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Ladies and gentlemen, thank you for standing by. Welcome to the American Electric Power First Quarter 2018 Earnings Call. At this time, all participant lines are in a listen-only mode. Later, there will be an opportunity for your questions. Instructions will be given at that time. As a reminder, today's conference call is being recorded.
I would now like to turn the conference over to Bette Jo Rozsa. Please go ahead.
Thank you, Lea. Good morning, everyone, and welcome to the first quarter 2018 earnings call for American Electric Power. We appreciate your 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 again to AEP's first quarter 2018 earnings call. We were very happy to get out of 2017 in a respectable fashion with one of the mildest years on record, but still delivering results within our guidance range for the year. We're off to a much more normal start in 2018 financially with more normal weather buoyed by what appears to be a resurgent economy. In fact, AEP service territory economy and load performance is as strong as it has been in years.
Unemployment rates are the lowest since 2000 and retail sales are up in all classes, all companies, and actually in all 10 sectors of the economy, which hasn't happened since 2011.
With that said, because of O&M timing and this return to normal levels after a year of reductions due to weather, our results for the quarter were on par with expectations in achieving our stated guidance range for the year of $3.75 to $3.95 per share, which we are reaffirming.
The first quarter 2018 EPS came in at $0.92 per share GAAP and $0.96 per share operating versus a $1.20 per share GAAP and $0.96 per share operating respectively in 2017. So, overall, a good quarter and start for the year. Looking deeper into the quarter, and Brian will cover this in more detail, fundamentally, we are in better shape than in the first quarter of last year given this has been a busy quarter of rate case outcomes that set the tone for the future.
I'll get into the rate case outcomes in a minute, but first I want to say thank you to our employees who worked so hard in the recovery efforts after last year's hurricanes; hurricanes Harvey in Texas, Irma in Florida, and Irma and Maria in Puerto Rico. Our last employees have returned from Puerto Rico and I'm so proud of their accomplishments in very severe conditions. In our business, they are our heroes.
Now, let's talk about some activities of interest here in this quarter. Wind Catcher is finally feeling some tailwinds. We have accomplished important settlements in Arkansas, Louisiana, and now Oklahoma with the industrials and Walmart that provides the framework for the various commissions to bless this significant project and its benefits for our customers.
We are continuing to try to bring other parties in Oklahoma, such as the Oklahoma staff on the settlement agreement and are continuing our efforts in Texas to achieve a settlement as well. We have taken on manageable risk intended to recognize market expectations relative to regulated wind projects and have worked hard to mitigate these risks in the background with engineering, construction, and operational strategies. We are confident in our ability to deliver the expected benefits to our customers and shareholders and look forward to obtaining Commission approvals so that we can move forward as quickly as possible. We are now awaiting Commission orders in Oklahoma, Arkansas, Louisiana and Texas and expecting orders in the May and June timeframe.
Regarding Ohio, we just received an order yesterday. We're pleased that the Public Utilities Commission of Ohio approved the settlement for the most part in the Ohio ESP case. Not only do we now have an ESP that is effective through 2024, which certainly brings an important element of stability, it also preserves the continuation of the Distribution Investment Rider at the settlement agreement level and a 10% ROE.
The order also supports future opportunities through the smart city initiative and the Renewable Generation Rider. These components really look to the future as a vision by Chairman, Asim Haque's PowerForward initiative.
AEP stands ready to support the PUCO in this important endeavor. Additionally, the Columbus Smart City initiative has taken a major step forward in providing societal benefits of electrification, EV adoption, distributed resources, smart street lighting and other benefits that will define the future for Columbus and the nation.
This order also preserves our ability to collect for OVEC subject to certain transmission-related limitations through 2024. All in all, a good order, brings stability and certainty to future benefits that will support AEP's drive to improve the customer experience.
Several other rate case outcomes have produced positive results. In Indiana, I&M has a settlement agreement filed and we anticipate a July effective date of a net revenue increase of $97 million, which includes tax reform adjustments and 9.95% approved ROE.
In Michigan, in order effective this month with a revenue increase of $49 million and a 9.9% authorized ROE has been completed. In Kentucky, a 9.7% authorized ROE and a net revenue of $16 million, adjusted for tax reform, was effective in January of this quarter.
SWEPCO Texas increased – their increase of $50 million and 9.6% ROE that was approved and retroactively applied to May of last year. In Oklahoma, which is our only significant rate case disappointment with only a 9.3% authorized ROE and $76 million net revenue adjusted for tax reform was effective in March.
And speaking of tax reform, the adjustment for tax reform in the Oklahoma case assumed that the authorized ROE versus the actual ROE of 5.2%, that cost PSO another $15 million. So, we have some work to do to try to clarify some of that activity. Brian will be discussing tax reform itself in more detail in a couple of minutes.
Because PSO's effective ROE is only 5.2% we're evaluating our options regarding cost control and additional rate case activity. Regarding the FERC 206 transmission cases, in the East, we filed with FERC a settlement with several of the parties that resolves all issues set for hearing.
The settlement agreed to have base ROE of 9.8% subject to a cap and common equity of 55%. With the RTO adder of 50 basis points, the effective ROE will be 10.3% and we will adjust our 50/50 cash structure to reflect the 55% equity layer.
