Ladies and gentlemen, thank you for standing by and welcome to the American Electric Power First Quarter 2017 Earnings Conference Call. At this point, all the participant lines are in a listen-only mode. There will be an opportunity for your questions and instructions will be given at that time. As a reminder, today's call is being recorded. I'll turn the conference now over to Ms. Bette Jo Rozsa. Please go ahead.

Thank you, John. Good morning, everyone, and welcome to the first 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 thank you for joining AEP's first quarter 2017 earnings call. This quarter, AEP released earnings that are on track for the year despite mild winter weather and an earlier completion during the quarter of the merchant generation sale. So overall, we are very pleased with the outcome for the quarter and sets the tone for confirmation of our existing 2017 operating guidance range of $3.55 to $3.75 per share. We reported GAAP and operating earnings for first quarter 2017 coming in at $1.20 per share and $0.96 per share, respectively. This compares with first quarter 2016 GAAP and operating earnings of $1.02 per share. The difference in GAAP and operating earnings for the quarter was largely driven by the merchant generation sale in which AEP reported a $127 million gain. The story of the first quarter was a mild winter that had an impact of about $0.08 per share and the early sale of the merchant generation that also impacted us in the quarter by another $0.06 per share, but we still made it up – that negative impact by the great performance from continued strategic investments in our regulated businesses and transmission. A little later, Brian will talk more about load numbers and this being the third warmest winter in over 40 years in our service territory. But suffice it to say, we are pleased with the quarter given these prevailing headwinds. Even though our normalized load was down from first quarter 2016, looking deeper at the fundamentals, there are indications for optimism, particularly in the energy sector in areas such as oil and gas, mining, primary metals and others, which we really haven't seen in quite a while. Additionally, our employees continue to be focused on O&M spending and prioritization to…

Thank you, Nick, and good morning, everyone. I'll take us through the financial results for the quarter, provide some insight on load and the economy, and finish with a look at our balance sheet and liquidity. Let's begin on slide 6, which shows that operating earnings for the first quarter were $0.96 per share, or $474 million, compared to $1.02 per share, or $501 million, in 2016. This decline can primarily be attributed to less favorable weather this year than last. Let's look at the earnings drivers by segment. Earnings for the Vertically Integrated Utilities segment were $0.45 per share, down $0.12 with the single largest driver being weather, which negatively impacted earnings for this segment by $0.08. While last year's weather was milder than normal, 2017 was even warmer. Other unfavorable drivers for this segment include a higher effective tax rate due to positive adjustments in 2016 that did not repeat this year and lower normalized retail margins primarily due to 2016 being a leap year with an extra day in the quarter. In terms of retail load and the economy, we are beginning to see some positive signs that I will cover in a few minutes. Partially offsetting these items were recovery of incremental investment across multiple jurisdictions and lower O&M. The Transmission & Distribution Utilities segment earned $0.24 per share for the quarter, up $0.02 from last year. In January, we told you about the global regulatory settlement that we had filed in Ohio which allowed us to resolve several issues related to historical cases. We are pleased that the Public Utility (sic) [Utilities] (17:01) Commission of Ohio issued a final order in February approving the settlement, which allows us to focus our attention on capital investment to improve reliability and better serve our customers. Favorable drivers…

And first go to the line of Jonathan Arnold with Deutsche Bank. Please go ahead.

Good morning, guys. Hello?

Hello? Can you hear me?

Yeah, I can hear you.

Okay. Good morning, Jonathan. How are you?

Morning. Good. Thank you. Just a quick question on transmission. Can you guys disclose whether you've taken some kind of reserve in the numbers for the section 206 pending case?

Yes, we have.

Jonathan, we have. We've just not indicated what that amount is, for obvious reasons.

No. I didn't. I just was curious if you've taken one. That was – thank you. And then on the generation business, it just seems to be tracking kind of pretty well relative to the guidance you'd given for the year, which from memory was like $0.09 from ongoing and $0.09 from assets to be sold, but some of those were sold earlier than you expected.

Right.

So can you just talk about how we should be thinking about the contribution from that business in the context of full-year guidance and what you've said before?

