Duke Energy Corp (DUK) 2012 Q3 法說會逐字稿

Good day and welcome to the Duke Energy third quarterly earnings conference call. Today's conference is being recorded.

At this time I like to turn the conference over to Mr. Bob Drennan, Vice President of Investor Relations. Please go ahead, sir.

Thank you, Shannon. Good morning, everyone, and welcome to Duke Energy's third-quarter 2012 earnings review and business update. Leading our discussion this morning are Jim Rogers, Chairman, President, and Chief Executive Officer, and Lynn Good, Executive Vice President and Chief Financial Officer.

Today's discussion will include forward-looking information and the use of non-GAAP financial measures. Slide two in the presentation package presents the Safe Harbor statement which accompanies our presentation materials. You should also refer to the information in our 2011 10-K and other SEC filings concerning factors that could cause future results to differ from this forward-looking information. A reconciliation of non-GAAP financial measures can be found on our website and in today's materials.

Please note that the appendix for the presentation materials include supplemental information and additional disclosures to help you analyze Duke Energy's performance.

Slide three details the topics for today's call. First, Jim will provide an update on our key priorities and Lynn will review our quarterly financial results. After these prepared remarks, we will take your questions.

The management team of Duke Energy will host an analyst meeting in New York City in late February. During that meeting we will update you on our strategic goals and our progress in resolving our near-term priorities. At that time we will provide our 2013 earnings guidance range and related assumptions, including our long-term earnings growth rate expectations. More details on this meeting will be distributed shortly.

Now I will turn the call over to Jim.

Thank you, Bob, and thank you all for joining us today. It is our first call to report on the consolidated financial results of the new Duke Energy.

As a combined company we are off to a great start. The third-quarter results reflect our efforts. We are pleased with what we are already accomplished and the positive momentum we have created.

The work of our employees has been outstanding. As the two companies come together, we continue to focus on our mission for customers and that is providing affordable, reliable, and increasingly clean electricity on a 24/7 basis. We are focused and we will continue to meet our merger commitments, achieving synergies and savings for both customers and investors.

Today Duke Energy announced adjusted diluted earnings per share of $1.47 for the third quarter. This compares to prior-year quarterly earnings of $1.50 per share. Once again we exceeded Wall Street consensus estimates.

In the quarter we continued to realize the benefits from our fleet modernization program despite less favorable weather and more results at our non-regulated commercial businesses. We are positioned to finish the year within our targeted adjusted diluted earnings guidance range of $4.20 to $4.35 per share.

Before going further I would like to say a word about Sandy. We were saddened by the loss of life and enormous damage caused by this storm. We were very fortunate that our service areas were spared the brunt of it.

We have quickly deployed contractors and employees to assist other utilities with restoration. In total, we sent over 2,900 workers to help in eight states from Virginia to Connecticut. I deeply appreciate the commitment and dedication of these workers, most of whom are still working to restore service in New York and New Jersey. It is an example of how our new scale and geographic scope have made our storm response capabilities even stronger.

Since merger close we have been focused on five key near-term priorities. First, resolving the North Carolina Utilities Commission's investigation into the post-merger change in leadership and achieving successful outcomes in our rate cases in the Carolinas. Second, achieving merger savings and efficiencies and successfully integrating the new company into a stronger, more efficient organization.

Third, completing the work necessary to determine the way forward for the Crystal River 3 nuclear unit in Florida. Fourth, putting the Edwardsport IGCC plant into service and receiving approval of the associated regulatory settlement in Indiana. And, fifth, our ongoing effort to optimize the performance of our nuclear generating fleet.

Over the next nine to 12 months we expect to resolve many of these priorities while making substantial progress on the others. For example, successful merger integration and optimizing nuclear performance will be ongoing priorities beyond this period.

A word on the status of the North Carolina Utility Commission investigation. This investigation is ongoing and we are maintaining open communications with the commission. We will continue to keep you informed on this ongoing matter.

Next, let me turn to the slide five. We are nearing completion of our $9 billion fleet modernization program. This will position the Company to comply with more stringent environmental rules, and it will increase the efficiency and fuel diversity of our generation sources.

This program allows us to ultimately retire up to 6,800 megawatts of our older, less efficient, coal-fired generation. In order to recover these important investments, we have rate cases planned in the Carolinas.

The first of these rate cases is the one Progress Energy Carolinas filed in North Carolina last month. This marks its first base rate increase request in North Carolina in 25 years. We have requested a net increase in annualized customer rates of $359 million. This is based upon an ROE of 11.25%, a 55.4% equity component of the cap structure, and a retail rate base of about $6.9 billion through the estimated date of the hearings.

