Earnings Call: Q1 2015

May 1, 2015

Good day, and welcome to the Duke Energy First Quarter Earnings Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Bill Curran. Please go ahead, sir. Thank you, Derek. Good morning, everyone, and welcome to Duke Energy's Q1 2015 earnings review and business update. Leading our call is Lynn Good, President and CEO along with Steve Young, 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. A reconciliation of non GAAP financial measures can be found on 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. As listed on Slide 3, Lynn will begin with an update on our principal Q1 activities. Then Steve will review our 2015 Q1 financial results, including an update on what we are experiencing in Brazil. Finally, Steve will close with an update on economic activities within our service territories as well as a review of our recently announced $1,500,000,000 accelerated stock repurchase program. With that, I'll turn the call over to Lynn. Good morning, everyone, and thanks for joining us. With the first quarter behind us, I'm pleased to report that we are on track to meet our financial objectives for the year and are demonstrating strong operational performance for our customers. We are making progress on our near term objectives and achieving important milestones on the strategic initiatives we announced last year, including growth investments totaling $8,000,000,000 Our strategies reflect a focus on new generation investments, electric and gas infrastructure and contracted renewable opportunities. Now let's focus on the quarter. This morning, we reported 1st quarter 2015 adjusted EPS of $1.24 We also affirmed our full year to 2015 guidance range of $4.55 to $4.75 per share. Steve will provide more details on the quarterly results in a few minutes. Let me start with reviewing a few operational highlights as outlined on Slide 4. I'm pleased with how our system performed during record cold temperatures during the Q1. On February 20, we set new all time peak demand records in the Carolinas. Our teams demonstrated exceptional preparation and collaboration across the company in meeting this challenge. Our generation fleet performed well during these periods of record demand as our customers benefited from our diversified portfolio of generation resources. The regulated natural gas fleet set a record for the quarter delivering more than than our customers. The fleet achieved a quarterly capacity factor of almost 94%, led by the Robinson and Harris plants, which set generation records for the quarter. We also recently learned that our nuclear fleet as a whole led the nation's large nuclear fleets in 2014 as measured by several key performance indicators. Our operational teams also responded to a series of major winter storms. In the Carolinas alone, 3 severe storms caused more than 1,000,000 power outages. We used the scale of our company to effectively prepare for and respond to these challenges. For example, in one major storm, we deployed more than 3,500 workers and restored power to 85 percent of the affected customers within 24 hours. Our ability to restore in the wake of storms was recognized in March by EEI. We were awarded the institute's Emergency Recovery Award for our restoration efforts of the winner of 2014. Our Edwardsport IGCC plant in Indiana also performed well during the Q1. We believe the best measure of performance for Edwardsport is over a long term basis. However, it's worth highlighting that the plant achieved 79% gasifier availability, representing its highest individual quarter yet. After last winter's challenges, we made a number of enhancements to the plant driving this year's performance. We expect orders from the Indiana other important strategic and regulatory priorities, which I'll briefly cover on Slide 5. We achieved a major milestone in our proposed $1,200,000,000 acquisition of jointly owned generating assets from the North Carolina Eastern Municipal Power Agency. State legislation that enables these municipalities to issue revenue bonds was finalized in March. And it also allows Duke Energy Progress to recover through a rider mechanism, its retail investment and operating costs associated with the acquisition. This important legislative milestone follows last December's approval by FERC. We remain on track to close the acquisition later this year once we receive approvals from the NRC, all 32 individual municipalities and the state regulatory commission. Once closed, we expect an annualized incremental earnings per share impact of between $0.05 $0.10 The plan to acquire these generation assets is a win win for all parties involved. The municipalities in Eastern North Carolina get rate relief, which will be a boost to economic development in the entire region. And our Carolinas customers will enjoy significant fuel savings through the addition of valuable nuclear and coal generation capacity to our supply mix, helping to mitigate the impact of the purchase on retail customer rates. In March, we filed with the FERC for approval of our proposed purchase of Calpine's Osprey combined cycle gas plant in Florida. This 5 99 Megawatt plant will help offset the impact of system retirements. If the ops repurchase is not approved in a timely manner, we have requested state commission approval to build 3 20 megawatts of new combustion turbine capacity at our Swan East site. We have requested FERC approval by July 30. In early April, the Ohio Commission approved our next 3 year electric security plan or ESP. The commission approved our request for 2 important rider mechanisms, a distribution capital investment rider and a storm cost rider. Parties including Duke Energy Ohio have until May 4 to file for a rehearing. We are evaluating this option for certain a it. Earlier this week, the Florida legislature passed new utilities regulations, including a provision allowing securitization of our remaining Crystal River III costs. This law is still subject to being signed by the Governor. As you will recall, our 2013 settlement in Florida included a provision allowing us to begin recovering up to $1,460,000,000 of Crystal River III assets in customer rates by the beginning of 2017. This securitization