American Electric Power Company, Inc. (AEP) Q3 2014 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. Welcome to the American Electric Power Third Quarter 2014 Earnings Call. [Operator Instructions] As a reminder, the call is being recorded. And now I'll turn the conference over to Ms. Bette Jo Rozsa. Please go ahead.

Thank you, John. Good morning, everyone, and welcome to the third quarter 2014 earnings webcast of American Electric Power. 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 Chief Executive Officer; and Brian Tierney, our Chief Financial Officer. We will take your questions following their remarks. I will now turn the call over to Nick.

Thanks, Bette Jo. Good morning, everyone, and thank you for joining us today on our third quarter 2014 earnings call. As I go through the story this quarter, I would say that, overall, it was actually an impressive quarter to come in at a respectable $1.01 per share and consistent with guidance given the headwinds of this being the sixth-mildest winter that we've had here in our service territory in 30 years and the intentional O&M advance spending that we described for you earlier in the year that we have continued. Our continued emphasis on regulated investments, particularly in the transmission area, that we then disciplined with advance spending from 2016 into 2014 and '15. And the focus on operating company performance continues to define the trajectory of consistent, dependable financial and operational performance. Keep in mind, we are in the middle of a multiyear plan to reposition our company, focused on infrastructure investments, particularly in the transmission and regulated utility lines of our business, improving our customer service through process and technology improvements, transforming our generation resources and defining an employee culture that enables the adaptability, flexibility and entrepreneurship that the future will demand. I would like to reiterate that this is a multiyear plan that began in 2013 focused on consistent earnings and dividend improvement. And we are still on target within the plan we laid out at EEI 2 years ago. We are taking advantage of opportunities around incremental transmission investments, advanced O&M spending made available from the first quarter performance and continue to drive efficiencies as we redefine processes through employee-led lean initiatives. All of these activities serve to mitigate the impacts of the, for lack of a better description, growing pains of dealing with the negative circumstances of the 2016 PJM capacity auction and Ohio deregulation-induced financial impacts. These mitigation activities have enabled the continued confirmation of our previous guidance ranges and growth rates for the 2014 to '16 period. There will no doubt be some growing pains, such as potential regulatory lag conditions or settlements that may reduce front-end revenues to accommodate longer-term business plan gains or the potential for mismatches between O&M efficiency gains and earnings test. These are examples of headwinds that may temper our earnings growth, but our investment strategy and the agility to compensate along the way continue to confirm our earnings trajectory. We will discuss this in more detail in November at the upcoming EEI Conference. I'm pleased to report that we are nearing the range for our 2014 guidance, the $3.40 to $3.50 per share from $3.35 to $3.55 per share as we tune in toward the end of the year. As I mentioned earlier, our GAAP and operating earnings for the quarter came in at $1.01 per share, and for the -- year-to-date earnings stand at $2.95 per share. This compares with third quarter 2013 GAAP earnings of $0.89 per share and $1.10 per share operating earnings. And year-to-date 2013 GAAP earnings were $2.33 per share and $2.63 operating earnings. AEP's Board of Directors also recently declared a dividend increase of $0.03 per share to $0.53 per share for the quarter, which represents a 6% annualized increase indicating their continued confidence in our business plan performance. Load growth in our service territory continues especially in the industrial sector, while there has been some commercial growth, and residential growth is still lagging. This segment will likely take time to recover and needs consistency with industrial and commercial growth. Both the industrial and commercial sectors have experienced several quarters of growth, so we'll be watching these metrics closely for trends. Brian will cover this subject in more detail in a few minutes. Briefly covering some of the regulatory activities that are ongoing, starting with the Ohio PPA filing that we made in October. This filing request approval from the PUCO to allow AEP Ohio to enter into a PPA arrangement with AEP Generation Resources for 100% of AEP Generation Resources share of several Ohio-based generating units, amounting to about 2,671 megawatts, and it's for the life of these units. This PPA would be separate but additional to the already requested OVEC generation through a PPA rider, which would be approved in the ESP 3 filing that is presently before the commission. These generating units represent about 1/3 of the Ohio-deregulated fleet. Placing these units in a PPA will preserve Ohio jobs, tax base, and more importantly, provide a hedge to Ohio customers to mitigate price increases in the future. We estimate that this PPA arrangement will save customers approximately $224 million over the next 10 years and will provide the stability of revenues to maintain and invest in these generating units, a true win-win. We already have PPA arrangements with other resources, such as renewables and energy efficiency. And the PPA rider is legal given that SB 221 allows for non-bypassable riders of this sort. AEP has asked for expedited approval by June 1 of next year. In our continued efforts to benefit our regulated jurisdictions with the transfer of Ohio-deregulated assets that were depended upon previously to satisfy capacity requirements through the AEP generation pool, we now have a settlement in West Virginia for the transfer of 100% of the 50% interest in the Mitchell plant into the rate base of Wheeling Power. This is a proposed settlement and subject to the UI [ph] commission approval. But it states that only 82.5% will go into rates initially with the other 17.5% going to rates no later than January 1, 2020. Until then, the 17.5% will essentially function in the deregulated market where the proceeds for capacity, energy and other services will accrue to the benefit of shareholders, much like off-system sales. There will also be an off-system sales sharing mechanism in place for the regulated 82.5% of generation as well as other provisions in the settlement as well. A hearing was held on October 21, and we await a commission decision. This is a good agreement in which taking a short-term risk with the 17.5% was worth the long-term benefits toward our regulated business plan. So before I go into the PJM market reform, and for that matter, the EPA Clean Power Plan, I'll now go to the equalizer chart, which usually is what I call it, on the next page. So as we go through the individual jurisdictions, and I'll sort of characterize this against last quarter as well, this thing tends to be a snapshot from quarter-to-quarter. And as you can probably see and have seen from the last quarter, the overall ROE has come down. This is the regulated entities, remember. So -- and most cases -- and I'm probably going to be redundant when I go through this is, is most of the impact that you see relative to lower ROEs is because of the advanced O&M spend that we had previously put in place, which we've continued to do because we did get ahead in the first quarter and were able to take on that additional expense, and also the unfavorable weather for the quarter. As I said earlier, it was one of the coolest summers we've had in decades. So in fact, in July, I think it was the coldest July we've had since 1979. So definitely, we've absorbed