美國電力 (AEP) 2017 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the American Electric Power Second Quarter 2017 Earnings Conference Call. (Operator Instructions) And as a reminder, your conference is being recorded.

I would now like to turn the conference over to your host, Ms. Bette Jo Rozsa. Please go ahead.

Thank you, Lois. Good morning, everyone, and welcome to the Second Quarter 2017 Earnings Call for American Electric Power. Thank you for taking the time to join us today. Our earnings release, presentation slides and related financial information are available on our website at aep.com.

Today, we will be making forward-looking statements during the call. There are many factors that may cause future results to differ materially from these statements. Please refer to our SEC filings for a discussion of these factors.

Our presentation also includes references to non-GAAP financial information. Please refer to the reconciliation of the applicable GAAP measures provided in the appendix of today's presentation.

Joining me this morning for opening remarks are Nick Akins, our Chairman, President and Chief Executive Officer; and Brian Tierney, our Chief Financial Officer. We will take your questions following their remarks.

I will now turn the call over to Nick.

Thanks, Bette Jo. Good morning, everyone, and welcome to AEP's Second Quarter 2017 Earnings Call.

Once again, this quarter, AEP released earnings that are on track for the year despite very mild spring weather. In fact, along with first quarter results, where winter was also mild, the weather has impacted earnings by about $0.12 per share year-to-date versus normal, but we're still on budget to meet our earnings guidance for the year.

As you know, we recognized the mild weather early on in the year and adjusted our O&M spending to compensate for the possibility of mild weather impacts. So again, we actually continue to be on budget with our projection for the midpoint of guidance. So we confirm our existing 2017 operating guidance range of $3.55 to $3.75 per share.

We reported GAAP and operating earnings coming in at $0.76 per share and $0.75 per share, respectively, versus second quarter 2016 GAAP and operating earnings of $1.02 per share and $0.95 per share, respectively. For the year-to-date, that brings 2017 year-to-date to GAAP and operating earnings of $1.97 per share and $1.72 per share, respectively, versus 2016 year-to-date of $2.04 per share GAAP and $1.97 per share operating earnings.

This year, comparing 2017 to 2016 is like comparing apples to oranges. We're a different company, centered on regulated operations and investments without significant unregulated operations as in 2016 and have effectively derisked the company and really focused on our earnings growth trajectory of 5% to 7% in the future. Nothing has changed for AEP in its view of achieving our 2017 guidance as a foundation for future growth.

Since football season is upon us, as Tom Landry, the famous coach of the Dallas Cowboys, once said, "Confidence comes from knowing what you're doing. If you're prepared for something, you usually do it. If not, you usually fall flat on your face."

AEP is confident. We know what we're doing, and we are prepared. We're on track again for guidance, and the fundamentals, as we will talk about later, are strong. So our headline is guidance confirmed, fundamentals getting stronger despite the weather.

Just to reiterate the point regarding mild weather year-to-date for the second quarter, our heating degree days -- and you'll see that in the 10-Q on the registrants -- were significantly below normal, making the quarter the second mildest in the last 30 years. When taking into account the first quarter as well, 2017 year-to-date has been the mildest year based upon heating degree days in the last 30 years. That being said, from a load perspective, Brian will be getting this in more detail a bit later, but we're pleased with the strong industrial load performance this quarter in almost all sectors, that if this trend continues, will bode well for commercial and residential pickups in the future.

Moving through some of the areas of interest this quarter. I'm sure you all saw the announcement yesterday regarding the Wind Catcher Energy Connection project, a proposed and substantial renewables project that would ultimately serve our AEP, SWEPCO and PSO customers in Oklahoma, Louisiana, Texas and Arkansas. This project has been almost a year in the making and is in the developmental stages with filings to be made in these 4 state jurisdictions asking for approval to develop, construct and own 2,000 megawatts of high-efficiency and capacity factor wind resources, along with an approximately 350 mile, 765 kV transmission line that serves as a generation interconnect to connect the resources to serve PSO and SWEPCO customers. The estimated cost of the project is approximately $4.5 billion, including AFUDC, and ownership is split between SWEPCO and PSO, 70%-30%, respectively.

