Nicholas Akins - Chairman, President, Chief Executive Officer Brian Tierney - Executive Vice President, Chief Financial Officer Betty Jo Rozsa - Managing Director, Investor Relations

Greg Gordon - Evercore ISI Jonathan Arnold - Deutsche Bank Steve Fleishman - Wolfe Research Julien Dumoulin-Smith - Merrill Lynch Praful Mehta - Citigroup Christopher Turnure - JP Morgan Ali Agha - SunTrust Stephen Byrd - Morgan Stanley

Ladies and gentlemen, thank you for standing by, and welcome to the American Electric Power Fourth Quarter 2017 Earnings conference call. At this time, all participants are in a listen-only mode, and later we will conduct a question and answer session. Instructions will be given at that time. If you should require assistance during today’s call, please press star followed by zero. An operator will assist you offline. As a reminder, your conference is being recorded today. I will now turn the conference call over to your host, Ms. Betty Jo Rozsa. Please go ahead.

Thank you, Tawanda. Good morning everyone and welcome to the fourth quarter 2017 earnings call for American Electric Power. Thank you for taking the time to join us today. Our earnings release, presentation slides, and related financial information are available on our website at aep.com. Today we will be making forward-looking statements during the call. There are many factors that may cause these results to differ materially from these statements. Please refer to our SEC filings for a discussion of these factors. Our presentation also includes references to non-GAAP financial information. Please refer to the reconciliation of the applicable GAAP measures provided in the appendix of today’s presentation. Joining me this morning for opening remarks are Nick Akins, our Chairman, President and Chief Executive Officer, and Brian Tierney, our Chief Financial Officer. We will take your questions following their remarks. I will now turn the call over to Nick.