some things, and that's what driven down the ROEs in general for that period of time. Because of the unregulated generation revenues from the first quarter, the effective ROE would be, certainly be higher than that for the -- and above the 10%. So we have -- we've come along very well. We continue to make progress, and as I go through some of these jurisdictions, we'll talk about some of the issues going on. So starting with Ohio power. Last quarter, it was at 14%. And as we told you last time, it was heading down to get -- toward the SEET levels. And it continues to do that. It's at the 12.6% level this quarter, and we continue to make progress in that regard. As far as APCo is concerned, APCo is at 8.3%. And it was low last quarter as well at 8.5%. So there has been some weather-adjusted activities and O&M activities, but the main issue there is we have a West Virginia rate case that has been filed in that jurisdiction for $226 million. $45 million of that is a vegetation management rider, and the earned ROE for West Virginia is really where we have the issue. It's approximately 5.8% as filed in the rate case. So we have a lot of work to do in the West Virginia jurisdiction. Virginia, we believe, is certainly within the earnings collar that exists based on that legislation. So our issue there is West Virginia. We know that, and we're working on it. In Kentucky, the ROE is certainly -- continues to be a challenge, but there has been some improvement. It was 7.4%. It's up to 8.4% this quarter, primarily because of off-system sales. But obviously, we're in the process of working through to file a rate case at the end of 2014 that will reflect the full recovery of Mitchell. And that case is expected to be effective in July of 2015. So that's a work in progress as well. For I&M. I&M came down from 10.8% to 9.1%. And the biggest driver there was the 2014 earnings were much lower because of the unfavorable O&M and weather-related conditions. And then as far as PSO is concerned, PSO actually came down from 9.1% to 8.3%, again because of weather and the Western footprint. Weather was significantly off. And of course, a lot of the O&M spend also occurred at PSO as well. They also have a settlement of their rate case that's before the commission as well. And then, SWEPCO. SWEPCO will continue to be a challenge because of the portion of Turk that is not in a rate base yet, but we do have a supportive PFD from the Texas Commission at this point relative to transmission expense. And we continue to look for improvement there. But it'll take time to get the Turk portion worked out. Probably, it'll be some time -- it'll probably impact earnings in 2016 before we're able to go after resolution of that issue. And then as far as AEP Texas is concerned, they're still hanging out there at that 12.4%, and that really reflects the stranded cost issues that we've talked about, recovery issues we talked about earlier. And then the AEP Transco is doing very well. Transmission Holdco has returned, is at the 11.4%, which is in line with its authorized return. Now it's at 11.9%, so doing very well from a transmission perspective. So as we move forward, let me go ahead and cover the PJM market and the EPA Clean Power Plan. There's been much discussion regarding the PJM capacity market reform, particularly regarding the PJM capacity performance proposal and their demand resource white paper. As a general concept, we agree with the approaches, as we have said earlier, that adequate and consistent price signals need to be provided so that generation can be maintained and additional investment made. Regarding the capacity proposal, PJM is looking at placing some limitations on clearing price volatility, which would be a positive move. And progress appears to be -- been made with regard to the severity of the proposed penalty provisions. We disagree with PJM regarding the applicability of penalty provisions on FRR entities, such as our fully integrated regulated space, because they have resource responsibility. We are working with others to develop comments to these proposals before PJM files for FERC by December 1. Regarding the DR demand resource white paper proposals, the current thinking is that DR will participate on the demand side with the load-serving entities. So DR will realize the benefits from avoided costs and reserve requirements instead of direct payments from the auctions. However, FERC will need to provide direction on the DR issue as they respond to the DC Circuit Court order. So stay tuned as many of these capacity auction-related issues are addressed, but we believe significant auction issues are finally being discussed and expect improvements to be made. Our previously discussed AEP's thoughts regarding the EPA's proposed Clean Power Plan. Generally, the cornerstone assumptions are not realistic. The timetables are much too aggressive. And it's just too complicated for the states, markets and stakeholders to comprehend without a well-thought-out plan for development and execution. The EPA's proposed rules will generally require a fundamental change in the way the electric grid, capacity and energy markets and the state review and approval processes function. For those of us like myself, who grew up planning, building and running the power system of today, it is the backbone of everything we do in society. We happen to take the continued reliable operation of the power system seriously. I instructed my team here at AEP to run system planning and performance studies, typically known as load-flow studies, that engineers use to plan and confirm the reliable operation of the grid. And I asked them to assume the EPA 2020 cornerstone assumptions and add generation that's included in the PJM Q. The results of those studies found widespread occurrences of voltage degradation, collapse, and in fact, cascading outages of the electric grid. These results are even before any contingency outages, such as loss of generation or transmission facilities. The Southwest Power Pool ran their own studies and confirmed the same results for their region of the country, which we also serve. FERC should require NERC and the RTOs to perform these studies as they will no doubt confirm the same results. But proper technical analysis needs to be done as a part of the review of the EPA-proposed plan so that we can arrive at a rational result that enables progress from an environmental perspective with a more balanced set of resources, while at the same time preserving the reliable grid we have today. If you hear someone say the proposed plan is okay, they probably have not run a load-flow or stability study of the system and have either depended upon a market study or some other generalization. There is a better way to meet our environmental objectives by working together at commonsense solutions. The 2020 timetable requirements must be dropped and the states be given the flexibility to do the proper analysis to formulate plans. They -- this will provide not only operationally efficient results but also financially efficient results as we achieve the environmental solutions that we're asking our grid to perform through this transformation. AEP stands ready to engage in that dialogue. Now regarding the unregulated business. We continue to make progress to improve the value proposition of the business by focusing on cost containment, investment decisions reflecting market signals, pushing for capacity market design changes and working at the state level with PPA approaches. Additionally, we continue to work with our board regarding the available options to further shareholder value and define milestones and objectives regarding varying issues associated with this business. And we'll work -- continue to do that work in 2015. AEP will continue in defining itself as a regulated utility by providing consistent and quality dividends and earnings potential. Any decision and the timing of those decisions will be dictated by that focus. Now I'll turn it over to Brian.

