Duke Energy Corporation (DUK)

Analyst Meeting 2013

← View all transcripts

Feb 28, 2013

Welcome to Duke Energy's 2013 Analyst Meeting. I am Bob Trender with Duke Investor Relations Department. We're very glad that you're here to hear from us today. This morning you will be hearing from members of Duke Energy's senior management team as they discuss future prospects for our company. Today, discussion is being tele webcast and will include forward looking information and the use of non GAAP financial measures. You should refer to the information included with our presentation as well as our SEC filings concerning factors that could cause future results to differ from this forward looking information. A Safe Harbor statement and a reconciliation of non GAAP financial measures is available on our website and in today's presentation materials. Now let me briefly describe today's format. In few minutes, I'll turn the program over to Jim Rogers, our Chairman, President and CEO for opening remarks. Jim will provide strategic framework for this morning's presentations. Immediately following Jim's remarks, we will move to Keith Trent, who will discuss our regulated utility operations and in turn other members of senior management will follow. We plan to have a short time for questions after each of the business section reviews and we reserve 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 to you before asking a question. We're scheduled for a break around 10:15 this morning and will resume promptly at 10:30. We plan to conclude by 12:30 p. M. As a reminder, please mute or turn off your phones and Blackberries. And now I'd like to turn the program over to Jim Rogers. Good morning. We're glad you're here. I also want to welcome everyone on the webcast. We've been looking forward to talking with you about Duke Energy's future. You can see our meeting objectives on Slide 5. Our senior leadership will describe Duke's strategy and where we stand executing it. You'll hear how Duke is positioned for the ever evolving energy landscape. We'll show the benefits of the merger, how we're optimizing our generation portfolio and recovering our investments. We're also reaffirming our value proposition. It's familiar to many of you all and it's simply this. We're a low risk, primarily regulated utility, well positioned to build on our record of strong operational and our customers and investors in the future as we have in the past. This is my 25th year as a CEO in this industry. I've seen a lot of change. I've seen deregulation in 19 states, deregulation of generation. The jury is out as to whether that will be a lasting model. I've seen RTOs formed in many parts of this country, renewable portfolio standards in 30 states, environmental regulations on coal plants that have cost the industry 1,000,000,000 of dollars that have translated into significant reductions in SOx, NOx and mercury. Been a lot of fads. It didn't play out as people thought. But to me, we are facing headwinds. In my judgment is, when you look at all of them, it adds up to the most complex, challenging dynamic environment that I think we've ever experienced. What does that mean? We'll take shale gas for example. Who would have predicted 5 years ago that shale gas and natural gasification natural gas generation would surge 21% last year with an average price of $3.48 more than a buck lower than in 2011 and significantly lower than the $10 to $12 a number of years ago. Who would have predicted that someone would forecast that natural gas in 20 over 52% of the generation in this country, the same percentage that coal has held for many decades in this country. That was a prediction by Black and we would be in an environment of anemic demand growth? And I believe that is one of several key issues. Clearly, with Fukushima cost and modernization of the grid cost and modernization of our generation fleet, we're seeing rising prices. That's part of the future. But the growth issue is more complex and more difficult to discern as we go forward. Pushing up demand as you see greater electrification of our economy. You're seeing an anemic rebound in the economy and as more houses are built, as industry rebounds that will push growth side. But pushing it down is something that's going to be very incremental and harder to measure. And that to me is the disintermediation both on the supply and the demand side. What does that mean? On the supply side, what that means to me is that you see more solar panels, you see more CHP as solar panel prices fall to 0 point dollars and $0.60 a watt per panel. So to me that takes away load for us. If you look on the demand side, it is an amazing array of new technologies that if deployed will lead to productivity gains in the make it very difficult to discern what the make it very difficult to discern what the actual growth in demand will be in the future. And that's going to require us to think differently as we go forward. The old test period approach to setting rates, I think it's going to be something of the past. We need to work hard to change the regulatory model, so that we are positioned to be prepared to handle a world if it turns out that we have very anemic growth and anemic is less than 1%. Anemic could be flat if you're bearish. Ish. But the bottom line is we have to be prepared to achieve 4% to 6% growth in that environment. So changing the regulatory model is going to be an important part of that. Changing the cost paradigm is going to be a very important part of that. And we've gone through a number of mergers over the last 25 years and each has been a catalyst for driving costs out of our operation and improving the efficiency of our the industry ranging from economic and market trends to developments in public policy and technology. These forces are interrelated and I have spoken to just a few of them. Trends like these are driving transformative change. No one has the future figured out. During my career, I've learned to take nothing for granted. But I do know this, we're in a good position to lead this transition and take advantage of new opportunities while mitigating the risk. As I prepare to leave Duke by the end of this year, I have one priority and one priority, and that is to support the executive team and Board and ensuring that this company is ready for whatever lies ahead. Ready to me, team with agility, particularly when you're such a large company with resilience, the ability to look around the corner and see the future for others to and move to take advantage of the opportunities or confront the challenges that are seen. Our leadership team will show you today why I have confidence in Duke's future. A scale, diversity and flexibility. Scale matters more than ever. We are the largest utility in the U. S. Based on most metrics, market cap generating capacity and customer serve. Scale importantly helps us to achieve cost savings and that will This diversity supports diversity of earnings. We also have a diversified generation portfolio. The pie chart shows the transformation of our regulated fleet from 2,005 to 2015. This is a result of fleet modernizations and the retirements of older, less efficient coal and oil units. As Keith will explain, we're well along in making a big shift from a heavily coal based mix to a balanced diversified portfolio with much less coal more natural gas. Coal share declines from about 55% in 2025 to 38 percent in 2015. Cash share grows from 5% in 2005 to 24 percent in 2015. Flexibility is also critical for managing the uncertainty we face in the future. As I said earlier, we need to be agile and create and maintain options to make adjustments to our plans as we have in the past. For example, we have operational flexibility provided by the Carolina. Also, we have fuel mix diversity and we have strategic flexibility with our commercial business, which Mark will about 90% of our total business. This segment significantly contributes to our low risk profile. This low risk helps sustain growth and that dividend is at the heart of our investor proposition. I'm proud of what our employees achieved in 2012 despite a year of earnings call. Slide 8 highlights a few accomplishments, starting with completing the merger after 18 months and three tries with FERC and obtaining approval of the cost recovery settlement of the Edwardsport IGCC plant. 2012 was a strong year operationally as you all know so well financially. Our employees achieved the company's best safety record ever. That's incredible given the turmoil that we were going through during that period. Our 14th consecutive year. We've completed 3 major new power plants in North Carolina and added 650 Megawatts of new wind and solar capacity. We delivered on our financial objectives, hitting the upper end of our earnings guidance range. We also grew the dividend and maintained the strength of the balance sheet. We have developed a strong record of consistently delivering on our operational and financial objectives. Pride ourselves on doing what we say we will do. The next slide provides a 4 year look at our financial track record, 2,009 through 2012. Some of you all remember, we came to you in early 20 10 with 3 financial objectives. Grow our long term adjusted EPS at a compound annual rate of 4% to 6%. 2nd, grow our dividend at a pace that allows us to have a ratio with earnings of between 65% 70% as our targeted payout ratio. Thirdly, to maintain the strength of our balance sheet. Slide shows we achieved each of these commitments. We achieved a 6% compound annual growth rate in adjusted diluted earnings per share and a 2% growth rate in the dividend. I'm proud of our total return, a key investor metric. See in the right side of the slide from 2,009 to 2012, Duke beat the Philadelphia Utility Index and the S and P 500. Our total shareholder return of 76.5 percent was more than twice the utility index. We maintain the strength of our balance sheet and continue to enjoy the benefits of a strong investment grade credit ratings. I share this not to brag about the last 3 years because you all know about it. Simply say, we do our best to deliver on what we promise. Another part of our track record is resolving our near term priorities. Since July, we've been focused on the one shown on Slide 10. Let me take them off quickly. Constructive rate case outcomes, the Edwardsport project, settlement approval, commercial service. Crystal River Nuclear Plant, repair or retire decision North Carolina post merger investigations, merger integration and synergy, nuclear fleet optimization. We're going to work on these. We have resolved 3 of these big issues within the last 3 months. The North Carolina investigations, the Crystal River retire decision and the Edwards Port settlement approval. We're systematically We're systematically reducing uncertainty and risk. This morning, you'll hear further updates on our remaining 20 13 priorities, bringing Edwardsport into commercial service and achieving constructive outcomes in our pending rate case. Lloyd will speak about our settlement with the public staff in the PEC case. It has a 10.2% ROE, a 53% equity component and he'll get into more detail about that when he speaks. But a fair result that allows us to go forward and recover our investments in PEC. You'll also hear more about our ongoing priorities to harvest the merger synergies and optimize our nuclear fleet. Now I want to explain how Duke is positioned to continue creating value for our investors over the long term. In other words, what's our plan to keep delivering on our promises? Slide 11 shows we will deliver on our promises in 2 ways. 1st, excel in the fundamentals of this business. Given the cost pressures and low growth that I talked about a few moments ago in our sector, Excelling in the fundamentals is more important now than ever before. This includes operational excellence, customer satisfaction, financial discipline and constructive regulation. You all know every utility must focus on these basics. This is the basic blocking and tackling of our business. Bouygues has a strong record in each area and we intend to keep improving. You'll hear a lot more about this today. Expect to learn how Keith and Zeya achieve operational excellence, which supports customer satisfaction as well as regulatory relationships. Lloyd will talk about what we're doing to achieve constructive regulatory outcomes in our rate cases. Lynn will report on our financial discipline. Our financial discipline underpins everything we do. Our financial strength benefits not only our investors, but also our customers as they benefit from our access to cost effective capital. Beyond the fundamentals, we are focused on leveraging Duke's most importantly differentiates us from other utilities. Scale efficiencies, diversity of generation and earnings which mitigates risk, favorable geography that provides both diversity and access to attractive markets, strategic flexibility to redeploy capital to seize new opportunities and adapt to changing market conditions, especially with our commercial business. You'll hear we'll hear more about this from Mark Manley. Our winning formula combines these strengths with a continuing a for the road ahead. We are anticipating, we're challenging conventional wisdoms, we're looking around the corner, so we can adapt to the evolving risk and opportunities in this industry. I believe based on 25 years of experience, this will allow us to create value for customers and investors. Our leadership team leads with passion and common sense. This underlies and underpins my confidence in Duke's readiness for the future. On my last slide, you can see our senior leadership team. This is a seasoned team with an average of more than 27 years of industry and professional experience. They have diverse backgrounds. This team is building on the solid foundation we have at Duke with our performance culture and engaged workforce. They are here today to talk about our strategy and how we are adapting to the new energy landscape. We'll see why I have so much confidence in them. They will answer your questions after each presentation. We'll also leave time for a general Q and A at the end. Now let me introduce Keith, who will talk about our regulated fossil generation, service operations. You have his and all of the presenters' biographies in the back of the presentation material. Keith has been with Duke since 2002 and now serves as Executive VP and Chief Operating Officer of Utilities. Keith, come on up. Thank you, Jim, and good morning, everyone. As Jim mentioned, I'm going to update you on our regulated fossil generation fleet and also on our T and D system. Let me start with 3 points. First, our fleet modernization program which began back in 2006 has positioned us very, very well for coming environmental regulations. Our early start in that program puts us ahead of others in the industry in our opinion. 2nd, we're on track to deliver operations related merger savings. This includes fuel and joint dispatch savings that go directly to our customers, but it also includes merger savings, that we're harvesting today and we're focused on savings beyond those that are simply related to the merger. Finally, as Jim highlighted, we're monitoring the changing landscape including low load growth and new environmental regulations. As events unfold and things become more clear, we're poised to retire additional plants and to make additional investments in our system. That's going to enable us to serve our customers for decades to come. Slide 15 gives you a sense of our size. Jim referenced this earlier, but let me give you a couple of stats. Six states, 7,200,000 customers, 50 gigawatts of generation, 32,000 miles of transmission and 250,000 miles of distribution. Those statistics tell you we're big. And we're telling you we're going to use that scale to benefit our customers and our investors. In addition to size, our combined fleet is very well balanced. The pie charts on the top right of this slide show that as a company we're not dependent on any single fuel. Currently nuclear provides 34% of our generation. Dave is going to talk about the nuclear fleet in a moment. The remaining 66% of the regulated fleet is coal and natural gas with a small amount of hydro. Our non nuclear fleet performed very well in 20 12. One way we measure ourselves there is looking at commercial availability. And I can tell you in 20 12, in most instances, we hit our commercial availability targets. Some were slightly below target. That's good, but we've got room for improvement and we know that. We're addressing the fact that our coal plants are no longer dispatching as baseload units, especially in the Carolinas. And you can see from the chart on the right Today as a result of low natural gas prices, our natural gas plants are operating as baseload with capacity factors in the 70% to 80% range. Now this may be the new normal. And if it is, we're ready. If it is, we're going to need to find efficiencies though at our plants and I can tell you we're very focused on that. And those efficiencies will go above and beyond what we're looking at from a synergy target perspective. Opportunities we're looking at are can we convert more fixed cost to variable cost. If we can do that, that's going to make us more efficient and it's also going to give us more flexibility. Regardless of what the future commodity prices look like, our fleet's balance and diversity will enable us to provide our customers with affordable, reliable and increasingly clean energy. 