Duke Energy Corp (DUK) 2013 Q1 法說會逐字稿

Good day and welcome to the Duke Energy first quarterly earnings call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Bill Currens. Please go ahead, sir.

Thank you, Markita. Good morning, everyone and welcome to Duke Energy's first-quarter 2013 earnings review. Leading our discussion today 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 2 presents the Safe Harbor statement which accompanies our presentation materials.

You should also refer to the information in our 2012 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 at www.duke-energy.com and in today's materials.

Please note that the appendix to today's presentation includes supplemental information and additional disclosures to help you analyze the Company's performance. In addition to our normal disclosures, we have included additional information on our regulated wholesale business, as well as updated estimated earnings based figures by jurisdiction through 2015.

In today's call, Jim and Lynn will review our first-quarter highlights and briefly update you on our near-term priorities, including our recent regulatory activities. Additionally, we will discuss trends in our customer usage patterns, as well as the economic conditions in each of our service territories. Finally, we will review our quarterly earnings considerations for 2013, as well as our overall financial objectives. After their prepared comments, Jim and Lynn will take your questions. Now let me turn it over to Jim.

Thanks, Bill. It is good to have you all on the call today. We are now 10 months into the merger with Progress Energy, and I am very pleased with how we are executing our plans. Our first-quarter performance built on our momentum in 2012.

For the first quarter, we announced adjusted diluted earnings per share of $1.02 compared with $1.13 for the same quarter a year ago. Even though below last year, our quarterly earnings are on plan. As a result, we are on track to achieve and today are affirming our 2013 earnings guidance range of $4.20 to $4.45.

Lynn will provide more details on the first-quarter earnings drivers for each of our segments. Also, she will provide our perspective on the quarterly variability in earnings this year.

During the quarter, our operational performance was strong, as highlighted by our nuclear fleet.

Slide five should be familiar to you. We have used it since last summer to show our near-term priorities and progress in resolving them. As you can see, we have checked off several important items. Now, we are focused on placing Edwardsport into commercial service and obtaining constructive rate case outcomes.

We have requested more than $1 billion of annual retail rate relief in the Carolinas and Ohio. I will discuss both Edwardsport and the rate cases in a moment.

We also remain focused on our longer-term priorities -- one, fully integrating the merged companies while achieving the targeted savings for customers and investors; and two, optimizing nuclear fleet performance.

Our integration efforts are producing results, and we are clearly on track to achieve the merger synergies we expected. During the first quarter, we achieved $37 million in fuel and joint dispatch savings from our Carolinas fleet. That was in addition to the $52 million in the first six months of the merger.

We are also making good progress on other integration efforts and are achieving labor reductions and other non-fuel O&M savings. In fact, about 30% of our merger initiatives have been completed. The other initiatives are either on schedule or ahead of schedule.

As for our nuclear plants, Dhiaa and his team continue deploying the nuclear operating model across the entire fleet, which includes 11 units in the Carolinas. We are seeing very positive results, as measured by our 17 nuclear performance metrics. Most importantly, our nuclear fleet capacity factor for the quarter exceeded 97%.

Now, turning to slide 6, I want to update you on the regulatory proceedings regarding our Crystal River nuclear unit in Florida. This plant has been safely shut down since late 2009. We decided earlier this year to retire the plant rather than attempt a complex, first-of-a-kind repair. We are finalizing a comprehensive decommissioning plan and will file it with the NRC.

As you all know, we selected the SAFSTOR method. The transition organization is fully staffed. Over the next few months, full-time staffing will be significantly reduced from the 600 previously on-site.

Late last year, we entered into a nonbinding mediation with NEIL, our insurance provider, to resolve all outstanding claims related to the Crystal River 3 unit. In February, both the Company and NEIL accepted the mediator's proposal, whereby NEIL would pay the Company an additional $530 million to resolve all outstanding insurance claims related to the plan. We received the $530 million last month and these proceeds benefit our Florida customers.

We believe that both decisions were in the best overall interest of our customers, joint owners and investors. The settlement agreement approved by the Florida Commission last year gave us the sole discretion and flexibility to retire this plant. The Commission is working with the parties in the proceeding to finalize the issues that the Commission will review. We expect the Commission to complete this shortly.

Oral arguments before the prehearing officer were held earlier this week and a scheduling order has been issued which sets hearings for October.

Before moving to the rate cases, let me give you a brief update on our new nuclear development activities. Yesterday, we announced our decision to suspend our plan for two proposed new nuclear units at our Harris Plant site in North Carolina. We continue to pursue combined operating and construction licenses for our proposed lean nuclear station in South Carolina and a lean nuclear station in Florida.