Interim rate changes reflecting these settlement parameters were filed with for PJM earlier this month. We await a final order from FERC as we bring certainty to our transmission-related investments in the East. Where AEP has much less exposure in the West, settlement discussions have stalled. We stand ready for further discussions, but this may likely go to hearing for a resolution to occur.
So as you move to the equalizer chart this time around, many of these many of these companies we've already covered so this will be a sort of a shorter version. But overall, our regulated ROEs are 9.5%, which it was 9.5% last quarter. We generally target the 10% range. And as you know, we have currently five rate cases that are completed. So, we expect these ROEs to continue to improve across the board.
Regarding AEP Ohio, the ROE for AEP Ohio at the end of the first quarter was 13.7%, but that includes issues that are actually excluded for evaluation of the SEET. And also, the SEET-adjusted ROE is 9.5%. As you recall, they have some legacy issues that are excluded from the calculation such as the RSR, some fuel-related activities, and 2014 SEET refund. So, the effective return is 9.5%. And those legacy items generally roll off at the end of the year. So, hopefully, we'll be able to merge those two bubbles into something that makes sense later on.
APCo, APCo at the end of the first quarter was 9.2%. APCo's improvement in ROE over the fourth quarter of 2017 is primarily weather. Just a note, the Virginia Legislature passed legislation establishing triennial rate reviews, and APCo's first triennial review will be in 2020 and will cover the 2017 to 2019 period. So, we have a little work to do there. And then West Virginia, we intend on following a rate case in May in that jurisdiction.
I already covered Kentucky, but just wanted to mention to you that we do have a couple of large aluminum company and a battery storage manufacturer located there, and that's part of our long-term strategy around improvements in the ROEs in Kentucky. Certainly, the economic development part of that is very important.
As far as I&M, I already covered both of those. PSO, I think we've talked about enough. SWEPCO continues to have the effect of not only the Turk 88 megawatts, which we'll have to deal with in the future, but also they lost some wholesale contract load that went off at the first of the year. So, that was an impact for them. But we expect them to move up just a little bit as form of (10:16) base rates and other mechanisms come into place in the retail jurisdictions.
AEP Texas, the ROE for AEP Texas at the end of the first quarter 2018 was 10.1% versus 10% last quarter. AEP Texas, their steady ROE is primarily attributable to favorable regulatory treatment in Texas with the ability to file an annual DCRF and TCOS filings. AEP Transmission Holdco continues to do well. At the end of the first quarter, it was 12.9% and it's slightly better than the fourth quarter due to benefits from tax reform and some timing matters. So, generally, while it looks like there's a trough there, we fully expect that to continue to improve with the rate case outcomes that we've put in place.
So, this has been a normal quarter financially, but an outstanding quarter overall from an execution standpoint that sets the tone for 2018 and beyond with several rate case outcomes and settlements regarding Wind Catcher behind us, as Rush's classic rock song, Red Barchetta, which – Red Barchetta is a car, it's a two-seater Italian car – would say it's time to strip away the old debris, fire up the shiny Red Barchetta and respond with a roar. That's what I see in the excitement, the energy of our teams of employees at this company working on projects such as Wind Catcher and other technology advancements that will change the face of AEP's interaction with our customers.
To paraphrase one of the latest Rock and Roll Hall of Fame inductees, Bon Jovi, and I know this phrase will stick with you the rest of the day, we're halfway there, living on a prayer, take our hand and we'll make it, we swear. So, enjoy the ride with American Electric Power. Brian?
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, review our balance sheet and liquidity, and finish with an update on tax reform.
Let's begin on slide 6, which shows that operating earnings for the first quarter were $0.96 per share or $473 million, comparable to last year's results. All of our regulated segments experienced growth for the quarter. And as expected, our competitive Generation & Marketing business was down due to last year's asset sales.
Looking at the drivers by segment, earnings for the Vertically-Integrated Utilities were $0.47 per share, up $0.02. Most of the $0.12 increase in weather was driven by the warm 2017 winter. Rate changes were also favorable due to the recovery of incremental investment across multiple jurisdictions. Offsetting these favorable items were anticipated decreases in our wholesale load as well as increased O&M and depreciation expenses.
The Transmission & Distribution Utilities segment earned $0.25 per share, up a penny from last year. Favorable drivers in this segment included higher normalized load, weather and rate changes, each contributing a penny. Partially offsetting these favorable items were higher O&M and depreciation expenses.
The AEP Transmission Holdco segment continued to grow, contributing $0.21 per share, an improvement of $0.07 from last year. This growth in earnings reflected our return on incremental rate base as well as other items, including a true-up for the FERC 206 settlement and other small non-recurring items. Our investment in this segment grew by $1.7 billion since last March.
Generation & Marketing produced earnings of $0.08 per share, down $0.06 from last year, primarily due to the sale of assets. Finally, Corporate and Other was down $0.04 per share from last year due to higher interest and O&M expenses and a prior-year investment gain. Overall, we experienced a solid quarter and are confident in reaffirming our annual operating earnings guidance.
Now, let's turn to slide 7 for an update on normalized load growth. Starting in the lower-right chart, our normalized retail sales increased by 1.5%, which is similar to last quarter. For the first time since 2011, we experienced normalized load growth across all three major retail classes.
