Conference Call Transcript

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Conference Call Transcript

DUK - Duke Energy Corporation Investor and Analyst Meeting

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C O R P O R A T E P A R T I C I P A N T S Stephen De May

Duke Energy Corp. - SVP - Investor Relations, Treasurer

Jim Rogers

Duke Energy Corp. - Chairman, President, CEO

Jim Turner

Duke Energy Corp. - Group Executive, President & COO - US Franchised Electric & Gas

Dhiaa Jamil

Duke Energy Corp. - Group Executive, Chief Generation Officer, Chief Nuclear Officer

Keith Trent

Duke Energy Corporation - Group Executive and President - Commercial Businesses

Lynn Good

Duke Energy Corporation - Group Executive, CFO

P R E S E N T A T I O N

Stephen De May - Duke Energy Corp. - SVP - Investor Relations, Treasurer

Welcome to Duke Energy's 2010 Investor and Analyst Meeting. My name is Stephen De May. I'm Senior Vice President, Treasurer and head of Investor Relations for the company. We're glad you could be with us today, and we look forward to an ongoing dialog with the messages you'll hear today.

Today's discussion is being webcast. It will include forward-looking information and the use of non-GAAP financial measures. You should refer to the information on this slide as well as additional information contained in our 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.

Now, let me describe today's format. In a moment, I'll turn the program over to Jim Rogers, our Chairman, President and CEO, who will open the meeting by reviewing our 2009 accomplishments and providing the strategic framework for this morning's presentations.

Following Jim, several of our senior executives, whom I will introduce shortly, will walk through the different parts of our business. We'll take a couple of questions after each section, but we've reserved time at the end of the meeting for the entire team to take your questions. Since today's meeting is being webcast, please wait for a microphone to be presented before asking a question.

I'd like to start of today's discussion with an overview of Duke Energy's business mix and corporate structure, which will provide helpful context for the presentations that follow. Looking first to slide five, you can see Duke Energy's current portfolio broken out by each of three business segments. You'll note that three-quarters of our business mix is associated with the regulated utilities in Franchised Electric & Gas, our largest business segment.

FE&G operates 27,000 megawatts of generation and transmits, distributes and sells electricity in five states. It also transports and sells natural gas in southwestern Ohio and northern Kentucky. Our Commercial Power segment operates 7,600 megawatts of non-regulated generation in the Midwest. That segment also has wind assets in various parts of the country and recently announced its first solar project.

Finally, our International Energy segment operates 4,000 megawatts of generation facilities in Latin America and also owns an equity investment in National Methanol Company located in Saudi Arabia. During today's presentation, you will hear references to both the business segments I've just described as well as our operating companies. This slide visually depicts the relationship between these entities. As you can see, our business segments are portrayed by the organizational chart and our primary legal, or operating companies, are portrayed by the gray boxes to the left of the organization chart.

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Our primary operating companies include Duke Energy Carolinas, Duke Energy Indiana and Duke Energy Ohio, which is the parent of Duke Energy Kentucky. These entities, along with the Duke Energy Holding Company shown at the top, are also SEC registrants. One of the most helpful aspects of this graphic is that it shows how Duke Ohio uniquely incorporates businesses from both our FE&G and Commercial Power segments.

Now it is my pleasure to present today's speakers, all of whom are group executives of Duke Energy and report directly to Jim Rogers. After Jim's opening remarks, you'll hear first from Jim Turner. Jim is the president and chief operating officer of the FE&G segment. His responsibilities are summarized on this slide, as they are for each of our speakers.

Next up will be Dhiaa Jamil. Dhiaa is chief generation officer and chief nuclear officer for Duke Energy, encompassing the entire regulated generation fleet. After Dhiaa, you will hear from Keith Trent. Keith is president of Duke Energy's commercial businesses, which includes the Commercial Power and International Energy segments I described a moment ago.

Our final presentation this morning comes from Lynn Good. As Duke Energy's chief financial officer, Lynn's oversight spans the traditional finance related functions. Finally, I would also like to introduce Marc Manly, sitting here in the front. Marc is group executive and chief legal officer for Duke Energy. He will join the others for the general Q&A session at the back end of the meeting. Thank you again for joining us this morning, and now I'd like to introduce our president and chief executive officer, Jim Rogers. Jim?

Jim Rogers - Duke Energy Corp. - Chairman, President, CEO

Thank you, Stephen, and thank you, all, for joining us this morning on what may turn out to be a very snowy day. This global cooling is beginning to be a problem, particularly for our politicians in Washington.

We really appreciate your interest our company and for your investment in Duke Energy. We're going to work very hard today to follow the script. In fact, they told me I've already deviated from the script. This will be my last deviation.

Then -- we have worked very hard, and I want you to hang on every word that we say because every word has been edited and re-edited about eight times. But, we think we'll be far more effective in getting the message to you in a clear way by following the script and then leaving plenty of time for Q&A at the end of the period -- end of our presentation.

Before I provide an overview of today's session, let me briefly summarize our year-end results. As you can see when the glasses go on, I am very close to the script. As you saw in our earnings release on Friday, we announced adjusted-diluted earnings per share for 2009 of $1.22 compared to $1.21 for '08.

Those results exceeded our 2009 employee incentive target of $1.20 on an adjusted-diluted earnings per share basis. I am proud of our performance in the face of a tough economy. Our employees made this happen last year. I appreciate their commitment, dedication and hard work and in one word to them, thanks.

Also, it was a difficult and challenging year for our customers, our entire industry and for us. Our retail load was down approximately 4% in '09 compared to '08. The greatest decline, just over 14%, was in our industrial sector as we saw manufacturing operations react to the recession by reducing production. We dealt with the economic challenge by continuing to focus on what we control, managing our costs and optimizing our operations.

During 2009, we effectively managed our costs by exceeding our $150 million target for O&M reductions, and we did this while maintaining our operational excellence, as you will see later from Jim and Dhiaa. During the year, our customer satisfaction levels remained significantly higher than the national average and our nuclear and fossil generation fleets had one of their best years ever. Turning to 2010, today we're announcing an earnings outlook of $1.25 to $1.30 EPS on an adjusted-diluted basis. The midpoint of this outlook represents a 4% to 5% increase from our 2009 results.

In past years, we have provided a point that represented our employee incentive target. With today's presentation, we will begin to provide an earnings guidance range. This conforms with what you're used to seeing from our industry peers.

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We expect to see growth in our regulated businesses as we realize the base rate increases that were recently approved in the Carolinas, Ohio and Kentucky. The economic environment our customers experienced last year made it difficult for us to ask for these rate increases. However, the settlements we achieved allowed us to begin to earn a return on and recovery of our capital investments in a timely and constructive way. Looking at the economy, we expect the recovery in 2010 to be anemic. We are projecting 2010 load growth on a weather-normalized basis to be essentially flat with 2009, and we expect power prices in competitive markets where we operate to remain low and at a zip code of the prices we saw in 2009.

