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

Thank you, Tracy. Good morning, everyone, and welcome to Duke Energy’s third quarter 2014 earnings review and business update. 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. Leading our call today is Lynn Good, President and CEO, along with Steve Young, Executive Vice President and Chief Financial Officer. After our prepared we will take your questions. Other members of the executive team will be available during this portion of the call. With that, I’ll turn the call over to Lynn.

Good morning, everyone and thanks for joining us. Earlier today, we released third quarter adjusted earnings results of $1.40 per share. These results are impacted by milder than normal weather, unfavorable results in Latin America and weaker retail load compared to the prior year quarter. Our year-to-date results remain above our internal plan, and we remain on track to achieve a revised 2014 adjusted EPS guidance range of $4.50 per share to $4.65 per share. Steve will provide more about the financials in a moment. Let me spend a few minutes on operational performance and progress and how we are positioning our business for growth. Our regulated nuclear fleet set a record quarterly capacity factor of 98% in the third quarter. Our regulated natural gas fleet also performed well achieving at least 80% capacity factor at eight of our nine combined cycle plans in the Carolinas and Florida. We also continued to deliver significant benefit from the 2012 merger with Progress Energy. Through the third quarter, we generated about $360 million of cumulative fuel and joint dispatch savings for our Carolinas customers. We are on track to achieve to guaranteed savings of $687 million over the first five years. By the end of this year, we expect to deliver non-fuel O&M savings of about $550 million, exceeding our original assumptions. It has been an active and successful quarter in advancing our strategy. Let’s turn to Slide 4, and several of our growth initiative announcements during the third quarter, including new generation and new gas and electric infrastructure. I’ll briefly summarize a few of our key announcements. In September Duke and Piedmont Natural Gas announced a joint venture with Dominion and AGL Resources, to build and operate the Atlantic Coast Pipeline. The 550 mile natural gas pipeline begins in West Virginia…

Thanks, Lynn. Today, I’ll focus on four areas: first, the primary drivers of our third quarter results; second, our retail volume trends and the economic conditions within our service territories; third, important accounting changes made in the third quarter; and finally, I will close with our financial objectives including the status of our 2014 adjusted earnings guidance range. Let’s start with the major earnings drivers for the quarter, as outlined on Slide 9. Our quarterly adjusted diluted EPS $1.40 was below the prior year’s quarterly results of $1.46 per share. As we discussed during our last earnings call we expected slightly higher adjusted earnings per share in the third quarter, compared to last year. However, adjusted earnings this quarter were hampered by three principal drivers. First, weather was below normal by around $0.06 per share. Additionally, unfavorable results at International Energy and lower retail customer load growth also contributed to reduced third quarter earnings. Overall, based on the strength of the first two quarters we remain on track to achieve our revised 2014 adjusted earnings guidance range of $4.50 to $4.65 per share. On a reported basis, we earned a $1.80 during the quarter compared to $1.42 last year. Reported results include an approximate $475 million pre-tax reversal of a first quarter impairment charge related to the sale of our Midwest generation business. This impairment reversal is recorded in discontinued operations and has been excluded from the company’s adjusted diluted earnings per share results. Next, let me discuss the key quarterly earnings drivers for each of our major segments. I’ll start with our largest segment, Regulated Utilities, where adjusted earnings were essentially flat during the quarter. For the second summer in a row we experienced mild weather compared to normal. However, the weather this quarter was normal than last year,…

In closing the third quarter demonstrated significant positive momentum in delivering value for our customers, communities and shareholders. And we are laying a strong groundwork and foundation for the future. Now we welcome your questions.

(Operator Instructions). We’ll go first to Julien Dumoulin Smith from UBS. Julien Dumoulin Smith – UBS: Hi, Good morning.

Hi, good morning.

Good morning, Julien. Julien Dumoulin Smith – UBS: Thanks, first question on the ARO and the overall CapEx OpEx composition of potential spend with the coal ash, could you just give a little bit of flavor around how much this could turn into an earnings opportunity in whatever parameters you can describe?

