. Okay, thank you. Thanks so much. Thanks. We'll take our next question from Greg Gordon with Morgan Stanley. Thanks. Good Two questions, one sort of in the weeds and a little bit follow on to the prior question. It looks like you've also tweaked your CapEx budget a bit at least relative to the last specific disclosure, the 2012 CapEx range looks like it is $300,000,000 lower on the low end and $500,000,000 or $600,000,000 lower on the high end than you last disclosed. Should I presume that that's because I remember you saying that you had sort of a placeholder for discretionary CapEx in there. Should I presume that that's now gone? Or is it a lot more puts and takes that go into that? And then the second question is, I presume that's also factored into your rate base growth update. The answer to the question is, Greg, we do refine CapEx as we get closer in. And as 2011 and 2012 develop, we get more specific on the way we're thinking about it. We have made some adjustments on discretionary. We've also reflected environmental for the first time. So it's a combination of being closer in and more refined in our estimates. And the revised estimates are what are implied in the rate base numbers we just talked about. Great. And then the second question relates to the growth rate aspiration. I presume that the growth rate aspiration is predicated on the assumption that the merger does in fact close. And sort of you're looking at sort of the opportunities for the company pro form 11 as opposed to standalone post 11 when you support that growth rate? Greg, it's a good question. What I would say is that the merger really positions us more solidly within the growth range of 4% to 6%. As you know, we've got some weakness in Ohio. We've got repricing that's going to happen as a result of the MRO in 'twelve. So on a standalone basis, we would have been trending in the lower end of that range. So the merger gives us an opportunity to have greater confidence and position us more solidly within the range. We'll take our last question from Michael Lapides with Goldman Sachs. Congrats on a great quarter and a great year. I'm looking at Slide 24 and it's the estimated and actual ROEs at your various regulated businesses. And the only I guess historically Duke had been an industry leader in terms of actually earning at or even in some cases better than the authorized ROE levels. It looks like your 2011 outlook is kind of showing that you expect to under earn in a number of the jurisdictions, almost a little bit of a mean reversion towards kind of what most of your peers actually do in the industry. Just curious, is lag becoming more of a I think items or steps you guys can take to help mitigate lag? I'll take a shot and I'm sure Jim has some comments as well. I think 'eleven is an interesting year, Michael, in that we have no new rate cases coming in. And so we will have inflation impacts. We also have a slower load growth assumption that we might have had several years ago that would contribute to lower returns. But we believe over time, as we put these rate cases into effect and as we continue to work on legislative initiatives in our jurisdictions that we have an aspiration of closing that gap. We've targeted to be within 75 basis points in the Carolinas, and I think we'll be pretty close to that. So I think it's a combination of factors that are affecting us. No, I think that's correct. And of course, we probably have the largest building program in the country. I mean, we're building 2 advanced coal plants. We're building 2 in terms of closing the gap. But at the end of the day, what we recognize we need for a variety of reasons is to move toward formula rates. This is a good answer for investors. It's a good answer for consumers because as I mentioned a few moments ago, we're in a period of rising prices over the next several decades. Formula rates allows us to smooth out those cost increases. In the interim, what we would do if because it takes a while to get legislative changes. We're looking for riders for instance. Environmental riders would be very important to achieve in the states we operate in. And in fact, we have those riders in Indiana and Kentucky today meeting more stringent environmental requirements. So I think it's a combination long term of riders and trackers around specific items and morphing over time into formula rates. That would be the vision and certainly that would be the aspiration we have going forward. Okay. Thank you. Thank you. That concludes the question and answer session today. At this time, Mr. Stephen DeMay, I would like to turn the conference over to you for any additional or closing remarks. Okay. Thank you, and thank you everyone for joining us today. As always, the Investor Relations team is available for your follow-up questions. Thank you, and have a good day.