美國電力 (AEP) 2015 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by. And welcome to the American Electric Power third-quarter 2015 earnings call. (Operator Instructions) I would now like to turn the conference over to better Bette Jo Rosza. Please go ahead

Thank you, Cynthia. Good morning everyone and welcome to the third-quarter 2015 earnings call for American Electric Power. We're glad that you're able 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.

Joining me this morning for opening remarks are Nick Akins, our chairman, President, and CEO, 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. Thank you for joining the AEP third-quarter 2015 earnings call.

Once again AEP is reporting a strong quarter performance driven by the strength of our regulated utilities and our transmission business, and as a result we are also increasing our 2015 guidance, as well. For the third-quarter 2015, AEP is reporting GAAP and operating earnings of $1.06 per share compared with $1.01 per share for third-quarter 2014.

This brings 2015 year-to-date GAAP and operating earnings to $3.22 per share and $3.21 per share respectively, compared with 2014 year-to-date GAAP and operating earnings of $2.95 per share. With a positive quarterly and year-to-date results in hand, AEP is increasing our 2015 guidance range from $3.50 to $3.65 per share to $3.67 to $3.77 per share and reaffirming our 4% to 6% growth rate.

As you already know, the board of AEP increased the dividend from $0.53 to $0.56 per share representing a 5.7% increase on an annualized basis, indicating once again confidence in the direction we're taking to become the next premium regulated utility, the tagline we used to last year's EEI financial conference. While load was also up in all three sectors, residential, commercial, and industrial, for third-quarter year-on-year we continued to analyze the make up of load and margins of each sector, as Brian will discuss in more detail later.

Our employees focus on continuous improvement and culture initiatives have been instrumental in not only achieving our earnings objective, but redesigning our lines of businesses for future success. Lean activities continue to progress across the enterprise. This has been a three-year effort in what is now over 65 initial 3- to 4-month deployment efforts generating over 20,000 ideas from employees to improve efficiency and deliver better outcomes.

We're in the process of finishing up the few remaining deployments and we will begin a process of ensuring the sustainability of the cultural and process-related changes that enable continuous improvement. It is because of primarily these efforts, along with investment growth in the regulated companies and transmission as well as the outcomes from the PJM supplemental auctions, that have approved our (technical difficulty) regarding 2016.

More to come on that in November of the EEI financial conference. As you know we announced the sale of AEP River Operations to American Commercial Lines for approximately $550 million plus the assumption of capital lease obligations of approximately $235 million.

We're very pleased with the outcome from the process we began back in March to sell River Ops at a fair price to a company we truly believe understands what it takes to be successful on the river. AEP will receive about $400 million in net cash proceeds to invest in our regulated businesses.

We have filed for the federal Hart-Scott-Rodino clearance and don't expect any delays, so we should close in November. I do want to take the opportunity to recognize and thank the entire River Operations management and operations team for their continued emphasis on providing value to AEP and its customers over the years. This sale represents a step toward the desire direction of delivering customer and shareholder value as a regulated utility company.

The PPA story in Ohio continues to develop with ongoing hearings that are occurring and should conclude here very quickly. We don't know the outcome yet, but AEP is actively pursuing discussions with the various parties in the case to ultimately drive to a solution that make sense for AEP, its customers, and other stakeholders.

We believe the PECO should be able render a decision sometime before the end of the year. Because we believe the timeframe for a decision is in hand, this will have a direct bearing on AEP's ultimate decision regarding long-term PPA coverage generation assets within our ongoing strategic evaluation process regarding the unregulated generation Ohio.

The PPA arrangements are important for the security of supply and pricing for Ohio customers and will provide an important signal regarding future investments in Ohio. We will complete our review of the board as expeditiously as possible, and as we deal with such issues that you all continue to ask about concerning strategic options, sale proceeds, use of proceeds, potential illusions, share buybacks, et cetera., I fully expect not only the PPA decision but the broader strategic decisions to be answered in early 2016.

AEP continues to work with each of our states regarding the clean power plan. We believe our states should follow initial plans with the EPA by September of next year to ensure the state maintains ownership in the development of resource plans that make sense for their particular jurisdictions. AEP and the industry needs clarity regarding investment decisions and new resources and will continue to work with the states to develop integrated resource plans that comport with the requirements of these ultimate state plans

. During the last quarter you may have seen AEP's investment in Greensmith, an energy storage integration platform company, and our continued development of utility skill solar in Indiana and Michigan, as well is our relationships with the universities to define energy solutions such as rooftop and utility skill solar along with battery technologies. These investments, in combination with our BOLD technology and transmission and other distributor-related investments, will move us toward a cleaner, more balanced energy portfolio that is focused on the quality of service to our customers.

You'll hear more about this during the EEI in November, as well. Now moving to what I usually call the equalizer chart of ROEs by operating unit. Note that the overall ROE has improved from to 9.4% from 9.1% from last quarter.

As I go through the State, I will mention what's going on in each one of those so you can have sort of a trend line of what to see in the future. For Ohio Power, the ROE for AEP Ohio is in line with expectations, and we expect to finish the year in-line with the 12% ROE forecasted.

For APCO, Virginia earnings are expected to remain steady during the period because of the previous legislation and the rate freezes that are in effect. For West Virginia we had recently the rate-case order that should address the weak returns there.

That was where our issue was in the APCO jurisdictions. The order-authorized rate increase of $99 million with an authorized ROE of 9.75%, rates were implemented in June of 2015, so we expect to see higher ROEs for ATCO for the balance of the year.

Kentucky, I know that looks a little strange to you. We didn't know what to do when return for the quarter was actually negative 0.1%. It almost looks like last year we probably should have just put the Kentucky investment into a mattress, but just understand that we did recently get through a rate case there, and we expect it to continue to improve.