Well, we have recorded at this point the ARO liability and while we have not begun to spend any significant funds we will begin spending that money in 2015 as we identify four plans that we are going on pretty quickly. Our focus right now is getting these plans approved, getting the permitting done, getting the logistics in place. The ultimate cash spend will be impacted by the decisions made by Dinah and the coal ash commission regarding many of the sites. Ultimately the cost recovery aspect has been kicked to the Utilities Commission. We have made no application for recovery because we haven’t incurred any cost. So ultimately the dispositions of that into customer rates is yet to be decided. Julien Dumoulin Smith – UBS: Fair enough. Then turning to the international business I’d be curious where do you stand in the strategic review and specifically does the latest hydrological developments in Brazil impacts that review in any sense and really what’s on the table at this point as the process continues?

So we are continuing to review all options and had set an internal timeline of late ‘14 early ‘15 for our review and we are on pace for that Julien. I wouldn’t say specifically that the hydrology in the year of 2014 is impacting that review, but certainly hydrologic risk, regulatory risk, market risk and opportunities are part of what we are assessing. So when we reach any important milestone in that review we will certainly update you but at this point Julien I don’t have anything further to discuss. Julien Dumoulin Smith – UBS: Great and then if you will, just turning to Florida quickly, [Necter] has talked about some other opportunities potentially adding solar in the state, gas reserves, I’d be curious what’s your thought process on pursuing those avenues as well?

At this point our focus is on the significant generation build that we have underway to replace capacity in the states that we are focused as we remarked in our comments on combined cycle upgrades and adding additional capacity. We certainly believe that solar represents an opportunity for the State of Florida as it makes sense for public policy and requirements of our customers and we will pursue that at the right time but I would say our focus at this point is on the gas capacity. Julien Dumoulin Smith – UBS: Great, well thank you very much.

Thank you.

Thank you.

We will take our next question from Greg Gordon from Evercore ISI. Greg Gordon – ISI Group: Good morning.

Good morning, Greg.

Good morning, Greg. Greg Gordon – ISI Group: Going back to page seven on Edwardsport can you review the dollars that are being reviewed for recovery in the rider proceedings and what the risk is f the commission were to decide that you weren’t performing up to their expectations?

Greg, I think, we can take you offline on the specific dollars in each of the filings and the team would be ready to do that as soon as the call over. Let me just give you some color generally about the proceeding. So the commission would be taking up IGCC-12 and 13 in February. They will be focusing on the operating results of the plant. There have been challenges by certain of the interveners during November of 2013 around the concept of negative generation when the plant was down and was drawing power from the grid. We also have discussed previously that we had some challenges during January with freezing 30 degree normal in Indiana we would expect the commission to be reviewing operating activities during that period. So I think between the IGCC filing as well as fuel there will be a comprehensive review of operations and our focus has been on continuing to improve performance and I think the demonstrated results that we shared on the call with 90% availability for the gas supplier in July and August and the overall capacity factors demonstrate that we’re moving in the right direction. Greg Gordon – ISI Group: Thanks I will get them offline. That’s all I got, thanks.

Thank you.

And we will go next to Steven Byrd from Morgan Stanley. Stephen Byrd – Morgan Stanley: Good morning.

Good morning, Steve. Stephen Byrd – Morgan Stanley: I wanted to discuss your tax position and your Latin American assets. Apparently we don’t know where you’ll ultimately come out in terms of your strategic review but if you were to think about selling assets and repatriating the money back to the US, can you discuss your tax position at a high level, I know you have a large US tax loss position, just curious how we should broadly think about tax implications if you were to try to repatriate a fairly large amount of capital from Latin America?