Around 70% of the requested rate increase is due to capital investments. This includes the 600-megawatt combined cycle unit at the Smith Energy Complex which went into service in June of 2011. It includes the 920-megawatt Lee Energy Complex scheduled for commercial operation by year-end.

The filing also includes (inaudible) associated with the 625-megawatt Sutton combined cycle gas plant expected to be in service in late 2013. All of these plants were approved by the commission through its certification process.

The commission has established a procedural schedule and evidentiary hearings will be held beginning on March 18, 2013. We expect revised rates to be in effect by mid-2013.

We are also finalizing our rate case filings for Duke Energy Carolinas. These petitions are expected to be the last in a series of three rate cases for Duke Energy Carolinas to recover capital investments made to modernize the generation fleet. This includes the 825 megawatt pulverized coal unit at Cliffside, these 620 megawatt combined cycle natural gas plant at Dan River, and certain upgrades made at the Oconee Nuclear Station.

After discussions with the North Carolina public staff we have shifted the filing of the cases for Duke Energy Carolinas until the first quarter of 2013. Our North Carolina filing will be made around one month before our South Carolina filing. In connection with this shift in timing, we will request approval to defer depreciation, O&M expense, and the return on Cliffside and Dan River until new customer rates are in effect. The public staff will not oppose this deferral request.

Next I will provide an update on our progress with merger integration as outlined on slide six. I am very pleased with how our two companies have come together. We are well on our way to achieving the benefits expected from this transaction.

Over the last four months we have essentially completed staffing the organization. As you all may recall, about 1,100 employees applied for our voluntary severance program. More than half of this group are expected to leave by year-end with the rest leaving over the next 12 months or so.

We remain on track to achieve the guaranteed $650 million in fuel and joint dispatch savings over the first five years. We are dispatching the generating fleets in the Carolinas as one combined fleet.

Joint dispatch, along with fuel savings, produce significant and immediate cost efficiencies that directly benefit our customers in the Carolinas. Effective September 1, we implemented a $70 million rate decrement in the Carolinas to begin passing on the expected first-year savings to customers. These efficiencies will extend beyond the five-year regulatory period and will help us mitigate the impact of future customer rate increases.

Now let's turn to slide seven which outlines our ongoing evaluation of whether to repair or retire the Crystal River 3 nuclear unit in Florida. On October 1 we provided the Florida Public Service Commission with an independent engineering report commissioned by the Duke Energy Board of Directors in March 2012.

This report evaluated three things. First, the technical feasibility and risk of the current repair option; two, the estimated costs to repair the unit; and finally, the timeline needed to repair the unit.

Zapata Inc. is the engineering firm that produced the report. They found that although the current repair plan appears technically feasible, a number of risks and technical issues remain that need to be resolved, including the ultimate scope of any repair. We have formed a technical review team to analyze the issues raised in the independent report. The team will continue to refine and evaluate the risk, scope, cost estimates, and schedule if the unit is repaired.

Because of the ongoing review of the scope and cost, it is unlikely we will begin any repair before year-end. Therefore, as outlined in the settlement agreement, we are subject to a total $100 million customer refund for replacement power costs in 2015 and 2016. This liability was recognized in the third quarter with an offsetting increase to goodwill.

We continue to have conversations with NEIL, the nuclear insurance company, regarding the level of insurance coverage for the repairs. NEIL has not yet finalized its coverage decisions. We expect to hold nonbinding mediation discussions with NEIL later in the fourth quarter. If we do not reach a mediated settlement, the next step is binding arbitration.

The Company has not made a final decision either to repair or to retire Crystal River 3. However, the regulatory settlement approved by the Florida commission earlier this year provides a framework for either path forward. We expect a decision could be made either by the end of this year or by summer 2013.

We will proceed with repairing the unit only if there is a high degree of confidence that the repair can be completed within our estimated cost and schedule. Any final decision will be made in the best interest of our customers, joint owners, and investors.

In Indiana, we are focused on bringing the Edwardsport plant online and receiving approval of the regulatory settlement for cost recovery. This has been a challenging project, but an important one. Not only for our company, but also for the state of Indiana. Edwardsport will use local Indiana coal in an environmentally responsible manner.

We are currently in the testing and startup phase and are about halfway through General Electric's new product introduction testing process. We have achieved important milestones.

First, construction is complete. Second, we have operated both the combustion and steam turbines on natural gas. Third, in late October we achieved syngas production from coal on one of the gasifiers and began testing the combustion turbines on syngas. Additional testing will continue over the next several months.

This testing and startup phase is identifying and correcting issues prior to start up. Issues discovered during the equipment testing and commissioning of the project have required an extension of the project timeline. The in-service date is now scheduled for mid-2013.