Yeah. So we have filled in – so obviously, we sold the business sooner than we thought. So we had the $0.09 in for the competitive assets that we sold. We sold them early. So we think there's about a $0.06 hit to our full-year for that. But Chuck and his team are working hard to fill that in, to the degree that they can, with what they're able to do in the retail business and wholesale trading and marketing, in addition to what they're able to do in the renewable business. So while it has been a hit, they're working hard to fill that in. And again we don't have – for the remaining part of that business it's about $0.09 or $0.10 as well, so it's not a big swing one way or the other.

But you were at $0.14 in the first quarter was kind of more my question, Brian.

Like how the strong the first quarter was?

Right. And is that going to – are we going to see some give back on the rest of the year or at some one quarter or another? Or is this just structurally going to be a higher number?

I think for the balance of the year we don't anticipate giving any back, so we've gotten ahead versus where we thought we'd be. But I wouldn't anticipate a big drag one way or the other in that business.

And so an ongoing earnings power out of this business would still be in that sort of the dime (27:52) type of number?

$0.10 to $0.15. Think about it.

Okay. And then could I – just one small thing. It sounded like you've not adjusted in your sales numbers for the leap day. And so therefore, they'd have been slightly less negative.

Jonathan, and that's where we get a little crosswise, even with ourselves internally. We had adjusted for it in the budget, but when you look at the comparison to the prior year, it's going to show a negative.

Okay.

And that also will largely eliminate as we work our way through the year. It's a larger percentage of the quarter. It's a very small percentage of the full year.

So just to clarify that, obviously it showed a reduction, but because of the leap year, we still looked at it year-on-year. So if you adjust for that, load was pretty flat.

Fine. Okay.

That's overall. Yeah.

And I guess while we're on the topic, we've noticed the change in the basis of presenting the sales. And it looked like you chose the presentation that looks a little less negative. But can you give us the sort of explanation of why – again I may have missed this on the call, but why you think this is more appropriate?

So billed, we can measure exactly. When you look at accrued, there's a fairly detailed calculation that gets you to the accrued calculation – gets you to the accrued number. So when we present billed and accrued, there is fairly more volatility in how we present the numbers than if we just show what we billed. Remember on a year...

Previous period adjustments and things like that, that's the issue.

Right. So on a year-over-year basis, these things flatten out. When you look at the incremental periods, there's less volatility in just showing the billed. And we wanted to present both of them, Jonathan, because we want to make sure that we're not hiding anything. And like I said, Bette Jo strongly objected to us showing the billed and accrued in the appendix. That's kind of a joke actually. But we felt that both presentation allows you to figure it out. But we felt that billed-only reflects more accurately the trend.

Okay. Thank you for that, and I'll let someone else go. Sorry.

Thanks, Jonathan.

Our next question is from Julien Dumoulin-Smith with UBS. Please go ahead.

Morning, Julien.

Hey, good morning, everyone, appreciate it.

Yes.

So perhaps just to follow up a little bit on your renewable commentary from the call. Can you elaborate a little bit on what exactly the opportunities are on the regulated side? Perhaps just articulate the eligible regulated jurisdictions. And also just talk about how you see that expanding over time. Maybe what is the opportunity and the cadence of that opportunity in terms of capital and megawatts?

Yeah. So we have several RFPs that have been out in various jurisdictions. But we also have the 900 megawatts in Ohio that we're moving forward with. And half of that at least will be AEP Ohio. And then the other jurisdictions, we have solar in Virginia, West Virginia, wind RFP in APCo. They're currently negotiating terms on the purchase of a 225-megawatt project. And then SWEPCO has a wind RFP where they'll purchase up to 100 megawatts of capacity that will also be owned. So you have several areas that are now emerging from an operating company perspective, where we're piecemealing in the renewable side of things from a build standpoint. We still have a couple of them that are outstanding from a purchase – power purchase arrangement. West Virginia and Virginia have a 120-megawatt PPA there, but most of these going in now are more build options.

Got it. And what's the timeline to getting some of these initial bids back and finalized?

