Bob Drennan - VP, Investor Relations
Jim Rogers - Chairman, President & CEO
Keith Trent - EVP & COO, Regulated Utilities
Dhiaa Jamil - EVP & CNO
Lloyd Yates - EVP, Regulated Utilities
Lynn Good - EVP & CFO
Marc Manly - EVP & President, Commercial Businesses
Bill Currens - Director, Investor Relations
Lee Mazzocchi - SVP & Chief Integration & Innovation Officer
Jennifer Weber - Chief Human Resources Officer
Julie Janson - General Counsel
Duke Energy Corporation (DUK) Investor & Analyst Meeting Conference Call February 28, 2013 8:30 AM ET
Welcome to Duke Energy’s 2013 Analyst Meeting. I am Bob Drennan with Duke Investor Relations department. We are very glad that you are here to hear from us today. This morning you will be hearing from members of Duke Energy’s senior management team as they discuss future prospects for our company.
Today’s discussion is being webcast and includes forward-looking information and the use of non-GAAP financial measures. You should refer to the information included with our presentation as well as our SEC filings concerning factors that could cause future results to differ from this forward-looking information. A Safe Harbor statement and a reconciliation of non-GAAP financial measures is available on our website and in today's presentation materials.
Now let me briefly describe today's format. In 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 will move to Keith Trent who will discuss our Regulated Utility Operations and in turn other members of senior management will follow.
We plan to have a short time for questions after each of the business section reviews and we reserve time at the end of the meeting for the entire team to take your questions. Since today's meeting is being webcast please wait for a microphone to be presented to you before asking your question. We are scheduled for a break around 10:15 this morning and we’ll resume probably at 10:30. We plan to conclude by 12:30 PM. As a reminder, please mute or turn off your phones and Blackberries.
And now I would like to turn the program over to Jim Rogers.
Good morning. We are glad you are 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 will hear how Duke is positioned for the ever-evolving energy landscape. We will show the benefits of the merger; our optimizing our generation portfolio and recovering our investments. We are also reaffirming our value proposition. It is familiar to many of you all and it is simply this. We are a low risk primarily regulated utility, well positioned to build on our record of strong operational and financial results. You will 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 is out as to whether that will be a lasting model. I’ve seen RTOs formed in many parts of this country; renewable portfolio standards in 30 states. Environmental mineral regulations on coal plants that had cost the industry billions of dollars that have translated into significant reductions in Sox, NOx and mercury; been lot of fast; it didn’t play out as people thought. To me, we are facing headwinds; in my judgment 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, which surged 21% last year for an average price of $3.48 more than a buck more than in 2011 and significantly lower than the $10 to $12 a number of years ago. Who would have predicted that someone would forecast the natural gas in 25 years would represent over 52% for the generation in this country; the same percentage that coal has held for many decades in this country; and that was a prediction (inaudible). Who would have predicted that we will be in an environment of anemic demand growth; well, I believe that is one of several key issues; clearly with Fukushima cost and modernization of the grid cost and modernization of our generation fleet, we’re seeing rising prices; that’s part of the future.
But the growth issue is more complex and more difficult to discern as we go forward; pushing up demand as you see greater electrification of our economy, you are seeing an anemic rebound in the economy and as more houses are build and industry rebounds that will push growth. But pushing it down is something that’s going to be very incremental and harder to measure and that to me is the remediation both of the supply and the demand side; what does that mean? On the supply side what that means to be 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. So 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. So 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. And 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 as a past.
We need to work hard to change the regulatory model, so that we are positioned to be prepared to handle a world, if it turns out that we have very anemic growth, and anemic is less than 1% anemic could be flat, if you are bearish. So the bottomline is we have to be prepared to achieve 4% to 6% growth in that environment; so changing the regulatory model is going to be an important part of that, changing the cost paradigm is going to be a very important part of that. And we’ve gone through a number of mergers over the last 25 years and each has been a catalyst for driving across out of our operation and improving the efficiency of our organization.
Slide six shows three types of forces that are reshaping the industry ranging from economic and market trends to developments of public policy and technology. These forces were interrelated and I have spoken to just a few of them. Trends like these are driving transformative change. No one, as the future figured out. Here in my carrier, I have learned to take nothing for granted and that is no risk; we are in a good position to lead this transition and take advantage of new opportunities from mitigating the risk.
As I prepare to leave by the end of this year, I have one priority and only one priority and that is to support the executive team forward and ensuring that this company is ready for whatever lies ahead; ready to be meet with agility, specifically when you are such a large company with resilience, the ability to look around the corner and see the future for others to and move to take advantage of the opportunities or confront the challenges that are seen. Our leadership team will show you today why I have confidence in Duke’s future. 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 US based on most metrics. Market cap generating capacity and customer served, they all importantly help us to achieve cost savings and 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 will explain, we are 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 ’05 to 38% in ’15. Gas share grows from 5% in ’05 to 24% in ’15. 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 plant in the Carolina. Also, we have fuel mix diversity and we have strategic flexibility with our commercial business which Marc 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 and that dividend is at the heart of our investor proposition. I am proud of what our employees achieved in 2012 despite a year of unparalleled turmoil and uncertainty. I’ve talked about this on our current earnings call.
Slide eight highlights a few accomplishments; starting with completing the merger after 18 months and three trials that occurred and obtaining approval of the cost recovery settlement at the Edwardsport IGCC plan. 2012 was a strong year operationally and as you all know, so well financially. Our employees achieved the company’s best safety record ever. That's incredible given the turmoil that we were going through during that period. Our 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 you will 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% to 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; we achieved 6% compound annual growth rate and adjusted diluted earnings per share and a 2% growth rate in the dividend.
I am proud of our total return; the key investor metric, seen 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 maintained the strength of our balance sheet and continue to enjoy the benefits of a strong investment grade credit rating. I should have; not to brag about the last three years, because you all know about it. Simply say, we do our best to deliver of what we promise.
Another part of our track record is resolving our near-term priority; since July we have been focused on the one shown on slide 10; let me take them all 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 are going 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 are systematically reducing uncertainty and risk.
This morning you will hear further update on our remaining 2013 priorities; taking 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 will get into more detail about that when he speaks; but a fair result allows us to go forward and recover our investments in PEC. You will also hear more about our ongoing priorities to harvest the merger synergy 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, [towards] our plans 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 fundamental is more important now than ever before. This includes operational excellence, customer satisfaction, financial discipline and constructive regulation.
You 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 Dhiaa achieve operational excellence which supports customer satisfaction as well as regulatory relationships. Lloyd will talk about what we are doing to achieve constructive regulatory outcomes in our rate cases.
Then we 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 and together they position us well for the ever evolving energy future and most importantly differentiate us from other utilities.
Scale efficiency, diversity of generation in earnings which mitigates risk, favorable geography that provides both diversity and access to attractive markets, strategic flexibility, to redeploy capital to cease 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 trends with a continuing focus on the fundamentals. Our main point is this. Duke Energy is well positioned on the road ahead.
We are anticipating, we are challenging conventional wisdoms, we are 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 engage workforce. They are here today to talk about our strategy and how we're adapting to the new energy landscape.
We will see why I have so much confidence in them. They will answer your questions after each presentation. We will 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 at 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 round.
Thank you, Jim and good morning everyone. As Jim mentioned, I am 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, 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 are on track to deliver operations related merger savings. These includes fuel and joint dispatch savings and go directly to our customers where it also includes merger savings that we are harvesting today and we are focused on savings beyond those that are simply related to the merger.
Finally, as Jim highlighted, we are monitoring the changing landscape including lower load growth and new environmental regulations. As events unfold and things become more clear, we poised to retire additional plans and to make additional investment 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 are big and we are telling you we are 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 the slide shows that as a company we are not dependent on any single fuel. Currently, nuclear provides 34% of our generation. Dhiaa is going to talk about the nuclear fleet in a moment.
The remaining 66% of the regulated fleet is coal and natural gas with the small amount of hydro. Our non-nuclear fleet performed very well in 2012. One way we measure our sales there is looking at commercial availability and I can tell you in 2012, in most instances we hit our commercial availability targets some were slightly below target, that’s good but we have got room for improvement and we know that.
We are addressing the fact that our coal plants are no longer dispatching as base-load units especially in Carolinas and you can see from the chart on the bottom right of the slide, but the capacity factor for our coal plants dipped below 50% last year. They as a result of low natural gas prices, our natural gas plants are operating as base-loads with capacity factors in the 70% to 80% range. Now, this maybe the new normal and if it is we are ready.
If it is we are going to need to find efficiencies low at our coal plants and I can tell we are very focused on that and those efficiencies will go above and beyond what we are looking at from a synergy target perspective.
Opportunities we are looking at are can we convert more fixed cost to variable cost? If we can do that, that’s going to make us more efficient and it’s also going to give us more flexibility.
In regards what the future commodity prices look like our fleet is balanced 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 power capacity. And we will retire 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, the combined Duke Energy and progress generation of mix in 2005 was mostly coal and nuclear. But by 2015, we will have a near equal balance of nuclear, coal and natural gas.
Our coal fleet today is clean, but it’s getting cleaner. The pie charts on the lower right of the slide show you that over 80% of our coal is scrubbed today and that number is going to go to 96% by 2015.
Two new plants are going to come online this year, Edwardsport, our 618 megawatt 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.
And we've produced electricity from both of our turbines using syngas, natural gas and a blend of both and in fact last week, our 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 two has been producing 200 megawatts of power on syngas and the steam turbine has been producing about 90 megawatts of generation.
So we are confident with this technology. We are confident that this plant is going to operate as designed and we are still looking at an in-service date in the mid part of this year.
Second plant we are completing this year is the 625 megawatt 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 fourth quarter of this year.
We are also focused on managing costs. We are particularly focused on delivering $687 million in fuel and joint dispatch savings to our customers in the Carolinas over the next five years. We are estimating that about half of these savings are going to come from jointly dispatching the progress in Duke fleets. The other half is going to come from fuel sales.
On joint dispatch, we hit the ground running; within 15 minutes from the time the merger closed, we were dispatching our systems in a combined way and delivering benefits to customers. The bars on the right side of this slide show you that we can deliver savings in different price regimes and let me talk about this just a moment.