Okay, let’s look at the cash on hand. We’ve got about $1.6 million overseas offshore right now. If we were to make an assertion that all of the previous earnings were to be repatriated over time, we would record a tax liability in the ballpark of $300 million to $350 million. We have not accrued any U.S. taxes on the international operations, but if we said all the past earnings were going to ultimately repatriate, that’s what we would record on our books. Now because of our current NOL position and under the current tax laws with the expiration of bonus depreciation, we would expect to come out of the NOL in 2015 and start utilizing tax credits. We would not be a significant tax payer until 2016 or 2017. So the actual cash outlays related to income taxes on our international operations wouldn’t be made for a few years down the road. Stephen Byrd – Morgan Stanley: Okay. So you do essentially, Steve, get some benefit from that tax loss position that you had when you think about bringing capital back, but there is still an accrual, there is still some degree of cash costs when you bring that money back?

Yes, that’s correct. We have both the accrual to catch-up taxes on all the previous earnings, and then the actual cash outlays would be a bit later.

And so the GAAP accounting or the generally accepted accounting principles require recognition of liability, Stephen, but the cash payment would occur, as Steve indicated, after the NOL is absorbed and we move through the utilization of renewable credits and so on. Stephen Byrd – Morgan Stanley: I see. But if you were to try to bring the capital back, let’s say in late 2015, would your tax loss position allow for some degree of a shield of the cash that would be coming back from Latin America?

I’d have to look back at the numbers more closely, but I believe there would be some tax shield there for a period of time, couple of years perhaps.

Coming into 2014, the NOL was $2.7 billion, Stephen, and I think the other thing that we would need to evaluate depending on what happens in the lame duck session is bonus depreciation extended. I think there are number of other moving pieces that could impact that assessment as well, that you may want to consider. Stephen Byrd – Morgan Stanley: That’s a good point. Just wanted to shift over to your pipeline investment and I wanted to better understand how to think about the actual cost of gas that you’ll be procuring. When you source the gas, would you be procuring gas at sort of the overall Henry Hub price, or would it need to be at a discount to Henry Hub because it’s essentially coming from low-cost shale plays and you’ve got to factor in transport costs? In other words, it’s sort of – is the cost of the pipeline kind of in your mind, the sum cost, and then you pay for billing Henry Hub rates, or does that transport need to factor in, and therefore you would be paying a lower price for gas essentially than what we might see in the Gulf of Mexico?

So I think the combination of things that you’re talking about are still under evaluation on specifics, Stephen, so we don’t have a specific price of natural gas that we’ve locked into in Marcellus. We will have a price that’s implying the transport as we look at making that multiyear commitment for the utilities, but as we stand back and look at the diversity of supply, look at the pricing out of Marcellus, look at the pricing of this additional transport facility into the Carolinas, we think there is a very compelling business case for our customers to have access to low-price diverse sources of gas. And so that’s exactly the business case that we believe excess for underpinning this investment for the benefit of our customers. Stephen Byrd – Morgan Stanley: Understood. Thank you very much.

Thank you.

Thank you.

We’ll go next to Jonathan Arnold from Deutsche Bank. Jonathan Arnold – Deutsche Bank: Yes, good morning.

Good morning.

Good morning, Jonathan. Jonathan Arnold – Deutsche Bank: Just on last – this might be – I might be reading too much into this, but last slide – last quarter on your 4% to 6% growth build-up slide, you said finalizing international strategic review and now you just you’ve dropped the word finalizing. Were you close to something that you’re now not close to, and the process sort of extended out a bit, or is the way do you communicating anything that?

I think you’re reading more into it. And we should use you as part of finalizing our slide, Jonathan, to point out where we’ve used language differently. No, in all seriousness, we’re on the same pace we were on second quarter. And I would love to tell you that analyzing international tax is something that can be done quickly, but there are a variety of complexities and analysis. We’re taking our time. This is an important part of our business that has contributed well for a long period. And so when we have an update on that, we will certainly share it but we’re on target to complete our work late ‘14, early 2015. Jonathan Arnold – Deutsche Bank: So you’re fairly confident then that you’ll know the outcome on that by the time you give your ‘15 outlook, I guess with the year-end call?