Thank you, Nick, and good morning, everyone. On Slide 5. You will see our comparison of 2014 results to 2013 by segment for both the quarter and the year-to-date periods. As I did in July, I will focus my remarks primarily in the quarterly results. You can find the details for the year-to-date comparison in the appendix. Operating earnings for the third quarter were $493 million or $1.01 per share compared to the $1.10 per share or $533 million recorded last year. These results, when combined with the results through June, pushed our year-to-date earnings to $1.4 billion or $2.95 per share compared to $2.63 per share or $1.3 billion earned in 2013. Our year-to-date results remain strong compared to last year driven by weather-related sales combined with strong operations during this past winter. The third quarter dampened these results somewhat due to mild weather and increased O&M as a result of shifting in timing. On the positive side, we continue to see growth in earnings through rate changes and our Transmission Holdco segment where we expect to meet or exceed our original guidance of $0.29 per share by year end. With that as an overview, let me step you through the major earnings drivers by segment for the quarter on Slide 6. Third quarter earnings for the Vertically Integrated Utilities segment were $0.45 per share, down $0.11 from last year's results. Weather adversely affected the quarterly comparison by $0.05 per share due to mild temperatures across much of our service territory. O&M expense was higher than last year, which lowered the results for this segment by $0.10 per share. The higher O&M was due in part to improved incremental spending, including shifting costs from future years, primarily in our generation and wires functions. O&M was also impacted by an increase in employee-related costs and the effect of certain credits recorded in 2013. Depreciation expense was higher year-over-year due to increased capital investment. This lowered earnings by $0.03 per share. Positive comparisons to last year include rate changes, which added $0.02 for the quarter. This increase in rates is related to incremental investment to serve our customers. Normalized retail margins contributed $0.01 per share to the year-over-year growth, driven by increased sales in the industrial class, primarily offset by lower sales to the residential class. I will talk more about the loading economy in a few minutes. Despite lower wholesale power prices, off-system sales margin for this segment improved by $0.02 per share. Solid plant operations and lower margin sharing contributed to this result. Other items in total added $0.02 to the earnings for the quarter including lower interest expense and higher AFUDC. The Transmission & Distribution Utilities segment earned $0.19 per share for the quarter, $0.06 below 2013 results. Regulatory reserves adversely affected the quarterly comparison by $0.04 per share. A decline in normalized load and higher depreciation expense each impacted the quarterly comparison by $0.01 per share. In addition, other items in total were off $0.02 per share. On the positive side, rate changes related to new distribution investment in Ohio drove a favorable comparison of $0.02 per share. The Transmission Holdco segment continues to grow contributing $0.09 per share for the quarter, a $0.05 improvement, reflecting our continued significant capital spending in this area. In the past 12 months, the segment's net plant grew by approximately $1.1 billion, an increase of 83%. The Generation & Marketing segment produced solid earnings of $0.24 per share, adding $0.01 to the quarterly comparison. An improvement in gross margins due to lower fuel costs and favorable hedging was partially offset by higher maintenance expenses. AEP River Operations contributed $0.02 per share more than the 2013 results due to improved barge freight demand. In summary, despite the effects of mild weather on the quarter, we were still able to shift costs out of future years, and we remain well positioned within the revised guidance range of $3.40 to $3.50 per share. Let's take a look at Slide 7, where we can review normalized load trends for the quarter. Similar to last quarter, when I made comments about industrial and total load on this slide, my remarks will adjust for the impact of the Ormet load. As you may recall, Ormet, our largest industrial customer at the time, ceased operations in the fourth quarter of 2013. By adjusting for Ormet, you get a sense of how our industrial and total load is recovering in more of a going-forward basis since Ormet is not expected to return to production. In the charts, the numbers are presented with and without the effects of Ormet. On the bottom right of the slide, you can see that overall, weather-normalized load was up 1.1%. This is being driven by industrial load, which was up 4.8%. This marks the fourth consecutive quarter with positive growth in industrial sales. The company experienced growth in 8 of our top 10 sectors for the quarter and 9 of our top 10 for the year. The lone exception for the year is the mining, excluding oil and gas sector, which was down 3%. The quarterly sector leaders are Pipeline Transportation, up 33%; Oil and Gas Extraction, up 11%; Primary Metals, our largest sector, was up 9% for the quarter; and Chemical Manufacturing, our second-largest sector, was up 6%. We will talk more about the shale gas impacts on the economy of AEP service territory later. On the upper right of the slide, you can see that commercial sales were up 0.002% for the quarter and have experienced positive growth for the last 5 quarters. We feel confident that we will notch a positive annual comparison for the year for the first time since 2008. 