When gas prices trended lower back in August, Progress Energy’s heavier gas fleet was dispatching from Progress territories into the Duke territories. Then in December as gas prices started to rise, Duke’s more heavy coal fleet began dispatching into Progress territory. The key here is under both of those price regimes we were delivering savings and harvesting savings for our customers.
So the joint dispatch system is working and it continues to get more efficient and even better. Our fuel program is on track as well. So far, we've locked in about 65% of the anticipating savings, the targeted savings and that came through, we negotiated coal contracts and also through fuel transportation segments.
And we are also ahead of our plan in terms of our coal blending programs. Let me give you one example, at our 2,200 megawatt 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 and the plant personnel are currently conducting test 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, specifically in the regulated operations, team have identified more than 200 specific initiatives. We’ve assigned clear accountability for those initiatives and we're on track to complete them. So we're focused on cost but not at the expense of our operational excellence.
So on a power delivery front; we measure reliability success using two measures, SAIFI and CAIDI. SAIFI captures the number of times the average customer experiences a sustained outage each year. CAIDI measures the average duration of annual outages in a minute. 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 CAIDI front, it's improved over the same time period. For 2012, the Duke annual CAIDI was just over two hours per customer which represents a 22% improvement from 2006 level. Both of these trends demonstrate our improving system. We're never going to reach zero here but I can tell you there are 7,000 T&D employees, they 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 have ever been. The size of our team and the diverse geography of our territories give us the scale and the ability to quickly move thousands of employees from one region to another to restore power quickly and safely. We flex that muscle in November, when we send more than 2,900 employees in contractors to assisting customer restoration in the wake of Super Storm Sandy. That was the largest deployment in our company’s history. Then just a few weeks ago, more than 700 of our contractors helped to restore power in the areas in the Northeast that were ambushed by the major bizarre.
You can 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 cost and deliver excellent operational result including strong reliability, good customer satisfaction reserves going to follow and we believe we are well positioned to deliver those results.
So that’s give you a picture of what we are doing on the operations front. Let me spend a couple of minutes on future investment opportunities. As slide 21 shows, we have spent $7 billion on air emission controls to reduce SO2 and NOx. With these investments, we have already reduced SO2 emissions by 86% and NOx emissions by 64% through 2012 of 2005 base. By 2015, those percentages are going to improve to 92% and 79% respectively.
As we look to the future, we are anticipating new air, water and waste rules. We estimate that an additional $5 billion to $6 billion in investment will be needed over the next decade to comply with new regulations, that’s down from our previous estimate that we have given you of around $6 billion to $7 billion. Improvement in the final [macro] will enable us to eliminate some of the anticipated blackouts 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 the spending is expected to be for air regulations such as MATS and about 95% of this air related investments are expected to be made in Indiana and in the Carolinas where we historically have had very constructive recovery of environmental compliant spend.
The remaining 75% of the $5 billion to $6 billion range is targeted for potential water and waste regulations which have not yet been finalized. We are continuing to monitor the development of these rules and we will adjust our estimates as we gain further clarity there.
So let me leave you with this thought. First, our fleet modernization program put us in the strong position in terms of diversity, fuel diversity and environmental regulation.
Second, we are taking full advantage of our unique scale and diversity. We are driving out cost without sacrificing operational excellence, that’s good for our customers and it’s good for our investors.
And third, we are ready for additional investments in our generation fleet.
Finally, we are clear about our mission. We will deliver affordable, reliable and increasingly clean energy in a safe manner but by delivering superior outcomes for our customers our communities and our shareholders. Thank you and now I will take questions.
Question of gas cost and fuel mix interest me. Could you talk a little bit about what's your, how you buy gas, where does it come from and how variable of a cost over a period of time and 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.
(Inaudible) varied from some degree jurisdiction to jurisdiction and it depends to some degree on the regulatory requirements and desires quite frankly, and historically I would say that the progress has hedged out further on natural gas prices that Duke has. We are entering into some hedges going forward on natural gas. As we look to the future, we are going to be the second largest buyer of natural gas among utilities, and so it’s obviously an important thing for us.
But we are presently not hedging out for long term contracts on the gas side. We are 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 will be full transparency in agreement with the regulators. Because from a hedging standpoint it’s good for us to do that and we do that, but we've got to balance the risk associated with the hedging and the benefits to customers and so the key for us is making good decisions that are in large step with our regulators.
In terms of coal contracts I can't comment specifically on additional contract re-negotiations at this point. As I mentioned to you we've got 65% of our fuel savings locked in and we are quite comfortable that we can achieve the balance of those [stages].
Pretty big numbers when you look at it over a decade, regarding regulations that don't exist (inaudible) been drafted by the EPA, the company held by the EPA. I am not a lawyer, I know you are. They will probably get litigated for multiple years whenever they come out and you know I'm thinking [316D], I'm thinking coal ash. How do you get your arms around A, what the rules will likely be and then B, thinking about what the cost to comply with those rules will be over a multi-year time horizon, and then C the timeline for implementation.
Those are great questions, so 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 players. The math rule, the rules are final, I realize that there's litigation going on to challenge the rules but we are assuming that those math rules will go in place and that we will need to comply by 2015 and in some instances we can get a one-year extension.
So we're using that as an assumption and so air is where we have the most certainty. The rule changes as I mentioned have given us an ability to eliminate, back out. So on the air side, what we look at most is the addition of some SERs and addition of sorbent injection. So we think we got a pretty good handle on the air side. Those are the spins that are the most near-term. They make up the majority of the spin 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 time and dates and really not giving you specific information but beyond the three years because it is harder to know exactly what timing is going to happen outside of this three year window. So, air we feel pretty good about. That’s where a lot of spins going to be happening in the next three years and one of the tools we're also using 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 and we were successful on reaching agreement with the OUCC recently on the environmental compliance plan regarding the spend that we're going to making there.
So, your point is well taken in that the further out you get and especially for the rules that we don’t have final rules on, there are certainly going to be some leeway and our forecast likely will change as we go in time. But we have a very, very strong process that we go through to evaluate what we think we're going to need. What needs to be retired, what needs to be added, and certainly we have some base set of assumptions and I won't go in to all of the base set of assumption. But we feel good about the assumptions we have, but again we are ready to change them if we see things going in a different direction.
May be just following up on that question because we are having a chat at our table about the same slide. Put it in to more sort of numerical detail, you’ve said that you got about 650 million of CapEx related to MAX and to go back to your appendix the total spend for environmental is $1.375 billion. So how much of that is sort of placeholder, how much of the other half is placeholder that could be subject to change as per Michael’s question where you just, you are thinking you are going to spend it but you really don't know for sure and it seems to be backend loaded at .
So again the air is the bigger component of it. I would say the air of this 1.4ish is in the 600 million range, and again I think we have a better certainty there. And then the remainder is water and waste 800 million there. Some more uncertainty there, but the types of projects we are talking about there are on the waste side ash [pawn] work, dry ash conversion kind of work and then on the water side, water treatment systems work.
So we have things that are specifically identified, we don't have just sort of throwing in this big bucket of contingency or gas. But having said that especially on the waste and water side, you can see some sliding or changing there, but we feel reasonably good about the estimates for this three year period.
Take one more question here and then we will move towards (inaudible).
Following up on move environmental expenses, I know that it’s important to you now to get at least if not always to get the regulators to concur and advance before you spend your money. To what degree have you talked to regulators about this plan-over for medium and longer range and what kind of reaction do they have looking for filings in advance or as you say Duke will judge you after you do it or what.
Yeah, so different and different places and Lloyd can probably go deeper on this than I can on the regulatory side, but what I have to say to you is in Indiana as I mentioned we saw the clients plan and so there is a very deep discussion with the interveners, with OUCC and then the commission obviously is being well informed in terms of what we are asking to do and we are seeking in order approving that spend.
In the other jurisdictions it will depend; in the Carolinas our practice has been to keep the commission and public stack very, very informed of that what we are doing. We live by no surprises kind of rule and we will continue to do that. So I think you (inaudible) it make a sense of how we interact with our regulators.
All right, at this time I am going to turn the show over to Dhiaa he will 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'll 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 target investment to achieve operational excellence and efficiencies across the fleet; and third I will discuss our plan to maintain the option for 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 are retiring Crystal River 3 in Florida. So from the math that you see on the screen we noticed that all 11 units are in the Carolinas and within well driving range which gives us a distinct advantage in that regard. It allows us to use resources and expertise more effectively and leverage best practices across the whole fleet more quickly and address emergency 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. As you see on the slide we’ve set up 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. The 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's important in nuclear from a performance point of view. They represent safety, reliability, safety in the form of personnel, radiological and nuclear safety, reliability with capacity factor on gross loss rate, there's an independent view of an (inaudible) index and cost of these efficiencies represented in terms of total operating cost.
As you look across the chart which represents several years of performance, you’ll 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, so 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 and we will achieve top cortile. I'm confident we are on the way to achieving that.
We've established high quality organization and detailed plans with targeted investment that will lead to step changing performance. As we make these investments, we will continue to emphasize cost control as we leverage the scale of our fleet, and the merger gives us opportunities to garner 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 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 result in the fleet. It illustrates disciplined approach to optimize the operation of the fleet. This particular depiction depicts our operating model, which I call our play book. It helps us quickly integrate our nuclear team post merger, it provides great clarity about our work policies and processes, and assists us in maintaining current and objective view of our performance.
Two main aspects of this 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. They reflect industry best standards. Governance discusses how we run the fleet, conduct of operations with the fleet. Oversight is represented by a strategic mix of internal and external oversight. It is described, I describe it as in crucible sight.
My colleagues get nervous when I talk about intrusive, the word intrusive and I realize the word intrusive is not always a pleasant word. That you hear it when you are talking about government action or may be it reminds of some unpleasant medical procedure, but I assure in nuclear it's 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’s the strong approach of highly inquisitive and aggressive reviews coupled with graphic mobilization of resources from across the fleet that is key to our success.
Turning to our next slide, you see the target investment we are making to increase overall fleet performance and to me 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 of Brunswick and Robinson. We hired over 200 individuals in a variety of discipline such as engineering, maintenance and operation. This is providing immediate benefit and we will also have a long term benefit to that effect.
We also put special teams in place at Robinson and Brunswick to accelerate improvement. And we have deployed supervisor inventories and 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 events and our DWR units and instrumentation to accurately measures (inaudible) fuel levels, water level and opportunities to augment emergency response.