Related to the Harris license applications, we have spent about $70 million to date. We plan to seek recovery of the retail allocation of these costs from the North Carolina and South Carolina Utility Commissions.

Next, starting with slide 7, I will update you on our rate activities in the Carolinas. Duke Energy-Progress filed a general rate case in North Carolina last fall. We reached a settlement agreement with the North Carolina Public Staff in February. Under the terms of the settlement, the return on equity would be 10.2% with a 53% equity component of the cap structure. The terms are subject to North Carolina Commission approval. Parties to the agreement have agreed to delay cash collection, a financing cost on CWIP, for the Sutton natural gas plant for one year.

Upon Commission approval, the immediate increase to customers would be $151 million. There would be another $31 million in year two, upon inclusion of Sutton in customer rates. This settlement provides a fair and balanced outcome for the Commission to consider. We have completed our hearings before the Commission and expect a decision in time for the new rates to be effective in June.

In addition, Duke Energy Carolinas has filed rate cases in both North Carolina and South Carolina, as outlined on slide eight. We are requesting an annual retail revenue increase of $446 million in North Carolina and $220 million in South Carolina. In each case, we are seeking a return on equity of 11.25%.

These rate cases are needed to recover the investments we have made to modernize our system. For example, Cliffside unit 6 and the Dan River natural gas plant, both put into service in late 2012 and both preapproved by the Commissions.

The evidentiary hearings on the North Carolina case begin July 8, while the South Carolina hearing begins July 31. We expect rates to be effective for South Carolina in September. We have also requested a September effective date for revised rates in North Carolina.

Before moving to the Ohio rate cases, I want to mention a recent decision by the North Carolina Supreme Court. The court remanded the Duke Energy Carolinas' 2012 rate case decision to the North Carolina Utilities Commission. As you all will recall, in early 2012, the Commission approved revised customer rates based on a settlement agreement with the Public Staff at a 10.5% return on equity. The North Carolina Attorney General appealed the decision to the state supreme court.

The Supreme Court has required the Commission to make an independent determination regarding the proper ROE. This past Monday, the Attorney General filed a motion with the Commission requesting that the rate increase approved in 2012 be reversed until the Commission issues its ROE decision. We opposed this motion.

We continue to believe that the settlement agreement approved by the Commission is fair and balanced.

Next, let's turn to Ohio regulatory activity, starting on slide 9 with our two distribution rate cases, one for electric service and the other for natural gas. Early last month, we reached agreements with all intervening parties in both cases. Under the settlement terms, the net annualized revenue increase for electric distribution would be $49 million. There would be no adjustment for natural gas distribution.

Parties to the settlement in the gas case agreed to litigate the recovery of costs associated with the remediation of the old manufactured gas plant sites. We are seeking annual recovery of $22 million over three years.

The Ohio Commission approved the electric case stipulation earlier this week, and we expect revised rates will be in effect later this month. It will most likely be later in the summer before we receive the gas order.

Next, I will update you on our cost-based capacity filing in Ohio, as outlined on slide 10. We filed the $728 million request last August. We are seeking appropriate compensation for our capacity service. This filing does not seek to alter the Electric Security Plan under which Duke Energy Ohio now operates.

Hearings began in April. We presented a strong case, and interveners made arguments consistent with their previous filings. Rebuttal hearings will resume later in May.

The legal basis under which this request was filed remains strong. The filing is consistent with the new cost-based compensation mechanism adopted for fixed resource requirement entities in Ohio. Once hearings are completed, we will await a Commission decision. The decision will inform our long-term strategic plans for our Midwest generation fleet.

Turning to slide 11, we continue to advance our fleet modernization program, $9 billion of investments, adding 6600 megawatts of natural gas and coal-fired generating capacity. This program gives us the ability to retire up to 6800 megawatts of our older, less efficient, high-emitting coal plants and our oil-fired units. This will give us a high level of fuel diversity, which will benefit customers by giving us flexibility to adapt to future changes in commodity prices.

In 2012, we brought three new plants online, a combination of natural gas and coal-fired units, and we are on track to bring our remaining two construction projects, Edwardsport and Sutton, into service in 2013. Let me provide you an update on the Edwardsport IGCC coal plant in Indiana.

As you all remember, we completed the construction in 2012. We are now in the final process of completing the testing needed before we begin to bring the 618-megawatt plant into service and deem it operational. Both gasifiers have successfully produced syngas from coal and we've produced electricity from both turbines, using syngas, natural gas and a blend of both.

We are on track to put Edwardsport into commercial service later this month. This will be a major milestone. As with any new large plant, additional testing, completion of punch-list items and project closeout activities will continue for several months past the commercial operating date.