That was part of the strategic decisions we made previously about what gets included in rate cases and the timing associated with them. Expect Kentucky to move up to 4% by the end of the year, and then by midyear it will be -- midyear 2016 it will be back in the 8% to 9% range.

So while we have this short-term perturbation of lower ROEs, we expect that to improve. For I&M it continues to be on track to grow earnings and achieve its authorized ROE range, which is around 10.2%. IM had a good third quarter as it continues to execute major capital investment programs and generation, Rockport, SDR, solar, and the nuclear life cycle management along with PJM transmission-related projects.

PSO, its ROE is about the same as last quarter and we continue to progress there through the rate case process. Base rate case was filed in July 2015 to recover generation, environmental control investments, and cost increases since the last base rate case.

We expect new rates to be put in place by first quarter of 2016. SWEPCO, transmission cost recovery in Texas in the form of a rate true-up in Louisiana as well as a true-up in increase in wholesale customer rates were the primary drivers for SWEPCO ROE improvement, although we continue to see it under pressure because of the Arkansas portion -- what we believe is the Arkansas portion of TURK -- that we ultimate will be looking for in terms of a retail solution, but the timing has yet to be determined.

For AEP Texas -- we expect the ROE in AEP Texas will continue to decline through 2015 as distribution CapEx increases are put in place. We're presently looking at alternatives for addressing the ROE's coming down in that jurisdiction, either through distribution cost recovery or DCRF or a rate case. But we're still looking at those options.

AEP transmission HoldCo -- HoldCo return of 11.3% is in line with the authorized return. So that keeps plugging along and we keep investing more and more in transmission.

So with all that said, as we look at the accomplishments of the third quarter and year-to-date, it should be instructive as to what the future holds for AEP. I'm reminded that yesterday October 21, 2015 was back to the future day, the day that Marty McFly and Dr. Emmett Brown time-traveled into the future from the 1989 sequel to Back to the Future.

When we look back at1989 and where we are today, during that time AEP has reduced SO2 emissions by over 80%, NOX emissions by over 80%, Mercury emissions by over 54%, and CO2 emissions since 2005 levels of 15%. More recently we have to deployed battery storage technology, the BOLD transmission line, utility and rooftop solar, and now embark on the infrastructure of the future to define a better customer experience.

These are all examples of Back to the Future's version of hoverboards and self-tying sneakers, but all of this is to say that we believe AEP is uniquely positioned both financially and culturally to be successful during this huge transition that is occurring within our industry. We will continue to focus on infrastructure development technology and resources of the future and a renewed focus on the customer experience. Our investors expect consistency and quality of earnings and dividend growth, so any decision we make should be viewed through the lens of being the next premium regulated utility.

Now I'll turn it over to Brian.

Thank you, Nick, and good morning, everyone.

Let's begin on slide 5 with a review of the major drivers affecting the earnings comparison for the quarter. This year's third-quarter operating earnings were $1.06 per share, or $520 million, compared to $1.01 per share, or $493 million last year. This solid performance was driven by our regulated businesses, which were all at or above last year's prior results.

With that background let's review the major earnings drivers by segment. Earnings per share for the vertically integrated utilities segment were $0.56, up $0.11 from last year. Key drivers in the quarterly comparison included rate changes, which added $0.09 per share and are related to the recovery of incremental investment to serve our customers.

Warmer temperatures in 2015 also contributed significantly to the earnings, adding $0.07 per share. Cooling degree days were 25% higher in the East and18% higher in our Western service areas. Margins for normalized load were off $0.03 per share for the quarter, due to lower residential sales and a slight decline in the average realization. Off system sales were down $0.03 per share, primarily due to much lower power prices this year. O&M expense was higher than the prior period, adversely affecting the quarter by $0.03 per share, mostly due to higher employee-related costs.

This segment did benefit from higher AFGDC as a result of our capital spending program, adding $0.01 per share, and lower state and federal income taxes contributed $0.03. The transmission and distribution utility segment earned $0.23 per share for the quarter, up $0.04 from last year.

The primary driver was an unfavorable regulatory provision recorded last year that was not repeated in 2015, which contributed $0.04 per share for the quarter. The remaining other variances were relatively small, including rate changes in Ohio and weather in Texas, each adding a penny versus last, and these are offset by lower off-system sales and higher O&M. The transmission HoldCo segment contributed $0.09 per share for the quarter, up $3 million over last year.

We remain on track to meet our guidance level for this segment for the year. Year-over-year the Transco's net plant grew by approximately $1.2 billion, an increase of 51%. The generation of marketing segment produced earnings of $0.19 per share, off $0.05 from the third quarter of last year.

We're beginning to see the adverse effect of lower Ohio capacity revenue and earnings, partially offset by lower O&M. AEP River Operations declined $0.01 per share, and corporate and other lost $0.02 per share, down $0.04 from last year, primarily due to higher O&M and franchise taxes.

On 5.6 we have a view of year-to-date operating earnings compared to last year. Operating earnings for the year-to-date period stand at $3.21 per share or $1.6 billion compared to last year's $2.95 per share or $1.4 billion.

Similarly to the quarterly comparison, growth from our regulated businesses are driving the improved results with the competitive businesses performing at or below last year. Consistent with our original guidance for 2015, our vertically integrated and transmission HoldCo segments are realizing strong growth, driven by our continued capital investment and rate base and execution of our regulatory plans. Favorable weather also contributed to year-over-year earnings growth.

As expected we're seeing a decline in year-to-year earnings in our competitive generation business, reflecting a loss of capacity revenue, which was tempered by lower O&M and the performance of our commercial and retail teams taking advantage of market opportunities.

The combination of all our businesses allowed us to exceed last year's results by $0.26 per share. These strong results and our confidence in our plan for the remainder of the year allow us to raise and narrow the operating earnings guidance range to $3.67 per share to $3.77 per share.