Of course dollars to meet these requirements may very as the rules are more clearly defined. The scale of fleet enable us to address the requirements more efficiently and while required these investments should also contribute to performance improvement. We move to Crystal River as we move to the next slide, I will update you on the plants to retire and decommission to Crystal River nuclear site in Florida. We have selected as you know the same store metric for decommissioning, replacing units and save storage configuration, until dismounting and decommissioning work occurs which will be within 40 to 60 years. As you all 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 NRC for permanent cessation of nuclear operation from CR3. Next step is to finalize our decommissioning transition organization actively working with plant employees to understand how we can best use their expertise and skills. Some of the staff of course will move to the transition organization while others will be redeployed across the fleet and company.
Once that transition team is staffed, we will focus on developing and submitting shutdown technical specification to the NRC. We expect the NRC to take about a year to review and approve that. After approval of that technical specification, we will develop and implement a steady state organization to step aside until decommissioning is complete. That organization is expected to be significant and be smaller in size than the current organization.
With this next slide, I'll update you on new nuclear work. As we plan ahead, we are continuing the project development work on Levy and maintaining new nuclear generation as an option for future capacity. Nuclear is a key component of our long-term resource strategy because it helps with geo diversity and represents carbon-free base 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 ’15 with Harris license expected sometime later in the future. Of course the way 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 V.C. Summer units now under construction in South Carolina. Also as we have discussed before, we are supportive of the development of a state regulatory framework in North Carolina that would allow for recovery of financing costs during construction in accordance with 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 construction and to maintain the strength of our balance sheet. As we keep new nuclear as a viable option for the future, we are actively learning from nuclear construction projects in the US and also at multiple locations in China.
In summary, our nuclear team is highly focused on what it takes to achieve a sustained operational excellence. We have superior a track record driven in part by robust operating model with strong governance and oversight. With the merger, we are 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 [forty] years, safely, reliably and cost effectively. Nuclear remains an important option for future generation diversity.
Thank you. And at this point I'll take your questions.
A quick question, going back to slide 26 where you are showing, what happens with the analysis of the legacy progress; was it that their performance had flat lined per years while the industry improved or did their fleet performance deteriorated?
I can speak with confidence about the current state and I can also tell you that I assure that the whole industry, I think your point on that is that we not keep up with the industry performance improvements and probably more than the case, anytime there is a disparity in performance, the whole industry moves up in performance at a rapid pace, ahead of industry. Today, we operate the 11 plants. Eight of them operate at the excellence 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 will be able to close those gaps very quickly.
You laid out the cost for the Fukushima requirement; you also mentioned there are some uncertainties as to the exact requirements of 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 and how different operators are approaching Fukushima compliance and estimates or is it fairly uniform approach and where would you put yourself in the spectrum of how conservative you have gone in the cost efforts?
So, just a little background that is the NRC put out their recommendations or their requirements in three 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 other rules are not yet well defined. So as a result, you see a variation in interpretation. We are very close as an industry to try to understand exactly what that requirements means, but even with that there are some variations and the design requirements are different. I have only two BWRs, other fleets have 12 BWRs. Certain modifications may be more expensive than others and so it will play to their strategy differently. But big picture you start with analysis and we start with walk-downs that is what Tier 1 emphasizes first. To the extent that you find vulnerabilities you have to address with modification with what it will cost money. Our approach is relative to others, I would tell you that we have more of a bias to say we are likely going to do the modifications. So those numbers reflect that bias, while others maybe have more confidence in their ability to their analysis to show different results. So our bias I would tell you I am confident is heavy on the conservative side for modifications.
Okay. Well, I have two more questions here then we will go onto…
Going back to the earlier question and that slide where you talked about the drop in your performance indices. Just curious how the merger integration has gone on with the progress fleet coming into the Duke fleet and was the issue of over staffing was a question of changes in management and processes, headcount reduction, give us some sense of where you see the change and how easily you have been able to blend the two fleets?
Yeah, I will tell you that blending the two nuclear fleet into one has been a bright spot for us, and we are be very pleased of how well we have come together as one team. You will find, Jim showed the first layer of management; if I fold my layer you would find very equal balance between legacy progress and legacy to two fleet; processes that we’re aiming for the future really don't necessarily represent uniquely to processes or legacy progress and processes work we’re showing, industry best standards as the new processes for the fleet. Integration, I am so pleased with how well things are going.
And second part of your questions deals with, so what is that you are finding? We have expertise on both sides and they excel in certain aspects of business and methodology, I would go back to my discussion about 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. Lastly, what is the single thing that will make a difference in performance, it would be that and the corporate infrastructure that we have in place which is supplemented by legacy progress folks, we will do exactly that.
BWR’s that you mentioned, I am sorry, it is going to be higher, can you give us an idea of the cost that you outlined how much for the BWR’s and how much is for the rest…….
You’re talking about Fukushima?
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 would, 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 the developing strategy for. That is the only unique aspect of the difference between BWR’s. So if we go to 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, but still we go to the extreme modification no one has done a detailed analysis on that, but conceptually, add $50 million per unit in modification space.
All rights, so folks thank you very much and at this point Lloyd will discuss the regulatory business.
Good morning everyone. I’ll focus on the regulated utilities, specifically the rate case that we filed and the one we are preparing to file. Like my colleagues, I have three facts about our regulated utilities strategy. First, we must begin recovering the cost of fleet modernization program discussed by Keith and Dhiaa. We are poised to do so on our near term rate cases and 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 Carolina case next month. All together, six rate cases will total more than a $1 billion of revenues. In addition, this summer we expect the Ohio Commission’s decision on our capacity case; every one of these instances will work with the commission and interveners to reach constructive outcome to recover modernization investment and to earn returns.
Let's take a closer look at these cases starting with the Progress Energy Carolina’s case on the next slide. In the PEC cases we will seek to recover costs associated with three combined cycle natural gas service holding almost 2200 megawatts of capacity. Two of the plants that 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 supports the retirement of 1500 megawatts of older coal-fired generation. Those retirements have already started taking place.
Last October, Progress Energy Carolina has filed its first rate case in North Carolina 25 years. Request this 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 investment. And 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. A $151 million in revenue increase in the first year and 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% component, equity component of our capital structure. Hearings began on March 18th, and we expect the decision in time for rates to go into effect in June. Now we're pleased to have a settlement, but several regulatory decisions are outstanding such as cost allocation and rate design and not all interveners are signed on to the agreement. South Carolina, Progress Energy is evaluating filing a rate case later this year.
Now lets turn to the rate case with Duke Energy Carolina, starting with the one filed several weeks ago as shown in next slide. This rate case takes recovery of costs associated with the new Dan River combined cycle and natural gas plant and the advanced Cliffside coal plant. We're also requesting recovery associated with modifications of the enhancements of the Oconee and McGuire and nuclear stations. Request is for increase of $446 million in annual revenue or 9.7% rate increase to our customers. Hearings began on July 8th, with rates effective in 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 Carolina’s cases of North Carolina to recover investment in new generation and to upgrade existing plant. In addition, Duke Energy Carolina is to provide the required 30-day notice or South Carolina rate case filing in March. We expect these revive rates to be effective in the fourth quarter of 2013.
Now 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 and we expect these two cases to be resolved by the summer.
And on next slide is an update on our $728 million capacity filing in Ohio. Hearings began this spring and there are few points I want you to keep in mind. First, our filing is consisting with the new cost based compensation mechanism for fixed resource requirement utilities, which includes Duke Energy Ohio. Second, we are not speaking the change in electric security plan under which Duke Ohio operates; capacity of the non-competitive service outside of the provisions of an ESP. And 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 19, and that the hearings inherence will begin on April 2nd. We’re hopeful for a decision by the middle of this year. So that is our calendar rate cases, important proceeding on multiple fronts; the outcome will support our financial strength and provide earnings growth.
For the next slide, I would like to mention the regulatory proceeding in Florida have a follow up on our recent decisions to retire the Crystal River nuclear unit. As shown on this slide, the current schedule cost testimony on March 18th, followed by the commission staff and intervener filings in mid May. Following an informal confidence there are two things that Florida commission staff answer the company by a motion to lift the March 18th filing requirement until a new date can be set after the March 12th issues conference.
Currently, the expectation is that the commissions focus will be in three areas. First, due to the company’s decision regard retire versus repair of the unit. Second, requirement of prudence and our acceptance of third party remediate this proposal of the insurance settlement with [Neill]. Third, determine of spoke the regulatory asset that will meet in 2017 for the 2012 settlement. We expect the commission to issue revised procedure schedule later in March.
Now with all of this activity in our jurisdiction, let me focus a moment on our regulatory environment. I think that's obviously important for our investors. Next slide summarizes an independent ranking of the regulatory climates in our retail states. Many of you are familiar with regulatory research associates where I closely follows the actions of the utility commissions throughout the country, evaluates them from an investor perspective above average, average and below average.
As you can see on this slide, 80% of the retail rate base in our six jurisdictions exists are rated above average. In the next slide, you can see the diversity of our retail customer mix. This diversity supports our lower risk profile and it helps us manage the ebb and flow of our economic cycles. If you look at the Carolinas, Ohio and Indiana, they have the greatest percentage of industrial loads and they will benefit as the economy continues to recover.
Florida on the other hand has the highest concentration of residential and commercial loads of more than 85% of sales. As the economy in housing market improves, more retirees will move to Florida and tourism will also continue to be important.
Our wholesale segment continues to be a source of growth. Long-term contracts we have in the Carolinas are case in point. Our 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 show 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 in fuel savings.
These savings will help moderate the impacts of the future rate cases as we continue to modernize of infrastructure. Our competitive rates are also important in attracting news businesses which will stimulate broader economic growth.
On the next slide you can see Duke Energy is committed to economic development. We work very hard at it because of strength of the areas we serve is fundamental to our long-term business success, the industries want reliable portable energy and our proven ability to attract and retain companies is a good sign of customer satisfaction.
2012 Duke and Progress help to attract more than $3.5 billion in investments in new and expanded business. For a record 14th year Site Selection Magazine in 2012 recognized Duke as being among the 10 best utility companies in promoting economic development. The magazine also ranked 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 are also a partner in the current initiative to expand the success in Charlotte Energy hub into a broader regional energy cluster in Carolinas. Last year, we helped to develop the Research Triangle Cleantech Cluster in Raleigh which [dovetails] with the research and manufacturing strength of our region.
