Bette Jo Rozsa - American Electric Power Co., Inc. Nicholas K. Akins - American Electric Power Co., Inc. Brian X. Tierney - American Electric Power Co., Inc..

Julien Dumoulin-Smith - Bank of America Merrill Lynch Jonathan Philip Arnold - Deutsche Bank Securities, Inc. Praful Mehta - Citigroup Global Markets, Inc. John J. Barta - KeyBanc Capital Markets, Inc..

Ladies and gentlemen, thank you for standing by. Welcome to the American Electric Power Third Quarter 2017 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we'll conduct a question-and-answer session. Instructions will be given at that time. And as a reminder, this conference is being recorded.

At this time, I would now like to turn the conference over to our host, Ms. Bette Jo Rozsa. Please go ahead..

Thank you, Rich. Good morning, everyone, and welcome to the third 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..

January in Oklahoma and Texas; February in Louisiana; and March in Arkansas. Wind Catcher represents a clear winner for customers, investors, economic development and the environment.

At this point, I should figuratively drop the microphone, but we'll let the facts, $4.5 billion invested, $7.6 billion in customer savings, substantial infrastructure development and great use of wind resources speak for themselves. So I'm pleased with the progress of Wind Catcher so far.

Moving on to our several rate cases to discuss and obviously, we're in a year of several rate cases. We got a summary on page 33, but at a high level, in Indiana, we filed a $263 million rate case of which $89 million is depreciation and amortization. The procedural schedule has been set with hearings in January.

In Michigan, we filed a $51.7 million rate case with $23.4 million being depreciation and a procedural schedule has been set for those hearings this November and an order is expected in April of 2018. The Kentucky rate case that was filed in June requested a $65.4 million increase, and is now in settlement discussions with the parties.

Hearings were set for December of this year, so we expect the results soon with this case. The Oklahoma rate case was filed in June for approximately $170 million, inclusive of about $14 million of AMI and reliability that we were already recovering through riders.

In September, staff recommended a $132 million increase and the hearings are scheduled in late October, early November with an ALJ report expected December. As I mentioned last quarter, this case is extremely important with the outcome impacting future investment decisions in Oklahoma, including Wind Catcher.

We are hopeful the Oklahoma Commission will send a positive message in this regard. At SWEPCO last December, we filed a base rate case in Texas requesting $105.9 million, offset by $36.9 million of reductions in TCRF, Transmission Cost Recovery Factor, and DCRF, Distribution Cost Recovery Factor, revenues netting to $69 million.

This case include environmental retrofits and remaining net plan investments in the retired Welsh 2 unit. The ALJ in the case issued a decision in September, proposing a base rate increase of $51 million with a 9.6% ROE. We expect a PUCT decision by the end of the year on this case.

In Ohio, in late August, we filed a joint stipulation settlement agreement among the parties in the ESP 3 extension case. The agreement covered distribution investment and enhanced reliability rider-related issues as well as Smart City investments in technology, continued OVEC recovery and other matters.

It allows a 10% ROE for rider-related capital and commits the company to file a rate case in June 2020. Hearings commence this next week. Proposals are also due to AEP Ohio in December for 400 megawatts of solar, so we're looking forward to further investment in this area as well.

Now, moving forward with the equalizer chart, overall, ROEs have come down from the previous quarter due to primarily weather, but also the pending rate case activity I just spoke about. With six different major rate cases, along with other regulatory activities, it has been quite a busy year.

As I mentioned earlier, many of these cases do not get resolved until first quarter 2018, so we expect a gradual increase with ROEs for the fourth quarter. And then, in 2018, ROEs once again should be tracking approximately in the 10% overall range.

So, as I go across looking at each one of the jurisdictions, I refer you to page 5 of the equalizer chart. Obviously, we have our two bubbles for AEP Ohio and that really talks about the difference between those legacy issues that are accounted for in the 12.6% versus what we're truly experiencing, the 11.1% that would be involved with the SEET test.

So the ROE for AEP Ohio at the end of the third quarter 2017 was 12.6%, and it reflects rate relief associated with our distribution investment program, shared savings attributed to our energy efficiency programs, and the annual transmission formula rate true-up in lowering financing costs.