Moving clockwise, industrial sales increased by 2.5% for the quarter. Each of our top 10 industrial sectors reported growth versus last year for the first time in years. Sectors that posted the strongest growth this quarter were pipeline transportation, oil and gas extraction and primary metals. The impact of tax reform, higher energy prices and a stronger global economy, as well as a weaker dollar, have all combined to create a positive environment for industrial sales.
In the upper-left chart, normalized residential sales were up 1.4% for the quarter. The chart shows improvement in residential sales over the past year. The growth is spread across both the Vertically-Integrated and T&D Utilities segments. Customer accounts were up 0.5% compared to last year, which is the strongest we've seen since 2015. Weather-normalized usage was also up 0.9% this quarter, and has correlated with the recent improvement in incomes, which I'll discuss in more detail on the next slide.
Finally, in the upper-right chart, commercial sales for the quarter increased by 0.5%. This is the first time since 2016 that our commercial class reported growth, which was largely concentrated in Ohio and our Western service territory. We continue to expect modest gains in commercial sales in 2018.
Now, let's move to slide 8 and review the status of our regional economies. As shown in the upper-left chart, GDP growth in AEP service territory exceeded the U.S. by 0.4% in the first quarter. In fact, the economy in AEP service territory has been growing at a faster pace than the U.S. for the past year. The upper-right chart shows that employment growth in AEP service territory continues to close in on that of the U.S.
For the quarter, job growth in AEP service territory was at 1.1% with higher growth in our Western territory than our Eastern. And while employment growth has continued to improve, unemployment rates in our footprint are at their lowest level since 2000. The bottom chart on this page shows growth in personal income. In the first quarter, income growth within AEP service area was 0.7% greater than the U.S. Rising customer incomes was a key driver for the increase in residential sales.
Now, let's move to slide 9 and review the company's capitalization and liquidity. Our debt to total capital ratio increased 1.1% during the quarter to 56.6%. Our FFO to debt ratio was solidly in the Baa1 range at 18.2% and our net liquidity stood at about $1.3 billion supported by our revolving credit facility. Our qualified pension funding improved to 102% and our OPEB funding improved to 131%. For both plans, the funded status improved due to rising interest rates, driving a decrease in liabilities that more than offset asset losses.
Let's turn to slide 10, and I will update the tax reform information that I provided earlier in the year. In regards to the change in the statutory corporate rate, we either have regulatory orders in place or filed settlements to reflect a lower rate in Indiana, Kentucky, Oklahoma and FERC Transmission for our Eastern states. In our remaining regulated jurisdictions, we are deferring the difference between the old and new rate for future adjustment. Trackers and formula rate filings will accommodate this change in Louisiana, AEP Texas and Ohio.
We have updated the slide to show that as of March 31, we have approximately $1 billion of excess deferred income tax, which is not associated with depreciable assets and will flow back to customers at a tenor set by each jurisdiction.
Options for passing this benefit to customers include decreasing rates for some period of time, increasing the amortization of regulatory assets, accelerating depreciation and offsetting items that would otherwise increase rates. We have addressed this issue in our Indiana and East FERC Transmission settlements and are working with our remaining jurisdictions to determine the best resolution.
As we discussed in January, we reduced our 2020 capital expenditures by $500 million to support our FFO to debt ratio, and we reiterated our equity plans which we anticipate raising $100 million in 2018 and 2019 and $500 million in 2020. As a reminder, this plan does not include provisions for Wind Catcher. In addition to this slide, there is more detail on slide 23 of the presentation.
Let's try and wrap this up on slide 11 so we can get to your questions. We will finalize our pending rate cases, obtain clarity on the Wind Catcher project, and continue working with regulators to provide the best solution for customers regarding tax reform. Our performance in the first quarter and the stability of our regulated business model gives us the confidence to reaffirm our operating earnings guidance range of $3.75 to $3.95 per share.
With that, I will turn the call over to the operator for your questions.
Thank you. Our first question is from the line of Greg Gordon with Evercore. Please go ahead.
Good morning, Greg.
Good morning, guys. Several questions for you. I'll try to make them brief. First is congrats on the Wind Catcher settlement in Oklahoma. You have a couple parties on board, but you have many more that have not officially signed on. But can you give us some color around the negotiations there? And what, on the margin, you have conceded to give up in this settlement to give customer protections versus the prior deal? And what it might take to get more parties on board?
Yeah, Greg. Obviously, a great question. We continue to try to get other parties on board. But as we said from the beginning, it was extremely important to get the industrials on board in Oklahoma. And I think by getting them on board, it certainly sets the predicate for the opportunity for the commissioners themselves to look at this and say, okay, we've got both the industrial customers and Walmart, and the customers have spoken.
Now, there are other parties, as you mentioned. And certainly, we're trying to get the Oklahoma staff engaged in this process and, certainly, the Attorney General – probably not likely to get the Attorney General on board. But others will continue to be open to that, including the Attorney General.
But at this point, though, I think it's framed up pretty well, because a lot of work's been done in the background. Our people have been working tirelessly with all these parties around the various jurisdictions to try to drive some consistency around what the risks were being taken. And a lot of it centered on the 10-year look-backs, the performance guarantees, certainly the force majeure-related provisions as well.
