Ladies and gentlemen, thank you for standing by and welcome to the American Electric Power Second Quarter 2017 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. And as a reminder, your conference is being recorded. I would now like to turn the conference over to your host, Ms. Bette Jo Rozsa. Please go ahead.

Thank you, Lois. Good morning, everyone, and welcome to the second quarter 2017 earnings call for American Electric Power. Thank you for taking the time to join us today. Our earnings release, presentation slides and related financial information are available on our website at aep.com. Today, we will be making forward-looking statements during the call. There are many factors that may cause future results to differ materially from these statements. Please refer to our SEC filings for a discussion of these factors. Our presentation also includes references to non-GAAP financial information. Please refer to the reconciliation of the applicable GAAP measures provided in the appendix of today's presentation. Joining me this morning for opening remarks are Nick Akins, our Chairman, President and Chief Executive Officer, and Brian Tierney, our Chief Financial Officer. We will take your questions following their remarks. I will now turn the call over to Nick.

Thanks, Bette Jo. Good morning, everyone, and welcome to AEP's second quarter 2017 earnings call. Once again this quarter, AEP released earnings that are on track for the year despite very mild spring weather. In fact, along with first quarter results where winter was also mild, the weather has impacted earnings by about $0.12 per share year-to-date versus normal, but we're still on budget to meet our earnings guidance for the year. As you know, we recognized the mild weather early on in the year and adjusted our O&M spending to compensate for the possibility of mild weather impacts. So again, we actually continue to be on budget with our projection for the midpoint of guidance. So we confirm our existing 2017 operating guidance range of $3.55 to $3.75 per share. We reported GAAP and operating earnings coming in at $0.76 per share and $0.75 per share, respectively, versus second quarter 2016 GAAP and operating earnings of $1.02 per share and $0.95 per share, respectively. For the year-to-date, that brings 2017 year-to-date to GAAP and operating earnings of $1.97 per share and $1.72 per share, respectively, versus 2016 year-to-date of $2.04 per share of GAAP and $1.97 per share of operating earnings. This year, comparing 2017 to 2016 is like comparing apples to oranges. We're a different company centered on regulated operations and investments without significant unregulated operations, as in 2016, and have effectively de-risked the company and really focused on our earnings growth trajectory of 5% to 7% in the future. Nothing has changed for AEP in its view of achieving our 2017 guidance as a foundation for future growth. Since football season is upon us, as Tom Landry, the famous coach of the Dallas Cowboys, once said, confidence comes from knowing what you're doing. If you're prepared for…

Thank you, Nick, and good morning, everyone. I'll take us through the second quarter and year-to-date financial results, provide some insight on load and the economy, and finish with a review of our balance sheet and liquidity. Let's begin on slide 6, which shows that operating earnings for the second quarter were $0.75 per share, or $370 million, compared to $0.95 per share, or $466 million in 2016. This difference can primarily be attributed to the sale of the competitive generating assets and positive items that occurred last year that were not repeated this year. Let's look at our earning drivers by segment. Earnings for Vertically Integrated Utilities were $0.25 per share, down $0.18. Favorable prior-year items contribute to this difference, including formula rate true-ups, a June 2016 recognition of deferred billing in West Virginia and a 2016 positive tax adjustment. Other rate relief was favorable due to the recovery of incremental investments across multiple jurisdictions. Weather was milder than last year, as Nick said, and our normalized retail margins were slightly lower. Other unfavorable items in this segment include higher O&M due to transmission services and forestry expenses, higher depreciation and lower AFUDC. The Transmission and Distribution Utilities segment earned $0.23 per share for the quarter, down $0.02 from last year. Unfavorable drivers in this segment include the reversal of a regulatory provision in 2016, lower normalized retail margins, higher O&M due to increased transmission services, higher depreciation and a higher effective income tax rate due to positive 2016 adjustments. Partially offsetting these unfavorable items are recovery of incremental investment to serve our customers and higher ERCOT transmission revenue. Our AEP Transmission Holdco segment continues to grow, contributing $0.26 per share for the quarter, an improvement of $0.07 over last year. The growth in earnings includes the implementation of…

Thank you. Our first question is from the line of Greg Gordon from Evercore. Please go ahead.