Edwardsport will be a very important addition to our generation fleet in Indiana.

The other major construction project is Sutton, a combined-cycle natural gas plant we are building in eastern North Carolina. We expect to place the 625-megawatt Sutton plant into commercial service during the fourth quarter. It represents the latest step in modernizing and adding more natural gas diversification in the Carolinas.

In summary, we are very pleased with our performance in the first quarter and our focus on resolving near-term priorities. The organization has quickly pulled together as one team. We continue to drive efficiencies that benefit customers and investors. We are making the most of the unique strengths this merger has created.

Our performance in the quarter leaves us well-positioned to meet our 2013 earnings and operational objectives. Now, Lynn will provide a more detailed look at our financial performance in the quarter, including a customer load and economic update.

Thank you, Jim. I would like to begin by saying how pleased I am with our first-quarter results. Slide 12 provides our earnings summary. As you know, first-quarter 2013 adjusted diluted earnings were $1.02 per share. These results were on track with our expectations for the quarter, although lower than our first-quarter 2012 results of $1.13 per share.

On a reported basis, our earnings for the quarter were $0.89 per share compared to $0.66 per share last year. A reconciliation of our reported results to our adjusted results is included in the supplemental materials.

Today, I will focus my remarks on the significant adjusted earnings drivers for each of our business segments for the first quarter. I will spend a few minutes on our volume trends and the economic conditions within our service territories. I will then discuss the timing of several key earnings drivers that you should consider as you assess our quarterly earnings for the remainder of the year. And I will close with our financial objectives going forward.

First, let's briefly discuss the primary adjusted earnings per share drivers for each of our business segments. Adjusted earnings at our regulated business, US Franchised Electric & Gas, increased by $0.44 per share. USFE&G's increased results were primarily driven by the addition of Progress Energy's regulated utility operations in the Carolinas and Florida, which contributed $0.35 per share in the quarter.

More favorable weather of $0.10 per share was also a significant driver for the quarter. As you might recall, first-quarter 2012 was extremely mild, with the Carolinas' heating degree days at their lowest level on record for a first quarter. Weather during the first quarter of 2013 was favorable to normal by $0.02 per share. Colder than normal weather in March more than offset the mild weather in January.

During the quarter, pricing and riders were favorable by $0.03 per share. This increase was primarily due to the timing of revised rates associated with our prior rate cases in the Carolinas.

As a result of these rate cases going into effect in February of 2012, we recognized an additional month of revised rates during this year's quarter.

Finally, additional wholesale revenues increased earnings by about $0.02 per share for the quarter.

As we discussed at our analyst day in late February, the wholesale business involves both short-term and long-term contracts to provide power to municipalities and co-ops within our service territories. We expect the wholesale business will contribute pretax net margins of $1 billion in 2013. This power is sold under various pricing mechanisms, such as formula rates and fixed capacity contracts with price escalators.

We have several new wholesale contracts that began in 2013. These contracts will grow over time, as the volumes sold increase over the contract term. The terms of these new contracts are long-term, between 15 to 20 years.

As we look forward, we expect our wholesale business to add an incremental $0.07 to $0.08 annually to earnings in 2014 and 2015, resulting in an average growth rate of 8% for this business.

Partially offsetting these favorable drivers for FE&G was decline in allowance for funds used during construction equity of $0.02 per share, resulting from the completion of several major construction projects in 2012, such as Cliffside and Dan River. As expected, this decline in AFUDC also contributed to a higher effective tax rate. This higher tax rate decreased earnings by $0.02 per share.

Next, I will address International Energy's results, which, as expected, were $0.06 lower than the prior-year quarter. International's results were impacted by lower volumes and higher purchase power costs due to delay and rainfall in Brazil, as well as FX and lower commodity prices at National Methanol.

Let me provide you an update on the rainfall conditions in Brazil. As we entered 2013, reservoir levels in Brazil were unusually low due to a delay in the rainy season. Since our analyst day in February, rainfall has been stronger. This has resulted in reservoir levels increasing from around 30% at the beginning of the year to around 60% currently. Even though this is a significant improvement, these levels are still below historic averages for this time of year.

Due to the low reservoir levels, higher-cost thermal power is being allocated to cover the demand, resulting in a higher exposure to costs for hydro generators, including our Brazilian operations. We will continue to monitor the reservoir levels and keep you updated as the year progresses.

Next, moving to our Commercial Power segment, results were $0.03 per share lower in the first quarter as compared to the prior year. This decline was primarily due to lower PJM capacity revenues for our Midwest generation fleet. Prices declined from $110 per megawatt day in the prior-year quarter to $16 per megawatt day in the first quarter of 2013.