The beauty of this project is several-fold. It benefits -- number one, it benefits customers by approximately $7 billion over the 25-year life, $2.7 billion on a present-value basis. Number two, it'll boost economic growth in the region where the jobs, taxes, royalties and economic development follow-on effects will be considerable. Three, it provides further diversification of generation resources by using indigenous, high-quality resources in the region, mitigating fuel and congestion risk for consumers as well. And it also provides AEP investors with the opportunity for earnings growth as a result.

This project is not presently in our capital plan because the various commissions need time for review. But this is a great project, and I'm happy to see Commissioner Foster Campbell in Louisiana and the Governor Hutchinson of Arkansas already make statements of support. Looking at the benefits to all of this project, this project should be a no-brainer.

Moving on to other subjects. AEP's operating companies are in the midst of several rate cases, 5 if you include the Ohio ESP. I'll cover these in more detail upfront before we get to the general discussion with the equalizer graph.

At SWEPCO, the Texas base case that was filed December of 2016 concluded its hearings in June. The net revenue request of $69 million, with a requested ROE of 10%; rate basing of wells; Pirkey, Flint Creek and Dolet Hills environmental controls retrofits, along with a recovery of the remaining Welsh 2 net book balance; and increasing SPP costs are the main drivers there. We expect an order in November, with rates retroactively applied from May of 2017.

I&M is working on base cases in both Michigan and Indiana. The Michigan case, filed in May, include a $51.7 million net revenue request, while the Indiana rate case, which was filed yesterday, include a $263 million net revenue request. Both cases requested a 10.6% ROE. Key drivers of these cases are increase in rate base not covered by riders, a loss of wholesale customer load and a request to accelerate depreciation of Rockport. New rates are expected to be effective in March of 2018 for Michigan and July of 2018 for Indiana.

AEP Ohio is seeking to extend their ESP, which is currently set to expire in May of 2018 to 2024. Key issues of the case include increasing the cap on the distribution investment rider to account for the longer period of investment, funding for a 4-year trim cycle, and some grid modernization activities. Settlement discussions are ongoing and appear to be productive.

PSO filed a rate -- a base case in June requesting a net revenue increase of $156 million and an ROE of 10%. Major drivers in that case include rate base environmental controls installed at Northeastern and Comanche for environmental compliance, and the PSO conversion to basically 100% AMI meters. Other items include increased depreciation rates and also SPP transmission charges as well. We expect rates to be effective in January of 2018 as a result of this case.

And regarding Kentucky, Kentucky Power filed a base case in June requesting a revenue increase of $65 million with an ROE of 10.3%. This case is primarily driven by load loss and other increases in rate base. And rates are expected to be effective in January of 2018.

So all in all, these 5 cases amount to over $500 million in revenue increases. So a substantial year for AEP to progress along the lines of improving the ROEs in these various jurisdictions.

Updating on a few other items. In May, the rationalization of our competitive generation business in Ohio continued with the sale of our sale -- sale of our share of the Zimmer plant 330 megawatts to Dynegy, and our corresponding purchase of Dynegy's share of Conesville Unit 4, which is 312 megawatts. This sale and purchase resulted in consolidating the ownership of each unit with its respective operator, enabling better planning and decision-making around each unit. Also consistent with our filing with the court regarding amendment to the NSR Consent Decree, AEP is proposed to retire Units 5 and 6 at Conesville, 800 megawatts in total, no later than the end of 2022. This will ultimately take our Ohio fleet down to just 2 coal-fired units after the retirement of Stuart station, 600 megawatts, next year and the acceptance of our proposal to retire Conesville 5 and 6 by the end of 2022. The remaining 2 units are Conesville Unit #4, which is 650 megawatts and Cardinal Unit 1, 595 megawatts, for a total of about 1,250 megawatts. We continue to explore strategic alternatives for these remaining 2 units in Ohio.

Our competitive renewables business continues to grow at a pace consistent with our messaging to you last fall, where we announced plans to invest $1 billion in contracted renewables over the next 3 years. As an update, AEP Renewables recently acquired the interest in a 28-megawatt solar project in California, which supplies energy to a 20-year PPA with an investment-grade utility. Also, AEP OnSite Partners continues to see its opportunities grow with a number of smaller-scale solar projects in construction in the pipeline. Between these 2 entities, we have committed $360 million in projects so far. And we continue to look for opportunities that are consistent with our disciplined return requirements and tolerance for risk.