Hi, everyone. It's actually Kevin (33:42) here.

Hey, Kevin.

If I'm just looking at your capital floor cash through 2019, it's about $5.6 billion a year and a 7.7% CAGR. Based on the current line of sight if you don't consider the wind project, would you expect a material drop off in core capital needs after 2019?

No.

Okay. So then, the $4.5 billion, I think, is 35% wires and 65% for the wind assets?

That's right.

The wind assets should be turnkey, so it wouldn't really impact EPS until probably 2021. What about the 35%? Would we see traditional rate making, like AFUDC, in 2020 or 2019?

Yeah, that's right. That's right. It'd be traditional rate making on that.

Okay. That's all I have. Thanks guys.

Yes.

Thank you. Our next question is from Jonathan Arnold from Deutsche Bank. Please go ahead.

Good morning, guys.

Good morning.

Just picking it up, also on the wind, the new investment, any thoughts, preliminary, Nick, on how you might finance this and how much room you have to put (35:02) leverage in the mix?

Yeah. So, obviously, we want to get to a point of getting Commission approvals, because I think this is a huge project. It's a great project. If you look at it company-by-company, it's not that huge. But when you look at the companies involved, the areas involved, we need to go through with the regulators and make sure they understand and see the benefits; and, some already have, but the benefits that we see in this project. Once we get to that point, then we'll be in a much better position to talk about financing and capital required and whether we issue equity. We've talked in the past about it. When you have a large project that really made sense and that we could focus the investment on that as opposed to the general confers of the corporation, then we believe investors should like that. So if we go down the road, we'll figure out what the appropriate mix is. And obviously, you know, we continue to look at capital, look at our credit metrics. I want to make sure we – that we remain a very firm foundation for investment. So Brian, I don't know if you have anything add to it.

I don't. We've always been thoughtful about how we finance our capital projects. As this progresses and we hear from the regulators, their interest in it, we'll look to put together a firm plan to make sure that we do it is as wisely as possible, as we do our regular capital program.

There are just not many projects you'll run into – and you know, really, the sense of urgency around getting approvals for this thing is centered on the federal government's basically given a 62%, 63% off sale and – with the PTCs; and, to take full advantage of the PTCs, that's $2.5 billion alone. So obviously, we want to get this thing through. And when you get – take all that into account just to apply investment and that kind of capital and reduce customer bills as a result and produce actually a more – certainly, a more resilient system as a result, I think is a great thing. So – but we'll have to figure it out when we get there.

Nick, can you give any insight into the calculation of the $7 billion customer benefit, like do you – are you assuming a carbon price? With what sort of level, and just is there anything else to kind of help us kind of get to that number?

Yes. So you know, we've obviously assumed a natural gas price going forward, because, obviously, this is a important hedge against fuel cost. And when you look at – we did (37:59-38:10) differentials. Obviously, we looked at carbon, and we looked at the value of the production tax credit. So those three components certainly provided the center of the analysis. And we've looked at mid-range cases. We've looked at low cases in terms of natural gas pricing and that kind of thing, and it still stands up. I mean, when you look at the – certainly, the immediate benefits and the real benefits of the PTCs along with what could happen with carbon, what could happen with natural gas prices, it just looks like a great project. So...

The $7 billion number, the $2.7 billion NPV, is that kind of the mid scenario, or where does that fit within the range of scenarios you looked at?

Yes, that's the mid case scenario, which was still a reasonably low natural gas price comparison.

Okay. And then, could I just – finally, on the transmission piece, obviously, you said normal rate making, but what's the – would that also be predominantly spending that would fall kind of in the back half of – very end of your plan into the sort of beyond 2019 period?

Absolutely.

Yes.

Okay. So we should think about this as more how we sustain 5% to 7% rather than incremental to or...