And it really – as we looked at it, and as I mentioned early on in our discussion, you have to – if you're going to do regulated renewables, then certainly we'll have to meet the market on what risks are being taken relative to regulated renewable investments. And we looked at it, looked at it in a lot of detail. We have a lot of, like – as I mentioned earlier, engineering and construction. We looked that in detail, the operational characteristics of particularly the generation tie (22:16), and we've come a long way in terms of the evaluation of those risks.
We were willing to take it, and the industrials were ultimately supportive. So, I think it just sets the tone for continued discussions. But as far as I'm concerned, we've put it in a very good place, and you'll note that those provisions are pretty consistent with the settlements that have been done previously by SPS over in New Mexico and Texas. And we're having discussions with the Texas parties now. So, you're starting to see, in my opinion, a coalition around what risk parameters, what the framework of a deal looks like, and I see that momentum gaining.
Well. Good luck with that. I think that's great. Two more questions. One is on when you look at the equalizer chart, in Oklahoma, I know PSO on a trailing 12 only earned 5.2% and the rate decision you've got there wasn't great, but it was better than the skinny deals that Oklahoma traditionally gives. So if we were to extrapolate out 12 months, we would still expect PSO's ROEs to improve dramatically, maybe if not towards your best case aspiration. Is that fair?
Well, the odd part about it is, if Wind Catcher gets approved, ultimately it's going to help the ROE overall because PSO has a really small rate base. I mean, essentially, no generation's been built there for quite a period of time. So you're really dealing with a large company that – with a lot of PPAs for generation. So, the rate base itself has dwindled to really pretty small. I mean it's less than 5% of the earnings of the corporation. And so, when you think about where PSO is heading, if Oklahoma really wants to develop infrastructure around these types of assets, energy assets, to take advantage of wind power, natural gas, certainly indigenous sources for that territory, we're going to have to see positive signals on those types of investments.
And they really do need to fix the issue of recovering transmission cost as well on a timely basis. So, a lot of this rate lag type of activity, it took a long time for the last rate case and actually the rate case pretty much turned out to be very disappointing. I was really expecting more from the Oklahoma Commission from that perspective, but I think there were a lot of issues that were being dealt with there that, hopefully, next time we'll be able to get over and we will be following another rate case in Oklahoma. But certainly, the Wind Catcher approval is what we have our sights on right now.
Great. And my last question is on page 9, we look at the credit statistics, obviously, on a trailing basis here at 18.2% FFO. But tax reform really hadn't kicked in yet, and I know you said the target is the mid-teens. But all things being equal, if we look out 12 months, how much of a degradation in that FFO are we looking at? Is it a couple of hundred basis points?
Brian.
We think it'll be 200 basis points to 300 basis points, Greg.
Okay. Thank you, guys.
Yeah. Sure thing.
Next, we go to the line of Steve Fleishman with Wolfe Research. Please go ahead.
Yeah. Hi. Good morning.
Good morning.
So, speaking of living on a prayer, I have a few Wind Catcher question. Sorry. I couldn't help. You asked for that one.
(26:31).
Yeah. Thank you for the Rush references, those are great. So just if I recall back last fall, you had talked about wanting decisions by April to make sure that you would have it online to get the full PTCs.
Yeah.
Is May-June going to be okay to be able to capture full PTCs? Like, what is the real deadline?
Yeah, we'll be fine. Really, we have to get to a point of getting these orders in place, and then we'll cover it with our board, obviously, in our July meeting. And then once they approve it, we're off and running. So if we get it in that June timeframe, we get the orders in the May to June timeframe, we'll be in good shape.
Okay. And then just you're appropriately very focused on making sure you're not taking on risks that are not typical for regulated investment. Could you – and I know you just did this, but just when you look at the main risks that you're kind of protecting from, could you just clarify what those are?
Yeah. I think certainly the 10-year look-back, because obviously the customers want to see a benefit, and we're convinced there will be a benefit. Now, that goes to the operations of the facilities. But the 10-year look-back obviously measures the benefits that customers see, and that analysis is based upon our existing generation. So, we feel pretty good about how that would work out. And then when you look at the force majeure provisions, those are really focused on – and you have to look at sort of the force majeure risk compared to the production guarantees, and the production guarantees are such that we really – and we looked at this operational from an engineering standpoint, and we feel like that there is risk mitigation associated with the production guarantees that enable us to take on more risk as it relates to force majeure.
And then, obviously, that goes to the production guarantee, the capacity factor guarantee, and we feel very comfortable about that as well, because we've been in that territory for a long time. We know how to build transmission. We know how to run transmission. If a tornado came through, it could take down a couple of structures or whatever, but we're used to doing that, and we know the timeframe of doing that. And then for the facilities themselves, obviously, there's a multitude of – yeah, it really is pretty good from a diversity of standpoint. It's not like a central station generation facilities. It's a bunch of small generators sitting up on poles. And that really gives us an opportunity to mitigate risk on an aggregate standpoint from that perspective as well.
So when we look at it, we are convinced that we're able to deliver the production guarantees, but also have the ability to adjust, if necessary. So, all in all, I'd say, the rewards at this point certainly outweigh the risks.
Okay. Thank you.
Yes.
Next, we go to the line of Jonathan Arnold with Deutsche Bank. Please go ahead.
Good morning, Jonathan.
Hey. Good morning, guys. The first question. I think, Brian, you mentioned that you had addressed the excess deferred tax in the Indiana and FERC East settlements. How much of the billion dollars does that speak to?