would allow us to provide a significant rate benefit to our customers while also providing full cash recovery of these investments. If signed by the Governor, we anticipate seeking Florida Commission approval later this year to issue bonds in early 2016. Also in early April, we successfully closed on the transaction to sell our Midwest commercial generation business to Dynegy for $2,800,000,000 in cash. With the sale complete, we've been able to sharpen our focus on the regulated business and quickly redeploy the proceeds to ensure an accretive transaction within the 1st 12 months. In a moment, Steve will discuss the use of proceeds. Our international business has been experiencing challenges due to the continued drought conditions and a softening economy in Brazil as well as weaker foreign currency exchange rates and lower MTBE prices at National Methanol. Steve will provide more detail on what we are experiencing during his prepared remarks. Next, I'll provide an update on our coal ash management activities. We have been taking action to improve our management of ash across each of our jurisdictions in a manner that protects the environment and our communities. As you may recall in February, we reached a proposed plea agreement with the U. S. Government. If approved, the agreement would close the federal investigation related to the Dan River coal ash spill and basin operations in North Carolina. In April, the judge granted a 4 week continuance of the hearing to May 14 to allow the court more time to prepare. As a consequence of this misdemeanor plea, we are working through an agreement to avoid debarment with the EPA. We have been working for some time on this proposed agreement and our target is to have it in place by the sentencing hearing on May 14. If an agreement is not in place by this date for some period of time, we would need to obtain prior approval before entering into new or modified contracts with federal government agencies. This is not expected to result in any material financial or operational impacts. We have been actively working on plans to close all of our ash basins in North ash excavation of ash at the initial 4 high priority sites. These permits, which we applied for last year, are being reviewed by Deaner. We expect to be able to begin moving ash later this year. We also continue to develop plans for our remaining 10 sites in North Carolina. And finally, we expect to begin moving ash from our W. S. Lee plant in South Carolina later this month. Environmental matters including ETA regulations are certainly a focus of ours over the coming years. The ETA's proposed Clean Power Plan creates aggressive state specific targets to reduce CO2 emissions. The plan is scheduled to be finalized this summer and includes some of the most far reaching and complex regulations the industry has ever faced. We continue to engage with the EPA and states and support policies that reduce carbon emissions over time without jeopardizing reliability and affordability. This is not a one size fits all solution to this issue and that's why it's important that our states maintain flexibility as they develop plans to comply with the final targets. I will also mention that the EPA published its final coal combustion residuals rule in the federal register on April 17. This new rule regulates the disposal of coal ash and is applicable to all new and existing landfills, structural fills and new and existing ash basins at active sites. We have already begun a site by site evaluation to determine our plans for compliance with these federal provisions across each of our jurisdictions beginning later this year. Additionally, in North Carolina, we must also comply with the state's Coal Ash Management Act, which requires the closure of all basins in the state over the next 15 years. Since the federal and state rules contain some conflicting provisions, such as different compliance timelines and groundwater monitoring requirements, our actions will be based upon the most restrictive provisions. We have already recognized $3,500,000,000 in asset retirement obligations for our North Carolina sites to comply with the state legislation. The new federal rules will result in actions in our other jurisdictions, in particular Indiana, where most of the remaining ASH is located. We will recognize incremental asset retirement obligations for the federal rules in the Q2. However, similar to the North Carolina rules, any closure costs are expected to be incurred over a long term time horizon. In closing, we're on track to meet our objectives for the year with a strong focus on operational excellence and financial discipline. We are moving forward responsibly in our ASH management plans. We are successfully executing on the growth projects and strategic initiatives announced last year, positioning Duke Energy for long term success. Now I'll turn the call over to Steve. Thanks, Lynn. Today, I'll review our Q1 financial results and discuss the economic conditions within our service Finally, I will briefly review the accelerated stock repurchase plan we launched in April with the Midwest Generation sale proceeds. Let's start with the quarterly results. I will cover just the highlights on slide 6. For more detailed information on segment variances versus last year, please refer to the supporting materials that accompany today's press release. We achieved 1st quarter adjusted diluted earnings of 1.24 dollars per share compared to $1.17 in the Q1 of 2014. Strong results from our regulated utilities and commercial Midwest generation business helped offset weakness at international. On a reported basis, 2015 Q1 earnings per share were 1 point 22 compared to a net loss of $0.14 last year. The loss in last year's reported results included a pre tax impairment charge of approximately $1,400,000,000 or $1.23 per share related to the Midwest Generation Business. Let me briefly review key quarterly earnings drivers at each of our business segments. On an adjusted basis, regulated utilities delivered higher results of $0.05 per share, primarily due to increased wholesale margins and higher retail rates, including energy efficiency cost recovery mechanisms. Similar to last year, we experienced