And finally, let me discuss Other. This category primarily includes corporate interest expense not allocated to the business units, results from Duke Energy's captive insurance company, other investments and quarterly income tax levelization adjustments.

We recorded higher interest expense of $0.04 per share associated with the Progress Energy Holding Company debt and $0.02 per share associated with higher debt levels at Duke Energy Holding Company.

We also recognized dilution of $0.41 per share for the quarter, resulting from the issuance of additional shares in connection with the Progress merger. As you know, we issued around 258 million shares after the completion of the merger. We now have around 705 million shares outstanding.

Turning to slide 13, I will spend a few minutes on our volume trends for the quarter and the economic conditions within our service territories. As a reminder, it's important to note that 2012 was a leap year.

Our 2013 guidance assumes weather-normalized retail load growth of around 0.5%. For the first quarter, our retail volume, excluding the impacts of weather, were down 0.5% to the prior-year period across all customer classes. However, if the prior-year leap year effect is excluded, our first quarter volumes would have been favorable by approximately 0.5%, which is consistent with our annual expectations.

Let me briefly discuss some of the trends we are seeing in each of our customer classes. First, our residential customers. Usage per customer for this class continues to trend slightly lower. We continue to experience growth in the average number of customers, primarily in the Carolinas, Indiana and Florida. Since last year, we've added approximately 50,000 new electric customers, an average increase of 0.7%. Trends in this customer class will continue to track the recovery in the housing markets as well as the general economy.

Exploiting the leap year effect, our commercial class remains on a slow and steady growth path. Usage per customer in this sector is relatively flat, while growth in consumer spending and retail sales remain modest. Office vacancy rates remain consistent and above historical norms.

In the industrial sector in the Carolinas, we continue to experience strength in the automotive sector, which has helped to offset the continued decline in the textile industry.

In the Midwest, the automotive sector is also strong, but has been offset by recent weakness in the steel industry due to volatile steel prices and global economic uncertainties. As you will recall, industrial activity comprises a very small percentage of our customer load in Florida.

Overall, the economy continues to perform in line with our expectations and is recovering at a slow and steady pace. We expect economic activity to pick up in the second half of the year.

Our service territories remain attractive for economic development activities. As an example, MetLife, the global life insurance and employee benefits provider, announced in March that it intends to create 2600 jobs in Charlotte and Cary, North Carolina by the end of 2015. And just a few weeks ago, Google announced it was expanding its data center site in western North Carolina, making an additional $600 million investment to the area. These announcements have resulted in new investments and jobs in our service territories.

Now, I'd like to discuss several earnings considerations for this year. As you are aware, the midpoint of our 2013 earnings guidance range of $4.20 to $4.45 is reasonably consistent with our adjusted EPS of $4.32 in 2012. Even though the annual earnings per share are expected to be reasonably consistent, the quarterly contributions in 2013 will differ from 2012. We expect a relatively weaker first half in 2013 compared to 2012 and a relatively stronger second half.

This variability is being driven by a few key drivers, which are outlined on slide 14. First, the timing of rate case resolutions. We expect to begin recognizing the benefits from our pending rate cases in the third and fourth quarters, upon approval from our commissions.

Our second key driver is the timing of recognizing O&M expenses and merger savings. We expect to experience more significant merger synergies in the back half of the year as these savings ramp up over time.

Third, the impact of the issuance of incremental shares in connection with the Progress Energy merger. As I mentioned a moment ago, we will have significantly higher share counts in the first half of 2013 compared to 2012. Even though the additional share counts are evenly distributed throughout the year, the offsetting earnings contributions from the Progress utilities are not. The first half of the year normally contributes lower earnings than the second half due to seasonality.

The fourth key driver is significantly lower PJM capacity revenues for our nonregulated Midwest generation fleet. As I previously mentioned, in the June 2012 to May 2013 PJM auctions, the capacity price declined sharply to $16 per megawatt day from the previous price of $110 per megawatt day.

Overall, our first quarter results are on track with our plan and give us confidence in our ability to deliver on our full-year 2013 EPS guidance range.

In closing, we are affirming the guidance range of $4.20 to $4.45 for 2013, based upon adjusted diluted earnings per share. Results for the full year will be largely dependent on the successful resolution of our pending major rate requests, effective cost controls and our results in the third quarter, historically, our most significant. We continue to focus on growing the dividend, which is central to our investor value proposition.

We are committed to a payout ratio of 65% to 70%, based upon adjusted diluted earnings per share. Our current dividend yield of 4.1% remains attractive in the ongoing low interest rate environment. And we remain confident we are on track to achieve our short-term and long-term financial objectives.