Based on lower-than-projected revenues and additional costs resulting from the delayed in-service date, our updated cost estimate for the plant is $3.154 billion, excluding AFUDC of approximately $400 million. The estimated cost increase results in the recognition of a pretax charge of about $180 million in the third quarter of 2012. This charge has been treated as a special item and excluded from Duke Energy's adjusted diluted earnings per share.

As for the Edwardsport regulatory settlement, the hearings wrapped up in July. We are optimistic the Indiana commission will rule on this matter by year-end.

Turning to slide nine, let me update you on our other major new plants under construction. Cliffside Unit 6 is now undergoing an intensive testing and commissioning process. We expect Cliffside to become commercially available by the end of the year with the current approved budget.

Our combined cycle natural gas projects in the Carolinas -- Dan River, Lee, and Sutton -- are all on budget and on schedule. Both Dan River and Lee are expected to be commercially available before year-end.

Before moving on to our commercial businesses let me briefly discuss our nuclear fleet. Our combined nuclear organization has enormous experience and depth of talent. Today we operate a nuclear fleet of around 11,000 megawatts with all of our plants in the Carolinas except one.

During the third quarter our operational performance for the combined nuclear fleet was strong. We performed an approximate 98% capacity factor, excluding Crystal River 3. This exceptional performance gave our customers the benefit of efficient and reliable nuclear generation during the hot summer months when they need it most.

We continue to push for improvement and overall consistency in fleet performance. Safety is always first. We also focus closely on reliability and efficiency metrics, such as capacity factors and operating costs per megawatt hour. We are leveraging best practices and making additional investments in our nuclear fleet to optimize safety, reliability, and efficiency.

I want to take a moment to provide a few updates on our Commercial Power and International operations.

In late August Duke Energy Ohio filed a request with the Ohio commission to establish a charge for its cost of providing capacity services in PJM consistent with the new state compensation mechanism. This filing also included a request for deferral treatment of the differences between our cost base capacity charge and the PJM market prices from August 2012 through May 2015. This filing does not seek to alter the electric security plan under which Duke Energy Ohio is currently operating.

A procedural schedule has been established for the capacity filing. It currently includes a hearing date of April 2, 2013. We have filed a motion with the Ohio commission requesting an expedited schedule.

Our current focus is on obtaining approval of this cost-based capacity compensation mechanism. Gaining the necessary clarity on this capacity filing will inform any long-term strategic decisions related to this asset portfolio.

The renewable portion of our commercial power portfolio continues to grow. We project a total renewable capacity of around 2,000 megawatts in service by the end of this year. Earlier this year we finalized a joint venture agreement with Sumitomo on two of our Kansas renewable wind projects, Cimarron II and Ironwood. Both are already in service.

As for our International business, it continues to perform very well. This business has provided reliable earnings over time. You may recall that Brazil represents half of the earnings from our International business.

In September, the president of Brazil proposed a program to reduce electricity tariffs by an average of around 20%. This is tied to concessions scheduled to expire in 2015 and 2017. We anticipate this program will be finalized in early 2013.

The program, if approved, is not expected to impact our Brazilian assets in the short term because our concession agreements expire in 2029 and 2033. Additionally, our assets are almost fully contracted through 2014 and around 60% committed in 2015 and 2016. We will continue to monitor this development and potential impact on market prices as we pursue additional contracting for our generation fleet.

In summary, we are off to a great start as a combined company. It shows in our financial performance, it shows in the savings we have delivered to our customers from day one, and it shows in the way our employees have focused on performing their work. I appreciate and am thankful for their laser focus on excellence in all they do.

Now I will turn it over to Lynn, who will provide a more detailed look at our financial performance for the third quarter and going forward.

Thank you, Jim. I will begin with an overview of Duke Energy's third-quarter earnings results for each of its business segments, an update on retail customer volume trends and economic conditions, as well as our financial objectives going forward.

As summarized on slide 11, for the third quarter of 2012 we announced adjusted diluted earnings per share of $1.47, slightly lower than the $1.50 for third quarter 2011. However, it is important to remember that our prior-year results included $0.12 of favorable weather. Even though weather was favorable this year, it was not at the same level we experienced in 2011.

This quarter is also the first period that reflects Progress Energy's results in our financial statements. Also remember that last year's results have been adjusted to reflect the 1-to-3 reverse stock split that occurred just prior to the merger closing.

On a reported basis, our earnings for the quarter were $0.85 per share as compared to $1.06 per share for the prior-year quarter. These reported results for the third quarter 2012 include $0.17 of impairment charges related to the estimated cost increases at Edwardsport and merger-related costs of around $0.42. These charges are considered special items and, therefore, have been excluded from our quarterly adjusted EPS.