Thanks Betty Jo. Good morning everyone and thank you for joining us today for AEP’s fourth quarter 2017 earnings call. I know many of you are happy to get 2017 in the rear view mirror and move onto 2018, but I would say that we ended 2017 very strong. I mentioned in the third quarter earnings call for those who watch Game of Thrones, Khaleesi’s dragons didn’t show up for the heat of the summer but we definitely spent the beginning of winter at the North Wall of the White Walkers - it was really cold. As a matter of fact, one of my family members had the great idea that I could barbecue chicken wings on New Year’s Day for the football games, so I was outside in 10 degree weather grilling wings. I don’t think I’ll do that again. But all in all, though I was cold outside as a shareholder, I was warm inside as we sold a lot of comfort to our customers during this cold spell. So starting with our financial performance for the fourth quarter, we came in with GAAP earnings at $0.81 per share versus $0.76 per share in 2016, and operating earnings at $0.85 per share and $0.67 per share in 2016. This brought the 2017 year-to-date total GAAP earnings to $3.89 per share versus $1.24 per share in 2016, and 2017 year-to-date total operating earnings to $3.68 per share versus $3.94 per share in 2016. The $3.68 per share for 2017 landed at the top end of our revised guidance, so we ended in very good fashion leading into 2018, and looking at AEP’s total shareholder return, we have consistently over the last one, three and five-year periods provided comparable returns to the S&P 500 and consistently outperformed by a wide margin the S&P 500 electric utilities index, the very definition of a premium regulated utility company. Our regulated operating ROE came in at 9.5% return for the year, and in 2017 we increased the quarterly dividend by 5.1%, so even with the headwinds of weather and the need for rate case recovery, AEP provided a very respectable year to our investors while providing quality service to our customers. Our employees continue to drive efficiencies across our business, which certainly played a significant role in meeting shareholder expectations in 2017. We dealt with major storm events with Hurricane Harvey, which was a direct hit to our AEP Texas territory, as well as provided support in Florida as a result of Hurricane Irma. We currently have AEP employees in devastated Puerto Rico helping with the recovery and rebuilding efforts there as well and certainly wish them a safe return. For 2018, we are maintaining our guidance range for the year of $3.75 to $3.95 per share and reaffirming our growth rate of 5 to 7% operating earnings. We will be investing $6 billion in capital substantially in the regulated entities, with the vast majority of that being wires related to provide reliability and quality of service to our customers. Disciplined execution and capital allocation will be key for us to meet our financial objectives. Obviously the rate case outcomes in the various jurisdictions that I will discuss later will be a key component of these allocation decisions. I was recently asked what song would be a good one to pick for this quarter to illustrate the quarter, and it has to be Taxman by the Beatles. Tax reform has definitely been at the forefront, taking center stage. As we adjust the outcome of tax reform, our focus is no different - allocation of capital, maintaining credit quality, and ensuring our consistent growth trajectory. In this case, we are also working with our state commissions to provide tax reform benefits to our customers as well, whether it be rate reductions, accelerated depreciation, additional capital projects that provide value to our customers, or other opportunities. We also, because of our strong credit metrics, are able to maintain a significant portion of our capital investment plans while not issuing any additional equity beyond what we provided at the last EEI financial conference. Brian will discuss this a little bit later. As you know, we have several rate cases that were filed in 2017 that we expect outcomes generally in early 2018. Rate case filings were made in Indiana, Michigan, Kentucky, Oklahoma and Texas, and we still have an outstanding ESP case in Ohio that we await the outcome as well. Additionally, as you all know, we’ve filed for state regulatory approvals for the Wind Catcher project in Oklahoma, Texas, Louisiana and Arkansas. First regarding Wind Catcher, I’m very pleased with the cases our teams are putting forward in all the jurisdictions. Sure, investors in opposition do what interveners do, but overall our regulatory teams have demonstrated the benefits of the project. The schedules in the various jurisdictions continue to be largely on path to complete in a timely basis for approvals. We are having settlement discussions where they can occur, and we’ll continue to do so where appropriate. Wind Catcher is a very unique opportunity, and our willingness to take on risk associated with this project while also providing all the benefits to the customers is a testament that we really are trying to do something good for customers. AEP is advancing this project because we believe strongly in the benefits it will provide Day 1 to our customers, our environment, and to the economies of the states involved. Because we provide such a critical service to our customers and communities we serve, AEP has a public trust to balance the needs of our investors with our customers and our other stakeholders. We are in a very critical time in the life of this project, and this is where AEP, our customers and our regulators need to make this happen. In my mind, it would be an absolute travesty to let this unique hedge against the market pass, and I remain confident that it will get done. All the rate cases continue to move forward. Commission orders have been received in Texas and Kentucky that were generally constructive, and we await orders in Indiana, Michigan and Oklahoma as well as the ESP case in Ohio. All the cases are moving according to plan, and the next couple of quarters will certainly answer many rate-related and ROE questions in these jurisdictions. We are certainly hopeful that the Oklahoma commission will revise the ALJ’s recommendation in the rate case to send a message that Oklahoma is truly open for business and allow AEP to continue to make substantial investments in the energy infrastructure in that state. As we have explained previously, we have the best customer satisfaction, the best service quality and the lowest rates. We just need to be able to attract a fair return on our investments in Oklahoma. After our previous disappointing rate case and a disappointing ALJ recommendation on our current case, we are hopeful that the Oklahoma commission will arrest this negative trend. With an authorized ROE of 9.5% but actually only recovering a 6% ROE, and if the ALJ recommendation has approved in its presence form only a 5% ROE, these results would be unattractive given AEP’s other investment opportunities. Now that PSO is on negative credit outlook by Moody’s, a positive result is even more important. So now I’ll move to the equalizer graph and explain some of the cases that we have ongoing. First of all, overall we’ve continued to have a 9.5% ROE, and over the 12-month period we have had some delays during the year that moved into ’18, and certainly weather has impacted ’17 as well overall. You’ll hear that in many of the cases going across the equalizer graph. So for AEP Ohio, the ROE for AEP Ohio at the end of fourth quarter 2017 was 14.2%, but you have to keep in mind that that 14.2% includes the legacy issues that were resolved from the global settlements that had been done earlier, so really when you look at the seed-adjusted ROE, we’re right around 10% in AEP Ohio, so we’re in a good place there. Those legacy issues will roll off over time - some roll off in ’18, some roll off in ’19, so you’ll start to see those two bubbles come closer together and in fact become the same bubble as we move forward. As far as APCo is concerned, the ROE for APCo at the end of the fourth quarter was 8.9%, which it was 8.4% at the end of the third quarter, so they are making progress; but again, it reflects weather for the entire year. They’re overall at a good place right now. Kentucky Power, we obviously--that was a work in progress last year. It was 4.5% ROE at the end of third quarter, 5.1%, so it’s moving up a little bit. It should move up even more now given that we have an outcome of a rate case. That rate case, the final order approved a $12.4 million increase, and it was--the settlement was actually adjusted there for certainly the impacts of tax reform. So all in all, constructive outcome from that perspective. Long-term solution for Kentucky Power, though, will again--the rates was only a part of it. The other is the economic development that’s occurring in those regions, and we are getting some positive progress there relative placements of large manufacturing in our territories, so that’s a good outcome, and we expect that to continue to improve. I&M achieved an ROE of 8.4% at the end of the fourth quarter 2017, which is unchanged from third quarter. Again, you probably know we have Indiana case and our Michigan case, both rate cases filed in those jurisdictions, and would expect an outcome of those in the next couple of quarters. So those cases move forward and certainly that should help to improve I&M. As far as PSO is concerned, we’ve already talked about that pretty extensively at this point. Their fourth quarter ROE was 6.2% versus 6.1% at the end of the third quarter, and of course we’re looking for the Oklahoma commission to adjust the recommendations of the ALJ at this point and hopefully have a good outcome associated with that rate case, which we expect an order very soon. That will certainly bode well for the continuation of Wind Catcher, and certainly that case continues to move forward in Oklahoma as well, so a lot of cases coming in and Oklahoma is at the epicenter of the activity associated with investments that we’re making. SWEPCO, ROE at SWEPCO at the end of the fourth quarter was 6.4%, at the end of the third quarter it was 5.9%. We did get a final order on the PUCT case, Public Utility Commission of Texas, that was constructive, so we expect that ROE to continue to improve as well. Just keep in mind, we still have that 88 megawatts of Turk hanging out there that will continue to be a slight drag to the ROE overall of SWEPCO. So as we look at AEP Texas, AEP Texas at the end of fourth quarter 2017 was 10%, and it was 10.3% last quarter, and AEP Texas decreased due to a tax refund that dropped out of the calculation that was taking place in there. Of course, AEP Transmission, the ROE for AEP Transmission holdco at the end of fourth quarter was 12.6%. It was 12.7% at the end of third quarter 2017, so fairly consistent, and we continue to see great things from AEP Transmission and we expect that to continue. So overall, regulated operations at 9.5% and we’ll continue to see--all those, as we’ve discussed with you earlier, gives you a very good view of the ones that need to move up and those that are in the middle of rate cases, and we expect those outcomes in the next couple of quarters, so that will be very instructive to us going forward relative to where we put our investments. So for fourth quarter ’17, it was an outstanding quarter, and the year’s results exemplify the resiliency and the commitment of AEP’s employees to deliver consistent earnings and dividend quality, regardless of the headwinds that may exist. We’re very proud of 2017, and as we move into 2018, the year of tax reform, Wind Catcher, rate cases, and also forging ahead with Smart Cities, Ohio’s PowerForward project, and other forward-thinking initiatives, this will set the tone for the years to come. I’ll turn it over to Brian at this point. Brian?