So regarding the proposed Ohio legislation, moving on to that, in an effort to ensure long-term generation for Ohio customers with reduced pricing volatility and economic development benefits for the state, AEP Ohio has been actively engaged with a variety of stakeholders to introduce legislation that will enable this to occur. The 2 primary components of our proposed Ohio restructuring legislation include, not only the recovery of OVEC per a legislative solution and also clarity on regulator recovery for the building of new generation if the PUCO determines a need.

With respect to OVEC, House Bill 239, with a companion bill in the Senate, calls for the owners of OVEC to receive recovery of OVEC through billing of customers or customer credits when market prices are above cost. The legislation would take the PUCO's actions, that were approving recovery for AEP, which needs to be reapproved every few years via the ESP and make it last for the remainder of the life of the plants through 2030. The bill would provide benefits to all OVEC utility co-owners in the state, so it's obviously something that's supported by the other utilities. And we expect hearings to resume when the legislature returns from summer recess in September, followed with a vote in the House and the Senate. The OVEC bill seems to have a wide range of support at this point.

Once we have an outcome of the OVEC legislation, we expect the legislature to consider a bill to provide clarity on regulatory recovery for the building of new generation. This restructuring legislation certainly will have more hurdles to overcome with opposing parties, but AEP believes there are several compelling reasons why this should be considered that would benefit the state of Ohio and our customers.

So now moving over to the equalizer graph. You can see that we have regulated operating ROEs, currently averaging about 9.8%, which we typically range -- you'll see it quarter-to-quarter in the 9.8% to 10.2% range, so centered around that 10% in general. We continue to maintain that. As you can see, there's -- we've noted that with asterisk, the ones that are in rate cases, and they typically are the ones that are lower from an ROE perspective. So we're doing exactly what is expected of us in terms of ensuring that we are getting the kind of return expectations for the investments that are made in these various jurisdictions.

We also are showing AEP Ohio a little bit differently because we wanted to make it absolutely clear that the 13.6% return that's reflected here is all in and includes legacy items that were involved in the settlement; involved in other activities, like the RSR payments; and those kinds of things that are not included in a SEET analysis. So if you exclude those items, the actual return on equity for AEP Ohio is 12.2% on a SEET basis. So just want to make absolutely clear that when we look at AEP Ohio, we're looking at 2 different things there. But the SEET-related activities, which is really germane to what AEP is actually accomplishing, is the 12.2%. The rest is legacy-related items.

So looking at each jurisdiction. And as I mentioned, AEP Ohio is obviously moving ahead with filings that have been made relative to grid modernization and other activities with smart cities, which is incredibly important to AEP from a strategic perspective to ensure that we're moving ahead from a technological perspective.

APCo, the ROE at APCo at the end of the second quarter was 8.9%. That -- there's been a onetime recognition last year as a result of the 2015 West Virginia base case. So that's why you see the ROE dropping off. But we'll -- and also, the weather has been a significant impact from an ROE perspective for the quarter as well to APCo. Base rates, as you know, are still frozen in Virginia as a result of the February '15 rate freeze law.

And as far as Kentucky's concerned, I talked about the Kentucky case. We obviously have filed that. It's an important case in front of the commission. I know it's a challenging case, given the loss of load there, and that's an issue for us. And I think there's a two-pronged approach there: one, in relation to the ratemaking aspects.

The other is related

to the economic development in the territory. And I can't say enough about the work that Matt Satterwhite's doing out there in terms of -- the President out in Kentucky. We have recently had an announcement of a large aluminum company that's agreed to locate in the service territory, bringing 500 permanent jobs and 1,000 construction jobs. And it really is centered on the aerospace technology area. So hopefully, that'll be a seed type of opportunity for other businesses to locate there.

So we're working very heavily on a two-pronged approach there. Obviously, you have to meet the ratemaking aspects of it. But secondly, we are working really hard on the economic development side of things to improve the denominator associated with the ratemaking activity.

From an I&M perspective, we achieved an ROE of 9.3%, mainly impacted by weather and formula rate true-ups. I&M filed, as you know, the rate cases in both Michigan and Indiana.