The 12.6% ROE, as I said earlier, includes those legacy issues and the 11.1% does not, and that's the one that's evaluated for SEET-related activities. APCo, it has come down a little bit. At the end of the third quarter, it was 8.4%; in second quarter, it was 8.9%. And that really is driven primarily by weather and usage during that period.

So in many of these, you'll see that as a sort of a crosscutting issue across the board is the weather-related activities associated with each one of these.

Kentucky, the ROE at the end of the third quarter was 4.5% and, as you know, we filed the rate case there back in July of 2017, so a new rate should be effective around the January timeframe in 2018. But that being said, the long-term strategy around Kentucky is also centered around economic development.

We had a large aluminum company that announced location within the company's territory, and we believe that's going to be a foundational part of some ancillary additions in load that can help from an economic development standpoint.

So that's really a two-pronged effort there and Matt Satterwhite, our President down there, is doing a great job turning that around. I&M achieved an ROE of 8.4% at the end of the third quarter 2017. I&M's ROE has been impacted by weather, again, and formula base rate true-ups.

I&M has filed base rate cases in both Indiana and Michigan, as I mentioned earlier, and those new rates are expected to be in place for both states in midyear 2018.

PSO, we've talked about, the ROE at the end of the third quarter was 6.1% and it's primarily driven by regulatory lag from the last rate case, hopefully we'll make up some ground on that, and unfavorable weather. So we expect the new rates of PSO to be in effect by January of 2018.

SWEPCO, the ROE for SWEPCO at the end of the third quarter was 5.9% and third quarter results were unfavorable because weather, again, but benefited from some lower O&M expense. SWEPCO also took a $6.3 million unfavorable adjustment due to the prior period income tax adjustment affecting the Dolet Hills Lignite Company subsidiary.

And of course, we've had the formula base rate that was approved by the Louisiana Commission kick in during that period as well. And then, of course, we have a Texas case that I talked about earlier that we're expecting an outcome soon on as well. So moving on to AEP Texas, they are at a 10.3%.

They have a steady ROE primarily attributable to increased revenues from the TCOS filing that was effective in late June, and then their Distribution Cost Recovery Factor filing that was effective in September. So all is good in AEP Texas.

AEP Transmission Holdco, the ROE for AEP Transmission Holdco at third quarter has been 12.7%, primarily driven by 206 reserve which offsets most of the year-over-year rate base increase.

The other driving factor is a decrease in ETT ROE as a result of settlement filed with the PUCT in January 2017 but all in all, going very well from a transmission standpoint. So with that discussion, obviously weather impacted just about every part of the system and then also we had hurricanes that hit.

And I wanted to say – give a shout out to our employees and also the industry in terms of its support relative to Hurricane Harvey, Irma and others. This has been an interesting year from a weather perspective. So this quarter, once again, because of weather, we've been treading water, no pun intended.

But again, I'm very proud of the employees who have been involved with not only eliminating most of the deficit that's occurred because of weather reductions but also the work they did relative to really recovering our nation from some pretty substantial storms.

So, being a music buff, I can't help but recall the lyrics of a song by the group Dream Theater and which is one of my favorite drummers, Michael Portnoy and probably no one knows who they are but the song is called Another Day and the lyrics go – live another day, climb a little higher, find another reason to stay.

Well, in 2017, because of our efforts to overcome the weather and other obstacles, we'll finish out the year 2017, we'll live for 2018 and continue on our path of reaffirming guidance centered on $3.85 per share and our 5% to 7% growth rate. The fundamentals of our business plan remain secure and we're confident going into 2018.

Brian?.

Thank you, Nick, and good morning, everyone. I'll take us through the third quarter and year-to-date financial results, provide some insight on load and the economy, review our balance sheet and liquidity, and finish with a discussion of what we'll present at the EEI Conference.

Let's begin on slide 6 which shows that operating earnings for the third quarter were $1.10 per share or $543 million compared to $1.30 per share or $640 million in 2016. This difference can be primarily attributed to the sale of competitive generation assets and mild weather. Let's look at the earnings drivers by segment.

Earnings for the Vertically Integrated Utilities segment were $0.58 per share, down $0.13. The primary driver for this variance was cooler-than-normal weather this year compared to warmer weather last year.

