Duke Energy Corporation (DUK)

Analyst Meeting 2013

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Feb 28, 2013

Welcome to Duke Energy's 2013 Analyst Meeting. I am Bob Drennan with Duke Investor Relations Department, we're very glad that you're here to hear from us today. This morning, you'll be hearing from members of Duke Energy's senior management team as they discuss future prospects for our company. Today's discussion is being telewebcast, we 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. Let me briefly describe today's format. In a few minutes, I'll turn the program over to Jim Rogers, our Chairman, President, and CEO, for opening remarks. Jim will provide the strategic framework for this morning's presentations. Immediately following Jim's remarks, we'll move to Keith Trent, who will discuss our regulated utility operations, 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, 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 A.M. We plan to conclude by 12:30 P.M. As a reminder, please mute or turn off your phones and BlackBerries. 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 five. Our senior leadership will describe Duke's strategy and where we stand in 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, recovering our investments. We're also reaffirming our value proposition. It's familiar to many of you all, it's simply this: We're a low risk, primarily regulated utility, well-positioned to build on our record of strong operational and financial results. You'll hear about our track record, how we will deliver value to 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's 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 billions of dollars, have translated into significant reductions in SOx, NOx and mercury. Seen a lot of fads that 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? Well, take shale gas, for example. Who would have predicted five years ago that shale gas and natural gasification and 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 25 years would represent over 52% of the generation of this country, the same percentage that coal has held for many decades in this country? That was a prediction by Black & Veatch. Who would have predicted that we would be in an environment of anemic demand growth? I believe that is one of several key issues. Clearly, with Fukushima costs and modernization of the grid cost and modernization of our generation fleet, we're seeing rising prices. That's part of the future. The growth issue is more complex and more difficult to discern as we go forward. Pushing up demand is you see greater electrification of our economy. You're seeing an anemic rebound in the economy. As more houses are built, as industry rebounds, that will push growth up. Pushing it down is something that's going to be very incremental and harder to measure. 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 $0.50 and $0.60 a watt per panel. To me, that takes away load for us. If you look on the demand side, an amazing array of new technologies that, if deployed, will lead to productivity gains in the use of electricity. There is a balancing of forces here that make it very difficult to discern what the actual growth in demand will be in the future. That's going to require us to think differently as we go forward. The old test period approach to setting rates, I think, is going to be something of the past. We need to work hard to change the regulatory model so that we're positioned to be prepared to handle a world if it turns out that we have very anemic growth. Anemic is less than 1%. Anemic could be flat if you're bearish. The bottom line is we have to be prepared to achieve 4%-6% growth in that environment. 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. 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 organization. Slide six shows 3 types of forces that are reshaping 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. 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 only one priority. That is to support the executive team and board in ensuring that this company is ready for whatever lies ahead. Ready, to me, means with agility, particularly when you're such a large company, with resilience, the ability to look around the corner and see the future before others do 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. Additionally, we have a strong foundation and a robust game plan to succeed in a changing energy landscape. Slide seven gives you a sense of Duke's 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, customers served. Scale importantly helps us to achieve cost savings, that will benefit customers as well as investors. Diversity is a hedge against risk in a dynamic environment. Duke has both geographic and regulatory diversity. This diversity supports diversity of earnings. We also have a diversified generation portfolio. The pie chart shows the transformation of our regulated fleet from 2005 to 2015. This is a result of fleet modernizations and the retirements of older, less efficient coal and oil units. As Keith Trent 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 and more natural gas. Coal share declines from about 55% in 2005 to 38% in 2015. Gas share grows from 5% in 2005 to 24% 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 joint dispatch of our plants in the Carolinas. Also, we have fuel mix diversity. We have strategic flexibility with our commercial business, which Mark will discuss. Today, our regulated utilities represent about 90% of our total business. This segment significantly contributes to our low-risk profile. This low risk helps sustain growth in the dividend payment, that dividend is at the heart of our investor proposition. I'm proud of what our employees achieved in 2012, despite a year of unparalleled turmoil and uncertainty. I talked about this on our current earnings call. Slide eight highlights a few accomplishments, starting with completing the merger after 18 months and three tries with the FERC and obtaining approval of the cost recovery settlement at the Edwardsport IGCC plant. 2012 was a strong year operationally, as y'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 nuclear team achieved a fleet capacity factor, excluding Crystal River, of over 90% for the 14th consecutive year. We completed three 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. We pride ourselves on doing what we say we will do. The next slide provides a four-year look at our financial track record, 2009 through 2012. Some of y'all remember, we came to you in early 2010 with three financial objectives. Grow our long-term adjusted EPS at a compound annual rate of 4%-6%. Second, grow our dividend at a pace that allows us to have a ratio with earnings of between 65% and 70% as our targeted payout ratio. Thirdly, to maintain the strength of our balance sheet. Slide shows we achieved each of these commitments. 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, the key investor metric. See in the right side of the slide, from 2009 to 2012, Duke beat the Philadelphia Utility Index and the S&P 500. Our total shareholder return of 76.5% 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 rating. I share this not to brag about the last three years, because y'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 ones shown on slide 10. Let me tick 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've gone to work on these. We have resolved three of these big issues within the last three months. The North Carolina investigations, the Crystal River retire decision, and the Edwardsport settlement approval. We're systematically reducing uncertainty and risk. This morning, you'll hear further updates on our remaining 2013 priorities, getting 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. 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 two ways. First, 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. Duke 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 Seiya 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 unique set of strengths. We have resilient people, we have a resilient platform. Together, they position us well for the ever-evolving energy future. Most importantly, differentiates us from other utilities. Scale efficiencies, diversity of generation and earnings, which mitigates risks. 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 will hear more about this from Marc Manly. Our winning formula combines these strengths with a continuing focus on the fundamentals. My main point is this. Duke Energy is well-positioned 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. You will 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&A at the end. Now let me introduce Keith, who will talk about our regulated fossil generation, T&D, and customer 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 Regulated Utilities. Keith, come on up. Thank you, Jim. Good morning, everyone. As Jim mentioned, I'm going to update you on our regulated fossil generation fleet and also on our T&D system. Let me start with three points. First, our fleet modernization program, which began back in 2006, has positioned us very well for coming environmental regulations. Our early start in that program puts us ahead of others in the industry, in our opinion. Second, we're on track to deliver operations-related merger savings. This includes fuel and joint dispatch savings that go directly to our customers. It also includes merger savings that we're harvesting today. 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, 7.2 million 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 2012. One way we measure ourselves there is looking at commercial availability, and I can tell you that in 2012, 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 base load units, especially in the Carolinas. You can see from the chart on the bottom right of the slide that the capacity factor for our coal plants dipped below 50% last year. Today, as a result of low natural gas prices, our natural gas plants are operating as base load with capacity factors in the 70%-80% range. 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 coal plants. I can tell you we're very focused on that. Those efficiencies would 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's gonna make us more efficient, and it's also gonna 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. 2006, 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 two pie charts on the right side of this slide that combined Duke Energy and Progress generation mix in 2005 was mostly coal and nuclear. 