cold weather during the quarter, so it was not a significant quarter over quarter driver. These positive drivers were partially offset by a slight decline in weather normalized retail load growth. I'll provide additional details on that in a moment. Our regulated utilities also realized higher O and M costs during the quarter. As you will recall in 2015, we are targeting increases of O and M cost at regulated utilities below the level of retail load growth. Our quarterly results were also impacted by the timing of items, including scheduled fossil plant outages, nuclear outage cost levelization and winter storm costs. We remain on track to achieve level of O and M costs during the year. Our Commercial Power business contributed increased earnings of $0.12 per share, driven by higher results from Midwest Generation. Earnings from Midwest Generation were supported by higher PJM capacity revenues and favorable pricing on generation volumes without significant hedge positions. Due to the sale completion, this is the last quarter that Midwest Generation will be included in our results. Additionally, we incurred slightly lower quarterly results from our commercial renewables business due to lower wind production, which was experienced across the United States. This business remains on track to achieve its targeted $100,000,000 of net income for 2015 as we put significant additional wind and solar capacity into service later this year. International's quarterly earnings declined by $0.13 over last year due to the factors we have been monitoring for some time, the ongoing drought, lower electricity demand and weakening foreign currency exchange rates in Brazil, as well as low MTBE prices at National Methanol that are directly correlated with Brent's oil prices. Let me spend a few minutes discussing conditions in Brazil. Setting aside foreign currency, there are 2 key factors impacting results, Generation Dispatch order and demand for power. First, let's discuss dispatch order. In response to the ongoing drought, generation dispatch has fundamentally changed in an effort to preserve reservoir thermal As a result, the hydro generators operate less and are now at the margin bearing the risk of softening demand. This brings us to the second factor, demand for power. Brazil's slowing economy and the effect of voluntary energy conservation efforts have resulted in lower demand for electricity. Brazil's demand for power has typically grown at greater than 3% over the past several years. We now expect demand growth for 2015 to be between 0% 2%. This coupled with the impacts of the revised dispatch order results in significantly less hydropower production than in previous years. As you compare our expected results in 2015 to what we incurred in 2014, there are several factors to consider: hydro dispatch, the allocation of assured energy and market prices. 1st, hydro dispatch in the Q1 of and we expect this dispatch order to continue throughout the remainder of the year. Secondly, in 2014, given the way the hydro system generators shaped their assured energy for the year, we were allocated higher percentages of energy in the first half of the year with lesser percentages being allocated to the second half. In 2015, on the other hand, we were allocated less energy in the first half of the year and more in the back half. The combination of these factors has resulted in a short position so far in 20 15, whereby contracted energy sales exceed the allocation of hydro generation. We are required to settle this short position in the market at a capped settlement price or PLD of R388 dollars per megawatt hour. In contrast, in early 2014, these same factors resulted in a long position, whereby the allocation of hydro generation exceeded our market price of up to BRL 8.30 per megawatt hour. Over the remainder of the year, we expect to be in a net short position. However, the level of this short position should moderate over the second half of the year, resulting in greater comparability with the second half of twenty 14 than what we are seeing early in the year. We are taking actions to mitigate some of the financial exposure we are experiencing. Entering 2015, we reduced our contracted position in Brazil from 93% to 91% and we are considering further reductions to our contracted percentage for 2016 if conditions do not improve. We have also identified opportunities to achieve cost efficiencies throughout the international business and have already instituted headcount reductions of approximately 15% or over 100 positions. We will continue to evaluate further efficiencies as we move forward. We will closely monitor impacts from the deteriorating demand for International to meet its financial plan for the full year. We will continue to update you as the year progresses. Moving on to slide 8, I'll now discuss our retail customer volume trends. As we outlined in the Q4 call, weather normalized load growth in 2015 is expected to be in the range of 1.5% to 1%. On a rolling 12 month basis, weather normalized retail load growth was down 0.2% through the Q1. Weather normalized load growth for the Q1 of this year is in line with our budget. However, the comparison to the prior year is challenging as the Q1 2014 results included 2.6% weather normalized load growth due to the unusual impacts of last winter's polar vortex. Within the residential sector, we continue to experience strong growth in leading to a decline of 1.4% in residential volumes over the rolling 12 months. This decline is primarily attributable to the strong 2014 results, but is also impacted by energy efficiency as well as changing usage patterns. We continue to see favorable trends in the key indicators for the residential sector, namely full time employment and median household income. I've discussed these metrics before and they continue to move in the right direction. Additionally, we see an increase in manufacturing jobs in our service areas, along with some positive data on new housing starts. The commercial and industrial sectors continue to show growth of 0.2% and 1.2% respectively over the rolling 12 months. The commercial sector is driven by declining office vacancy rates and expansion in the health and