These expectations lead us to our 2010 earnings outlook. In her presentation, Lynn will give you the details and assumptions for this outlook as well as our long-term growth objectives. Now, I would like to give you a more detailed perspective on 2009 and how it sets us up for 2010 and beyond.

Last year, we delivered on what we said we would do. As I noted earlier, we've reached negotiated settlements in North Carolina, South Carolina, Ohio and Kentucky. We made significant progress on our two largest capital projects, Cliffside in North Carolina and Edwardsport in Indiana. These two projects are the lynch pins of our fleet-modernization strategy as they will enable us to retire nearly 1,200 megawatts of older, less efficient coal units. Our modernization strategy is further advanced by the construction of our two new gas-fired plants, Buck and Dan River in North Carolina.

We're getting traction on our Smart Grid and energy-efficiency initiatives, including major deployment of smart meters in Ohio. Jim will update you on our major modernization and new initiatives in each of our five regulated jurisdictions.

We continue to manage through the recession, and we call it a recession because the anemic recovery feels like a recession. We mitigated the margin pressure from increased competition in Ohio, from falling commodity prices with the rapid deployment of Duke Energy Retail Sales. Keith will take you through our retail strategy in Ohio as well as the strategy for the remainder of our diverse Commercial Power businesses and International operation, which exceeded their 2009 adjusted segment EBIT target by a combined $70 million.

As we focused on managing our costs in '09, we also began repositioning our company for 2010 and beyond. Our goal is to continue to take incremental and sustainable O&M cost out our business in '10. We have already taken such steps this year with our voluntary severance program for employees and with the announcement of further consolidation of our corporate functions.

However, I can assure you we will not sacrifice our track record of operational excellence and high customer satisfaction to achieve our cost-reduction objectives. We understand, and we understand it deeply, that excellence in operations and high customer-satisfaction levels drive our regulatory and financial results as well as the cost of our product.

As we were in '09, we will continue to be focused on balancing our affordable, reliable and environmental goals. We are convinced our business sustainable performance is in getting that balance right, and the truth of the matter is it's more art than science.

We've continued to protect the strength of our balance sheet. With our modernization strategy, capital is our lifeblood and we must maintain superior access to the capital markets. We issued $3.75 billion of fixed-rate debt of 5.2% during '09. In the last two years we've raised more than $7 billion of fixed-rate debt at attractive rates and terms, and we issued $600 million in equity through our DRIP plans.

Our total shareholder return was up 22% for the year in '09. That compares favorably with the Philadelphia Utility Index, made up primarily of our peers, which was up only 10%. For the past three years, we have posted a positive shareholder return of around 4% while the Utility Index actually dropped almost 5% even though, and I think this is a remarkable fact, our adjusted earnings have been essentially flat, over the last three years, we grew our dividend an average of approximately 4% each year during this recessionary period, probably a tougher economic time than our country has experienced since the Depression.

We also maintained a 5% to 6% dividend yield last year. With 2009 in the rear view mirror, let me summarize our focus and goals for 2010 and beyond. This slide illustrates our strategies for modernizing our regulated infrastructure and for maximizing diverse earnings from our commercial businesses.

This focus will help us maintain our financial strength in a future that is more certain than we have ever faced before. If we can anticipate and shape inevitable changes in future state and federal policies, we believe we will differentiate ourselves from others in our sector.

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Let me give you all an example. In our regulated and commercial operations, we expect an array of tighter and more stringent environmental regulations from the U.S. EPA. As a result, coal generators will face difficult decisions on whether to spend incremental capital to retrofit or just shut down existing coal units.

Additionally, Congress continues to debate greenhouse gas legislation. If Congress fails to act, and in all likelihood they won't this year or maybe next year, but in any event we expect the US EPA to attempt to regulate carbon emissions beginning sometime in the next several years. Despite the uncertainty of these new regulations, we expect to retire 3,200 megawatts of older fossil generation in our domestic regulated fleet by 2020 as well as almost an additional 900 megawatts in our domestic commercial generation fleet.

To meet this challenge, we're the only company in the U.S. currently building two baseload coal units, Cliffside and Edwardsport, with 825 and 630 megawatts respectively. These plants will be some of the cleanest and most efficient in the US.

As I noted, we are also adding two new 620-megawatt gas plants, Buck and Dan River. We are doing this when the cost of capital is low, and it can only increase in the future in our judgment. This build-out will allow us to smooth out and reduce future rate increases on our customers. In my view, this will prove to be a major differentiator for our company. It will be an example of creating a win/win for our customers as well as our investors. We believe that closing the gap between allowed and earned rates of return is critical, particularly in this period of high capital spending.

We will continue to manage our costs and exercise discipline on our capital-allocation process, and I really want to underscore those two points. We will continue to seek timely and constructing regulatory and legislative outcomes directed at approving our earned returns.

But, the reality is we must close the gap between our allowed and earned returns. This is, in my judgment, job one for our regulatory team. I recognize that this will not be an overnight success. Changing the regulatory paradigm takes time in all of our five jurisdictions. We have a sense of urgency, but we've also balanced it with the patience required to get the job done, and I'm confident that we will.

In our commercial businesses, we own a diversified mix of generation ranging from about 3,600 megawatts of gas in the Midwest, 4,000 megawatts of hydro and gas in Latin America and almost 750 megawatts of wind across the US as well as approximately 4,000 megawatts or primarily coal assets in Ohio, an important set of assets serving our load in Ohio.

As we move to a future where power generation is going to be required to have an even smaller emissions footprint, we believe our lower carbon commercial generation will continue to increase in value and, as you know, we are pursuing growth in renewable generation, which we will -- which we believe will also position us well for this future where there's lower carbon, our SOX, our NOx, our mercury.

There are going to be tighter regulations on emissions from power plants in the future. In our judgment, that is inevitable. Our challenges in our commercial businesses are in Ohio, I suspect you might have a question or two about that, and our response to its competitive environment. Additionally, we must be disciplined in our capital-allocation decisions for these businesses to ensure that we are earning the appropriate risk-adjusted returns on our growth projects. For the commercial team this, in my judgment, is job one.

Our commercial businesses have been, and continue to be, meaningful contributors to our earnings and growth opportunities. The businesses provide us with options for growth, which we can dial up or we can dial it down, depending on the quality of the investment opportunities. This flexibility will be of great value in the years ahead for both our investors and our customers.

Our diverse portfolio of regulated and commercial business provide us with options for capital rotation, including joint ventures, sales and the repatriation of cash from our foreign operations as opportunities arise. We will continue to evaluate all of these options and make decisions that we believe will best position Duke Energy for the future.

Overall, this slide illustrates what sets us apart from our peers. We have a strong portfolio of regulated and commercial businesses. We are growing these businesses by investing capital efficiently to modernize our infrastructure and to earn competitive returns.

We have the constructive regulatory and environmental and public policy skills to execute on our investments in capital recovery strategies and, importantly, we have the management agility to operate in what I believe will be unprecedented, uncertain times.