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's gonna go to 96% by 2015. Two new plants are gonna come online this year. Edwardsport, our 618 MW IGCC plant in Indiana, has completed construction and is now in the final phase of required testing. We've successfully produced syngas from both gasifiers. That was a big milestone for us. We've produced electricity from both of our turbines using syngas, natural gas, and a blend of both. Last week, combustion turbine number one, 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 MW of power on syngas, and the steam turbine has been producing about 90 MW of generation. We're confident with this technology. We're confident that this plant's going to operate as designed, we're still looking at an in-service date in the mid part of this year. Second plant we're completing this year is the 625 MW Sutton combined cycle plant. It's currently under construction. This plant will be our fifth natural gas plant since 2011. The target date for that plant is the 4th quarter of this year. We're also focused on managing costs. We're particularly focused on delivering $687 million in fuel and joint dispatch savings to our customers in the Carolinas over the next five years. We're estimating that about half of these savings are going to come from jointly dispatching the Progress 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, 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 territories. In December, as gas prices started to rise, Duke's more heavy coal fleet began dispatching into the Progress territory. The key here is under both of those price regimes, we were delivering savings and harvesting savings for our customers. The joint dispatch system is working, 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, that came through renegotiated coal contracts and also through fuel transportation savings. We're also ahead of our plan in terms of our coal blending program. Let me give you one example. At our 2,200 MW Belews Creek plant, we set a 2012 target to burn 20% mix of non-traditional high sulfur coal. That was our target. We exceeded that target. In fact, we're burning a 35% mix, the plant personnel are currently conducting tests to see if we can take that percentage even higher. During the first six months after the merger closed, we produced $52 million 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. We're focused on cost, but not at the expense of our operational excellence. On the power delivery front, we measure reliability success using two measures, SAIFI and SAIDI. SAIFI captures the number of times the average customer experiences a sustained outage each year. SAIDI measures the average duration of annual outages in minutes. The chart on the left shows that SAIFI for the combined company has dropped from 1.3 in 2006 to 1.2 outages per customer in 2012. That's an 8% improvement. On the SAIDI front, it's improved over this same time period. For 2012, the Duke annual SAIDI was just over two hours per customer, which represents a 22% improvement from 2006 levels. Both of these trends demonstrate our improving system. We're never going to reach zero here, but I can tell you that our 7,000 T&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 in customer restoration in the wake of Superstorm Sandy. That was the largest deployment in our company's history. 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. You 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. 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 billion on air emission controls to reduce SO2 and NOx. With these investments, we've already reduced SO2 emissions by 86% and NOx emissions by 64% through 2012 off of a 2005 base. By 2015, those percentages are going to improve to 92% and 79% respectively. As we look to the future, we're anticipating new air, water, and waste rules. We estimate that an additional $5 billion-$6 billion 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 billion-$7 billion. Improvement in the final MACT rules enabled us to eliminate some of the anticipated baghouse additions, which in turn has reduced the anticipated spend there. The pie graphs on 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 billion-$6 billion 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. Let me leave you with these thoughts. First, our fleet modernization program puts us in a strong position in terms of diversity, fuel diversity, and environmental regulation. Second, we're taking full advantage of our unique scale and diversity. We're driving out cost without sacrificing operational excellence. That's good for our customers and it's good for our investors. 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. I'll take questions. Question on gas cost and fuel mix interests me. Could you talk a little bit about how you buy gas, where does it come from, and how variable are the costs over a period of time? What have you done? 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. 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 second-largest buyer of natural gas among utilities. It's obviously an important thing for us. 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 program we have with respect to hedging, there'll be full transparency and agreement with the regulators. From a hedging standpoint, it's good for us to do that, and we do do that, but we've got to balance the risk associated with the hedging and the benefits to customers. 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 savings. Pretty big numbers when you look out over a decade regarding regulations that don't exist. Have been drafted by the EPA, that have not been put out by the EPA. I'm not a lawyer. You are. They will probably get litigated for multiple years whenever they come out. I'm thinking 316, I'm thinking COLA. 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 multiyear time horizon, and then, C, the timeline for implementation? Those are great questions. Let me break it down in pieces a little bit. First of all, from an air standpoint, that's where I think we have the most clarity. The MATS rule. The rules are final. I realize that there's litigation going on to challenge the rules, but we are assuming that those MATS rules will go in place, and that we'll need to comply by 2015. In some instances, we can get a one-year extension. We're using that as an assumption. Air is where we have the most certainty. The rule changes that I mentioned have given us an ability to eliminate baghouses. On the air side, what we look at most is the addition of some SCRs, and addition of sorbent injection. 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 three-year time horizon that we've given to you, which is the $1.4 billion. Quite frankly, the reason that we're not giving you specific times and dates, and really not giving you specific information much beyond the three years, is because it is hard to know exactly what timing is going to happen outside of this three-year window. Air we feel pretty good about. That's where a lot of the spend's going to be happening in the next three years. 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's going to be in the future. We were successful in reaching agreement with the Indiana Office of Utility Consumer Counselor recently on the environmental compliance plan regarding the spend that we're going to be making there. 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. We have a 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. Certainly, we have some base set of assumptions, and I won't go into all of the base set of assumptions. We feel good about the assumptions we have. 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. Put it into more sort of numerical detail. You said that you've got about $650 million of CapEx related to MATS in the back of your appendix. The total spend for environmental is $1,375 million. 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 in 2015? Again, the air is the bigger component of it. I would say the air of this 1.4 is in the $600 million range. Again, I think we have better certainty there. The remainder is water and waste, $800 million 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. On the water side, water treatment systems work. We have things that are specifically identified where we don't have just sort of throwing in this big bucket of contingency or guess. Having said that, especially on the waste and water side, you could see some sliding or changing there. We feel reasonably good about the estimates for this three-year period. Take one more question here, and then we'll move to Lloyd. Following up on those environmental expenses, Keith. 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 your money. To what degree have you talked to regulators about this plan over the immediate and longer range, and what kind of reaction do they have? Are they looking for filings, some filings in advance, or they just say, "Do it, we'll judge you after you do it," or what? Different in different places, and Lloyd can probably go deeper on this than I can on the regulatory side. What I would say to you is, in Indiana, as I mentioned, we filed a compliance plan. 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 seeking 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 staff very informed of what we're doing. We live by a no surprises kind of rule, and we will continue to do that. That gives 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 Dhiaa 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 three 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. Second, I'll share with you today our plans to continue to make targeted investment to achieve operational excellence and efficiencies across the fleet. 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 six 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 3 in Florida. From the map that you see on the screen, you notice that all 11 units are in the Carolinas 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 emergent 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 the set of seven 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 first quartile, dash green is second quartile, yellow is third, and red is fourth quartile. We chose those seven indicators because frankly, they represent what is 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 forced loss rate. There is an independent view of an info index, and cost efficiency is represented in terms of total operating cost. As you look across the chart, which represents several years of performance, you will notice lots of green and dash green historically with the fleet, which represents solid performance for the fleet 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. We are 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, we will achieve top quartile. I am confident we are on the way to achieving that. We have established high-quality organization and detailed plans to with targeted investment that will lead to step change of performance. As we make these investments, we will continue to emphasize cost control as we leverage the scale of our fleet. The merger gives us 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 what appears to be a busy slide. The two 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 operations for the fleet. Oversight is represented by a strategic mix of internal and external oversight. I describe it as intrusive oversight. Now, my colleagues get nervous when I talk about the word intrusive. I realize, the word intrusive is not always a pleasant word, that you hear it when you are talking about government action or maybe it reminds you of some unpleasant medical procedure. I assure you, in nuclear, it is a beautiful word. 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 is the 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 targeted investment we are making to increase overall fleet performance and to meet the NRC's Fukushima-related requirements. Over the next three years, we anticipate investing an additional $175 million in capital, and $15 million in O&M to improve fleet performance. Human resources is one area of targeted investment. For example, at 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 effect. We will also put special teams in place at Robinson and Brunswick to accelerate improvement. We have deployed supervisory mentors or coaches from across the fleet to further accelerate the improvement. Moving to Fukushima. Over the next three years, we anticipate investing about $500 million in capital and about $100 million in O&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 BWR units, instrumentation to more accurately measure spent fuel pool level, water level, and opportunities to augment emergency response. Of course, dollars to meet 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 improvements. We move to Crystal River. As we move to the next slide, I will update you on the plans to retire and decommission the Crystal River nuclear site in Florida. We have selected, as you know, the SAFSTOR method for decommissioning. We will place the unit 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 million. 