PSO, at the end of the quarter, was 6.7%. The -- that low ROE is primarily because of the regulatory lag and the outcome of the last Oklahoma commission rate case there. And this rate case that's been filed now is particularly important, because -- particularly in light of the investment, the proposed investment related to the wind project. We have to see a positive indication in relation to the ability to invest in Oklahoma. And this current case is extremely important in demonstrating our ability to invest in that state. So we're looking for a good outcome out of this particular rate case.

SWEPCO, the ROE for SWEPCO at the end of 2017 was 6.3%. And certainly, SWEPCO is working on full cost recovery associated with the environmental equipment that I mentioned earlier. And of course, on -- in April, the LPSC, Louisiana Public Service Commission, unanimously approved an increase to the formula base rates, increasing annual revenues by $36 million, which those rates were effective May 1. So SWEPCO continues to make progress from that perspective, but you still have the -- and will continue for the time being, having the overhang of the Turk plant, the 88 megawatts of Turk that still is hanging out there. So we'll continue to see that. And it definitely impacts the ROE by -- overall ROE by about 1.3%.

AEP Texas. The ROE for AEP Texas at the end of second quarter 2017 was 10.2%. And the lower ROE is primarily due to increased capital expenditures and slightly lower-than-expected revenues.

As far as the Transco's concerned, it continues to plug along. Second quarter at 13.2%. The improved ROE is driven by a decrease in regulatory lag compared to prior years, primarily due to the implementation of fully forward-looking rates in the PJM region as a result of the 205 case.

So we continue to make progress. It shows the diversity of the AEP system. Some are going to be high. Some are going to be low. Actually, none are high. Make sure to make that point. But certainly, for those that are lower from an ROE perspective, we continue to work on those, and we're making the steps that you would expect us to make.

So with that, I'll conclude. As you can see, we're in the midst of some substantial rate activity in our state jurisdictions this year and continue our strong growth in the transmission business. But we also continue to make considerable progress on our mission to be the premier regulated-energy company in the future. With a culture that supports innovation, financial and operational discipline and execution and our focus on the future, Wind Catcher, smart cities, Columbus, BOLD transmission being perfect examples, this company is heading in a different but right direction.

As many of you know, I play the drums in a band that is appropriately named The Power Cords. One of our favorite songs we haven't played yet is Hitch a Ride by Boston. The lyrics talk about leaving the steely, cold city and hitching a ride to the other side of -- sailing away, sunshine and freedom. Interesting, wind, sun and freedom, to make the right decisions with a firm foundation. That's why AEP is different today, and we remain undaunted in our mission. Brian?

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

Let's begin on Slide 6, which shows that operating earnings for the second quarter were $0.75 per share or $370 million compared to $0.95 per share or $466 million in 2016. This difference can primarily be attributed to the sale of the competitive generating assets and positive items that occurred last year that were not repeated this year.

Let's look at our earning drivers by segment. Earnings for Vertically Integrated Utilities were $0.25 per share, down $0.18. Favorable prior year items contribute to this difference, including formula rate true-ups, a June 2016 recognition of deferred billing in West Virginia and a 2016 positive tax adjustment. Other rate relief was favorable due to the recovery of incremental investments across multiple jurisdictions. Weather was milder than last year, as Nick said, and our normalized retail margins were slightly lower. Other unfavorable items in this segment include higher O&M due to transmission services and forestry expenses, higher depreciation and lower AFUDC.

The Transmission & Distribution Utility segment earned $0.23 per share for the quarter, down $0.02 from last year. Unfavorable drivers in this segment include the reversal of a regulatory provision in 2016, lower normalized retail margins, higher O&M due to increased transmission services, higher depreciation and a higher effective income tax rate due to positive 2016 adjustments. Partially offsetting these unfavorable items are recovery of incremental investment to serve our customers and higher ERCOT transmission revenue.

Our AEP Transmission Holdco segment continues to grow, contributing $0.26 per share for the quarter, an improvement of $0.07 over last year. The growth in earnings includes the implementation of the FERC 205 forecasted transmission rates. This segment also recorded formula rate true-ups for the second quarter, which are similar to last year's number. In future years, the true-up should remain minimal due to the implementation of forecasted rates. 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 our return on incremental investment. Net plant less deferred taxes grew by $1.1 billion, an increase of 32% since last year.