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But also we're clear, and I hope if there's any message you take out of today's presentation, is that we are clear on what must get done and what our priorities are going forward. I believe all of these attributes will lead to future earnings and dividend growth.

Let me conclude this strategic context by taking a moment and kind of outlining what our presenters will drill down into today. Jim will discuss our modernization strategy, particularly given recent demand trends, which may have raised questions about our assumptions. He will also provide you with an outlook for future ratemaking activity, and he will describe how we will earn closer to our allowed rates of returns.

Dhiaa will describe our regulated power-generation operations and steps we have taken to prepare for an uncertain future, most likely involving more stringent environmental regulations that I've talked about earlier.

Keith will begin a discussion of our commercial businesses that over the next year will give you even greater visibility into the earnings and growth potentials of these segments. He will outline our strategy for delivering earnings growth and strong cash flows and solid returns from these businesses, and Lynn will provide you with the actions that support our ability to achieve our long-term growth and financial objectives. As I said a moment ago and I want to emphasize now, we want you to leave today with an even clearer understanding of how we plan to grow our business by achieving our mission of providing energy that is affordable, reliable and clean and, equally important, by redefining the boundaries of our existing business models. With that, let me turn it over to Jim to take through our Franchised Electric & Gas operations. Jim?

Jim Turner - Duke Energy Corp. - Group Executive, President & COO - US Franchised Electric & Gas

Thanks, Jim. Good morning, everybody. Apparently my colleagues have started a wager on whether I get this done in 30 minutes, my allotted time, so if you want to get in on the action send Stephen De May an email, but you have to do it within 15 minutes. Then, the window closes. As Jim mentioned, today's Franchised Electric & Gas presentation is going to be in two parts. I'll give you an overview of the strategic priorities of our regulated businesses, including the fleet and grid modernization strategy and our regulatory initiatives.

Then, Dhiaa will describe the strong operational performance of our generation fleet and how we're planning to meet ongoing environmental challenges. Dhiaa's also going to briefly update you on the progress of our two new nuclear plants that we're looking at constructing.

Today's discussion is necessarily forward-looking, but I wanted to pause a moment to add my thanks to our employees, for their strong performance in 2009. In our regulated businesses, we had one of the best years ever from an operations standpoint, from the availability of our generation fleet to the reliability of our power delivery system, and we did this while holding operating and maintenance expense flat versus 2008.

We achieved best-ever results on safety, continuing a three-year trend that is moving us closer and closer to the reality of a zero-injury culture, and we delivered solid regulatory outcomes in an economic environment and a regulatory climate that proved to be less than hospitable to utility rate increases.

So, I begin my remarks this morning with thanks to the men and women who make their executive team very proud to stand before you this morning and talk about the company. I'd also like to give you a direct line of sight now into the things we're doing to position our company and our regulated business in this very dynamic environment for utilities.

Let me first highlight the four components of the value proposition for our regulated businesses. The first component is the successful deployment of capital to modernize our generation fleet and our power delivery system. These efforts are fundamental to our enhanced mission and help explain why our capital needs, even in a challenging economy, have remained relatively robust. You will see from Dhiaa's profile of our generating fleet, why plant requirements and not just load growth make fleet modernization critical to our future.

The second element of our value proposition is constructive regulatory outcomes. This, of course, is where the rubber meets the road for regulated businesses. Said another way, our fleet and grid modernization efforts are only as good as our ability to recover the investments in an adequate and timely manner. As you will see, we've identified regulatory lag as a key issue that will occupy our focus and attention going forward. Jim, did you say that was job two, or job one? The third component --

Job one -- the third component of our value proposition is operational excellence. The bottom line here is its strong operational performance is important for our customers, but it also helps underpin our active regulatory agenda.

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The fourth component of our strategic value proposition, revenue growth and diversification, encompasses the way we are working to grow revenue other than by pushing kilowatt hours through existing retail meters, including energy-efficiency products and services, wholesale origination and our economic development efforts.

So turning now to the first component of our strategic value proposition, as Jim said and as you know, we're in the midst of a significant capital building program to modernize our generation fleet and power delivery grid. Some of you have asked why our capital needs for new generation resources remain robust even as our load growth has fallen off in a recessionary economy.

Of course, we build power plants to meet the long-term needs of our customers, and although the recessionary economy has impacted our near-term load projections we, nevertheless, expect and we need to plan for growth in our peak demand to continue over the long near-term. More importantly, as this chart shows, the new generating units are necessary not simply to meet projected load growth but to replace the significant number of megawatts we will be retiring both in the Carolinas and the Midwest over the next decade.

In both the Carolinas and the Midwest, our need for new capacity is driven by a combination of growth in peak demand and the replacement of older, less efficient power plants. It's been over 20 years since we completed our last major build phase for new power plants with our most recent baseload plant in the Carolinas coming on line in 1986 and the most recent plant in Indiana coming on line in 1982.

In the Carolinas chart, you can see we plan to add a diverse mix of resources to our portfolio during the next five years with the largest single contributor being our Cliffside advanced, coal-fired generation project at 825 megawatts. Now, I'll have more to say about the status of the Cliffside construction in a moment, but I should note that late last year the North Carolina Utilities Commission reinforced the need for this resource in two significant ways.

First, the Commission rejected an environmental group's challenge that the Certificate of Public Convenience and Necessity for the plant should be revoked in light of the recessionary economy and softening of demand. Second, the Commission's order on our North Carolina rate case approved the addition of CWIP for Cliffside in our base case. These two orders serve as strong confirmation of our Cliffside modernization strategy for the Carolinas.

The other resource additions in the Carolinas are the combined-cycle gas plants we're building at our existing Buck and Dan River Stations, respectively. Together, these plants will add approximately 1,240 megawatts of capacity to our system. I'll discuss the status of the construction of the projects in detail in a moment.

Finally, in the Carolinas we plan to add about 365 megawatts through a diverse mix of renewable capacity, primarily PPAs, for compliance with North Carolina's Renewable Portfolio Standards. As part of our renewable strategy, we've received approval to invest $50 million in a first-of-its kind roof-top solar program in North Carolina.

Again, our modernization efforts are not just about adding resources. We expect to retire over 2,000 megawatts of coal and old fleet CTs in the Carolinas through 2020. We're showing retirements through 2020 on this graph because this captures all retirements resulting from commitments linked directly to the Cliffside modernization project as well as additional retirements currently being modeled in our integrated resource plant. Turning to Indiana, you can see that the addition of the 630-megawatt Edwardsport IGCC plant accounts for the vast majority of resource additions during this time period. With our Indiana modernization plan we have over 500 megawatts of coal-fired generation that will likely be retired or moth-balled between now and 2020 with an additional 600 megawatts of unscrubbed coal under evaluation for possible retirement. Before we leave this slide, I should note that our integrated resource plans also include robust expectations for energy efficiency as well, part of our broader objective to achieve a resource mix that enables us to meet the needs of our customers with affordable, reliable and increasingly clean electricity.