Now let's take a look at slide 11 -- I'm sorry slide 7 -- to review the normalized load performance for the quarter. Starting in the lower right corner, you see that our load increased by 0.9% for the quarter with growth spread across all major retail classes. This brings our year-to-date normalized load in line with last year.

The upper left quadrant shows that our residential sales grew by 0.8% compared to last year. The growth in residential sales is coming from a mix of customer and usage growth.

Most of the customer growth is happening in our Western territory, especially Texas, where residential counts are up 1.2% versus last year. The growth in residential usage is coming from Ohio where we saw the strongest growth in employment for the quarter. Year-to-date residential sales are down 1.1% versus last year, but this is mostly caused by the weak normalized growth reported in the first quarter, and remember that had the impacts from last year's polar vortex in it as well.

In the upper right corner commercial sales were up 1.3% for the quarter. The strongest growth in commercial sales happened in Ohio, which is consistent with the economic indicators we will discuss in more detail later.

Finally the lower left quadrant shows that our industrial sales grew at 0.7% compared to last year. We continue to see robust industrial sales growth from customers in oil and gas-related sectors, despite the decline in oil prices, which I will cover in more detail later in the presentation.

I would like to point out that most of our load growth for the quarter and year-to-date period is coming from our T&D Utilities segment, where we only recover the wires portion in our rates. Unfortunately normalized sales are down 0.8% in our vertically integrated utilities, where we recovered the full bundle rate. This means even though our normalized load is similar to last year, we lost approximately $0.08 for the year due to the mix of our sales by segment and class.

With that let's review the most economic data for AEP's service territory on slide 8. Starting with GDP you can see the estimated 1.6% growth for the AEP service area is about 0.5% less than the estimated growth for the US. This is not surprising considering the impact of falling oil prices, especially in our Western footprint.

While the nation benefits from lower fuel prices, the regional economies supporting the shale plays are experiencing the direct impact of lost jobs. For example, there are a number of metro areas like Shreveport, Tulsa, and Abilene, that have fewer people working today than they did at the start of the year.

The bottom left quadrant shows that the job market within AEP's service area is holding steady but grew at half the pace of the US. Job growth within AEP's Eastern territory exceeded the Western service area for the first time since 2011.

The sectors showing the strongest job growth for the quarter include construction, leisure and hospitality, and education and health services. We should point out that the sector which saw the biggest employment decline this quarter is natural resources and mining. This is no surprise given the decline in oil prices and active rig counts.

Now let's turn to slide 9 to update you on the domestic shale gas activity happening in AEP's footprint. Given the impact low-energy prices are having on a regional economy, one might expect our electricity sales to the oil and gas-related sectors to be down. However, we continue to see significant load increases in the parts of our service area located near major shale formations, as illustrated in upper left chart.

We are still seeing nearly 10% growth in our sales to the oil and gas sectors this quarter, despite oil prices being down 50% from last year, rig counts being down nearly 60%, and the fact that there are over 10,000 fewer oil and gas workers today than we had at the end of last year. The upper right chart shows that growth in oil and gas loads was spread across all major shale plays within AEP's service territory, with the strongest growth coming from the Eagle Ford, Permian, and Marcellus shale region.

If we dissect the oil and gas growth into its components, as shown in the bottom left chart, we continue to see the strongest growth from the midstream pipeline transportation sector, which grew by over 33% over last year. This is mostly due to the expanding natural gas infrastructure in West Virginia, Ohio, and Texas. Our upstream oil and gas extraction sales were up nearly 8%, while downstream petroleum and coal product sales declined by 0.8%. We still have a large number of new oil and gas-related expansions expected to come online over the next 18 months that will drive our industrial sales growth through 2016.

In contrast to the oil and gas sectors, the red bars in the upper left chart show that sales to the remaining industrial sectors are not growing as they were last year at this point, down 3.1% in the third quarter. In fact, through September half of our top 10 industrial sectors were down from last year's results. One industry clearly affected by the low energy prices is the mining sector, where sales were down 9% for the quarter and 8% for the year.

On a lighter note, let's turn to slide 10 and review the company's capitalization and liquidity. Our debt-to-total-capital improved by nearly 1% this quarter and is now at a healthy three 53.4%. Our credit metrics, FFO interest coverage FFO-to-debt are solidly in the BBB and BAA1 range at 5.7 X and 21.6% respectively.

Our qualified pension funding declined a bit this quarter, dropping from fully funded last quarter to 97% this quarter. This is a result of declining equity values and a slight decrease in interest rates. Our pension assets are now weighted to 60% in duration-matching fixed income securities with the balance being held in global equity and alternative investments. We adopted this more conservative investment stance as we approached full funding late last year. Our OPEB obligations remain fully funded at 112%.

Finally our net liquidity stands at $3.6 billion and is supported by our two revolving credit facilities that extend into the summers of 2017 and 2018.

Our treasury group was active during the quarter taking advantage of the low cost of debt capital. First in August, Texas North accessed the market for $125 million of senior private placement notes. The offering utilized a delayed funding structure and realized the weighted average life of issuance of 13.4 years and a weighted average interest rate of 4.04%.

Secondly in September, the treasury group in Texas Central Management accessed the market for $250 million of ten-year senior unsecured notes at it coupon rate of 3.85%. Over the past two years the treasury group has been able to lower AEP's weighted average cost of debt to 4.6%. We are well-positioned as we approach 2016, where we have a manageable debt maturity stack of slightly more than $1 billion.

Finally before we turn the call over to your questions, let me review on slide 11 some of the information we will be providing at the upcoming EEI financial conference. We will confirm our previously stated 4% to 6% growth rate, which assumes the sale of River Operations and the retention of the other businesses in AEP's portfolio. We will provide an updated operating earnings guidance range for 2016 with detail by segment. As in the past our growth rate is predicated on our continued investment in our regulated properties. So we will provide a capital expenditure plan for the next three years, details on transmission and utility investment opportunities, and a three-year financing plan for getting it all done.