Other drivers in this segment include lower O&M and higher normalized retail margins, which were offset by higher depreciation and higher effective tax rate. The Transmission & Distribution Utilities segment earned $0.29 per share for the quarter, down $0.03 from last year.

Unfavorable drivers in this segment included a higher effective tax rate, weather in Texas, lower sales in Ohio and increased depreciation. Partially offsetting these items was recovery of incremental investment to serve our customers.

Our AEP Transmission Holdco segment continued to grow, contributing $0.15 per share for the quarter, an improvement of $0.01 over last year, reflecting a return on incremental investment. Net plant less deferred taxes grew by $1.1 billion, an increase of 30% since last September.

The Generation & Marketing segment produced earnings of $0.07 per share, down $0.09 from last year. This segment realized lower earnings due to the sale of the competitive generating assets. Partially offsetting this impact were lower depreciation on the remaining assets, higher marketing revenues and lower overall expenses.

Corporate and Other was up $0.04 per share from last year, primarily due to an investment gain and lower O&M. Let's turn to slide 7, and review our year-to-date results. Operating earnings through September were $2.82 per share or $1.4 billion compared to $3.27 per share or $1.6 billion in 2016.

Similar to the quarter, this difference can primarily be attributed to unfavorable weather, the sale of the competitive generation assets and positive items that occurred last year that were not repeated this year. Offsetting these were transmission earnings and recovery of incremental investment. Looking at the drivers by segment.

Earnings for the Vertically Integrated Utilities were $1.27 per share, down $0.43, with the single largest driver being weather, which negatively impacted earnings by $0.22. Favorable prior year items contributed to this difference, including formula rate true-ups, recognition of deferred billing in West Virginia and positive tax adjustments.

Other rate relief was favorable due to the recovery of incremental investment across multiple jurisdictions. Additional variances in this segment include higher depreciation, lower AFUDC and lower retail margins, particularly in the East. Through September, the Transmission & Distribution Utilities segment earned $0.76 per share, down $0.03.

Favorable drivers in this segment included rate changes and higher ERCOT transmission revenue. These were offset by several items including lower normalized load, the reversal of the regulatory provision in 2016 and higher effective tax rates, depreciation and O&M.

AEP Transmission Holdco segment earnings through September were $0.56 per share, up $0.14 over last year. The growth in earnings included the implementation of deferred 205 forecasted transmission rates. This allowed for a one-time increase from historical expense true-ups to future-looking estimated expenses to be trued up in the subsequent period.

This one-time adjustment will not be repeated in future periods. We experienced a slight decline in our joint venture earnings due to an ETT settlement earlier this year. The growth in earnings over last year also reflects a return on incremental investment.

The Generation & Marketing segment produced earnings of $0.25 per share, down $0.15 from last year. This segment realized lower earnings due to the sale of the competitive generating assets, as expected.

Partially offsetting this impact were lower depreciation on the remaining assets, positive impacts from solar projects going into service and lower overall costs. Finally, Corporate and Other was up $0.02 per share from last year due to investment gains and tax adjustments.

For the year-to-date period, certain unfavorable comparisons to 2016 were anticipated, like the sale of the competitive generating assets and other favorable 2016 items.

In response to the earnings impact from very mild weather, which continued into the third quarter, we have reduced O&M expenses compared to last year for the fourth quarter of this year.

Because of the continued impact of weather and the fact that we have one quarter remaining in the year, as Nick said, we are narrowing our 2017 guidance range to $3.55 per share to $3.68 per share.

Also as Nick said earlier, we anticipate growing at 5% to 7% off of our original 2017 guidance range and are reaffirming our 2018 operating earnings guidance range of $3.75 to $3.95 per share in 2018. Now, let's look at slide 8 to review normalized load performance.

Starting with the lower right chart, our normalized retail sales decreased by 0.3% this quarter and we're down 0.2% for the year. For both comparisons, the growth in the industrial sector was offset by declining residential and commercial sales.

Had it not been for the outages caused by Hurricane Harvey, our normalized sales would be flat for both the quarter and year-to-date periods. Moving clockwise, industrial sales increased by 1.9% for both the third quarter and year-to-date comparisons.