Thank you, Nick, and good morning everyone. I’ll take us through the fourth quarter and year-to-date financial results, provide some insight on load and the economy, review our balance sheet and liquidity, discuss tax reform, and finish with a review of our outlook for 2018. Let’s begin on Slide 7, which shows that operating earnings for the fourth quarter were $0.85 per share or $420 million, compared to $0.67 per share or $330 million in 2016. All of our regulated segments experienced growth for the quarter compared to last year, and as expected our competitive generation and marketing business was down due to last year’s asset sales. All the detail by segment is shown in the boxes on the chart, but overall the growth in our regulated business was driven by lower O&M, return on incremental investment, and positive weather impacts all partially offset by a higher effective tax rate. The generation and marketing segment produced earnings of $0.05 per share, down a nickel from last year. The impact of the sale of the competitive assets was partially offset by lower operating expenses on the remaining assets and higher trading revenues. Corporate and other was up $0.05 per share from last year primarily due to lower O&M and favorable tax adjustments. Turning to Slide 8, our annual operating earnings for 2017 were $3.68 per share or $1.8 billion, compared to $3.94 per share or $1.9 billion in 2016. This difference can be primarily attributed to unfavorable weather, the sale of the competitive generation assets, and positive items that occurred last year that were not repeated this year. Offsetting these were lower O&M, higher transmission earnings, and recovery of incremental investment to serve our customers. Looking at the drivers by segment, earnings for the vertically integrated utilities were $1.64 per share, down $0.37 with one of the largest drivers being weather, which had a negative impact of $0.18. This difference was driven by the warm summer in 2016 which increased our cooling load compared to the warm winter in 2017, which decreased our heating load. Favorable prior year items also contributed to this difference, including formula rate true-ups, recognition of deferred billing in West Virginia, and positive tax adjustments. Other rate relief was favorable due to the recovery of incremental investment across multiple jurisdictions, and we reduced O&M in response to the unfavorable weather in 2017. Additional variances in this segment include higher depreciation and taxes other than income taxes, along with lower AFUDC. The transmission and distribution utilities segment earned $1.01 per share, up $0.06. Favorable drivers in this segment included rate changes, higher ERCOT transmission revenue, the prior year Ohio global settlement, and lower O&M. These were offset by several items, including lower normalized load, the reversal of a regulatory provision in 2016, and higher depreciation and taxes. The AEP Transmission holdco segment earned $0.72 per share, up $0.18 over 2016. The growth in earnings over last year largely reflected our return on incremental investment. Net plant less deferred taxes grew by $2.1 billion, an increase of 52% since last December. The growth in earnings also reflected the implementation of the FERC 205 forecasted transmission rates as well as the normal historical expense true-up. Finally, we experienced a slight decline in our joint venture earnings due to an ETT settlement in 2017. Generation and marketing produced earnings of $0.30 per share, down $0.20 from last year. This segment realized lower earnings due to the sale of assets. Partially offsetting this impact were lower depreciation on the remaining assets, positive impacts from solar projects going into service, higher trading revenues, lower taxes, and lower overall costs. Finally, corporate and other was up $0.07 per share from last year due to investment gains, lower O&M, and taxes. 2017 was a re-basing year following the sale of the competitive generation assets. We are pleased with our operating earnings for the year which were achieved despite the headwinds from very mild weather. Now let’s take a look at Slide 9 to review weather-normalized load. Starting with the lower right chart, our normalized retail sales increased by 1.6% this quarter and ended the year up three-tenths of a percent. It has taken some time, but we finally saw the growth in residential sales we expected following the steady expansion of industrial sales that started last spring, particularly in the west. Moving clockwise, industrial sales increased by 5.6% for the quarter and ended the year up 2.8%. There were two reasons for this increase. First, we saw broad industrial sales growth across most of our operating companies and industries this quarter. In fact, our five largest industrial sectors experienced nearly 11% growth this quarter, led by chemicals and primary metals. Second, in the fourth quarter two large co-generators on our system took their units offline for routine maintenance and purchased their needs from us. Moving to the upper left chart, normalized residential sales were up two-tenths of a percent for the quarter and down 1.2% for the year. The story here differs by geography. Residential sales were up 1.8% in our western footprint where customer counts increased by seven-tenths of a percent in the fourth quarter. In the east, however, residential sales declined by nine-tenths of a percent despite the three-tenths of a percent increase in customer counts. Finally in the upper right chart, commercial sales for the quarter decreased by 1.2%, bringing the year-to-date normalized contraction to eight-tenths of a percent. Commercial sales declined at every operating company in 2017 except AEP Texas, with the most pronounced drop in Appalachian and Kentucky Power. Despite this, we still expect a modest improvement in 2018 as the economic recovery works its way through the business cycle. Next, let’s review the status of our regional economies on Slide 10. As shown in the upper left chart, GDP growth in AEP service territory exceeded the U.S. by nearly seven-tenths of a percent in the fourth quarter. Higher energy prices and the strong global economy in 2017 were the primary drivers for this improvement. For the quarter, the western footprint grew at 3.4% with the growth in our eastern territory following close behind at 3.3%. The bottom left chart shows the gap in employment growth is closing between AEP and the U.S. Once again, the strongest job growth occurred in our western territory at 1.3%, which was only a tenth of a percent behind the U.S. Employment growth in our eastern territory closely followed at 1.1%. The final chart to the right shows the net jobs created in AEP service territory in 2017 by sector. In total, there were approximately 87,000 more people working in AEP’s footprint at the end of 2017 than at the start of the year. Over 60% of the new jobs added in 2017 came from three categories: education and health services, professional business services, and manufacturing. These categories typically represent higher wage jobs which should support residential sales growth in 2018. The exception was the retail sector, which lost nearly 5,500 jobs in 2017. As you know, more people are choosing to shop online as opposed to traditional big box stores. Despite this outlier, we are encouraged by the momentum of economic trends in our service territory and still expect modest growth in 2018. Now let’s move to Slide 11 and review the company’s capitalization and liquidity. Our debt to total capital ratio increased nine-tenths of a percent during the quarter to 55.5%. Our FFO to debt ratio was solidly in the Baa1 range at 18.7%, and our net liquidity stood at about $2.3 billion supported by our revolving credit facility. Our qualified pension funding improved approximately one percentage point to 101%. Despite a lower discount rate, gains from plan assets outpaced an increase in the plan liability due to strong market returns. Our OPAB funding improved 18 percentage points during the quarter to 130% primarily due to strong investment returns and a change in the medical coverage for post-65 retirees. This change lowered the estimated OPAB liability and annual expense. The estimated cost for both plants in 2018 is expected to reduce after-tax expense by $53 million. Let’s turn to Slide 12 now and talk about tax reform. Remember back two years ago when bonus depreciation was extended. At that time, we were getting increased cash due to not having to pay cash taxes. In response, the company did what Congress had hoped it would do and increased our capital expenditures for the benefit of our customers. This increase in capex had the effect of offsetting increased ADIT balances, so the story that we talked about then was lower cash taxes, increased retained cash, increased capex, increased customer benefits, and steady growth rate. In contrast to that story, let’s talk about what tax reform and the elimination of bonus depreciation means to AEP - lower taxes, lower cash metrics, but also reduced ADIT balances, so if we largely maintain our capital spending program for the benefit of customers in the face of lower cash metrics, then we can maintain our previously forecasted growth rates. That is exactly what we plan to do. We plan to maintain our capital spending forecast of approximately $6 billion in 2018 and $6.2 billion in 2019, and to reduce our 2020 capital spending forecast by $500 million to about $5.5 billion. Our credit metrics will move from the high end of the Baa1 range to the lower end, but we do not anticipate raising incremental equity due to tax reform. We still anticipate raising $100 million through equity programs in each year 2018 through 2020, and an additional $400 million in 2020. This represents no change in equity needs from what we discussed with you at EEI in November, and we are reaffirming our 5 to 7% growth rate. Finally, as was the case at EEI in November, this plan does not include Wind Catcher. Two other questions we often get are related to the deductibility of interest on parent debt and whether or not we have a significant net operating loss carry-forward. We expect interest on our parent debt to be mostly tax deductible and we are going into 2018 without a significant net NOL. Most of our state commissions have already opened documents related to changes in the tax law. We have begun working with regulators to determine the appropriate mechanisms to provide the customer benefits of both the change in tax rate and the excess ADIT. We have several options, including decreasing rates, increasing the amortization of regulatory assets, accelerating depreciation, and offsetting other rate increases. Overall, we’ll maintain our credit metrics in the Baa1 range and stay within our earnings growth rate of 5 to 7% while customers get the benefit of continued investment and lower taxes. Let’s try to wrap this up on Slide 13 so we can get to your questions. We begin 2018 with a solid track record. Regulated earnings were strong in 2017 as we continue to invest capital in our regulated businesses. For seven years now, we have maintained O&M discipline and kept spending in a tight range of between $2.8 billion and $3.1 billion. In addition, over time we have grown our dividend with earnings, and expect to be able to do so going forward. Last year, AEP’s board of directors increased the quarterly dividend by 5.1% on an annual basis. Looking ahead to 2018, we are reiterating our operating earnings guidance of $3.75 to $3.95 per share. We are also confident that there is significant runway in our capital programs to reaffirm our 5 to 7% operating earnings growth rate. We will finalize our pending rate cases, obtain clarity on the Wind Catcher project, and continue working with regulators to provide the best solution around the customer benefits of tax reform. With that, I will turn the call over to the Operator for your questions.