So, while we're on the status of our new plants let me update you on the status of our construction. As I mentioned, our new clean coal plant in Edwardsport, Indiana, is a 630-megawatt, integrated gasification and combined-cycle facility that will come on line in 2012. Edwardsport will be, in my opinion, the cleanest coal plant in the world.

It will emit less sulfur dioxide, nitrogen oxides and particulates than the old power plant it replaces while providing ten times more power than the existing plant. The IGCC technology also provides an opportunity for us to explore pre-combustion carbon capture as well as potential storage

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for sequestration of the CO2 recapture. We're approximately 50% complete with the construction of the base plant and we've incurred about $1.3 billion in costs, including AFUDC through December 2009.

Now, during 2009 we receive a number of constructive regulatory rulings on Edwardsport, including approval in January 2009 of an updated construction estimate of $2.35 billion and approval of multiple updates to our IGCC CWIP rider.

In November 2009, we notified the IURC that design modifications and scope growth will increase the project estimate by approximately $150 million plus an appropriate level of contingency above the $2.35 billion previously approved by the IURC.

Last month, the IURC approved our request to address this cost estimate revision through a separate sub-docket. We continue to refine the cost estimate and will file testimony in April 2010. The IURC will conduct a hearing on this matter in August.

We'll put forward a strong case demonstrating the reasons for and the reasonableness of the requested increase in the estimate and, of course, we will continue to work hard with our vendors to find ways to mitigate the cost pressures and bring this plant in at the lowest possible cost for our customers. I should also note that we continue to address carbon capture and storage related to the Edwardsport plant in separate sub-dockets. Turning now to our Cliffside coal plant under construction in North Carolina, the project is over 55% complete and we continue to be within our budget and expect the plant to come on line in 2012. I mentioned earlier the favorable North Carolina regulatory outcomes during 2009 related to Cliffside. I should mention that the South Carolina Commission also authorized CWIP recovery in our rate case there.

Turning now to our Buck and Dan River gas-fired projects in North Carolina, each project represents 620 megawatts of combined-cycle capacity. Both plants have already received the necessary CPCNs and air permits. In 2009, we broke ground on the Buck construction and we began site preparation work at Dan River. We're on track for the Buck and Dan River projects to come on line in 2011 and 2012, respectively.

Now, let me briefly direct your attention to the right side of the -- of this chart as well, which represents the other prong of our modernization strategy, what we call grid modernization. This is -- there's certainly a lot of talk, and even hype, about Smart Grid these days. I want to take a moment to de-hype, and hopefully de-mystify, the concept.

For Duke Energy, Smart Grid is an opportunity to harness digital technology to enable two-way communications with our customers and advance a number of tangible enhancements to our service delivery, improved outage detection and service restoration, deployment of self-healing circuits that can instantaneously reroute power to minimize outage footprints and reduced O&M costs related to tasks such as meter reading and service connects and disconnects.

Over time, a smarter grid will enable our customers to better optimize their energy use through energy-management systems, smart appliances and time-of-use rates, and we've been planning to invest up to $1 billion on Smart Grid over the next five years. Through December 2009, we've invested approximately $90 million of that in limited-scale deployments of Smart Grid across our service areas.

Our initial focus for a full-scale deployment is on Ohio, where we expect to install 140,000 smart meters in 2010, growing to a five-year total to install -- five-year total of 1 million smart meters, both gas and electric, and associated communications technology. Our Smart Grid investments in Ohio, representing about $450 million over five years, will be authorized in a timely fashion as a result of the annual tracker that was authorized in our Electric Security Plan.

In Indiana, our plans to invest a comparable amount over five years ran into a speed bump in late 2009 when the Indiana Utility Regulatory Commission issued an order denying our Smart Grid deployment plan. We've been working with the settling parties in our Smart Grid case to address the IURC's concerns, and we anticipate coming back to the Commission with a scaled-down version of our plan in the near future. Obviously, this will reduce the $1 billion for Smart Grid shown on this graph.

Finally, we're evaluating the best way to leverage the $200 million we were awarded in federal stimulus funds for our Midwest Smart Grid deployment to reduce the cost of deployment for customers. This slide serves as a snapshot of the strength of the regulatory environment in which we operate. On the left side, we've listed key accomplishments during 2009. I've touched on a couple of these outcomes already, but I want to reinforce that we advanced the ball on a number of fronts during the past year, again, a year in which regulatory initiatives were not always greeted with open arms and a warm embrace.

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I'm pleased with the favorable rate case outcomes that will add nearly $460 million in revenue upon full implementation but I'm especially pleased that these outcomes, tough regulatory climate and all, were the product of settlement agreements with all or nearly all of the parties to these proceedings. In my opinion, this reinforces the constructive nature of the jurisdictions in which we operate.

But the past is not necessarily prologue, and even though our jurisdictions generally rank well as constructive places to do business we know we've got work to do, particularly in a time of significant capital deployment, to continue closing the gap between the time we invest our capital and the time it takes to recover that investment. In a moment, I'll discuss how we're planning to do that.

First, not that this audience needs any reminder, let me provide some context for addressing why regulatory lag is so important to us. This graph shows that we expect to grow rate base by about $8 billion between 2009 and 2014. This growth is driven primarily by the fleet and grid expansion plans I discussed earlier as well as the sizable annual capital investments necessary to maintain our power plants and our power delivery system and CapEx necessary to add new customers to our system.

Over time, our anticipated rate base growth will create a significant earnings platform, but we know this platform is most attractive to you when it actually is generating earnings and even cash. The next slide will show the work we have in front of us to close the regulatory gap.

This slide compares our current authorized returns on equity in each of our states to the expected earned ROEs in 2010. Let me make a couple of clarifying points about this chart. The ROE specified for Ohio, as you saw from Stephen's earlier slide this morning, is for the electric and gas transmission and distribution part of the business.

The ROE earned by the power generation part of the business in Ohio is not included here. Those earnings are reflected in the Commercial Business results under Keith. Keith will discuss Ohio with you in detail a little later.

The shaded ranges in the chart reflect the anticipated earned ROEs based on our forecasts for 2010. Let me also note that the forecasted achieved return on -- for Kentucky includes the vertically integrated electric utility and the gas distribution business.

As you know, we recently received a favorable order on our gas rate case, which we settled last year for $13 million. This represented about 75% of what we filed for. Clearly, though the result on our gas rate case was positive, we have more work to do to address regulatory lag in Kentucky. As you'll see in a moment, we are expecting to file an electric base rate case in Kentucky later this year with rates effective in 2011. Now regulatory lag is not a new phenomenon in our industry, but we are determined to minimize its impact as the next two slides with discuss. One way to address regulatory lag is through the regular filing of rate cases. This chart reflects the anticipated rate case activity we believe will be needed to help improve the timely recovery of capital investments and operating expenses between now and 2014.