Yeah, so as far as the wind RFP, that's probably toward the tail-end of the year, because it gets filed and then going through that process of negotiation and getting the approvals to get it done. As far as the Ohio PPAs, sort of the same type of schedule on those. We've got to go back to the Commission and get – we've already done the bidding and we've got to go back to the Commission and start reeling all those in. And by the way, the legislation makes it more prescriptive as far as new generation, but it won't stop us in terms of investing in the renewables in Ohio, in particular. So, Ohio, West Virginia, SWEPCO, those are moving ahead.

Excellent. And then, turning back to the transmission side, obviously, we've gotten a court case. How, if at all, does the latest court case impact any of your 205 or 206 filings? I imagine that might even impact the settlement discussions themselves. I'd just be curious.

Yeah. I think that's probably more long-term, but it really referred back or remanded back to the FERC to really focus on how to come up with the result that they did. So, as we look at it, I don't think it's going to have much impact in the discussions that we have. It could delay a decision, because they may want to get through that process, but we still feel like, as far as 206, it's in that reasonableness framework and FERC still – at least, the previous FERC. We have new FERC Commissioners coming on, I guess, pretty soon, but their driver will still be on the investment in transmission. And so, we expect them to fortify the results that they came up with and it should be fine.

But to be clear, the court order doesn't necessarily change your expectation of the (34:49) requirement on the...

No.

Okay. Great.

No. It doesn't.

Got it. All right. Excellent. Well, thank you all very much.

Sure thing.

Next, we'll go to Ali Agha with SunTrust. Please go ahead.

Thank you. Good morning.

Good morning, Ali.

Good morning.

Good morning.

Good morning. Nick, to the extent that you are successful in tweaking the Ohio legislation that you're looking at, could that potentially lead to incremental CapEx opportunities – rate-based CapEx opportunities beyond the $17.3 billion that you've laid out over the next three years?

It could. As a matter of fact, the 900 megawatts is not included in our present forecast on the renewable – our financial forecast, so you have that. And what we're really trying to get with that second part of it, which you mentioned, is the ability to go back to the Commission in a very prescriptive manner to get the approval for whatever kind of resources we want to have done. So, those would all be incremental to that effort. And we really believe – in Ohio, if Ohio wants to take on its own resource portfolio, then there has to be a mechanism for that type of investment and we want to be there to make those investments. So, it would be incremental.

Okay. And then, I guess, Brian, how much headroom do you have – when you look at that CapEx budget, $17.3 billion, how much headroom do you have that you could potentially increase that without having to go to the equity markets?

We have some room in our balance sheet to be able to that, and we continuously look at that as we're trying to measure how much CapEx we put into growth, how much dividend we pay out to our shareholders and what the strength of our balance sheet is. But if we were to get some of those incremental projects, either renewable or transmission, we believe we could fund those without having to access the equity markets.

Good, good. And last question, just to clarify, again, Brian. So, as you mention, the early sale of the merchant portfolio kind of created a bit of a gap in terms of the earnings that you'd budgeted for the year, but given the results through the first quarter, I just want to be clear, are we still trying to fill the gap or is the gap now largely filled? How should I be thinking about that $0.06 gap?

So, I think we were looking at about $0.09 from the competitive generation assets and $0.09 or $0.10 from that business – the go-forward business that we were going to keep; so, all together, about $0.20. We're at about $0.14, now. We still think we'll be in that $0.20 to $0.25 range for the combined businesses for the full-year.

Ali, just to go over one point, though, when – and I mentioned that our employees have been working really hard to look at O&M and those kinds of issues. When the quarter started out – the first quarter started out, we knew we were going to close this transaction. I think it was at the end of January, we closed it. So, we were $0.06 short. January and February, as you recall, were very, very warm winters and we knew we were getting behind from that perspective. So, we started the process of going through our organization to determine what we could do from an O&M perspective to bring all of this back into line – to alignment, and that's what we do. We do that on a regular basis and those plans are there, and we'll continue to manage that through the year. So, when you think about a $0.06 gap or anything like that, just remember, we know there's a $0.06 gap, too, and we're working through that. And our employees are used to this. I mean, it's amazing to me. I think – from a cultural perspective, over the last five years, we have certainly gotten to the point where our employees are fully engaged in what we're trying to achieve and demonstrate to our shareholders and to our customers. And I'm very proud when we have things like that occur, that we adjust to it, and we'll continue to adjust to it.