Now I will turn it back over to Jim.

Thanks, Lynn. With that, let's open up the phone lines for your questions.

(Operator Instructions). Greg Gordon, ISI Group.

Thanks, good morning. Can you give us an update of where you stand in terms of your CEO search, and whether you can give us any view on whether we get visibility on that sort of at the front end of the period that's stipulated in the settlement or towards the end of the year?

Greg, I will address that. The CEO selection process is being led by a special committee of the Board. The committee is working with an outside adviser to support this process and applying a great deal of rigor and due diligence.

Of all the decisions a Board can make, the most important decision is the selection of the CEO. They are looking at both internal candidates as well as external candidates. The process is ongoing. They are being very thoughtful, deliberative and are working their way through this, and it's difficult at this time to predict when the decision will actually be made.

But in every event, it will be made before the end of this year.

Thanks very much. One other question, on a different subject.

It has been fairly often the case that you've been able to settle cases in North Carolina. I can't remember a situation where the ROE has been challenged in court and remanded in this fashion. Is there any precedent for this type of scenario, and can we look at that precedent, if there is any, into how the Commission might respond?

As a general rule, the Supreme Court defers to the judgment of the state commission. I think what's important to appreciate about the remand to the state commission is this. They didn't strike down the 10.5% ROE. What they simply did was ask the Commission to explain in detail the basis of their approval of the merger and specific -- I mean, the settlement and specifically the underlying basis for the 10.5%.

There is ample evidence in the record and what is expected from the Commission -- at least what we expect from the Commission is that they will review the evidence that was presented and they will write an order that underpins the 10.5%.

Thank you very much.

Dan Eggers, Credit Suisse.

Hey, good morning, guys. Just following up on Greg's question on the North Carolina situation. Does that potentially have any bearing on how the progress settlement is put together when it gets presented ultimately to the Commission? Or does it prospectively slow down the Duke case in the sense of maybe you need to build a bigger or more broad docket in order to avoid a debate in the future?

Good question, Dan. I would address it this way. When we file for a rate case, we file with a lot of testimony that really supports the ROE requests that we are making. As a consequence of that, when we enter into a settlement, as we have in the Progress Energy case, basically that 10.2% is underpinned with testimony, and we will file additional testimony when there is a hearing on the settlement.

So I think the most important point here is it, one, doesn't change the historic practice in the Carolinas of reaching settlements and presenting settlements to the Commission. What the court has really done has asked the Commission to explain in much greater detail why they approved the settlement and specifically why they approved the ROE.

So I think it's really a message to the Commission to address, based on record evidence, why they made their decision in more detail.

Okay. All right. Thank you. Oh, can I ask one more? I am sorry.

Sure.

On the Ohio capacity case situation, obviously, the other parties have pretty staunchly maintained their position and you guys have maintained yours. Is there an opportunity for you guys to look at a settlement or find a common ground on this issue? Or is this one that's going to have to go to a Commission decision and prospectively litigation to get to a fair outcome, from your perspective?

My judgment is -- you know, we have always reached settlements in Ohio. But this one has been difficult if not impossible to reach a settlement. I don't rule out the possibility of settlement later in the process. But I think everybody has kind of strapped on their position and going full speed before the Commission to make the argument.

And the argument is a strong argument, and if I had put my -- I haven't practiced law in a long time -- but if I put my hat on as a lawyer, this case is a very strong case for us, because this capacity charge has been approved for AEP, and the consequence of it, the Commission can't discriminate against one company versus another company in the application of their rulings. And so we're clearly going to win in the Supreme Court. I believe we can win -- and there seems to be evidence that -- or an indication that we could win at the Commission.

Okay. And then I guess, Lynn, just one question on Commercial Power. After the first quarter, kind of fairly far off the full-year rate, and capacity is going to work (inaudible) in the second half. What should we be thinking about that is going to help fill in against guidance where you guys have it today?

Dan, we do have an assumption of some success in Ohio in our guidance. And I think as we shared with you in February, as you look at the broad guidance range of $4.20 to $4.45, we have assumed a range of outcomes. And so they as we move through this process and get some more clarity on Ohio, I think we'll be able to give you more sense of how Commercial will contribute, as well as how the other parts of the business will contribute.

Okay, thank you, guys.

Stephen Byrd, Morgan Stanley.

Good morning. I wanted to touch on your disclosure on wholesale revenues, and, Lynn, you provided some discussion of that business. Could you talk a little bit to the degree to which -- talk a bit to the execution risk relating to that and the certainty of being able to achieve that. It looks like good EPS contribution, 8% growth. Could you just talk a little bit more about where you stand? You mentioned a few contracts, but just I couldn't relate that back to the overall number.