The empty boxes reflect anticipated future revenue changes. For obvious reasons, the timing of future rate cases is not set in stone, but this should give you some sense for what to expect in the coming years. Obviously, it's a busy regulatory calendar. For 2010, in particular, we plan to file the electric rate case in Kentucky I just mentioned and we are evaluating a rate case filing in Indiana as well.

The rate case activity anticipated during this period will be a key lever to mitigate the regulatory lag associated with rapid infrastructure growth but we are acutely aware that the revenue produced, even from frequent rate cases, doesn't always keep up with the pace of expenditures. That's why we've worked to create mechanisms that result in the more timely recovery of our costs. Edwardsport in Indiana and Smart Grid in Ohio come immediately to mind. We're working to give ourselves more of these kinds of levers in all of our jurisdictions.

I'll note that in the recently completed North Carolina rate case we negotiated the settlement of a rider where we're collecting essentially the extra financing costs, extra carrying costs, associated with our increased fuel inventory, which built up during the recessionary economy. So, this slide gives you some insight into the regulatory and legislative activities we're evaluating and looking to pursue in each jurisdiction in addition to the rate cases discussed on the previous chart.

You'll note that the Carolinas historically have made limited use of rate rider recovery mechanisms due to statutory limitations and regulatory norms, so we expect to work with policy makers and stakeholders during 2010 to create potential legislation for 2011 that will give us and our regulators more tools to address lag.

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Such tools may include formula rates, forward-looking test years, decoupling and other rider mechanisms. As we've said before, in North Carolina we need specific statutory changes to enable CWIP cash recovery outside of a rate case to advance our proposed new Lee Nuclear plant that Dhiaa will discuss with you in a moment. I should note that South Carolina has already enacted a law that enables such CWIP recovery for new nuclear outside of a rate case.

Of course, when we are talking about the need for legislative changes there are no guarantees of success, but you do have our commitment that we will be working in every jurisdiction to reduce the earnings attrition attributable to regulatory lag. By the way, these mechanisms benefit consumers as well by reducing our financing costs and smoothing out the effective rate increases over time.

Of course, rate cases and rider mechanisms are not the only way to address earnings attrition. Aggressive cost management is another tool for minimizing lag, and you'll see in a moment this is another area that has our focus.

As for the balance of our regulatory and legislative agenda, you can see that rate cases will not be the only thing occupying our attention. With approval of our modified save-a-watt plan for energy efficiency in four of our five states, Indiana's order was issued just last week, we will work to continue to evolve the manner in which we make energy efficiency, both demand management and energy conservation, important components of our long-term resource plan.

In particular, we remain committed to ensuring that the recovery of energy efficiency investments is on a level playing field with the recovery of our investments in generation resources so that energy efficiency creates value for both customers and shareholders.

With a busy regulatory agenda, we are more committed than ever to delivering on the third prong of our strategic value proposition, operational excellence. We know that satisfied customers do not guarantee the success of our regulatory and legislative agenda, but we also know that dissatisfied customers and regulators can make that agenda a lot more difficult.

This slide captures a few key elements of our scorecard that are relevant to regulators and customers, rates, reliability and customer satisfaction. Our rate competitiveness is driven in large part by resource decisions made decades ago, which explains why we feel so strongly about the fleet modernization decisions we are making today to position us for the future. We know we will face upward pressure on rates as we modernize our system, but we remain committed to preserving the affordability of our product in the regions that we serve.

One of the key tools we have for keeping our rates competitive and mitigating regulatory lag is cost management. Some of you have commented on the fact that our EPS has been flattish since 2007, attributable in large part to the severe economic downturn that began in 2008.

We've worked to do our part by keeping our operating and maintenance costs flat for three years, essentially absorbing inflation during this period. I should note that our cost management efforts have been generally ubiquitous throughout the segment and have not depended upon large, one-time items.

As we move into 2010, we continue to be focused on achieving sustainable cost reductions that will serve as one key enabler for our regulated business to preserve margins as we navigate through the lingering effects of the recession. Although we do expect that 2010 O&M costs will be higher than 2009 for the regulated business, the anticipated increase will be driven primarily by costs that have deferral or recovery mechanisms associated with them and thus are bottom-line neutral to the Company.

Now, I've grouped together seemingly -- several seemingly disparate items, energy efficiency, wholesale origination and economic development under the fourth and final component of our strategic value proposition, so let me explain what I believe to be the common denominator here. With the upward pressure on retail rates I described earlier, we're focused on delivering sources of revenue growth that do not depend on pushing kilowatt hours through existing retail meters.

Energy efficiency where we're compensated for reduced sales, wholesale origination where we mitigate retail rates by spreading the fixed costs of our business over a larger regional footprint and economic development where we spread the fixed costs of our business over a larger retail footprint are three tools for accomplishing this growth and diversification.

I should note that we had a significant success in wholesale origination in 2009 when we signed up a large co-op in South Carolina to a long-term deal that will grow to approximately 1,000 megawatts of new load by 2019. We also continue to enjoy success, even in a sluggish economy, in attracting new load to our retail service territories through our focused and award-winning economy development efforts.

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So, let me close by saying we know we have a lot on our plate but we also believe we have the right focus and, more importantly, the right people to deliver on our strategic value proposition. Now, I'll be happy to take a couple of clarifying questions right now, and as Jim and Stephen both said, there's going to be plenty of time for questions for all of us at the end. So with that --?

Q U E S T I O N A N D A N S W E R

Unidentified Audience Member

What's the biggest driver of (inaudible - microphone inaccessible)

Jim Turner - Duke Energy Corp. - Group Executive, President & COO - US Franchised Electric & Gas Can you repeat it again?

Yes. What's the biggest driver of the gap between allowed return and earned return? And, what are you doing to address that?

One of the largest gaps, one of the things that creates regulatory lag the most, are the capital expenditures, for example, on maintaining our power delivery system in our generating plants that close to rate base very quickly. These are not like our long lead-time items such as the big power plants where we accumulate AFUDC. These items close the rate base very quickly and therefore impact our depreciation expense very quickly, and it's hard to keep up with it, even through regular rate case filings.

The other thing is rate cases look backwards. When you set your retail rates you look backwards in time for a test-year level of expenses, so expenses that go forward from the rate case obviously will then impact your regulatory lag as well.

So what we're looking at are a number of tools, and again we'll be working through the legislative process in North Carolina and we're working in other states to try to close that gap as much as we can, either through forward-looking test years or formula rates. Ultimately, we may look at something like decoupling.

So if your sales go down for example, if your sales go down from what you said in the test year, that's going to impact regulatory lag. There are a number of drivers. We're focused on all of the drivers and putting the right tools in place to hit them all. Just a second, Carl, there's one from the back.

Could you tell us how much of your O&M is cost recovery and then what you expect that percentage to be going forward?