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. We are 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 specifications 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 the site until decommissioning is complete. That organization is expected to be significantly smaller in size than the current organization. With this next slide, I will 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. New nuclear is a key component for our long-term resource strategy because it helps with fuel diversity and represents carbon-free baseload capacity. The NRC is reviewing our applications for combined construction and operating license for six new nuclear units. Two Levy units in Levy County, Florida, two Lee units in Cherokee County, South Carolina, two 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 will 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 40 years, safely, reliably, and cost effectively. Nuclear's remain an important option for future generation 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 in your analysis of the legacy Progress fleet? Was it that their performance had flatlined for years while the industry improved, or did their fleet performance deteriorate? I can speak with confidence about the current state. I can also tell you that I assure you that the whole industry, I think your point on that is, did we not keep up with the industry performance improvements? Probably more than the case. Anytime there's a disparity in performance, the whole industry moves up in performance at a rapid pace. Competitive industry. Today, we operate 11 plants. Eight of them operate at the excellent level. They are the envy of the industry, and we will maintain them at that level. Three, 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. You also mentioned there are some uncertainties as to the exact requirements and the spending. The total amount struck me as fairly robust relative to some of the varying measures. As you talk 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? Where would you put yourself in the spectrum of how conservative you've gone in the cost estimates here? 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. 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. Even with that, there's some variation, and the design requirements are different. I have only 2 BWRs. Other fleets have 12 BWRs. Certain modifications may be more expensive than others. It will play into their strategy differently. 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. Those numbers reflect that bias. While others maybe have more confidence in their ability to their analysis to show a different result. Our bias, I would tell you, I am confident is heavy on the conservative side for modifications. Okay, we'll have two more questions here, then we'll go on to Lloyd. 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. Was the issue of overstaffing, was it a question of changes in management, in processes, headcount reduction? Give us some sense of where you see the change and how easily you've been able to blend the two fleets. Yeah. I would tell you that blending the two nuclear fleet into one has been a bright spot for us. I'm really very pleased of how well we have come together as one team. Jim showed the first layer of management. If I fold my layer, you would find a very equal balance between legacy Progress and legacy Duke fleet. Processes that we're aiming 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, what is it that you're finding? We have expertise on both sides, 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. If you asked me what is the single thing that will make a difference in performance, it would be that. The corporate infrastructure that we have in place, which is supplemented by legacy Progress folks, it will do exactly that. Quick question on the BWRs that you mentioned. Costs are going to be higher. Can you give us an idea of the cost that you outlined? How much are for the BWRs and how much is for the rest of the fleet or any type of %? You're talking about Fukushima? Fukushima. Yes. The only difference between the rest of the fleet and the 2 BWR units are the hardened vents. There is a question about whether the hardened vents, which approach would you take? There's the filtered, the hardened vents, versus a method of confinement that the industry and the NRC are still negotiating or developing a strategy for. That is the only unique aspect of the difference between BWRs. If we go the extreme, and that is a 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. Let's assume we go to the extreme. The modification, no one has done a detailed analysis on that. Conceptually, it could add a $50 million per unit in the modification space. All right. Well, folks, thank you very much. At this point, Lloyd will discuss the regulatory business. Good morning, everyone. I'll focus on the regulated utilities, specifically the rate cases we filed and the one we're preparing to file. Like my colleagues, I have three facts about our regulated utility strategy. First, we must begin recovering the cost of fleet modernization programs discussed by Keith and Dhiaa. Poised to do so in our near-term rate cases, this will drive earnings growth. Second, we operate in constructive regulatory jurisdictions with competitive rates. Third, 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 two rate cases in North Carolina, two in Ohio. We anticipate filing two cases in South Carolina, starting with the Duke Energy Carolinas case next month. Altogether, six rate cases will total more than a billion dollars of revenue requests. In addition, this summer, we expect the Ohio's commission decision on our capacity case. Every one 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 next slide. In the PEC cases, we'll seek to recover costs associated with three combined cycle natural gas turbines, totaling almost 2,200 megawatts of capacity. Two of the plants are complete and already providing fuel savings, and the third 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 on budget. This new capacity is of course the retirement of 1,500 megawatts of older coal-fired generation. Those retirements have already started taking place. Last October, Progress Energy Carolinas filed its first rate case in North Carolina in 25 years. Request is for an increase of about $359 million 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 investments. 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 million in revenue increase in the first year, then another $31 million in the second year. That's a 5.7% increase in rates to our customers in the second year. A 10.2% return on equity and a 53% equity component of our capital structure. Hearings begin on March 18th, and we expect a decision in time for rates to go into effect in June. We're pleased to have a settlement, but several regulatory decisions are outstanding, such as cost allocation and rate design, and not all interveners have signed on to the agreement. South Carolina. Progress Energy is evaluating filing a rate case later this year. Let's turn to the rate cases for Duke Energy Carolinas, starting with the one filed several weeks ago, as 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 McGuire nuclear stations. Request is for an increase of $446 million in annual revenue or a 9.7% rate increase to our customers. Hearings begin on July 8th, with rates effective September. As you can see on this pie chart, more than 90% of this increase is associated with new capital investment. This rate case is the last of three Duke Energy Carolinas cases in North Carolina to recover investments in new generation and to upgrade existing plants. In addition, Duke Energy Carolinas has provided the required 30-day notice for South Carolina rate case filing in March. We expect these revised rates to be effective in the fourth quarter of 2013. Let's take a brief look at the electric and gas distribution cases in Ohio. Combined, they represent a requested annual revenue increase of $132 million. Hearings get underway this spring. We expect these two cases to be resolved by the summer. On the next slide is an update on our $728 million capacity filing in Ohio. Hearings begin this spring, and there are a few points I want you to keep in mind. First, our filing is consistent with the new cost-based compensation mechanism for fixed resource requirement utilities, which includes Duke Energy Ohio. Second, we're not seeking to change the electric security plan under which Duke Ohio operates. Capacity is a non-competitive service outside the provisions of an ESP. Third, 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 19th. Technical hearings begin on April 2nd. We're hopeful for a decision by the middle of this year. That's our calendar of rate cases, important proceedings on multiple fronts. Successful outcomes will support our financial strength and provide earnings growth. With the next 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 18th, followed by the commission staff and intervener filings in mid-May. Following an informal conference this Tuesday, the Florida Commission staff asked that the company file a motion to lift the March 18th filing requirement until a new date can be set after a March 12th issues conference. Currently, the expectation is that the commission's focus will be in three areas. First, the company's decision regarding retire versus repair the unit. Second, determine the prudence of our acceptance of the third-party mediator's proposal of the insurance settlement with NEI. Third, determine the scope of the regulatory assets that will be included in rates beginning in 2017, per the 2012 settlement. We expect the commission to issue a revised procedural schedule later in March. With all of this activity in our jurisdiction, let me focus a moment on our regulatory environment, because I think that's obviously important for our investors. Next slide summarizes an independent ranking of the regulatory climates in our retail states. Many of you are familiar with Regulatory Research Associates. The firm closely follows the actions of the utility commissions throughout the country, evaluates them from an investor perspective: above average, and below average. As you can see on this slide, 80% of the retail rate base in our six jurisdictions exist in above average, are rated above average. 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 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 sales. As the economy and housing market improve, more retirees 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. On the next slide, our customers expect reliable service and reasonable rates. 