We will also have some slides detailing our generation fleet transformation over the past several years, as Nick just described. These slides will demonstrate how AEP has invested over $8 billion to transform the fleet, and the resulting dramatic reductions in emissions that this investment has enabled.

This story is becoming increasingly important to a certain class of investors, and we believe AEP has a great story to tell. Finally we will surely be talking about any developments in both the Ohio PPAs and the strategic review of our competitive generation business.

With that preview for the future, let me turn the call over to the operator for your questions.

Thank you.

(Operator Instructions)

And we'll go to Dan Eggers with Credit Suisse. Your line is open.

Good morning, guys. Nick, you guys made great progress on the equalizer chart as far as improving the overall earned ROEs. How much more room when you talk about 2016 given the rate cases you see coming? Where do you see the 2016 ROE headed, and how much more improvement do you need in ROE to be able to hit the 4% to 6% growth rate?

I think it's going to continue to improve, Dan. We're probably on the order of 9.6% to 10%, in that range for 2016. It will continue to improve overall.

And then with Kentucky coming up that's helpful, although Kentucky is pretty small in the overall comparison. But the others are doing quite well.

Okay, and I guess preemptive on the Ohio generation side, but given the weakness of the power stocks in the IPP sector, is there a market of buyers still sitting out there who would be willing to transact on your assets right now? Or are market conditions potentially going to slow down, you know, maybe the urgency of making a decision on those assets?

Yes, I think there's still a set of buyers out there. It's just -- it certainly goes to the question whether a spin option is, while it's still on the table, it's more difficult because you have the paper involved with those companies. But for sale, there's still parties out there, and some of the recent transactions have shown that.

I guess just one last question. When you guys look at the load trend that's going on right now, how is the residential-versus-commercial trends having bearing on what you guys expect to see for load growth next year?

Commercial continues to improve. Matter of fact, that's probably the bright spot of the portfolio, and you have these cycles that change as we go along.

The residential, that's going up and down the last few quarters, and it really does drive this view that we need the economy to really start picking back up, particularly from the energy policy perspective. If we start exporting or if we continue a buildout of the economy that's focused on energy, then our economy will pick up as well, so we're getting some benefits from auto manufacturing and that kind of thing. But primary metals on the world market, mining, those kinds of activities are certainly having an impact.

So we've been in sort of a strange period for several quarters and actually years now. We obviously need to get the economy moving again from an energy perspective.

Got it. Thank you, guys.

Greg Gordon, Evercore ISI. Your line is open.

Hey, Greg.

Good morning. A couple questions. First, the 4% to 6% earnings growth aspiration, is that still off the midpoint of the original 2014 guidance of $3.20 to $3.40 per share?

Yes it is.

Okay, great, because you earned $3.43 in 2014, and this year you are -- at the new midpoint you're going to earn $3.73. Even if I weather normalize that, that's $3.65.

So notwithstanding the deceleration in load growth trends that you're experiencing, one would presume you're doing very well relative to that aspiration. So I have to ask, has that aspiration built in the expectation that there will be some dilution from the sale of a generation assets which gets offset overtime as you redeploy that capital into the transmission business?

Greg, that assumes the business-as-usual case, that we continue to own the properties that we do today with the exception of River Operations. And we'll do for you at EEI like we do the normal waterfall stairstep between 2015 and what we anticipate 2016 to be.

In addition to weather, which if you look across all our businesses is probably closer to $0.12, we've had things like inception gains, the generation of marketing at about $0.06. We've had the benefit from the sale of some plants and reducing our ROA obligations, that's another $0.06.

You can pretty easily do a stairstep that would take off that $3.72 about $0.24 for things that we don't anticipate to be recurring parts of our business.

That was the gist of my question. I appreciate that.

Greg, I think you have to sort of look at it like in the previous quarters. We've been talking about working to try to get to a solution for 2016. Now we have moved to confident about 2016.

Certainly even taking into account the things you've just articulated, looking back at your aspiration at the beginning of 2014, you are doing very well.

The second question is with regard to the timeline for getting an answer from Ohio on whether or not you will be able to contract a portion of that fleet. And whether that is a negating factor for concluding an asset sale or whether there is a deadline at which you would move on an asset sale and not wait around for an open-ended process?

It won't negate the discussion. I think really what matters here is as we get through the process with Ohio by the end of the year, if we have a result that says these particular units are going to be covered by a long-term PPA, then that says that we're sort of ambivalent whether, assuming the PPA addresses our concerns as certainly being long-term. We have a lot to plan out there, and as well some of the other provisions to ensure that we are able to make it quasi-regulated.

Then we are somewhat ambivalent as to whether we hold those units or not. And I think it certainly bodes well for our ability to hold on to those units and still be a regulated utility. For the remaining assets that aren't covered by the PPA, there is still a process ongoing.

So we will go through this, and as I said earlier our Board has been for the last two years, as you know, we have been going through this with our Board. And the PPA because originally we thought it may be later for a decision and no one knew because we did not have the schedule. We were concerned by that and we were not going to wait for it.

Now there's a schedule in place. There's hearing that have occurred and will conclude here pretty soon. We will have result pretty soon, and the PPA is very, very important to our standing in Ohio overall and whether we keep that portion of the generation or not.

But it doesn't change the objectivity and the measured approach that we are using to go through this process to ensure that we are making the right decisions for our shareholders. Because we get a PPA doesn't mean, certainly, that the process is all for any of the remaining generation that's not covered by that type of PPA.

So we're looking at this very straightforward and we been very consistent in our discussions. I know last quarter -- previous quarter, we were saying that we were after the capacity auctions, the capacity performance supplemental auctions, that we would know and understand a lot more. We do.