So our focus on economic development is really paying off. We've seen several large investor announcements in the last couple of years. Let me give you couple of examples. Michelin Tire which is South Carolina’s largest manufacturing employer has announced over a $1 billion in expansion in the last two years. Continental Tire is nearly completion of $500 million tire manufacturing plant which will provide over 1,600 new jobs in the Sumter, South Carolina area.
Let me change gears if you will a little bit about regulatory initiatives. As Jim talked earlier about some of the macro force shaping our industry, this new landscape calls for fresh look at regulatory models and mechanisms. Both cases were not achieving the returns our regulators have authorized. The regulatory process itself is a major reason.
We need to close this gap. We are 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. (Inaudible) legislative and regulatory solutions that benefit all of our stakeholders. We're considering ways to track and recover cost more efficiently, just smooth out customer rate spikes. Center Solutions include forecasted test years, greater use of trackers, faster, more predictable review times for the rate cases.
So let me summarize. Our regulatory calendar presents significant near-term opportunity. Our rate cases are largely driven by investments in modernizing our system, reasonable outcomes in these cases will provide a strong basis for top line growth. We operate in constructive regulatory environment and we are well positioned to continue attracting new business in our service area. We are exploring new ways to reduce regulatory lag and adapt to rate making process to the new energy landscape.
Now I will be happy to take any questions.
What is the path do you see out of five state as far as looking at ways of predicting helping other mechanisms place to help mitigate some of the rate pressures on an ongoing basis, related decisions are these going to be legislative opportunities as you guys [lag] your strategy?
Okay. Sorry, I don't want to deafen anybody. On the last comment, you made about the idea of looking the ways to mitigate the impact the slow demand growth, can you walk through the state-by-state strategy how you guys look to address that and then how much that is going to be commission related versus legislative in trying to get to those solutions.
So, I think as opposed on a walk state-by-state 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 will give you an example if you look at Indiana right now, one of things as we are working with some of the legislators on Senate Bill 5 to 60, which really looks that reducing regulatory lag, have a T&D as this bill is in process, but have a tracker for transmission distribution investment have defined approval timeframes for rate cases, 300 days or a 60-day extension.
So things like that, we will look at something in Carolinas, working with, again now it will be more legislative. In Florida, we have a fair number of trackers but there are some opportunities there, but I think those are the couple of examples. I think the focus will be on trackers may be a migration to formula base rates in some areas where it makes sense, but I think we do need as Jim mentioned earlier, we need to work hard without changing these regulatory models because of this slow 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 in load growth it will lead to. I know that we work hard on it everyday that we have several opportunities. Now, you start to think about the Carolinas that I mentioned earlier, excellent places to do business. When we see an opportunity, we will travel out with some of the commerce teams in the state and we will work really hard to bring those in, data centers are good opportunities for us, manufacturing facility, some service industry has been very successful.
Our industrial rates are relatively low. Our customer satisfaction is high and as a result of that we have been able to attract manufacturing facilities to manufacturing in other facilities to our service areas.
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 have a mix debt and equity and alike. And what is (inaudible) for no longer presumably charging whatever expenses you have relative to that plant to operating earnings but switching it over and charging it against the decommissioning?
So the first question in terms of how the $600 million is invested I want to (inaudible) good for later, all right so how about saving that question. Now give me the second question again.
It sounds like Jim Rogers. How do you assign costs related to Crystal River 3 now and will those be charged against operating earnings or are they charged against the decommissioning?
So, today correct me if I'm wrong here Lynn, today they are charging the operating earnings but the plant went, came out of their rate base in January of 2013, right. So I think that will be a better question for Lynn to answer also. Why don't you give him a microphone?
I know you can hear me. The decommissioning fund, there are rules on how often and how soon you can tap into it. Currently to plan for the safe store we have access to 3%. Once we file and there's some regulatory review of the post shut down decommissioning activity report will have access to a greater amount of the decommissioning.
So, Carl I think under the same-store provisions we are talking about decommissioning 40 to 60 years from now. So we have a long runway to continue to invest and earn and the allocation of assets will be consistent with that decommissioning plan and that's something we are monitoring on an ongoing basis.
You should think about it almost like pension fund.
So you would have a debt and equity mix, you also run a variety of Monte Carlo simulation on investment performance and cost structure decommission, you have a probability of full funding and we monitor adjustments with the pension fund.
Lloyd, how are you thinking, I mean 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, I mean ’14 and beyond what the rate case cycle across the broader system looks like, whether you are likely to be in front of your regulator every other you are filing rate cases like some of your peers are or whether you have the potential to kind of slow down that process over a multi-year cycle?
So 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 gas serving in the ’16 to ’17 timetable there are some investments that need to occur in Florida and depending on earnings they may drive rate cases but right now there is nothing definitive after we execute the Progress Energy Carolinas, South Carolina rate case. There's a gap there.
CapEx forecast for the next few years as well as kind of that 4% to 6% earnings growth rate that Jim laid out at the beginning of the, does not follow on rate cases in that cycle for the next two to three years after the current ones wind down?
Not right now.
I wanted to ask you, just sort of clarify this when you mentioned this new regulatory initiative, I mean, I heard trackers four times things like save out and even decoupling. Those sort of things that seems like you guys, you didn’t mention. So those are not really, didn’t work out so well in the past and may be they are before their time kind of thing. I just want to understand whether or not those sort of things were at all in the table if you are exploring them that's number one?
And then number two on Florida, you know, there is an effort that seems to be gathering some steam. I mean there has always been effort to repel this nuclear fall of things but it looks like there is more of an effort that leads to the state Senate there, more of a concern about how that nuclear clause has been working. I was wondering if you could address that towards the larger context of your trackers. You know, there seems to be a little bit push back maybe on that and also we are hearing a little bit on 560 as well. If you could just give a little bit more color with respect to that?
So, I would say that everything is on the table. I just didn’t mention all of those, save a lot of energy efficiency programs and those things. So we have a lot of ideas right now. And I think the important part here is to have those discussions with our regulators, 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, I think, four senators introduced the change to this nuclear legislation bill that occurred back in 2005 the bill was signed, and we still believe that makes sense, construction work in progress for new nuclear makes sense to build new nuclear, I realize there are some concerns in Florida associated with that, but if you look at the advantage 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. And I think as time goes on in the legislation down there, I think we will work with them and I think they will come to the right resolution.
It seems that there is concern with respect to whether or not this play bill will actually come to provision. So, I guess some wondering is that how much I guess the risk is there in, if in fact worst case scenario which we feel that sounds like there might be some modification or whatever it is, any sense on that?
I can't speculate on what kind of --- how the bills are going to change.
Yeah sure but just in terms of quantification, in terms of how much is the stake with respect to that?
Yeah, in money.
A way to think about this we have collected $676 million from our nuclear cost recovery and we spent about $1 billion this is for the leading plants I think. That’s the question you are asking?
Okay. I’ll follow-up afterwards, I appreciate it.
And lot of the investment over the next few years will be in construction of new plants and modernization, where will the rate base growth come from in the second half of the decade through say 2020 and how should we look at the level of rate base growth over the second half of the decade?
So, I will start with it. You saw some key metrics on the environmental spent and we are, I think there is always an opportunity to spend capital. If you look at our company, we never seem to run out of opportunities to invest capital. I think that there are opportunities on transmission distribution to create a good modernization that haven't shown up yet, but we have lots and lots of projects where it makes sense to invest capital into the systems.
So I think everyone was looking, question is 4% to 6% earnings growth and how that translates to our ability to invest capital to grow that rate base? I think we are pretty solid believing we have lots of opportunities to invest capital whether it’s in environmental, whether it’s on the T&D system or whether you can continue to modernize fully for cleaner more efficient energy. I think there is plenty of investment opportunity there, thank you.
Part of the session this morning we will resume to 10:30 promptly.
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 and provide an overview of that area. Marc is Executive Vice President and President of our Commercial Business. So Marc?
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 segments, reporting segments, one is Duke Energy International and the other is our domestic Commercial Power and before I take those in turn let me do what others have done and you've seen the rhythm, identify the key takeaways which generally come in threes.
First we follow a low risk business model. What does this mean? We have operations that by and large are highly contracted in terms of the assets. Those assets are diversified by geography, by regulatory structure and fuel mix, and this diversity provides stability and growth of earnings as our track record has demonstrated which I'll get to. Second, the diversity helps support Duke’s financial objectives. We participate in growth markets in international and in renewable and with our Midwest commercial generation, we have strategic flexibility. Third, we do have challenges with our Midwest commercial generation but we are focused on what we can control.
As Lloyd mentioned we are pursuing a regulatory strategy to get our capacity costs and we are also controlling our costs which I will get into. Let me turn to Duke Energy International. It consists of 4600 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 Corporation based in Saudi Arabia. It's a joint venture with Saudi Company with the Sudanese company and with Duke. This investment has demonstrated very strong historical earnings and cash flows. It's typically contributed between 20% to 30% adjusted net income and we extended the arrangement through 2032.
Second point I’ll note which is as you will see in the lower right hand chart, our operations in Brazil, Peru and National Methanol typically account for more than 90% of total earnings DEI. Chile, as you know we invested in Chile last year. Its long been a target market for DEI and in July we purchased a 240 megawatt capacity play called the [Unghii] Diesel facility and then in December, we closed on two hydro projects that are completed $415 million will complete project financing for more than half of that shortly.
So, third point is DEI is positioned to self fund its growth and its growth, again consistent with the return and risk objectives. As of the end of the year, we had a balance of 1.1 billion in offshore cash and we continue to look for tax efficiently to bring the cash back to the US. 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, and let me start from the chart in the upper left. Compared to the US the GDP growth and expected growth in our principle markets including Chile that we just entered is higher than the US.
Now that leads as you go over to the upper right hand chart, we talked about anaemic growth in demand in the US from data we have which is now weather adjusted. Demand growth in US as even trended nationally below Europe. Look at the demand growth in Chile and Brazil and Peru and other Latin American countries greater than 4%. And what's the limit that demand growth. If you go down to the lower right hand chart compared to the US in terms of per capita consumption of electricity, these markets still have a long way to go to reach our levels of energy use.
And then finally, if you go over to the lower left, this chart represents what the net income of DEI has been over the past several years, a very strong performer 24% CAGR over that period.
