Earnings Call: Q1 2013

May 3, 2013

Good day, and welcome to the Duke Energy First Quarter Earnings Call. Today's conference is being recorded. At this time, I would like turn the conference over to Mr. Bill Curran. Please go ahead, sir. Thank you, Marquita. Good morning, everyone, and welcome to Duke Energy's 1st quarter 2013 earnings review. Leading our discussion today are Jim Rogers, Chairman, President and Chief Executive Officer 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. In our 2012 10 ks 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 20 15. In today's call, Jim and Lynn will review our Q1 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, Phil. It is good to have you all on the call today. We are now 10 months into the merger with Progress Energy, and I'm very pleased with how we are executing our plans. Our Q1 performance built on our momentum in 2012. For the Q1, 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're 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 Q1 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 5 should be familiar to you. We've 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 Edwards Port into commercial service and obtaining constructive rate case outcomes. We have requested more than $1,000,000,000 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. 1, fully integrating the merged companies while achieving the targeted savings for customers and investors and 2, optimizing nuclear fleet performance. Our integration efforts are producing results and we're clearly on track to achieve the merger synergies we expected. During the Q1, we achieved $37,000,000 in fuel and joint dispatch savings from our Carolinas fleet. That was in addition to the $52,000,000 in the 1st 6 months of the merger. We're also making good progress on other integration efforts and are achieving labor reductions and other non fuel O and M savings. In fact, about 30% of our merger integration initiatives have been completed. The other initiatives are either on schedule or ahead of schedule. As for our nuclear plants, Thea and his team continued deploying the nuclear operating model across the entire fleet, which includes 11 units in the Carolinas. We're seeing very positive results as measured by our 7 key 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 to complex first of a kind repair. We are finalizing a comprehensive decommissioning plan and we'll file it with the NRC. As you all know, we selected the safe store method. The transition organization is fully staffed. Over the next few months, full time staffing will be significantly reduced from the previous from the 600 previously on-site. Late last year, we entered into a non binding mediation with Neil, our insurance provider, to resolve all outstanding claims related to Crystal River III Unit. In February, both the company and Neil accepted the mediator's proposal, whereby Neil would pay the company an additional $530,000,000 to resolve all outstanding insurance claims related to the plan. We received the $530,000,000 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 plan. The Commission is working with the parties proceeding to finalize the issues that the commission will review. We expect the commission to complete this shortly. Oral arguments before the pre hearing 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 We continue to We continue to pursue combined operating and construction licenses for our proposed Lee Nuclear Station in South Carolina and the Lee Nuclear Station in Florida. Related to the Harris license applications, we have spent about $70,000,000 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'll 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 of financing cost on quit for the Sutton Natural Gas Plant for 1 year. Upon commission approval, the immediate increase to customers would be $151,000,000 There would be another $31,000,000 in year 2 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 8. We are requesting an annual retail revenue increase of $446,000,000 in North Carolina $220,000,000 in South Carolina. In each case, we are seeking a return on equity of 11.25 percent. These rate cases are needed to recover 6 in the Dan River Natural Gas Plant, both put into service in late 2012 and both pre approved by the commissions. The evidentiary hearings on the North Carolina case begins July 8, while the South Carolina hearing begins July 31. We expect rates to 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 Carolina's 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 oppose 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 2 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 $49,000,000 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 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'll update you on our cost base capacity filing in Ohio as outlined on Slide 10. We filed the $728,000,000 request last August. We're 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 begin in April. We presented a strong case and intervenors 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 a 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. $9,000,000,000 of investments adding 6,600 Megawatts of natural gas and coal fired generating capacity. This program gives us the ability to retire up to 6,800 megawatts of our older, less efficient, high midding coal plants in 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 3 new plants online, a combination of natural gas and coal fired units and we're on track to bring our remaining 2 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're now in the final process of completing the testing needed before we begin to bring the 6 18 Megawatt plant into service and deem it operational. Both gasifiers have successfully produced syngas from coal and we produce electricity from both turbines using Syngas, natural gas and a blend of both. We're on track to put Edwards Port 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 past the commercial operating date. Edwards Port 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're building in Eastern North Carolina. We expect to place the 6 25 Megawatt Sutton plant into commercial service during the Q4. It represents the latest step in modernizing and adding more natural gas diversification 1st 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're making the most of the unique strength 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'd like to begin by saying how pleased I am with our Q1 results. Slide 12 provides our earnings summary. As you know, Q1 2013 adjusted diluted earnings were $1.02 per share. These results were on track with our expectations for the quarter, although lower than our Q1 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 Q1. I'll 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, U. S. Franchise Electric and Gas, increased by $0.44 per share. U. 