food service subsectors. As for the industrial sector, metals, transportation and chemicals continue to drive growth in the Midwest and Carolinas. One factor that we are closely monitoring is the impact of the strong U. S. Dollar, which could hamper domestic manufacturing activity. We have not seen significant impacts of this dynamic with our industrial customers to date, but we'll continue to closely monitor trends. Our economic development teams remain active, successfully helping attract new business investments into our service territories. During the quarter, these activities led to another $1,200,000,000 in capital investments being announced, which is expected to result in almost 3,000 new jobs across our 6 state footprint. Before closing, I'd like to briefly cover the mechanics of the recently launched $1,500,000,000 accelerated stock repurchase program, as outlined on slide 9. In early April, after closing on the sale of the Midwest Generation business, we began the program. We immediately received and retired 16,600,000 shares, which is 85% of the total expected to be retired. The program will be completed by the end of Q3 of this year. The actual number of shares repurchased will depend upon the daily volume weighted average price of our stock during the term of the program. The timing of the close of the sale was ahead of what we planned for in our 2015 earnings guidance presented in February. This allowed us to accelerate the deployment of the proceeds and launch the share repurchase. Additionally, the Midwest Generation business contributed stronger results during the quarter than we expected, earning almost our full 6 month assumption in just 3 months. For the full year, the early close of the sale and timing of the ASR are slightly favorable to our overall financial plan, offsetting some of the weakness being experienced term and longer term. We have a strong established track record of achieving these objectives and we remain on track to continue meeting them in 2015. The strength of our balance sheet underpins our ability to access the debt markets on reasonable terms. This helps fuel our growth strategy, support the dividend and maintain low cost rates for our customers. In early April, we were pleased to receive an upgrade to our credit ratings at S and P. This upgrade resolves S and P's positive outlook on the company, which was initiated last fall. Related to the dividend, we our target payout ratio and the Board now has the flexibility to consider growing the dividend more in line with our earnings growth over time. We are off to a strong start to the year on our regulated business and are executing on our strategic initiatives. We are closely monitoring developing trends in our international business and are taking actions within our control to react. We expect unfavorable variability in the international business in the Q2 due to the factors I previously discussed as well as the absence of a favorable tax benefit in Chile that impacted prior year results. This negative variability to the prior year is expected to moderate in the back half of the year. We are also taking a hard look at our cost structure. We remain on track to achieve our 2015 guidance range of between $4.55 to $4.75 per share and continue to target earnings per share growth of between 4% to 6% through 2017. With that, let's open the line for your questions. Thank you. Our first question comes from Daniel Eggers with Credit Suisse. Comments you guys made. Good morning. Hey, good morning. Is the usage comparison down at this point in time? Is that really just a function of the math behind the Q1 of 2014 kind of trying to discern weather versus usage? Or is there something more structural happening? I couldn't figure out what that Q1 comp is doing to this number. I think that the Q1 comps are influenced by what happened in the Q1 of 2014. And let me recap a bit. We're about flat on the rolling 12 month variance overall. Industrial is 1.2% growth, continuing being around 1% which we've seen really since 2011 on a consistent basis. Commercial has been growing also. It grew at about 0.2%. That's lower than what we've seen in the past. But we continue to see in the commercial sector some strength as vacancy rates are declining, health care and foodservice are strong. We did see some softening in government a bit. But overall, I think with new people moving into our service territories, commercial is poised to continue to grow. Residential is where we saw the decline. And there I do think part of the decline in residential of 1.4%. Roughly half of that you could attribute to the anomaly of the 2014 results of the people were literally forced to stay at home due to the weather and it was hard to model that accurately. When I look at residential, I do continue to see usage per customer going down due to energy efficiency, due to people living more in smaller spaces condominiums and apartments than perhaps we've seen in the past. But on the flip side of that, I also see that we are adding customers particularly in the Carolinas and Florida sector very strongly. We see unemployment continue to decline and median household income rise. We also see some favorable housing data. Existing home sales are increasing, which should lead to some new home building. So those are factors that offset the energy usage. The question we ask is when does the saturation hit on energy efficiency at residential? And when does the core growth overtake that? That? So we'll keep an eye on those factors. But I think the fundamentals of our service area economies are ultimately very solid. So the this usage comp right now because there's going to be some friction in the this usage comp right now because there's going to be some friction in the weather adjustments? That's correct. I think there will be always rolling 12 month average. The base period is going to have some of that in it from the polar vortex of 14. I think I'd look at other trends there as well. And I think 1.5% to 1% is certainly still a reasonable estimate for where we're going. And Jan, the one thing I would add to that, if we look at these results relative to how we planned the year, we're on plan. So that's another indication