Let me answer question that we agreed to take up today that came up from the earnings call and that is the drought condition in Brazil. This is a busy chart what it depicts is 12 years of reservoirs levels in the region where we have our dams and reservoirs, very critical southeast region of Brazil. The very bottom line is that I think it's red, it’s the 2001 reservoir levels and that was the worst drought year during this period for Brazil and life time rationing.
You can see what we and the industry was concerned at getting of December that reservoir levels for this year which are depicted in that blue front had obviously and completed the year was on par for 2001, and let me just remind you the rainy season in Brazil is roughly November to May, so the raining season was delayed. What has happen since then the rains have returned were above where 2001 was. As of now the reservoir are at about 45% of capacity and based on government of methodology of taking rainfall and computing it to expected reservoir levels by next months, we expect to be up to 55%.
So that’s the status on the reservoir levels we are watching it carefully. Lynn will discuss that because of the reservoir levels for our 2013 expected contributions from Brazil we’ve lowered with somewhat and obliviously we have upside if it gets to that other part of the curve and we have downside if it doesn’t continue raining.
Onto slide 50, overview of our domestic commercial power segment, it’s comprised the four separate businesses Midwest generation, Duke Energy Retail, Duke Energy Renewables and Commercial Transmission. A couple of points on each of these operations, the Midwest generation consists of 3700 megawatts of coal and oil fire generation and 3200 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, a third of that business in 2007 and we've grown it to 1700 megawatt, 1600 megawatts of wind and a 100 megawatts of solar and 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. And finally our commercial transmission business, there we are focused on transmission projects out of our service territories that basically integrate renewables with load or relief ingestion. We have a joint project of [AET] in the pioneer line in Midwest and we have a broader joint venture with the American Transmission Company to pursue projects.
Let me turn to Midwest commercial generation; make no mistake we are not satisfied with the financial performance of these assets, but the good news is it is a good set of assets and its well positioned the business to adopt to market changes and pending environmental regulations. All of our coal units with the exception of (inaudible) 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 and the whole 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 phase ESP, we still need more clarity as Lloyd indicated with respect to our cost base capacity filing. He has covered that; I won’t go into more detail. I will simply note that we will wait the outcome of that proceeding almost on our long term strategic decision about those assets.
This slide indicates that sort of the two approaches we are 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 and we focused in three ways. One, we manage 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 commodities to reduce volatility and to book economic margins.
Finally, just as Keith explained with respect to 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. They are focused 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, and as a result we've reduced our fleet O&M on a per megawatt hour basis by over 25% from ’09 to ’12. So these are good set of assets, we think they are 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. Let me turn to Duke Energy Renewables, as I indicated since our entry in 2007, we have brought this business to scale. We're very busy in 2012. We added 650 megawatts of additional net [out] wind and solar capacity, all within budget and all within schedule, although we came right to the end of 2012. And so today, we operate 1,700 megawatts in 11 states and we're now the fifth largest renewable generation producer in the US.
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 a proved based on her conservative (inaudible) rate with creditworthy counter parties. Each of our development, we work the documents, our project finance-able, and with respect to this growth, we have project finance over 1.4 billion of our growth and likewise we look for good joint venture partners to limit our CapEx obligation. Our first venture was with Sumitomo Corporation in 2012 and that involves two Kansas Wind projects with a total capacity of 300 megawatts. So as to renewables we will continue to pursue further growth opportunities, particularly in Solar, we would use the same approach. We won't do the project unless we have a long-term PPA that on basis of risk and returns meets our objectives.
So let me finish by summarizing our commercial business strategy. Again we follow a low risk approach with highly contracted generation assets. We have historically and we expect to continue to provide good earnings, cash flow and earnings diversity for the company and finally we are keenly focused on Midwest generation of generating good returns for that rate set of assets. With that I will open your questions.
I have got two questions. First on Brazil, obviously there has been a lot of news out there with regard to regulatory dynamics for those whose concessions are coming up for renewals, yours are not but you probably have some indirect exposure that as your hedges roll up in ‘15, ‘16, and beyond? Can you explain what's happening to the directly exposed companies and how you might be indirectly exposed?
Yes. And as you can imaging we’ve heard a number of questions about that and here’s our analysis and why we are 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 Act 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 offsetting the political context and election is coming up in 2014, so I think they need to be understood in that context. And now to get us as you mentioned we are directly impacted, the law applies concessions that were granted before 95 and are due to expire the next couple of years, all of our concessions were granted after that point.
And then finally on indirect, Lynn again will mentioned some of the things that lead to variability in our earnings projections for this year. With respect to Brazil we haven't reduced our expected earnings for the following and I included this data, I think in page 3 of the appendix. One, we are very highly contract, so for this year those assets are 97% contracted by 2015 they are still almost 80% contract, by 2017 they are still over 50% contracted. And as we can't go that contract prices, I am not going to give you the exact ones the proprietary, so we have an 8% growth in our contract revenues or prices from ‘12 to ‘15. So we think we are fairly well protected that being said, we are watching it carefully.
And my second question was on (inaudible) assets in the Midwest, for the same timeframe it looks like just based on what you are showing in the appendix that we should count on a fairly substantial improvement in capacity revenue?
That is our hope and I think we have included what the auction prices have cleared and as you know the capacity revenues in PGM for ’12 -‘13, ’13 -‘14 were very low, well below what we need for attracting new entry. They are going up the next two years still not where they need to be and again we are counting substantially on getting fair treatment with our capacity filing and getting the cost based revenue to the extent the PJM capacity payments don't severe our costs.
Give you the opportunity to get the, the question, but I wasn’t selected for the first one so. You know probably hand this off to Lynn, but you talked a number…
I'm going to ask Lynn to handle it.
What's the question?
Lynn, Marc mentioned a number of times terms like risk adjusted returns and returns consistent with your objectives and alike I would like to know more about what your objectives are that you are driving the meet?
Okay. Well, let me give you my perspective and you know my wet blanket at the first table will describe her objectives. But as you can imagine, we approached a number of projects, whether its renewables, whether its potential projects in Latin America and we go through elaborate process leading up to Jim, the treasury gives us a hurdle rate for the levered, un-levered cost of capital, we add a sovereign, adder, we had various other adders and we evaluate it.
So that's what I mean by risk adjusted and those hurdle rates and it varies by country, it varies by project we are doing and I'll say a word about Chile. Its 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. You know, we were able to get these assets in Chile consistent with our risk, consistent with our hurdle rates, luckily because some other people, particularly the Europeans were sitting on the sidelines. So Lynn doesn't let us get deal fever and bid more than the risk adjusted return would permit. And she’s either bemused or mad at me.
Anything else? Next is the main event, Ms. Lynn Good.
As you can tell what are the most popular things I do is establish cost of capital. So I would love to tell you more. But thank you so much for being here and as I look around the room and see how many people have already flipped fully through the deck, we have a lot of read ahead, I am just going to fill in the gap for you today. And what I'd like to do is cover of course our 2013 earnings guidance, CapEx and financing plans, our long-term growth expectations and finally our dividend policy. And I am going to begin as my colleagues have with the key takeaways from the 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. So as Jim mentioned, since 2009 we have delivered average annual earnings growth of 5.7% and dividend growth of 2% annually. And finally, our scale, diversity and strategic flexibility give us unique strength on which to build for the future.
With that backdrop let me start on slide 57 by discussing our short-term and long-term financial objectives. Today, we are introducing 2013 adjusted diluted earnings guidance of $4.20 to $4.45 per share with a mid point that's reasonably consistent with our 2012 actual results. As 2013 represents the first full year for the combined company, it's an appropriate foundation for future growth and therefore it is the base year for our long-term adjusted earnings per share growth range of 4% to 6% through 2015. Finally, we are also committed to growing the dividend; a very important part of our investor value proposition. We continue to target dividend growth within a payout ratio of between 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 and our regulated utilities offset by share dilution, lower results for Duke Energy International, and higher holding company interest expense. This guidance range reflects the potential variability and 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. First, 2013 will include a full-year of earnings from the progress utilities in the Carolinas and Florida.
Second, 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 rate should be an effect for Duke, Carolinas in both North and South Carolina.
Third, we expect weather normalize retail load growth as well as continued growth in our wholesale business due to new contract. 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 way the strength of the economic rebound and the impact of energy efficiency on load growth trend. Since our projections assume normal weather, we also expect additional customer load since 2012 weather was below normal.
Fourth, we are planning lower O&M as we realize merger savings, and 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 accepted the voluntary separation plan has 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 the merging costs to support our nuclear fleet.
Finally, 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 invest the capital at this site during 2013. We also expect to fully realize the remaining balance of cost 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.
Next, 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; first, the effective favorably 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 for the $0.03 EPS impact.
Second, the impacts of lower than normal rainfall in Brazil which Marc discussed earlier, even though conditions have recently improved, we will continue to monitor development and their impact on generation, dispatch and energy margins for the balance of 2013, and of course we will continue to update you on these developments as the year progresses. And finally, lower results in National Methanol due to lower commodity prices.
Next is 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 reflect the continued lower 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 the 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 or results from the full year impact of incremental shares issued in connection with the Progress merger.
And finally, we expect an increase in our adjusted effective tax rate from 31% in 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, 2012, 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 have been closer to $7 billion. Compared to the proforma amounts of $7 billion, CapEx will trend down modestly in 2013 as we complete several major construction projects with FE&G and in our renewables business.
Over the three year period from 2013 to 2015 about 85% to 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 to $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 on the appendix of my presentation.
Slide 60 demonstrates how the capital and 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 amortized 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 would expand from about $45 billion at the end of 2012 to about $50 billion by the end of 2015. This represents the compounded annual growth rate of 4%.
Moving on to slide 61, let me talk through our credit profile and 2013 cash flow assumptions. We remained committed to maintaining our strong credit ratings and liquidity position. Our business plan and credit metrics continues to position the company well within our ratings category. 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 payment 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 guideline.
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 this slide, these issuances are expected to include around $2.1 billion of first mortgage bonds at the various utility. 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 objective to grow earnings 4% to 6% off of previous state year of 2009. This steady growth is even more apparent when adjusting for weather, as shown in the grey portion of the bars.