Yes, so we have a high degree of confidence in our ability to achieve those numbers and that growth rate, because the contracts have been signed and are in place. So the two that we pointed to was a wrap contract, or an extended contract, with NCEMC in the eastern part of our Carolina territory, and then a contract that we announced really back in 2010 involving co-ops in the northern part of South Carolina, a contract that will ramp up over a period of time over the next several years.

So the contracts are in place and we believe that we have a high degree of confidence in achieving those numbers.

Okay, thank you very much. And then just on the financial side of things, your interest expense year to date and your overall assumptions. Just curious if, as you are looking at your financing plan relative to where you initially set your assumptions, are things generally tracking online or are rates coming in lower? How are you tracking in terms of your financing costs?

Generally tracking online. And we have in the appendix our expectation for additional financing over the course of the year. We do have a number of issuances that will play in in the back half of the year.

Understood. Thank you very much.

Jonathan Arnold, Deutsche Bank.

Good morning. Just a quick one on Brazil. What would be a good assumption for a run rate headwind if the current curtailments continue through the year? We have heard some talk that they might want to really kind (inaudible) of the buffer ahead of well cap next year, et cetera. If things don't improve, is Q1 a guide to future quarters?

You know, Jonathan, that's a good question. As we looked at planning for Brazil and for International, what was delivered this first quarter is actually consistent with our plan. So we were expecting this level of contribution.

We do see some expectation of higher-than-average dispatch on thermal generation for the balance of 2013, but we would not expect it to have the impact that it had in the first quarter. But what I would also say is this is a situation that we are continuing to monitor, and we'll give you an update as the year progresses.

Okay, thank you. On another front, could you give us a little more insight into what's still showing in the cost to achieve line and what kind of timeframe should we expect that to fade?

Cost to achieve will be with us for a few years, Jonathan, primarily related to integration of systems and also costs as we continue to move through the exiting of employees who are leaving under the voluntary severance plan. So a couple of examples would be HR and finance systems will not be in effect until early 2014. Nuclear assets sweep, where we are combining systems in the nuclear operation and work management systems, those projects will continue into 2014, 2015 and 2016. So they will tail off over time, but we will continue to have costs to achieve for a couple of years.

And then this sort of Q1 level is probably where we are for the next year or two? Is that --?

I haven't looked at it from a run rate perspective. So let us take that one, Jonathan, and the IR team will be prepared to respond, give you some more input on that.

Thank you very much.

Michael Lapides, Goldman Sachs.

Hi, guys. Can you talk a little bit about Crystal River, and specifically decommissioning costs in the decommissioning fund? Meaning what are the variables that could significantly change the expected decommissioning costs of the plant? Where does the fund stand in terms of meeting the decommissioning costs for the plant? And how do you manage the risk around the cost variability of decommissioning? Meaning are there ways you can shelter Duke from cost escalation in the decommissioning of Crystal River over time?

So, Michael, I will start and see if we can resolve -- Dhiaa is also here for further discussion on the specifics of the decommissioning plan.

But we have $600 million in the decommissioning trust fund, which is a fully-funded level assuming that the plant retires in the 2030 timeframe. Under the SAFSTOR method that we've adopted, we have 40 to 50 years to move through decommissioning of this plant. And so we believe our funding level is adequate. We will be monitoring it as we go. And you ought to think about it as almost equivalent to the way we manage liabilities in a pension fund, where we have investments with equity and fixed income that we match to an expectation of liabilities. And we run scenarios and assumptions on costs, as well as scenarios and assumptions on investment of assets to ensure that we are adequately funded.

So, Michael, if I add to that, from a plant point of view, there is a process that we will follow to produce a cost estimate for decommissioning. We have to file with the NRC a report that is called the post-shutdown decommissioning activity report, and have to outline in that report our estimates, a site-specific cost estimate. We are due to submit that in November of this year. And 90 days after that, that is considered approval of that report, we will be able to give you significantly more details about the scope of that work.

Primarily, systems have already been drained down because the plant has been shut down for quite a while. So we are a good bit ahead on those activities. Basically, we will just allow most systems to -- we stopped maintenance on those systems, other than those that are associated with the spent fuel pool and related support systems. That will dictate the vast majority of the plan going forward.

Got it. And is there a way -- what are the biggest cost buckets or cost areas in terms of decommissioning a nuclear facility like CR3? I'm just trying to think about some of the variables, very big picture, broad brush, that could change your forecast decommissioning costs higher or lower when you put out that report in November?

It is entirely based on dismantling all equipment at the plant, and then dealing with the spent fuel pool contents. Currently, CR3 does not have dry storage, so that's a pretty significant consideration, of how do we move forward with the fuel that is in the pool.