of the international, given the obviously slow start to the Q1 and probably rough looking Q2 given the Brazil dynamics, what is your confidence in getting to the full year guidance you guys have laid out for there? And if you're coming light there, where do you see the business making out more of that earnings? Well, I think the International segment will have challenges February at about 345,000,000 dollars of net income. We recognize that and have discussed that thoroughly. I think there are offsets to that in our other businesses. We have seen favorable weather in the Q1 and that's in the bank. Our ability to accelerate the share repurchase program due to the close early closure of the sale is accretive to us by in the neighborhood of $0.04 We were fortunate in that we got our full earnings estimate out of the Midwest Generation business in the Q1. It was a very good quarter for that business. So the acceleration of the share repurchase should all inure to the bottom line to us. So that's favorable as well. So I think we've got levers in our cost structure as well to pull that can help us offset some of the shortfalls in international. The other thing I would mention Dan is we've been moving more rapidly through the approval process generation assets from NCE and PA. In our planning, we assumed all of that benefit was in 2016. And it looks like we're tracking ahead of that. So that's another thing I'd point to. Okay, very good. Thank you, guys. Thank you. Thank you. Our next question comes from Shahriar Pourreza with Guggenheim. Good morning. Good morning, Shahriar. Good morning. So just on the international business, Steve, you provide pretty good sensitivities around Brent and exchange rates. Is there any way to price the risk around the weak hydrology conditions and even sort of what you're seeing from an economic development in Brazil? Sure. That's difficult to put a sensitivity to. It is hard to predict the impact on demand on electricity usage. It's more volatile than in the U. S. Last year, it was 3.7% for the entire year and was over 7% in the Q1 and then it changed throughout the year. So it's more volatile there. Additionally, it is difficult to predict what the spot pricing might be given the lower demand. The cap is 388 AIs, but where spot pricing settles under that cap is hard to know and that affects the bottom line there. So it's hard to give a sensitivity there. We'll just have to keep an eye on it as we move forward. Got it. And then just in the U. S, it seemed like you're in a really good spot. You've sold the assets in the Midwest. You're doing the buyback program. Can we maybe just get a little bit of a refreshed view on your growth avenues? And maybe just focusing a little bit outside of the current gas projects, generation projects maybe centered around more midstream or muni acquisitions in the area? Sure. Let me take a shot at it and Steve can add to it. I kind of think around the jurisdictions on where growth is coming from. And if we start in Indiana, it's grid related growth. We filed for a $2,000,000,000 investment in grid related reliability and optimization projects. That's moving through the regulatory process. We also have distribution and transmission investment in Ohio. And in the remarks, we fact that under our ESP, we have an approved tracker, which gives us timely recovery of those investments, which we think is positive. I think in the Carolinas, you're familiar with the generating assets, gas plant, the pipeline you're familiar with. We also are investing $500,000,000 in solar, about half of which of it of that will be owned generation. And then in Florida, we have close to $2,000,000,000 of investment on generation in the Citrus County in Osprey or Suwanee investment. So those are the things I would point to as kind of unfolding. We're moving through regulatory approval processes on each one of those. And of course, continuing to look for ways that we can put capital to work for the benefit of customers. Got it. Got it. And then just one last question around the dividend. Currently, maybe we could just get a viewpoint on the policy especially as your earnings growth trajectory is where it is kind of where you'll be around the target range of where you want to be? Steve, do you want to take that one? Sure. Our dividend has been growing at 2%. And of course, our earnings have been growing in the 4% to 6% range. And that was just to help calibrate and get back within our target range after the issues that occurred during the financial crisis and the merger with Progress. And we've now gotten to a point where we are within that target be to have the dividend grow closer to the earnings growth rate. So that's where we're headed. Excellent. Thank you very much. Thank you, Shahriar. Our next question comes from Michael Weinstein with UBS. Hi, guys. Good morning. Hey, Hey, I was wondering if you could discuss a little bit about the puts and takes of the securitization bill in Florida for Crystal River? Sure. Michael, it is legislation that has passed both houses. It is awaiting signature from the government or governor. It is a part of a regulatory reform bill that worked its way through the House and Senate in Florida. And we see it as a great opportunity for us to bring a rate reduction to our customers so that when the Crystal River investment goes back into rates, it will go back into rates at a lower amount for the benefit of the customers in Florida. And it does also give us accelerated recovery of the cash investment as we would securitize the investment. We still have some gates to go through, Governor's signature being one that I mentioned. We will also need to file for approval with the Florida Commission. We'll need to issue the bonds. And then, I think strategically is very valuable to our utility in Florida and to our customers in Florida. Great. And have you had any indications at this point at this early stage about how capital or coal ash remediation might be treated? Would it be given full rate based treatment? Or is it something that would be similarly securitized in some way? We are early in the process of beginning the actual investment of dollars around the ASH remediation. You may recall