As we look ahead through 2015, the primary drivers supporting our continued 4% to 6% earnings growth rate include the following: Average annual regulated rate base for us 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 and integration savings and continuous improvements, 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% to 2%, disciplined growth in our international business with effective cost control and operational efficiency and finally benefiting from the recovery at 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 contain pursue growth opportunities in our renewables business. We are well positioned to achieve our earnings growth objective 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 that 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 payment. As 2013 is the 87th consecutive year Duke Energy has paid a dividend on its common stock. Since 2009, we’ve run our dividend by about 2% annually. We expect to continue increasing the dividend annually targeting a long term payout ratio of 65% to 70% of adjusted diluted earnings per share.
In summary, we are well positioned to achieve each of our objectives. We expect to achieve the 2013 adjusted earnings per share of between $4.20 and $4.45. Our low risk business mix supports growth and earnings and the dividends 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 the day, you’ve heard our plans to focus on the fundamentals of the business, operational excellence, customer satisfaction, financial discipline and constructive regulations. As Jim said, these are the blocking and tackling that every utility must do well. But we believe Duke has unique strength, such as our size and scale, our diversity in generation and geography, our fuel and joint dispatch savings for customers and other merger synergies provides unique platform to drive more efficiencies in how we do business. Additionally, we have strategic flexibility with our commercial platform. Our entire management team is very focused on achieving these commitments and helping us build upon the track record of continuing to deliver our promises to our stakeholders.
So at this point I am going to ask the rest of the senior management team to join and I will take questions as we gather here on the stage.
Okay. We are in the home stretch guys. Moving to have a brief moderated panel with our senior management team, but before I introduce, we have the 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 who do not know who I am, Bill Currens, Director of Investor Relations with the Company.
As Jim mentioned in his opening, we’ve got a very experienced and talented team up here. And 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. But let me start it off with just a brief introduction of three individuals and I'll 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. So all things Ohio are here for Julie. I'll 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 are going through bringing the companies together and making sure we are after all the synergies that we promised to you as well as to our regulators. And we also have Jennifer Weber who is our Chief Human Resources Officer. I'll probably be seeing her tomorrow as well.
So let me start it off with a very high level question just to wrap this up for Jim. Jim 25 years as a CEO in this industry it’s remarkable, great track record. I know you are very proud in terms of what you delivered. When you look back over those 25 years what are the things that have surprised, what are the challenges that you encountered and what type of lessons learned could you give all of us?
[Technical Difficulty]……working. How much of that did you all hear? A little. Well, I've been delighted to be a CEO for 25 years and especially in this industry. And the real lesson if you go straight to the lessons are these, I saw a slide about Jeff Holzschuh of Morgan Stanley not long ago that pointed out that when I joined the industry in ’88 there were over a 100 utilities in the United States, electric utilities. Today there is about 50.
So I have been here during a period of great consolidation. I have had the good fortune of working to do three consolidations and each has been challenging in their own special way. The first one and everyone of them has created greater earnings growth as a consequence of coming together because our cost structures have been reduced and its the accommodation itself produces savings and it also provides a catalyst for even greater savings and that's where we sit today with a combination that we just did with Progress.
As I said earlier, it’s critical to change our cost paradigm for the next five years to 10 years and this combination will help us achieve that objective. The other thing is that I clearly see the value in different regulatory regimes. So all your eggs are not in one basket as they were for me back in 1988 for the assets were just in Indiana because commissions I have seen over the past 25 years changed in terms of constructive they are.
Some states, it has been very consistently constructive but not always and you this from looking across the country to the changes that have occurred. The other thing I've realized is the importance of having great relationships with regulators. And we are really working hard to have no surprises type of relationship with the regulators through the period for the last 25 years that's been kind of one of my hallmarks.
And I have a great confidence that Lloyd with his relationships with the presidents of each of our states are developing the type of relationships that really allow us to be successful in the future. And the bottom line is this business is a good business, if you have steadily grow earnings, grow the dividend and you have produced 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. And that's what we will continue to do going forward and you had a great opportunity to listen to some of our team today and now you have an opportunity to listen to all of them. And as I said in 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 whatever thing was going on, we still delivered and that’s what matters, that's what matters to you, that's what matters to all of our investors and that's what matters to our customers. And if you keep that in mind, I think that's the way we will be going forward. I'll stop with that. Thank you.
Great transition to the next question that I would like to post to Lee. Lee, Jim mentioned changing the cost paradigm and delivering on our commitments, that's a large part of what you have 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. So first when it pertains to merger savings the focus area on our fuel savings is paramount. Keith mentioned this morning $687 million of effective savings over five years. We've got a pretty 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 are well underway with 65% of that savings under contract and the remainder on target to hit the joint dispatch value. Then if you move over to our non-fuel O&M savings, Lynn mentioned close to 700 initiatives. So these are projects large and small, each one has been assigned to a specific owner [Technical Difficulty] The panel unfortunately except for Jim you have the leadership work, so if we get the microphone back over to Jim for make sure everyone else is niced up. Let me ask just one other question and then I want post this to Jennifer before I know several of you have questions.
Jennifer one building on the merger one of the critical aspects of a merger and I think one of the pieces it 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?
That's a good question Bill and you are right this is often an underestimated area of focus for companies going through a merger of our size and scale, and so our senior management team decided that we needed to place an emphasis and a focus on this mightier work. So we began work in October engaging a broad cross section of our leaders across the company to get clear definition around the kind of performance culture that we need to have in place to accomplish a lot of the business objectives that you heard our leaders articulate this morning and so in the same way we think about our industry evolving. We think about our business model evolving. We think about new regulatory framework.
We've got to ask us the question how do we need to evolve our performance culture. So one thing became very clear and you can get intentional about this and I think that's one of the things that companies often miss is that you can and should get very intentional about defining this.
So one thing that became very clear was that our leaders had a shared view and a consistent view of a cultural attributes that we want to strengthen going forward and I'll highlight some of those.
One was a culture of high trust and this is being viewed as very foundational to another attribute that was mentioned and that's high accountability, so effective accountability across the company. Another attribute that was mentioned was innovation. So if you think about the way our industry is evolving you heard Lee mention this as well, its going to require us as a company to innovate, think about new ways of doing things, think about more official ways of doing things and then the other attribute that was mentioned is a culture and this is very, very related to the definition of performance culture of high accountability, high accountability for achieving superior business results, high accountability for operational excellence and so those were some of the things that were mentioned.
We are in the beginning stages of this. We intend net week at an Enterprise Leadership Conference when we are 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.
Unidentified Company Representative
Described a great deal of CapEx and rate based growth and I am wondering what the rate impact to customers is and how you balance that over the next three years particularly if you are filing a bunch of rate cases now but then not filing in ’14 and ’15 and then also when you detailed growth in wholesale (inaudible) just wondered what that is and then finally Jim if you could talk about strategy for Ohio, is the capacity ruling does not go your way?
The customer will impact Lloyd shared with you specifics on the pending rate cases the Progress and Duke rate cases so we filed for roughly 10%, the settlement and the Progress case, it's going to be 4.7% year one, growing to a total of 5.7% end of year two. We're very conscious of maintaining those billing pack increases at a level that make sense for our customers and as we look beyond this current set of rate cases, we're going to be leveraging opportunities to merger savings and cost control to mitigate price impact as we look for ways to deploy additional capital under our jurisdictions. So 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, in extension with MC EMC and the eastern part of the Carolinas and one with the Northern (inaudible) in South Carolina. Lloyd, would you like to add to that anyway?
So back to MC EMC contract is a significant contract we signed last year, 20-year contract that goes from a 1,000 megawatt to 2,000 megawatt, grows 2,000 megawatt to a little over 20-year period. The EMC contract signed with Duke Energy Carolinas rose from 150 megawatts to 1,000 megawatts over an 18-year period. So if you start to look at the opportunities for wholesale growth earnings that's what defining the numbers that Lynn talked about earlier.
Since Julie built it, all things Ohio, I am going to ask her (inaudible) to start the answer with her perspective because she has been very engaged in most recently becoming General Council.
I need the mic. So I appreciate the fine introduction from Bill and Jim with respect to my past in Ohio but I think it's probably best that I stick to my legal entity. As it relates to the capacity case and so we really believe we have a strong legal premise for a successful outcome in the capacity case, what we heard from interveners primarily was that we have already received our compensation for capacity through our electric security plan and that is simply not accurate, because it's been not to get too granular until Ohio Law with you but Ohio Revise Code Chapter 49, 28 which provide for the standard service offer framework within the State of Ohio is one that provides for the provision of competition retail electric service.
It goes into depth about whether its provided to an MRO or any SP and in fact it's prescriptive about what can be contain within an electric security plan and electric stability and service are of course one those many factors. It does not provide for the provision of capacity costs through the chapter and quite frankly, it could not has been provided for through our ESP and was not. The other arguments that interveners make that this is somehow already been settled and whether that in a (inaudible) or collateral that too as you all know our electricity security plans matter was not litigated and it was a settlement and quite frankly the AEP capacity case and their ESP case were very separate as are ours in the system.
Unidentified Company Representative
We are cautiously optimistic about Ohio but at the end of today we don't get the results we want, so we review our strategic options with respect to those assets.
Hey, I think in the last few days we had the board flush out its nice members so now the super committee is completely filled out. Can you talk a little bit about now that super committee is completed, what are the next steps that will probably happen in the course of succession planning?
Unidentified Company Representative
The board has retained their consultant to work with them and what they are doing is going to a very thoughtful process to identify successor. They have started on this even before we added the last director and this process has been as you know the most important thing the board does is select a CEO, it's probably the thing that they are most careful about, and that is why this process is going to be very thoughtful.
They will take as much as they need to do that, and as I said in the earnings call, they will both access internal candidates as well as external candidates and make a decision with respect to see 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.
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 and US P&G in terms of how much of that O&M might be clause related, percentage terms are fine?
Clause related, clause related. So 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 to $700 million annually but I would 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 mike passed around. Dhiaa I want to follow-up on your presentation. You highlighted a lot of capital and O&M requirements related to performance improvement in Fukushima just in terms of clarification. Are those your costs that you estimate across the entire fleet or are those specific to particular units?
Thank you, Bill. Let me start by emphasizing that all of the rules associated with Fukushima they are not completely known and they would be known in time. So what I share with you is our best estimate based on what we know today. We anticipate over the next three years to spend approximately $500 million in capital and $100 million in capital in O&M for the entire fleet, that is for 12 units, 11 operating and Crystal River to cover things like the [coping] requirements with natural phenomena for the BWRs which we have only two that includes hardened vents but not these filtered hardened vents. It includes better instrumentation for spent fuel cool water levels for the entire 12 units and better emergency response, some indication equipment for the entire fleet. So it’s really comprehensive for the whole fleet. Michael next?