5 of our 7 operating companies have experienced normalized commercial sales increases of 1% or greater through the first 9 months of the year, and we continue to see growth in the number of the commercial customers. Finally, in the upper left of the slide, you can see that residential sales were down 1.1% for the quarter. Even though residential sales have been down over the past 2 quarters, they are up year-to-date and are expected to be positive for the year. Turning to Slide 8. Let's review the recent economic for AEP service territory. Looking at estimated GDP growth for the quarter with recent updates, the economy for the U.S. is now growing faster than AEP's territory at 2.3% and 1.7%, respectively. On the upper-right side of the slide, you can see that economic growth in our western footprint continues to outpace the U.S. and our eastern service area, which trails U.S. growth by 0.006%. In the bottom-left quadrant, you can see that positive job growth in AEP service area trails that of the U.S. as a whole by 0.004%. Similar to GDP, job growth in AEP's western territories outpaces both the U.S. and AEP's eastern service areas. For AEP, we have experienced strong employment gains in the following sectors: natural resources and mining, construction, leisure and hospitality and manufacturing. With that segue, let's turn to Slide 9 to see how the U.S. shale gas developments impact AEP's industrial growth. As we've mentioned previously, we are seeing significant industrial load increases in the parts of our service territory that are located in major shale formations. AEP is fortunate to serve at least parts of 5 of the major 7 shale plays in the U.S., which according to the EIA account for over 95% of growth in domestic oil production and 100% of the growth in domestic natural gas production since 2011. For the quarter, industrial shales in the shale counties were up 28% compared to the 1% increase in nonshale counties. Over the past 4 years, we've seen an average increase of 31% over the prior year in our shale counties. This shale region growth is significant for AEP because 17% of our industrial sales are located in shale gas counties. The bottom chart shows industrial sales growth by major shale region. In our Eastern footprint, industrial sales are growing fastest in the Utica and Marcellus regions. In our Western footprint, we are growing fastest in the Permian and Woodford regions, while sales are down slightly in the Eagle Ford areas. Turning to Slide 10. Let's review the financial health of the company. Our debt-to-total capital has continued to improve and now stands at 53.4%. Our credit metrics, FFO interest coverage and FFO to debt remain solidly in the BBB and Baa1 range at 4.9x and 18.5%, respectively. Our qualified pension funding decreased 1% from last quarter and now stands at 99% funded. During the quarter, a modest decrease in plan liabilities from slightly higher interest rates was more than offset by plan asset declines. Finally, our liquidity stands at about $3 billion and is supported by our 2 revolving credit facilities that extend into the summers of 2016 and 2017. We are currently looking for opportunities to extend these tenors. We've worked hard over the last several years to achieve the financial strength demonstrated on this slide and believe we are well positioned for the future. Finally, turning to Slide 11. Let me preview some of the detail that we expect -- that we will be sharing with you at the EEI Fall Conference in a few weeks. Last year, we provide detail supporting the company's 4% to 6% operating earnings growth rate off of original 2013 guidance. This year, we will show you how we have been executing on our plan and delivering results that keep us in the ranges we provided you. You should expect an update about investment and growth opportunities available to our Transcos and transmission JVs as well as our regulated wires and integrated utilities companies. We will provide you with an update on the continuous improvement and lean initiatives that we outlined last year. You will recall that O&M discipline was a crucial component of filling the earnings gap presented by declining capacity revenues over the next few years. We will provide updates on our progress on these initiatives. Last year at EEI, we provided a lot of information designed to offer insight, transparency and credibility to our investment and 4% to 6% growth goals. We plan to update you on those details this year. At this time, we do not have any plans to make strategic announcements at the fall EEI Conference. With that, I will turn the call over to the operator for your questions.