The merger related costs consists of employee severance costs, costs related to the interim and permanent FERC mitigation plan, concessions agreed to with the Carolinas commissions in order to receive merger approval, and merger transaction costs.

Let me briefly discuss the primary adjusted earnings per share drivers for each of our business segments. Adjusted earnings at our regulated business, US Franchised Electric and Gas, were $0.62 higher than the prior-year quarter, primarily due to the addition of the former Progress Energy regulated utility operations in the Carolinas and Florida.

Updated customer pricing, including the implementation of revised customer rates at Duke Energy Carolinas, also contributed to USFE&G's increase in quarterly results by $0.12 per share. These favorable drivers were partially offset by less favorable weather.

Duke Energy International's results for the quarter were $0.02 lower due primarily to unfavorable exchange rates in Brazil. As expected, Commercial Power's results were $0.06 lower than the prior-year quarter, primarily due to implementation of the new market-based electric security plan in Ohio.

Our non-regulated Midwest gas generating fleet realized lower PJM capacity revenues as the market-based price fell from $110 per megawatt day in the prior year quarter to $16 per megawatt day in the current quarter. Due to continued low natural gas prices, this gas-fired fleet continued operating at record generating levels. Actual generation for the quarter was around 35% higher than the prior-year quarter.

Other financial drivers for the quarter included dilution of $0.54 for the quarter-over-quarter impact on EPS resulting from the issuance of additional shares in connection with the merger and $0.05 of additional interest expense on Progress Energy Holding Company debt. As you will recall, we issued around 258 million shares to former holders of Progress Energy common stock and now have around 700 million shares of Duke Energy outstanding.

An important consideration as you evaluate our year-to-date EPS result is that the weighted average number of shares outstanding will increase from the current year-to-date average of 531 million to 575 million shares for full-year 2012.

Slide 12 presents both our quarter-over-quarter weather-normalized customer usage trends as well as what we are experiencing on a rolling 12-month basis for our regulated business. This chart includes trends for the Progress Energy utilities compared to what they experienced last year.

Trends for the third quarter show residential and industrial demand down from the prior-year quarter. Since volume trends in any single quarter can be difficult to evaluate, we have also included 12 month's rolling average volume trends as a point of comparison. Over this 12-month horizon total weather-normalized load is slightly higher with growth seen in all major customer classes.

For residential customers, we continue to experience growth in the number of customers in each of our service territories. In fact, the average number of residential customers has increased by around 50,000, or 0.7%, over last year's quarter. This growth is around double what we experienced at this time last year. However, average usage for residential customer continues to trend modestly lower as a result of the challenging economy and energy efficiency efforts.

Industrial demand reflects recent weakness in primary metals in the Midwest, the chemical sector, and textile customers in the Carolinas. The automotive sector remains strong.

We entered the year expecting overall load growth to be less than 1% over the prior year. Our actual experience to date has generally met expectations, although customer usage patterns continue to be hampered by the economic uncertainty.

Despite improvements in national unemployment, home sales, and retail sales, US fiscal policy and the European situation leave us cautious about the strength of future growth. We believe our service territories are well-positioned and remain attractive for the long-term. However, we are planning our business for an environment of a very modest load growth until we see greater economic stability.

As Bob highlighted during his opening comments, we will hold our analyst meeting in late February in New York. During that meeting we will discuss our overall business strategy, our 2013 earnings guidance range, CapEx, and financing assumptions. You will also have the opportunity to hear from our executive team on focus areas in their businesses.

During this meeting we will discuss our long-term earnings growth objectives for the new combined company. We continue to target a long-term earnings growth range of 4% to 6% in adjusted diluted earnings per share and have determined that 2013, the first full year for the combined company, represents an appropriate base for future growth.

Our long-term earnings growth potential remains strong and will continue to be anchored by investments in the regulated businesses; weather-normalized load growth; reaching reasonable regulatory outcomes, particularly in the Carolinas and in Ohio; achieving merger integration benefits and synergies; managing our costs, including emergent work related to our nuclear fleet and the addition of new resources; and continued contributions from our commercial businesses.

We have included on slide 13 and overview of the primary earnings drivers we expect in each of these areas for 2013. Continued growth in the regulated businesses and our ability to harvest merger synergies will help us mitigate the decline in PJM capacity revenues impacting our non-regulated Midwest generation. Our detailed planning for 2013 and beyond continues and we look forward to discussing our strategic plan in further detail during our analyst meeting in late February.