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 million in savings over the next five 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, as you can see, Duke Energy is committed to economic development. We work 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 and Progress helped to attract more than $3.5 billion in investment 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 six of our retail states in the top 12 in the nation for business climate. North Carolina was ranked number one. Ohio ranked number two. We're also a partner in a current initiative to expand the success of the 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. 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 examples. Michelin Tire, which is South Carolina's largest manufacturing employer, has announced over $1 billion in expansion in the last two years. Continental Tire is nearing completion of a $500 million tire manufacturing plant, which will provide over 1,600 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. In most cases, we're 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. Potential solutions include forecasted test years, greater use of trackers, faster, more predictable review times for our rate cases. 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 a constructive regulatory environment, and we're well-positioned to continue attracting new business in our service areas. We're exploring new ways to reduce regulatory lag and adapt the rate-making process to the new energy landscape. I'll be happy to take any questions. What is the path that you see 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? Lloyd, bring the microphone up so you can get a little louder. 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 state-by-state strategy of how you guys look to address that, and then how much of that is going to be commission-related versus legislative in trying to get to those solutions? 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. This bill is in process but has a tracker for transmission distribution investment, has defined approval time frames for rate cases, 300 days or a 60-day extension. Things like that. We'll look at something in the Carolinas. Again, that'll be more legislative. In Florida, we have a fair number of trackers, but there's some opportunities there. I think those are a couple of examples. I think the focus will be on trackers, maybe a migration to formula-based rates in some areas where it makes sense. I think we do need, as Jim mentioned earlier, we need to work hard to start changing these regulatory models because of this low load growth. Lloyd, can you talk about the economic development slide, and will that help lead into anything other than 50 basis points load growth? I don't know how many basis points load growth it'll lead to. I know that we work hard on it every day, that we have several opportunities. If you start to think about the Carolinas, as I mentioned earlier, excellent places to do business. When we see an opportunity, we'll travel out with some of the commerce teams in the state, and we'll work really hard to bring those in. Data centers are good opportunities for us, manufacturing facilities, some service industries have been very successful. Our industrial rates are relatively low, our customer satisfaction is high, and as a result of that, we've been able to attract manufacturing and other facilities to our service areas. Yeah. Lloyd, Crystal River 3. Could you talk a little bit about how the $600 million of nuclear decommissioning funds are presently invested and whether you have any plans to change that? I know you could have a mix of debt and equity and the like. 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? The first question in terms of how the $600 million is invested, I'm going to punt that to Lynn Good for later. All right? How about saving that question? Now give me the second question again. Getting to sound like Jim Rogers. How do you all assign costs related to Crystal River 3 now, will those be charged against operating earnings or are they charged against the decommissioning fund? Today, correct me if I'm wrong here, Lynn, today they're charged against operating earnings. The plant came out at a rate base January of 2013, right? I think that would be a better question for Lynn to answer also. Why don't you give Lynn a microphone? Can you hear me? All right. I know you can't hear me. We can hear you. The decommissioning fund, there are rules on how often and how soon you can tap into it. Currently, to plan for the SAFSTOR, we have access to 3%. Once we file and there's some regulatory review of the post-shutdown decommissioning activity report, we'll have access to a greater amount of the decommissioning. Carl, I think under the SAFSTOR provisions, we're talking about decommissioning 40-60 years from now. 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. Yeah. You should think about it almost like pension funds. You'd have a debt and equity mix. You also run a variety of Monte Carlo simulations on investment performance and cost structure to decommission. You have a probability of full funding, and we monitor it just as we do pension funds. Bob. Lloyd, how are you thinking? This is a very important year from a regulatory perspective. Lots going on in the Carolinas and in Ohio. How are you thinking longer term, meaning 2014 and beyond, what the rate case cycle across the broader system looks like, whether you're 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 slow down that process over a multi-year cycle? The way I would answer that question is I think that depends on the capital investments we make over the next few years. Keith talked earlier about some of the environmental investments. If you look longer term at our integrated resource plan, you see some investments in the Carolinas. Some combined cycle gas turbines in the 2016 and 2017 timetable. There's some investments that need to occur in Florida, and depending on earnings, they may drive rate cases. Right now, there's nothing definitive after we execute the Progress Energy South Carolina rate case. There's a gap there. CapEx forecast for the next few years, as well as that 4%-6% earnings growth rate that Jim laid out at the beginning of this. There's no follow-on rate cases in that cycle for the next two to three years after the current ones wind down? Not right now. Ken. I wanted to ask you, just to sort of clarify this, when you mention these new regulatory initiatives, I heard trackers and forecasts here, but things like Save-a-Watt and even decoupling. Those sort of things it seems like you guys 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 understand whether or not those sort of things were at all on the table or if you were exploring them. That's number one. Go ahead. Number 2, Florida, there's an effort that seems to be gathering some steam. 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. 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 on 560 as well. If you could just give a little bit more color with respect to that. Sure. I would say that everything's on the table. I just didn't mention all those, Save-a-Watt, energy efficiency programs and those things. 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 four or five 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 four senators introduced a change to this nuclear legislation bill that occurred back in 2005, the bill was signed. We still believe that that makes sense. Construction work in progress for new nuclear makes sense to build new nuclear. I realize there's some concerns in Florida associated with that. If you look at the vintage of nuclear plants we have in this country right now, some of those plants will start to retire in 2030, 2040, and provisions like this 2005 legislation make very good sense for companies to build new nuclear. I think as time goes on in the legislation down there, I think we'll work with them, then I 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. Yeah. I guess I'm sort of wondering is, how much, I guess, a 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 can't speculate on- Sure how the bill's going to change. Yeah, sure. Just in terms of the quantification, in terms of how much is at stake with respect to that. In dollars? Yeah, in money. I don't know, a way to think about this, we've collected $676 million from our nuclear cost recovery, and we've spent about $1 billion. This is for the Lee plants, I think. Is that the number? Is that the question you're asking? Okay. 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? How should we look at the level of rate base growth over the second half of the decade? I'll start with this. You saw some, Keith mentioned some of the environmental spend, and we are. I think there's always opportunities to spend capital. If you look at our company, we never seem to run out of opportunity to invest capital. I think that there are opportunities on the transmission distribution grid for grid modernization that haven't shown up yet. We have lots and lots of projects where it makes sense to invest capital into the system. I think everyone's question is 4%-6% 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 capital, whether it's in environmental, whether it's on the T&D system, or whether to continue to modernize the fleet for cleaner, more efficient energy. I think there's plenty of investment opportunity there. Thank you. Part of the session this morning will resume to 10:30 A.M. promptly. Yeah. I'll be down there. You'll Okay. If you could take your seats, please, we'll get started here in a moment. Welcome back to the 2013 Duke Energy Corporation Analyst Meeting. Our next speaker today is Marc Manly. Marc is going to talk about the Commercial Businesses, provide an overview of that area. Marc is Executive Vice President and President of our Commercial Businesses. Mark? Thank you, Bob. Good morning, all. I took over this business function two months ago after serving as General Counsel for 10 years. I'm delighted to lead the business and to talk about it with you today. As you know, the commercial business is comprised of two reporting segments. One is Duke Energy International, and the other is our domestic commercial power. 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 threes. 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. This diversity provides stability and growth of earnings as our track record has demonstrated, which I'll get to. Second, the diversity helps support Duke's financial objectives. We participate in growth markets in international and in renewables. With our Midwest commercial generation, we have strategic flexibility. Third, 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 hydro, gas, liquid fuels, and coal in Latin America. Overall, the capacity is 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 Company 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%-30% of DEI's adjusted net income. We've extended the arrangement through 2032. Second 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. Chile. As you know, we've invested in Chile last year. It's long been a target market for DEI. In July, we purchased a 240-megawatt capacity play called the Yungay plant. In December, we closed on two hydro projects that are completed, $415 million. We'll complete project financing for more than half of that shortly. The third point is DEI is positioned to self-fund this growth and its growth, again, consistent with our return and risk objectives. As of the end of the year, we had a balance of $1.1 billion in offshore cash. We continue to look for a tax-efficient way 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 DEI. 