[Operator Instructions] And first on the line, we have Dan Eggers from Credit Suisse. Daniel L. Eggers - Crédit Suisse AG, Research Division: Can we just talk a little bit more about kind of where O&M stands? Obviously, you've been able to monetize the good first quarter this year, but when you look at the plan and kind of the more lackluster weather this summer, how much O&M do you guys expect to pull forward from '15 and '16 into '14? And how should we think about that affecting kind of '15 and '16 inflation off the '14 numbers?

You saw our original plan is -- still is our plan, to move the $60 million that we discussed earlier into '14. So that was pretty much the extent of what we were capable of moving in from those years.

And Dan, we've completed about 30 of that so far year-to-date, with most of that 30 being in the third quarter. And we anticipate about another 30 in the fourth quarter of this year. Daniel L. Eggers - Crédit Suisse AG, Research Division: Okay. And then on the load growth conversation, you obviously -- the weather-normalized numbers as you show them the slides look pretty good, but the first quarter number still feels a little flaky, shall we say. What do you guys expect for kind of normalized load growth at this point in time? And what do you see swinging that as far as the industrial staying durable, I suppose?

Brian?

Yes, so Dan, we anticipate being the end of the year at about 7% -- 0.007% including Ormet and almost 2% if you exclude Ormet for the balance of the year. The thing that you'll notice in the quarterly results, and it's likely to be true in the next few years as well, is a preponderance of that growth is being felt in the industrial side. So when we traditionally think about load growth, we're thinking about it sort of more evenly spread across residential, commercial and industrial and recognizing we make more margin in the residential and commercial side than we do industrial. So while we're pleased in the growth that we're seeing, it's not in the part of the business that is higher margin for us, and we have that forecast going forward in '15 and '16 as well.

As a general rule, we -- I guess post-2008, we saw industrials come off, but the financials still held in there because the residential and commercials were late coming off as a result. So as the industrials were consistently going offline, I think it was like 17% reduction post-2008, and then -- but we were able to hold those financials. So now the reverse is sort of happening, where it's great that we're seeing the industrial increases that we're seeing on a consistent basis. But it's going to take time for the residential, and particularly the residential to catch up, because they need sustainability of industrial and commercial load growth for people to actually start relocating and moving out of the house and for the 20-year-olds and that kind of thing. So that's what we're looking for. So that -- it's good that we see the consistency. But, obviously, it's going to be a slow process. Daniel L. Eggers - Crédit Suisse AG, Research Division: I have just one last one, just on the Ohio generation conversation. Obviously, you have this request for late spring next year, but what markers should we be watching from the outside as far as when you think decision points could come up on the interim as to whether you're able to get a PPA done and maybe the sensitivities to what you're willing to do or not do in the negotiation process?

Yes. So there's sort of 3 markers there, but I'm not sure how each marker plays into the decision process because the first marker is clearly important. And that is the current ESP filing, the ESP 3 filing that contains the PPA for the OVEC generation, if the commission rejects that, then that's probably a pretty clear indication that the PPA process is pretty much going nowhere. But if they approve that, then there's the potential for subsequent approvals relative to FirstEnergy's request and then ultimately to our request. So that first milestone is critical. And then as we move forward into next year, and I think all of this is going to happen after the governor's election, we'll probably see before the end of the year our ESP 3 case. Hopefully, it will be resolved by the commission. And then subsequent to that, the other 2, including the FirstEnergy request, but our request as well, on the additional generation. So I think it's clearly important. It's important to the industrials, certain industrials. And it's also important from the stability of these resources that are located in Ohio. Right now, Ohio is short capacity, and it's just amazing to me that Ohio would be moving a policy direction that enables generation to be built out of state for import back into the state, particularly with the Utica Shale gas development. But this is where the policy decisions are made with the Ohio Commission. And we need to hear what the thought process is, and we're ready to go based upon whatever that outcome is.

Our next question is from Anthony Crowdell with Jefferies.

Two quick questions, one related to Ohio. And I believe with the OVEC filing, I thought the commission had to come up with a decision in, I believe, it was like 270 days. And I know, I think you've exceeded that. Have there been any filings on when a decision is coming out or maybe somebody saying it's past due? And the second question is related to FERC ROEs. And previously, you guys had a -- in one of your chart books, you showed how your ROE was kind of in the middle of the range. And with this downward pressure we've seen in transmission ROEs, does that push you guys more on the higher end and there's a risk that there's going to be downward pressure on your FERC ROE?

Okay, so first the Ohio issue. Yes, they're beyond the 270 days. But usually, we don't send past-due notices to the commission. So it's one of those things where I think the commission is going to have to thoughtfully go through this process. And it's a major, I mean, it's a major decision for them relative to the PPA approach. And I'm certainly hopeful that they're thoughtfully considering it and making sure that any order stands up to any type of legal type of challenge. We certainly believe it's legal. And in our filings, we certainly presented a case to that effect. And let's hope they do the right thing. As far as the transmission ROEs, yes, there is downward pressure on transmission ROEs, but they haven't affected us. We certainly have our projects and our TransCo ROEs that are in place. So from an overall sense, we're well within the bandwidth of reasonableness. So from our perspective, we're still in great shape. And I think even in the future, FERC seems to be really careful about ensuring that we continue to encourage transmission investment. And I would expect those ROEs to still encourage that and be the preferable place to put -- for us to put our money.