Hold on a second, Greg (sic) [Jon] (30:50). About $100.25 million.
Jon.
Thanks. And then I think you've given some guidance in the past as what timeframe you thought was a reasonable rule of thumb for this or what you'd seen in the 1986 case, any updated thoughts around that.
Yeah. I think if you assume 10 years, you'll probably be at about the right place.
Perfect. Okay. Thank you. And then just on sales, Brian, I may have missed this. At one point, I think you said you were going to have a little additional commentary on the residential piece and the 1.4% in the first quarter, obviously, is bucking the trend. Do you have some follow-up comment on that, was weather normalization kind of tricky this quarter?
No, I think that's pretty much on track. The places where we're seeing it, though, Greg, is in the places where we're just T&D Utilities, so we're seeing it more in Texas and Ohio. And that's why you're not seeing as much uplift in revenue is because it's just in the places where we are wires only. It's mostly in the places where we're wires only so. So while we're encouraged by this given where it's coming from and the mix of those sales, we're not getting a huge amount of uplift in regards to net income because of that residential increase.
Okay. Great. Thanks very much, guys.
Thank you.
Next, we go to the line of Julien Dumoulin-Smith with Bank of America Merrill Lynch. Please go ahead.
Good morning, Julien.
Hey, good morning.
Good morning
So, perhaps, to turn the attention slightly differently here. I understand that you received your order in Ohio and you've got the ESP under control and out there. But to what ability is there to negotiate and address the tax issue still or is there a need to at this point? I just wanted to kind of come back to that. It seems like you largely addressed the issues there, but I just want to kind of come back to that given there's not an obvious venue to address that directly notwithstanding reopening these issues. So, I just want to understand.
Specifically, Ohio?
Yeah. He's talking about Ohio.
Exactly.
Yeah. So, we have two avenues for addressing that. One is just the absolute change in rate which I think we can handle in DIR filings. But then also what the Commission has done is asked us as well as the other AEP utilities – the other Ohio utilities to come in and have a dialog with them about that. So, they've set up a hearing mechanism whereby all of the Ohio utilities will go in and have the dialog. And I think we'll be able to put together something that is compelling, and doesn't have to be litigious. I think we'll be able to settle that.
Got it. Excellent. And then turning back to Wind Catcher real quickly, obviously, you're working every state front. To the extent to which, let's say, Texas and those negotiations aren't necessarily as fruitful here on the prescribed timeline that you just talked about, how confident are you about signing up alternatives like munis and co-ops just to be able to continue working on the project, notwithstanding clarity in Texas, shall we say?
Julien, I really think we are going to get a result in Texas. And I think it'd be problematic during the pendency of something that's working to go sell somewhere else. So, we're feeling pretty good about the direction this all is taking and the timing of it.
Got it. And maybe actually if you could clarify, I would suspect that the issues, they're largely the same as you just described a moment ago across the various states. Is there anything unique with respect to Texas? Obviously, the industrial interveners there have historically been fairly outspoken as well.
No, I think as far as Texas is concerned, I mean the industrials in Texas, you have some of the people who represent the same people, but I think you've got certainly different industrials with different thought processes. But when you think about the settlement that was done with SPS and how it compares against what, certainly what we've done relative to the Oklahoma industrials, it's pretty much the same. And SPS settled with all the parties in Texas. So I think we have an opportunity. We knew going into this thing that with four states, there'd be some commonality in that. In fact, the four states have, in most cases, most favored nations and that kind of thing. So, they're all watching each other in terms of the result. And we have a result in Oklahoma and in the other jurisdictions there that is consistent with what is happening in Texas at this point. And I think we're in good shape.
All right. Excellent. Well, best of luck.
Yes. Thank you.
Next, we go to a line of Paul Ridzon with KeyBanc. Please go ahead.
Good morning. Can you hear me?
Good morning, Paul. Yes, I can hear you.
Two questions. Is there a statutory deadline in any of the Wind Catcher states, when this has to be done by?
I don't think there's a statutory deadline, but certainly there's a business deadline. I mean, we've been very transparent about the timing necessary and the procedural schedules have been set up consistent with getting a decision on time. So, I think it's really more driven by, I guess, one of the previous questions sort of brought out, when is our drop-dead date and that kind of thing. But I can just tell you that May and June fits.
And then some of the concessions you've made are around cost caps. Who's wearing that risk? Is it you or the contractors?
Yeah. It's both. We have fixed-price contracts with the appropriate contingencies. And I think that that risk is being shared. And actually, this tells you a little bit about the commitment of the suppliers that we're working with. I mean, these are established suppliers that do a lot of business that we do a lot of business with. And I can guarantee a lot of homework's been done on what these operational provisions will look like, what the construction side will look like, what the supply will look like, what risks are being borne. And also even if route changes were to occur on the generation tie (38:02) that those have been discussed and (38:05) as well. So, we feel very good about where our suppliers sit at this point.
We're not building nuclear plants here, right?
We're not building nuclear plants. Well, I wouldn't want to trash nuclear or anything, because I'm supportive of nuclear. But this is putting small generators up on poles and putting transmission structures up and lines up, and we do that all the time. And 765, we do that all the time. And so, this is not something that is a first – like stamp number one. And the other thing, too, is that when we look at this entire project, it is definitely important to AEP because it represents what we're capable of doing. And when you introduce 765-kV in that part of the country, it could be a tremendous benefit in the future, not just from an economic development standpoint, but also in terms of our ability to continue to serve our customers and serve them well.