So that’s certainly our target, Jonathan. And just to step back for a moment, when we undertook this review, we were looking at several dimensions. One dimension is, how do we optimize cash? We’ve had opportunities to bring home cash in a couple of large transactions over the last several years but we would love to solve cash in a way that was more predictable and more consistent with funding in the dividend. And then secondly, we’re evaluating is there a way to improve the growth profile of the business in light of what we see as near-term to mid-term headwinds, currency, pricing, etcetera. So our intent as we finish, our review would be to share our perspectives on both of those objectives, and the work we’ve completed that could accomplished some or all of this objectives as we complete our work. Jonathan Arnold – Deutsche Bank: Okay, thank you. And then just somewhat similar question I’m afraid, but when you first announced the Midwest generation sale, you sounded more robust about the idea that it would be accretive. Now you are saying that it depends on the timing and the ultimate use of proceeds [indiscernible] one way or another on use of proceeds that makes you less confident that this is an accretive deal?

Jonathan, we continue to see accretion. What we were trying to communicate is the timing is not completely firm, we were hoping actually when we started to close by the end of ‘14. We think it’s probably more early ‘15. And so we’re just kind of talking about that timing as we share that perspective.

But ultimately we do see this as an accretive transaction certainly. Jonathan Arnold – Deutsche Bank: All right, great. Well, thank you very much.

Thanks so much.

We’ll take our next question from Michael Lapides from Goldman Sachs. Michael Lapides – Goldman Sachs: Hi guys. Just curious, did anything change in terms of your thought process regarding rate case timelines, if any, in Carolinas. The only reason why I asked is the solar CapEx, the development of the Lee facility, just curious about how you get those in rates?

We have no direct plans for rate case activity in the Carolinas right now. We’re looking at our cost structure as we move forward. Typically when you try to play on rate case as I think about data points on rate cases, you look at when a base load plant moves into service, because your cost structure changes at that time. Lee has been scheduled for late ‘17 or during 2018 for commercial operation for the Carolinas. So that might be a point that you’d look at there. Shortly following that or plant additions for DE progress as well. So that’s kind of your starting point. But we’re looking at our cost structure between now and then, in light of other factors. And that could compel us to move earlier or it could push us back later if other events occur. Michael Lapides – Goldman Sachs: And can you give us – change in topics a little bit, when thinking about the Indiana smart grid rollout, what the annual – kind of the average annual revenue increase tied to that would be?

So it’s about less than 1% to around 1%, lower for industrial. The industrial class will not participate in all of investment. And we’re targeting somewhere around $250 million of spending a year around over the seven-year period. Michael Lapides – Goldman Sachs: Got it. Thank you, Lynn. Thanks Steve. Much appreciate it.

Thanks so much.

We will go next to Hugh Wynne from Sanford Bernstein. Hugh Wynne – Sanford Bernstein: Thank you. I have a couple of questions. My question goes to Slide 14, where you outlined your sort of 4% to 6% EPS growth trajectory and the drivers that will get you there. 4% growth over ‘15 and ‘16 in earnings is kind of an 8% increase against a 1% increase in retail load over that period, 6% growth over ‘15, ‘16 would be a 12% increase in earnings against maybe slightly more than 1% growth in retail load. I was just wondering, if you could help me understand, how you’re going to close that gap in a way that’s tolerable to rate payers. I understand that 4% range we’re hoping to do with wholesale growth and cost control and the 7% range we’re hoping to do it with accretive acquisitions, but I wonder if you just might give more color on how you close that gap? And secondly, what the long-term implications for EPS growth of 5% load growth are beyond 2016?