Just quickly a follow-up on Ohio. Do you think the delay -- obviously, you're not going to send a past-due notice. But do you think part of the delay maybe that you're waiting for a decision for the OVEC plan, but then you filed for the incremental plans? Is that causing some of the delay, you think? Or it's just really -- everyone seems really quiet in Ohio with the governor's election. Is it maybe related to that?

Yes. I think it's probably the latter of what you said. Because it is separate. It's a separate issue. But the commission has had our ESP filing for a while now. But I think for -- there's a lot of activity obviously around governor's elections in the state -- in any state. And this is a policy decision that needs to be made in a calm environment. And as we look forward to the policy decisions here, it's important for, certainly, the aspect of maintaining generation. But also it raises the question of what does the future mean for Ohio in terms of the building of new capacity within the state. And that probably -- the PPA is somewhat of a Band-Aid approach to maintaining existing generation. But you still have further issues to define within Ohio because clearly they were depending upon the PJM market construct to provide for that -- for capacity to be built, but that's not happening. So there'll be continued evolution of policymaking in Ohio relative to the energy picture.

Our next question is from Kit Konolige with BGC Partners.

Nick, in your discussion of the unregulated generation business, you discussed that you're, as you've said before, involved in assessing what the optimum approach is to enhance shareholder value. So I'm just wondering if a, you were saying anything different today with regards to timing when you talked about continuing to work in 2015? And b, how much the current proceedings on, at PJM regarding capacity performance and the DR issue and moving the demand curve, how much you want to see those completed or maybe the next auction completed before you go ahead and give us an idea of what you've decided to do with that segment?

Yes. So clearly, you're going to see some milestones here. Obviously, the Ohio PPA is one, and then the auction and what happens relative to that certainly will be another. But those are -- all those are particular areas that we're focusing on to enhance the value of our unregulated generation and provide the ability to continue for that business to be a bona fide operation in the future because clearly they need to be able to invest and maintain their facilities in the future. So it's sort of a no-regret strategy around maintaining and enhancing the value of that business. That, to me, is separate from the decision of what that -- what the disposition of that business is in the future. We still maintain that we're a regulated utility. We have to be able to take volatility out of the equation, particularly the capacity market volatility. And it has to be -- it has to look quasi-regulated. Now I don't think the time line of the decision process has changed at all. And we'll still be able to measure that business based upon the lack of volatility and the ability to invest in that business in the future and -- but clearly, we are looking for something that is either regulated, quasi-regulated. But at the end of the day, we will be a regulated utility.

So, I mean, not to press you too hard on this, but is there a way to describe what the timetable could be as you see it now on when you would have enough information about the policy environment to be able to determine whether it was close enough to a regulated that you'd want to retain it or make a decision whether to retain or to divest?

Yes. So the question that you started out with was relative to some of the milestones. And those near-term milestones are going to tell you a whole lot. But as far as actually getting into the decision, we are about focusing on infrastructure development, focusing on the development of transmission, focusing on certainly infrastructure that provides for improvement in the customer experience. And to the extent this particular business enables us to use it as a springboard to other focused areas that I just talked about, that's a positive thing. So we will determine the future of that business based upon not only the value it produces from a shareholder perspective but also what our other options are that we've described. So I don't think any -- nothing has changed relative to the process that we're going through. And, obviously, we're looking at the options relative to that business. And we'll continue to do that. 2015, I think in early 2015, particularly with the Ohio decision and the PJM capacity auction, will be particularly instructive. And I think it will probably be a fascinating 2015.

No doubt, okay. One other separate area. Can you give us a sense of how much -- let me put it this way, how much would the growth rate in load have to decrease before it impacted your earnings growth rate target?

Brian?

Kit, when we put those out a year ago, in the years '14 to '16, overall load was in the negative 0.005% to positive 0.005% range. We're seeing ourselves now clearly above that in year-to-date, but the mix is very much different from what we talked about. So that was the range that we used last year, was the negative 0.005% to positive 0.005%. And we'll be providing an update to that more specifically at EEI in a couple of weeks.

So you're referring to the difference in margin that you get from industrial versus residential?

Correct.

Our next question's from Paul Patterson with Glenrock Associates.

Just -- not to beat a dead horse here on the Ohio situation. But with respect to the independent market monitor, there's been some back and forth in the FirstEnergy case. And I noticed that they've intervened in your case. How should we think about the significance of that in terms of your case or how you feel about that?

Yes, I don't think it's completely unexpected. And I think that whenever -- there are going to be challenges based upon the process that we're going through. But the issue remains that SB 221 allows for the Ohio Commission to decide what resources are contained within a PPA approach. And it's very different than the obligation that was placed by legislation in places like Maryland and New Jersey. So a very different approach. And matter of fact -- I mean, you have multiple parties still participating with FRR. They can participate in the PJM market, but they still have regulated operating company requirements relative to generation resources. So it's difficult to make that argument that a FERC-regulated PPA is -- goes against a market construct. So certainly the independent monitor will have his opinion, and everyone else will have their opinions. But we believe we're doing the right thing.