I will close with slide 14, which addresses our main financial objectives. We remain on track to achieve our 2012 earnings guidance in the range of $4.20 to $4.35 per share, adjusted for the 1-for-3 reverse stock split.

In addition to growth in our long-term earnings per share, continued growth in the dividend remains central to our investor value proposition. We are targeting a payout ratio of 65% to 70% based on adjusted diluted earnings per share. Our current dividend yield of 4.9% remains attractive compared to the S&P and the current low interest rate environment.

The strength of our balance sheet, liquidity, and credit metrics support our ability to grow the business as well as the dividend. We remain committed to maintaining this financial strength, which allows us to finance our growth in a cost effective manner directly benefiting our customers.

In summary, I am pleased with our quarterly financial performance and how we have hit the ground running as the new Duke Energy. We have a strong growth platform as efficiencies from the merger allow us to pass along savings to our customers and shareholders. From a financial perspective, we remain very well positioned for the future.

Now let me turn the call back over to Jim for closing comments.

Thanks, Lynn. Before taking your questions I want to emphasize again how proud I am of our employees. We are now four months past merger close and they haven't missed a beat in delivering on our mission.

They have an extraordinary get-it-done mentality. We are facing our challenges as one team. We know what we need to do and we are doing it. We are determined to realize our vision of the new Duke Energy, turning our scale and diversity of assets into sustained performance and greater value.

Needless to say, we appreciate your interest and investment in Duke Energy. With that let's open up the phone lines for your questions.

(Operator Instructions) Greg Gordon, ISI Group.

Thanks, good morning. You had lots of trucks in New York City from Cincinnati so we appreciate the help.

We are glad we could be there.

Couple questions. First, we are nine months through the year, and I think if I've done the math correctly, and please forgive me if I haven't, you have had operating earnings of $3.74 year-to-date. Can you give us any visibility into where you think you will be within your $4.20 to $4.35 guidance range for the year given we have just got a quarter to go?

Greg, it is a good question and we are leaving the range at $4.20 to $4.35. As we continue to put the companies together we have got merger integration that we are focusing on and we just think that is an appropriate place to be at this point. But as we have said, we are very pleased with where we are. We think the quarter was very strong and the team is working hard on the fourth quarter.

Okay. When I look at the drivers you have given us for next year, there is nothing in there that I think looks surprising or new relative to things that you have talked about as structural drivers before.

Is it fair to think about 2013 in some ways as a transition year because the merger closed six months later than you expected? So merger synergies will come in a little bit later than expected; you don't get the retail rate hikes until later in the year.

If I think about the annualized drivers as they roll into 2014 if you are successful, it seems like you have a lot more operating leverage and revenue growth potential in 2014 relative to sort of just getting started with getting things working in your favor in 2013. Is that fair?

You know, Greg, I think 2013 is an important year and after giving it lots of consideration we think is an appropriate base for growth. As you mentioned, we will have some partial year benefits. The rate cases will be a partial year, synergies will not be at a full run rate, but I think the drivers of some capture here should give you a good indication of where we see 2013. Then annualization into 2014 would be an appropriate consideration. But we will have more on 2013 in February.

Do you think that your 2014 numbers will be better than 2013, the same, worse?

Greg, we are going to do guidance in February and talk about 2013 and the long-term growth rate. That is as far as I can go at this point.

You can't fault me for trying. Thank you.

I know, I know.

Dan Eggers, Credit Suisse.

Good morning. Maybe I'm going to try and carry on with Greg trying to front run the analyst day a little bit. But with all the generation investments kind of getting toward the end of completion what do you guys see bucketing as being the next major wave of investments the utilities need to make from a system maintenance or reliability perspective?

I will take a shot. Jim may have some other things to add.

We still have some generation to complete so the Sutton plant is scheduled to go in service in 2013. We also have environmental spending for the coal fleet that will continue. We have nuclear investment that we foresee, not only in the existing fleet, but also to address Fukushima as we go forward.

And we are always looking for ways to modernize the T&D system. As you know, we are in the midst of a Smart Grid rollout in Ohio. That remains the potential opportunity for distribution automation in our other jurisdictions. So those are the things I would point to.

That is a great list, Lynn.

Then I guess if you were to look at the demand growth, and I know you guys have been more cautious on recovery than a lot of other companies have been so far, do you need to see demand growth better than this 1% a year normalized to support that 4% to 6%? Or how do you think you are going to be able to hit those targets relative to maybe a rate filing strategy going forward?

Dan, we are planning the business for very modest growth/ So we were at less than 1% this year; I think 1% or less is a good planning assumption going forward. In recognition of that we are focused on costs that are consistent with that environment, and so I think that, at least for the near term, is the new normal we are working with.