Got it. Thank you.

Our next question's from Praful Mehta with Citigroup. Please go ahead.

Good morning.

Hi. Thanks, guys. The first question was on the remaining generation assets. I know it's a small fleet left now – or small set of assets left now, but when do you think you have a decision on what you want to do with them in terms of the strategic review? Is that sale process – if it were to go down the sale process part, do you think that's something that you can get done or at least announce this year? And is part of that the retail business? If you do exit all the generation, do you intend to then hold on to retail or is retail something that you would also look to exit from?

Well, first of all, on the rest of the competitive business, that strategic process is in place. It's been going on. Negotiations are going on and we expect a result on that before the end of the year. And remember, we've already written those assets down. So, from a financial standpoint we're practically out of it, but nevertheless, we're going through that process to ensure that we wind up with arrangements that we can live with relative to those assets. So, that will continue. As far as the retail is concerned, I know this discussion goes back and forth based upon the exposure relative to retail. From day one of the retail effort, we have been very, very disciplined in our approach. It's relatively small, about 450,000 customers. And we manage and hedge that very well regardless of whether we have generation or don't have generation. Now, it'd be preferable to have generation. Obviously, we're looking at that from a strategic standpoint. But nevertheless, we feel very good about where we sit from that perspective. The other side of it is strategic. I really believe that the retail customers we have, we have a relationship with those customers. And if you look at the future and what it holds relative to our business, that relationship is going to be critical, not only in terms of providing their energy needs, but in terms of the channel growth associated with additional earnings associated with serving those customers. So, at this point, I'd say as long as we can manage it and be very disciplined about it and it provides a strategic hedge for us, particularly if jurisdictions decide to go deregulated or whatever, we have the foundation to make sure we're successful. So, at this point, that's the way we look at retail.

Got you. But if there was an IPP looking to match their generation with retail, are you open to opportunities at this point or the intention is to keep it at this point in terms of the strategic review?

No. We're open to those opportunities because, obviously, having generation attached to it in some fashion not only provides a hedge, but also it could provide further benefits in terms of growth to that part of the business. But it has to be done in a very disciplined way.

Got you. And then, just moving to the renewables side, the contracted renewables, then, is the deregulated side. It looks like, off that $1 billion investment, there seems to be good progress this year in terms of the investments in that business. Just wanted to understand from an end-game perspective, once you do have the three-year $1 billion investments and you've completed that cycle, is the intention, then, to kind of continue to re-up and reinvest or allocate capital towards further building out that platform or, at that point, would you go through a strategic review? Just wanted to understand what happens post the three years.

Yeah, I think the way we look at it is, obviously, it's a continuing part of our business, but our business is really about the capital allocation. And it's about the issues that we have ongoing with our lines of businesses. So, if there's additional transmission capability out there, we're going to take advantage of it. If there's additional opportunities from a regulated infrastructure standpoint, we're going to take advantage of it. If there continue to be opportunities with a high threshold that Chuck maintain – Chuck Zebula maintains for his business, we're going to take advantage of that as well. But it'll all be within the context of ensuring that we get the most stable earnings capability that we can get and, as well, provide that consistency to the market and invest in the right things. That's clearly where we stand. So, it's hard to say what will happen in three years. And if you look at some of the things that we see, there's additional opportunities that we may or may not be able to take advantage of, that we have a pipeline of needs for capacity and for capital. And we're going to take advantage of it in the best way we can. So, it really is all about capital allocation, not about growing a contracted renewable business.

Got you. And then, if tax reform were to actually pass and you did have the tax rate going from like to whatever, 15%, does that impact or would that impact your decision in any way around this business?