We saw strong industrial sales growth across most of our operating companies and industries this quarter. The positive industrial performance these past two quarters are good indicators of future growth in our residential and commercial classes as the economic recovery works its way through our service territory.

In the upper left chart, normalized residential sales were down 1.4% for the quarter and down 1.5% year-to-date. Story here differs by geography. Residential sales were up 0.5% in our Western footprint, where customer accounts increased by 0.7% in the third quarter.

In the East, however, residential sales declined by 3%, where customer accounts were essentially flat. Finally, in the upper right chart, commercial sales for the quarter decreased by 1.3%, bringing the year-to-date normalized contraction to 0.7%.

Turning to slide 9, let's take a deeper look at some of the indicators that were responsible for the stronger industrial load performance this year. The chart at the top illustrates why we are confident with the trend for this class. Since 2013, the majority of AEP industrial sales has been concentrated in the oil and gas sectors in AEP shale regions.

While it was good to have growth from the energy sector, there was a concern that the industrial mix was becoming unbalanced as non-energy-related sales struggled. This concern was evident last year when energy prices fell, and the majority of our service territory fell into recession.

As of the third quarter, all of our operating companies are now out of recession and in recovery mode for the first time since 2011. In addition, over the past two quarters, there is no longer a distinction between growth in the oil and gas and the rest of our industrial sectors.

This balance is indicative of a healthier base from which AEP's economy can grow. The bottom left chart helps explain why we experienced recent improvement in the non-oil and gas sectors. The chart shows the strength of the U.S. dollar compared to the broad index of other currencies.

In 2016, the strong dollar and weak global demand were significant headwinds for manufacturing in AEP service territory. Fortunately, the global economy is in a much better position in 2017 and the dollar has started to soften over the past two quarters, which coincides with the growth in industrial sales shown above.

The current dollar index is the lowest it's been since 2015. The table in the bottom right corner shows some of the major export industries located in AEP's footprint that are benefiting from the weaker dollar. In total, these sectors represent nearly half of AEP's industrial sales.

With that, let's review the status of our regional economies on slide 10. As shown in the upper left chart, our Eastern territory grew by 3.2% this quarter, which was 1.1% faster than the U.S. Our Western territory grew at 1.9%, which was a significant improvement from previous quarters.

Looking at the growth in our East Vertically Integrated Utilities in the upper right chart, Kentucky Power remains the fastest growing territory in terms of GDP growth, notching an increase of 3.1% for the quarter. As you know, Kentucky Power's territory has a higher concentration of coal mining, which is growing for the first time in years.

Appalachian Power's territory also has a high concentration of mining and is experiencing a similar trend, growing at 2.5%. Despite its GDP growth of 2.5%, Indiana Michigan Power has actually experienced sales declines in all three retail classes.

Exposure to the automotive industry, which had a record-setting year in 2016, has moderated somewhat this year. The bottom left chart shows our West Vertically Integrated Utilities where SWEPCO's service territory saw 1.6% growth for the quarter.

As expected, PSO came out of recession this quarter experiencing GDP growth of 0.6% driven by improvement in the oil and gas activity. Finally, the bottom right chart shows that both of our Transmission & Distribution Utilities continue to improve in the third quarter, with the growth in Ohio approximately 1% above that in Texas.

The Ohio service territory is more diversified with growth coming from many sectors, such as manufacturing, construction, and education and health services. Overall, we are encouraged by the momentum of these economic trends in our service territory. Now, let's move to slide 11 and review the company's capitalization and liquidity.

Our debt-to-total capital ratio increased 0.1% during the quarter to 54.6%. Our FFO-to-debt ratio is solidly in the BBB+ and Baa1 range at 17.4% and our net liquidity stands at about $3 billion, supported by our revolving credit facility. Our qualified pension funding improved approximately 1 percentage point to 100%.

Plan assets increased due to strong returns and plan liabilities were essentially flat due to relatively stable interest rates. Our OPEB funding improved 2 percentage points during the quarter to 112%, with investment gains outpacing plan benefit payments and expenses.

The estimated after-tax O&M expense for both plans for 2017 is expected to be unchanged from last year at about $15 million. Finally, our Treasury group continues to take advantage of robust low-cost debt capital markets to fund our spending program.