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. 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. That leads as you go over to the upper right-hand chart. We've talked about anemic growth in demand in the U.S. From data we have, which is not weather adjusted, demand growth in the U.S. has even trended nationally below zero. Look at the demand growth in Chile and Brazil and Peru and other Latin American countries, greater than 4%. 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. Finally, if you go over to the lower left, this chart represents what the net income of 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 reservoirs. Very critical southeast region of Brazil. The very bottom line is the, I think it's red, is the 2001 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 with 2001. Let me just remind you, the rainy season in 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 2001 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%. That's the status on the reservoir levels. We're watching it carefully. Lynn will discuss that because of the reservoir levels for our 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 raining. Turn to slide 50, an overview of our domestic commercial power segment. It's comprised of four separate businesses, Midwest Generation, Duke Energy Retail, Duke Energy Renewables, and Commercial Transmission. A couple 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 2009 to acquire retail customers in Ohio on a defensive basis and defend margin deterioration as a result of lower market prices. Currently, DER serves annual load of approximately 8 million megawatt hours. Duke Energy Renewables, started that business in 2007, and we've grown it to 1,700 megawatts, 1,600 megawatts of wind, and 100 megawatts of solar. Most importantly in this business, we've consistently delivered what we said we would through long-term, up to 15 years, contracted projects with attractive risk-adjusted features. 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 AEP in the Pioneer Line in the Midwest, and we have a broader joint venture with the American Transmission Co. to pursue projects. Let me turn to Midwest commercial generation. Make no mistake, we're not satisfied with the financial performance of these assets. The good news is it is a good set of assets and it's well-positioned the business to adopt to market changes and pending environmental regulations. All of our coal units, with the exception of Beckjord, and that's displayed in the pie chart with all the colors, are equipped with scrubbers and SCRs. We don't expect them to become economic with the pending environmental regulations. 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 Lloyd indicated with respect to our cost-based 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 to inform us on our long-term strategic decision about those assets. This slide indicates the two approaches we're taking with respect to 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&M expenses. We focused in three ways. One, we managed this fleet of combined coal and gas as a single fleet to exploit scale synergies. Two, we've been hedging our margins with matching financial trades of power and the commodities to reduce volatility and to book economic margins. 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. What has our team done in these areas? Let me give you some details. Their focus on optimization of capital and operation has given us great results. We've reduced headcount of contractors at the fleet by more than 50%. We've reduced Duke headcount by more than 20% since 2010. As a result, we've reduced our fleet O&M on a per megawatt hour basis by over 25% from 2009 to 2012. These are a good set of assets. We think they're very cost-effective. On our hedging strategy, this year we've hedged and locked in margin with respect to more than 80% of our expected economic coal burn and over 50% of our gas fleet. Turn to Duke Energy Renewables. As I indicated, since our entry in 2007, we have brought this business to scale. We were very busy in 2012. We added 650 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. Today, we operate 1,700 megawatts in 11 states, and we're now the fifth 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 creditworthy counterparties. Each of our developments, we work the documents, are project financeable. With respect to this growth, we have project financed over $1.4 billion of our growth. Likewise, we look for good joint venture partners to limit our CapEx obligations. Our first venture was with Sumitomo Corporation in 2012, and that involved two Kansas wind projects with a total capacity of 300 MW. As to renewables, we will continue to pursue further growth opportunities, particularly in solar. We will use the same approach. We will not do the project unless we have a long-term PPA that on the basis of risk and returns, meets our objectives. 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 continue to provide good earnings, cash flows, and earnings diversity for the company. Finally, we are keenly focused on Midwest Generation of generating good returns for that great set of assets. With that, I will welcome your questions. Paul, I want to start with you then. I have got two questions. First on Brazil. There is obviously there has 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 to that as your hedges roll off in 2015, 2016, and beyond. Yep. Can you explain what is happening to the directly exposed companies and how you might be indirectly exposed? Yep. As you can imagine, we've heard a number of questions about that. Here's our analysis and why we're not overly concerned. One, we look at this and say, first of all, Brazil is proceeding within the rule of law. These concessions are coming up. The Provisional Measure 579 is within the rule of law. Brazil has to deal with these concessions that are coming up. Second, we need to recognize some of the statements about the expected reduction in pricing, which could have indirect effects on us, are set in a political context. An election's coming up in 2014. I think they need to be understood in that context. Now to get to us, as you mentioned, we're not directly impacted. The law applies to concessions that were granted before 1995 and are due to expire the next couple of years. All of our concessions were granted after that point. 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. I included this data, I think on page three of the appendix. One, we're very highly contracted. For this year, those assets are 97% contracted. By 2015, they're still almost 80% contracted. By 2017, they're still over 50% contracted. 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 2012 to 2015. We think we're fairly well protected. That being said, we're watching it carefully. Great. My second question was on assets in the Midwest. For the same time frame, it looks like, just based on what you're showing in the appendix, that we should count on a fairly substantial improvement in capacity revenue? That's our hope. I think we've included what the auction prices have cleared, 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 two years. Still not where they need to be. Again, we're counting substantially on getting fair treatment with our capacity filing and getting a cost-based revenue to the extent the PJM capacity payments don't cover our cost. Give you the opportunity to get the easy question, but I wasn't selected for the first one. You'll probably hand this off to Lynn, you talk a number of- 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. I'd like to know more about what your objectives are that you're striving to meet. Well, let me give you my perspective and my wet blanket at the first table will describe her objectives. 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. That's what I mean by risk-adjusted and those hurdle rates. It varies by country. It varies by project we're doing. I'll say a word about 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. Lynn doesn't let us get deal fever and bid more than the risk-adjusted return would permit. She's either bemused or mad at me. Anything else? 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. Would love to tell you more. Thank you so much for being here. 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. What I'd like to do is cover, of course, our 2013 earnings guidance, CapEx and financing plans, our long-term growth expectations, and then finally, our dividend policy. 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. Second, 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. Finally, our scale, diversity, and strategic flexibility give us unique strengths 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-$4.45 per share with a midpoint that's reasonably consistent with our 2012 actual results. As 2013 represents the first full year for the combined company, it's an appropriate foundation for future growth. Therefore, it is the base year for our long-term adjusted earnings per share growth range of 4%-6% through 2015. 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 65% and 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 FE&G, our largest business segment, which will contribute 90% of our consolidated adjusted earnings in 2013. 2013 will include a full year of earnings from the Progress utilities in the Carolinas and Florida. 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. 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, 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 additional customer load since 2012 weather was below normal. We are planning lower O&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 the 1,100 employees who accepted the voluntary separation plan have left the company. These important merger initiatives are allowing us to offset the impact of inflation, higher pension costs due to low discount rates, as well as emerging costs to support our nuclear fleet. I want to highlight two drivers in our Florida jurisdiction. As a result of our recent decision to retire Crystal River 3, 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 million remaining, which represents $10 million less than what we amortized in the last six months of 2012. Let me move to International, which is expected to generate approximately 13% of our consolidated earnings for 2013. The lower earnings in 2013 will be driven by three items. The effect of unfavorable foreign currency exchange rates in Brazil. For 2013, 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 in a $0.03 EPS impact. 