Yes so – and let me discuss the growth trends broadly here. As Lynn mentioned, we’ve put together some investments in the pipeline the NCEMPA acquisition. Those provide a strong earnings growth to Senate Bill 560 during the three to five year period we will start to produce some earnings as well. So we feel confident about the earnings growth rate on a longer term basis. When you look year-to-year, some of the drivers to think about, you’ve got weather normalized customer growth and that’s modestly forecasted at 1%. We also have wholesale sales growth and contracts that we’re stepping into, that have produced earnings for us as well. Some of our investments, although not put into rates, do approve AFUDC between rate cases, and that can provide some earnings enhancement as well. Our commercial renewables business has provided a solid 1% earnings growth on a total company basis as well, and we think that business will continue to grow for us. So those are some of the metrics that we look at when we think about our longer term earnings growth rate trajectory. The ability to control O&M between rate cases is critical to utilities as well, and we certainly demonstrated that. Hugh Wynne – Sanford Bernstein: Okay. Let me just ask a more specific question about the international business. You mentioned that you have this [indiscernible] in Brazil. What are the earnings implications of that beyond the quarter? Are you expecting that a year of depressed earnings, or will it take even longer to reestablish a reservoir from Brazil?

I think when you’re thinking about Brazil hydrology, one of the – probably the key factor to think about is the upcoming rainy season, which typically runs November/December through March/April. And I think the results of that rainy season will be critical to decisions made in 2015. I wouldn’t try to guess at what that rainy season would look like, but I don’t think that you’d see any rationing occur unless there was a third consecutive core rainy season, and it’s the force rationing that really has an impact on earnings. Hugh Wynne – Sanford Bernstein: Great. Thanks a lot.

Thank you.

(Operator Instructions) We’ll go next to Ali Agha from SunTrust. Ali Agha – SunTrust Robinson Humphrey: Thank you. Good morning.

Good morning.

Good morning. Ali Agha – SunTrust Robinson Humphrey: Steve, I wanted to be clear on the growth rate targets you had talked about, the 4% to 6%. So as you pointed out, some of your growth initiatives like the pipelines and the additional buyback of the assets from the municipalities etcetera, those are going to start really contributing to you more in the timeframe beyond ‘16. So if I am hearing you right, should we assume that, that contribution keeps you on the 4% to 6% growth rate beyond ‘16, or should we think of those actually taking you above the range? How should we think about these growth initiatives relative to the 4% to 6%?

Yes, we will be rolling out beyond ‘16 in February, as we’ve traditionally done. And that’s the point which we’ll be discussing the longer term projections of earnings, but right now we feel comfortable through ‘16 with the 4% to 6% earnings growth rate. Ali Agha – SunTrust Robinson Humphrey: Okay. But in a high-level sense, is it fair to say that this keeps you on-track, that kind of run rate?

Ali, I’ll jump in. 4% to 6% is our long-term growth aspiration. We spend a lot of time in 2014 laying the foundation and groundwork for that, by putting projects in place that will give us an opportunity to deploy the capital necessary to achieve that growth rate. And so we are on track to do that. We think we’ve demonstrated that with tangible projects that will deliver earnings that are consistent with what we’re trying to accomplish, consistent with a strong dividend paying company. So we’ll, as Steve said, update more specifics in February, but we believe that we are putting the pieces in place to deliver a strong growth rate. Ali Agha – SunTrust Robinson Humphrey: Okay. And then Lynn, can you remind us, the grand jury investigation around the coal ash spill. What’s the status of that? Is that still ongoing, or what’s happening there?

So the litigation continues Ali, and I can’t discuss any specifics on those matters, but I will say is we’re cooperating fully defending the company. We cannot predict the outcome of these proceedings at this point, but of course, we’d provide updates when they are milestones met. Ali Agha – SunTrust Robinson Humphrey: Okay. And my last question, as you talked about using the proceeds from the Midwest sales, one of the potentials for that is share buybacks, but if I put that in the context of these big mega projects, the pipeline and the acquisitions coming up, and put them in the equation, Steve you said, no equity issuance through ‘16. Should we think of this as no equity issuance even beyond ‘16 when some of this big capital spend is going to be used on that ‘17, ‘18 period?