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, Q1 2012 was extremely mild with the Carolinas heating degree days at their lowest level on record for a Q1. Weather during the Q1 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 in 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 $1,000,000,000 in 20.13. This power is sold under various pricing 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 20 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 point 0 $8 annually to earnings in 2014 2015, resulting in an average growth rate of 8% for this business. Partially offsetting these 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'll address International Energy's results, which as expected were 0 point International's results were impacted by lower volumes and higher purchase power costs due to delay in 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 lower 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 Q1 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 Q1 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 258,000,000 shares after the completion of the merger. We now have around 705,000,000 shares outstanding. Turning to Slide 13. I'll 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 Q1, our retail volumes, 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 Q1 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. 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. Excluding 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 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 2,600 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 $600,000,000 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 20.12. 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 3rd and 4th quarters upon approval from our commissions. Our second key driver is the timing of recognizing O and 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 3rd, 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 twenty thirteen compared to 12. 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 4th key driver is significantly lower PJM capacity revenues for our non regulated Midwest generation fleet. As I previously mentioned, in the June 2012 to May 2013 PJM auction, the capacity price declined sharply to $16 per megawatt day from the previous price of $110 per megawatt day. 2013 EPS guidance range. In closing, we are affirming the guidance range of $4.20 to $4.45 for $2.13 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 control and our results in the Q3, 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'll turn it back over to Jim. Thanks, Lynn. With that, let's open up the phone lines for your questions. Thank We'll take our first question from Greg Gordon with ISI Group. Thanks. Good morning. 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 stipulated in the settlement or towards the end of the year? Greg, I'll address that. The CEO selection process is being led by a special committee of the Board. The committee is working with an outside advisor 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's 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, the merger and specific I mean the settlement and specifically the underlying basis for the 10.5%. There's ample evidence in the record and what is expected from the commission and 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. Percent. Thank you very much. Thank you. And next we'll go to Dan Eggers with Credit Suisse. Hey, good morning guys. Good morning, Dan. 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 the commission? Or does it prospectively slowed 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 request that we're making. As a consequence of that, when we enter into a settlement as we have in the Progress Energy case, basically that $10,200,000 is underpinned with testimony and we will file additional testimony when there's a hearing on the settlement. So I think the most important point here is that 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 is ask the commission to explain in much greater detail why they approve the settlement and specifically why they approve 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. Thanks. Thanks. Can I ask one more? I'm 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? Dan, my judgment is, I mean, we've always reached settlements in Ohio, but this one is difficult, if not impossible to reach a settlement. I don't rule out the possibility of settlement later in the process, but I think where everybody's kind of strapped on their position and going full speed before the commission to make the argument. The argument is a strong argument. And if I put my I've 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 1 company versus another company and 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, Len, just one question on commercial power. After the Q1 kind of fairly far off the full year rate and capacity is going to work in the second half. What should we be thinking about that's going to help fill in against guidance where you guys have it today? Dan, we do have an assumption 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 $420,000,000 to $445,000,000 we've assumed a range of outcomes. And so 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. Thank you. Thank you. And next we'll go to Stephen Byrd with Morgan Stanley. Good morning. Good morning. Good morning, Stephen. 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 that the talk a bit to the sort of the execution risk relating to that and the certainty you've been able to achieve that? It looks like good EPS contribution 8% growth. Could you just talk a little bit more about sort of where you stand? You mentioned a few contracts, but just I couldn't kind of relate that back to the overall number? Yes. So, Stephen, 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 2 that we pointed to was a wrap contract or an extended contract with NCEMC in the eastern part of our Carolina 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, Stephen. 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 we'll plan in the back half of the year. Understood. Thank you very much. Thank you. And we'll go next to Jonathan Arnold with Deutsche Bank. Good morning. Hi, Jonathan. 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've had some talk that they might want to really kind of build a buffer ahead of World Cup next year etcetera. So I mean if things don't improve, is Q1 a guide to future quarters? Jonathan, that's a good question. As we've looked at 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 Q1. But what I would also say is this is a situation that we're continuing to monitor and we'll give you an update as the year progresses. Okay. Thank you. And on another front, can you give us a little more insight into what's still showing up in the cost to achieve line? And what kind of time frame 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 'fourteen. Nuclear assets suite, where we're combining systems in the nuclear operation and work management systems, those projects will continue into 2014, 2015 2016. So they will but we'll continue to have costs to achieve for a couple of years. And this sort of Q1 level is probably where we are for the next year or 2? 