The Generation & Marketing segment produced earnings of $0.04 per share, down $0.05 from last year. This segment realized lower earnings due to the sale of the competitive generating assets. Partially offsetting this negative impact were lower depreciation on the remaining assets, better wind conditions and lower overall costs. Corporate and Other was down $0.02 per share from last year due to increased O&M and interest expense.

Let's turn to Slide 7 and review our year-to-date results. Operating earnings through June were $1.72 per share or $845 million compared to $1.97 per share or $967 million in 2016. This difference can primarily be attributed to unfavorable weather, the sale of competitive generating assets and positive items that occurred last year. Offsetting these effects were transmission earnings and recovery of incremental investment to serve our customers.

Let's look at these earnings drivers by segment. Earnings for Vertically Integrated Utilities were $0.69 per share, down $0.30 with the single-largest driver being weather, which negatively impacted earnings by $0.11. Partially offsetting the unfavorable drivers is the increased recovery of incremental investment across multiple jurisdictions. The box on the chart was other smaller impacts for this segment.

Through June, the Transmission & Distribution Utility segment earned $0.47 per share, the same as in 2016. Favorable drivers in this segment include rate changes, higher ERCOT transmission revenue and weather. These were partially offset by several items, including lower normalized load, the reversal of a regulatory provision in 2016 and higher O&M, depreciation and effective income tax rates.

AEP Transmission Holdco segment earnings through June were $0.41 per share, up $0.13 over last year. The growth in earnings includes the implementation of the FERC 205 forecasted transmission rates, the impact of the annual true-up for formula rates and a return on incremental investment.

The Generation & Marketing segment produced earnings of $0.18 per share, down $0.06 from last year. This segment realized lower earnings from the sale of the competitive generation assets as well as lower trading and marketing margins. These decreases were offset by lower depreciation on the remaining generating assets, an improvement in the retail business, positive impacts from solar projects going into service and lower overall costs.

Finally, Corporate and Other was down $0.02 per share from last year due to increased O&M. For the year-to-date period, certain unfavorable comparisons to 2016 were anticipated, like the sale of the generating -- like the sale of the competitive generating assets. The milder weather was not anticipated but is a reality that we're addressing. In response to these issues, we will manage to lower O&M expenses for the second half of 2017 compared to 2016. With that in mind, we are confident in reaffirming our operating earnings guidance for the year.

Now let's take a look at Slide 8 to review normalized load performance. Starting with the lower-right chart, our normalized retail sales increased by 0.7% this quarter and are now essentially flat for the year. For both the quarter and the year-to-date, the growth in industrial sector is being offset by declining residential and commercial sales.

Moving clockwise on the slide. Industrial sales increased by 4% this quarter, bringing year-to-date growth in line with expectations for the year at 1.8%. Industrial sales trends have improved since the second quarter of last year when the impact of low energy prices was the most severe. We are now seeing strong industrial results across most of our operating companies and industry. We are optimistic that growth in industrial sales is predictive of better performance for our residential and commercial classes.

In the upper-left chart, normalized residential sales were down 1.5% for the quarter and down 1.6% year-to-date. Residential customer counts were up 0.4% this quarter, which is nearly double the pace we saw in 2016.

Finally, in the upper-right chart, commercial sales for the quarter decreased by 0.7%, bringing the year-to-date normalized growth to negative 0.4%. Commercial sales were down across our system with the most pronounced drop in Appalachian Power and Kentucky Power. Since residential and commercial sales tend to lag industrial growth in a business cycle, we anticipate improvement in these classes in the coming quarters.

Turning to Slide 9. Let's take a deeper look at some of the indicators that help explain our stronger industrial load performance for the quarter. The top chart shows the relationship between AEP's Oil and Gas Extraction sales and oil prices. In 2017, oil prices have hovered around the $50 per barrel range through the first 2 quarters, which has been enough to attract more upstream drilling activity within our service territory. Compared to last year, Oil and Gas Extraction sales are up 3.2% for the quarter, which is the strongest growth since 2015. The increase in drilling activity is largely focused in Oklahoma.