That's a good question. You know, obviously, our indigenous utility growth is centered on 5% to 7%. I think it should make the 5% to 7% more robust.

Okay. Thank you very much.

Thank you. And our next question is from the line of Chris Turnure from JPMorgan. Please go ahead.

Hi, Chris. How are you doing?

Good morning, guys.

Good morning.

Just to follow up yet again on the wind project, I don't think you talked about recovery for the actual generation portion of it. If you take ownership at a specific kind of date when it becomes commercial, I guess you could time it with a general rate case, certainly, but would you also pursue a rider on top of that just to have a measure of a safe cushion there?

Yeah, we will. And then, you know, it's part of the normal rate making process, but we would obviously be filing for whatever CCN approvals and we got – there's an exception to the MBM rule, the Market Based Mechanism, in Louisiana that, I guess, a hearing just yesterday or the day before approved an exception for that. So you're going through the right steps to get to the point where the Commissions become comfortable with the investment, and then we'll go through the normal rate making process for both the generation and the transmission.

Okay. And then, I think one of your peers had gotten some support from committing to local procurement of equipment with a project in Colorado. Are there any other kind of offerings that you're making to politicians and the Commissions down the road that would help kind of garner support here?

Yes, certainly. I mean, obviously, you don't do a project like this without looking at the socio-economic benefits in the region and for the customers. So – and even Governor Hutchison this morning mentioned it's good for jobs in Arkansas as well, but substantial – certainly, there's substantial procurement in all four of the states involved.

Okay. And then, switching gears to rate making, the PSO filing that you just made had a pretty big ask and you just got a conclusion of a rate case with new rates effective early this year in that jurisdiction. I (42:22) 9.5% authorized ROE. Could you just remind us of some of the challenges that you faced in getting that rate case across the finish line, if any?

So with the previous rate case in Oklahoma, obviously, we were disappointed with that outcome; and, it was a somewhat challenging time in many respects. And when you – when we look at the present case, our message has clearly been that this is a very important rate case for Oklahoma, because Oklahoma was doing just fine from a jurisdictional perspective up until a couple of years ago, and then the last rate case was really deficient in terms of its outcome because not only was the timeframe long to get it resolved, but also the outcome is, in effect, chasing expenses that are being made on behalf of customers. So we've got to get that back on the right track, and that's why this case is so important. Not only will it send a signal that we can invest the way we feel like we should in Oklahoma, and can in Oklahoma, but also have an impact on projects like we just discussed, because you really have to think about investments in jurisdictions that are chronically short. Oklahoma has not been that, and I think we're viewing sort of a perturbation that we can recover from. And I truly believe that Oklahoma and Stuart Solomon down at PSO, which is our President down at PSO, is working very hard to get that message across to everyone involved that in order to have a successful Oklahoma from an energy standpoint, PSO has to be part of that picture. And certainly, we're focused on making sure we get a good outcome.

Okay. Can you just remind us of the test year in that case and any kind of true-ups throughout the process?

Yeah. Do you have the test year...? Let's see.

Chris, we can have Bette Jo get you that detail

Yeah.

Okay. Great. Thanks, guys.

Thanks.

Thank you. Our next question is from Anthony Crowdell from Jefferies. Please go ahead.

Hey, good morning.

Hey, Anthony.

Just to stay on the wind and follow up on Jonathan's question, so this is wind that would be in rate base and this is wind that you had said is kind of, you used the word, more robust incremental to 5% to 7% utility growth?

Certainly, we still maintain our 5% to 7% earnings growth trajectory and, really, we'll have to see how this project gets resolved in combination with all the other projects that we're doing to see what it does to be ultimate growth rate going forward. So in and of itself, the project is incremental, but obviously, we need to – before we start talking about changes in growth rates, we need to make absolutely sure what project we have, and also how it plays in concert with all the other capital programs we have in place.

Would more generation in a region put even more stress on the unregulated portion of the Turk plant?