2000 and 6, we began our multi year construction program to modernize our regulated generation fleet. By the end of this year, we will have added 6,600 megawatts of new coal and gas fired capacity. And we will have retired 3,800 megawatts by the end of this year. That retirement number by 2015 is going to increase to around 6,800 megawatts. This modernization program is providing additional fuel diversification. You can see on the 2 pie charts on the right side of this slide, the combined Duke Energy in Progress generation mix in 2,005 was mostly coal and nuclear. But by 2015, we will have a near equal balance of nuclear, coal and natural gas. Our coal fleet today is clean, but it's getting cleaner. The pie charts on the lower right of the slide show you that over 80% of our coal is scrubbed today and that number is going to go to 90 6% by 2015. 2 new plants are going to come online this year. Edwardsport, our 6 18 Megawatt IGCC plant in Indiana successfully produced syngas from both gasifiers. That was a big milestone for us. And we've produced electricity from both of our turbines using syngas, natural gas and a blend of both. And in fact, last week, combustion turbine number 1, which currently is a highly instrumented turbine so that GE can gather data. We took that turbine to full load last week. That enabled GE to gather the data that they need and want to be able to do some further testing. That was a big milestone for us. For the last several days, combustion turbine number 2 has been producing 200 megawatts of power on syngas and the steam turbine has been producing about 90 megawatts of generation. So we're confident with this technology. We're confident that this plant is going to operate as designed and we're still looking at an in service day in the mid part of this year. 2nd plant we're completing this year is the 625 Megawatt Sutton Combined Cycle Plant. It's currently under construction. This plant will be our 5th natural gas plant since 2011. The target date for that plant is Q4 of this year. We're also focused on managing costs. We're particularly focused on delivering 687 $1,000,000 in fuel and joint dispatch savings to our customers in the Carolinas over the next 5 years. We're estimating that about half of these savings are going to come from jointly dispatching the Progressen and Duke fleets. The other half is going to come from fuel savings. On joint dispatch, we hit the ground running. Within 15 minutes from the time the merger closed, we were dispatching our systems in a combined way and delivering benefits to customers. The bars on the right side of this slide show you that we can deliver savings in different price regimes. And let me talk about this just a moment. When gas prices trended lower back in August, Progress Energy's heavier gas fleet was dispatching from Progress territories into the Duke territory. Then in December, as gas prices started to rise, Duke's more heavy coal fleet began dispatching into the progress territory. Key here is under both of those price regimes, we were delivering savings and harvesting savings for our customers. So the joint dispatch system is working and it continues to get more efficient and even better. Our fuel program is on track as well. So far we've locked in about 65% of the anticipated savings, the targeted savings. And that came through renegotiated coal contracts and also through fuel transportation savings. And we're also ahead of our plan in terms of our coal blending program. Let me give you one example. At our 2,200 Megawatt Blues Creek plant, we set a 2012 target to burn 20% mix tests to see if we can take that percentage even higher. Okay. And then, tests to see if we can take that percentage even higher. During the 1st 6 months after the merger closed, we produced $52,000,000 in combined fuel and joint dispatch savings. That was ahead of our plan. In addition to our fuel and joint dispatch program, we're harvesting other merger savings. We've specifically in the regulated operations team have identified more than 200 specific initiatives. We've assigned clear accountability for those initiatives, and we're on track to complete them. So we're focused on cost, but not at the expense of our operational excellence. So on the power delivery front, we measure reliability a sustained outage each year. Safety measures the average duration of annual outages and minutes. The chart on the left shows that safety for the combined company has dropped from 1.3 in 2,006 to 1.2 per customer in 2012. That's an 8% improvement. On the SADI front, it's improved over the same time period. For 2012, the Duke annual SADI was just over 2 hours per customer, which represents a 22% improvement from 2,006 level. Both of these trends demonstrate our improving system. We're never going to reach 0 here, but I can tell you that our 7,000 T and D employees are passionate about what they do and stand ready to respond quickly when our customers need them most. With the merger, our storm response capabilities are stronger than they've ever been. The size of our team and the diverse geography of our territories gives us the scale and the ability to quickly move thousands of employees from one region to another to restore power quickly and safely. We flexed that muscle in November when we sent more than 2,900 employees and contractors to assist restoration in the wake of Superstorm Sandy. That was the largest deployment in our company's history. Then just a few weeks ago, more than 700 of our contractors helped to restore power in the areas in the Northeast that were ambushed by the major blizzard. See on the right side of this slide a very nice note from a Pennsylvania resident who was very thankful for the help that we were able to give them. Jim mentioned the importance of customer satisfaction. We believe that when you control costs and deliver excellent operational results including strong reliability. Good customer satisfaction results are going to follow and we believe we're well positioned to deliver those results. So that gives you a picture of what we're doing on the operations front. Let me spend a couple of minutes on future investment opportunities. As slide 21 shows, we've spent $7,000,000,000 on air emission controls to reduce SO2 in NOx. With these investments, we've already reduced SO2 emissions by 86% and NOx emissions by 64% through 2012 off of a 2,005 base. By 2015, those percentages are going to improve to 92 79% respectively. As we look to the future, we're anticipating new air, water and waste rules. We estimate that an additional $5,000,000,000 to $6,000,000,000 in investments will be needed over the next decade to comply with new regulations. That's down from a previous estimate that we had given you of around $6,000,000,000 to $7,000,000,000 Improvement in the final MAC rules enabled us to eliminate some of the anticipated back house additions, which in turn has reduced the anticipated spend there. The pie graphs the right side of this slide show that approximately 25% of this spending is expected to be for air regulations such as mats. And about 95% of these air related investments are expected to be made in Indiana and in the Carolinas, where we historically have had very constructive recovery of environmental compliance spend. The remaining 75% of the $5,000,000,000 to $6,000,000,000 range is targeted for potential water and waste regulations, which have not yet been finalized. We're continuing to monitor the development of these rules and we'll adjust our estimates as we gain further clarity there. So let me leave you with these thoughts. 1st, our fleet modernization program puts us in a strong position in terms of diversity, fuel diversity and environmental regulation. 2nd, we're taking full advantage of our unique scale and investors. And third, we're ready for additional investments in our generation fleet. Finally, we're clear about our mission. We will deliver affordable, reliable and increasingly clean energy in a safe manner, while delivering superior outcomes for our customers, our communities and our shareholders. Thank you. And now, I'll take Discussion on gas costs and fuel mix interest me. Could you talk a little bit about what your how you buy gas? Where does it come from? And how variable are the costs over a period of time? And what are you doing? I know you've renegotiated some of your coal contracts. Are there others to renegotiate? Will there be savings in the future relative to declining use of coal? Vary from some degree from jurisdiction to jurisdiction and it depends to some degree on the regulatory requirements and desires quite frankly. But and historically, I would say that the progress has hedged out further on natural gas prices than Duke has. We are entering into some hedges going forward on natural gas. As we look to the future, we're going to be the 2nd largest buyer of natural gas among utilities. And so it's obviously an important thing for us. But we're presently not hedging out for long term contracts on the gas side. We're evaluating whether that should change. One of the things I can tell you is we will not get ahead of our regulators there. And we will make sure that whatever do that, but we've got to balance the risk associated with the hedging and the benefits to customers. And so the key for us is making good decisions that are in lockstep with our regulators. In terms of coal contracts, I can't comment specifically on additional contract renegotiations at this point. As I mentioned to you, we've got 65% of our fuel savings locked in and we're quite comfortable that we can achieve the balance of those drafted by the EPA. They've not been put out by the EPA. I'm not a lawyer, I know you are. They will probably get litigated for multiple years whenever they come out. I'm thinking 316b, I'm thinking coal ash. How do you get your arms around, A, what the rules will likely be? And then, B, thinking about what the cost to comply with those rules will be over a multi year time horizon and then see the timeline for implementation? Those are great questions. So let me break it down in pieces a little bit. First of all, from an error standpoint, that's where I think we have the most clarity. The MATS rule, the rules are final. I realize that there is litigation going on to challenge the rules. But we are assuming that those match rules will go in place and that we'll need to comply by 2015. In some instances, we can get a 1 year extension. So we're using that as an assumption. And so air is where we have the most certainty. The rule changes that I mentioned have given us an ability to eliminate bag houses. So on the air side, what we look at most is the addition of some SCRs and addition of sorbent injection. So we think we've got a pretty good handle on the air side. Those are the spends that are the most near term. They make up the majority of the spend in this 3 year time horizon that we've given to you, which is the $1,400,000,000 Quite frankly, the reason that we're not giving you specific times and dates and really not giving you specific information much beyond the 3 years is because it is hard to know exactly what timing is going to happen outside of this 3 year window. So air we feel pretty good about. That's where a lot of the spend is going to be happening in the next 3 years. And one of the tools we're also using is in Indiana, we have filed compliance plans on the environmental plan that we have. And Indiana is a place where a large portion of our spend is going to be in the future. And we were successful in reaching agreement with the OUCC recently on the environmental compliance plan regarding the spend that we're going to be making there. So your point is well taken in that the further out you get and especially for the rules that we don't have final rules on, there's certainly going to be some leeway and our forecast likely will change as we go in time. But we have a very, very strong process that we go through to evaluate what we think we're going to need, what needs to be retired, what needs to be added. And certainly we have some base set of assumptions and I won't go into all of the base set of assumptions, but we feel good about the assumptions we have. But again we're ready to change them if we see things going in a different direction. Really just following up on that question because we were having a chat at our table about the same slide. To put it into more sort of detail, you said that you've got about $650,000,000 of CapEx related to MAX back to your appendix. The total spend for environmental is $1,375,000,000 So how much of that is sort of placeholder? How much of the other half is placeholder that could be subject to change as per Michael's question where you're thinking you're going to spend it, but you really don't know for sure and it seems to be back end loaded 15. Yes. So again the air is the bigger component of it. I would say the air of this point 4 ish is in the $600,000,000 range. And again, I think we have better certainty there. And then the remainder is water and waste $800,000,000 there. Some more uncertainty there, but the types of projects we're talking about there are on the waste side, ash pond work, dry ash conversion kind of work. And then on the water side, water treatment systems work. So we have things that are specifically identified where we don't have just sort of throwing in this big bucket of contingency or guess. But having said that, especially on the waste and water side, you could see some sliding or changing there. But we feel reasonably good about the estimates for this 3 year period. Take one more question here and then we'll move to Lloyd. Following up on those environmental expenses, Keith, to what degree I know that it's important to you now to get at least if not always to get the regulators to concur in advance before you spend the money. To what degree have you talked to regulators about this plan over immediate and to regulators about this plan over immediate and longer range and what kind of reaction do they have? Are they looking for some filings in advance or they just say do it, we'll judge you after you do it or what? Yes. So different in different places and Lloyd can probably go deeper on this than I can on the regulatory side. But what I would say to you is in Indiana, as I mentioned, we filed a compliance plan. And so there is a very deep discussion with the interveners with OUCC and then the commission obviously is being well informed in terms of what we're asking to do and we are seeking an order approving that spend. In the other jurisdictions, it will depend. In the Carolinas, our practice has been to keep the commission and public stack very, very informed of what we're doing. We live by a no surprises kind of rule and we will continue to do that. So that gives you, I think, a sense of how we interact with our regulators. You I think a sense of how we interact with our regulators. All right. At this time, I'm going to turn the show over to Dave to talk about our nuclear performance. Thank you, Keith. Good morning, folks. As Jim mentioned, I will cover our nuclear program this morning. Similar to Keith, I will start with the 3 takeaways from my presentation. First, in my presentation, I will highlight our strong operating model. That model helps us drive best in class fleet performance, which includes, as Jim mentioned earlier, 14 years of above 90% capacity factor for the whole fleet. 