Next, we'll go to Steven Fleishman with Wolfe Research.

Just, Nick, in your prepared remarks, you mentioned something about kind of hitting your growth rate, but also kind of dealing with growing pains. Could you just talk a little bit more about the growing pains, the regulatory lag and some of the things you mentioned there?

Yes. So overall, I'm just trying to make sure that people understand as we go through this process, we're moving -- we're trying to smooth out a huge hole that we had in 2016 and still provide consistent quality earnings and dividend growth for our investors through that period, regardless of what happens. And typically, when you do that -- and your questions like when you -- well, the Mitchell deal, for example. The Mitchell arrangement, the 17.5% that I talked about earlier, it'd have been great to get the whole thing transferred in and be able to recover all of that day 1. But for us, we felt like because we have ins and outs that are occurring throughout that entire cycle, we felt comfortable to go ahead and do that particular settlement, even though the larger benefits for us, and ultimately for the consumer as well, will be when we are able to transfer that other 17.5%, at least the financial side of that 17.5%, into a base rate. So it's those kinds of trade-offs that we're making all the time. And then as we do lean efficiency gains, we're also having to measure those types of things compared to what's going on in relative earnings tests in the various jurisdictions and those types of things. So we have to be -- it's sort of a -- we're pulling multiple levers through this entire process. And some things will go positive. Some things will go negative. But we're very comfortable with where we stand within the guidance range that we've given. And I think we're solidly within that guidance range going forward. So that's the point that I was making. I think there's -- we just don't want to have a lot of irrational exuberance that says that we're adding all the positives and not considering the negatives. This is our job, and this is what we do. And -- but we're very happy with where our guidance range is right now.

Okay, great. Second question is just on the dividend increase you guys announced earlier this week, the 6%.

Yes.

Could you maybe just give us a little sense on context that within your dividend policy? It is at the high end of your earnings growth range. Is that -- how should we just think about that, the overall dividend policy?

Yes. So, Steve, we had a 60% to 70% range that certainly we have espoused earlier for a couple of years now. And the board certainly is committed to that. And we felt like it was time to make a move that not only demonstrated our confidence in the business and the formulation and the guidance that we've given through the period, but also to make sure that we stayed within that 60% to 70%. And I think that it was important for us to make that move. And the context of it was centered around where we see the earnings in the future and where we see this business case developing. And the board felt confident about that approach.

Okay. And then just lastly, just how are you feeling about reliability next summer with all the plant shutdowns in your Eastern region? Obviously, a lot of those are your plants. Just how do you feel about reliability?

Yes. So -- this is probably a sore subject for me because as we look at the retirements that are occurring in 2015, if we do have a hard, hot summer or even worse, a cold winter in '15, we're going to have serious issues. And I think that -- I think it's going to be a challenge from a reliability perspective. So, hopefully, we'll have a milder summer and a milder winter, but I still believe there's 2 functions here. One is will the system actually operate the way it was intended to operate? And I think it's going to be on the ragged edge of its ability to do that. And then secondly, financially, what will it mean to customers? Because there will be shortages. There will be prices that -- already the Northeast is concerned about deliverability of natural gas because a lot like a pipeline capability, well, the same is true for the electric grid. And there will be areas where prices will be much higher than people anticipated. So I -- the more you take out of this grid, particularly on base load generation that provides 24/7 support, the more volatile it becomes both operationally and financially. Now I can sit here and say, as a company, from a financial perspective, as long as we operate with excellence, which is what we did during the last polar vortex, we'll be fine financially. But part of our role too is to think about our customers. And while I'm certainly sensitive to 2015 and concerned about 2015, we won't know until we get there.

Our next question is from Mike Lapides with Goldman Sachs.

This may be a Brian question. Brian, you were talking about demand and how industrial demand is really what's driving the year-over-year growth and that the margins on industrial are obviously less than res or commercial. Can you quantify that for us? Like you've given 3-year guidance, roughly on a EPS basis, what's the sensitivity to every 1% change in demand for each of the customer classes?

I don't have that for you, Michael. We'll be able to have that at the EEI Conference. But I think a 0.5% overall evenly distributed was a $0.05 move EPS annually.

Okay. And so kind of back of the envelope, if that 0.5% is being driven largely by industrial, you'd kind of think that -- that assumes it's -- the 0.5% is evenly distributed, but what you're seeing isn't necessarily that?

That's the point we're making.

Okay. One other question, balance sheet. Balance sheet has gotten much healthier, congrats on that, over the last couple of years. When you look forward, do you see a time in the next 2 to 3 years where your balance sheet, kind of heaven forbid, is even too healthy? And how do you define what your long-term goal is for the balance sheet?