that our first commitment is to excavate 4 sites between now and 2019 in our capital plans for that period. We're at $1,200,000,000 $1,300,000,000 for those sites and are developing plans for the remaining sites. So the spending will ramp up over the next 4 years, but really continue for 10 to 15 years as we address the remaining sites. Our intent would be to present these costs for review by the North Carolina Commission later in the decade when we have a regularly scheduled general base rate case. And that will be something that I would see maybe 2018, 2019. And that's the path we're on at this point, Michael. And our focus is getting the approvals from the state necessary to begin the excavation movement of ash and that's been our primary focus at this point. Great. One last question. I think you mentioned that you thought the second half of the year would be better than the first half of Brazil. I'm just wondering if you could explain that a little bit more. We were talking about comparability to prior year, Michael. So let me ask Steve to weigh in. Yes. What we're referring to is, as Lynn said, comparability. I think Brazil will be challenged throughout the year because demand is lower. There have been informal rationing implementations that will affect demand as well. But it will be more comparable to the last half of twenty fourteen as thermals were dispatched in the last half of twenty fourteen and some of the similar effects that we're seeing now started to move into place. That was the reference we're making there. Okay, great. Thank you. Thank you. Next we'll hear from Huynh with Bernstein Research. Hi. Hi, Huynh. Hi, Huynh. Hi, Huynh. Hi, Huynh. Hi. I wanted to follow-up on a couple of those recent questions regarding coal ash and the international operations. You mentioned that the ARO in North Carolina was about $3,500,000,000 Is the Indiana ARO for coal ash removal likely to be of a similar magnitude or are you expecting it to be materially less? We would expect that to be less, Hugh. There's less wet tonnage of ash in Indiana by it's roughly a third. And we're running numbers now. We will probably disclose a range in the upcoming 10 Q and book it in the Q2. But it will be a smaller number than what we've seen in the Carolinas. Okay. And then are these costs are these future removal costs primarily expenses? Or is a very substantial portion of them likely to be capital investments? The way the accounting works on coal ash here is that we will book an estimate of the liability here and the offset to that will be plant in service and assets or for retired plants a regulatory asset. And then we'll work with the regulators on recovery of these costs and effectively amortize the regulatory assets in conjunction with the regulatory treatment from the regulator. So that's the way it's going to appear on the books, primarily on the balance sheet until we understand recovery mechanisms at this point in time. Okay. And that will be kind of a commission by commission discussion whether there's any return allowed on some portion of these outlets? Well, that's correct. Ultimately, the commissions will determine what's to be recovered over what time frame. They'll have great flexibility to that. And I would add as actual costs are incurred, they will be charged against the overall liability that's booked on day 1. Again, balance sheet oriented until we know what the commission recovery mechanisms are. And Hugh, I would think about this as a decommissioning type cost that is something that the industry and certainly we have been aware of for decades, but we're reaching a period where not only are we retiring plants, but we now have federal legislation and in the case of North Carolina state legislation. All of our jurisdictions have addressed federally mandated costs in a constructive way over time. And so we are executing this to achieve closure in the time frames required and the methods required. And we'll continue to update you on both the costs that we incur as well as the timing for presentation to regulators. Got it. That's very helpful. Just a quick question follow-up question on Brazil. Is there is your expectation that it's going to take a period of quarters or even years for hydroelectric output to normalize? I guess in my mind, I'm thinking that if hydroelectric facilities or anything like bathtubs, you probably have to have more water go in than is coming out for the level to rise. And that might take several years of normal or above normal hydrology. Is there a kind of a permanent or I shouldn't say, Cronin, is there a long term drag to the earnings power of the hydroelectric assets in Brazil as a result of these 2 years of drought? Well, Hugh, one thing I might state there, I do believe that the Brazilian authorities will continue to run thermals through the next rainy season, which will carry you into 2016. So that will have some dampening effect on Brazil results in and of itself. Beyond that, it is hard to say what pricing might be contracting levels and demand might be. Brazil has a number of issues going on politically, social unrest, etcetera that could affect these results. But the one thing I would say is I do think thermals will be dispatched through another rainy season. And Hugh, we have in the the reservoirs are low, but they're moving up. I think the rainy season in 2015 will be extraordinarily important. And the system operator is using thermals as a method of restoring those reservoirs. That coupled with weakened demand is increasing the reservoir level. And I think that ultimately will be a big indicator of how long the country continues to experience the effects of the drought. Great. Can you all provide color on your comment regarding the threat of debarment and what impact that might have on contracts with the military or other elements of your commercial business? Yes. So this is a consequence Hugh, of the plea in the investigation that we entered into in February. And we have been working actively through reaching an agreement on this and have a hope and expectation we can finalize by May 14. But if not, we will continue to move forward working to resolve this issue. It only relates to new and modified