2nd, I'll share with you today our plans to continue to make targeted to achieve operational excellence and efficiencies across the fleet. And third, I will discuss our plan to maintain the option for new nuclear, which supports fuel diversity. Our vision in nuclear is to be the best fleet in the country. We do that by closely and continuously monitoring our performance. Before I go there actually, I do need to orient you to our fleet first, if I may. We operate, as you know, 11 plants at 6 different sites. Our capacity is 10.5 gigawatts. We own 8.2 of that. We announced earlier this month that we're retiring Crystal River III in Florida. So from the map that you see on the screen, you notice that all 11 units are in the Carolinas are and within well driving range, which gives us a distinct advantage in that regards. It allows us to use resources and expertise more effectively and leverage best practices across the whole fleet more quickly and address the merchant work. As I started to say earlier, our vision is to be the best fleet in the country. We do that with monitoring lots of data. You see on the slide is set up 7 key performance indicators that we monitor our performance against and we compare ourselves to the rest of the industry on. The colors represent the quartiles of performance. Green represents 1st quartile, dashgreen is 2nd quartile, yellow is 3rd and red is 4th quartile. We chose those 7 indicators because frankly they represent what's important in nuclear from a performance point of view. They represent safety, reliability, safety in the form of personal, radiological and nuclear safety, reliability with capacity factor and post loss rate. There's an independent view of an inflow index and cost efficiencies represented in terms of total operating cost. As you look across the chart, which represents several years of performance, you noticed lots of green and dash green historically going back several years. Far right column, going back several years. Far right column represents our performance in 2012 for the full combined fleet. Clearly, you see different set of colors there. So we're not satisfied with our performance in 2012. The striped green and yellow colors in 2012 indicate we have work to do to achieve top quartile and we will achieve top quartile. I'm confident we're on the way to achieving that. We've established high quality organization and detailed plans to target investments that will lead to step change in performance. As we make these investments, we will continue to emphasize opportunities to harness synergies. We will aggressively pursue these cost control measures. However, we will not do that at the expense of safety and operational excellence. Our nuclear plants are important assets to our customers and company and we will always operate them as long term assets. The previous slide, I showed the results. With this slide, I will show you how we consistently achieve good results in the fleet. It illustrates a disciplined approach to optimize the operation of the fleet. This particular depiction depicts our operating model, which I call our playbook. It helps us quickly integrate our nuclear team post merger. It provides great clarity about our work policies and processes. It assists us in maintaining current and objective view of our performance. Two main aspects of this, what appears to be a busy slide or the 2 main components in my opinion are the governance and oversight. Governance defines the standard that we operate the fleet to. They reflect industry best standards, governance discusses how we run the fleet, conduct of operation for the a strategic mix of internal and external oversight. It is described, I describe it as intrusive oversight. My colleagues get nervous when I talk about intrusive, the word intrusive. And I realize the word intrusive is not always a pleasant word. You hear it when you're talking about government action or maybe it reminds you of some unpleasant medical procedure. But I assure you, in nuclear, it's a beautiful world. In nuclear, intrusive oversight fosters an environment of transparency. It allows us to detect performance problems very early and allows us to take action to correct them well before measures would indicate there is a problem. That is why intrusive oversight is very important. It's this strong approach of highly inquisitive and aggressive reviews coupled with rapid mobilization of resources from across the fleet that is key to our success. Turning to the next slide, you will see the target investment we're making to increase overall fleet performance and to meet the NRC's Fukushima related requirements. Over the next 3 years, we anticipate investing an additional $175,000,000 in capital and $50,000,000 in O and M to improve fleet performance. Human Resources is one area of targeted investment. For example, Brunswick and Robinson, we hired over 200 individuals in a variety of disciplines such as engineering, maintenance and operation. This is providing immediate benefit and will also have a long term benefit to that. We'll also put special teams in place at Robinson and Brunswick to accelerate improvement. And we have deployed supervisory mentors and coaches from across the fleet to further accelerate the improvement. Now moving to Fukushima. Over next 3 years, we anticipate investing about $500,000,000 in capital and about $100,000,000 in O and M for Fukushima regulatory requirements. These expenditures will focus in key areas such as coping with natural phenomena, the design of containment vents in our EWR units, instrumentation to more accurately measure spent fuel pool level, water level and opportunities these requirements may vary as the rules are more clearly defined. The scale of our fleet enables us to address the requirements more efficiently and while required these investments should also contribute to performance improvement. We move to Crystal River. As we move to the next slide, I'll update you on the plans to retire and decommission the Crystal River Nuclear Site in Florida. We have selected, as you know, the safe store method for decommissioning. We'll place the units in safe storage configuration until dismantling and decommissioning work occurs, which will be within 40 to 60 years. As you well know, the NRC requires nuclear plants to put aside funds during operation for decommissioning. Our Nuclear Decommissioning Trust Fund for CR3 currently has assets of approximately $600,000,000 We expect that fund to cover the decommissioning cost. Recently, we filed notification with the NRC for permanent cessation of nuclear operation from CR3. Next step is to finalize our decommissioning transition organization, actively working with plant employees to understand how we can best use their expertise and skills. Some of the staff, of course, will move to the transition organization, while others will be redeployed across the fleet and company. Once that transition team is staffed, we will focus on developing and submitting shutdown technical specification to the NRC. We expect the NRC to take about a year to review and approve that. After approval of that technical specification, we will develop and implement a steady state organization to staff aside until decommissioning is complete. That organization is expected to be significantly smaller in size than the current organization. With this next slide, I'll update you on new nuclear work. As we plan ahead, we are continuing the project development work on Levy and maintaining new nuclear generation as an option for future capacity. Nuclear is a key component of our long term resource strategy because it helps fuel diversity and represents carbon free baseload capacity. The NRC is reviewing our applications for combined construction and operating license for 6 new nuclear units, 2 LEAVY units in Levy County, Florida, 2 LEAVY units in Cherokee County, South Carolina, 2 units at Harris, which is in Wake County, North Carolina. We anticipate receiving those licenses, particularly for Levy and Lee, somewhere around the end of 2014 or early 2015 with Harris license expected sometime later in the future. Of course, the waste confidence issue could delay the issuance of these licenses and we're monitoring that very closely. In addition, we continue to explore regional partnership opportunities for new nuclear. This includes ongoing discussions with Santee Cooper regarding ownership and its interest of the new VC summer units now under construction in South Carolina. Also, as we have discussed before, we are supportive of the development of a state regulatory framework in North Carolina that would allow for recovery of financing costs during construction. Important for the proposed nuclear units at Lee and Harris, we need to be able to recover financing costs as they are incurred to ensure reliable cash flow during construction and to maintain the strength of our balance sheet. As we keep new nuclear as a viable option for the future, we're actively learning from nuclear construction projects in the U. S. And also at multiple locations in China. In summary, our nuclear team is highly focused on what it takes to achieve and sustain operational excellence. We have a superior track record driven in part by a robust operating model with strong governance and intrusive oversight. With the merger, we're making well placed investment to achieve greater reliability and efficiencies and to take advantage of economies of scale. Nuclear generation has served our customers well for more than four years safely, reliably and cost effectively. Nuclears remain an important option for future generation and diversity. Thank you. And at this point, I will take your questions. Quick question, going back to Slide 26 where you're showing the what happened your analysis of the legacy progress? Was it that their performance had flat line for years while the industry improved or did their fleet performance deteriorate? I can speak with confidence about the current state. And I can also tell you that I assure you that the whole industry, I think your point and that is did we not keep up with the industry performance improvements? Probably more than the case. Anytime there is a disparity in performance, the whole industry moves up in performance at a rapid pace. It's a competitive industry. Today, we operate 11 plants. 8 of them operate at the excellent level. They are the envy of the industry and we will maintain them at that level. 3, while they meet all standards of safety, they have gaps to excellence. And as I mentioned, our operating model and the manner that we operate the fleet, I am confident we'll be able to close those gaps very quickly. Yes, I'm sorry, right there. You laid out the cost for Fukushima requirements. And you also mentioned there are some uncertainties as to the exact requirements in the spending. The total amount struck me as fairly robust relative to some of the varying measures. As you've talked to the nuclear community and your colleagues elsewhere, do you see a fair amount of variation in how different operators are approaching Fukushima compliance and estimates? Or is it a fairly uniform approach? And where would you put yourself in the spectrum of how conservative you've gone in the cost estimates here? So just a little background, that is the NRC put out their recommendations or their requirements in 3 tiers, Tier 1, Tier 2 and Tier 3. We know more about Tier 1 than we do about Tier 2 and 3. Timing for Tier 2 and 3 is really still vague. Even with Tier 1, some of the rules are not yet well defined. So as a result, you'll see variation in interpretation. We are very close as an industry to try to understand exactly what a requirement means. But even with that, there's some variation. And the design requirements are different. I have only 2 VWRs. Other fleets have 12 VWRs. Certain modifications may be more expensive than others. And so it will play into their strategy differently. But big picture, you start with analysis and you start with walk downs. That is what Tier 1 emphasizes first. To the extent that you find vulnerabilities, you have to address them with modification, which will cost money. Our approach relative to others, I would tell you that we have more of a bias to say we are likely going to do the modification. So those numbers reflect that bias, while others maybe have more confidence in their ability to their analysis to show different results. So our bias, I would tell you, I am confident, is heavy on the conservative side for modification. Okay. And we'll have 2 more questions here and then we'll go on to Lloyd. Yes. Going back to the earlier question and that slide where you talked about the drop in your performance indices. Just curious how the merger integration has gone on with the Progress fleet coming into the Duke fleet? And was the issue of overstaffing? Give us some sense of where you see the change and how Give us some sense of where you see the change and how easily you've been able to blend the 2 fleets? I would tell you that blending the 2 nuclear fleet into 1 has been a bright spot for us. I'm very pleased of how well we have come together as one team. You will find Jim showed the first layer of management. If I fold my layer, you would find very equal balance between legacy progress and legacy to clear Processes that we're aiming for, for the future really don't necessarily represent uniquely Duke processes or legacy progress processes. We're pursuing industry best standards as the new processes for the fleet. Integration, I am so pleased with how well things are going. The second part of your question deals with, so what is it that you're finding? We have expertise on both sides and they excel in certain aspects of the business. The methodology, I would go back to my discussion about the methodology. We have to be able to detect signs of decline very early and turn them around. That is the key to the future. You cannot rely on metrics to tell you that you need to make a change. Ask me what is the single thing that will make a difference in performance, it would be that. And the corporate infrastructure that we have in place, which is supplemented by Legacy Progress folks, it will do DWRs that you mentioned, costs are going to be higher. Can you give us an idea of the costs that you outlined? How much are for the BWRs? How much is for the rest of the fleet or any type of percentage? You're talking about Fukushima. Fukushima, yes. The only difference between the rest of the fleet and the 2 VWR units are the hardened vents. There is a question about whether the hardened vents will which approach would you take? There's the filtered the hardened vents versus method of confinement that the industry and the NRC are still negotiating or develop like a strategy for. That is the only unique aspect of the difference between BWS. So if we go the extreme and that is a filtered hardened filter vents as opposed to what we believe would be an adequate strategy of just hardened vents with a confinement strategy. We believe that's a better approach from an overall safety point of view. But let's assume we go to the extreme. The modification, no one has done a detailed analysis on that, but conceptually would add $50,000,000 per unit in modification space. All right. Well, folks, thank you very much. And at this point, Lloyd will discuss the regulatory business. Good morning, everyone. So I'll focus on the regulated utilities, specifically the rate cases we filed and the ones we're preparing to file. Like my colleagues, I have three facts about our regulated utility strategy. 1st, we must begin recovering the cost of fleet modernization program discussed by Keith and Fea, poised to do so in our near term rate cases and this will drive earnings growth. 2nd, we operate in constructive regulatory jurisdictions with competitive rates. 3rd, given the industry landscape Jim described, we must find ways to reduce regulatory lag and earn closer to our authorized returns. Next slide shows our 18 month regulatory calendar. As you can see, 2013 is a very important year for the company. We filed 2 rate cases in North Carolina, 2 in Ohio. Carolinas case next month. Altogether, 6 rate cases will total more than $1,000,000,000 of revenue requests. In addition, this summer we expect the Ohio's Commission decision on our capacity case. Every of these instances will work with the commissions and interveners to reach constructive outcomes to recover modernization investments and to earn returns. Let's take a closer look at these cases, starting with the Progress Energy Carolinas case on the gas turbines totaling almost 2,200 megawatts of capacity. 2 of the plants are complete and already providing fuel saving and the 3rd plant will be in service by the end of the year. These plants were approved by the commission and are coming into service on time and budget. This new capacity supports the retirement of 1500 megawatts of older coal fired generation. Those retirements have already started taking place. Last October, Progress Energy Carolinas filed its 1st rate case in North Carolina in 20 5 years. Request is for an increase of about $359,000,000 in annual revenues, representing an 11% increase in overall rates to our customers. As you can see on the pie chart, 72% of this case is associated with new capital investment. Now just this week, we had an important development in the case, settlement with the public staff of the North Carolina Commission. Let me give you the key terms of this settlement. $151,000,000 in revenue increase in the 1st year and another $31,000,000 in the 2nd year. That's a 5 point 7% increase in rate to our customers in the 2nd year, a 10.2% return on equity and a 53% return 50 3 percent component equity component of our capital structure. Hearings begin on March 18, and we expect a decision in time for rates to go into effect in June. Now we're pleased to have a settlement, but several regulatory decisions are outstanding such as cost allocation and rate design and not all interveners are signed on to the agreement. South Carolina, Progress Energy is evaluating filing a rate case later this year. Now let's turn to the rate cases for Duke Energy Carolinas, starting with the one filed several weeks ago that's shown on the next slide. This rate case seeks recovery of costs associated with the New Dan River combined cycle natural gas plant and the advanced Cliffside coal plant. We're also requesting recovery associated with modifications and enhancements to the Oconee and Maguire Nuclear Station. Request is for an increase of $446,000,000 in annual revenue or a 9.7% rate increase to our customers. More than 90% of this increase is associated with new capital investment. This rate case is the last of 3 Duke Energy Carolinas cases in North Carolina to recover investment in new generation and to upgrade existing plants. In addition, Duke Energy Carolinas be effective in the Q4 of 2013. Now let's take a brief look at the election and gas distribution cases in Ohio. Combined, they represent a requested annual Now the next slide is an update on our $728,000,000 capacity filing in Ohio. Harries began this spring and there are a few points I want you to keep in mind. 1st, our filing is consistent with the new cost based compensation mechanism for fixed resource requirement utilities, which includes Duke Energy Ohio. 2nd, we're not seeking to change the electric security plan under which Duke, Ohio operates. Cassie is a non competitive service outside the provisions of an ESP. Then 3rd, our request would justly and reasonably compensate us for providing capacity services. We'll file testimony in this case tomorrow. The commission staff and interveners file March 19. Technical hearings So that's our calendar of rate cases, important proceedings on multiple fronts. Slide, I'd like to mention a regulatory proceeding in Florida as a follow-up on our recent decision to retire the Crystal River Nuclear Unit. As shown on this slide, the current schedule calls for us to file testimony March 18, followed by the commission staff and intervenor filings in mid May. Following an informal conference this Tuesday, the Florida Commission Commission staff asked that the company file a motion to lift the March 18 filing requirements until a new date can be set after a March 12 issues conference. Currently, the expectation is that the commission's focus will be in 3 areas. 