Yes. So Michael, we've been getting some of those questions. And I think the idea is what do we do with that balance sheet capacity. And I think you've seen as we have increasingly shifted our spend to the wires side of the business. So you saw before we started 2014, something like 69% of the spend, '14 to '16, was going to wires pieces of our business and increasingly more of that to the transmission side where we had the lowered regulatory lag and the higher ROE. So if you look for us to consume some of that balance sheet capacity that you talked about, I'm inclined to think that you would see that trend continuing. As Lisa and her side of the business in transmission seems to have an insatiable appetite for capital that can return that 11.49% to 11.2% ROE range with very, very little lag. So that's part of the challenge that the management team is working on, is how do we grow the company in the ranges that we've talked about? How do we overcome some of the revenue gaps that Nick talked about associated with capacity? And in addition to growth, how do we continue to reward our shareholders in the form of a dividend? And we need to make sure that we balance all of those shareholder interests equally, and that's what we're struggling with. And that's what we'll provide what I hope are positive updates for investors at the EEI Conference.

I think it's an important question, too. We get a lot from an M&A perspective and everything like that. And while obviously the patent answer to any M&A question is we can't talk about it. But we can talk about the way we think about investments and the use of our balance sheet. And, actually, we just look at it as uses and sources. And one source is our healthy balance sheet to be able to invest more in our business. But probably the more important question is what are you investing in? And we want to make absolutely sure that we're investing in those types of investments that will produce the quality returns, the continuity and consistency and the concurrence of a recovery of investment that things like transmission provide. And that's our measure, that's our -- that's our measuring stick. And that's the litmus test for how we invest. So we're well aware of where our balance sheet stands, but we're always looking at credible options for -- to enhance shareholder value.

I guess, one last one. We've seen this in the wireline telecom business this year. There's been a little discussion in the power and utility business as well. Everybody loves to ask the question about what are going to do with the generation business. And I want to ask a little bit of that same question, but really for the transmission business, a high-growth business, high-return business, in terms of do you think that's adequately reflected in the share price? And -- or do you think there are alternative corporate structures that may enable investors to kind of price that in correctly? And how do you go about the process of looking at that?

I would say it this way, and Brian can certainly add on to this. But you look at REITs or yield cos and all those types of structures, and there's rewards associated with each one of them, particularly in a business that is central to AEP, and certainly one that we continue to invest in. So I think -- I'd rather see AEP emerge as trading more like a fully regulated and transmission-oriented utility. And that to me is where we're at in the process at this point.

Michael, we've gotten those questions before, and instead of just saying, "Oh, we're not going to look at those things," we've looked very hard at them with our advisers and tax experts and the like and have come up with the concept that from a REIT standpoint, in particular, we took a really hard look at. A lot of what we've done on the Transco formation is get those Transcos approved at each of the utilities where we operate. And because the REIT would own the transmission assets, we would have to go about and get them certified at each of the states where we do business because they'd be utility asset owners. And then to take advantage of the tax implications of the REIT, we would have to sell a portion of that REIT off. We'd have to spin it because we wouldn't get the tax advantage under a parent environment. And then we'd have to likely come up with some split by which we would share those tax benefits. So the complexities are pretty immense. And we'd want to make sure that the benefits are sustainable and that proposed tax law changes and the like wouldn't make all that hard work and complexity that we'd go to transitory and fleeting. So in the meantime, the REIT is something we've looked very hard at, and it doesn't work for us. And then on a yield co, the size and scale of where we're at doesn't work now as well. So there are structures that we'll continue to look at and look at them hard. But to date, we've found that, as Nick said, keeping those businesses under an AEP umbrella are very beneficial to our shareholders.

Michael, I think you can probably appreciate this and some others on the call that we remain focused on answering this unregulated generation question. So that is something that we're focused on at this point. And as far as the timing of transmission, we can continue to invest in transmission, notwithstanding these other structural components. But the clear issue for us is to get on with this unregulated generation decision.

That'll be from Greg Gordon with ISI Group.

So perhaps you won't answer this, Brian. But you talked about the growth rate, 4% to 6%. You've obviously been asked about that ad nauseam a bunch of different ways. You're going to give us an update at EEI. But when you gave that, initially you said it was based off a midpoint of $3.05 to $3.25 for '13, which you then -- you gave a guidance range for '14 of $3.20 to $3.40. You updated that to $3.35 to $3.55 after the first quarter. Now you're at $3.40 to $3.50. 2013 seems to me quite a stale base year to be basing a growth rate off of. Should we assume that you're going to give us an update on the growth rate off of '14, or perhaps '15, on what you've earned as a base year? Or how should we think about that?

So I agree with you, Greg. I think looking back to original guidance for 2013 is getting pretty stale here towards the end of 2014. So we are going to update how we look going forward, what the growth rate looks like. I'm inclined to think we're not going to add another year of specific earnings guidance at the end. We've gone 2014, '15, '16. I don't think we're going to show specific guidance, '17, '18. But we are going to talk about the growth rate at EEI.

So it sounds like the gross rate isn't going to change demonstrably, but the base year will be refreshed?

We just need to -- I mean, I don't want to be here in 2015 talking about original guidance for 2013. So we need to get off that and start talking about more what we look like going forward. And we'll be able to do that in a credible way at EEI.

Okay. 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. John, can you give the replay information?

Certainly, and ladies and gentlemen, this conference is available for replay. It starts at 11:15 a.m. Eastern time, will last until October 30 at midnight. You may access the replay at any time by dialing (800) 475-6701 or (320) 365-3844. The access code is 338687. That does conclude your conference for today. Thank you for your participation. You may now disconnect.