Let me just add to that. I think Lynn said that well but I would underscore the point that we are going to have to kind of think through what the new cost paradigm needs to be in a world where the demand growth is 1% or less. And I think that is a practical thought.

I think our company compared to others is probably ahead in the modernization of our generation fleet, and that is really going to drive our earnings over the next year or so. All the other things that Lynn listed will also be drivers of earnings growth.

But I think it has to -- we have to achieve superior growth through O&M control and changing the cost paradigm. I think that is an imperative. And this combination has been a great catalyst in to us being able to do that.

Jim, when you sit down and go through these rate cases, do you think you need to go either to the commissions or to the legislatures and evaluate things like a decoupling or some other source of more structural mechanisms for regulatory policy perspective if demand growth is going to kind of stay at the sustained lower level?

You know, Dan, I agree with that in this way. I believe that if you look and all the states that we operate in moving toward more of a formula rate approach, very similar to what they have in Alabama, for instance. A formula rate approach is the right direction to go in over the next decade for a variety of reasons.

One is to really deal with the modernization of T&D and continued modernization of our fleet, to also address the issue of slow growth in demand. But, more importantly, I think it gives us credibility with our customers if we had formula rates with respect to investing in their homes and businesses to help them to reduce their usage.

So I think that puts us in a stronger position on the other side of the meter. So there is multiple reasons, all good public policy reasons, to move toward a formula rate approach over the next decade.

Okay, got it. Thank you, guys.

Steve Fleishman, Bank of America.

Good morning. First, could you just give a little more clarification of this agreement that you mentioned with staff in North Carolina on delaying the rate case there and getting deferral treatment? How long would that deferral treatment be in place and when would it start?

Steve, what we have agreed to do is shift the filing of the case really in recognition of the workload that the staff has in addressing the Dominion case, the Progress case, and then Duke following. In connection with that shift, we will be filing to defer O&M appreciation return on Cliffside and Dan River and then put that deferral into rates over a five-year period.

So there has been precedent in the Carolinas for these deferral filings as you are trying to synchronize an in-service with a rate increase, so we have done this in previous cases. We did it for our Buck plant, for example. And so this is just part of trying to synchronize cost, incurring costs with a rate mechanism.

And just when is in-service versus when you would actually be getting rates? How long a deferral period is that?

You are talking about months. So in service by the end of 2012 roughly and then rates would be in effect sometime later in 2013.

Okay. Then one of the drivers you mentioned for 2013 is growth in USFE&G wholesale business. Could you talk a little bit about what growth you are expecting there?

Steve, we gave a little visibility to this as we provided guidance for 2012. So it is the addition of customers, extension of contracts in both the Duke service territory, historic legacy Duke as well as the legacy Progress territory. So one that I would point to would be the co-ops in South Carolina. This is a continuation of what we shared with you in 2011.

Okay. I know you won't answer this question, but just for some color. I think you mentioned that 2013 is an important year, but I think in meetings a few months ago you also talked about it as being a transition year. As I think about a 4% to 6% growth rate off of a -- if it is still a transition year, you are not -- in theory you are actually growing less than that, because you are off a base that was still transitioning. Is 2013 a transition year or an important year?

You know, Greg, the -- Steve. I want to say Greg because I think this transition year has taken on a life with certain investors and analysts. And I'm not trying to signal anything specific on transition or otherwise.

We think 2013 is the first full year of the combined company. We have had six months to get things started, but we are not at a ramp rate on the merger synergies. And so we believe that represents a good starting point for the Company and provides an appropriate base for us to grow on.

So, Steve, I don't know how to respond to the notion of transition or otherwise; just highlighting the items that I have talked about.

Okay, thank you.

Michael Lapides, Goldman Sachs.

Really two questions. Congrats on a good quarter. Real quickly, just trying to think about O&M pressures.

Now I know merger synergies, and you will disclose merger synergy savings levels at the analyst day in February, but when you think about things that could offset that, meaning O&M pressures, could you give kind of a handful of what O&M pressure points could exist within your various businesses?

Let me start and then Lynn can add to it. As we add new plants that will increase O&M, but that will be offset by the retiring of plants, so there would be a netting out that will go on there.

Fukushima costs that Lynn mentioned a moment ago, these incremental costs -- and they could be up to $100 million a year. These costs could be pressure with respect to O&M.

But, Michael, the way I think about it is the one thing that we have really been able to do well, and we have roughly $6 billion in O&M every year, what we really have been able to do well over the last several years is really use the cost lever to hit the numbers. I think that we are going to continue to do that going forward, even though there will be pressure on us from the bringing on of new plants, the increased nuclear cost.