Then one last question, and if you addressed this, I'll circle back with Bette Jo. But transmission was very strong in the quarter. What was driving that?
So, there were some – there was obviously the FERC 206 settlement was a contributor to that. But tax reform also contributed to that in that the rate base goes up higher with the ADIT not going into rates. So, those two factors mainly contributed to that increase.
Is this kind of – did all of this hit in the first quarter, or are we going to continue to see those, at least on the tax reform, flow through the year?
We expect an uplift of about $0.04 versus what we'd shown you at EEI over the course of the whole year, $0.04 to $0.05.
Thank you very much.
Yes.
Sure thing, Paul.
Next, we go to the line of Praful Mehta with Citi. Please go ahead.
Thanks so much. Hi, guys.
Good morning, Praful. How are you doing?
Good. How are you?
Just fine.
Excellent. So, quickly just on the deferred income taxes, on the unprotected one, I think, Brian, you mentioned 10 years as a possible assumption for refund. We've also heard from other utilities who are paying it back a lot sooner. So just want to understand, is that mostly an assumption of a negotiation or is that a preference from your end to kind of draw it out over a longer period because there are benefits to kind of growing rate base as you kind of refund it back as well?
Yes. So, you're going to see everything from much quicker than that to much slower than that across our 11 jurisdictions. And so, the data point that I have is what we were able to do in Indiana where we were able to increase the depreciation on some of our coal units there and have that be the factor by which we flow back the excess, and that was a 10-year period. So if you're modeling something across the system, I think 10 years would be a pretty good assumption.
Got you. And your preference is not to do it sooner as well, just to understand from a preference perspective?
Our preference really is kind of do it on a jurisdiction-by-jurisdiction basis, right? And when we talk about taking down reg assets, when we talk about fuel, when we talk about other things that are going to increase rates, it's really going to be jurisdiction by jurisdiction as to what the best way for those customers is for them to receive that benefit. And we're going to work with interveners and commissions and try and be as constructive as we possibly can on a jurisdiction-by-jurisdiction basis.
Got you. Fair enough. That's helpful. And then just quickly, just strategically, more from a corporate M&A perspective, the conversation has increased a little bit given tax reforms behind. And it also looks like companies who are better positioned, like yourselves with stronger credit going into tax reform have a competitive advantage. Do you see that at all? Do you see any dialog increasing, and how are you looking at strategic M&A at this point?
So, let me just address the financial aspect of it, and I'll Nick address the strategic aspect of it. So when we're looking at our balance sheet, you look at our credit metrics and they are very healthy now. We do expect them to go back into the normal range for Baa1 rated company due to the impact of tax reform. So, we're very strong right now. We had anticipated being a tax payer. That's gone away, to a large degree, with the impact of tax reform, Wind Catcher and other such things. But because of the impacts of tax reform, we do anticipate, as we talked about earlier in the call in the question-and-answer period, that FFO to debt to come in 200 basis points to 300 basis points over the next year or so. So, we anticipate consuming that cushion that you might see there otherwise. And I'll let Nick comment on the strategic component.
Yeah. So, we are in the middle of what I would call an M&A transaction without a premium. It's called the Wind Catcher. And so when we look at the strength of the balance sheet, certainly we'll be looking at the financing needs for Wind Catcher and that's a $4.5 billion transaction. So, that's where our thoughts are at this point.
Got you. Thanks so much, guys, appreciate it.
Thank you.
Next is the line of Ali Agha with SunTrust. Please go ahead.
Good morning, Ali.
Thank you. Good morning. Nick, to clarify, as you're looking at the four states for approval in Wind Catcher, is it fair to say just given where we are that Oklahoma probably is the most challenged of the four? And related to that, could you theoretically complete the project if the other three states say yes and Oklahoma was to say no?
Yes. So, on the first point, I would agree with you. Oklahoma has been the most challenging. And really, with the ALJ order there, it made even more of a challenge for the commissioners to really take a look at it from a positive standpoint. But I really believe they will at the end of the day and – because they obviously look at much broader issues. And so, with that said, I think as far as Wind Catcher is concerned, we intend on this project being for those four states and certainly the FERC customers. There's some FERC customers too that are involved. And if one were to fall out, we're really – as I said, I mean, I think we're at a good place in terms of the transition of getting this thing across the finish line. And at this point, we really aren't entertaining the notion of going forward with the project without one of the jurisdictions. I really don't see that happening.
I see. Second question, Brian, wanted to clarify if I heard you right, you were mentioning that when you're looking at your transmission earnings for 2018, you're now thinking they will come in about $0.04 to $0.05 better than what you had indicated to us back at EEI. Is there anything offsetting that? Or in the context of the year, should we see that as a positive cushion that may, if things play out, cause you to move to the right or above your midpoint of your range?
That's a good question, Ali. It's really early in the year. And in a company as big as ours, we're going to have pluses and minuses across the year as things go on. So, we wouldn't anticipate any change at this point to what our guidance is. That's just one area that is up versus what we had anticipated. There are others that are down, and we'll lay those out to you as we go through the year on a quarterly basis.