I don't know if I have the exact amount of that's cost recovery, but what you're looking at are things like environmental reagents in our power plants. We have a storm deferral that was created in the Midwest related to Hurricane Ike from 2008, so those are the kinds of things that you'd see in both our deferred or our -- well, in our deferral bucket, as you -- if you will. So, these are things that are not impacting the bottom line. It's not a significant chunk of the O&M, but it's fairly sizable. But, it's not the -- certainly not the majority.

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So if cause is very insignificant, could you take out 10% next year and have it sustainable?

Jim Turner - Duke Energy Corp. - Group Executive, President & COO - US Franchised Electric & Gas Of the O&M?

Unidentified Audience Member Overall O&M number?

Jim Turner - Duke Energy Corp. - Group Executive, President & COO - US Franchised Electric & Gas Are you talking for the entire pot? Or, are you talking about the deferral or recoverable bucket?

Unidentified Audience Member (inaudible - microphone inaccessible)

We are -- we're very focused, and Lynn's going to have some discussion about O&M as well, we're very focused on keeping our O&M flat or even reducing our O&M. We have the voluntary severance plan that Jim mentioned earlier that will be a key focus for us in 2010. We've -- we're putting pressure on every part of our business to take costs out. Ten percent may be a bridge too far, but I will tell you we are very focused on driving the cost down. Carl?

Jim, can you identify the depreciated value of the plants that will be retired when Edwardsport and Cliffside come on so that that would be the -- we could figure out the net reduction in rate base?

Jim Turner - Duke Energy Corp. - Group Executive, President & COO - US Franchised Electric & Gas Yes. Carl, we don't have a number that we've put out there for the undepreciated net book value of the plants.

Unidentified Audience Member Right.

We don't have a number that we've put out there yet. We're not concerned that we have any kinds of issue in terms of that un-depreciated balance. We think we'll be able to recovery those over time through our rates, but we expect it not to be very consequential across our businesses.

Jim, could you talk a little about the -- specifically what your -- how you're going to go about trying to get legislation in, in the Carolinas? What are the timeframes we should be looking at? Do you have sponsors lined out or in mind for -- and what kind of mechanisms?

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Yes. We are certainly working with members of the General Assembly now. We are -- I would expect that you will see a very full-scale effort starting late this year pushing into the first part of 2011, and my hope is that be the middle of 2011 we will be successful in coming out with a package of items.

The number one, clearest, biggest focus that we have for North Carolina is getting CWIP for nuclear outside of [the] rate case. That is absolutely the most important thing we've got to get done in North Carolina, but we would hope in the context of discussing that mechanism to be able to drive a number of other mechanisms that we can do for other kinds of investments besides nuclear.

We would expect this to get tied up a little bit in energy efficiency discussions because that is a key focus area for members of the North Carolina General Assembly, so we think working to be more aggressive on the energy efficiency front, as we have been in North Carolina, will help position this discussion for us. So there'll be a package of items besides the nuclear CWIP, but that one's clearly the 800-pound gorilla. Let me stop and turn it over to Dhiaa and then, again, we can get back to this later in the day. So, thank you very much.

Dhiaa Jamil - Duke Energy Corp. - Group Executive, Chief Generation Officer, Chief Nuclear Officer

Thank you, Jim. Good morning. I'm pleased to be here with you this morning to talk about the regulated generating fleet. Let me start by highlighting the position itself. Last year, our company made several changes in leadership responsibilities to help clarify accountability, streamline decision-making and strengthen relationships internally and externally.

As part of these changes, the chief generation officer position was created with accountability for the regulated generating fleet. This change allows us to more effectively leverage capabilities across our fleet and improve operation and reduce cost of the operation.

This morning, I will outline three focus areas for generating -- for regulated generation, which I will expand on more in my slides. These include fleet operational excellence, environment compliance and new nuclear.

Next slide shows an overview. This map shows our Carolina and Midwest service area with all of our regulating generating stations. We're fortunate in that we have a diverse portfolio utilizing nuclear, coal and natural gas, hydro resources with the higher percentage of our generation, of course, coming from coal.

The table shows you the fleet, a breakdown by region, as well as installed capacity by fuel type and our 2009 actual generation. You can see that in the Midwest our customers are primarily served by our coal stations. In the Carolinas, however, nuclear energy consistently account for more than 50% of our generation.

For the entire regulated fleet in 2009, coal provided 59% of our actual generation followed by nuclear at 39%. We believe maintaining diversity in our fuel supply helps minimize reliance on one particular fuel source and reduces a potential impact of price volatility for our customers and also reduces the risk for our investors.

As previously noted, one of our focus areas is maintaining operational excellence. I'll report to you this morning with pride the performance of our fleet in 2009. These graphs show you the 2009 nuclear and fossil performance. From a reliability perspective, 2009 was truly a banner year for us. Our nuclear capacity factor was more than 94%. This is the tenth consecutive year that we've exceeded 90% in capacity factor. It's also the second highest capacity factor for the fleet in our history.

Similarly, the fossil fleet operated through an exceptionally high reliability factor last year. Instead of capacity factor, we use commercial availability as the reliability measure for fossil given how we dispatch our fossil fleet. Last year, our fossil commercial availability was more than 90%, a 6% improvement over 2008, and industry average for commercial availability is not available because different people do the commercial availability differently.

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The exceptional reliability results for both nuclear and fossil stations are built on a solid foundation of excellence and operation and also excellence in maintenance. We operate our stations as long-term assets, and our employees clearly understand that well-planned and executed outages, reliable maintenance and superior operation will help us achieve sustainable results. We're proud of our fleet performance, and we'll build on our success to continue providing reliable, cost-effective product out to our customers.

Strong plant performance is just one part of operational excellence. The other key component, of course, is cost management. The graphs, these graphs here, show you the cost aspect of the business. On the left side it displays the nuclear total operating cost. This includes fuel, O&M and administrative and general expenses. In 2009 our nuclear total operating cost was $19.33 per megawatt-hour comparable to our 2008 operating cost, which by the way was the lowest of all US nuclear fleets. We now have preliminary industry data that shows 2009 costs will once again we'll be lowest among all fleets. In Nuclear there are a number of factors that collectively assist us in maintaining low cost operation, including low force loss rate, superior reliability focused on outages, and effective cost management programs and event-free performance.

In fossil generation the dominant benchmark cost measure is clearly production costs, which include O&M and fuel but not A&G. For 2009 fossil production costs was $31.8 per megawatt-hour. As a reference other leading fossil units cost average about $40 per megawatt-hour in 2008. Our ability to consistently maintain lower production costs than the industry is attributable to the heat rate of our stations and also on our continuing focus on cost control, which allowed us to stand or target in major budget items last year. While we place considerable emphasis on cost control across our generating fleet it has not been at the expense of safety and operating excellence as the reliability slide clearly showed earlier. Our generating units are important resources for our customers and our employees are working with a goal of continuing to improve performance cost effectively.