Lynn, how do you think about that?

I think those are a couple of good examples, Michael. Another one that I know a number will focus are things like pension costs. In a low interest rate environment that also can be a bit of a headwind.

But I think, as Jim indicated, we are looking at the total complexion of our O&M. The synergies give us a great opportunity to identify areas we can save costs. We are looking for ways to maintain a very modest trajectory in O&M growth as we go forward to really match what we see as top-line growth potential.

Got it. One follow-up Indiana related. Just trying to think about the process going forward.

So you have got the settlement that has been sitting in front of the IURC on Edwardsport for a number of months. When do you think the commission there rules on that settlement and, therefore, when do things go into place as part of that settlement? And then when do you file again for kind of final cost recovery on Edwardsport?

Michael, we are optimistic that the commission will approve the settlement by the end of the year. There is no specific procedural schedule that would indicate that they must, but we are optimistic that they will rule by the end of the year.

Then we have trackers, as you know, in Indiana that would be considered along with the settlement. The trackers would, first of all, put into rates the return on the invested capital and then we are intending to file a tracker to pick up in-service, which would be the O&M and depreciation. So those will be filings; the in-service filing will occur shortly and the other trackers are already under consideration by the commission.

Okay. But can you give a little highlight of just if the commission approves the settlement that would go into effect beginning of 2013 timeframe. When would the next potential revenue change related to Edwardsport likely occur?

Probably I would say a quarter or two following in 2013. Michael, the procedural schedule on these trackers are every six months typically.

Okay, thank you. I will follow up off-line. Much appreciated, congrats on a good quarter.

Thank you, Michael.

Hugh Wynne, Sanford Bernstein.

Good morning. Just a couple quick questions, the first one on Brazil. You mentioned on slide 10 that these 20% cuts of (inaudible) rates will be expected to be finalized in early 2013. You are protected in the short term by the contract structure -- by the maturity of your contracts in Brazil.

What is the maximum potential revenue earnings impact, however, once these existing contracts are renewed at the new rates?

Hugh, we are not in a position to estimate this at this point. I think a couple of things need to happen.

First of all, the program needs to be approved and that is scheduled to occur in 2013. Then we will have to evaluate how that impacts market prices, and this is not the only item that would impact market prices. There is supply/demand, there are new resources coming on in Brazil.

As you know, they have increased growth in demand of electricity. Hydrological conditions can impact prices as well. So we need to step back and evaluate all of those things before we can give you any clarity on impact.

Okay. I imagine that will be part of the analyst day?

We will certainly update you in February and I think this will be ongoing as we see how these rules are finalized.

Good. The second question is on Edwardsport. You mentioned that you have produced syngas at one of the gasifier you have produced electricity. Did that test show the gasifier and the combined cycle gas turbines operating at design capacity or was there any shortfall from design expectations?

Let me, if I may, turn to Jeff Lyash to address that.

Thank you, Jim. As you may know, we have been through the power island and fully tested it on natural gas, both combustion turbines and the steam turbine generator. In the last few weeks we have put gasifier 1 in service, successfully produced very high quality syngas, and used that syngas in the first of the two combustion turbines to produce up to about 115 megawatts.

That testing, so far, has gone very well. While we have experienced some equipment infant mortality failure type issues, we have seen nothing that calls into question the robustness or the viability of the design. The test program is going pretty much as expected at this point.

Great. And if you permit me, can you make any comments on your success to date in reducing your fuel costs in the Carolinas to offset the $650 million rate reduction that you have committed to?

Yes. Hugh, we are on track and see success not only in generating joint dispatch savings, but also in fuel flexibility. I think for the first quarter through September; we will be filing in the next week some specifics on that first-quarter impact. You will have an opportunity to see that when it is filed.

We would expect the joint dispatch savings to ramp up over time and similarly fuel. We have about 65% of our commitment on fuel under contract at this point. As we burn the coal that will then flow to customers.

Great, thank you very much.

Thank you.

Stephen Byrd, Morgan Stanley.

Good morning. I wondered if you could talk a little bit about your sense of the likely regulatory and political climate in North Carolina after the elections that we just saw. Just any general sense as a result of the election; anything about the governor and just some of the changes there?

I would make a couple of observations. One is that what you have seen is a significant -- the Republicans control both the House and the Senate. They picked up several seats in the Senate. They now have close to a super majority in the House. This is the first Republican governor in 20 years and he won by over 10%.

So I think that they are putting -- this new administration is going to come in; they have a lot of work to do. They don't have the same deep bench of people to pull from because they have been out of power in Raleigh for 20 years. But my belief is that Pat McCrory will do a good job of pulling talent from around the state into Raleigh to really create kind of a world-class administration.