Certainly, the tax effects are a critical part of this business. So, we'll make that determination when we know what the – any investment tax credits or whatever does relative to that. So, the key component around tax reform, you got to remember, though, and we want to maintain that position, is that we have less debt at the parent and, because we have debt at the operating companies, we have the flexibility to work with our jurisdictions on whatever the result is from a tax reform perspective. So, that in itself is a risk mitigation effort for us. So, we're not going to go longer in terms of risk relative to contracted renewables or anything else.

Got you. Much appreciated. Thank you, guys.

Yes.

Our next question is from Steve Fleishman with Wolfe Research. Please go ahead.

Morning, Steve.

Hey. Good morning. My question was actually answered. Thank you.

Good.

And we'll go to Paul Patterson, Glenrock Associates. Please go ahead.

Good morning. How are you?

Morning, Paul. How are you?

Okay. Just on the – I know that you guys are very much less in the merchant business. But there are some proposals that PJM is entertaining with respect to state subsidy impacts on the wholesale market. They've got several initiatives. And I'm not asking you go over all of them. But just in general what do you think about the potential of those to potentially coming about? And how they might influence the policies in Ohio?

Well, I guess the real question is, any proposal out of PJM, is it going to be timely enough for anything? Because it takes so long to get through any kind of process. So when they talk about market reform to adjust for what the states are trying to do because of a lack of ability to cover base load generation in PJM's competitive market, I think it's going to take time for them to do. I mean you put it in a stakeholder process and who knows when it makes it out. And then you go from there. So I guess and maybe my – our past history of dealing with the organized markets from a merchant standpoint is clouding my judgment. But I wouldn't bet on a lot of major changes there that would be particularly timely, particularly for nuclear and certainly for coal as well. And from a state perspective I support the state stepping up where the organized markets don't cover what needs to be covered to ensure that there is a balanced portfolio. And if FERC doesn't do it, then the states should. And the FERC should let the states do it, because unless you do, really focus on these organized market reforms that enable a balanced portfolio to continue to exist. It's a risk management question, not a literal market, lowest cost type of question. So until that's resolved, I support the states.

Okay. And then – thanks for that. Then in terms of the solar tax credit amortization that impacted I guess tax rates for the Generation & Marketing. I apologize if I missed this, but what – could you just elaborate a little bit more on what that is? And how we should see that going forward?

Yeah. We do the longer realization measurement, rather than realizing it all at once.

Okay. And that's...

The one that's much more consistent with the regulated utility model.

Okay. And why did that drive down tax rates this quarter versus last quarter?

So we had a solar project where we had the investment tax credit where it's realized contemporaneously, so that's what drove it down. So we had the investment tax credit on a solar project where we realized it in the beginning period.

In this first quarter?

Yes.

Okay. And how will that – and so that just sort of – that's kind of a one shot in the arm kind of thing?

Correct.

Okay. Okay. And then just finally, and I apologize for missing this. But you did mention quickly on the call that there was a SEET impact that would change the ROE. That we should be careful in looking at that equalizer chart with respect to the impact on SEET. And I just was wondering, what would the SEET number be? Or roughly speaking, if it was adjusted for that?

Yeah. We haven't discussed that. All really we can say is that the 14.5%, there are some legacy issues in there. So when a SEET test actually occurs, which I guess was filed second quarter of 2017 for 2016, that that would be excluded. So you look at it on its face value, 14.5% looks pretty robust. But you got to consider that there – whenever a SEET test is done, issues get excluded, which would bring that ROE down. But we haven't said what that is.

Okay. So the ROE would be lower. Okay. Just wanted to make sure. Okay.

Yeah. Yeah.

Thanks so much.

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

Hey, good morning.

Morning, Anthony.

Nick, I wanted to jump on something you maybe – and I may have misheard it. To Praful's question, when you were talking about the retail business, did you say you would strategically look at merchant generation to add to the retail portfolio if it made sense?

No, didn't say that. No, didn't – no, I think what we're saying – we're saying is that, if there's opportunities to match generation in some fashion with the retail play, that that wouldn't – that could make sense. But it doesn't mean we're going to go acquire or buy or have more merchant generation to back it up. That's not the case.