Well, again right now I can’t project beyond ‘16. We’ll be finalizing our plans for beyond ‘16 and discuss that in February. But we’ll be looking at our various spend for coal ash, other investments such as the pipeline in NCEMPA as we make those decisions, and we’ll be firming up beyond ‘16 in February for you. Ali Agha – SunTrust Robinson Humphrey: Okay, but conceptually you’re okay with buying back stock now if you think that makes sense, but then issuing equity in a year or two later if it’s required, I mean, conceptually that’s not an issue?

No, Ali, I would say that as we look at the options for the Midwest generation, we’ll be considering the timing of all these matters including investments. And our objective is to optimize proceeds and investments in the way that creates the greatest value for shareholders. So I would say all options are on the table at this point and we’ll share more specifics as we move forward. Ali Agha – SunTrust Robinson Humphrey: Fair enough. Thank you.

Thank you.

We’ll go next to Andy Levi from Avon Capital Advisors. Andy Levi – Avon Capital Advisors: Hi guys, good morning. Just a very, very quick question. Just on the international, I guess with – again oil is up actually today, but with oil down so much, I just remember from your initial guidance that you gave back in February. You had a sensitivity on Brent crude, I think it was $10 movement, it’s like $0.02, and never really paid a lot of attention to that. So as you get into next year, obviously we don’t know where Brent crude is going to be, but I guess it’s down about $30, $35 from the beginning of the year. How should we think about that for National Methanol?

Well, the sensitivity that we gave, Andy, is correct. About a $10 movement is $0.02 and that’s a $10 average movement on an annual basis, to make sure that’s clear. So that’s the sensitivity, and that relates to our National Methanol subsidiary, which is a portion roughly 25% of our international business. So we will bake that into our forecast and keep an eye on where oil prices are moving as we make our projections in February. Andy Levi – Avon Capital Advisors: And does slightly policy – that has nothing to do with it at all as far as how they allocate oil to Asia or to the U.S. and they are pricing there. That doesn’t…

No. And Andy this correlation that we’re sharing with you is a rough correlation. We’re not actually in the oil business. Andy Levi – Avon Capital Advisors: Right.

Okay. So the correlation has generally worked over time. We make more money when oil prices are high and less when oil prices are low, but it’s not a perfect correlation. Andy Levi – Avon Capital Advisors: Okay. Thank you.

Thank you.

And we’ll take our next question from Greg Gordon, Evercore ISI. Greg Gordon – Evercore ISI: Thanks. I have a follow-up question on the pipeline. Just maybe you can clarify a bit. Traditionally the shippers bear the costs of moving gas to where it’s been consumed. And I guess the question is, whether or not because the cost of transportation on new pipes like this, especially given the negative basis that the Marcellus producers are already facing versus Henry Hub is so high might be prohibited for them to make it economic. Is it likely that the transportation costs will be borne to some degree by the consumers?

So we are entering into long-term transport contracts on the part of our utilities. That was what we put in front of the commission this, Greg, this quarter, so that we could enter into those multiyear transport contracts. And that’s part of the transaction. So the utility customers will bear the transport.

That’s right. And these costs are typically passed through the fuel cost mechanisms. Greg Gordon – Evercore ISI: No, I completely understand it’s a non-traditional framework relative to what E&P analysts generally think about, in your pipeline as well as some others have gotten push back from E&P investors that, well, it just seems like a very expensive transportation cost. And I pointed out to them that these are consumer-sponsored pipes and I just wanted to get some clarification on that.

That’s correct.

That’s a demand concept [ph] versus supply. So I think that key distinction, Greg, is we look at the need for natural gas in the Carolinas and our dependency on a single pipeline, we think this diversification makes sense for our customers. Greg Gordon – Evercore ISI: I completely agree. I just wanted to understand the economics. Thank you.

Thank you.

This does conclude today’s question-and-answer session. I would like to turn the conference back over Lynn Good for any additional or closing remarks.

So thank you everyone, and thanks for your interest in Duke. We look forward to seeing many of you next week in Dallas at EEI. So thanks again.

This concludes today’s conference. We thank you for your participation.