1st, to the company's decision regarding retire versus repair of the unit 2nd, determine the prudence of our acceptance of a third party mediator's proposal of the insurance settlement with Neil. 3rd, determine the scope of the regulatory assets that will be included in rates beginning 2017, compared to 2012 settlement. We expect the commission to issue a revised procedure schedule later in March. Now with all of this activity in our jurisdiction, let me focus a moment on our regulatory environment. I think that's obviously important for our investors. Next slide summarizes an independent ranking of the regulatory climates in our retail space. Many of you are familiar with regulatory research associates. FARM closely follows the actions of the utility commissions throughout the country, evaluates them from an investor perspective, above average, average and below average. As you can see on this slide, 80% of the retail rate base in our 6 jurisdictions exists and above average are rated above average. For the next slide, you can see the diversity of our retail customer mix. This diversity supports our lower risk profile and it helps us manage the ebb and flow of our economic cycles. If you look at the Carolinas, Ohio and Indiana, they have the greatest percentage of industrial load and they'll benefit as the economy continues to recover. Florida on the other hand has the highest concentration of residential and commercial load, more than 85% of and will move to Florida and tourism will also continue to be important. Our wholesale sector continues to be a source of growth. Long term contracts we have in the Carolinas are a case in point. A new 20 year contract went into effect this year between North Carolina EMC and Progress Energy Carolinas for about 1,000 megawatts of incremental load in 2013, growing to 2,000 megawatts by the end of the contract. An 18 year contract between Duke Energy Carolinas and Central EMC in South Carolina will deliver approximately 115 megawatts of load in 2013, growing to 1,000 megawatts of load by 2019. These new contracts provide additional growth over the coming years on top of the growth in the retail business. Here on the next slide, our customers expect reliable service and reasonable rate. This slide shows that on average, our rates are below the national average with the exception of Florida and Ohio. As Keith discussed earlier, the merger will provide 687 $1,000,000 in savings over the next 5 years to our Carolinas customers from joint dispatch and fuel savings. These savings will help moderate the impact of the future rate cases as we continue to modernize our infrastructure. Our competitive rates are also important in attracting new businesses, which will stimulate broader economic growth. On the next slide, you can see Duke Energy is committed to economic development. We're very hard at it because the strength of the areas we serve is fundamental to our long term business success. Expanding industries want reliable affordable energy and our proven ability to attract and retain companies is a good sign of customer satisfaction. 2012 Duke in progress helped to attract more than $3,500,000,000 in investments in new and expanded business. For a record 14th year, Site Selection Magazine in 2012 recognized Duke as being among the 10 best utility companies in promoting economic development. The magazine also ranked 6 of our retail states in the top 12 in the nation for business climate. North Carolina was ranked number 1, Ohio ranked number 2. We're also a partner in a current initiative to expand the success in Charlotte Energy Hub into a broader regional energy cluster in Carolinas. Last year, we helped to develop the Research Triangle CleanTech Cluster in Raleigh, which dovetails with the research and manufacturing strengths of our region. So our focus on economic development is really paying off. We've seen several large industrial announcements in the last couple of years. Let me give you a couple of examples. Michelin Tire, which is South Carolina's largest manufacturing employer has announced over $1,000,000,000 in expansion in the last 2 years. Continental Tire is nearing completion of a $500,000,000 tire manufacturing plan, which provide over 1600 new jobs in the Sumter, South Carolina area. Let me change gears and say a little bit about regulatory initiatives. As Jim talked earlier about some of the macro forces shaping our industry, this new landscape calls for a fresh look at regulatory models and mechanisms. Both cases were not achieving the returns our regulators have authorized. The regulatory process itself is a major reason. We need to close this gap. We're going to work hard to close this gap. This will keep us stronger financially and provide a lower cost of capital, which will support our capital improvement programs. We're exploring legislative and regulatory solutions that benefit all of our stakeholders. We're considering ways to track and recover costs more efficiently and to smooth out customer rate spikes. Forecasted test years, greater use of trackers, faster, more predictable review times for the rate cases. So let me summarize. Our regulatory calendar presents significant near term opportunity. Our rate cases are largely driven by investments in modernizing our system. Reasonable outcomes in these cases will provide a strong basis for top line growth. We operate in constructive regulatory environment, and we're well positioned to continue attracting new business in our service area. We're exploring new ways to reduce regulatory lag and adapt the rate making process to the energy landscape. Now I'll be happy to take any questions. What is the path you see kind of by state as far as looking at ways of putting decoupling other mechanisms in place to help mitigate some of the rate pressures on an ongoing basis related decisions or are these going to be legislative opportunities as you guys lay out your strategy? Okay. Sorry, I don't Okay. Sorry. I didn't want to deafen anybody. On the last comment you made about the idea of looking at ways to mitigate the impact of slow demand growth, can you walk through the stay by stay strategy of how you guys look to address that? And then how much of that is going to be commission related versus legislative and trying to get to those solutions? So I think as opposed to walking state by state, because I think all of those states are different. I think our focus is looking at the various jurisdictions, working with our legislators and regulators to come up with ways to reduce regulatory lag as opposed to going state by state. I'll give you an example. If you look at Indiana right now, one of the things is we're working with some of the legislators on Senate Bill 560, which really looks at reducing regulatory lag, has a T and D right and that's just still in process, but has a tracker for transmission distribution investment, has defined approval timeframes for rate cases, 300 days or a 60 day extension. Extension. So things like that, we'll look at something in the Carolinas working with again that will be more legislative. In Florida, we have a fair number of trackers, formula based rates in some formula based rates in some areas where it makes sense. But I think we do need, as Jim mentioned earlier, we need to work hard to start changing these regulatory models because of the slow load growth. Laurie, can you talk about the economic development slide? And will that help lead into anything other than 5 or 50 basis points load growth? So I don't know how many basis points low growth it will lead to. I know that we work hard on it every day that we have several opportunities. You start to think about the Carolinas that I mentioned earlier, excellent places to do business. When we see an opportunity, we'll travel with some of the commerce teams in the states and we'll work really hard to bring those in. Data centers are good opportunities for us. Manufacturing facilities, some service industries been very successful. Our industrial rates are relatively low. Our customer satisfaction high. And as a result of that, we've been able to track manufacturing facilities to manufacturing and other facilities to our service areas. So Crystal River 3, could you talk a little bit about how the $600,000,000 of nuclear decommissioning funds are presently invested and whether you have any plans to change that. I know you have a mix of debt and equity and the like. And what is the process for no longer presumably charging whatever expenses you have relative to that plant to operating earnings but switching it over and charging it against the decommissioning? So the first question in terms of how the $600,000,000 is invested, I'm going to punt that to Lendgood for later. All right. So how about saving that question? I'll give you the second question again. How do you all assign costs related to Crystal River 3 now and will those be charged against operating earnings or are they charged against the decommissioning fund? So today correct me if I'm wrong here then today they're charged against operating earnings. But the plant went came out of the rate base January of 2013, right? So I think that would be a better question for them to answer also. Why don't you give it a microphone? Can you hear me? All right. I know you can't hear me. The decommissioning fund, there are rules on how often and how soon you can tap into it. Currently to plan for the safe store, we have access to 3%. Once we file So Carl, I think under the safe store provisions, we're talking about decommissioning 40 to 60 years from now. So we have a long runway to continue to invest and earn and the allocation of assets will be consistent with that decommissioning plan and that's something we'll monitor on an ongoing basis. You should think about it almost like pension funds. So you do have a debt and equity mix, you also run a variety of Monte Carlo simulations on investment performance and cost structures decommissioning, you have a probability of full funding and we monitor adjustments we do pension funds. Bob? Boyd, how are you thinking I mean, this is very important year from a regulatory perspective, lots going on in the Carolinas and in Ohio. How are you thinking 'fourteen and beyond what the rate case cycle across the broader system looks like, whether you are likely to be in front of your regulator every other year filing rate cases like some of your peers are or whether you have the potential to kind of slow down that process over a multiyear cycle? So the way I would answer that question is I think that environmental investments. If you look longer term at our integrated resource plan, you see some investments in the Carolinas System Mechanic Cycle Gas Servants in the 2015, 2016, 2016 and 2017 timetable, there's some investments that need to occur in Florida and depending on earnings, they may drive rate cases. But right now, there's nothing definitive after we execute the Fire Synergy Carolina, South Carolina rate case. There's a gap there. CapEx forecast for the next few years as well as kind of that 4% to 6% earnings growth rate that Jim laid out at the beginning of this. There's not follow on rate cases in that cycle for the next 2 to 3 years after the current wind down? Not right now. Yes. I wanted to ask you, I mean just to sort of clarify this, when you mentioned these new regulatory initiatives, I mean, I heard trackers and forecasts here, but things like stable watt and even decoupling, Those sort of things, it seems like you guys you didn't mention. So I guess those are sort of not really they didn't work out so well in the past and maybe they were before their time kind of thing. I just wanted to sort of understand whether or not those sort of things were at all on the table if you were exploring them. That's number 1. Go ahead. Then number 2, on Florida, there's an effort that seems to be gathering some steam. I mean, there's always been efforts to repeal this nuclear clause thing, but it looks like there's more of an effort, at least in the state Senate there, or more of a concern about how that nuclear clause has been working. And I was wondering if you could address that in sort of the larger context of trackers. There seems to be a little bit of pushback maybe on that and also we're hearing a little bit of 5.60 as well. If you could just give a little bit more color with respect to that? Sure. So I would tell you that everything is on the table. I just didn't mention all those save a lot energy efficiency programs and those things. So we have a lot of ideas right now. And I think the important part here is to have those discussions with our regulators and legislators. So that 4 or 5 years down the road, we're all aligned in terms of where we need to go with respect to our business and our customers. I think in Florida, there have I think 4 senators who introduced a change to this nuclear legislation bill that occurred back in 2005, the bill was signed. And we still believe that that makes sense. Construction work in progress for new nuclear makes sense right now, some of those plants will start to retire in 2030, 2000 and 40 and provisions like this 2,005 legislation make very good sense for companies to build new nuclear. And I think as time goes on in the legislation down there, I think we'll work with them and think they'll come to the right resolution. It seems that there's some concern with respect to the whether or not this plant will actually come to fruition. So I guess I'm sort of wondering is how much I guess the risk is there if in fact worst case scenario was repealed, it sounds like there might be some modification or whatever. Just any sense on that? I don't have any I mean, I can't speculate on how we go, what kind of how the bill is going to change. Yes, sure. But just in terms of the quantification, in terms of how much does it take with respect to that? In dollars? Yes. In money. And the way to think about this, we've collected $676,000,000 from our nuclear cost recovery and we spent about $1,000,000,000 this is for the Levy plant, I think. Is that the number? So is that the question you're asking? Okay. Just I'll follow-up afterwards. I appreciate it. All right. Bob? A lot of the investment over the next few years will be in construction of new plants and modernization. Where will the rate base growth come from in the second half of the decade through say 2020? And how should we look at the level of rate base growth over the second half of the decade? So I'll start with this. You saw some Keith mentioned some of the environmental spend and we are so I think there's always opportunity to spend capital. If you look at our company, we never seem to run out of opportunities to invest capital. I think that there are opportunities on transmission distribution grid for grid modernization that haven't shown up yet. But we have lots and lots of projects where makes sense to invest in crude makes sense to invest capital into the system. So I think everyone's looking question is 4% to 6% growth earnings growth and how that translates to our ability to invest capital to grow that rate base. I think we're on pretty solid footing. We have lots of opportunities to invest more efficient energy, I think there's plenty of investment opportunity there. Thank you. As part of the session this morning, we'll resume to 10:30 Okay. If you could take your seats, please. We'll get started here in a moment. Welcome Welcome back to the 2013 Duke Energy Corporation Analyst Meeting. Our next speaker today is Mark Manley. Mark is going to talk about commercial businesses, provide an overview of that area. Mark is Executive Vice President and President of our Commercial Business. So Mark? Thank you, Bob. Good morning all. I took over this business function 2 months ago after serving as General Counsel for 10 years. And I'm delighted to lead the business and to talk about it with you today. As you know, the commercial business is comprised of 2 reporting segments. 1 is Duke Energy International and the other is our domestic commercial power. And before I take those in turn, let me do what others have done. And you've seen the rhythm, identify the key takeaways, which generally come in 3s. First, we follow a low risk business model. What's this mean? We have operations that by and large are highly contracted in terms of the assets. Those assets are diversified by geography, by regulatory structure and fuel mix. And this diversity provides stability and growth of earnings as our track record has demonstrated, which I'll get to. 2nd, the diversity helps support Duke's financial objectives. We participate in growth markets in international and in renewables. And with our Midwest commercial generation, we have strategic flexibility. 