Good day, and welcome to the Duke Energy’s First Quarter Earnings Call. Today’s conference is being recorded. At this time, I would like to turn the conference over to Mr. Bill Currens. Please go ahead, sir.

Thank you, Derek. Good morning, everyone, and welcome to Duke Energy’s first quarter 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 first quarter activities. Then, Steve will review our 2015 first quarter financial results, including an update on what we’re 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 $1.5 billion 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 billion. 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 first quarter 2015 adjusted EPS of $1.24. We also affirmed our full-year 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 first quarter. 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 the experience of record demand as our customers benefited from our diversified portfolio of generation resources. The regulated natural gas fleets at a record for the quarter delivering more than 12 million megawatt hours. The performance of our nuclear fleet continued to improve, serving as a valuable resource of baseload generation to 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…

Thanks, Lynn. Today, I’ll review our first quarter financial results and discuss the economic conditions within our service territories, including retail customer volume trends. I will also provide an update on Brazil’s challenging economy and ongoing drought conditions. 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 first quarter adjusted diluted earnings of $1.24 per share compared to $1.17 in the first quarter of 2014. Strong results from our Regulated Utilities and commercial Midwest Generation business helped offset weakness at International. On a reported basis, 2015 first quarter earnings per share were $1.22 compared to a net loss of $0.14 last year. The loss in last year’s reported results included the pre-tax impairment charge of approximately $1.4 billion or $1.23 per share related to the Midwest Generation business. Let me briefly review the 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 recovering 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 will provide additional details on that in a moment. Our Regulated Utilities also realized higher O&M costs during the quarter. As you will recall, in 2015, we are targeting increases of O&M cost at Regulated Utilities below the level of retail…

[Operator Instructions] Our first question comes from Daniel Eggers with Credit Suisse.

Is the usage comparison down at this point in time? Is that really just a function of the math behind the first quarter 2014 kind of trying to discern weather versus usage or is there something more structural happening? I couldn't figure out what that first quarter comp is doing to this number.

I think that the first quarter’s comps are influenced by what happened in the first quarter of 2014. 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 food service 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 Polar Vortex. There people were literally forced to stay at home due to the weather and 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? So we will keep an eye on those factors. But I think the fundamentals of our service area economies are ultimately very solid.

So the 0.5% to 1% makes sense on an ongoing basis. So your view is we shouldn't get too caught up in this usage comp right now because there's going to be some friction in the weather adjustments?

That’s correct. I think that will be always rolling 12 month average, the base periods going to have some of that and it’s from the Polar Vortex of 2014, I think I would look at other trends there as well. And I think 0.5% to 1% is certainly still a reasonable estimate for where we are going.

Dan, the one thing I would add is that if we look at these results relative to how we plan the year, we’re on plan, so that’s another indication of the fact we think we’re tracking with our expectations.

And I guess just on International, you've given the obviously slow start to the first quarter and probably rough looking second quarter, 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 in light there, where do you see the business making up more of that earnings?

I think the International segment will have challenges meeting their targets, which were set in February at about $345 million 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 first quarter and that’s in the bank, our ability to accelerate the share repurchase program due to the early closure of the sale is accretive to us by in the neighborhood of $0.04, we were fortunate and that we got our full earnings estimate out of the Midwest Generation business in the first quarter. It was a very good quarter for that business. So the acceleration to share repurchase should all add to the bottom line to us. So that’s favorable as well. So I think you 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 to the approval process on the acquisition of the generation assets from NCEMPA. 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 would point to.

Our next question comes from Shahriar Pourreza with Guggenheim.

So just on the International business, Steve, you provided 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?

Shah, 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 US. Last year, it was 3.7% for the entire year and it was over 7% in the first quarter and then 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 reais, but where spot pricing sells under that cap was 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.

And then just in the US, seems like you're in a really good spot. You've sold the assets in the Midwest; you're doing the buyback program. Could 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 may be centered around more midstream or muni acquisitions in the area?

Let me take a shot and then Steve can add to it. I think around the jurisdictions on where growth is coming from and if we start in Indiana, it’s grid related growth. We filed for $2 billion investment in the 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 mentioned the 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 million in solar, about half of which of that will be owned generation. And then in Florida, we have close to $2 billion in investment on generation in the Citrus County and Osprey or Swany investment. So those are the things I would point to as unfolding or 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.

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 will be around the target range of where you want to be.

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 it 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 gone to a point where we are within that target range, at the upper end of it. So our Board will consider that as we move forward, but ultimately our goal would be to have the dividend growth closer to the earnings growth rate. So that’s where we are headed.

Our next question comes from Michael Weinstein with UBS.

I was wondering if you could discuss a little bit about the puts and takes of the securitization bill in Florida for Crystal River.

Michael, it is a legislation that has passed both Houses. It is awaiting signature from the 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 we will give you more perspective on where we see opportunities to put that capital to work on a go-forward basis. But this is something that I think strategically is very valuable to our utility in Florida and to our customers in Florida.

And have you had any indications at this point, this early stage, about how capital or coal ash remediation might be treated? Will it be given full base 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 four sites between now and 2019. In our capital plans for that period, we are at $1.2 billion, $1.3 billion for those sites and are developing plans for the remaining sites. So the spending will ramp up over the next four 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 are on at this point, Michael. And our focus is getting the approvals from the state necessary to begin the excavation and movement of ash. And that's been our primary focus at this point.

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 more.

We were talking about comparability to prior year, Michael, so let me ask Steve to weigh in.

Yes. What we were 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 2014, as thermals were dispatched in the last half of 2014, and some the similar effects that we are seeing now started to move into place. That was the reference we are making there.