So you have the 88 megawatts of Turk sitting out there, but when we did the analysis, you know, we showed that even though you're taking some 9 million megawatt hours of wind power and energy coming in, you still need the capacity across the board. And in fact, when we looked at the capacity factors of the other generation, you only saw a very small 1% to 3% drop off in terms of capacity factor on coal. And certainly, even with natural gas, it wasn't that large of a drop off. So this is really playing against, you know, the forward view of fitting in a slice of energy to the benefit of consumers, but still using the capacity out there that's available. So it could put more pressure on the unregulated part of Turk, but Turk is a very efficient unit not – I don't think it's going to be – I mean, any difference is probably going to be negligible at best.

Okay. And just switching gears, Ohio, you had said that I – I don't know if it's – you used the word settlement discussions are going on or potential for settlement with the extension of the ESP. Do you think there's issues with – you have – in the legislature, you have, is it HB 247, I think to end ESPs or to change the way utilities file rate case in Ohio? At the same time, at the PUC you're trying to extend the settlement of an ESP. You think that may cause any – may prohibit you from reaching a settlement there?

No, I don't think that legislation is going to go very far.

Great. Thanks for taking my questions.

Yeah.

Thank you. Our next question is from Leslie Rich from JPMorgan. Please go ahead.

Hey, Leslie.

Hi, how are you?

Fine.

Just for a little clarification, I'm sorry if it's sort of already been covered, but you would file for approval shortly for the wind projects? And then, you would plan to commence construction, if approved, in 2018 at some point?

That's right.

Mid 2018?

Yeah, and we'd be looking for an outcome on those regulatory cases by April of next year. So we don't have much time to waste on that one. It really is – it's really driven by making sure we can take full advantage of the PTCs. That's the driver. And for the Commissions that take a look at this, you know, it is a fairly unique situation in that, yes, it's great generation resources. Yes, it provides considerable benefits to customers, but the timing of it needs to match up so that we can be successful in terms of putting it in place and taking advantage of those PTCs.

So you've already safe-harbored the equipment, or I guess the developer has done that?

Yes. Yes, we have.

And I guess, why does the region need 2,000 megawatts of generation? I mean, are you shutting other plants? Are you – you know, is demand growing? You said capacity factors on (49:48) gas plants won't decline that much.

Yeah, Leslie, and really – and this is probably the most important point to be made in the regulatory filings, and I'm glad you asked that question. This is really – any wind power project is an energy play, not a capacity play. So from an energy perspective, you're going to get 9 million megawatt hours out of it coming into the system, but at the same time you're only going to get, I think, an SBP that's only like 7%. I may be off by a percent or two, but only 7% counts as capacity. So you still need the other units to provide capacity, and they fill in from an energy perspective as well. So we just have to keep in mind, this project, the difference in capacity and energy. We're not shutting any other units down. Those units are absolutely needed. But what it does do is provide more diversity from a resource perspective, low energy – very low energy pricing coming in to the sector, which means economic growth. And then, when you think about the transmission side of things, yes, it's a 765, 360-some-odd mile generation interconnect, but usually with large transmission you get large economic development. So I see this as just an extremely important project not just from a energy consumption standpoint, but from an economic development standpoint as well.

So the benefits to customers are from lower fuel costs?

Absolutely. You know, you're basically – it's a hedge and it's an arbitrage against, primarily, fossil fuel generation resources. And so, if you're able to take the energy and continue with the capacity as used and useful, it's another powerful combination just like we used to do coal pricing versus natural gas pricing. Now you have coal pricing, natural gas pricing and, certainly, the intermittent resources provided from a wind power perspective. So just adds another part of the portfolio.

So do you anticipate that when you make these filings that it would result in rate increases to customers?

No. No, it won't. Actually, that's the amazing part of it. You're investing a large part of the capital, but keep in mind the government's paying you – the federal government's paying you for a substantial part of this capital. And then, it's being used – from an energy perspective, you look at the overall cost to consumers, the cost of the capital being deployed through rate base, and then the attendant energy reductions through fuel, it's a benefit to customers. And that's where we come up with the $7 billion over the 25-year period. I mean, it's substantial.