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. Thank you. We'll take our next question from Michael Lapides with Goldman Sachs. Hi, guys. Can you talk a little bit about good morning. Can you talk a little bit about Crystal River and specifically decommissioning costs and the decommissioning fund? Meaning, what are the variables that could significantly change the expected decommissioning cost of the plant? Where does the fund stand in terms of meeting the decommissioning cost for the 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? Yes. So Michael, I'll start and see if we can resolve. Thea is also here for further discussion on the specifics of the decommissioning plan. But we have $600,000,000 in the decommissioning trust fund, which is a fully funded level assuming that the plant retires in the 2,030 timeframe. Under the safe store 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'll be monitoring it as we go. And you ought to we fixed income that we match to an expectation of liabilities. And we run scenarios and assumptions on costs as well as scenario and assumptions on investment of assets to ensure that we're 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 post shutdown decommissioning activity report and have to outline in that report our estimates as 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'll 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're a good bit ahead on those activities. Basically, we'll just allow most systems to we stop 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 like 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 just 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's in the pool. Other than that, it's really just dismantling the equipment in the manner we go about doing that. Those are the 2 main variables. Got it. Thank you. Much appreciated guys. Thank you. We'll go next to Stephen Fleishman with Wolfe Research. Yes. Hi, good morning. Hi, Steve. Good morning, Steve. I guess in the context of past success, I think you guys have beaten consensus quarters for 3 or 4 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're on plan on internal numbers, Steve. So we did hit plan. Okay. And what we were trying to demonstrate with Slide 14 is sort of the quarterly variability that you can expect as you look at comparables between 12% 13%. So we have a high degree of confidence that we're 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 2014 and then incrementally in 2015? It is. Okay. And the is that matching up with rate base growth in wholesale as well? So when you have wholesale on the slide, is it matching there? Or is it more just tied to contracted price increases? It's load. It's you can think of it as additional load, Steve, 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. Thank you. Thanks, Steve. We'll take our next question from Hugh Wynne with Sanford Bernstein. Good morning. My question is on page Good morning, Hugh. Hi. 2013 earnings guidance assumptions. The I'm looking at Commercial Power and the assumption of $95,000,000 of earnings in 2013 relative to the $6,000,000 earned in Q1. 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 Q1? Or do you expect a material improvement in the subsequent 3 quarters? So Hugh, 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've seen trends comparable to others in the Midwest where we're seeing a little bit more coal generation, a little bit more little less gas generation as prices have risen. So those are the other drivers to think about. Okay. And on 23, you provide an analysis of your weather normalized generation or power sales over the last 12 months. And on the right hand column, you can see that it's 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'll see in the year or 2 years ahead? Yes. And so, Hugh, if you look back at rolling 12 months to 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're projecting 0.5%. So we feel like we're reasonably consistent or in the range with our expectations. We think they're cautious. And as we have done every quarter, we'll just continue to update you on developments that we see. We're seeing strength in customer growth. We're seeing some strength in automotive in our industrial segment and then some weaknesses in primary metals that I referenced a moment ago. Great. Thank you very much. Thank you. Thank you. We'll take our next question from Julien Dumoulin Smith with UBS. [SPEAKER JULIEN DUMOULIN SMITH:] Hi, Julien. [SPEAKER JULIEN DUMOULIN SMITH:] So following a little bit up on the North Carolina situation, I wanted to get a little bit more clarity here because there's 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's a certain time line 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'll 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 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're 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 a 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 will be working on resolving that through settlement over the coming weeks months and that will be 3rd in line. That would be my view of how that unfolds. Great. And each continue to have a discretely separate process for setting that ROE? I believe that I'm confident that's the way it will work because that makes sense and is 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, so there's 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 the kind of the part of the system that we're 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 5 years adding in a moderate way assets that are complementary to our portfolio. Any particular markets as it stands today that you're focused on? Well, we were focused on Chile in 2012. Fair enough. Thank you. Thank you. We'll take our next question from Andy Bischoff with Morningstar. Hi, good morning. Good morning. Good morning. I was wondering if you could just comment on the level of switching from gas, pet coal in your generation portfolio. A couple of peers have posted pretty dramatic shifts in their generation mix compared to 2012. And Andy, what I would say is in our Midwestern fleet, we've 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 expensive and the price at which gas and coal gas' advantage to coal is a bit higher. And what is that price in the Carolinas? I'd say probably $4.50 ish. I think that's the price, Lynn, that once gas gets to $450,000,000 then we turn on the Cliffside plant because it's our most efficient coal plant. Perfect. Thanks for the clarity. Thank you. And we'll take our last question from Ali Agha with SunTrust. Thank you. Good morning. Good morning. Good morning. I wanted to get a little more insight. On one of your 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're at a cyclically low point here because of the capacity payments. International, 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'm 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? Ali, we're 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're arguing why aren't we higher? We're delighted to hear. The 4% to 6% we think is a reasonable expectation. You've talked about commercial certainly contributing to that. And then we look at franchise 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 'thirteen with rate cases and other things, I think we'll be able to give you a better sense of what 'fourteen and 2015 could look like as the year progresses. Okay. I understand. The largest chunk, obviously, is the regulated business and that dominates the percentage growth gone down. Sure. 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're 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'd be premature for me to comment on what we would do, but we believe we're entitled to this capacity payment. And if we don't get it, I think we'll 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'll 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'll 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'll 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 at MMBtu. It averaged $3.48 at MMBtu last year and now we're in the $4.40 range. And some people are predicting will be to $5 to $5.5 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. Understood. Thank you. Thank you. At this time, I'd like to turn the call back over to Mr. Kearns 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're off to a strong start in 2013. I want to reemphasize the fact that we are on plan and we will we're 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.