Next, we’ll hear from Hugh Wynne with Bernstein Research.

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 $3.5 billion. Does 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, it's roughly a third and we are running numbers now. We will probably disclose a range in the upcoming 10-Q and book it in the second quarter. But it will be a smaller number than what we've seen in the Carolinas.

And are these costs, are these future removal costs primarily expenses or a very substantial portion of them likely to be capital investments?

Hugh, 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 or regulatory asset. And then we will work with the regulators on recovery of these costs and effectively amortize the regulatory assets in conjunction with the regulatory treatment from the regulators. 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.

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 will 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 one, again, balance sheet oriented until we know what the Commission recovery mechanisms are.

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 are 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 will continue to update you on both the costs that we incur as well as the timing for presentation to regulators.

Just a quick question, follow-up question on Brazil, 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 are anything like bathtubs, you'd 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, I shouldn't say permanent, is there a long-term drag to the earnings power of the hydroelectric assets in Brazil as a result of these two 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, et cetera, 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 slide deck, back in the appendix, sort of a tracking at the reservoir level. I think to your point, 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.

Can you provide any 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?

And 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 in 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.

Next, we’ll hear from Chris Turnure with JPMorgan.

I wanted to circle back to Florida and the securitization of the Crystal River 3 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?

Some of the facts there, I think the securitization will be around $1.3 billion, $1.4 billion. And the way it will mechanically work, as Lynn said, early in 2016, if things move along properly, is when the securitization would occur. But the proceeds will be used, half of the proceeds will displace and take out 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.

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 three approvals required, NRC, and we are hopeful that that will move through over a few months. So we expect that to be before the end of the year. The thing that's interesting about the NRC approval, these are plants we already operate. We operate the Brunswick and Harris plants. So we will 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 legislation. We've cleared those. And so the ones that remain, we think, can go rather quickly, giving us an opportunity to close sooner than we anticipated.

So the rider doesn't improve your outlook in any way? That was expected and that's required to close and it's all set?

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 tended wholesale contract with these same municipalities. They were self-supplying when they owned 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.

Next, we’ll hear from Jonathan Arnold with Deutsche Bank.

Could you just remind us, as you're thinking about the plan today, how 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. And maybe just related to that, I know you said you're going to take a deep look at the cost structure. Are you kind of positioning for an eventuality where if the sales growth doesn't materialize, just how should we think about those pieces?

Sensitivity, Jonathan, on the sales growth that we've thrown out is that a 1% organic retail load growth would translate into roughly 2% earnings growth. So that's a metric to give you an idea of what it means in terms of earnings per share and growth trends and 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 0.5% to 1% is still a reasonable growth trend to project on. We are always looking at our cost structures and trying to find flexibility. We are a large company with a lot of different operations and we have levers that we can pull.

But you're not considering starting to plan off of a lower number to just have a bit more comfort that you can hit this number or is that, 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 are seeing, but we are always trying to prepare and be ready for other circumstances.

And then just one other on International, I was just curious, you're talking about headcount reductions. Just given the nature of the business, predominantly hydro footprint, what kind of flexibility do you really have there? And how should we think about how that changes the positioning of business going forward?

I think in terms of cost reductions, we have identified over 100 positions. There's various administrative, corporate office type positions that are examined and support roles. So that has been acted upon and will help offset some of the losses.

Our next question comes from Paul Ridzon with KeyBanc.

A quick question. Steve, I think I heard you say that the strength at 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 use or is it $0.04 absolute?

It's $0.04 to the plan that we had submitted. And let me give a discussion here. In the first quarter, our Midwest operation earned, it provided earnings that were equal to what we projected for a six-month period. We had, in February, projected that the sale would occur and close mid-year. And so we had the Midwest Generation in our results for six months and about $95 million of earnings during those six months. They got those earnings in the first quarter 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 one quarter earlier, within the neighborhood of $0.04 compared to our original plan.

Our next question comes from Paul Patterson with Glenrock Associates.

Almost all my questions have been answered. Just to clarify, though, you guys said that you are taking a hard look at your costs. And Jonathan asked about this. I just am wondering, though, you guys 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, et cetera, that could, 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 International or sales growth, whatever, I'm just wondering, do you see it – is there 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 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 will 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.

Our next question comes from Travis Miller with Morningstar.

I was wondering going back to the retail usage trends, particularly on the residential side, I suppose. Are you seeing any kind of penetration on distributed generation at all and what might change that?

It's modest at this point. So we are a company with 7.2 million meters. We serve about 20 million to 25 million 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 to 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 are 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 in primarily utility scale up to this point, but we do believe customers will have an interest over time if the economics continue to improve on distributed generation.

And then I wonder if you could give an update on the Atlantic Coast pipeline, that, or even the projects that you have related to that?

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 in 2016, 2017. 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, et cetera, that would tie into that pipeline or is that something you can start before that?

So we look at that infrastructure as being infrastructure that we are building over time, not for any one plant but to continue to provide diversification supply and infrastructure over time. So we've built five combined cycles over the last three to five 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.

Our next question comes from Ashar Khan with Visium.

Just wanted to get a sense of on the – you mentioned the $0.05 to $0.10 on the North Carolina, the municipal acquisitions. Can you just remind us why there's this variance of $0.05 to $0.10, how we can end up at $0.10 versus $0.05?

What we’re thinking about there is basically the financing of it. It's roughly a $1.2 billion investment. Half of that will be through Opco debt and absorbed in the retail and wholesale rates. The other $600 million is the $0.05 to $0.10 range, dependent on, it was financed with cash or with equity. We are 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.

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 second quarter earnings call on August 6. So thank you for joining us today.