We were assuming that it was a never-ending approach associated with getting a PPA result. And it appears that the Ohio commission has taken this on seriously and are moving forward with determining what a solution would be. We are going to go through that process, fully understand it, and by first quarter next year our Board will certainly know all of the ins and outs of the issues that we are dealing with, and then we will move forward.

If there was the potential -- there's been chatter about the potential for substantive settlement talks in the contract discussions. Is that going on or not?

Are you talking about the PPAs

The PPAs, yes.

Well certainly there's been a lot of chatter and a lot of discussion with multiple parties in this case. It's a complex issue.

Certainly we continue to have conversations, and certainly FE can speak for themselves. But we are -- we both have the firm belief that there needs to be some kind of support for this generation Ohio, and it's really a discussion around what those mechanisms would look like. And so we'll continue in discussions with the parties.

I will stop there.

Okay, thank you, guys. Take care.

Anthony Crowdell, Jefferies

Good morning, I didn't know you guys are such Back to the Future fans.

(laughter) We all remember that. Some of us do, anyway. I'm probably talking to some people that don't even remember.

If you wanted to wear a Star Trek outfit at EEI, Nick, I'm okay with it.

I happened to think about that when I was talking about the BOLD line. Boldly going where no man has gone before.

Just quickly, when you think on the PPA process if we don't reach a settlement or whatever, a fully -- if we end up going a fully litigated track, when do you guys expect that to be finished?

Well so, if it's fully litigated we still expect to get an order by the end of the year. Fully litigated means obviously there were still be appeals and all that kind of stuff, but we're actually focusing on the commission order itself, because that really tells us where the policymaking decision in this state is moving towards.

And so we certainly believe that will occur before the end of the year.

Do you think such a big issue like this for Ohio with giving a PPA or entering into PPAs, do you think the appeals process would be I guess lessened if you do get a fully litigated order? Meaning are the parties start off getting a litigated order just so that the appeals process is maybe less shorter or the record is stronger versus a settlement.

Certainly I think it depends on what the order looks like. Certainly -- the commission certainly has taken a deliberative approach to this. We have certainly done a lot of analysis along with FE and others who participated in hearings about can a PPA be used. We feel really good about where we stand from a legal perspective going forward.

I think the real issue is the commission needs to come out with an order that comports with the discussions that occurred relative to the PPA. If there's deviation from that in some fashion it could be opening yourself up to more substantial appeals. But we have given the recipe. The recipe is there.

Certainly it drives a positive solution for the customers, for Ohio, and the commission certainly has the track record to be able to put that kind of thing in place that holds up.

Great, thanks for taking my question.

Thank you. Praful Mehta, Citigroup

Thanks so much for taking my call. My key question is around the generation business.

As we look at it from the EBITDA perspective year-to-date for the generation business, you have already achieved about $725 million of EBITDA. Relative to guidance midpoint of about $590 million for 2015. I just wanted to understand more long-term, is this more specific things that have happened in 2015 that are driving 2015 EBITDA to be higher, but longer term your guidance stays consistent?

Praful, a couple of things going on there. One is for the first half of the year we still had some considerable capacity revenues coming from Ohio. That dropped off in May, and we'll be experiencing that negative impact through the balance of the year. That's something that on an annualized basis you need to factor that out of the business going forward.

We also had two other pieces that contributed to the gene marketing results this year that we don't think you can consider as regular ongoing items. One is we've had inception gains of about $0.06 per share, and the other is we've had reductions in liabilities that in a positive way flow through O&M associated with the sales of two plants. One is Muskingum River and the other is a coal impoundment that we were able to sell. The combination of those two items is another $0.06.

So there are some things that you need to factor out if you're going to annualize that business on a go-forward-looking basis.

I've got you. That's very helpful.

Finally, just a key question on Ohio. I heard your points around the ESP and the PPA -- I guess I'm just trying to understand from a long-term perspective. I get message that if it's long-term, you know, it's a different answer or you're at least indifferent between sale versus keeping it.

What defines long-term? Is seven years long term enough? If you don't get the full 2015, at what point do you say, I actually do have a difference between keeping the business versus selling it?

Certainly I don't want to get into that too much because -- but long-term to us, we have filed for life of a plant. And I'll just say this, the term has to be substantial because we have to have a feeling that we can invest. And with the large capital investments that we make in generation, we need to know that we can do that and be secure from a future perspective.

So when I look at even our FERC wholesale contracts, we've had contracts that are 10 years, 15 years -- we've had the same customers for 75 years. When we talk about long-term it has to be substantial enough for us to make that kind of investment.

So I'm not going to say an actual number at this point because we have life-of-plant sitting out there, and that's what we believe what it takes. We will wait and see what it winds up being.

I can tell you this, three years, which is the length of the capacity deal in PJM, that was a three-year capacity market, that is not long enough. That's a problem within PJM and the state has an opportunity to fix that.

Thank you so much.

Paul Patterson, Glenrock Associates.

How are you doing? I just wanted to follow up I guess on that question about the generation business and the asset retirement obligation. I'm sorry if I was cutting out a little bit.

On slide 22 I noticed this that there is a $62 million benefit. And just to make sure I understood that, a lot of that has to do with asset retirement obligation going away because of some plant sales.

For the most part you don't see that recurring, is that correct?

We had reserved asset retirement obligations that ended up being higher than what we were able to realize by selling the plant to a third party. We were able to get the third party to take those obligations for less than what we had recorded on the books, and that allowed us to flow the difference between what we had recorded through O&M.

We have gone back now and checked for the remaining plants both from an engineering standpoint and from a marketing standpoint -- from a market standpoint -- those values that we have recorded the AROs at, and we believe those values to be accurate as they are in the books today.

Okay, and then just for the expected AEP Dayton, ATC liquidations which seem to be leveling off, how should we think about how they actually impacted year-to-date earnings and generation marketing? And how do you see the outlook for those in 2016?