3rd, we do have challenges with our Midwest commercial generation, but we're focused on what we can control. As Lloyd mentioned, we're pursuing a regulatory strategy to get our capacity costs and we are also controlling our costs, which I'll get into. Let me turn to Duke Energy International. It consists of 4,600 megawatts of highly contracted more than 60% hydro, low cost, clean generation. Let me note a couple of things that are on this slide. We also have a 25% investment in National Methanol Corporation based in Saudi Arabia. It's a joint venture with a Saudi company, with a Celanese company and with Duke. This investment has demonstrated very strong historical earnings and cash flows. It's typically contributed between 20% to 30% EI's adjusted net income, and we've extended the arrangement through 2,032. 2nd point I'll note is, as you'll see in the lower right hand chart, our operations in Brazil, Peru and National Methanol typically account for more than 90% of total earnings for DEI. DEI. Chile, as you know, we've invested in Chile last year. It's long been a target market for purchased a 2 40 Megawatt capacity play called the Umghai Diesel Facility. And then in December, we closed on 2 hydro projects that are completed, third point is, EEI is positioned to self The third point is EEI is positioned to self fund this growth and its growth, consistent with our return and risk objectives. As of the end of the year, we had a balance of $1,100,000,000 in offshore cash and we continue to look for ways to tax efficiently to bring the cash back to the U. S. Finally, as you see on the slide, last year, 18% of Duke's overall adjusted net income were comprised of earnings from EEI. On Slide 49, this slide gives the metrics of why, at least, we think Duke Energy International is so important and such a good contributor. And let me start from the chart in the upper left. Compared to the U. S, the GDP growth and expected growth in our principal markets, including Chile that we just entered, is higher than the U. S. Now that leads, as you go over to the upper right hand chart, we've talked about anemic growth in demand in the US from data we have, which is not weather adjusted. Demand growth in the US has even trended nationally below 0. But look at the demand growth in Chile and Brazil and Peru and other Latin American countries, greater than 4%. And what's the limit to that demand growth? If you go down to the lower right hand chart compared to the U. S. In terms of per capita consumption of electricity, these markets still have a long way to go to reach our levels of energy use. And then finally, if you go over to the lower left, this chart represents what the net income of DEI has been over the DEI has been over the past several years, a very strong performer, 24% CAGR over that period. Let me answer a question that we agreed to take up today that came up on the earnings call, and that is the drought condition in Brazil. This is a busy chart. What it depicts is 12 years of reservoir levels in the region where we have our dams and reservoir, very critical southeast region of Brazil. The very bottom line is that I think it's red, is 2,001 reservoir levels and that was the worst drought year during this period for Brazil. It led to rationing. You can see why we and the industry was concerned at the beginning of December, that reservoir levels for this year, which are depicted in that blue line that hadn't obviously yet completed the year, was on par for 2,001. And let me just remind you, the rainy season Brazil is roughly November to May. So the rainy season was delayed. What has happened since then? The rains have returned. We're above where 2,001 was. As of now, the reservoirs are at about 45% of capacity. And based on government methodology of taking rainfall and computing it to expected reservoir levels. By next month, we expect to be up to 55%. So that's the status on the 2013 expected contributions from Brazil, we've lowered it somewhat. And obviously, we have upside if it gets to the other part of the curve, and we have downside if it doesn't continue rating. Turn to Slide 50, an overview of our Domestic Commercial Power segment. It's comprised of 4 separate businesses: Midwest Generation, Duke Energy Retail, Duke Energy Renewables and Commercial Transmission. A couple of points on each of these operations. The Midwest generation consists of 3,700 megawatts of coal and oil fired Generation and 3,200 Megawatts of Natural Gas. Duke Energy Retail, we created that in 2,009 to acquire retail customers in Ohio on a defensive basis and defend margin deterioration as a result of lower Duke Energy Renewables started that business in 2,007, and we've grown it to 1700 megawatts, 1600 megawatts of wind, 100 megawatts of solar. And most importantly, in this we've consistently delivered what we said we would through long term up to 15 years contracted projects with attractive risk adjusted features. And finally, our commercial transmission business, there we're focused on transmission projects out of our service territories that basically integrate renewables with load or relieve congestion. We have a joint project with AP in the Pioneer line in the Midwest, and we have a broader joint venture with the American Transmission Company to pursue projects. Let me turn to Midwest Commercial Generation. Make no mistake, we're not satisfied with financial performance of these assets. But the good news is it is a good set of assets and it's well positioned business to adopt the market changes and pending environmental regulations. All of our coal units with the exception of Bexch become economic with the pending environmental regulations. And the full status of all of our generation is outlined in appendix in my materials. While we've achieved some clarity on this generation through the approval of our current market based ESP, we still need more clarity as Laurie has indicated with respect to our cost base capacity filing. He has covered that. I won't go into more detail. I'll simply note that we'll wait the outcome of that proceeding these assets, the regulatory proceeding that Lloyd is leading and discussed and then on the right, the operational things. With respect to operational, we've done a very focused effort to control our O and M expenses, and we focused in 3 ways. 1, we manage this fleet of combined coal and gas as a single fleet, so we exploit scale synergies. 2, we've been hedging Finally, just as Keith explained with respect to the regulated fleet, we are exploring ways to move more of our costs from fixed to variable, so we can adjust and have the flexibility with respect to those assets in a dynamic market. But what has our team done in these areas? Let me give you some details. Their focus on 2010. And as a result, we've reduced Duke headcount by more than 20% since 2010. And as a result, we've reduced our fleet O and M on a per megawatt hour basis by over 25% from 'nine to 'twelve. So these are a good set of assets. We think they're very cost effective. Then on our hedging strategy, this year with hedge and locked in margin with respect to more than 80% of our expected economic coal burn and over 50 percent of our gas fleet. Turning to Duke Energy Renewables. As I indicated, since our entry in 1,007, we have brought this business to scale. We were very busy in 2012. We added 6 50 megawatts of additional net owned wind and solar capacity, all within budget and all within schedule, although we came right to the end of 2012. And so today, we operate 1700 megawatts in 11 states, and we're now the 5th largest renewable generation producer in the U. S. Importantly, again, this growth has strong financial underpinnings. We only build projects once we have long term PPAs that lock in good returns that Lynn has approved based on her conservative hurdle rates with credit worthy counterparties. Each of our developments, we've worked the documents, are project financeable. And with respect to this growth, we have project financed over $1,400,000,000 of our growth. And likewise, we look for good joint venture partners to limit our CapEx obligations. Our first venture was with Sumitoto Corporation in 20 12, and that involved 3 no, I'm sorry, 2 Kansas wind projects with a total capacity of 300 megawatts. So as to renewables, we will continue to pursue further growth opportunities, particularly in solar. We'll use the same approach. We won't do the project unless we have a long term PPA that, on the basis of risk and returns, meets our objectives. So let me finish by summarizing our commercial business strategy. Again, we follow a low risk approach with highly contracted generation assets. We have historically and we expect to are keenly focused on Midwest generation of generating good returns for that great set of assets. With that, I'll welcome your questions. Two questions. First on Brazil, there's obviously there's been a lot of news out there with regard to regulatory dynamics for those whose concessions are coming up for renewal. Yours are not, but you probably have some indirect exposure that as your hedges roll off in 2015, 2016 and beyond? Yes. Can you explain your what's happening to the directly exposed companies and how you might be indirectly exposed? Yes. And as you can imagine, we've heard a number of questions about that. And here's our analysis and why we're not overly concerned. 1, we look at this and say, 1st of all, Brazil is proceeding within the rule of law. These concessions are coming up. The 2nd, we need to recognize some of the statements about the expected reduction in pricing, which could have indirect effects on us are said in a political context and elections coming out from 2014. So I think they need to be understood in that context. And now to get to us, as you mentioned, we're not directly impacted. The law applies to concessions that were granted before 95 and are due to expire the next couple of years. All of our concessions were granted after that point. And then finally on the indirect, Lynn again will mention some of the things that lead to variability in our earnings projections for this year. With respect to Brazil, we haven't reduced our expected earnings for the following. And I included this data, I think on Page 3 of the appendix. 1, we're very highly contracted. So for this year, those assets are 97% contracted. By 15, they're still almost 80% contracted. By 2017, they're still over 50% contracted. And as we calculate the contract prices, I'm not going to give you the exact ones, they're proprietary. But we have an 8% growth in our contract revenues or prices from 12% to 15%. So we think we're fairly well protected. That being said, we're watching it carefully. Uh-huh. Second question was on assets in the Midwest. For the same timeframe, it looks like and just based on what you're showing in the appendix that we should count on a fairly substantial improvement in capacity revenue? And that's our hope. I think we've included what the auction prices have cleared. And as you know, the capacity revenues in PJM for 2012, 2013, 2013, 2014 were very low, well below what we need for attracting new entry. They're going up the next 2 years, still not where they need to be. And again, we're counting substantially on getting fair treatment with our capacity filing and getting the cost based revenue to the extent the PJM capacity payments don't cover our costs. Give you the opportunity to get the easy question, but I wasn't selected for the first one. So you'll probably hand this off to Lynn, but you talk a number I'm going to ask Lynn to handle it. Okay. What's the question? Lynn, Mark mentioned a number of times terms like risk adjusted returns and returns consistent with your objectives and the like. And I'd like to know more about what your objectives are that you're striving to meet. Okay. Well, let me give you my perspective. And my wet blanket at the first table will describe her objectives. But as you can imagine, we approach a number of projects, whether it's renewables, whether it's potential projects in Latin America and we go through an elaborate process leading up to Jim. The Treasury gives us a hurdle rate for the levered unlevered cost of capital. We add a sovereign adder. We add various other adders and we evaluate it. So that's what I mean by risk adjusted and those hurdle rates and it varies by country, it varies by project we're doing. And I'll say a word Chile. It's not as if in Chile, we haven't been paying attention. We've been outbid because other people in the past several years apparently have more liberal return objectives. We were able to get these assets in Chile consistent with our risk view, consistent with our hurdle rates, luckily because some other people, particularly the Europeans were sitting on the sidelines. So Lynn doesn't let us get deal fever and bid more than the risk adjusted return would permit. And she's either bemused or mad at me. Anything else? Okay. Next is the main event, Ms. Lynn Good. As you can tell, one of the most popular things I do is establish cost of capital. So, we'd love to tell you more. But thank you so much for being here. And as I look around the room and see how many people have already flipped fully through the deck, we have a lot of read ahead. I'm just going to fill in the gaps for you today. And what I'd like to do is cover, of course, our 2013 earnings guidance, CapEx and financing plans, our long term growth expectations, and finally, our dividend policy. And I'm going to begin as my colleagues have with the key takeaways from a financial perspective. First, with the merger of Duke and Progress, we have created a low risk predominantly regulated business that will generate reliable earnings and cash flows well into the future. 2nd, we have an established track record of meeting our operational and financial objectives. As Jim mentioned, since 2009, we have delivered average annual earnings growth of 5.7% and dividend growth of 2% annually. And finally, our scale, diversity and strategic flexibility give us unique strength on which to build for the future. With that backdrop, let me start on Slide 57 by discussing our short term and long term financial objectives. Today, we are introducing 2013 adjusted diluted earnings guidance of $4.20 to $4.45 per share with a mid point that's reasonably consistent with our 2012 actual results. As 2013 represents the 1st full year for the combined company, it's an appropriate foundation for future growth. And therefore, it is the base year for our long term adjusted earnings per share growth range of 4% to 6 percent through 2015. Finally, we are also committed to growing the dividend, a very important part of our investor value proposition. We continue to target dividend growth within a payout ratio of between 60 5% 70% based on adjusted diluted earnings per share. Let me now move to Slide 58 and discuss more specifics about our 2013 earnings guidance. In general, our 2013 results are driven by growth in our regulated utilities, offset by share dilution, lower results at Duke Energy International and higher holding company interest expense. This guidance range reflects the potential variability in timing and outcomes from our pending rate cases and deferral requests, as well as our cost based capacity filing in Ohio. These proceedings are important not only to 2013, but for years beyond. Let me begin with earnings in 2013. First, 2013 will include a full year of earnings from the Progress utilities in the Carolinas and Florida. 2nd, 2013 will include partial year benefits from pending rate cases in the Carolinas and in Ohio. By the middle of the year, we expect revised rates to be in effect for progress in North Carolina as well as our gas and electric distribution cases in Ohio. In the last half of the year, revised rates should be in effect for Duke Carolinas in both North and South Carolina. 3rd, we expect weather normalized retail load growth as well as continued growth in our wholesale business due to new contracts. We are planning weather normalized retail load growth of 0.5% for the coming year, year, consistent with the growth we experienced in 2012. We remain cautious as we weigh the strength of the economic rebound and the impact of energy efficiency on load growth trends. Since our projections assume normal weather, we also expect are planning lower O and M as we realize merger savings. Of the almost 700 merger cost saving initiatives, more than 70% of them are underway and nearly 20% of them are complete. Additionally, by the end of 2012, 700 of of low discount rates, as well as emerging costs to support our nuclear fleet. Finally, I want to highlight 2 drivers in our Florida jurisdiction. As a result of our recent decision to retire Crystal River III, we will recognize lower returns on invested capital at this site during 2013. We also expect to fully realize the remaining balance of cost of removal in Florida during 2013. At the end of 2012, we had approximately $110,000,000 remaining, which represents $10,000,000 less than what we amortized in the last 6 months of 2012. Next, let me move to International, which is expected to generate approximately 13% of our consolidated earnings for 20 13. The lower earnings in 20 13, we are forecasting an average exchange rate of 2.12 compared to the average of 1.95 in 2012. Every 10% change in this exchange rate for a full year results at a $0.03 EPS impact. 2nd, the impacts of lower than normal rainfall in Brazil, which Mark discussed earlier. Even though conditions have recently improved, we will continue to monitor developments and their impact on generation dispatch and energy margins for the balance of 2013. And of course, we'll continue to update you on those developments as the year progresses. And finally, lower results of National Methanol due to lower commodity prices. Next, Commercial Power. Commercial Power is expected to have earnings consistent with 2012 and contributing less than 5% to our consolidated earnings. 