In back-to-back weeks this quarter, we issued $700 million in senior notes for AEP Texas and $625 million in senior notes for AEP Transco.

The 30-year spread on the Transco deal of T plus 100 basis points (25:53) was the lowest issuance spread for an AEP company since before the financial crisis and equal to the lowest for any utility senior unsecured 30-year notes since the start of 2015. Let's try to wrap this up on slide 12 and get to your questions.

Despite the significant impact of mild weather on this year's earnings, we were able to find offsetting expense reductions that allow us to narrow operating earnings guidance within the original range to between $3.55 to $3.68 per share. Significant portion of those O&M savings will occur in the fourth quarter.

Given our ability to put capital to work, serving our customers, we are also confident in reaffirming our 2018 operating earnings guidance range of $3.75 to $3.95 per share. We are also confident that there is significant runway in our capital programs to reaffirm our 5% to 7% operating earnings growth rate.

As we always do, we will provide specifics with our presentation at the fall EEI Financial Conference. We will detail the drivers behind next year's earnings guidance. We will also provide detail around our capital expenditure plans, rate activity, cash flow and a more specific annual financing plan than we have provided in prior years.

We look forward to seeing many of you in Orlando in about 10 days. With that, I will turn the call over to the operator for your questions..

Thank you. And we will start with the line of Julien Dumoulin-Smith with Bank of America. Please go ahead..

Good morning, Julien..

Hey, good morning..

Good morning..

Congratulations on holding the line here on costs. Yeah, talk about it. Bring those dragons..

We need them..

I know. Oh man. Let me ask you real quickly if I can, on – let's just start with the weather really quickly. You talk about not exactly adding back that $0.13 year-over-year, how would you think about it? Obviously, you didn't change the 2017 number as much, just to hit that directly out of the gate here..

Yeah, when we look at the $0.13 – we're looking at this year like it is an anomaly. We're not doing anything stupid for reducing an O&M perspective. We are doing the tree trimming, we're doing all the things we need to do.

But there is one-time things that we can do whether it's travel, whether it's all those kinds of things that employees can do to reduce costs and the efficiencies that we've seen from all the previous years' activities continue to inure to the benefit of O&M as well.

So there's some opportunities for us to really respond to the weather-related activity. But keep in mind, we're very careful, we didn't want to move a bunch of stuff from 2017 into 2018 because there's things we need to do in 2017 and we want to keep the plan secure for 2018. So we really looked at it in that fashion.

When you look at the weather and if it's weather adjusted $0.13, not all of it, so I think you do have some opportunity next year. I think it just makes us more confident about the midpoint for next year, particularly assuming we get any kind of normal weather.

It would be great if we had a good winter before we had a bad summer or a good summer after we had a bad winter, but we had neither. And so all of the plans aligned negatively this year but to come out of it the way that we have I think really does show the ability to change our O&M profile to respond to it.

I don't know, Brian, do you have anything you want to add to that?.

No. We've kept O&M that's now been tracked flat essentially for the last seven years.

And it's been lean activity, procurement activity, continuous improvement activity and we are advancing that activity and when we have the weather gap that we had this year, this management team knows what levers to pull to fill in that gap and we are not going to resort to gimmicks like factoring weather out.

We know we're responsible for responding to what the weather is and trying to come in within our guidance range and that's exactly what this team has done..

Today, it's a different company than we had two years or three years ago with the unregulated generation.

Today, I think it's much more transparent and the levers that you have to pull are still there in some regards, but weather will be more of a impact on the company than in previous years because then you had the market conditions that you could look at, and sometimes it saved you, sometimes it went against you, but that's all part of the process of making sure that we're consistent as we can be regardless of the situation..

Excellent. Thanks for the detail. Quick to follow-up on cleanup item here, we've seen some headlines around Oklaunion here.

Can you comment just on, I presume that's fairly negligible in terms of earnings contribution to the extent which you were to transact on that? And presumably if you were, that would be all of it, that would not be any kind of specific portion of it? And then perhaps, in tandem with that, any thoughts here on Conesville given that the transfer has been completed for – a little bit here?.