And so we are very happy that he has been elected and proud of the fact that he is from Charlotte. He was our mayor for 14 years. And it's the first governor from Charlotte that has ever been elected.

Okay, great. Thank you. Just wanted to switch gears very quickly to confirm on Brazil. You don't anticipate any changes to the existing contracts, the existing hedges you have as the proposed (technical difficulty)

Kit Konolige, BGC.

Good morning, guys. Totally different question for you, Jim. I saw a report in a publication called POLITICO that you are being considered as the next Secretary of Energy when Stephen Chu leaves. What can you tell us about that?

The only thing I can tell you is since 1990 people have been trying to promote me out of this job into the government and they have been unsuccessful. I have a mission here to complete of integrating these two teams. I am focused on that.

I am flattered that they would consider me for that lower-paying job, but I think my wife would weigh in and say get the money and focus on Duke. So I think that is how I am thinking about it.

Okay, fair enough. Then, Lynn, just to beat this dead horse a little bit more. When you were talking about the 2013 drivers I think I heard you call out the capacity revenues as something you cited among the drivers as a negative. Then I wrote down that you said that merger synergies would help offset that.

So should we be looking at any of these items in particular as more or less important than the others?

Kit, as I look at -- slide 13 we have tried to give you positive and negative impact in the quarter. I would point to rate cases, I would point to synergies, I would point to costs as being important items. Certainly the economy is something that we will be focused on.

So I'm not intending to give relative magnitude on any of them at this point. We will give you a full discussion in February, but there are a number of important items on this page.

Okay, fine. Finally, any update -- do you guys have a sense of when this [Jenner & Block] report is likely to be out? Any further sense of timing on moving forward with the commission's concerns in North Carolina over the CEO transition?

As you know, this investigation is ongoing. We are cooperating with the North Carolina commission and Jenner & Block. We are keeping open communications with the parties and we are working our way through this. I am hopeful that we can find a way to work our way through this in a way that creates value for both our customers as well as our investors.

But no sense of timing on when we might be able to move forward from that, Jim?

It is just hard to zero in on the exact timing, but we are working our way through it. I think everybody's intent is to do their best to get through this and get it behind us one way or another as soon as possible.

Great, thank you.

Thank you.

Ali Agha, SunTrust.

Good morning. Jim or Lynn, going back to your dividend payout target 65% to 70%, if I take the 2012 guidance and your current dividend you are at or actually slightly above that range right now. So fair to assume that if earnings are going to grow 4% to 6% dividend growth should be somewhat south of that?

Ali, we have been growing the dividend at 2% really since 2009 to bring ourselves into the payout ratio. As we look forward, we will be balancing that dividend policy with capital spending and growth aspirations and we will give you more specifics on dividend in February. But we are committed to growing it; it is an important part of our value proposition and we are focused on growth into the future.

And separately, can you remind us your earnings sensitivity? A 1% change in load growth, roughly what does that do to the bottom line?

It is $100 million of net income.

$100 million of net income?

Yes.

Got it. Last question, Jim, for you. Assuming the Edwardsport settlement is approved and you go forward, given the cost escalations, etc., in retrospect from a financial perspective, ROE earned perspective, how would you grade that project and that investment when all is said and done?

I think if you look back on the project -- I mean two ways to look at it. If you look at the total cost of the project and you look at a return on invested capital it clearly is greater than our cost of capital, so it is net positive from that standpoint. The minute this plant is completed and in rate base it will be earning at whatever our ROE is at the time and in the future, which now would be 10.5%.

Okay. So you are going with the escalation, you think it was all worth it at the end?

I do, and I think we will appreciate the value of that plant more as the years go on. It is a great hedge. First, it is the most efficient coal plant in the world and we will appreciate the value of that plant more and more in the future. Because gas prices are low today, but you look out over the 40-year life of that plant, can you expect them to be $4 to $5 for 40 years?

To pick up on Ben Franklin who used to say there are all only two things in life that are certain, death and taxes, I would add a third certainty to that and that is the volatility of the price of natural gas. So I think this becomes a great hedge against natural gas prices in the future.

Thank you.

Ali, I would like to jump back in on sensitivity on 1%. I misspoke. It is $100 million pretax, $65 million net income.

Got it. Thanks a lot.

Thank you.

That does conclude today's question-and-answer session. At this time I will turn the conference back to Mr. Jim Rogers for any additional or closing remarks.

Thank you all again for participating in our call today. We look forward to seeing those of you all who will be at the EEI Financial Conference in Phoenix next week. Again, thank you very much for investing in Duke Energy.

That does conclude today's conference. We do thank you for your participation.