The bottom chart is showing the relationship between our mining load and the price of natural gas. Mining production is closely tied to demand from the electric utility sector. When natural gas prices are low, electricity markets tend to select more gas generation over coal units. In addition, we have experienced increased mining for metallurgical coals in the Appalachian Basin. Higher commodity prices in 2017 are responsible for the improvement in this sector's sales for the quarter, which are positive for the first time in years. We will continue to monitor energy prices throughout the year as it clearly impacts our energy-related industries.

Now let's review the status of our regional economies on Slide 10. As you know from previous calls, most of the energy-producing economies within our service territory experienced recession in 2016, especially in the West. With higher energy prices and a subsequent pickup in oil and gas activity in 2017, our service territory has now come out of recession and is in recovery. As shown on the upper-left chart, our Eastern territory grew by 3.2% this quarter, which was 0.7% faster than the U.S. estimate. Our Western territory grew by 0.5%, which is a notable improvement from previous quarters.

Looking at the growth at our East Vertically Integrated Utilities in the upper-right chart, it is noteworthy that Kentucky Power eclipsed Indiana Michigan in terms of GDP growth. As you know, Kentucky Power's territory has a higher concentration of coal mining, which improved for the first time in years. Indiana Michigan, on the other hand, has a higher exposure to the automotive industry, which had a record-setting year in 2016 but has moderated since. Appalachian Power's territory came out of recession last quarter and is expected to improve throughout the year.

The bottom-left chart shows our West Vertically Integrated Utilities. SWEPCO's service territory came out of recession last quarter and saw a 1.1% growth in GDP compared to last year. PSO, on the other hand, is still technically in recession and isn't expected to emerge until later this year.

Finally, in the bottom-right chart, you see that both of our Transmission & Distribution Utilities continue to improve in the second quarter, with the growth in Ohio nearly 3% above that in Texas. 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 economic trends of our operating companies. They are consistent with the improvement we projected in our guidance for 2017.

Now let's move to Slide 11 and review the company's capitalization and liquidity. Our debt-to-total-capital ratio increased 0.5% during the quarter to 54.5%. Our FFO-to-debt ratio is solidly in the BBB+ and Baa1 range at 18.1%.

In June, Moody's upgraded Ohio Power's rating 2 notches from Baa1 to A2 and cited the strong financial metrics and a supportive regulatory environment as reasons for the upgrade. In addition, Moody's revised the outlook for AEP from stable to positive, recognizing strong financial performance of Ohio Power, I&M in the Transcos as well as AEP's overall strategy of focusing on growth in our wires business.

Our qualified pension funding improved approximately 1 percentage point to 99%. Plan assets increased due to strong returns and the company contribution of $94 million during the quarter. Plan liabilities were essentially flat due to relatively stable interest rates. Our OPEB funding improved 2 percentage points during the quarter to 110%, 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 net liquidity stands at about $1.85 billion, supported by our $3 billion revolving credit facility. As discussed last quarter, we terminated the $500 million facility in May.

Let's turn to Slide 12 and try and wrap this up. While quarterly and year-to-date earnings were below last year's results, with the exception of weather, these results were anticipated due to the sale of our competitive generating assets and certain 2016 events that did not repeat this year. Our financial results are in line with the internal forecasts that support our annual guidance.

We expect O&M expense for the second half of 2017 to be favorable compared to 2016 by $0.16 per share. We expect these reductions to be evenly spread amongst the Vertically Integrated Utilities and Transmission & Distribution Utility segments. Accordingly, we are reaffirming our 2017 operating earnings guidance range of $3.55 to $3.75 per share and expect to deliver results, as Nick said earlier, in the middle of that guidance range.

With that, I will turn the call over to the operator for your questions.

(Operator Instructions) Our first question is from the line of Greg Gordon from Evercore.

It's actually Kevin here. If I'm just looking at your capital forecast through '19, it's about $5.6 billion a year and a 7.7% CAGR. Based on the current line of sight, if you don't consider the wind project, would you expect a material drop-off in core capital needs after 2019?

No.

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

That's right.

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

Yes, that's right. That's right. There'll be traditional ratemaking on that.

Our next question is from Jonathan Arnold from Deutsche Bank.