2013 earnings for this segment reflects the continued low market power prices and lower PJM prices and lower PJM capacity prices. Additionally, the resolution of the Ohio state based capacity filing could materially impact these results. As Lloyd discussed, we are aggressively pursuing these filings and hearings are scheduled for early April. We cannot predict the outcome of this proceeding with certainty. However, a range of outcomes is contemplated in our overall EPS guidance range for 2013. Before moving to a summary of our cash flows and financing plan, let me highlight a few of our overall consolidated financial drivers. First, we will recognize higher interest expense as we incur the full year impact of the progress holding company debt. Additional dilution will result from the full year impact of incremental shares issued in connection with the Progress merger. And finally, we expect an increase in our adjusted effective tax rate from 31% in 20 12 to between 34% 35% in 20 13. This increase Progress, which has a higher effective tax rate. Turning now to Slide 59, I want to discuss our capital expenditures for the 3 year period from 2013 to 2015. From a historical perspective, in 2012, we spent approximately $6,000,000,000 of capital. However, this amount excluded the first half impact from progress. If this progress spending had been included, 2012 CapEx would have been closer to $7,000,000,000 Compared to this pro form a amount of $7,000,000,000 CapEx will trend down modestly in 20 13 as we complete several major construction projects at from 2013 to 2015, about 85% to 90% of our forecasted CapEx is expected to be deployed in our regulated utility. As our major construction projects are completed at FE and G, our environmental compliance spending will begin to Of the $5,000,000,000 to $6,000,000,000 in environmental capital that Keith discussed earlier, we estimate approximately 1 point $4,000,000,000 will be spent in the 2013 to 2015 timeframe. In addition, we expect to deploy approximately 400 $1,000,000 annually in our non regulated businesses. Finally, we will continue to maintain a level of discretionary capital, giving us flexibility to pursue opportunities for additional growth in both our regulated and non regulated businesses. Further details on our capital plans can be found in the appendix to my presentation. Slide 60 demonstrates how the capital in our regulated businesses are expected about $16,000,000,000 in our regulated business over the 3 year period from 2013 to 2015. Of this amount around 8,000,000,000 dollars is maintenance capital, which will substantially offset our depreciation expense. The remaining capital is is $45,000,000,000 at the end of 2012 to about $50,000,000,000 by the end of 2015. This represents a compounded annual growth rate of 4%. Moving on to Slide 61, let me talk through our credit profile and 2013 cash flow assumptions. We remain committed to maintaining our strong credit ratings and liquidity position. Our business plan and any incremental equity through 2015. More details on our credit metrics for each issuer are included in the appendix. We have total available liquidity of $5,600,000,000 at the end of 2012. From a cash flow perspective, we expect our uses of cash principally our capital expenditures, debt maturities and dividend payments will be greater than our sources of cash during the year. We also expect to make discretionary contributions to our pension plan of approximately $350,000,000 during 2013. Our pension plans 13. Our pension plans remain fully funded under the Pension Protection Act guidelines. In order to fund our debt maturities of $2,700,000,000 as well as our cash flow needs during the year, we expect to issue around $4,300,000,000 of financing during 2013. As outlined on these slides, these issuances are expected to include around $2,100,000,000 of first mortgage bonds at the various utilities. Additionally, we expect to issue approximately $1,400,000,000 of company debt during the year, consisting of a mixture of unsecured and retail instruments as well as the $500,000,000 hybrid that we issued in January. Let me now turn to our long term earnings per share growth expectations on Slide 63. The chart on this slide illustrates our consistent track record of delivering on our financial objectives to grow earnings 4% to 6% off our previous stake here of 2,009. This steady growth is even more apparent when adjusting for weather, as shown in the gray portion of the bars. As we look ahead through 2015, the primary drivers supporting our continued 4% to 6% earnings growth include the following: average annual regulated rate base growth of 4% a full year of earnings impact from our pending rate cases beginning in 20 14, long term load growth of approximately 1%, continued growth in our wholesale business adding between $0.07 and 0 point 0 $8 dollars annually to EPS. Ongoing disciplined cost control resulting from additional merger integration savings and continuous improvement, allowing us to offset some of the pressure from inflation and emerging costs. We are targeting average annual O and M growth in the range of 1% to 2 percent disciplined growth in our international business with effective cost control and operational efficiency and finally 15, PJM capacity prices will be $132 per megawatt day, more than 5 times higher than the $23 per megawatt day in calendar year 2013. We will also continue to pursue growth opportunities in our renewables business. We are well positioned to achieve our earnings growth objectives underpinned by constructive regulatory outcomes, effective cost management, including merger integration savings, as well as strong operational performance. Next, let me briefly discuss our dividend. Supported by stable and predictable cash flows from our regulated businesses. We have a long history of dividend payments as 2013 is the 87th by about 2 percent annually. We expect to continue increasing the dividend annually, targeting a long term payout ratio of 65% to 70% of adjusted diluted earnings per share. In summary, we are well positioned to achieve each of our objectives. We expect to achieve the 2013 adjusted earnings per share of between $4.20 $4.45 Our low risk business mix supports growth in earnings and the dividend as well as helping maintain the strength of our balance sheet, liquidity and credit metrics. Let close by going back to a slide that Jim presented earlier. Throughout today, you've heard our plans to focus on the fundamentals of the business, operational excellence, customer satisfaction, financial discipline and constructive regulation. As Jim said, these are the blocking and tackling that every utility generation and geography, our fuel and joint dispatch savings for customers and other merger synergies provide a unique platform to drive more efficiencies in how we do business. Additionally, we have strategic flexibility with our commercial platform. Our entire management team is very focused on achieving these commitments and helping us build upon the track record of continuing to deliver our promises to our stakeholders. So at this point, I'm going to ask the rest of the senior management team to join, and I'll take questions as we gather here on the stage. We're going to have a brief moderated panel with our senior management team. But before I introduce, we have a few new faces that you haven't already heard from earlier this morning. But before I do that, let me just introduce myself to those of you that do not know who I am, Bill Curranz, Director of Investor Relations with the company. As Jim mentioned in his opening, we've got a very experienced and talented team up here. We want to give you also plenty of time to ask your additional questions that you haven't had an opportunity to ask so far. Carl, we'll look for the easy questions first. But let me start it off with just a brief introduction of the 3 individuals and I'll just ask them to briefly raise their hand. We've got Julie Janssen, who is our General Counsel. Julie is also the former President of Duke Energy, Ohio. So all things Ohio are fair for Julie. I just set her up. I'll be looking for a new job tomorrow. We also have Lee Mazzocchi, who is our Chief Integration and Innovation Officer. Very important role with what we're going through bringing the companies together and making sure we're after all the synergies that we promised to you as well as to our regulators. And we also have Jennifer Weber, who is our Chief Human Resources Officer. I'll probably be seeing her tomorrow as well. So let me start it off with a very high level question just to wrap this up for Jim. Jim, 25 years as a CEO in this industry, remarkable, great track record. I know you're very proud in terms of what you've delivered. When you look back over those 25 years, what are the things that have surprised you? What are the challenges that you encountered? And what type of lessons learned could you give all of us? Not working. It's now working. How much of that did you all hear? A little. Well, I've been delighted to be a CEO for 25 years and especially in this industry. And the real lessons, he goes straight to the lessons of these. I saw a slide by Jeff Holzschuh, Morgan Stanley not long ago that pointed out that when I joined the industry in 'eighty eight, there were over 100 utilities in the United States, electric utilities. Today, there's about 50. So I have been here during a period of great consolidation. I've had the good fortune of working to do 3 consolidations and they each been challenging in their own special ways. The first one and every one of them has created greater earnings growth as a consequence of coming together because our cost structures have been reduced. And as the combination itself produces savings, but it also provides a catalyst for even greater savings. And that's where we sit today with a combination that we just did with Progress. As I said earlier, it's critical to change our cost paradigm for the next 5 to 10 years. And this combination will help us achieve that objective. The other thing is, is I clearly see the value in different regulatory regimes. So all your eggs are not in one basket as they were for me back in 1988 where all the assets were just in Indiana. Because commissions I've seen over the past 25 years change in terms of how constructive they are. Some constructive, but not always. And you know this from looking across the country to the changes that have occurred. The other thing I realized is the importance of having great relationships with the regulators. And we're really working hard to have a no surprises type of relationship with the regulators. 25 years, that's been kind of one of my hallmarks. I was and I would have great confidence that Lloyd with his relationships and with the Presidents of each of our states are developing the type of relationships that really allow us to be successful in the future. And the bottom line is, this business is a good business if you can steadily grow earnings, grow the dividend and you'll produce great results, predictable results. Predictable results. I look back over the last 3 or 4 years, we beat consensus every quarter. We beat the annual consensus every year and that quarter after quarter opportunity to listen to some of our team today and now you have an opportunity to listen to all of them. And as I said at the very beginning, with everything that was going on, we still delivered. And that's what matters. That's what matters to you. That's what matters to all our investors and that's what matters to our customers. And if you keep that in mind, I think that's the way we'll be going forward. So I'll stop with that. Thank you. That's a great transition to the next question that I'd like to pose to Lee. Lee, Jim mentioned changing the cost paradigm and delivering on our commitments. That's a large part of what you've been charged with in your role. How do you push accountability of merger savings, other efficiencies, continuous improvement down into the organization? And how do we make sure and our achievements? Thank you, Bill. So first when it pertains to merger savings, the focus area on our fuel savings is paramount. So Keith mentioned this morning $687,000,000 effective savings over 5 years. We've got a pretty strong mechanism of accountability. We actually reconcile that savings on a daily basis. We report out monthly. We also report to our commission routinely and frequently. At the end of 2012, we were $52,000,000 savings actually ahead of our plan and we're well underway with 65% of that savings under contract and the remainder on target to hit the joint dispatch value. Then if you move over to our non fuel O and M savings, Lynn mentioned close to 700 initiatives. So these are projects large and small. Each one has been assigned to a specific owner, some The panel, unfortunately, except for Jim, your lavalier should work. So if we could pass the microphone back over to Jim, we'll make sure everyone else is mic'd up. Let me ask just one other question, and I want to pose this to Jennifer before I know several of you have questions. Jennifer, one building on the merger, one of the critical aspects of a merger and I think one of the pieces that often is underestimated is bringing cultures together. What is Duke Energy doing? What is the focus of the senior management team, the focus of the Board of Directors in terms of making sure that we get 2 cultures brought together successfully? Okay. My wobblyer is on, so it's working. That's a good question, Bill. And you're right, this is often an underestimated area of focus for companies billing through a merger of our size and scale. And so our senior management team decided that we needed to place an emphasis and a focus on this body of work. So we began work in October, engaging a broad cross section of our leaders across the company to get clear definition around the kind of performance culture that we need to have in place to accomplish a lot of the business objectives that you've heard our leaders articulate this morning. And so in the same way we think about our industry evolving, we think about our business model evolving, we think about new regulatory frameworks, we've got to ask the question, how do we need to evolve our performance culture? So one thing became very clear, and you can get intentional about this, and I think that's one of the things that companies often miss is that you can and should get very intentional about defining this. So one thing that became very clear was that our leaders had a shared view and a consistent view of the cultural attributes that we want to strengthen going forward, and I'll highlight some of those. One was a culture of high trust, and this is being viewed as very foundational to another that was mentioned was innovation. So if you think about the way our industry is evolving, Lee mentioned this as well, it's going to require us as a company to innovate, think about new ways of doing things, think about more efficient ways of doing things. And then the other attribute that was mentioned is a culture and this is very, very related to the definition of performance culture of high accountability, high things that were mentioned. We're in the beginning stages of this. We intend next week at an enterprise leadership conference where we're bringing our 400 top leaders together in Charlotte, we intend to get further feedback on how do we bring this to life and how do we execute on this over the next few years. You described a great deal of CapEx and rate based growth, and I'm wondering what the rate impact to customers is and how you balance that over the next 3 years, particularly if you're filing a bunch of rate cases now, but then not filing in 2014 2015? And then also, Lynn, you detailed growth in wholesale of $0.07 to $0.08 a year. Just wondered what that is? And then finally, Jim, if you could talk about strategy for Ohio if the capacity ruling does not go your way? The customer bill impact, Lloyd shared with you specifics on the pending rate cases, the progress in Duke rate cases. So we filed for roughly 10%. The settlement and the progress case is going to be 4.7% year 1, growing to a total of 5.7% at the end of year 2. We're very conscious of maintaining those bill impact increases at a level that makes sense for our customers. And as we look beyond this current set of rate cases, we're going to be leveraging opportunities through merger savings and cost control to mitigate price impact as we look for ways to deploy additional capital into our jurisdictions. So that's something that we're very focused on as we go forward. The wholesale contracts, Lloyd touched on briefly. There are 2 of them that we highlighted, 1 an extension with NCEMC in eastern part of the Carolinas and one with the northern co ops in South Carolina. Lloyd, would you like to add to that in any way? Testing, that would work. So back to the NCEMC contract, it's a significant contract we signed last year, 20 year contract that goes from 1,000 megawatts to 2,000 megawatts, grows to 2,000 megawatts of load over a 20 year period. Central E and C contract signed with Duke Energy Caroline megawatts to 1,000 megawatts over an 18 year period. So if you start to look at the opportunities for wholesale growth, earnings, I mean, it's pretty successful, it's defined in the numbers that Lynn talked about earlier. Since Julie was billed as all things Ohio, I'm going to ask her Leslie to start the answer with her perspective because she's been very engaged in