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. Of course, we'll continue to update you on those developments as the year progresses. Finally, lower results at 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 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. Also, additional dilution will result from the full-year impact of incremental shares issued in connection with the Progress merger. Finally, we expect an increase in our adjusted effective tax rate from 31% in 2012 to between 34% and 35% in 2013. This increase is principally due to lower allowance for funds used during construction equity earnings and a full year of earnings from Progress, which has a higher effective tax rate. Turning now to slide 59, I want to discuss our capital expenditures for the three-year period from 2013 to 2015. From a historical perspective, in 2012, we spent approximately $6 billion of capital. However, this amount excluded the first half impact from Progress. If this Progress spending had been included, 2012 CapEx would've been closer to $7 billion. Compared to this pro forma amount of $7 billion, CapEx will trend down modestly in 2013 as we complete several major construction projects at FE&G and in our renewables business. Over the three-year period from 2013 to 2015, about 85% and 90% of our forecasted CapEx is expected to be deployed in our regulated utilities. As our major construction projects are completed at FE&G, our environmental compliance spending will begin to increase. Of the $5 billion-$6 billion in environmental capital that Keith discussed earlier, we estimate approximately $1.4 billion will be spent in the 2013 to 2015 timeframe. In addition, we expect to deploy approximately $400 million 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 to translate into earnings growth potential. As discussed earlier, we expect to invest about $16 billion in our regulated business over the three-year period from 2013 to 2015. Of this amount, around $8 billion is maintenance capital, which will substantially offset our depreciation expense. The remaining capital is expected to contribute to earnings-based growth. As a result, we expect that our earnings base could expand from about $45 billion at the end of 2012 to about $50 billion 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 credit metrics continue to position the company well within our ratings categories. As a result, our plans do not require 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 $5.6 billion 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 million during 2013. Our pension plans remain fully funded under the Pension Protection Act guidelines. In order to fund our debt maturities of $2.7 billion as well as our cash flow needs during the year, we expect to issue around $4.3 billion of financing during 2013. As outlined on these slides, these issuances are expected to include around $2.1 billion of first mortgage bonds at the various utilities. Additionally, we expect to issue approximately $1.4 billion of holding company debt during the year, consisting of a mixture of unsecured and retail instruments, as well as the $500 million 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%-6% off our previous base year of 2009. 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%-6% earnings growth rate include the following: average annual regulated rate base growth of 4%. A full year of earnings impact from our pending rate cases beginning in 2014. Long-term load growth of approximately 1%. Continued growth in our wholesale business, adding between $0.07 and $0.08 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&M growth in the range of 1%-2%. Disciplined growth in our international business with effective cost control and operational efficiency. Finally, benefiting from the recovery in PJM capacity prices at commercial power. As you know, by calendar year 2015, PJM capacity prices will be $132 per megawatt day, more than five 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. We recognize the dividend is very important and an important part of our value proposition for investors. Our dividend is supported by stable and predictable cash flows from our regulated businesses. We have a long history of dividend payments, as 2013 is the 87th consecutive year Duke Energy has paid a dividend on its common stock. Since 2009, we've grown our dividend by about 2% annually. We expect to continue increasing the dividend annually, targeting a long-term payout ratio of 65%-70% of adjusted diluted earnings per share. In summary, we are well-positioned to achieve each of our objectives. We expect to achieve a 2013 adjusted earnings per share of between $4.20 and $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 me 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 must do well. We believe Duke has unique strengths, such as our size and scale, our diversity in 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. 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. That work? Okay. We're in the home stretch, guys. We're going to have a brief moderated panel with our senior management team. Before I introduce, we have a few new faces that you haven't already heard from earlier this morning. Before I do that, let me just introduce myself to those of you that do not know who I am, Bill Kearns, 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 will look for the easy questions first. Let me start it off with just a brief introduction of the three individuals, and I'll just ask them to briefly raise their hand. We've got Julie Janson, who is our General Counsel. Julie is also the former President of Duke Energy Ohio. 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've promised to you as well as to our regulators. We also have Jennifer Weber, who is our Chief Human Resources Officer. I'll probably be seeing her tomorrow as well. 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. It's remarkable. A 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've encountered, and what type of lessons learned could you give all of us? Not working. It's now working. How much of that did y'all hear? A little. Well, I've been delighted to be a CEO for 25 years, especially in this industry. The real lessons, to go straight to the lessons, are these. I saw a slide by Jeff Holdshue from Morgan Stanley not long ago that pointed out that when I joined the industry in 1988, there were over 100 utilities in the U.S., electric utilities. Today, there's about 50. I have been here during a period of great consolidation, and I've had the good fortune of working to do three consolidations, and they've each been challenging in their own special ways. Every one of them has created greater earnings growth as a consequence of coming together because our cost structures have been reduced. The combination itself produces savings, but it also provides a catalyst for even greater savings. That's where we sit today with the 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. This combination will help us achieve that objective. The other thing is, I clearly see the value in different regulatory regimes. 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 states have been very consistently constructive, but not always. 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. We're really working hard to have a no surprises type of relationship with the regulators. Through the period for the last 25 years, that's been one of my hallmarks. I 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. 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. I look back over the last three or four years, we beat consensus every quarter. We beat the annual consensus every year, and that quarter after quarter consistency pays off. That's what we will continue to do going forward. You've had a great opportunity to listen to some of our team today, and now you have an opportunity to listen to all of them. As I said at the very beginning, I have great confidence in this team. Given the challenges we went through last year, everybody really stepped up and delivered. We demonstrated perseverance, resilience, and at the end of the day, with everything that was going on, we still delivered. 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. If you keep that in mind, I think that's the way we'll be going forward. 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 track our achievements? Thank you, Bill. First, when it pertains to merger savings, the focus area on our fuel savings is paramount. Keith mentioned this morning, $687 million expected 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 million 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. If you move over to our non-fuel O&M savings, Lynn mentioned close to 700 initiatives. These are projects, large and small. Each one has been assigned to a specific owner. The panel. Unfortunately, except for Jim, your lavalier should work. 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, 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 two cultures brought together successfully? Okay. My lavalier 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 going through a merger of our size and scale. Our senior management team decided that we needed to place an emphasis and a focus on this body of work. 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. 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? 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. 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. I'll highlight some of those. One was a culture of high trust, and this is being viewed as very foundational to another attribute that was mentioned, and that's high accountability. Effective accountability across the company. Another attribute that was mentioned was innovation. 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. The other attribute that was mentioned is a culture, and this is very related to the definition of performance culture, of high accountability. High accountability for achieving superior business results, high accountability for operational excellence. Those were some of the 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. Described a great deal of CapEx and rate-based growth, I'm wondering what the rate impact to customers is and how you balance that Over the next three years, particularly if you're filing a bunch of rate cases now, but then not filing in 2014 and 2015. Lynn, you detailed growth in wholesale of $0.07-$0.08 a year, just wondered what that is. 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. We filed for roughly 10%. The settlement in the progress case is going to be 4.7% in year one, growing to a total of 5.7% at the end of year two. We're very conscious of maintaining those bill impact increases at a level that makes sense for our customers. 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. That's something that we're very focused on as we go forward. The wholesale contract Lloyd touched on briefly, there are two of them that we highlighted. One, an extension with NCEMC in the eastern part of the Carolinas, and one with the Northern Co-op in South Carolina. Lloyd, would you like to add to that in any way? Testing. That wasn't working. 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 EMC contract signed with Duke Energy Carolinas grows from 115 megawatts to 1,000 megawatts over an 18-year period. If you start to look at the opportunities for wholesale growth in earnings, that's what'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. Don't know if I need the mic or not. No. You're working. 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. What we heard from interveners primarily was that we've already received our compensation for capacity through our electric security plan, and that is simply not accurate because, and not to get too granular into Ohio law with you, but Ohio Revised Code Chapter 4928, which provides for the standard service offer framework within the state of Ohio, is one that provides for the provision of competitive retail electric service. It goes into depth about whether it's provided through an MRO or an ESP, 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 does not provide for the provision of capacity costs through the chapter. Quite frankly, it could not have been provided for through our ESP and was not. The other argument that interveners make that this has somehow already been settled and whether that's res judicata or collateral estoppel. That too, as you all know, our Electric Security Plan matter was not litigated, and it was a settlement. Quite frankly, AEP capacity case and their ESP case were very separate, as are ours in the system. We are cautiously optimistic about Ohio. At the end of the day, we don't get the results we want, we'll review our strategic options with respect to those assets. Next, let's go over to Bly. Hi. I think in the last few days we've had the board flesh out its ninth member. 