[Operator instructions] Our first question will come from the line of Greg Gordon with Evercore. Your line is open.

Hey Greg, how are you?

Oh, I can’t complain. It’s still cold here, but we know that’s good for demand, so I’ll take it.

That’s good.

Brian, a couple questions for you. First, I was modestly distracted when you mentioned that you’re making a reduction in expenses due to change in benefit costs. That was a prospective savings of how much?

It’s going to be a credit for us to costs of about $53 million.

Okay, thank you. Then you said parent interest expense would be mostly tax deductible, which means it’s not completely tax deductible. Can you elaborate on why you chose that language?

Yes Greg, so the IRS hasn’t written their rules yet, but we think what’s allowed for in the tax law is that parent company interest expense can be allocated to both our regulated properties and to our competitive businesses. In the regulated properties, they will be fully deductible; in our competitive properties, we’ll have significant EBITDA to be able to deduct that as well. What will be left behind will be a very small portion which will be allocable to the parent, which doesn’t have EBITDA associated with it, and that’s the small portion that we think will not be deductible.

Can you quantify for us at this time a range of dollars in terms of debt that you think will not qualify?

About $1 million tax affected.

Okay, so which really is de minimis.

I couldn’t say zero and be fully forthcoming. There is a small part that’s left.

Fair enough now you’ve disclosed it - thank you. Did you say that the major factor that drove industrial demand up in the fourth quarter was these two co-gen facilities shutting down and taking demand from you, and so that’s why you don’t consider that an ongoing trajectory of demand?

No, that was a small portion of it. We think the larger portion of it was really the broad growth across most of our industrial sectors.

So why are you sort of reverting to a very low expected demand growth forecast in 2018? Is that out of a function of conservatism or are you fairly confident you’re seeing things in the Q4 data that were not permanent?

It’s that small portion that was associated with the co-gens that’s not permanent, and again we don’t want to overstate the industrial growth because of that portion, and as we look forward and forecast the full year 2018, we look at what we think are expansions, we look at what we think the growth rate it, and we think we’ve got that forecasted appropriately with the essentially flat that we’re estimating for industrial in 2018.