We think those prices are going to continue to be under pressure, but I will say this, Paul, and we talked about this before. We do have as we go into a year -- a significant component of that generation is hedged, so for the third quarter of this year we are at about 60% of the margins and megawatt hours were hedged going into that period.

So we will have similar amounts hedged going forward in 2016. So for two things, one we will be able to take advantage of prices if they do recover, and we do see them under pressure right now in 2016. But also if we were to have unit outages or increased load from our hedges, we wouldn't be subject to market pricing for that as well

Great. And then back to Ohio and the PPA situation, take this with a grain of salt, but if there was an outcome in terms of settlement versus fully litigated, what would you say the odds are that it would be settled as opposed to fully litigated?

I wish I could answer that at this point. There's a lot of context within discussions, and there's multiple aspects to this, not just the units that are the generation that's within a PPA but really what's the total answer for Ohio. I even think about it from a clean power plan perspective.

The state of Ohio needs to have some framework for a foundation of a transition with baseload generation that allows it to make plans associated with ultimate retirements of that generation and replacement with new resources that are put in place. All incremental resources are either going to be natural gas, renewables, certainly efficiencies regarding the grid itself. Those are the kinds of investments that I think can really drive Ohio to a more balanced energy future that mitigates a lot of risk for consumers.

So what we're talking about here is a foundation to be provided for a transition. That's clearly important. I think it should be important to the governor, it should be important to the policymakers in the state.

If you drive that kind of solution you could wind up in a much better place than you would otherwise. So I know I said a lot other than what the direct question you asked and what's the percentage chances. But I think I'm going to those kinds of things that should and will be discussed in the framework of supporting a PPA-type of arrangement

Okay. I gathered from your previous comments that you feel pretty confident that we will get a decision one way or the other by the end of the year.

I want to make sure that as you know sometimes regulators when there's an issue that's got some -- a lot of speculation, et cetera., associated with it, sometimes it's delayed. Do you follow what I'm saying? You don't get the feeling that that's -- you feel pretty confident, tell me if I'm wrong, that you feel that this is very likely to be settled one way or the other by the end of the year

I think it will. It certainly should be settled by the end of the year. And if it goes the settlement route, then you have to think about, okay, how do you argue about the settlement, and who is involved, and all of that kind of stuff. If you litigate, well the commission needs to make a decision.

I'm really focused on making sure we drive to a solution as quickly as possible. This is been two years, by the way. The first case that was filed by AEP, and then FirstEnergy followed up. I think both -- certainly Chuck can speak for himself -- but both companies need to get on with the investment and the decisions that need to be made relative to these assets.

I certainly believe there's recognition by the commission that they do need to make this decision.

Great thanks so much.

Julien Dumoulin Smith, UBS.

Good morning. So perhaps just to follow up a little bit of detail from the last question, and again I hate if the issue is a little too much.

Is there a minimum tenor that defines getting a long-term solution for a PPA? I know it's a transient question, but how do you think about that?

Minimum tenor would be a long time. We just want to make sure that everyone understands that if -- regardless of the solution here, if there is a PPA there's sort of two parts of the gate here. One is that the commission approves the PPA. The second is what does the PPA look like?

AEP has been very out front and very focused and measured in our discussion about this to say that our expectation is a long-term PPA. One that goes past a three-year ESP cycle or has adjustment mechanisms or all of that kind of stuff. We want to make sure that we have a long-term PPA that we can depend on and that we can actually make the investments we need to make.

So minimum is long-term.

Got it. Very clear now.

Secondly, a bigger picture question, when you think about CPP, obviously we got that finalized recently, how are you thinking about coordination between the various states that you have operations in? T&D Utilities fully integrated. When do you think you start to get clarity about what needs to happen in each of those states through the filing process, et cetera? And perhaps to add to that do you need the legislative approval in any state to kick off the CPP compliance?

I think we want to make sure that the commissions are certainly involved with this. Now the states are going to take their own approach. They may litigate. I'm sure some states will litigate it. That could be done in parallel.

Our message is regardless of what you decide to do, you really need to work with us on developing a state implementation plan, because that's the only way that not only can a state have its own approach. And keep in mind the EPA did allow the states to say, okay come back with a plan and tell us what the reliability implications are. Because I believe that when the states look at their plans and they go through with the process that needs to occur. And if there are reliability implications they are in a much better position to have a plan and the factual information to support that.

And then who knows what administration changes and all that occurs along the way. But you are also in a much better position to negotiate relative to your own state implementation plan, as opposed to a one-size-fits-all federal plan that is very difficult for one state to change.

So this is why we are sort of staying out of the arguments whether states and attorney generals and all that get involved from that perspective -- from a litigation perspective. We want to make sure that the states continue to move forward.

And for us states that do work with us on developing these plans will be in a much better position because every filing we make relative to our resource plan -- integrated resource plan -- or other types of plans, we'll be able to comport with what the state really wants to see, that may be based on upon their own unique views of how they want to approach this.

We want to be part of that and be part of the discussion, and we want to be able to drive that discussion, because we have a lot of factual information that I think the states will be able to benefit from. We have already started those discussions and we will continue with that dialogue.

The states that just refuse to do a plan, we'll continue to look at the clean energy economy of the future and the technology of the future. And we will continue to advance that within the resource plans that we have.

So we just want to make sure we have answers to the questions of where states' preferences are in terms of resources that they want to move forward with, and that we are there to do it. That's where we are at.

I believe the states obviously have to make their own decisions relative to this, but we are working with the state PPAs and the state public utility commissions. And as far as legislation is concerned, we believe each individual state is unique from that perspective.

We will be working with the commissions and we'll be making our voice known in terms of where we think it should go in the future.

Great thank you.

Stephen Byrd, Morgan Stanley

Good morning, Stephen.