As Jim already mentioned, we are currently building -- in a building program to modernize our generating fleets. We're making prudent decisions related to modernization to ensure we can continue serving our customers for many years to come with diverse resources. You can see on this graph the in-service dates for our generating fleet, which currently shows our fleet is aging. We have plans in place to retire all coal units placed in service in the 1940s or earlier, and more than 30% of the plants put in service in the 1950s.

In fact, based on the current license life of our nuclear station all of our stations could be retired by 2050. However, as you know, it may be possible to renew our nuclear stations’ license once again in the future. Developing and implementing a carefully designed phased approach for upgrading or retiring generating units as well as replacing the outputs of those units will benefit our customers over the long run. Our plants have aged well but the time has come to modernize the fleet.

Along with our focus on providing new, cleaner generation, is our continuing effort to reduce our environmental footprint. We've been working for more than a decade to reduce emissions through installation of environmental controls. Approximately 75% of our fleet has scrubbers or SCRs. This includes all of Duke Energy plant not just the regulated fleet. The graph on the slide shows the considerable reductions we have made in sulfur dioxide and nitrogen oxide in pounds per net megawatt-hour with the addition of those environmental controls.

Sulfur dioxide has been reduced by 71% and nitrogen oxide by 56% over the last four years. We've made significant investments, approximately $5 billion in addressing environmental issues associated with our fleet and we are recovering through rates all of our costs to make these important upgrades. As I stated earlier the results show significant reductions in overall emission intensity. It's also worth noting that once we complete our current modernization work and associated unit retirement plans, that Jim spoke about, almost 90% of our fleet with have emission control equipment.

While we focused on the addition of environmental controls to our fossil fleet over the past years primarily related to NOx and SOx, of course, we've been working to address pending new and changing environmental regulations. Let me just spend a few minutes discussing some of these. For coal combustion byproduct, which includes coal ash we expect regulations to be final by the first quarter of next year. In the near term we're preparing for the impact associated with the designation of coal ash. While we do not know exactly what the final coal ash regulation will include, we anticipate they will require installation of additional systems and it will increase cost per handling and disposing of ash.

For air pollutants, there are several key regulations that will affect our operation. The Clean Air Transport Rule, Phase 1, is currently in effect and limits actually the tons of NOx and SOx emission. Final Replacement rule is expected in 2011. The replacement rule may require retirements of and scrub installations on units that do not currently have these controls. In addition, a Maximum Achievable Control Technology, MACT final results are expected next year. The rule may require equipment to control and continuously monitor mercury and other hazardous air pollutant emissions.

We also expect tighter regulations for ozone, sulfur dioxide and particulate matter. The last item I want to mention under upcoming regulation is carbon. As Jim's opening remarks make it clear, we are in a new environment when it comes to electricity generation. You are all aware of the

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national/international focus on carbon reduction. If carbon will be regulated, Duke Energy supports passage of federal regulation mandating economy-wide the regulation of greenhouse gas emissions from all U.S. sources.

We know that absent legislation, the EPA will work to regulate the carbon emissions. The time frame for legislation is currently unknown. However, the EPA could, in fact, start regulating as early as next year. Now the exact impact and affect on pending regulations are unknown. We're planning for different scenarios and the potential impact on our stations. This may include additional installation of air emission control equipment, additional or accelerated unit retirement, beyond what we are currently planning and additional cost.

We've analyzed various models regarding the expected cost of these regulations. As mentioned earlier, we have already spent about $5 billion on environmental controls over the past decade. Our modeling suggests future investment could be in the same range phased in over a very long period of time and likely to begin after 2012. As we address near term environmental regulations affecting our fossil stations our long-term plans include the addition of new nuclear generation through upgrading the output of existing units and the planning for new ones.

In 2007 we submitted a license application to the NRC for two Westinghouse AP 1000 units in Cherokee Country, South Carolina. We're aggressively pursuing the license for this station to keep this new nuclear options open for our customers in the 2021 timeframe. We're taking a very deliberate and methodical approach to our work to ensure we're doing the right things and making decisions based on what is in the best interests for our customers and our investors. Also in nuclear development we've announced the formation of an alliance last June to explore new nuclear option in the Midwest. We're developing plans to evaluate potential sites for new nuclear in the Midwest include DOE’s Portsmouth site. In 2009 we submitted the request to do equal funding of the initial phase of this project, which is initially focused on performing environmental studies for a generic early site permit. We believe moving forward with these new nuclear projects is a prudent action. However, there are still some key considerations where additional work is needed to advance these projects.

There are three considerations we're focusing on in support of the new nuclear generation projects. These include receiving a license from the NRC, helping create supportive state regulatory framework, and developing regional partnerships.

As already mentioned, we submitted our license application for Lee Nuclear in 2007 and have been working on the development activities including completing site prep work, developing detailed cost estimate which was validated by a third party, addressing requests for additional information from the NRC, receiving approval to seek recovery project development costs, signing a used fuel disposal contract and submitting a loan guaranty application, which by the way we're keeping up to date. Based on our current information we anticipate receiving our license in the 2013 timeframe. The timeline on the bottom of the slide graphically depicts our current project milestones schedule. As discussed earlier recovery of initial financing costs during construction or CWIP is critical for a new nuclear project.

In North and South Carolina, both states have statutes in place that provide the means for construction financing cost recovery. However, the recovery mechanism is different in both states. In South Carolina we can seek financing cost recovery through separate annual adjustments. In North Carolina has to be sought through a general rate increase. As you know, our customer base is split 70/30 between the two states and therefore it's very important to have consistent legislation in place for both states for us to move forward with the Lee plant.

To ensure reliable cash flow during construction and maintain a strong, reliable balance sheet, we need the ability to recover financing costs as they are incurred outside of a general rate case. Complementary to our cost recovery effort, we're also working to develop regional partnerships. We have partners for our Catawba nuclear station and have a long history of working with multiple owners on projects. For Lee nuclear station we are exploring various partnership options, which will provide opportunities to share construction, project management on operational risks. Additionally, this provides the prospect of adding capacity in smaller increments over time to better match load growth and planned retirements and lessen the cost recovery, collections, and cash flow impacts.

The bottom line for us on new nuclear is while it's our preference to have regional partners, having the right regulatory framework is a must. In summary, as a corporation we measure success in many ways. In regulating generation we have multiple measures we track day-to-day, month-to -month, and year-to-year to allow us to capitalize on good practices and make improvements based on lessons learned. We're focused on sustaining excellence in our operation, and believe we are well positioned to achieve superior results going forward.

We have made changes to address environmental issues and have additional improvement planned. We are prepared for the future with a robust modernization plan including the addition of new nuclear, which we believe is an important resource for our future. Thank you for your time, and I believe I have time for a few questions.

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I just wanted to better understand your delay in NRC approval. I think there were some estimates about a four-year approval plan. Now it looks like it's more six?

Let me make sure I understand the question. Our plans, I think the timeline that I showed you is our current milestones reflects a COD date of 2021, which we announced probably middle of last year. If you're talking about the delay with the AP1000 specifically?