Okay. My last question and then I’ll cede the floor, it looks to me that the ALJ position in Oklahoma, which looks incredibly confiscatory to me as well, is as much as an $0.08 or $0.09 swing in the expected earnings versus what you asked for in the case. Now, that would be well within the range of guidance you gave for 2018, so is it fair that even though there is a fairly large swing in outcomes there, that you reiterated your guidance because you’re so comfortable you can be in there? Then the second question is, what’s your recourse to Oklahoma if they in fact, other than just pulling capital out of the state or selling the company if indeed the ALJ decision comes down as approved as rendered?

Greg, certainly our guidance that we’ve given, we’re very comfortable with that guidance that we’ve given, and actually Oklahoma is one of our smaller jurisdictions, so--but that being said, we still expect a good outcome in Oklahoma. On your second point, I think when you go in one case, which was our previous case, and you’re looking to repair the balance sheet and make sure that PSO is moving forward in a positive fashion from an investment standpoint, we pulled several hundred million dollars of investment out of Oklahoma after that last rate case, and the present rate case, to have an ALJ recommendation that’s not helpful at all in terms of continuing the recovering of PSO, if the commission follows suit with that, that’s just another really bad message about investment in Oklahoma. We have other places to put our capital. We have plenty of places to put our capital, and so Oklahoma would wind up being sort of in the red area like Kentucky was. That’s something we take very seriously because we want to make investment in Oklahoma. It’s a well-run utility, as I said earlier. When you look at the performance of PSO in relation to its customers and the rate making and everything, it doesn’t deserve the ROE recommendation and it doesn’t deserve the outcomes that we’re getting in Oklahoma. So we have to look at that and see what the broad view is. Now there again, it is an ALJ recommendation, and the commission itself will be making the determination, and we’re certainly hopeful that those adjustments will be made and that’s what we expect to happen. You brought up the issues of what the responses could be - obviously we could pull capital out of Oklahoma, we could look at strategic options for Oklahoma, but that’s really--let’s don’t get there yet, because we’re going to let the commission speak on this. I really believe that the commission will be responsive, so let’s just wait and see what that order looks like.

Okay, thank you guys. Have a great day.

Next we’ll go to the line of Jonathan Arnold with Deutsche Bank. Your line is open.

Good morning guys.

How you doing, Jonathan?

Good, thank you. Thanks for all the clarity that you’ve given this morning. One question on--can you give us some sort of sense of where you think the rate base for (indiscernible) to get out to 2020 shakes out versus the--I think you have 13.1 as the forecast at EEI.

Yes, what we’d previously shown you at EEI was a CAGR for that over the 18 to 20 period of about 8%. We anticipate it will be about 9%.

Okay, that’s great. Thank you, Brian. Presumably as we’re sort of thinking about the earnings implications, the main offset is the higher financing costs on more debt with the lower FFO, increasing your financing needs albeit without equity.

Our rating is going to stay the same--

No, no, but you have more debt, obviously, in the forecast.

True.

So to that, I was going to--I mean, you’re now talking about mid-teens as your FFO to debt target. I think one of the slides from EEI was sort of mid to high teens. Can you give us sort of hundreds of basis points net effect of what you think is going to happen to that metric?

Yes, so Jonathan, remember we were showing in the upper teens back then and people were saying to us, hey, you need to consume more of that balance sheet capacity and grow more than what you’re showing, and what we always said to people back then was, we anticipate being a significant taxpayer around 2020 and that’s going to consumer some of that balance sheet and drop us from the high teens into the mid-teens. We’re now anticipating bottoming out in the 14% FFO to debt range before we start climbing again.

I’ll just add onto that, I think it’s probably a testament to the sound financial condition of what Brian and the team has been doing for this organization, to be able to absorb the tax reform implications without issuing additional equity. I mean, in essence what we’re doing is trading FFO to debt and that ability to carry that against not having to issue equity, so it’s a positive outcome for our shareholders.

Absolutely, we just wanted to get behind what’s in those numbers. Then finally as we try to compare the capex, where you’re taking the $500 million out of the 2020 number, it looks like you’ve got some moving parts in there, but the corporate pieces, I was just curious what’s behind that and some of the other moving parts in the capex forecast.

Jonathan, it’s really going to be across the breadth of our businesses. Transmission will be a bit of that, environmental will be a piece of that. Contracted renewables will be a small piece of that. It will largely be spread across our business, but our interest in terms of how we allocate capital, transmission is still a preferred place for us to put capital, distribution and the wire side is still a preferred place for us to put capital, and there will be small portions associated with competitive renewable and some portion still associated with environmental at our generation. So largely spread across our businesses, but our preferences for where we put capital to work will remain the same.

Okay, and then just finally, do you see this as pretty set, or is there a chance that the numbers shift around a bit depending on how your conversations with states go, which you’re obviously saying are in process?

So clearly that portion about how we allocate the excess deferred income tax back to our customers is something that’s in play, and since it’s in play across 11 jurisdictions, all of which may have different interests, that’s something that we will firm up over time. We don’t anticipate there to be a strategic change in our numbers that would have our capital and financing plans change materially.

Unless of course we get Wind Catcher.

Well Wind Catcher, of course, is a big change. I was answering the question in regards to tax reform. Wind Catcher is a big change and that would clearly require us to come back out to you and explain how we’re going to finance that.

And is the assumption that Wind Catcher would displace other things, or is it partially incremental? Can you remind us how we should think about that?

Jonathan, it’s a $4.5 billion project, so that is a significant change to what we’ve talked about in our capital and financing plans, so we’d need to come out to you and tell you a complete story about what Wind Catcher means, when we get approvals and when we decide to go forward with that project.