it until most recently becoming General Counsel. If I need the mic or not, no. So I appreciate the fine introduction from Bill and Jim with respect to my past in Ohio, but I think it's probably best that I stick to my legal knitting, as it relates to the capacity case. And so we really believe we have a strong legal premise for a successful outcome in the capacity case. What we heard from interveners primarily was that, we've already received our compensation for capacity through our electric security plan. And is simply not accurate because it's and not to get too granular into Ohio law with you, but Ohio Revised Code Chapter 4,928 which provides for the standard service offer framework within the state of Ohio is one that provides for the service. It goes into depth about whether it's provided through an MRO or an ESP and in fact is very prescriptive about what can be contained within an electric security plan and electric stability and service are of course one of those many factors. It It does not provide for the provision of capacity costs through the chapter. And so quite frankly it could not have been already been settled and whether that's rate judicata or collateral stopple, that too as you all know our electric security matter was not litigated and it was a settlement and quite frankly AEP's capacity case and their ESP case were very separate as are ours in this instance. We are cautiously optimistic about Ohio. But at the end of the day, review our strategic options with respect to those assets. Next, let's go over to I think in the last few days, we've had the Board flesh out its 9th member. So now the super committee is completely filled out. Can you talk a little bit about now that that super committee is completed, what are the next steps that will probably happen in the course of succession planning? The Board has retained a consultant to work with them. And what they're doing is going through a very thoughtful process to identify a successor to me. They have they started on this even before we added the last director. And this process has been, as you know, most important thing the Board does is select the CEO. It's probably the thing that they are most careful about. And that's why process is going to be very thoughtful. It will take as much time as they need to do that. And as I said on the earnings call, they'll both assess internal candidates as well as external candidates and make a decision with respect to who the best leader will be for this company, question is a The question is a follow-up on all this new cost paradigm. Can you just help me frame how I should think about O and M at USF E and G in terms of how much of that O and M might be clause related? Percentage terms are fine. Claws related. Jim, I think probably should get you some specifics on that. I think our clause related recovery is in the range of $600,000,000 to $700,000,000 annually. But I'd like the IR team to do a little more specific work on that for you. Let me ask just one quick follow-up as we get the mic passed around. Tay, I want to follow-up on your presentation. You highlighted a lot of capital and O and M requirements related to performance improvements in Fukushima, just in terms of clarification, are those your costs that you estimate across the entire fleet or are those specific to particular units? Thank you, Bill. Let me start by emphasizing that all of the rules associated with Fukushima is not they're not completely known and they will be known in time. So what share with you is our best estimate based on what we know today. We anticipate over the next 3 years to spend approximately $500,000,000 in capital and $100,000,000 in capital in O and M for the entire fleet. That is for 12 units, 11 operating and Crystal River to cover things like the coping requirements with natural phenomena. For the BWRs, which we have only 2, that includes hardened vents, but not the filtered hardened vents. It includes better instrumentation for fuel pool water level for the entire 12 units and better emergency response communication equipment for the entire fleet. So it's really comprehensive with the whole fleet. Michael, next. What's the landscape of utility mergers over the last 5 or 10 years, even maybe even longer term than that, we've generally gotten actual reductions in nonfuel O and M. I look at the merger that happens in the upper New England area, talking about 3% actual reductions in nonfuel O and M, now different company. But if you look at the merchant merger between Exelon and Constellation, you actually got very sizable meaningful reductions in nonfuel O and M. Just curious outside of in about 1% to 2% range versus an actual decline rate? Michael, we are going to be negative O and M period. We're targeting 1% to 2% over the 3 to 5 year period. You mentioned nuclear being an emerging cost. We also have commitments around vegetation management. We have inflation driver for many companies, us included. So I variety of things. I know the team is challenging themselves to work beyond the merger integration targets that we established because as Jim and others have talked about in this low loaded growth environment, we believe cost control is absolutely essential. And we'll be making those decisions to spend money balancing the need for efficiency with the need to continue to invest in our assets for the future. And so we'll continue to keep pressure on costs. And I actually it's a good target for us to start with and we'd love to beat that if we can. Is a good target for us to start with and we'd love to beat that if we can. Lynn, when I look at the structural drivers you've laid out for earnings growth, your aspiration is to grow 4% to 6% off 13%. Your earnings power of rate base plus QIP as you sort of articulated here grows by 4% a year to $50,000,000,000 plus or minus in $15,000,000 What are the big drivers that could get you to $6,000,000 Because it seems like obviously the vast majority of the business is the regulated utilities, The earnings base is growing at 4%. Is it you expect ROE to go up? Is it that the wholesale business is a kicker? Is it that you're expecting a lot of growth in commercial ops and international? How do we bridge to sort of a base case of 4% to 6%? I think the drivers you talked about, so load growth, I think we have modest load growth expectations. So that would be a positive. Wholesale would be another positive. Additional capital spending, if we can find great ideas and grid modernization and other things, we continue to look for opportunities to deploy capital. And if we can do a bit better on O and M, challenging ourselves to trend it down even further than the 1% to 2% that represents growth. And as I look at 2013 to 2014 with the variability we have in this plan in 2013 on all of the rate case outcomes, state based capacity, cost control and other things, I think you begin to see that we have a range of variability in 2013 specifically as a result of these pending proceedings. Just one follow-up. So in the context of that range, when I think about 4% to 6% and the obviously, you're in many jurisdictions, the average expected earned ROE. From 13 to 15, I mean, is there an assumption that it's the base case, is that a stable earned return, a growing earned return, declining earned return? I'm sorry, Greg, you had a hard time. Sorry. So if you think about the weighted average earned return on equity that represents the base case or the midpoint of that growth rate. Is that a stable return across the forecast period, a growing return or a declining return, sort of the base case? No, I would think about the care line as being kind of the 10% -ish range with cost control and cases driving us up and additional capital expenditures potentially driving us down. And so I would think about in this environment around 10% for the retail returns. We have the ability to do slightly better than that when we introduce wholesale. And the care line is just where I would focus, Greg, on the material driver. Okay. Let's go Dan next. Jim, I guess, well, maybe 2 questions. 1, Jim, can you talk a little bit about your views on carbon policy? It's gotten a lot of attention out of the administration and kind of where you see that progressing and kind of how it affects the long term planning for Duke at this point? Well, first, I think there's a very low probability that there will be a price on carbon coming out of Congress. In this session of Congress and probably in the next session. And I think it's pretty obvious why that's true. I think the big issue is what the EPA does. I believe they have limited capability to regulate CO2. I believe they will try. I believe it will end up in court. It will go through a 4 year battle with respect to their We've tried We've tried to be ahead of the curve with this $9,000,000,000 modernization program that's allowed us to retire these plants. We're reducing significantly our carbon footprint 20% plus this year. Probably by the time we complete the modernization program almost a 30% reduction in our CO2. So we've reduced our exposure to increases as a consequence of the legislation, our potential legislation with respect to it. But from an EPA standpoint, it will be a long battle, a tough battle, long place to try to impose a price of carbon. I guess maybe 2 capital allocation questions didn't come up today. Number 1, your thoughts on the ability to repage great cash out of the United States into the U. S. And are there any tax schemes that go along post the merger that would allow you to do that? And then secondly, the potential investment in SCANA's nuclear plant, which got attention a while ago and then why it's for a bit of So, Greg, we stay Greg, Dan, sorry, we stay very engaged the discussions of tax reform and we're active in 2011 and 2012 around potential repatriation. And we'll continue to be so as tax reform has taken up this year, although we're not hopeful. We also continue to look for structured ways that we can bring cash home and that'll be a priority in 2013 as well. And I think we always maintain the maintain the strategic flexibility of just flat out repatriating. And that becomes an option that we could evaluate the context of additional growth opportunities or capital deployment where the economics of that would make sense. And your question on BC Summer, Theo, do you want to take that one? I did not hear the question completely, but I assume it's about the status of discussions with VC Summer, I think. Yes. In the past, you guys have talked about the idea of being a potential partial investor in the plan. I wasn't sure where that is going and whether there's any doesn't show us. Sure. Yes. So as you know of course that we signed an LOI back in 2010 for 5% to 10% of Sanity Cooper's portion of the plant. We've been performing due diligence ever since and we have not come to acceptable terms. We have allowed the LOI to expire end of last year, but we have continued to negotiate with Santee Cooper to try to come up with the right terms. That's where things stand right now. And as you have questions, please raise your hand. We'll make sure to get a mic to you. Paul? Hi. I wanted to sort of follow-up on Greg's question with earnings growth and what have you. First of all, the 4% to 6% is based on what the mid looking at it's more like a 3% grower. So what I'm trying to gather here just to sort of understand it more, it would sort of imply well, no, actually, obviously there's some growth obviously in commercial what have you. How should we think just sort of would we quantify the improvement in return because that's what I would think would be driving. How much of an an improvement should we be thinking about the utility business having in terms of return? Paul, Paul, similar question here and I'm giving you a bit of a range of ROE. I think it's going to be important for us to complete our work on pending rate cases. We're asking for additional recovery in the Carolinas. Those rate cases are not behind us. And so as we look over the period, it will be a matter of reaching the returns that we are expecting on the additional investment that we are pursuing right now. And then we'll be evaluating whether or not we need to go into rate cases probably after 2015, 2016. The lever that we have to maintain our returns is cost control, which will be a continued focus. And so I would think of us in the 10 ish range. We have an opportunity to go slightly above that perhaps over the period, but beyond that that's what I would share at this point. Okay. And then I guess, Jim, as you're beginning to transition out, any significant change in the makeup of the businesses prior to the selection of somebody new or just any thoughts as you're exiting, should there I mean, I would assume that there probably wouldn't be that big a change, just any thoughts that you could sort of follow-up? Well, it's really a Board decision in terms of the businesses that we pursue. And so on an annual basis with our Board, we review for instance DEI. We review the Midwest generation. We review the renewables business. We review the Midwest Gen. We review all these things annually and think and one of the questions we always ask, do you hold them or fold them with respect to those assets? And that is just part of our process. And so today, the Board believes that the renewable business makes sense and produces good returns with the right amount or appropriate amount of risk. They believe that DEI makes sense given the fact that it produces significant amount of cash and has had been on a great growth trajectory. The Board continues to believe that the Midwest assets make sense, especially in the context of being able to get a capacity payment in Ohio. It's really an open question. As I answered Leslie's question, we'll have to review our strategic options depending on what the result if we get a negative answer from Ohio. So I believe that we have a strong Board. They have clarity in terms of the direction of where our industry is going. And I don't see significant changes occurring in the direction of the company as a consequence of a new CEO, maybe because every CEO has his own view of the future. But our Board is strong, large and has great clarity in terms of where we're going. Okay. Before going to our next question here in the audience, let me pose a quick question to Mark. Mark, you talked a lot today in your presentation about historic growth in countries in Latin America where we have operations and projected growth in excess of what we're experiencing here in the United States. Do you see the international business growing faster than the regulated business for Duke Energy? I don't. I think what we've done in Latin America and by the way, if we get higher prices, we're not going to turn them down. But it's consistent with our strategy. Our entry into Chile was consistent with the strategy. We've allocated to the international business over the past several years a modest amount of growth capital. I think as I intimated, we've either backed out of projects because they didn't meet our objectives or we got outbid on some projects and we just happened to hit the mark with the 2 projects in Chile. We've gone back and I mean I've added up the cumulative amount over the past 4, 5 years of growth capital and we haven't exceeded that. It just came in a lumpy fashion in 2012. So, no, I hope it grows through price increases and other things and demand growth, but we're not making any strategic pivot. Question here from the audience. I have a few follow-up questions, Jim, from your initial remarks during your at the beginning of this conference. One is on solar. I was a little confused as to whether that's sort of a positive or negative for you and maybe you can clarify that specifically for Duke, how the solar industry is playing out and how whether that's positive or negative for you guys. And then another specific is on the natural gas part of your generating capacity. In an ideal world looking out as a long term investor, which I assume you will always be of Duke, how high would you like to see that get as a percent of your overall mix looking out 10 years or beyond? And then lastly, I know these are all sort of subtle questions, but talk a little bit more about why growth is slow from a secular point of view. Is it some of it's conservation and and efficiency and some of it's a slow economy, but let's assume for a moment that the economy really started to pick up and gain real traction 4% GDP. Well, 1st with solar, I think it's both a positive and a negative. And let me tell you what I mean. It's a if you think back 5 years ago, there was legislation pending in Congress that basically would have a national renewable portfolio standard and utilities could not invest in the renewables that they bought. This would have precluded a huge investment opportunity for us. And any time a mall passes that then allow us to deploy capital that's bad news because we make money when we capital. The consequence of the probability of that happening and it did happen, we started a renewables business and we have 1700 megawatts today producing higher returns than from our regulated business primarily given driven by the how we financed it. So we took preemptive action in the event we'd be precluded from all our renewable sales have been utility scale, primarily because that's where the greatest opportunity has been. So if we are preemptive on this, we could turn it from a negative to a positive. The negative aspect of it is and you've seen this in California where they come in and put solar on the rooftop. Those