Other than that, it's really just dismantling the equipment and the manner we go about doing that. Those are the two main variables.

Got it, thank you. Much appreciated, guys.

Steven Fleishman, Wolfe Research.

Yes, hi, good morning. I guess in the context of past success, I think you guys have beaten consensus quarters for three or four years in a row every quarter, and didn't do it this time. Is that more -- did you hit your internal numbers and just consensus was too high, or did you not hit your internal numbers?

We are on plan on internal numbers, so we did hit plan. And what we were trying to demonstrate with slide 14 is the quarterly variability that you can expect as you look at comparables between '12 and '13. So we have a high degree of confidence that we are going to finish the year consistent with our expectations. So that's where we are.

Okay. And then a follow-up on the wholesale sales and the slide. So the $0.07 to $0.08 is both in '14 and then incrementally in '15?

It is.

Okay. And the -- is that matching up with rate-based growth in wholesale as well? So when you have wholesale in the slide, is it matching there, or is it more just tied to contracted price increases?

It is load. You can think of it as additional load, where we are bringing on additional megawatts of load in those years.

Okay. And is there any offset in retail, i.e. less retail sales or less wholesale for retail benefit?

No.

Okay. Great, thank you very much.

Hugh Wynne, Sanford Bernstein.

Good morning. My question is on page 19, 2013 earnings guidance assumptions. I am looking at Commercial Power and the assumption of $95 million of earnings in 2013 relative to the $6 million earned in the first quarter. I think that reflects the expectation of an award of capacity revenues by the PUCO, if I'm not incorrect.

What should we expect regarding the underlying earnings power of that fleet in the absence of an award of capacity revenues this year? Will it resemble what we saw in the first quarter, or do you expect a material improvement in the subsequent three quarters?

So the other major driver in that segment is capacity prices. So $16 through May of this year; it will go up to $28 in the back half. And then you have energy for the coal and gas fleet, and we have seen trends comparable to others in the Midwest, where we are seeing a little bit more coal generation, a little less gas generation, as prices have risen. So those are the other drivers to think about.

Okay. On 23, you provide an analysis of your weather-normalized generation or Power sales over the last 12 months. On the right-hand column, you can see that it has been broadly flat. Is this a trend you expect to continue, or are there reasons to believe that the last 12 months were somehow different from what we will see in the year or two years ahead?

If you look back at rolling 12 months through the end of '12, we were at 0.6%. If we were to do leap year adjustment on this rolling 12 months, it would be 0.3% overall growth, and we are projecting 0.5%.

So we feel like we are reasonably consistent or in the range with our expectations. We think they are cautious. And as we have done every quarter, we'll just continue to update you on developments that we see. We are seeing strength in customer growth, we are seeing some strength in automotive and our industrial segment, and then some weaknesses in primary metals that I referenced a moment ago.

Great, thank you very much.

Julien Dumoulin-Smith, UBS.

Good morning. So following a little bit up on the North Carolina situation, I wanted to get a little bit more clarity here, because there are just so many different pending filings, including the Supreme Court remand regarding ROE.

I'd be curious, is there any potential for all of these ROEs to kind of be resolved at once, shall we say? Obviously, there is a certain timeline here with which the NCUC needs to address the remand, but they have other rate cases in front of them. Is there any ability to kind of deal with it at once or would your expectation be we will get an updated ROE for a certain period of time, and then we'll have a new ROE effective whenever the subsequent case comes into effect? Just trying to get a sense of the ability to interject -- call it -- new testimony into the ROE and, secondly, the timeline.

My judgment is is there is adequate testimony underpinning the 10.5% ROE in the Duke Energy case that was remanded back. I think what the Commission will do, particularly in light of the motion by the Attorney General, they will probably -- they are probably already going to work to write an order that really underpins the 10.5%. So I think they'll do it seriatim, and that will be first.

I think the second thing that they will focus on is the settlement of PEC with the 10.2%, and that order will probably come on the heels of that. And then subsequently with the new Duke Energy case, that will probably -- we will be working on resolving that through settlement over the coming weeks and months, and that will be third in line. That would be my view of how that unfolds.

Great. And each continue to have a discreetly separate process for setting that ROE?

I believe -- I am confident that's the way it will work, because that makes sense and it's consistent with their traditional practice and procedure of the Commission.

Great. Going back to the International business for a second here, obviously, there have been some acquisitions -- Chile, there has been some commentary around Peru. What is the thought process as we sit here today around expanding the business, given the cash balance? Is this a year for more expansive deployment of that balance?