Okay, thank you.

Next we’ll go to the line of Steve Fleishman with Wolfe Research. Your line is open.

Morning Steve.

Hey, good morning. A couple questions, first on the Wind Catcher. You had talked about making a decision by maybe March-April, I think. Is that the still rough timeline, you think?

Yes, I think the schedules are still moving towards April. We had a two-week delay in Texas for the tax reform implications, but the other jurisdictions are pretty well--have pretty well stayed intact, so we’re still looking at the same time frame and really we need to make that we get those kinds of responses so that we can make decisions about the other commitments relative to the project. We’re still in good shape.

Yes, and in terms of just your conviction level on it, it seems like the recommendations so far have generally not been that good in any of the states, or maybe one of them, so I’m just--but you did talk about maybe some settlement talks in certain states. Maybe you could talk about which ones are able, and why you’d be convinced you can still get this moving forward?

Yes, so many of these recommended rejections have been caveated with, okay, if you do move forward, we need these kinds of protections in place, and that really tends to be the center of the discussion and the center of the testimony. The thing is these cases, and you probably read the transcripts like I do - I get irritated with the transcripts half the time because it’s really arguments on the fringes, and a lot more discussion needs to be had about the benefits of the project and the benefits of a hedge and that kind of thing, but you argue on the fringes and a lot of it is risk adjustments associated with the project that allow for customer protections to be in place relative to the project benefits. We’re certainly encouraging that all interveners propose what they want to get approved. There is obviously--you know, as we go through discussions with the interveners, it’s important for us to be able to have those discussions wherever we can, and certainly we’re having those discussions certainly with Oklahoma and in Texas. Those discussions continue. I can’t really talk about the content of those discussions because obviously they’re confidential, but again we’ve made additional guarantees and rebuttal testimony, we’ve put that out as a framework for those customer protection type of mechanisms, and you might suspect that’s where the dialog is centered.

Okay, but Oklahoma is one of the states where you might have discussions, as you say?

Oh yes, and you know, that’s really where the framework originated and the rebuttal testimony. Like I said, it’s in a critical part of the Wind Catcher timeline when you’re in this time frame with the testimony done and being able to have those kinds of discussions, so. As far as confidence level is concerned, I’m still very happy with the way this project looks, and even with tax reform, because a lot of times it gets hung up with what we call our ultra-low gas case, and it’s not really even a gas case. It was really made up - we took our low gas case and we stress-tested the project at 50% of whatever those gas costs. It’s far less than NYMEX is now, and so that’s why I say a lot of the arguments are on the fringes, talking about things that really haven’t happened. So if we can just get the dialog to where it’s a reasonable type of discussion, then we’ll be in good shape. You know, I testified in a case in Oklahoma in the 90s. There was a rail spur in the northeastern, and the commission--the Oklahoma commission approved that and we got capital recovery on the project, but it benefited in terms of fuel costs. This is no different. Matter of fact, we’ve got more customer protection mechanisms in a rebuttal than we ever had anything like that, so when you look at what’s going on in this case, we have stepped up to provide answers to the concerns that the interveners have had, and again caveated by--they certainly recommended rejection, but at the same time they said, okay, let’s work on these customer protection mechanisms, and that’s what we’ve done.

Great, thank you.

Next we’ll go to the line of Julien Dumoulin-Smith with Merrill Lynch. Your line is open. Julien Demoulin-Smith: Hey, good morning.

Good morning, how are you doing? Julien Demoulin-Smith: Good, thank you very much. Let me follow up on Steve’s question just a quick bit, because I want to understand a little bit around the compartmentalization of Wind Catcher to the extent to which should one piece or another fall away as part of the approval process, can you ultimately move forward with this under a smaller context, or perhaps just under the wind or the transmission piece? Just want to frame the risk of the project moving forward again as you work through the settlement, and obviously I don’t want to necessarily prejudge anything with respect to the settlement either. I obviously heard what you just said.

I’m with you on that - let’s don’t prejudge it. But I would say that we’re certainly expecting all the states to give approval to it. You can’t really re-size this project. The benefit of this project is its size, its proximity, where it’s located in western Oklahoma with high capacity factor wind, and with the transmission sized accordingly to serve that capacity, I think you’re getting maximum benefit in terms of the value proposition to customers. I’d have to say--you know, we’re just going to have look and see what outcomes. We’re expecting all states to approve it. If all states don’t approve it, then we’ll just have to look at it at the time, because I think there may be other takers out there that might be interested, so we’ll see. But I really think that as we go forward, it will be pretty important for us to take a hard look at that project and understanding the benefits of that project, we’ll make a determination whether we move forward or not, based upon the way the jurisdictions respond. That’s really probably all we need to say at this point, because we want to make this project moves ahead. Now that being said, I will say that we are not going to move forward with a project that we don’t feel like is beneficial not only to our customers - obviously it’s beneficial to our customer, but our shareholders have to benefit as well, and we have a lot of places we can put our capital, and we just need to make sure it’s done--as I mentioned earlier in my opening, the allocation of capital is going to be extremely important for us to focus in and prioritize our investments to ensure we meet our financial objectives. Wind Catcher is only a part of that - actually, it’s incremental to the entire plan that we have today, and we’re going to make sure it stands on its own merits. So that being said, I’m still confident. Julien Demoulin-Smith: Got it, excellent. Going back to a little bit more detail on the prior conversation around the impact of tax reform and flowing that back into the state, regulatory commission processes, can you give us a little bit of a sense on how you’re thinking about that across the various states? I mean, there’s a number of ways that you could presumably approach this in terms of both addressing perhaps unrecovered items, accelerating investment, returning benefits to customers, etc. Maybe a little bit of a flavor as you think about the various states.