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. What they're doing is going through a very thoughtful process to identify a successor to me. They started on this even before we added the last director. This process has been, as you know, the most important thing a board does is select a CEO. It's probably the thing that they are most careful about, and that's why this process is going to be very thoughtful. They'll take as much time as they need to do that. 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, given the challenges in the industry, given the challenges in front of this company going forward. Go to Jim next. Thanks, Bill. The question is a follow-up on all this new cost paradigm. Can you just help me frame how I should think about O&M at USFE&G in terms of how much of that O&M might be clause related? Percentage terms are fine. Clause related. Jim, I think we probably should get you some specifics on that. I think our clause-related recovery is in the range of $600 million-$700 million annually. 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. Fay, I want to follow up on your presentation. You highlighted a lot of capital and O&M requirements related to performance improvements and 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, they're not completely known, and they will be known in time. What I share with you is our best estimate based on what we know today. We anticipate over the next 3 years to spend approximately $500 million in capital and $100 million in O&M for the entire fleet. That is for 12 units, 11 operating and Crystal River, to cover things like the scoping requirements with natural phenomena. For the BWRs, which we have only two, that includes hardened vents but not the filtered hardened vents. It includes better instrumentation for spent fuel pool water level for the entire 12 units and better emergency response communication equipment for the entire fleet. It's really comprehensive for the whole fleet. Michael, next. About the landscape of utility mergers over the last 5 or 10 years, maybe even longer term than that, we've generally gotten actual reductions in non-fuel O&M. I look at the merger that happened in the upper New England area, talking about 3% actual reductions in non-fuel O&M. Different company, but if you look at the merchant merger between Exelon and Constellation, you actually got very sizable, meaningful reductions in non-fuel O&M. Just curious, outside of nuclear, what's putting upward pressure on non-fuel O&M to where we're talking about what the growth rate, kind of that 1% to 2% range, versus an actual decline rate? Michael, we are going to be negative O&M between 2012 and 2013. Lower O&M, you'll start to see our merger synergies kick in and impact. 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 new resources that are coming into play that need to be addressed. Of course, we have pension benefits that have continued to be an inflation driver for many companies, us included. I think there are a 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 load growth environment, we believe cost control is absolutely essential. 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. We'll continue to keep pressure on costs. I actually think in this environment, an aspiration of 1%-2%, harvesting the synergies and working hard to change the cost paradigm 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%-6% off 2013. Your earnings power of rate base plus equip, as you've articulated, here grows by 4% a year to $50 billion, plus or minus in 2015. What are the big drivers that could get you to 6%? 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 a base case of 4%? To the 6%. Greg, I think the drivers you talked about. Load growth, I think we have modest load growth expectations. That would be a 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. If we can do a bit better on O&M, challenging ourselves to trend it down even further than the 1%-2%, that represents growth. 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. In the context of that range, when I think about 4%-6% and obviously you're in many jurisdictions, the average expected earned ROE. What is- From 2013 to 2015, is there an assumption that the base case, is that a stable earned return, a growing earned return, declining earned return? I'm sorry, Greg, I had a hard time hearing. Sorry. 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 Carolinas as being kind of the 10% range, with cost control and rate cases driving us up and additional capital expenditures potentially driving us down. 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. The Carolinas is where I would focus, Greg, on the material driver. Okay, let's go to Dan next. Jim, I guess maybe two questions. One, Jim, can you talk a little bit about your views on carbon policy? It's gotten a lot of press and attention out of the administration and where you see that progressing and how it affects the long-term planning for Duke at this point. 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. 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 four-year battle with respect to their capabilities. I do think eventually there will be a price on carbon, and that's why we've taken the actions we've had. We've tried to be ahead of the curve with this $9 billion 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. We've reduced our exposure to increases as a consequence of the legislation or potential legislation with respect to it. From an EPA standpoint, it will be a long battle, a tough battle, long plays to try to impose a price on carbon. I guess maybe two capital allocation questions that didn't come up today. Number 1, your thoughts on the ability to repatriate cash from outside the U.S. into the U.S., are there any tax schemes that go along post the merge that would allow you to do that? Secondly, the potential investment in SCANA's nuclear plant, which got attention a while ago into why it's pivoted. Greg. Dan, sorry. We stay very engaged in the discussions of tax reform, and we're active in 2011 and 2012 around potential repatriation. We'll continue to be so as tax reform is 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. I think we always maintain the strategic flexibility of just flat out repatriating. That becomes an option that we could evaluate in the context of additional growth opportunities or capital deployment where the economics of that would make sense. Your question on VC Summer, Seiya, 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, Dan? Yeah. In the past, you guys have talked about the idea of being a potential partial investor in the plant. I wasn't sure where that is going and whether there's been any substantive progress. Sure. Yeah. As you know, of course, that we signed an LOI back in 2010 for 5%-10% of Santee Cooper's portion of the plant. We've been performing due diligence ever since, we have not come to acceptable terms. We have allowed the LOI to expire end of last year, we have continued to negotiate with Santee Cooper to try to come up with the right terms. That's where things stand right now. As you have questions, please raise your hand. We'll make sure to get a mic to you. Paul? I wanted to sort of follow up on Greg's question with the earnings growth and what have you. First of all, the 4%-6% is based off what the midpoint, as I understand it, of 2013. Is that correct? That's right. Okay. When I'm looking at the rate base growth, it looks more like from that period on, it's more like a 3% grower. 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 and what have you. How should we think, how would we quantify the improvement in return? Because that's what it would seem would be driving. How much of an improvement should we be thinking about the utility business having in terms of return? Paul, a 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. As we look over the period, it'll be a matter of reaching the returns that we are expecting on the additional investment that we're 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. I would think of us in the 10-ish range. We have an opportunity to go slightly above that, perhaps over the period. Beyond that's what I would share at this point. Okay. 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? I would assume that there probably wouldn't be that big a change. Just any thoughts that you could sort of follow up on? Well, it's really a board decision in terms of the businesses that we pursue. It's 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, one of the questions we always ask, do you hold them or fold them with respect to those assets? To date, the board believes that the renewable business makes sense and produces good returns with the right appropriate amount of risk. They believe that DEI makes sense given the fact that it produces significant amount of cash and has 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 if we get a negative answer from Ohio. I believe that we have a strong board. They have clarity in terms of the direction of where our industry is going, 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. 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. By the way, if we get higher prices, we're not going to turn them down. 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. We just happened to hit the mark with the two projects in Chile. We've gone back and I've added up the cumulative amount over the past four or five years of growth capital, and we haven't exceeded that. It just came in a lumpy fashion in 2012. 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 at the beginning of this conference. One is on solar. I was a little confused as to whether that's a positive or negative for you, and maybe you can clarify that specifically for Duke, how the solar industry is playing out and whether that's a positive or negative for you guys. 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 at Duke, how high would you like to see that get as a percent of your overall mix looking out 10 years or beyond? Lastly, I know these are all subtle questions, but can you talk a little bit more about why growth is slow from a secular point of view? Some of it's conservation and efficiency, some of it's the slow economy, let's assume for a moment that the economy really started to pick up and gain real traction, 4% GDP. Well, first with solar, I think it's both a positive and a negative. Let me tell you what I mean. If you think back five years ago, there was legislation pending in Congress that basically would have a national renewable portfolio standard, utilities could not invest in the renewables that they bought. This would have precluded a huge investment opportunity for us. Any time a law passes that doesn't allow us to deploy capital, that's bad news because we make money when we deploy capital. The consequence of the probability of that happening, and it did happen, we started a renewables business, we have 1,700 megawatts today producing higher returns than from our regulated business, primarily driven by how we financed it. We took preemptive action in the event we'd be precluded from that investment. With respect to solar on the rooftop, we are looking at the possibility of pursuing that kind of business. All our renewable sales have been utility-scale, primarily because that's where the greatest opportunity has been. If we are preemptive on this, we can turn it from a negative to a positive. The negative aspect of it is, you've seen this in California, where they've 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 to kind of buy down your bill over time because of tiered rates in California. That has really cut into PG&E and Southern California Edison's load that they've had to provide. 