contracts. So we do not see an impact on our ability to provide power to the important bases that are in our service territories. We do not see any material financial or operational impact as a result. But it's a consequence. We need to work through it and that's what we are focused on. Got it. All right. Thank you very much. I appreciate it. Thank you. Thank you. Next we'll hear from Chris Turnure with JPMorgan. Good morning guys. I wanted to circle back to Florida and the securitization of the Cristal River III money. Was this expected by you guys? How does it fit into your financing plans over the next couple of years? And your prior statement that you don't need equity through 2017, I think? And also could you quantify the potential number for the securitization for us? You want to take it Steve? Yes. Some of the facts there. I think the securitization will be around $1,300,000,000 $1,400,000,000 And the way it will mechanically work as Lynn said early in 2016 if things move along properly some operating company level debt down at Duke Energy Florida. The remaining half proceeds will be dividended up to the parent and will be used to help fund and finance growth projects. And this was not in our initial financing plan that we presented back in February. Okay, great. And then going back to the North Carolina muni purchase, you mentioned it's going along a little bit faster than you had originally anticipated. What's the potential timing there for final closure now? I guess it's at some point before year end, but when do you think specifically the NRC will come out with their decision? And then also my understanding was that you didn't need any kind of specified regulatory recovery mechanism there, but you got this rider in the legislation that was signed early last month. Could you just clarify that a little bit? And if anything has changed versus how you expected to recover the assets? So I think, Chris, you've got the elements there. There are 3 approvals required NRC and we're hopeful that that will move through over a few months. So we expect that to be before the end of the year. And the thing that's interesting about the NRC approval, these are plants we already operate. We operate the Brunswick and Harris plant. So we'll be working through that diligently to secure that approval. Then the 32 municipalities need to approve. We think that will occur quite quickly over the next month or so. And then we need approval from the NCUC. The rider mechanism that you talked about has already been approved through the legislature, so it will be a matter of implementation here in the state. So when we look at the big issues that were obstacles to closing, it was FERC approval and it was Okay. So Okay. So the rider doesn't improve your outlook in any way that was expected and that's required to close in the call center. It is from a cash standpoint, it's a rider, so you get more timely recovery, cash recovery, Chris. And we would always have assumed that we could record some return. And from an earnings standpoint, the profitability from this is the attended wholesale contract with these same municipalities. They were self supplying when they own the asset. We bought the asset. We will now supply them at a FERC regulated rate. We purchased the asset at a price that did not distort retail rates in any fashion. So it's fairly revenue neutral there. The profitability is on the large wholesale contract that follows it. Okay, great. Understood. Thanks. Thank you. Next we'll hear from Jonathan Arnold with Deutsche Bank. Hey, good morning guys. Hi, Jonathan. Hello. Could you just remind us as you're thinking about the plan today, important to the 4% to 6% through 2017 this 0.5% to 1% sales growth is? I appreciate there's some noise in the numbers right now. But and maybe just related to that, I know you said you're going to take a deep look at the cost structure. Is that are you kind of positioning for an eventuality where the sales growth doesn't materialize? Just how should we think about those pieces? A sensitivity, Jonathan, on the sales growth that we've thrown out is that a 1% organic retail So that's a metric to give you an idea of what it means in terms of earnings per share and growth trends that kind of thing. So it's obviously critical for us particularly between rate cases to see load growth from our organic businesses there. In terms of do we anticipate a downturn there, I think the 1.5% to 1% is still a reasonable growth trend to project on. We're always looking at our cost structures and trying to find flexibility. We're a large company with a lot of different operations and we have levers that we can pull. Okay. But you're not considering starting to plan off a lower number to just have a bit more comfort that you can hit this number? Or is that we're at this stage not saying that by the sound of it? No. It's too early to try to move in any direction on that. I think the growth estimates are reasonable given what we're seeing, but we're always trying to prepare and be ready for other circumstances. And then just one other on international. I'm just curious you're talking about head count reductions. Given the nature of the business, the predominantly hydro footprint, what kind of flexibility do you really have there? And how should we think about that? How it changes the positioning of business going forward? Well, I think in terms of cost reductions, we have identified over 100 positions. There's various administrative corporate office type positions that are examined in support roles. So that has been acted upon and will help offset some of the losses. Okay. Thanks very much. Thank you, Jonathan. Our next question comes from Paul Ridzon with KeyBanc. Good morning. Good morning, Paul. Good morning. Quick question. Steve, I think I heard you say that the strength at the merchant and the ASR will offset some of the pain in international? Yes, that's correct. And then just a clarification, did you say the ASR happening sooner than anticipated was $0.04 accretive to previous views or is it $0.04 accretive absolute? It's $0.04 to the plan that we had submitted. And let me give a discussion here. In the Q1, our Midwest operation earned provided earnings