Just picking it up also on the wind and the new investment. Any thoughts preliminary, Nick, on how you might finance this? And how much room you have to prepare leverage in the mix?

Yes. So obviously, we want to get to a point of getting commission approvals, because I think this is a huge project. It's a great project. If you look at it company by company, it's not that huge. But when you look at the companies involved, the areas involved, we need to go through with the regulators and make sure they understand and see the benefits. And some already have, but the benefits that we see in this project. Once we get to that point, then we'll be in a much better position to talk about financing and the capital required and whether we issue equity.

We've talked in the past about if we had a large project that really made sense and we could focus the investment on that, as opposed to the general coffers of the corporation, then we believe investors should like that. So if we get down the road, we'll figure out what the appropriate mix is. And obviously, we continue to look at capital, look at our credit metrics. We want to make sure that we remain a very firm foundation for investment. So Brian, I don't know if you have anything to add to it.

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

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

And Nick, can you give any kind of -- any insight into the calculation of the $7 billion customer benefit? Like do you -- are you assuming a carbon price? At what sort of level? Just anything else to kind of help us kind of get to that number.

Yes, so we've obviously assumed a natural gas price going forward and -- because, obviously, this is an important hedge against fuel costs. And when you look at -- we did -- we spent a lot of time on the analysis of that and certainly, look at the fuel aspects of it. We looked at fuel differentials. Obviously, we looked at carbon, and we looked at the value of the production tax credit. So those 3 components certainly provided the center of the analysis.

And we looked at mid-range cases. We've looked at load cases in terms of natural gas pricing and that kind of thing, and it still stands up. I mean, when you look at the -- certainly, the immediate benefits and the real benefits of the PTCs, along with what could happen with carbon, what could happen with natural gas prices, it just looks like a great project. So...

The $7 billion, the $2.7 billion NPV, is that kind of the sort of mid scenario? Or where does that fit within the range of scenarios you look at?

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

Okay. And then could I just -- finally, on the transmission piece, obviously, you said normal ratemaking. But what's the -- would that also been predominately spending that would fall kind of in the back half or very end of your plan into the sort beyond '19 period?

Absolutely.

Okay. So we should think about this as more how we sustain 5% to 7% rather than incremental 2%? Or is it...

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

And our next question is from the line of Chris Turnere from JPMorgan.

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

Yes, we will. And it's part of the normal ratemaking process, but we would obviously be filing for whatever CCN approvals. And we got a -- there's an exception to the MBM rule, the market-based mechanism in Louisiana that, I guess, a hearing just yesterday or the day before approved an exception for that. So you're going through the right steps to get to the point where the commissions become comfortable with the investment, and then we'll go through the normal ratemaking process for both the generation and the transmission.

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

Yes, certainly. I mean, obviously, you don't do a project like this without looking at the socioeconomic benefits in the region and for the customer. So -- and even Governor Hutchinson this morning mentioned that it's good for jobs in Arkansas as well. But substantial -- certainly, there's substantial procurement in all 4 of the states involved.

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

So in the previous rate case in Oklahoma, obviously, we were disappointed with that outcome. And it was a somewhat challenging time in many respects. And when you -- when we look at the present case, our message has clearly been that this is a very important rate case for Oklahoma. Because Oklahoma was doing just fine from a jurisdictional perspective up until a couple of years ago. And then the last rate case was really deficient in terms of its outcome because, not only was the time frame long to get it resolved, but also, the outcome is in effect, chasing expenses that are being made on behalf of customers.

So we've got to get that back on the right track, and that's why this case is so important. Not only will it send a signal that we can invest the way we feel like we should in Oklahoma and can in Oklahoma, but also have an impact on projects like we just discussed. Because you really have to think about investments in jurisdictions that are chronically short. Oklahoma has not been that. And I think we're viewing sort of a perturbation that we can recover from. And I truly believe that Oklahoma and Stuart Solomon down at PSO, which is our President down in PSO, is working very hard to get that message across to everyone involved. That in order to have a successful Oklahoma from an energy standpoint, PSO has to be part of that picture. And certainly, we're focused on making sure we get a good outcome.

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

Yes, do you have the test year?

(inaudible)

Let's see.