Good morning. We definitely need more sci-fi movie references on earnings calls, so thank you for that.

Most of my questions have been addressed. I just had two I wanted to discuss.

Transmission's always been a good area of growth for you, and you're in a pretty strong financial position. I wondered if you could just comment on how bullish you are in terms of finding additional transmission growth opportunities? And to the extent that you do see more opportunities, could you talk at a high level at the types of transmission opportunities that you see out there?

Yes, so we continue to have -- like I think I said last quarter -- there's well over 2000 projects that we're working on today. We have other projects out there that are waiting for capital, and we constantly are reviewing the capital situation that occurs.

If we wind up with bonus depreciation or other opportunities that we can advance capital. Actually in anticipation of the sale of River Ops, we started the transmission spend last quarter when we raised the transmission in anticipation of that so that we would not have the delay in terms of the earnings power of transmission associated with that.

So we are constantly looking at ways to do that. You're going to hear more about that at EEI.

And we will have more to say about -- and I think Brian was talking about the capital plans for the future -- we will have more to say about that.

Understood. Just thinking about, you had mentioned utility scale solar investments.

When you look across your territories and you think of the ability to actually invest capital versus enter into PPAs. Can you talk at a high level in terms of the regulatory landscape for the decision or preference between direct investment versus being off-taker?

We historically have been an off-taker of renewables. We have like over 2000 MW of wind power. I am a little tired of others taking credit for wind power.

When they would not exist without the PPAs that exist from AEP. We are going to be obviously much more outspoken about what we're doing relative to PPAs.

But also from an investment perspective, we believe for utility scale solar we should invest in that. Because it is a resource of the future and we have very good operations, maintenance, and project management expertise that we believe we have something to bring to the table in terms of efficiencies associated with that.

So when we talk to our regulatory jurisdictions remember our regulatory jurisdictions are sort of on the cusp of dealing with these kinds of situations. So for us when we file a resource plan you're going to see some portion natural gas, you're going to see utility scale solar, and you're going to see other grid-type efficiency technologies to put in place, whether its energy storage, whether its integrated volt VAR control, information system deployment, advanced metering. Those kinds of things will be key to our future. That's something that we are very focused on.

We have transmission. Transmission is a great opportunity for us because it's a large-scale system that needs refurbishments.

So is distribution. Distributional is a great opportunity for us. But even the buildout of distributed generation, particularly this type of utility scale -- we know where to place it on the system. It can be part of a resource plan that's filed with commissions. We are in the best position to build and own that type of generation.

Great. Thank you very much.

The other thing that we're doing is we are focused also on PPA arrangements with customers with -- directly with customers. And we've done that in some respects. With the Ohio State University, with Dennison University and others.

As long as we have a long -- again a long-term PPA to back up supply provisions for energy storage, for utility scale solar, for rooftop solar, we will do it. That's why I say AEP has a very firm foundation. We are not having to spend large amounts of capital on environmental equipment like we spent the $8.2 billion that Brian mentioned earlier. We're about done with that.

We have a real opportunity to advance this company in the future from a new age energy supply perspective.

Thanks very much.

Hugh Wynne, Bernstein Research

Good morning. I had a question about the AEP transmission HoldCo. You've had a very good result year-to-date since earnings up $0.07 off a 2015 base of $0.30.

The third quarter had a uncharacteristically poor result with sort of flat earnings year-over-year. I was wondering if you could perhaps explain a little bit what happened, if there are any implications for the future.

So we had a one-time blip there, Hugh, related to O&M. At ETT we had a cross-arm issue from some of the build out that we had to do there. We had to spend some dollars to address that physical issue.

We don't anticipate that to be a recurring item, and we believe it was a blip for the quarter and we will be able to get back on track for the end of the year.

Okay. And then if I could just quickly, following up on the prior question on the clean power plant. Is there a form of regulation or a structure of regulation that you're trying to push your states to consider? Or are you happy to work with states on their individual objectives, even if those are -- take materially different structures or regulatory approaches?

Yes, I think we are willing to work with the states on their own individual unique circumstances, and we will be working in that vein. What we are looking at is we would rather see, and this is sort of tentative for us because we're still looking at a mass-based approach, because that's more amicable to trading within states.

But we've got to have the state solutions before we really understand how important the trading aspects are going to be. We believe we are better off with a mass-based approach.

Is that a view that your other COs share, or is that subject to debate?

You'd have to talk to them. Their states may be in different places. I know California obviously is in a different place, and it will be unique to each individual region of the country, I believe. And really what kind of resources that you are transitioning from within the states as well.

I appreciate that insight. Thank you.

Paul Ridzon, KeyBanc

Thanks, most of my questions have been answered, but can you remind us what your indicative guidance for 2016 was?

$345 million to $385 million.

And any comment how you feel about where in that range things are looking?

We will be updating that at EEI in a couple weeks.

Given that I guess the decision of what to do with Ohio generation will be a big driver for 2016, how will you handle that in guidance.

Yes, that's why Brian said earlier that the forecast for 2016 and the guidance that we'll give in November will still include those generation resources. It's not an assumption that we're going to continue to own it. I want to be careful with that.

What it does say is that's what we know today. We will plan for 2016 with that assumption, and if something does happen first quarter or whenever a transaction is actually completed, then we will have to re-benchmark and adjust.

And you indicated you expect oil and gas to expand through 2016. Are there any particular regions that are driving that expansion?

It's all shale related, Paul, so it's Texas in particular. And then West Virginia and Ohio.

Keep in mind while the rig count is not going up the electric load is, and that's because there's a lot of consolidation that's occurring in efficiencies around compressor load that continues to get added. So you have to de-link what rig count is doing versus what the electric load itself is doing.

Basically we are behind the curve on the development of the infrastructure to move the gas out, and that's gong to continue through 2016.

That's right.

Okay, thank you very much.