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. I think that we have to be aggressive on this as well as 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-the-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. As an overall organization, we're moving to a place where we'll be almost one-third coal, one-third gas, these are rough numbers, and probably one-third nuclear and renewables. That's going to be the mix that I see for our company, and that's a pretty balanced position to be in. The biggest challenge to us is simply the challenge of avoiding all gas all the time. Did you have a third part of your question on the economic recovery and load growth? Just balancing the pressures that you've alluded to versus 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 load 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. Most recently, it's fallen to about four-tenths of a percent growth in electricity for every 1% growth in GDP. That's the function of the energy intensity of our economy changing. We're at a place where I believe the demand will grow, new homes, new businesses. As we said earlier, North Carolina is the number two state in the country to do business. That's important. Indiana's 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, there's a lot of residential growth in North Carolina. Primarily, it's called 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, they don't want to go all the way back to New York or New Jersey. They stop in North Carolina, that's where they retire. We're seeing growth really from that. 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. I've spent a lot of time in Silicon Valley. I've met with a lot of new technology companies, it's crystal clear to me that they're developing technologies that will translate in significant reductions in the demand of electricity. In Charlotte, we have a project now called Envision Charlotte, where we've committed to try to reduce the demand in all of the uptown area by 20% in five years. Projects like that are going on all across this country. 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. That means taking action on cost, 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 do we have from the audience? Anybody raise their hand? Ali? Questions. Lynn, one I wanted to clarify on Ohio. Could you just first remind us what you've asked for in that capacity? If you do get it, how much increment is that? If I recall correctly, in your commercial power 2013 assumptions, which you have them commercial power flat versus 2012, I believe you have assumed that you get the positive ruling out of Ohio, just looking at the slides. Just want to be clear what you've assumed in there for 2013. Gently. Sure. Ali, what we have filed for is $730 million for the period of August of 2012 through May of 2015, which is the period that Duke Energy Ohio is an FRR entity. 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. What we have included in the range of $420-$445 is a variety of assumptions and scenarios that could play out in the state of Ohio. There is an assumption when you look at commercial power being flat at the midpoint. There is an assumption of a level of recovery. I'm not going to share those specifically with you given the status of the proceedings. Okay, fair enough. My second question, 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 2015. 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 USFE&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? I start with a bit of a track record. Our teams have done a very good job in this front on managing O&M. If you look 2007 to 2010, we kept O&M relatively flat during that period. Last year, early in the year, we were experiencing poor weather, we made O&M adjustments accordingly. I say that to say we've got a track record of dealing effectively with O&M. On the coal fleet in particular, I talked earlier about the fact that it's not running as base load, and quite frankly, we're not projecting that it's going to run as base load 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 That we can create some operational flexibility on that front. 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. There are a variety of things that we're exploring. I will tell you that there's nothing like a sense of urgency to drive good outcomes. 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&M mark. 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. I think 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, it'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. I'm confident that we're going to be able to change this. 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 the 25 years that Jim refers to relative to him being there. I think 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 as well. However, having said that, you have what you have, you can only go so far, you all work hard and produce good results. Jim started the presentation by talking about anemic load growth. He just went into additional comments on the same theme, 1% is, on a relative basis, pretty anemic. It's not going to produce great opportunities, regardless, to produce great increases in earnings. It is what it is. Having said that, I'm questioning fuel and I'm questioning, in particular, gas. The Wall Street Journal has a very optimistic story today about gas, about the availability of gas, and 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? If not, have you tried to get it? What are the prices and is the hedging that Lynn referred to earlier, is that good enough, or can you be locking in lower prices for gas for longer periods of time? In terms of long-term contracts, I'll tell you historically, the E&P companies have not been that receptive to longer-term contracts. That is changing to some degree. 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. It's early days in that front, but I think there are opportunities that are emerging. I think the place where it may make the most sense are the areas that are more and more dependent on gas. Florida, as an example, with the Crystal River 3 retirement and then the potential retirement of Crystal River 1 and 2 in the 2015 to 2017 timeframe, you're going to get into a place where you're 75% dependent on gas. In that kind of environment, it very well may make sense to regulators, to customers, and to us to look for long-term type agreements. There are different ways that you can structure that, I think there may be ways to structure it so that we can actually generate some earnings on that. A lot of ideas going on, but this will be part of the innovation that I think we're going through right now as a company. Sure. I have three or four questions if I can address them to different members. Jim, first of all, just starting off, congrats. Okay. First question for Jim. Congrats. The performance of the company has been excellent over the last three 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 pier right now. As we go through the next five or six years, do you think this is going to be further M&A in the group? 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? If I was hanging around, it wouldn't be the last one. It would be the beginning of the next round. I'm a true believer that building a strong company through combinations makes sense. 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. 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. Given our experience with the FERC and three tries before we got it right, as far as they were concerned. 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. Just going to the integration, Jen, I guess you mentioned there were like four. 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 many 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 direct report. Okay, I'll go to this mic now. This is keeping us on our toes, this microphone. It includes a blend of the two companies. It's our direct reports, their directs, 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 for 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 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. Okay. What I was more interested, could you share with us what the percentage is? How much percentage is the legacy Duke versus- Sure. Could you give us a- I would say in general, the percentage is about 60/40, 65/35 in terms of the split. 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? Keith, I have just a question on the regulated side as you take on 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 two? Yeah. One of the key challenges is really this O&M world that we're in, right? We've talked a bit about that. That's really what we're focused on in large measure, and it's the hard focus on the coal assets is the challenge. We're working through that. The other piece of this is we're bringing two teams together. And like Dhiaa said, we have great leadership from the Progress side, great leadership from the Duke side, and they've come together very well. The biggest single challenge is going to be how do we address this new O&M world that we're approaching. 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 this cycle change? 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. 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%-70% and see our way to getting within that ratio in the next year or so. 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. 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. Our commitment to growth of the dividend is a very important part of the value proposition, and we think over time, there will be an opportunity to accelerate growth of the dividend. Let's look for one final question from the audience that has not been answered. We're past lunchtime. Jim, let me turn it back over to you for some final comments. 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. Looking at the age, some of you couldn't have been in the industry 25 years ago. The reality is that this is a great industry to be in. 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? 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. I think it just has popped up on the screen. That's kind of a symbol of what we're going to be in the future. It will be a little change in look. It also reflects collaboration. It reflects the recognition that we have to continue to work to reduce our emissions. Environmental issues have been key to me, an important part of my legacy, going all the way back to 1990 when I was the only CEO in the industry to support the Clean Air Act amendments with respect to SO2. We have come a long way together. I have produced strong results for you all. I've done my best. Look forward to seeing you in my next life. Thank you all very much

Data Source: Quartr Last updated: Feb 28, 2013

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