Yes, it’s an all-of-the-above type of thing, because state jurisdictions are going to look at it differently based upon their own individual situations. Kentucky already took advantage of part of it. We also have areas where we can accelerate depreciation or adjust plant balances or those types of things, so I think it’s particularly important for us to be mindful of where each individual jurisdiction, where the touch points are, and be able to address that. Now, I think that obviously lowering rates to customers is a critical component of this, but at the same time there are distinct opportunities that we’ve had discussions with commissions about previously that we could take advantage of and really have a real positive outcome for not only the customers but also in terms of ensuring that we’re moving ahead in a positive way, whether that’s capital investment to focus on the customer experience, whether it’s certainly things we can do with plant balances to accelerate depreciation and so forth. So all those are things to be discussed, and we’ll have--I really believe we’ll have reasonable outcomes from a commission perspective, and we’ll go forward. Julien Demoulin-Smith: Excellent, thank you very much.

Next we’ll go to the line of Praful Mehta with Citigroup. Your line is open.

Thanks so much, hi guys.

Good morning.

Morning. So just on tax reform, wanted to dig into one other topic on it. Looking at your EEI slides and the drop relative to that in your cash flow from operations for ’18 and ’19 is about $700 million to $800 million, wanted to understand what are the buckets that are driving that drop? Is it one of the bonus depreciation to makers, is it the revenue requirement coming down? Just wanted to understand what are the buckets that are driving it, and if there are any that can move as a result of all the negotiations that you’re talking about right now.

The part that moves as a part of the negotiations is really the billion or so of excess ADIT, and what we’ve shown in the slide in the deck on Page 36 is what we believe is a conservative allotment of that. I’m not going to go into what it is specifically, but we believe we’ve been conservative as what that excess ADIT flow-back will be. Everything else, the numbers kind of work out the way they work out. Of course, we’re going to be a lower taxpayer than what we thought, we’re going to have PTCs and investment tax credits included in those numbers that will also impact making us much less of a taxpayer than we were, but in terms of risk, it’s about a billion dollars of excess ADIT, and as Nick was describing, there are going to be thoughtful negotiations going on across all of our jurisdictions as to what’s the best way to have that have an impact for our customers.

Got it, so from a rating agency perspective, the drop--given you had accretion, I guess, going in, in terms of your FFO to debt, there is not a requirement to do anything at the back end given your metrics are improving by the back end, and you already had cushion, is that the way to think about the FFO to debt going forward?

That’s right. Praful, we were starting in a position of strength relative to our credit metrics against our ratings, and the reason we were in that position of strength was we anticipated being taxpayers in 2020 and we described that to rating agencies and investors. People understood that those metrics were going to deteriorate over time, but still stay within the metrics that are appropriate for our current ratings. Now that we’re not going to be a big taxpayer but our cash metrics are going to come in line with our ratings over time, and we don’t think that will be an issue for the rating agencies and we don’t think it will have an impact on our ratings.

Got you, fair enough. Finally just in terms of load growth, again in the EEI deck you had load growth of, I think for 2018, 0.7%, which is now down to 0.2% for 2018. I know you touched on this earlier as well with, I think, Greg’s question, but just wanted to get any more color on what led to the drop in ’18, anything we should be focused on, and is that ’18 number more of a steady state, do you think?

Yes, so our numbers for ’18 essentially stayed the same. The fourth quarter of ’17 came in stronger than what we thought it was going to be, so the adjustment means less of an increase in ’18 even though our numbers in ’18 stayed about the same. Does that make sense?

It’s just a (indiscernible) point of reference.

Yes, got it, that makes sense. Thanks so much, guys. Appreciate it.

Thanks Praful.

Next we’ll go to the line of Christopher Turnure with JP Morgan. Your line is open.

Morning Christopher.

Morning, Brian and Nick. I wanted to see if you guys were prepared to clarify the 5 to 7% growth. My understanding is previously it was off a 365 base in 2017 and went through 2019. Is that the same way that we should think about it now?

I think we had given detail around that going out even a year farther than that, but we don’t anticipate any change to that in even years beyond that, so we see a runway for that out as far as we can see in our forecasts. We’ve given detail around that out through 2020.

In 2020 at least, could we consider 5 to 7% to be an annual growth rate as opposed to a CAGR off of a previous base?

You know, it’s an earnings growth rate, Christopher, so say it’s off 365. As we go forward, we don’t see that changing as ’16 came in more or less than what we had forecast.

Okay, fair enough. Then there is a lot of jurisdictions here to deal with as it relates to tax reform, and a couple of previous questions have touched on this already, but we have you guys reiterating the 5 to 7% long term rate, we also have a $700 million to $800 million decrease in your forecasted operating cash flow versus EEI, as would be expected here. Is it fair to characterize your assumptions as they relate to tax reform as conservative as they pertain both to the DTL revaluation as well as just the refund considerations to customers themselves?

Yes, so let me clarify that a little bit. We do assume that we are going to the lower tax rate from the 35% down to 21%, and that that will be a fairly direct pass-through to our customers in terms of rate since that 35% was baked into our rates and now 21% will be, so we view that as not being an earnings issue. Similarly with the excess ADIT issue - it’s a matter of how do we flow that cash back to our customers and over what period of time. In 1986, it ranged from two years, I think, to 20 years depending on jurisdiction, and I think we’ll have an equally large spread of jurisdictions depending on each jurisdiction’s particular interest, so both of those we have reflected in our numbers, but both of those tend not to be earnings issues, they tend to be, as you were pointing out, cash issues.

Okay, and just on that front, to hit the 5 to 7% growth rate because cash will eventually impact earnings at some point, you don’t need to hit any certain targets in certain jurisdictions to delay that refund or get some kind of reg asset taken off your balance sheet or anything? You feel that you can reach that level with the refunds happening essentially right away?