people that have lots of money can put solar on the rooftop. There's some very innovative companies that will put it on for free and kind of buy down your bill over time because of tiered rates in California. And so that is really cut into BG and E and Southern California Edison's load that they've had to provide. So, I'm D and Southern California Edison's load that they've had to provide. So I don't think we're immune from that even though our rates are significantly lower than California, significantly lower than the national average. If the tiering of the rates change that exposes us. And so I think that we have to be aggressive on this as well as to be mindful that this is a real risk and we need to prepare for it. With respect to natural gas, the biggest risk our industry faces today is regulators saying all gas all the time. That would put us in a place that's not a good place because the strength of the power sector today is in our all of our above approach to producing electricity. We need a balanced portfolio of nuclear and coal and gas and renewables and significant investments in energy efficiency. What is the right portfolio is really more of a function of what part of the country you're in. For instance, our Midwest assets are probably always have a higher percentage of coal than they will nuclear. Our Florida assets will probably have a higher percentage of gas. But as an overall organization, we're kind of moving to a place where we'll be almost 1 third coal, 1 third gas, these are rough numbers and probably 1 third nuclear and renewables. So that's going to be the mix that I see for our company and that's kind of a pretty balanced position to be in. But the biggest challenge to us is simply the challenge of avoiding all gas all the time. And you have a third part of your question on the economic recovery and low grade. Just balancing this sort of the pressures that you've alluded to versus I mean if you had a 4% GDP growth kind of economy sometime in the future, would you be less concerned about your secular growth? Or are these other factors really holding down low demand? I think that the recovery from the recession for the economy has been very anemic. Historically, the growth in the demand for electricity tracks the growth in GDP. Think back to the 60s, for every 1% growth in GDP, there was a 5% growth in the demand electricity. If you get to the 90s, for every 1% growth in GDP, there was a 1% growth in the demand for electricity. And most recently, it's fallen to about 0.4% growth in electricity for every 1% growth in GDP. So as an and that's a function of the energy intensity of our economy changing. And so we're at a place where I believe the demand will grow new homes, new businesses. I mean as we said earlier, North Carolina is the number 2 state in the country to do business. So that's important. Indiana is at the top of the list. It just passed a right to work law in the Midwest, the only one. Ohio is improving as a business environment. And there's a lot of residential growth in North Carolina primarily as they call the halfback phenomena. People from New Jersey and New York go to Florida and either don't like the prices or don't perfectly like the weather, so they move back to don't want to go all the way back to New York or New Jersey, they stop in North Carolina and that's where they retire. So we're seeing growth really from that. So while the one hand there's some positive things pushing growth up and making us feel better about the growth in demand. There's also some negative factors like the solar on the rooftop, like the technologies and I've spent a lot of time in Silicon Valley. I've met with a lot of new technology companies and it's crystal clear to me that they're developing technologies that will translate in significant reductions in the demand of electricity. I mean in Charlotte, we have a project now called Envision Charlotte, where we've committed to try to reduce the demand in all of the above area by 20% in 5 years. Projects like that are going on all across this country. So again, I feel probably more of a sense of I see the positives, but I see the negatives. When I weigh both of them, I say let's get prepared for what could be from a growth standpoint, a worst case scenario and that means taking action on calls, changing the regulatory paradigm. Those are critical things that we need to do to be prepared in the event the worst case from a demand growth standpoint becomes a reality. What other questions Questions. And then one I wanted to clarify on Ohio. Could you just first remind us what you've asked for in the best case? If you do get it, how much increment is that? And if I recall correctly, in your commercial power 13 assumptions which you have them commercial power flat versus 12, I believe you have assumed that you get the positive ruling out of Ohio just looking at the slides. I just want to be clear what you've assumed in there for 30? Gently. So Ali, what we have filed for is $730,000,000 for the period of August of 2012 through May of 2015, which is the period that Duke Energy Ohio is an FRR entity. So we are not sharing with you today our specific planning assumptions. We're in the midst of a negotiation. The hearings on this proceeding don't occur until April. But what we have included in the range of $420,000,000 to $445,000,000 is a variety of assumptions and scenarios that could play out in the state of Ohio. So there is an assumption when you look at commercial power being flat at the midpoint there is level of recovery, but I'm not going to share those specifically with you given the status of the proceedings. Okay, fair enough. And my second question, I just wanted to be clear. I think for 2013 you've been very explicit in assuming no new equity issuance. Is that true for the entire 2013 through 2015 planning period or could that change? Yes, it is. No equity through 20 15. Thank you. Let me ask a quick question as we get the microphone passed to the next audience participant just to Keith. Keith, a lot of the cost of the business sits within FE and G, the regulated operations. You talked about moving from fixed to variable cost, taking a critical look at the coal fleet. What are the things that you want to challenge your team in terms of changing the cost paradigm of the regulated fleet operations? Sure. So I start with a bit of a track record. Our teams have done a very, very good job in this front on managing O and M. If you look at 2,007 to 2010, we kept O and M relatively flat during that period. Last year, early in the year, we were experiencing poor weather and so we made O and M adjustments accordingly. So I say that to say we've got a track record of dealing effectively with O and M. So on the coal fleet in particular, I talked earlier about the fact that it's not running as baseload. And quite frankly, we're not projecting that it's going to run as baseload for a fairly extended period of time. What we are doing, we're exploring opportunities one where we can reduce minimums at the coal plants so that we can create some operational flexibility on that front. But beyond that, we're really looking at more transformational things. There's a menu. We don't have that menu defined yet, but some of it could involve going to seasonal operation. Some of it can involve having more traveling crews to reduce workforce. So there are a variety things that we're exploring. I will tell you that there's nothing like a sense of urgency to drive good outcomes. And Mark talked about the work that was done on the commercial generation fleet in the Midwest. I was involved in that operation earlier in my career. And at one point, we challenged the teams there to try to hit a certain variable O and M mark. And the reaction we got initially was, we don't really think we can do that. Well, we are now way below the mark that we initially set for the team. So I think it's part of it is creating a sense of urgency, which I think we can do. Part of it is being innovative and creative. And I think the team is showing that it can do that. One example I'll give that's not exactly on point, but it's related and that is the fuel blending. We have found a way to do more than the team thought they could do. So I'm confident that we're going to be able to change this. But to Jim's point, we've got to change the cost paradigm and we'll do it. Carl, thank you. First, I wanted to say that I've been an observer of this company for more than 25 years that Jim referred to relative to him being there. And I think you've it's always been one of the best managed companies in the country and continues to be that and I would anticipate that it will be that in the future with new leadership You can only go so far as you all work hard and produce good results. Jim started the presentation by talking about anemic load growth. He just went into addition comments on the same theme and 1 percent is on a relative basis pretty anemic and it's not going to produce great opportunities regardless to produce increases in earnings, but that's it is what it is. Having said that, I'm questioning fuel and I'm questioning particular gas. Wall Street Journal has a very optimistic story today about gas, about the availability of gas, how much gas we're going to have nationwide over a long period of time. Is anyone offering you gas under contract for long periods of time? And if not, have you tried to get it? And what are the prices? And is the hedging that Lynn referred to earlier, is that good enough? Or can you be So in terms of long term contracts, I'll tell you historically the E and P companies have not been that receptive to longer term contracts, but that is changing to some degree. And so we have considered some opportunities on long term gas. Again, before you would do anything like that, you need to have your regulators right beside you. And so it's early days in that front. But I think there are opportunities that are emerging. And I think the place there where it may make the most sense are the areas that are more and more dependent on gas. So Florida as an example with the Crystal River III retirement and then the potential retirement of Crystal River I and II in the 2015 to 2017 timeframe, you're going to get into a place where you're 75% dependent on gas. Well, in that kind of environment, it very well may make sense to regulators, customers and to us to look for long term type agreements. And there are different ways that you can structure that. And I think there may be ways to structure it so that we can actually generate some earnings on that. So a lot of ideas going on, but that'll be part this will be part of the innovation that I think we're going through right now as a company. Sure. I have 3 or 4 questions, if I can address them to different members. Jim, first of all, just starting off, congrats. Okay. First question, Jim, congrats. The performance of the company has been excellent over the last 3 years as you mentioned and congrats to you and your team. One point which you mentioned in your remarks in the beginning was how the utility universe went from 100 to 50. Of course, Duke now stands at the top of the year right now. As we go through the next 5 or years, do you think this is going to be further M and A in the group? And I guess the other question would be, is this it for Duke? Is Duke now too big that anything else doesn't make sense for it? It? If I was hanging around it wouldn't be the last one. Would be the beginning of the next round. Because I'm a true believer that building a strong company through combinations makes sense. And I've had my nose bloodied in the process, but I still believe at the end of the day, this creates value for our shareholders as well as our customers. So if I was making a recommendation to the Board, to the new CEO, my recommendation would be look for opportunities. I probably wouldn't do one in the region. I mean given our experience with the FERC and three trials before we got it right as far as they were concerned. But I would look for opportunities to combine and to really strengthen the company going forward because that's just one way to create growth in the future. Then just going to the integration, Jen, I guess you mentioned there were like 4 you're having a meeting next week, 400 top leaders are going to be there. Could you just give us a breakout as you stand here out of those 400, how much are the old Duke and old Progress? What is the combination if I can get a sense? It's actually a blend of legacy Duke leaders and legacy progress leaders. It includes all of our Okay. I'll go to this mic now. This is keeping us on our toes, this microphone. So it includes a blend of the 2 companies, our direct reports, their direct and then a level below that. We think given the news that we're sharing today, given the visibility we're giving this community into our strategy going forward and our growth objectives, we're going to do an even deeper dive from our top leaders and we're going to translate that into our expectations for them as leaders of the company. We're also trying to put them our leaders in a position of being able to articulate our focus and our priorities as a combined company and then we're engaging them on this topic of culture. What I was more interested, could you share with us what the percentage is? How much is a percentage is the legacy deal versus Sure. So I would say, in general, the percentage is about sixty-forty, sixty five-thirty five in terms of the split. And if you look at that in terms of the overall contributions, in terms of the employee count as we merged as a company, it's pretty representative of that. Okay. Okay. And Keith, I Just a question on the regulated side as you take on these combining these two companies. What are the key challenges apart from the rate cases in terms of your job as you're looking forward for the next year or 2? Yes. So one of the key challenges is really this O and M world that we're in, right? And we've talked about a bit about that. And that's really what we're focused on in large measure and it's the hard focus on the coal assets is the challenge. But we're working through that. The other piece of this is we're bringing 2 teams together. And like they have said, we have great leadership from the Progress side, great leadership from the Duke side and they've come together very, very well. But the biggest single challenge is going to be how do we address this new O and M world that we're approaching. Then if I can end up, Lynn, one thing which we have is kind of the dividend growth rate is pretty anemic. Most companies have growth rates which are more parallel to the EPS growth rate going forward. When does the cycle change? Or is it just going to be like the growth rate of the dividend is going to be just half the growth rate of the EPS? I'm just trying to get a sense as to when can the dividend start increasing at a more rate, which is equivalent to the EPS? That's a good question. Because the dividend as you know is very important and growth of the dividend is very important. We've been managing the dividend growth within the payout ratio of 65% to 70% and see our way to getting within that ratio in the next year or so. And I think when we're positioned within the payout ratio, then you could expect the dividend to have the potential to grow at a higher pace. But we think that discipline around dividend growth has been important as we've been spending so much capital for modernization and it's been a trade off that we thought was appropriate. But our commitment to growth is a big dividend is very important part of the value proposition and we think over time there will be an opportunity to accelerate growth of the dividend. Okay. Let's look for one final question from the audience. That has not been answered. Okay, we're past lunchtime. So Jim, let me turn it back over to you for some final comments. Well, I want to thank you all very much for being here. I want to thank you for your interest in our company and your investment in our company. This is the last time I'll be before you as the CEO of Duke Energy. It's been a great honor to lead this company. It's been a great honor to be a CEO in this industry for 25 years. And it's been a great honor for me to work with all of you all, some more than others. But because looking at the age, I mean, some of you couldn't have been in the industry 25 years ago. But the reality is, is that this is a great industry to be in. I mean, I wake up every day knowing that I'm transforming the lives of millions of people when they throw the switch and turn on the electricity. I love public policy. What could be a better industry to be in for energy and environmental policy? And I think that probably the most important thing is, I get satisfaction out of working with strong independent minded leaders like the team you see sitting here on the stage. We're getting ready to change our logo and I think it's popped up on the screen. But that's kind of a symbol of what we're going to be in the future. It will be a little change in look, but it also reflects collaboration. It reflects the recognition that we have to continue to work to reduce our emissions. I mean, environmental issues have been a issue have been key to me, an important part of my legacy, going all the way back to 1990 when I was the only CEO of the industry to support the Clean Air Act amendment with respect to SO2. So we have come a long way together. I have produced strong results for you all. I've done my best and look forward to seeing you in my next line. Thank you all very much.

• Slides