Okay. And last question, can you also remind us relative to the rate increase that you had assumed in your 2018 guidance, how much of that is currently locked in?
So, we have about 75% of it's currently locked in.
75%. Got it. Thank you.
Okay.
Thank you, Ali.
Next, we go to a line of Paul Patterson with Glenrock Associates. Please go ahead.
Good morning, Paul.
Good morning. How are you?
Just fine.
Just sort of quickly follow up here on Wind Catcher. Why is it that the – what are the key issues, I guess, sort of maybe stopping the OCC staff and others from coming on board?
Your guess is as good as mine. I think, obviously, the ALJ looked at it from a procedural basis it seemed like to me. But we're pretty convinced we did file under the right provisions under Oklahoma law. But obviously, we'll continue with discussions with certainly the Oklahoma staff. And I think – I really do believe we put provisions in place with the industrials that should benefit that discussion with them. Obviously, to have that kind of company of the customers certainly would help from a policy side and from a staff side to really take a hard look at this. So, the verdict's still out on that and we'll continue those discussions.
Okay. And then, in Oklahoma, there's this tax issue on Wind. I guess we expect it's intertwined with school funding and there was something that passed the House yesterday. And I was just wondering how would that work with respect to the settlement or with respect to the project, or does it have any impact. Can you give us sort of a sense about that?
Well, it won't have any impact on the project. And it got poured out of the legislature yesterday. So, we don't see that happening.
I mean, I thought it passed the House is what I just saw.
No.
The provision for the tax credit, I thought it was removed. But we can talk about it later. But what you're saying is you don't see any activity on that whatsoever, is what you're...?
No.
Okay. So if something like that did happen, though, since it's been sort of debated and what have you, and the school funding issue, in terms of the settlement, how would that – would that be something that you guys would absorb or would that be something that – how would that be treated if there was subsequently some sort of impact on wind generation in Oklahoma as a result of something that the state legislature may or may not do in the future?
Yes. So, there is that risk, but not likely. And the state tax credit wasn't assumed in the Wind Catcher economics, to begin with. So if something were to occur, it wouldn't have any effect.
Okay. So, I got you. Okay. I think maybe that's what was in there. Maybe that's what I'm confused about.
Yeah.
Okay. Great. And that's it. I really appreciate it. Thanks so much, Nick.
Sure thing, Paul.
Next, we go to the line of Christopher Turnure with JPMorgan. Please go ahead.
Good morning, Christopher.
Good morning, guys. I just wanted to get your latest thoughts on the potential for grid modernization spend in Ohio. Previously, I think you've talked about $500 million of incremental potential versus your current plan if you get the green light there. But the Commission has been going through exploring the process generically for the whole state and I'm curious to hear your thoughts.
Yes. So, the $500 million was for the entire system, because you know when we presented that EEI. If we were able to get – move forward with grid modernization in those jurisdictions, there was an incremental $500 million. Certainly, Ohio, the order sort of sets up the tone to really have that discussion because the more we move in the technological front and the more we move into optimization efficiencies around the grid, we'll be able to have those kinds of discussions. And I think yesterday's order of the Ohio Commission was the first step in that process. And I think it bodes well for Ohio and, certainly, we'll use that pattern in the rest of our system as well.
So right now, there's nothing incremental on the $500 million. That was a Distribution Investment Rider and those kinds of things. Those issues were already in place. So, we'll obviously continue to have that dialog.
Okay. And then, you mentioned I think towards 2018 year-end the gap between the SEET earnings test in Ohio and the actual earned ROE calculation narrowing. Can you quantify potentially the impact on earnings that that alone would have in 2019?
Brian.
Yeah. So, we anticipate it ultimately being around 10% and that's factored into what it is we've guided you to. There's no incremental change to that.
Okay. Fair enough. Thanks, guys.
Yes. Thanks. Sure.
And next, we go to the line of Michael Lapides with Goldman Sachs. Please go ahead.
Good morning, Michael.
Good morning, Nick. Thank you for taking my questions.
Yeah.
Looking at the cash flow sides in the appendix, the three-year forecast, and this isn't new information. But just curious, you all talk about needing more equity in 2020, but your cash flow actually gets a lot better in 2020, I mean, by like $1 billion if you just use cash from ops minus cash from investing activities. Are you being overly conservative when thinking about 2020? Is the equity really something that might need to come a little bit earlier? It's not a big amount, but like you're pretty cash negative for the next two years and then it gets a lot better. Or is this all just kind of prepping for Wind Catcher?
What you see on slide 25 really doesn't include Wind Catcher. And what we're looking at is what happens to our FFO to debt over time and trying to time, like you've seen others do, any equity needs with when they're actually needed and not take the dilutive effect of that sooner than we need to. So, we are going to let our FFO to debt metric deteriorate maybe 200 basis points to 300 basis points, get down into that Baa1 range. And we anticipate needing to bolster that a little bit, but not before the 2020 timeframe.
Got it. And can I ask, what's in that slide? What's your assumption in there for the return of the excess ADFIT, the billion dollars? And the only reason I asked that is one of your neighbors in Louisiana and Arkansas is under a much faster – and I think one of my colleagues asked this earlier, but their timeline for returning the excess ADIFT is actually a really quick one, like one to three years. I'm just trying to think about what you've assumed or embedded in your guidance on cash flow for that.