Yeah, obviously, we're still looking at the unregulated generation from a strategic sense and Oklaunion has been a drag, particularly on the unregulated side, in the ERCOT portion of Texas. And just like any other base load generation, I don't think it gets the value it deserves for what it provides to the market.

But that being said, yeah, any kind of result that we get out of Oklaunion, I wouldn't expect too much of a financial change as a result. And then as far as Conesville is concerned, we continue to look at that, we consolidate some interests in some of the units, but we continue to look at our options from that perspective as well.

And really I didn't talk about those upfront in any of the areas, but just know that we continue to work with Buckeye and Cardinal and then of course, seeing what the disposition of those units can be in relation to all the other opportunities that we have but there's no doubt we continue our process of that strategic review..

Got it.

And just to clarify what this all meshes together to for your 2019, if you think about as you roll forward a few years that $0.10 of call it non-core utility earnings, the composition that is largely renewable by that point in time, or just how would you think about that given where you are in the plan on both the deployment of capital on the new generation assets as well as obviously getting rid of the legacy stuff?.

Oh, yeah, absolutely, Brian, do you want to....

Yeah. So hedges that we have associated with our competitive generation and capacity revenues decline over time. And earnings from the renewable portion increases over time. Overall, we don't expect that business to be changing much from about the $0.10 contribution of earnings that it has in the near term..

So if you look at 2018, 2019, 2020, you're seeing minimization of the contributions of the old legacy units, but we're maximizing the contribution of the renewables efforts, particularly in Chuck Zebula's area, the contracted renewables, but also very much so the regulated renewables.

And as I mentioned earlier, we have an RFP out in AEP Ohio for solar and then, of course, Wind Catcher. You're going to see other projects like that, that are going to be drivers for those future years and we're very much looking forward to it..

Excellent. Thank you all very much..

Yeah..

We'll now go to the line of Jonathan Arnold with Deutsche Bank. Please go ahead..

Good morning, Jonathan..

Hi, good morning, guys..

Good morning..

I've had just a question about the Transmission segment and obviously, you didn't provide for the quarter much a breakdown of the $0.01 of growth, but it seemed to be little slower than you've generally been seeing on investment growth.

So I was curious, did you take any additional reserve against 206, or anything like that this quarter or just what's behind that $0.01?.

So we did take reserve against the 206 for the quarter. For the year, contributing to that $0.14 improvement is the – what we're able to do in the FERC 205 as we're able to look at forward-looking O&M test years rather than truing up past years.

And that contributed to the growth but we're pretty much on track with where we expected to be for the Transmission Holdco segment..

You're going to see an anomaly with the credit of the 205. That's really some of what you're seeing, too, the true up associated with it..

So that's the $0.09 that you're talking about on a year-to-date basis?.

Yes..

Yeah..

And – but the – you're now reserved to the level that you think is a reasonable outcome for the 206 beyond the reserve you took earlier in the year, I guess?.

We are, Jon..

That's right..

And we think that issue is going to play out over a fairly long period of time with what's going on with the New England Transmission Owners case and its remand back to FERC. We think we'll be in a long period of having to reserve before that issue gets resolved..

Yeah.

And what drives the decision to up the reserve right now?.

Yeah, I don't think it's been an increase in the reserve. I think we've been steady about where it's been and have kept it held at that level. I think there are positive things to come out of the new FERC makeup and we're just going to hold steady for – until it gets resolved..

Okay. But I thought you just said you did increase the reserve and that's why you didn't have growth this quarter, but now it sounds like maybe you didn't..

We did not increase the reserve. It's been steady. It's been constant..

No, we didn't increase it, but the true-up hits in July. That's what happened..

Okay. And then, just one other, on Wind Catcher, we noticed earlier this week that Xcel proposed some sort of different terms to how they might look to get recovery in Texas.

And I don't know if you have any comment on that – the base or framework or if you think that could end up being a template for how things might play for you?.

No. I don't see it that way because these projects are pretty unique and the way you look at them, and ours has a 350-mile, 765kV generation interconnection associated with it, but it's also massively larger. So you can look at the risk being taken and the economics of the projects themselves. They stand on their own merits. So we filed our plan.