Julien, we continue to look for opportunities to grow the business that are consistent with our return expectations, the countries we like. Generation is kind of the part of the system that we are interested in. And I would say our aspirations this year are no different than they are any year. If we find an asset that fits with us and meets return expectations, we would pursue it. And we have been systematically, over the last five years, adding in a moderate way assets that are complementary to our portfolio.

Any particular markets as it stands today that you are focused on?

Well, we were focused on Chile in '12.

Fair enough. Thank you.

Andy Bischof, Morningstar.

Hi, good morning. I was wondering if you could just comment on the level of switching from gas back to coal in your generation portfolio. A couple of your peers have posted pretty dramatic shifts in their generation mix compared to 2012.

Andy, what I would say is, in our Midwestern suite, we have seen an increase in coal generation and a decrease in gas generation, really consistent with the fact that those assets -- coal assets are positioned very favorably for transport.

In the Carolinas, we haven't seen what I would call switching, but we have seen higher capacity factors of our coal plants in our Duke Carolinas territory. The transportation, as you know, in the Carolinas is a bit more expensive and the price at which gas is advantaged to coal is a bit higher.

And what is that price in the Carolinas?

I would say probably $4.50-ish.

I think that's the price when -- once gets gas gets to $4.50, then we turn on the Cliffside plant, because it's our most efficient coal plant.

Thanks for the clarity.

Ali Agha, SunTrust.

Thank you, good morning. I wanted to get a little more insight. On one of yours slides, you talk about an EPS growth of 4% to 6%. That's the aspiration from '13 through '15. And you look at your Commercial Power, you are at a cyclically low point here because of the capacity payments. Internationally, you've talked about the fact that the hydro situation is hurting you right now. You have that wholesale growth coming up next couple of years, cost reductions ongoing.

I am just curious -- I would have thought the growth rate would be somewhat higher given the cyclically low '13 that we're looking at. Can you give me a little more insight into how we keep it in that 4% to 6% range?

We are smiling at the question, because I think our questions have primarily been how could you possibly get to the high end of the range. And you are arguing why aren't we higher, which we are delighted to hear.

The 4% to 6%, we think is a reasonable expectation. You have talked about Commercial certainly contributing to that. And then we look at franchised electric and gas, with the key drivers being rate base, our merger synergies, the continued focus on driving costs out of the business.

So we have a high degree of confidence of hitting the 4% to 6% range. And as we see these fundamental pieces coming into place in '13, with rate cases and other things, I think we'll be able to give you a better sense of what '14 and '15 could look like as the year progresses.

Okay. Understand. The largest job obviously is the regulated this mess, and that dominates the percentage growth (multiple speakers).

Absolutely.

Second question. On Ohio, just to be clear, Jim, on the strategic plan there, you had gone down the path of looking to potentially exit the merchant generation business. Then the capacity case obviously came up and you want to play that out.

Once that decision comes out, whether you get it or not, regardless, but once that decision is out, strategically, does that merchant portfolio still fit with Duke, or would it still make sense to focus more on the regulated and get out of that volatile business?

That's a good question. I think we are going to wait and see what the decision is from the Ohio Commission, and then we're going to make a decision with respect to those assets. I think it would be premature to comment on what we would do, but we believe we are entitled to this capacity payment. And if we don't get it, I think we will have to make a tough decision about those assets going forward. But more to come on that. Our focus is on creating value and reducing the risk of our portfolio, and so we will make a decision consistent with that.

Okay, so I should not assume -- just to be clear on your thinking -- if you do get the capacity payment, that does not necessarily mean that you're going to still own those? You could still go down the divestiture path?

Ali, I think we will have to wait and see the conditions of the order from the Commission. So at this point, we are under order to move the assets out of the utility to an affiliate by the end of 2014, and I think we will just await any clarity the Commission would provide on that as part of the cost-based capacity order.

I think the other dynamic that plays into this is also the movement in gas prices. I mean, this time last year, gas was about $1.87 an MMbtu. It averaged $3.48 an MMbtu last year, and now we're in the $4.40 range. And some people are predicting we will be to $5.00 to $5.50 before year-end in gas prices. So that will have a significant impact on the value of the coal plants in the Midwest, as well as the gas plants as we look forward.

That's good. Thank you.

At this time, I would like to turn the call back over to Mr. Currens for any additional or closing remarks.

This is Jim Rogers stepping in for Bill. I want to thank you all again for your interest and your investment in Duke Energy. We are off to a strong start in 2013. I want to reemphasize the fact that we are on plan and we are moving forward to hit the numbers this year, and we look forward to keeping you informed as the year goes on. Thank you all.

That does conclude today's conference. We appreciate your participation. You may now disconnect.