No just specifically the NRC COL approval coming in 2013 versus 2011, 2012?

Actually the NRC COLA application has not significantly moved. We have been projecting around 2012 for the license and we believe 2012 may be aggressive but 2013 appears to be very realistic for us.

And is there anything in particular with the EPA potential rule-making that is more onerous? One of the rules that you mentioned is one of the more onerous than others and have you given an estimate of how much it's going to potentially increase your cost?

Yes, it's really premature to give a specific number but I tell you we've been studying various scenarios, some assuming very restrictive rules, others assuming moderate rules. And have planned for a variety of potential outcomes for regulations. What I can tell you as I mentioned in my presentation we've spent approximately $5 billion over the past decade in making improvements. We believe a moderate approach to the upcoming regulations puts us in that same time -- that same price range but spread over a very long time we believe the changes will be phased in over time and more importantly we don't believe significant changes will be required before 2012. Yes, Carl?

Do you have any timeline on the spending for Nuclear assuming that you -- let's assume that you're going to get the cost recovery on a timely basis in North Carolina?

I think we have demonstrated over time a very methodical and deliberate, and disciplined approach with our Lee Nuclear Plant.

We plan to move forward with the same manner. We don't anticipate significant dollars before we sign the EPC contract. We don't anticipate to sign the EPC contract before having the COLA in hand. So if we project a COLA by 2013 EPC will follow. Of course, if some outstanding things

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happen that require us to move that date line up I think our schedule has provisions that will allow us to move it up. But our current plan is no significant dollars prior to 2013.

Okay I want to follow on -- what's a significant dollar?

Significant dollars are anything that are beyond project development costs that we currently have approval from North and South Carolina on. So involves long lead items of equipment and commitment of cash for the future.

Unidentified Audience Member Thank you.

Dhiaa Jamil - Duke Energy Corp. - Group Executive, Chief Generation Officer, Chief Nuclear Officer One more?

Yes, actually two questions kind of unrelated. First on the Edwardsport can you give an update on the cost for that? I mean I think the latest was 2.35 billion, but there was some discussion in one of your filings the middle of the year, maybe in the third quarter, regarding about some incremental cost to that? And second can you talk about the AP 1000 and some of the concerns that the NRC has with the reactor shield design for the AP 1000 and whether there's risk that all of the development cycle of AP 1000s may get pushed out until the NRC gets comfort on that?

If I may let me address your second question first and then maybe ask my colleague, Jim Turner, to address the Edwardsport question. On the AP 1000, of course, there were announcement about some potential delays particularly with the shield building as you mention. We have been working very closely with Westinghouse along with the other AP 1000 applicants, by the way, to closely monitor this development.

We believe that some changes have been made. We believe that Westinghouse is very effectively working with the NRC to address this issue. There's some testing that has taken place. The NRC is monitoring the testing. The testing is coming to a conclusion this month. A report will be submitted by Westinghouse to the NRC. That's anticipated to be in March and we're fully thinking that that will resolve the specific technical issues with the shield building.

From a schedule perspective while this may have a minor impact on the design change certification for the AP 1000, which by the way is required before reference plant and other plants can have their license, our schedule as you saw on the slide -- on the slide has ample margin in it to absorb even significant delays without impacting our own schedule.

Michael, let me hit your second question on Edwardsport. It was in the prepared remarks but you recall we went to the Commission, I think, in mid '08 or so to raise the cost estimate to $2.35B. The Commission approved that in January of 2009. We notified them late last year that we were seeing design changes and scope growth that were causing more upward pressure on cost. And we said $150 million, in that range. That's without contingencies so there will be some contingency obviously on top of the $150. What we did in conjunction with announcing that the Commission actually approved our updated CWIP rider for Edwardsport and then we agreed with all the parties and the Commission to separate the revised estimate out into a separate sub docket. So we'll file testimony in that case in April, early April -- I think April 7th is the date and then we'll have a hearing in August on the revised estimate.

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At this point we're going to take a 10 minute break and when we return, Keith Trent will give the commercial business review and Lynn a financial overview before heading into the general Q&A session.

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Thank you. For the second half of our meeting Keith Trent is going to lead off with an overview of our commercial businesses and following Keith will be Lynn with the financial overview -- I'm sure you're all looking forward to. And then the entire executive team will take the stage and take your questions. So I'd like to right now introduce Keith Trent head of our commercial businesses.

Keith Trent - Duke Energy Corporation - Group Executive and President - Commercial Businesses

Thank you, Stephen and good morning again. My goal this morning is to shine some more light on Duke's commercial businesses and to show you a set of businesses that provide diverse earnings and growth opportunities for the company. Now I know -- I knew before but as I was circulating around at the break it became even clearer to me that many of you have a lot of questions about Ohio.

And so I'll spend most of my time this morning on Ohio and the Midwest generation business but I'll also cover our other unregulated or unregulated businesses. The commercial businesses fall in three distinct buckets and taken together these businesses provide geographic technology and fuel diversity for the company.

The Midwest generation is a mature business that has provided strong historical cash flows and earnings. As Jim Rogers mentioned earlier our Ohio fleet that is currently dedicated under Duke Energy Ohio's Electric Security Plan consists of around 4,000 megawatts of generation, the vast majority of which is coal-fired. Our Midwest gas generation, which is centered primarily in PJM consists of approximately 3,600 megawatts of gas-fired generation. That's clear that this business faces near term headwinds but it will continue to produce strong cash flows and solid returns for us. We don't anticipate investing additional growth CapEx in this business over the next several years. But we do intend to manage our O&M and our maintenance CapEx very prudently.

The second leg of the three businesses is our renewables business, which we launched in 2007 with an initial focus on wind. We now have almost 750 megawatts of wind operating with more coming on line very soon. And over the past two years we've launched our solar voltaic business, our biomass business and also our commercial transmission business. The near term growth in the renewables business is going to be driven by favorable state and federal public policy and we'll manage our risk very carefully in these businesses through a development model that is based on long-term contracts.

Duke Energy International, our third leg, is predominately hydroelectric generation in Brazil and a combination of hydro and fossil generation in Peru. Duke Energy International provides stable earnings, good growth and good earnings diversity for Duke. In fact, we saw the value of this diversity this last year in the recessionary climate that we all went through where the recessionary impacts were milder in Latin America than here in the United States. Taken together the commercial businesses provide a diversified source of earnings in cash for Duke which has contributed substantially to our earnings growth over time.

In fact in 2009 we saw the benefit of this diversity. While everyone felt the impact of the economy in 2009 our Commercial Businesses actually exceeded our internal adjusted EBIT target by almost $70 million. Suffice it to say that I'm very proud of the Commercial Businesses team. They came through for us in a very big way in 2009 and I'm confident that they're prepared to take on the challenges that we're going to face in the future. Now I'd like to discuss each of our businesses in more detail.