What's the landscape of utility mergers over the last five or 10 years even maybe even longer term than that? We've generally gotten actual reductions in non-fuel O&Ms. I look at the merger that happened in the New England area, talking about 3% actual reductions in non-fuel O&M, a different company but if you look at the merchant merger between Exelon and Constellation you actually got very sizeable, 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 are talking about what's the growth rate in about 1% to 2% range versus an actual decline rate.
Michael we are going to be in negative O&M between ’12 and ’13. So lower O&M and you will start to see our merger synergies kick in and impact and we are targeting 1% to 2% over the three to five year periods. 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 and then of course we have pension benefits that has continued to be an inflation driver for many companies us including.
So 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 loaded growth environment, we believe cost control is absolutely essential and we will be making this decision to spend money, balancing the need for efficiency with the need to continue to invest in our assets for the future and so we’ll continue to keep pressure on cost and I actually think in this environment, an [aspiration] of 1% to 2% harvesting the synergies and working hard to change the cost paradigm is a good target for us to start with and we would 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 for 4% to 6% of ‘13, your earnings power of rate based was quipped as you sort of articulated your rose by 4% a year to 50 billion plus or minus ’15. What are the big drivers that could get you to six 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 or is it that you are expecting a lot of growth in commercial opposite international? How do we bridge to sort of a base case of 4% to 6%?
I think the drivers you talked about. So, I think we had a modest load growth expectation. So that would be a positive. Wholesale would be another positive. Additional capital spending, if we can find great ideas and great modernization and other things, we continue to look for opportunities to deploy capital. And if we can do a bit better on O&M, challenging ourselves to trend it down even further than the one that present that represents growth. And as I look at ‘13 to ;14 with a variability we are having this plan in ‘13 on all of the rate case outcomes, state base capacity, cost control and other things. I think you begin to see that we have a range of variability in ‘13 specifically as a result of these spending proceedings.
Just one follow-up, so in the context of that range when I think about 4% to 6% and obviously been in many jurisdiction to be average expected earned ROE from ‘13 to ‘15 is there an assumption that the base case is that stable on return or growing on return declining on return?
I am sorry I really had a hard time.
So you think about the weighted average earned return on equity that represents the base case sort of mid-point of that growth rate is that a stable return across the forecast period a growing return or a declining return in sort of the base case?
I would think about the Carolina’s as being kind of 10%ish range with cost control and rate cases driving us up and additional capital expenditure potentially driving us down. So I would think about in this environment around 10% for the retail return, we have the ability to do slightly better than that when we introduce wholesale. And the Carolina is where I would focus Greg on the material driver.
Jim I guess may be two questions; one Jim, can you talk a little bit about your views on carbon policies you got along (inaudible) administration and kind of where you see (inaudible) and kind of how it effects of long term money for Duke at this point?
First I think there is a very low probability that they will be apprised on carbon coming out of Congress, in this section on Congress and probably the next session, and I think pretty obvious why that is true. I think the big issue is what the EPA does. I believe that we have level capability to regulate CO2. I believe they will try, I believe they will end up in court, it will go to a four year battle with respect to their capabilities, but I do think eventually there will be a price on carbon and that's why we’ve taken the actions we had.
We try to be ahead of the curve with this $9 billion modernization program is allowed us to retired these plans. We are reducing significantly carbon footprint to 20% plus this year probably by the time we complete the modernization program almost at 30% reduction in our CO2. So we’ve reduced our exposure to increases as a consequence of the legislation, our potential legislation with respect to it. But from a EPA standpoint, it will be a long battle, a tough battle, long place to try to pose a price on carbon.
Yes, you had may be two capital allocation question didn't come up today. Number one involving the ability to repatriate cash outside of the United States in to the US and are they any tax schemes that go along plus the merger will allow you to do that, and then secondly the potential investments in (inaudible) which got attention a while a go and why its permitted.
We stay very engaged in the discussions of tax reform and we are active in 2011 and 2012 around potential repatriation. And we will continue to be so as tax reform is taken up this year although we are not hopeful. We also continue to look for structured ways that we can bring cash home and that will be a priority in 2013 as well. And I think we always maintain the strategic flexibility of just flat out repatriating and 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. And your question on [DC] Summer, Dhiaa 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 [DC] Summer.
Yeah, in the past you guys have talked about the idea of being a potential partial investor in the plan, I wasn’t sure where that is going and whether this could mean something for us.
Yeah, so as you know of course that we signed an LOI back in 2010 for 5% to 10% of Santee Cooper’s portion of the plant. We've been performing due diligence ever since and we have not come to acceptable terms. We have allowed the LOI to expire end of last year but we have continued to negotiate with Santee Cooper to try to come up with the right terms, that's where things stand right now.
And as you have questions please raise your hand, we will make sure to get the mike to you. [Paul].
I wanted to sort of follow up on Brad’s question with earnings growth and what have you, first of all the 4% to 6% base of course the midpoint as I understand is 2013, is that correct?
Okay and then when I'm looking at the rate based growth it looks more like from that period on its more like a 3% lower. So what I'm trying to gather here just to sort of understand it more it would sort of imply, well obviously there's some growth obviously in commercial and what have you. How should we think just sort of how do we quantify the improvement in return 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 returns.
Paul, you know a similar question here and I'm a bit of a range of ROE. I think its going to be important for us to complete our work on pending rate cases. We are asking for additional recovery in the Carolina, those rate cases are not behind us and so as we look over the period it’ll be a matter of reaching returns that we are expecting on the additional investment that we are pursuing right now and then we will be evaluating whether or not we need to go into rate cases probably after 2015-2016. The lever that we have to maintain our returns is cost control which will be a continued focus and so I would think of us in the 10ish range. We have an opportunity to go slightly above that perhaps over the period but beyond that that's what I would share at this point.
Okay, then I guess Jim as you are beginning to transition out any significant change in the makeup of the businesses prior to the collection of somebody new or just any thoughts as you are exiting, should there, I mean I would assume that they probably want to be that bigger change, just any thoughts that you could throw (inaudible).
Well, it’s really a Board decision in terms of the businesses that we pursue. It’s all in the annual basis with our Board to review, for instance, DEI. We review the Midwest generation. We reviewed the renewables business. We reviewed the Midwest Gen, we review all these things annually and one of the questions we always asked hold them or fold them with respect to those assets and that is just part of our process. And so to-date, the Board believes that the renewable business makes sense and produces good returns for the appropriate amount of risks. They believe that the DEI makes sense, given the fact that it produces significant amount of cash and it has been on the great growth trajectory.
The Board continues to believe that the Midwest asset makes sense especially in the context of being able to get a capacity payment in Ohio. It's really open question, as I said, answers Leslie’s question. We’ll have to review our strategic options depending on what the result, if we get a negative answer from Ohio. So I believe that we've a strong Board, they have clarity in terms of the direction of where our industry is going and I don't see significant changes occurring in the direction of the company as a consequence of a new CEO. Maybe, because every CEO has his own view of the future, but our Board is strong, large. It has great clarity in terms of where we're going.
Before going to our next question here in the audience let me propose a quick question to Mark. So Mark you talked a lot today in your presentation about historic growth in countries in Latin America where we have operation and projected growth in excess of what we are 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 have done in Latin America and by the way if we get higher prices we are not going to turn them down. But it's consistent with our strategy; our entry into Chile was consistent with the strategy. We’ve allocated to the international business over the past several years a modest amount of growth capital. I think as I intimated we’ve either backed out of projects because they didn’t meet our objectives or we got outbid on some projects and we just happen to hit the mark with the two projects in Chile. We’ve gone back and added up the cumulative amount over the past four, five years of growth capital and we haven’t exceeded that. It just came in a lumpy fashion in 2012. So now I hope it grows through price increases and other things and demand growth, but we are not making any strategic pivot.
Question here from the audience?
I have a few follow-up questions Jim from your additional remarks at the beginning of this conference. One is on solar, I was a little confused as to whether that sort of positive or negative for you and maybe you can clarify that superficially for Duke how the solar industry is playing out and how is that positive or negative for you guys. And then other specific is on the natural gas part of your generating capacity, in an idea world looking out as a long term investor which I assume you’ll always be at Duke, how high would you like to see that get as a percent of your overall makes looking out 10 years and beyond. And then lastly I know these are all subtle questions, but talk a little bit more about why growth is slow from a secular point of view, some of it is conservation and efficiency and some of it is slow economy. But let's assume for a moment that the economy really start to pick up and gain real traction 4% GDP?
Well, it’s sold and I think it’s both the positive and the negative and 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 and utilities could not invest in the renewable that they bought. This would have precluded a huge investment opportunity for us at anytime a law passes it then 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 didn't happen, we started the renewable business and we have 1700 megawatts today producing higher returns than from some our regulated business primarily driven by how we financed it. So we took preemptive action in the events we’d be precluded from that investment.
With respect to solar on the roof top, we are looking at the possibility of pursuing that kind of business; all are renewable sales have been utility scale primarily because that's where the greatest opportunity has been. So if we are preempting on this we could turn it from a negative to a positive.
The negative aspect of it is that 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 are some very innovative companies that will put it on for free to kind of buy down your bill over time because of [tiering] rates in California and so that is really cut into (inaudible) and so the California Edison slowed that they have had to provide.
So I don't think we are immune from that even though our rates are significantly lower than California significantly lower than the national average. If the tiering of the rates change, that exposes us and so I think 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 us put in a place that's not a good place because the strength of the power sector today is in all of our 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 are in. For instance, our Midwest assets are probably always have a higher percentage of coal than they will nuclear. Our Florida assets will probably have a higher percentage of gas but as an overall organization, we are kind of moving to a place where we will be almost one-third coal, one-third gas and these are rough numbers and probably one-third nuclear and renewables.
So that's going to be the mix that I see for our company and that's kind of a pretty balanced position to be in but the biggest challenge to us is simply the challenge of avoiding all gas all the time. You have a third part to your question on the economic recovery and load growth.
Just bouncing the sort of pressures that you've eluded to I mean if you had a 4% GDP growth kind of economy sometime in the future would you be less concerned about your secular growth or these other factors really holding down load demand?