Okay. And my real question was on Ohio. Just I want to understand what's happening in Ohio. You're saying that you're going to try to I guess separate the bill, where you're going to request I guess approval of the OVEC plan first. And then, second, go in for I guess the – I don't know if it's restructuring, the word restructuring.

Yeah.

Is that the process in – is it a fair read-through, you think, for investors, if you receive approval for OVEC, that's a good litmus test for the restructuring?

Yeah. So both are in; both are in right now. There are some legislators who have indicated because OVEC is probably a cleaner issue to drive through pretty quickly, because there's some reasons to get OVEC clarified that sort of – it's a much easier proposition to get done from a legislative standpoint. The broader question of this ability to invest on behalf of the electric distribution utility is a broader question that brings in probably more issues to be discussed. So, the question is, do you try to do it all together or do you just drive out the easy part first, and then deal with the one that has just the broader issues associated with it. So, that's what I was talking about. So, that's why – one may get solved – the OVEC thing may get solved third quarter, and then the other gets solved fourth quarter. And so, that way we can have a dialogue of all the parties and get a more robust solution on the second part of it. (53:41)

Sorry. Go ahead.

I was just – my question – would the OVEC part of the original filing – and I apologize the year, so like 2014 or something, that was the original filing you made in Ohio?

Yeah, it was. We wanted more prescriptive language in there that allowed for – to ensure that OVEC can continue on from here on out till it gets that recovery from the AEP Ohio side because we never – that PPA has always been with AEP Ohio and stayed with AEP Ohio even with deregulation. So, we want to make sure that it continues to be attached to the AEP Ohio distribution company.

Great. Thanks for taking my questions.

Yes.

Next, we'll go to Stephen Byrd with Morgan Stanley. Please go ahead.

Good morning, Stephen. Stephen Calder Byrd - Morgan Stanley & Co. LLC: Hi, good morning.

How are you doing? Stephen Calder Byrd - Morgan Stanley & Co. LLC: Most of my questions have been addressed. I just want to follow up on Ali's question on the balance sheet. Brian, the FFO to debt stats look very, very good compared to the target range. Should we assume that there is some ability to move downward within that range? I guess, I'm thinking generally in the middle of that range rather than be at the high end of the range to the extent that you find more investment opportunities?

There is, Stephen. Part of what we're trying to balance is – I joked that a little over a year ago, the U.S. Congress dropped $3.5 billion on our Treasurer's lap and said, hey, can you use this in terms of bonus depreciation. And then, we had proceeds from a sale of about $2.2 billion again this year. And what I think we've shown is an ability to put that excess capital that we found to work in growing our business organically. The benefits of those things start to wane a little bit as we get to the end of the decade and those credit metrics get back in to the middle part of the range, how do I say it, naturally as some of the benefits that we're working through have been reinvested in the business, one, and expire in terms of the tax benefits, two. Stephen Calder Byrd - Morgan Stanley & Co. LLC: That's great. That's a good point. That's all I had. Thank you.

Thank you, Stephen.

And we'll go to Paul Ridzon with KeyBanc. Please go ahead.

Good morning.

Hey, Paul. How are you?

I'm well, thanks.

Good.

I hate to bring it up, again, but would you keep some of the Ohio generation as a backstop to retail, is that what you were driving at?

No. No. What we're saying is if there was a hedging relationship that could be done through contract with a generation provider – just like we do in our normal hedging practice. Instead of hedge against the market, hedge against some generation. We're open to that. We're not open to owning generation. Been there, done that, not doing it again. So, as far as maintaining generation in Ohio to support the retail effort? No. That's not in the cards, either.

Thank you for that clarification.

Yes.

And then, Lisa's business did pretty well this quarter. Was there anything unusual in this, and then what's the outlook for this for the rest of the year?

I think it continues to be robust according to the plan. And certainly, as additional other opportunities arrives, we'll take advantage of it just like we have in the past. And Lisa continues to review her transmission projects and Transource's transmission projects as well, and will continue to do that. So, she – her business has performed very well, and we continue to see that progressing.