Chris, we can have Bette Jo get you that detail.

Our next question is from Anthony Crowdell from Jefferies.

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

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

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

So you have the 88 megawatts of Turk sitting out there. But when we did the analysis, we showed that even though you're taking some 9 million-megawatt hours of wind power and energy coming in, you still need the capacity across the board. And in fact, when we looked at the capacity factors of the other generation, you only saw a very small 1% to 3% drop-off in terms of capacity factor on coal. And certainly even with natural gas, it wasn't that large of a drop-off.

So this is really playing against the forward view of fitting in a slice of energy to the benefit of consumers, but still using the capacity out there that's available. So it could put more pressure on the unregulated part of Turk, but Turk is a very efficient unit and that -- I don't think there's going to be, I mean, any difference. It's probably going to be negligible at best.

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

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

Our next question is from Leslie Rich from JPMorgan.

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

That's right, that's right.

Mid-'18.

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

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

Yes. Yes, we have.

And I guess, why does the region need 2,000 megawatts of generation? I mean, are you shutting other plants? Are you -- is demand growing? You said capacity factors on the coal and gas plants won't decline that much.

Yes, Leslie. And really, and this is probably the most important point to be made in the regulatory filings. And I'm glad you asked that question. This is really -- any wind power project is an energy play, not a capacity play. So from the energy perspective, you're going to get 9 million megawatt hours out of it coming into the system. But at the same time, you're only going to get -- I think an SPP is only like 7%. I may be off by 1% or 2%, but only 7% counts as capacity. So you still need the other units to provide capacity, and they fill in from an energy perspective as well. So -- and so we just have to keep in mind in this project the difference in capacity and energy.

We're not shutting any other units down. Those units are absolutely needed. But what it does do is provide more diversity from a resource perspective. Low energy, very low energy pricing coming in to the sector, which means economic growth. And then when you think about the transmission side of things, yes, it's a 765, 360-some-odd mile generation interconnect. But usually with large transmission, you get large economic development. So I see this as -- just an extremely important project, not just from an energy consumption standpoint, but from an economic development standpoint as well.

So the benefits to customers are from lower fuel cost?

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

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

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

Our next question is from the line of Steve Fleishman from Wolfe Research.

So just on that same topic. Is it -- will it be clear in there, kind of in like the first year or 2, that there's net reductions like in year 1 to customers from this so that...

Yes, yes. It's not like it's back-end loaded or anything. These -- in year 1, you're seeing benefits to consumers.

Okay. And then I guess more importantly, just for the approval process in the different states, can you just talk to a little bit of -- I know states have different rules and laws on how they approve projects like this. Xcel, I know, has kind of gone through different processes, is doing something similar. So could you just -- like do any -- can all these approvals be done through just the regulatory process? Do any states need legislative changes or some kind of different way of doing regulation?

Steve, there's no legislative changes. It's all done through the regulatory process. But just keep in mind, and this goes back to the investment the -- whether it's in our capital plan or not. States deal with it in different fashions. I mean, and if we're talking April, we are going to have to sit down at the end of that April time period and figure out, okay, what is the risk to our shareholders of moving forward with this particular project, given the -- not only the regulatory outcome -- outcomes, but also the other risk components that are involved with this as well.

And we believe, certainly from a risk standpoint, from an operational and construction standpoint, if we can't put generators on top of poles and build transmission lines that we always build all the time, we shouldn't be in this business. So it's not like building a central station generation facilities. So you don't have the same level of risk from that perspective.

But the risk part of it -- part of the evaluation will be as well, the -- what kind of indications we're getting from the various jurisdictions. Because some of them, you may get outright approval. Some of them, you may get CCN approvals or CECPN approvals in Arkansas. And what is that going to mean? What is it going to mean in terms of risk? So we have another milestone where we continue to spend money on development of this project because we feel like it's that important. But in the April time frame, we will be sitting down with our board to talk about, okay, what did we learn? What are the options available to us? And what are the risk being taken? And make a decision to continue on.

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

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

And that question will come from Gregg Orrill from Barclays.

So with regard to the Wind Catcher project, would you consider selldowns as a way to finance it? Is that something you're exploring?

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

Funny how fast the word gets around.

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

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