Just assume 7 to 10 years.
Okay. So if it's quicker than that of the return of the excess ADFIT, that would negatively weigh on cash and might either bring forward the equity need or raise the equity need?
It's a change in cash flows.
Got it. Okay. Finally, Nick, just kind of you mentioned about the West Virginia rate case filing. How are you thinking about what structural changes in West Virginia you might ask for, and whether you do it in the case filing or whether you do it in some legislative effort? Just it's a state with traditional historical test years, little bit of lag. Just trying to think about how you're thinking big picture there.
Yeah. We haven't supposed any structural changes in West Virginia. And I think, probably, all that West Virginia has been through and going through now from an economic standpoint, we really are focused on ensuring that our rate cases are filed very efficient. They certainly are focused on making sure that we're doing the right things by what we believe in terms of service quality to our customers in West Virginia. I think we probably ought to stick to that approach in West Virginia for the time being. And so, we haven't presupposed any structural changes.
And when we think about the next seven or eight months, eight or nine months in 2018, how are you thinking about where else kind of sizable general rate case filings may occur?
Well, really, the only ones would be West Virginia and Oklahoma. Everything else has really flushed itself out this quarter. And so, we're pretty clean going forward from a regulatory standpoint.
And of course, Mike, we'll have our usual formula (57:01) base rate filings in places like transmission and Ohio and other places.
Got it. Thank you.
I would say, on your previous question too, we had Virginia recently in the quarter, they also dismissed a case that would have been for two wind power projects. And so, as Virginia thinks differently than West Virginia, the more we see that from a supply perspective, that's going to be an important data point for us as we go in for these cases, how to deal with that. And so, that would probably be the extent of the – your structural question just brought up that issue in my mind of how resources are being seen differently in the two jurisdictions and of APCo, and we'll have to try to drive some consistency there.
Got it. Thank you, Nick. Thanks, Brian. Much appreciate it, guys.
Thank you.
And operator, we have time for one more question.
Very good. It's the line of Angie Storozynski with Macquarie. Please go ahead.
Good morning, Angie.
Good morning. So, I surprising, had a question about Wind Catcher. So, we've seen a number of renegotiations of wind equipment contracts by utilities, by different developers and OEMs – with OEMs, seemed willing. So, now that you have these caps on the cost of the projects and then you have the performance guarantees, couldn't you just go back to GE and say, okay, well, this is the reality we're facing, as such we need to actually get a cut on the equipment cost and also maybe you can provide us with a performance guarantee for the wind turbine.
Yeah. Brian.
So, Angie, whether it's Invenergy, GE or Quanta, all of our partners have skin in the game on this and they are being very proactive in how they're helping us manage the risk of things like caps relative to the cost of equipment, relative to tax impacts they might have, relative to other increases and decreases in their costs. And it's very much of a partnership rather than a traditional supplier relationship. So, they are working very proactively with us on all those issues.
Okay. So, basically, the true risk is more on the timing of the construction of the transmission line. I mean if all of the other factors are really, in a sense, mitigated right, the cost of construction of the wind farm, the operating more NCF (59:54) of the wind farms, it's really the transmission line that is more of a risky part of the project?
It's all the things that you would think in a project. It's cost and schedule. And so, we have some of the cost mitigated through the partnerships that we have with our suppliers and they're also helping us to mitigate the schedule component of it as well. So, it's what you would expect in a project of this size and scope. We need to bring it in at cost, on budget, and on schedule, and we have experienced partners who are working with us to help us do that.
And we've mitigated pieces of the risk too, because we're acquiring the plant at commercial operation. So, Invenergy is obviously doing their work associated with that. It's been well thought out. Going to your earlier point though, we obviously are paying particular attention to the generation interconnection or you call it transmission, that piece of it to ensure, from a supplier perspective, we're in good shape. We've had conversations with certainly their executive leadership about the importance of the arrangement we have in place. And I think in terms of routing, that work continues in earnest and alternatives are considered in earnest. So when you look at the construction side and the risk being taken, we're in really good shape.
Okay. And the last question is – so you mentioned that now under the new tax regime, you won't be paying taxes for longer – cash taxes. And so, what happens with the PTCs and accelerated depreciation generated by this project? Maybe you've said that, but are you using a tax equity investor or are actually considering using that?
So, right now, we don't anticipate needing one, but we are monitoring very closely our tax appetite with our ability to use the PTCs as we take on a project the size of Wind Catcher and trying to make sure those things match up. That's something that's contemplated in the settlements that we're talking about. And to the degree that we're not able to use them on the same time, there will be an ability to defer the tax asset and earn some recovery on it.
Okay. Thank you.
Thank you.
Thank you.
Thank you, everyone, for joining us on today's call. And as always, the IR team will be available to answer any additional questions you may have. Lea, would you please give the replay information?
Certainly. Ladies and gentlemen, this conference is available for replay after 11:15 AM Easter time today through May 3 at midnight. You may access the replay service at any time by calling 1-800-475- 6701 and enter the access code of 446736. International participants may dial 320-365-3844. Again, those numbers are 1-800-475-6701 and 320-365-3844 with the access code of 446736.
That does conclude your conference for today. Thank you for your participation. You may now disconnect.