Jon Fritze, Guggenheim Partners

Good morning. I know we'll touch on 2016 at EEI, but just under a scenario where you retain the approximate 3 gigawatts under a PPA, and you sell the remaining 5 gigawatts, does the scenario necessarily have to lend itself to dilution? Or do you have enough levers to pull of IE or 2000 + transmission projects or even buybacks to mitigate any type of a dilution opportunity?

I think you're sort of answering the question. And that is we have to understand what -- certainly what the proceeds would be. If there is dilution then there's all kinds of transactions that can be done to mitigate that.

But also from a share buyback and that kind of thing, you can make adjustments there as well. It's too difficult to answer at this point. There are just so many moving parts in that analysis. But we will certainly go through that process.

Got it. One last question, obviously we've got staff recs are out on the PPAs, and sort of when you look at what the recommendations are obviously what's the most contentious item? Is at the tenor of the PPA?

There were certainly some comments as far as the ROE. Is everything sort of up for negotiation?

I guess probably the most contentious is the PPA itself. The staff said we object to a PPA but it can work under certain provisions.

So if you get to the second door then it's probably tenor, and those types of things that would be discussed. Just like with a long-term wholesale provider that we provide you all the time. It's always price, tenor, and what the provisions are.

But I would say certainly on the former, getting the PPA addressed, and then secondly around tenor and then what's included.

Terrific. Thanks so much.

Andy Levi, Avon Capital Advisors

Good morning. Can you hear me?

Yes, I here you

Great. Just on the PPAs could you categorize the settlement talks that are going on?

Well I've said there was discussions going on. So we're obviously going through that process and talking about a lot of issues.

Really I can't say anything more at this time about that. I can tell you that we are discussing with several parties.

Great. Thank you.

And then on the potential asset sales, the generation. I guess there are two buckets, is kind of the way to look at it, that could become one bucket or be broken up into two buckets depending on the PPA.

Is it possible that the bucket that is not involved in the PPA gets moved before the PPA gets resolved?

I would say not likely. Because we're looking for an overall answer to this. Obviously if the PPA is not put in place then we have a larger amount of generation that we have to go through this process with.

So they will probably be answered at the same time.

And if you were to get a PPA on the first bucket, would it be possible that you would pursue a PPA for the second bucket?

Well that's an interesting question, but I think getting the PPA through and getting whatever units are included in a PPA -- I would say that the open units that aren't included in the PPA we are not going to assume that they are going to be brought back in at some later time. So besides, we really don't have the time for that.

Just regulatory wise, the only potential for a PPA at this stage is with what's been filed for, right? You would not be able to add MWs or assets to that to a settlement process could you?

Unless there's a settlement

So through a settlement it's possible to add MWs, for no better way to put it, I guess. Is that correct?

Then you'd wind up with a lot of additional discovery and that kind of stuff around that. So I'm just saying potentially it could be done. But it would open up perhaps another can of worms that we have to deal with.

Got it, Okay. Thank you, see you soon.

Operator, we have time for one more question.

Ali Agha, SunTrust

Thank you. Good morning.

I know that, Brian, you mentioned that on 2016 guidance you've assumed the sale of River Operations but you've kept the generation as is. Should we assume that that sale at least from a timing perspective is dilutive in 2016? Is that a fair assumption?

The sale of River Ops?

Yes.

No. So, Ali, let's just look at recent earnings history from that business.

Last year we earned $0.10. This year we were forecast to earn $0.08 for the year. In 2012 and 2013 we earned $0.02 per share from business. So I would not think of that is being dilutive for 2016

Okay. And then also, Brian, as you mentioned earlier, your current 4% to 6% growth is based off the midpoint of the original. As we look forward (technical difficulties) when you're looking at 4% to 6% you should use your original midpoint of 2015 guidance as you move things forward? Or conceptually how should we be thinking about what base to use for the 4% to 6% going forward?

We will lay out a framework for that. I need to stop talking about 2014 original guidance because of getting pretty far back in the rearview mirror now.

We will lay out that framework at EEI. It's -- our long-term anticipated growth rate is 4% to 6%. And we can normalize everything and take you through that discussion in more detail at EEI with some charts that we are putting together.

I got it. Last question, Nick, as you've look at the timeline on strategic issues on Mergent and the Ohio PPA, obviously things have moved as other events have gotten delayed.

Are you now at a point where you say, look we think this will happen by year-end and we've got 30 by early next year? But if regulatory processes continue to get shifted further, is early next year sort of cast in stone in your mind to finally dissolve the strategic issue on Mergent? Or would you still be flexible depending on how the PPA stuff is moving?

This thing has gone on long enough, and I think that we have to get on with making a decision and really our Board has been dealing with this for a year and a half, two years now as well.

It's very important that we get the answer that we need from the commission so that we understand what Ohio's policy is going to be in the future. So my view is that first quarter this coming year we will have an answer ready with the commission that we know, not so much whether it holds up in court or anything like that, but what the thinking is. And that's what's clearly important, is the way we address this process.

And to not be thinking about it for a long period of time or not hearing what people are thinking about it externally from a policy perspective, that is very important to us. So my view is our patience has sort of run thin here and we need to get on with it.

Just to clarify, so if the PPA rider discussion for whatever reason is continuing beyond Q1, you are not going to wait for that to continue beyond that. Is that fair?

I think that's fair. I think that's fair. I can't say that on January 29 or January 30 we think we are going to get an order on February 1 that we are going to pull the plug on January 30.

But we fully expect the commission to get done by year end, and then we will go about the process as quickly as we can to focus on what the future holds. I'm just saying that first quarter we will be -- we should be in a position where we move on.

Understood. Thank you.

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. Cynthia, would you please give the replay information?

Today's conference call will be available for replay after 11.15 AM today until midnight October 29.

(Operator instructions)

That does conclude your conference call for today.