Well again, we did not assume right away, we certainly don’t assume day one flow-backs, and we don’t think that would be a reasonable answer for jurisdictions to ask from us. We’ve built these ADIT balances up over the last 10 or so years, and a flow-back period that is in that time range, we think would be reasonable, or a flow-back that would be associated with the life of an asset would be reasonable.

It wouldn’t make any sense for the regulatory commissions to ask for all the cash back immediately, because that would impact the credit metrics of each individual entity, and historically it hasn’t been dealt with that way. Back in the 80s when this occurred, it was amortized over time and we would fully expect the same thing this time around.

Okay, I didn’t necessarily mean just with the deferred tax liability going back on that, just the lower tax rate itself.

Yes, so we assume that flows through to customers pretty directly.

The other thing I just want to reiterate too is that through all this, if there is any question of the 5 to 7% growth rate being in jeopardy in some fashion, that’s just not the case. We’re looking at the 5 to 7% growth rate just like we looked at it before, and luckily--well, not just luckily, but certainly we’re in the enviable position to be able to adjust to tax reform and still confidently talk about our 5 to 7% growth rate.

Understood, thank you guys.

Next we’ll go to the line of Ali Agha with SunTrust. Your line is open.

Thank you, good morning.

Morning Ali.

Nick or Brian, on the Wind Catcher project, there has been some rumblings in the past that maybe a competing transmission line may complicate the overall project. Can you talk to that - is that a concern?

We don’t see that. I mean, other projects will have to stand on their own merits, just like our project. Our project is unique in that it does originate in western Oklahoma high capacity wind, but we also terminate it at where the load is in our territory, and that’s toward Tulsa. I think the other projects have different routings and different assumptions associated with them and congestion associated with them, different assumptions entirely. So there may be opportunities to look at right-of-ways and some element of consistency, but other than that, though, there is really--they’re just different. They’re originating different, the takers are different, and so I would say there’s plenty of wind in Oklahoma, there’s plenty of opportunity for development, and there’s plenty of ability to continue to move that process forward. The pie is big enough for more than our particular transaction, so more power to them, but more power to us as well.

Okay. Also, as you’re looking at the project and assuming it gets approved and everything, is the plan still to own 100% of this or is there a scenario where you could sell down a piece to a third party or reduce that ownership?

No, we intend on owning 100%.

I see, okay. More near term, I remember when you laid out your ’18 guidance for us back at EEI, it was assumed in there a certain amount of rate increases from the various rate cases that had been going on and still going on. Can you just remind us what percentage of that has currently been locked in?

About 50%, Ali.

Fifty percent - okay. Last question, Brian, just a clarification, so the 5 to 7% growth rate, you are still basing that off an implied 365 number for ’17, and I heard you say it will go beyond 2020 as well. But again, should we assume that’s kind of an annual growth, or we should again assume it’s cumulative and could move around within years?

It’s a growth rate. It will move around within years, but the growth rate is 5 to 7%.

And off a 365 base for ’17?

Yes.

Okay, thank you.

Now just keep in mind, as I said earlier, that if we get Wind Catcher and other things that we’ve talked about during EEI Financial, then that can certainly be helpful; but overall, we’re looking at 5 to 7%. We’re within that range and nominally when we look at it, you can look at that range and we’re going to be consistent. That’s what we’re about, that’s what we do.

Understood, thank you.

Operator, we have time for one more question.

Certainly. Last, we’ll go to the line of Stephen Byrd with Morgan Stanley. Your line is open.

Good morning. Thanks for all the disclosure, it’s been helpful. Most of my questions have been addressed. I guess just stepping back at a high level and thinking about your growth drivers, I do see a couple positives. I guess the rate base CAGR is going up, you’ve had some good results on the pension side as well, and I know you have to raise your debt financing a bit, but that’s certainly an accretive use of money in terms of the rate base CAGR. So I guess I see a few positives - you know, Oklahoma is an unknown and certainly potentially concerning, but I respect your perspective on that. At a very big picture drivers--I guess there is often confusion between cash and GAAP and real earnings power here. I just want to make sure I’m thinking about high level drivers correctly.

Stephen, you’re thinking about it right. When we talk about 5 to 7% growth rate, we’re basing that off an increase in net plant and then getting that reflected in rates, and even at EEI we talked about there being somewhat of a lag associated with the investment we’ve put into place and then having that reflected in rates. That’s least in our transmission business because of the formula-based annual true-ups that they have in the rate base. But really, that 5 to 7% growth rate is based on our continuing to put investment in the ground for the benefit of our customers than getting that reflected in rates, and that has--what we’ve been able to do even with what’s happened with bonus depreciation, with the reduction in the ADIT and the reduction in cash flows, we’ve still been able to keep that investment essentially unchanged. We change at $500 million in the third year of our forecast, but by being able to keep that investment essentially the same, that allows us to stay in that growth range.

I think you have to look at the overall message of AEP has been consistent for years now, but it continues to even be augmented beyond that. This is a very, very solid, financially sound utility that is doing smart things for our customers and working with our jurisdictions, but it’s obviously accentuated by the largest transmission system in the country and the fact that we are making our own version of an adjustment in the fleet itself, and that’s why you have the Wind Catcher and you have other wind power projects, you’re having other transitions occur from a resource standpoint. So the augmentation of that along with what’s going on, on the distribution side - you know, we talked about $500 million of additional incremental investments to be made in distribution on grid modernization that’s not in the plan, these are all things that are changing as time goes on, and when you see the adoption of electric vehicles and all those things that are occurring, there is some important catalysts that we’re seeing in the future that we plan on taking advantage of.

That’s a great overview. Thanks very much, that’s all I had.

Thank you everyone for joining us on today’s call. As always, the IR team will be available to answer any additional questions you may have. Tawanda, would you please give the replay information?

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