Was there anything – any large projects or anything came on this quarter or year-over-year that kind of drove that nickel uptick?

Are you talking about transmission?

Yes.

Okay. So, a component of that was the 205 filing being retroactive to January 1. Does that make sense?

Yes.

So, we got an administrative order from FERC that allowed us to go back and put our 205 filing in effect January 1, and that allowed us to pick up $0.04 or $0.05.

Got it. Okay. Thank you very much.

Thank you.

And we'll go to Michael Lapides with Goldman Sachs. Please go ahead. Michael Lapides - Goldman Sachs & Co.: Hey, guys. Thanks for taking my question.

Good morning, Michael. Michael Lapides - Goldman Sachs & Co.: Good morning, Nick. You guys have done, and many other utilities as well, a lot of work around getting – improving regulation in some of the states, like Arkansas with the new formula rate legislation, in Louisiana with its formula rate plans. Just curious, how do you think about making similar type of changes in a place like Oklahoma, where not just your company there, PSO, but others deal with significant amounts of regulatory lag, where the rate of recovery versus request tend to come in very different than what you see in a lot of other regions? How do you think about, from either a legislative or a regulatory process, whether to fix that and what are your alternatives if you can't?

Yeah, so, wherever we can do it, certainly, we'd love to pursue formula base rates in the various jurisdictions because, obviously, it brings more concurrent recovery of invested capital. And you continue to do that. I mean, certainly, you mentioned Arkansas, I think in Indiana, Michigan there's some form of formula rate. So – there's riders associated with that, a lot of riders, but certainly from a formula-based rate perspective, we'd like to see that progress because these states that have large regulatory lags – and Oklahoma was a perfect example where you file a case and it takes a long time to get recovery and approval of the rates. And then, there's a haircut associated with it, but still drives the utility at subpar ROEs. I mean, here's, what, 7.6% or whatever it was in Oklahoma with an authorized return that's higher than that and you never catch up. We're having to file another rate case to make the point that, hey, we're not getting the returns from the investments that we're making in this state. So, for those states that have – I mean, it's fine to have – if you don't have formula-based rates, at least have a rate case mechanism that's timely and even some forward-looking aspects of it to ensure that we can invest the capital that's needed and required for the benefit of our customers. So, Michael, we're working on that across the board. It's really been in the context of riders, but where we can get it, we're focused on getting these formula-based rates in place. Michael Lapides - Goldman Sachs & Co.: Do you need legislative change in Oklahoma to improve the regulatory rate-making process or can that be done directly between the utilities and the OCC?

Yeah. It's a constitutional issue in Oklahoma. So, yeah, we would certainly – that'd be a lot more support, I guess, than just legislative. But Oklahoma can fix the situation though, by – actually, in Oklahoma, we have had some pretty progressive riders in place and they've done a decent job of that, but the rate case aspects is just taking too long and getting results that are subpar and you're always behind the eight ball. So, we really need Oklahoma to step up the game a little bit in terms of our ability to make the investments that Oklahoma requires. I mean, Oklahoma is in a situation where they have a massive set of potential around generation to reduce customers' cost, and also these other mechanisms, investments to be made that really benefit. We did the tree trimming cycle in Oklahoma through a rider and it worked great from a outage recovery perspective. So, there's a lot of benefits out there that are being impeded by the progress to get these cases through. So, hopefully we'll make some progress from that perspective. Michael Lapides - Goldman Sachs & Co.: Got it. Thanks, Nick.

Yes.

Operator, we have time for one more question.

And we'll go to Shahriar Pourreza of Guggenheim Partners. Please go ahead.

Hi, Shahriar.

Hey, guys. Actually, my questions were answered. Congrats. Thanks.

Okay. Thank you.

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

Certainly. And, ladies and gentlemen, this conference is available for replay. It starts today at 11:15 AM Eastern Time; will last until May 4 at midnight. You can access the replay at any time by dialing 800-475-6701 or 320-365-3844. The access code is 421901. Those numbers, again: 800-475-6701 or 320-365-3844, access code 421901. That does conclude your conference for today. Thank you for your participation. You may now disconnect.