I'd say that the recovery from the recession for the economy has been very anemic, historically the growth and 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 of electricity. If you get to the 90s for every 1% growth in GDP there was a 1% growth in the demand for electricity and most recently it’s fallen to about four-tenth of percent growth in electricity for every 1% growth in GDP. So as it’s a kind of and that's a function of the energy intensity of our economy changing.
And so we're at place where I believe the demand will grow. New homes, new businesses, I mean as we said earlier, North Carolina is the number two state in the country to do business. So, that's important. Indiana is at the top of the list. It just passed the right to workflow in the Midwest, the only one.
Ohio is improving as a business environment and there is a lot of residential growth in Ohio, I mean in North Carolina primarily as they call the half back phenomena. People from New Jersey and New York go to Florida and either don’t like the prices or don’t perfectly like the weather. So they move back to, so they go all the way back to New York and New Jersey. They stop in North Carolina. That's where they retire.
So we're seeing growth really from that. While at the one hand there is some positive things pushing growth up and making us feel better about the growth in demand. There is also some negative factors like the solar on the rooftop, like the technologies and I’ve spent a lot of time in Silicon Valley. I have met with a lot of new technology companies and it's crystal clear to me these are developing technologies that will translate in significant reductions to the demand of electricity.
I mean in Charlotte, we have a project now called Envision Charlotte, where we committed to try to reduce the demand and all of the other area by 20% in five years. Projects like that are going on all across this country. So again, I feel probably more of sense of, I see the positives, but I see the negatives. Now we have both of them, I say let’s get prepared for what could be from a growth standpoint or worst case scenario and that means taking action on calls changing the regulatory paradigm, those are critical things if we need to do to be prepared in the event the worst case from a demand growth standpoint becomes a reality.
Another questions do we have from the audience. Somebody raise their hand?
Lynn, I wanted to clarify on Ohio, could you just remind us as what you have asked for the capacity if you do get it, how much increment is that and if I recall correctly in your commercial power ‘13 assumptions, which you have them flat versus ‘12, 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 assumed in there for ‘13?
So what we have filed for $730 million for the period of August of 2012 through May of 2015 versus a period that Duke Energy Ohio is an FRR entity. So we are not sharing with you today our specific planning assumptions, we are in the midst of a negotiation, the hearing on this proceeding due and occur until April. But what we have included in the range of 420 to 445 is a variety of assumptions and scenarios that could play out in the State of Ohio. So there is an assumption when you look a commercial power being flat, it's a midpoint, there is an assumption of a level of recovery but I am not going to show the specifically with you given the status of the proceedings.
Okay, fair enough and my second question just wanted to clear, I think for ‘13 you have been very explicit in assuming no new equity issuance, is that true for the entire ‘13 through ‘15 planning period or could that change?
Yes it is; no equity for 2015.
Unidentified Company Representative
Let me ask a quick question as we give the microphone pass to the next audience participant. Just to Keith. Keith, a lot of the cost of the business sits within at the FE&G regulated operations, you talked about moving from fixed to variable costs and taking a critical look at the coal fleet, where are the things that you want to challenge your team in terms of changing the cost paradigm with the regulated fleet operations?
So I start with bit of a track record, you know, our teams have done a very, very good job in this front on managing O&M. If you look 2007 to ‘10, we kept O&M relatively flat during that period. Last year, early in the year, we were experiencing poor weather and so we made O&M adjustments accordingly. So, I say that we got a track record of dealing effectively with O&M.
So on the coal fleet in particular, I talked earlier about the fact that it’s not running as base-load and quite frankly we are not projecting that is going to run as base-load for fairly extended period of time. What we are doing, we are exploring opportunities one where we can reduce minimums at the coal plants, so that we can create some operational flexibility on that front.
So beyond that, we are really looking at more transformational things and there's a menu, we don't have that menu defined yet but some of it could involve going to seasonal operations, some of it can involve having more traveling crews to reduce work force. So there are a variety of things that we are exploring.
I will tell you that there's nothing like a sense of urgency to drive good outcomes and Mark talked about the work that was done on the commercial generation fleet in the Midwest. I was involved in that operation earlier in my career and at one point we challenged the teams there to try to hit a certain variable O&M mark and the reaction we got initially was you know we don't really think we can do that.
But we are now way below the mark that we initially set for the team. So I think a part of it is creating a sense of urgency which I think we can do, part of it is being innovative and creative and I think the team is showing that it can do that. One example I'll give that does not exactly but it’s related and that is the fuel blending. We have found a way to do more than the team saw they could do. So I'm confident that we are going to be able to change this but to Jim’s point, we've got to change the cost paradigm and we will do it.
Thank you. First I want to say that I've been an observer of this company for more than 25 years that Jim referred to relative to him being there and I think you've, its 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 and you can only go so far as you all work hard and produce good results. Jim started the presentation by talking about anemic load growth, he just went in to additional comments on the same theme and 1% is on a relative basis pretty anemic and it’s not going to produce great opportunities regardless to produce great increases in earnings but that it is what it is.
Having said that I'm questioning fuel and I'm questioning in particular gas, Wall Street Journal has a very optimistic story today about gas, about availability of gas and how much gas we are going to have nationwide over a long period of time. Is anyone offering you gas on the contract for long periods of time and if not have you tried to get it and what are the prices and is the hedging that Lynn referred to earlier, is that good enough or can you be locking in lower prices for gas for longer periods of time.
So in terms of long term contracts, I'll tell you historically the EMP companies have not been that receptive to longer term contracts, but that is changing to some degree and so we have considered some opportunities on long term gas. Again before you do anything like that you need to have your regulators right beside you, and so its early days on that front. But I think there are opportunities that are emerging and I think the place there, where it may make the most sense are the areas that are more and more dependent on gap.
So Florida as an example, with the Crystal River 3 retirement and then the potential retirement Crystal River 1 and 2 and ‘15 to ‘17 timeframe, you are going to get in to a place 75% dependent on gas. Well in that kind of environment, it very well may make sense to regulators, the customers and to us to look for long-term type agreements and there are different ways that you can structure that and I think there maybe ways to structure it so that we can actually generate some earnings on that. So a lot of ideas going on but that will be part, this will be part of the innovation that I think we are going through right now at the company.
I have three or four questions if I can address them in to different members. Jim, first of all, is it starting up? First question, the performance of the company has been excellent over the last three years as you mentioned and congrats to you and your team. Now one point which you mentioned in your remarks at the beginning was how the utility universe went from 100 different (inaudible) top of the tier right now. As we go through the next five or six years, do you think this is going to be further M&A the group, and the other question would be if 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 because I am a true believer that building a strong company two 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. So if I was making a recommendation to the Board to the new CEO, my recommendation would be look for opportunities. I probably wouldn’t do one in the region, I mean given our experience with the FERC and three trials before got it right as far as they were concerned. But I would look for opportunities to combine and to really strengthen the company going forward because that’s just one way to create growth in the future.
Then just going to the integration Jim. I guess you mentioned there were like (inaudible) you having a meeting next week 400 top leaders are going to be there, but give us a break out as you stand here out of those 400 how much are the old Duke and old progress what is the combination if I get a sense?
It's actually a blend of legacy Duke leader and legacy progress leaders. It includes all of our (inaudible) so it includes a blends of two companies our direct reports and their direct and then a level below that. We think given the news we are sharing today, given the visibility we are giving this community and to our strategy going forward now growth objectives we are going to do an even deeper dive for our top leaders then we are going to translate that into our expectations for them as leaders of the company. We are also trying to put our leaders in a position of being able to articulate, our focus and our priorities as the combined company and we are more engaging them on this topic of culture.
Okay, what I was willing to, could you share with us what the percentages, how much is percentage is the Legacy Duke versus?
Sure, I would say in general the percentage is about 60-40 to 55-35 in terms of the split and if you look at that in terms of the overall contribution and in terms of the employee count as we merge as a company, its pretty well representative of that.
Okay, and Keith I have just a question on the regulated side of the stake on combining these two companies. What are the key challenges apart from the rate cases in terms of your job, as you are looking to forward for the next year or two?
Yes, one of the key challenges is really as O&M world that we are in, right and we’ve talked about that and that’s really where we focused on in large measure and it’s a hard focus on the coal assets is the challenge. But we are working through that. The other piece of this is, we are bringing two teams together and like Dhiaa said we have great leadership from the progress side, great leadership from the Duke side and they have come together very, very well. But the biggest single challenge is going to be how do we address this new O&M world that we are approaching.
And if I can end up Lynn, one thing which you have is kind of the different growth rate is pretty anemic, most companies have growth rate which are more parallel to the EPS growth rate going forward. When does the cycle change or is it just going to be like the growth rate that the dividend is going to be just half the growth rate of the EPS and I am just trying to get a sense as to when can the dividend start increasing at more rate which is equivalent to the EPS.
That's a good question, I guess the dividend as you know is very important and growth of the dividend is very important. We've been managing the dividend growth within the payout ratio of 65% to 70% and see our way to getting within that ratio in the next year or so and I think when we are positioned within the payout ratio then you could expect the dividend to have the potential to grow at a higher pace. So we think that discipline around dividend growth has been important as we've been spending so much capital for modernization and its been a trade off that we thought was appropriate, but our commitment to growth is I think the dividend is very important part of the value proposition and we think over time there will be an opportunity to accelerate growth of dividend.
Okay, let's look for one final question from the audience. Okay, we are past lunch time. So 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. But because looking at the age I mean some of you couldn’t have been in the industry 25 years ago.
But the reality is that this is a great industry to be in. I mean I wake up everyday 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. We could be a better industry to be in for energy and environmental policy and I think that probably the most important thing is I get satisfaction out of working with strong independent minded leaders like the team you see sitting here on the stage. We are getting ready to change our logo and I think it just has popped up on the screen. So that's kind of a symbol of what we are going to be in the future.
It will be a little change in look, but it also reflects collaboration, it reflects the recognition that we have to continue to work to reduce our emissions. I mean environmental issues have been a issue, been key to me and important part of my legacy going all the way back to 1990 when I was the only CEO of the industry to support Clean Air Act amendments with respect to SO2. So we have come a long way together. I have produced strong results for you all. I've done my best and look forward to seeing you in my next life. Thank you all very much for being here today.