that were equal to what we've projected for a 6 month period. We had in February projected that the sale would occur and close midyear. And so we had the Midwest generation in our results for 6 months and about $95,000,000 of earnings during those months. Well, they've got those earnings in the Q1 and then we closed the deal. That allowed us to accelerate the timing of the initiation of the share repurchase. And the share repurchase provides benefits to us happening earlier, roughly 1 quarter earlier in the neighborhood of $0.04 compared to our original plan. Thank you for the clarification. Sure. Thank you. Our next question comes from Paul Patterson with Glenrock Associates. Hey. Hi Paul. How are you? Almost all my questions have been answered. Just to clarify though on the you guys said that you're taking a hard look at your costs and Jonathan asked about this. I just am wondering though you are always probably taking a hard look at your costs. I mean is there anything that we might think of as being potential cost cutting program etcetera that could in case things don't in case whatever some factor here or there doesn't work that could help you meet the numbers if there was a hiccup, let's say, more in international or sales growth, whatever. I'm just wondering, do you see it is this something new that you're identifying? Or how can you could you just elaborate a little bit on that? I'll take a shot. Paul and Steve can certainly chime in. I think this organization has demonstrated great discipline with cost. And when you think about where we've come post merger, integration projects, corporate center, benefits, moving into the operations, consolidating work management tools, the nuclear fleet working together over a now a several year period. We continue to look for ways to optimize our investment and optimize the operation of our business. And that is not going to change. And so I would not point to any single thing. I would just point to ongoing financial discipline. When we make commitments, our expectation is that we'll deliver those commitments using all the levers that exist in the company and making the right risk reward trade offs because at the end of the day, we want to provide reliable service, maintain a safe operation and commitment to employees. So it's no one thing, but it's just ongoing financial discipline. Okay. Thanks a lot. Thank you. Thank you. Our next question comes from Travis Miller with Morningstar. Hi, good morning. Thank you. Good morning. Just wanted to go back to the retail usage trends particularly on the residential side, I suppose. Are you seeing any kind of penetration on And what might change that? It's modest at this point. So we are a company with 7,200,000 meters. We serve about 20,000,000 to 25,000,000 customers and we have about 5,000 to 5,500 rooftop installations. I do think that there is an ongoing interest on the part of customers pursue distributed generation when it makes sense for them. I think the one distinction that I might make in many of our service territories, our retail rates are extraordinarily competitive. We're 20% below the national average here in the Carolinas as an example. So the economics have not been as favorable as they might be in other jurisdictions where the prices are just frankly higher. So we think about our renewable strategy for the company including economic forms of renewable investment. It's been primarily utility scale up to this point, but we do believe customers will have an interest over time as the economics continue to improve on distributed generation. Okay, great. Thanks. And then wonder if you could give an update on the Atlantic Coast Pipeline that or even the projects that you have related to that? Yes. So the Atlantic Coast Pipeline is moving through its early stage development process with open houses, surveying, engineering work, still targeting a FERC filing later this year with construction hopefully beginning 'sixteen, 'seventeen. So it's on track and enjoys very strong support here in North Carolina, represents important infrastructure for the eastern part of the state, not only to enable electric generation, but also for industrial growth. Do you wait for the FERC filing and any kind of approvals there before you start any kind of projects, power generation etcetera that would tie into that pipeline? Or is that something you could start before? Yes. So we look at that infrastructure as being infrastructure that we're building over time, not for any one plant, but to continue to provide diversification of supply and infrastructure over time. So we've built 5 combined cycles over the last 3 to 5 years. We have another one planned for 2018. And all of those over time underpin this infrastructure, but I wouldn't tie any given plant to the expansion. Okay, great. Thanks a lot. Thank you. Thank you. Our next question comes from Ashar Khan with Visium. Good morning, Ashar. Good morning, and congrats. Good results. Thank you. Just wanted to get a sense on the you mentioned the $0.05 to $0.10 on the North Carolina after municipal acquisitions. Can you just remind us why there's this variance of $0.05 to $0.10 and how we can end up at $0.10 versus $0.05? Yes. What we were thinking about there is basically the financing of it. Roughly a $1,200,000,000 investment. Half of that will be through OpCo debt and absorbed in retail and wholesale rates. The other $600,000,000 is the $0.05 to $0.10 range dependent on if it was financed with cash or with equity. We're not going to issue equity here, but that just gives you an idea of the range. I would think about that more in the midpoint of that range in terms of what it's really going to yield. Okay. Thank you so much. Thank you, Shahriar. Okay. That does conclude today's question and answer session. At this time, I will turn the conference back over to Lynn Good for any additional or closing remarks. So thank you all for joining us today for your interest and investment in Duke Energy. I think we'll see a number of you maybe in May at conferences, but we'll look forward to our Q2 earnings call on August 6. So thank you for joining us today. That does conclude today's conference. Thank you for your participation.