I know that Xcel had to change theirs a little bit, but that's sort of their business and our projects are our business. So we'll continue with all four jurisdictions in the same manner in which we filed and we'll see where it goes..

Okay. I think that's it. Thank you, guys..

Thank you..

We'll now go to the line of Praful Mehta with Citigroup. Please go ahead..

Thanks so much. Hi, guys..

Hi, Praful. Good to see you..

Hi, same here.

Just following up on Wind Catcher, I wanted to understand, of the $2.5 billion benefit that you've highlighted for the first 10 years, how important is that PTC? And do you see any risk to that PTC flowing through to the project itself?.

That PTC is really important and that's why the brevity in which we're asking for approvals of this project are instrumental. I mean, the numbers stand for themselves. The numbers are just, like I said earlier, a slam dunk.

But when you look at the $2.5 billion PTC, that's a huge part of the economics associated with making sure our customers can benefit from that so – and timing is critical..

Got you.

So I guess, when do we get color on like the likelihood of the timing? And what kind of risks does it bring to the approvals, I guess?.

Yes. So, obviously, we filed – and I'm really actually happy that the procedural schedules have been set up pretty consistent and constructive of getting a solution in place.

I mean, all four jurisdictions have procedural schedules that match-up to sort of our April timeframe that we're looking at, so that we can really take a hard look at what the risks are, what the rewards will be, what the result of the Commission's orders will be. That will give us some real insight in terms of this project.

But like I said before, I'm pleased with the progress that's been made..

Praful, you may....

Okay. Fair enough..

Praful, you may not have gotten to it, yet, but slide 32 of our presentation, we kind of lay out the timeline in each of the jurisdictions and when we expect hearings to begin. And you can anticipate orders shortly after those hearings take place..

Got you. Thanks. And then in terms of the pending rate cases, obviously, you have a pretty busy regulatory schedule.

Just wanted to understand, your ROEs for all these rate cases are in the 10% to 10.5% range, is there any risk given current interest rate environment on those ROEs? Or do you see those ROEs – authorized ROEs to be pretty stable?.

I think we are pretty consistent, as we talked earlier about 2018 being in that approximately 10% range, and of course, it's going to result from negotiations or from the outcomes of these cases. And so as we look at it, the aggregation of those cases will be in that approximate 10% range, that's what you should look for.

And of course, we filed – the normal course of rate cases. I mean, you file based upon what we really believe the ROE should be and then, the course, you have to deal with other parties and deal with the – and the Commission itself will make the decision on what the ultimate ROE is.

And like I said earlier, we expect our aggregated to be around that 10% range..

Got you. Thanks so much, guys..

Yeah..

And we'll now go to the line of John Barta with KeyBanc. Please go ahead..

Good morning, John..

Good morning. Thanks for taking my question.

I just want to better understand how interrelated the wind plant and gen-tie for Wind Catcher are, were hypothetically, is the capital associated with the wind side were reduced a little bit? Is the need still there for the 765 kilovolt gen-tie?.

Oh, yeah, they go hand-in-hand. Obviously, you would be building a huge wind farm to nowhere if you don't have the generation interconnection there. And so with – and with 2,000 megawatts of wind capacity at that location, that drives a pretty large substantial generation interconnection.

And even if you – in this case, you won't reduce the size of it, but the size of the wind farm is really the big driver on the capacity side associated with the size of the generation interconnect. So they go hand-in-hand. One doesn't occur without the other and that's why it's all being viewed as a single project.

And that's why we're working really hard to lock in the arrangements associated with construction on both sides, so that we can eliminate as much risk as possible..

Okay. Thank you. That's it..

And we have exhausted all questions in queue at this time. Please continue..

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. Rich, would you please give the replay information..

Certainly. Ladies and gentlemen, this conference will be available for replay after 11:15 a.m. Eastern today through November 4 at midnight. You may access the AT&T teleconference replay system at any time by dialing 1-800-475-6701, and entering the access code of 431431. International participants may dial 1-320-365-3844.

Those numbers again are 1 -800-475-6701 or 1-320-365-3844 with an access code of 431431. That does conclude our conference for today. Thank you for your participation and for using AT&T Executive TeleConference. You may now disconnect..