Great. Thank you.

Yes.

Thank you. Our next question is from the line of Steve Fleishman from Wolfe Research. Please go ahead.

Morning, Steve.

Thank you. Good morning, Nick. So just on that same topic, is it – will it be clear in there, kind of in like the first year or two, that there's net reductions like in year one to customers from this, so that....?

Oh, yeah. It's not like it's back-end loaded or anything. These – in year one, you're seeing benefits to consumers.

Okay. And then, I guess more importantly, just for the approval process in the different states, can you just talk to a little bit of – I know states have different rules and laws on how they approve projects like this. Xcel, I know, has kind of gone through different processes...

Yeah, yeah.

...doing something similar. So could you just – like, is it – did any – can all these approvals be done through just the regulatory process? Do any states need legislative changes or some kind of different way of doing regulation?

No. Steve, there's no legislative changes. It's all done through the regulatory process. But just keep in mind, and this goes back to the investment – you know, whether it's in our capital plan or not. States deal with it in different fashions. I mean – and if we're talking April, we're going to have to sit down at the end of that April time period and figure out, okay, what are the risks to our shareholders of moving forward with this particular project given the – not only the regulatory outcomes, but also the other risk components that are involved with this as well. And we believe, certainly from a risk standpoint, from an operational and construction standpoint, if we can't put generators on top of poles and build transmission lines that we always build all the time, you know, we shouldn't be in this business. So it's not like building a central station generation facility. So you don't have the same level of risk from that perspective, but the risk part of it – part of the evaluation will be as well – be what kind of indications we're getting from the various jurisdictions because, some of them, you may get outright approval, some of you may get CCN approvals or CECPN approvals in Arkansas. And what is that going to mean? What is it going to mean in terms of risk? So we have another milestone. We continue to spend money on development of this project, because we feel like it's that important. But in the April timeframe, we will be sitting down with our board to talk about, okay, what have we learned? What are the options available to us and what are the risks being taken, and make a decision to continue on.

Okay. Great. And then, just on going back to the Ohio ESP talk, you said you're having discussions and – I can't remember your comment, but I think it sounded optimistic. So can you just give a little more color on how you feel on the ESP extension?

Yeah. So you know these discussions have been going on for quite a while with multiple parties, and some of the issues are new and challenging issues. You know, when you think about Smart Cities and the technology deployment and everybody thinks they ought to have part of the game, and we think, you know, universal access was important and we should be the primary driver of ensuring that that access is providing to all consumers, including underdeveloped, but also others as well so. So it's challenging issues, and things you have to go back and forth with the different parties on. And we've been – I can say we've been fairly successful in conversations with several of the parties. And there's still a few issues that are still outstanding, but we feel like progress is being made.

Okay. Thank you.

Yes.

Operator, we have time for one more question.

Thank you. Our next question will come from Gregg Orrill from Barclays. Please go ahead.

Hey, Gregg.

Hey, thank you. So with regard to the Wind Catcher project, would you consider sell-downs as a way to finance it? Is that something you're exploring?

Gregg, we've already been approached by people who are interested in co-investing with us. Right now, our interest is having this be part of our regulated portfolio and we don't see a need for that at this time.

Okay. Good luck.

Thank you.

Funny how fast word gets around.

Okay, well, thank you for joining us on today's call. As always, the IR team will be available to answer any additional questions you may have. Lois, would you please give the replay information.

Thank you. And, ladies and gentlemen, this conference will be made available for replay after 11:15 today through August 5th. You may access the AT&T Executive replay system at any time by dialing 1-800-475-6701 and entering the access code 426838. International participants can dial 320-365-3844. Again, the numbers are 1-800-475-6701 and 320-365-3844, with the access code 426838. That does conclude our conference for today. Thank you for your participation and for using AT&T Executive TeleConference. You may now disconnect.