American Electric Power Company Inc (AEP) — Q4 2017 Transcript

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 eager to leave 2017 behind and step into 2018, but I want to highlight that we concluded 2017 on a strong note. In the third quarter earnings call, I used a reference from Game of Thrones, comparing our situation with Khaleesi’s dragons to the cold of the winter we faced. One of my family members had the idea for me to barbecue chicken wings on New Year's Day for the football games, so I ended up grilling outside in 10-degree weather, which was certainly an experience I won't repeat. However, while it was cold outside, as a shareholder, I felt good inside because we managed to deliver considerable comfort to our customers during that frigid spell. Now, regarding our financial performance in the fourth quarter, our GAAP earnings were $0.81 per share compared to $0.76 per share in 2016. Our operating earnings stood at $0.85 per share versus $0.67 per share in 2016. This brought our total GAAP earnings for 2017 to $3.89 per share, a significant increase from $1.24 per share in 2016, while our year-to-date total operating earnings were $3.68 per share versus $3.94 per share in 2016. The $3.68 per share for 2017 met the top end of our revised guidance, marking a strong finish as we head into 2018. Looking at AEP’s total shareholder return, we have consistently matched the S&P 500 returns over the last one, three, and five-year periods and have outperformed the S&P 500 electric utilities index by a considerable margin, solidifying our status as a premium regulated utility company. Our regulated operating return on equity (ROE) was 9.5% for the year, and we raised our quarterly dividend by 5.1%. Despite challenges from weather and the need for rate recoveries, AEP delivered a solid year for our investors while providing top-tier service to our customers. Our employees have been instrumental in driving efficiencies throughout our business, which played a significant role in meeting our shareholder expectations in 2017. We encountered significant storm events, including Hurricane Harvey, which directly impacted our AEP Texas territory, and we provided support in Florida due to Hurricane Irma. Presently, we have AEP employees helping with recovery efforts in Puerto Rico, and we wish them a safe return. For 2018, we are maintaining our guidance range of $3.75 to $3.95 per share and reaffirming our growth rate of 5 to 7% in operating earnings. We plan to invest $6 billion in capital, primarily within our regulated entities, focusing on improving reliability and service quality for our customers. Our disciplined execution and capital allocation will be crucial to achieving our financial goals. Obviously, the outcomes of various rate cases I will discuss later will significantly influence those allocation decisions. Recently, someone asked me which song reflects this quarter, and I believe it has to be "Taxman" by the Beatles, since tax reform has taken center stage. As we adapt to these tax changes, our focus remains on wisely allocating capital, maintaining credit quality, and ensuring our sustained growth trajectory. We are also working with our state commissions to extend tax reform benefits to our customers, whether through rate reductions, accelerated depreciation, or additional capital projects. Thanks to our strong credit metrics, we can proceed with a substantial portion of our capital investment plans without issuing any new equity beyond what was reported at the last EEI financial conference. We have several rate cases filed in 2017 with expected outcomes early in 2018. These filings were made in Indiana, Michigan, Kentucky, Oklahoma, and Texas, and we are also awaiting the outcome of an outstanding ESP case in Ohio. With regard to the Wind Catcher project, I am pleased with the progress our teams are making across various jurisdictions. Although there are investors in opposition, our regulatory teams have effectively demonstrated the project’s benefits. The timelines in the various jurisdictions remain largely on track for timely approval. Settlement discussions are ongoing where possible, and we aim to continue those conversations. Wind Catcher presents a unique opportunity, and our readiness to embrace the risks associated with this project underscores our commitment to delivering value to our customers. AEP is advancing this initiative because we firmly believe in the benefits it will offer from day one to our customers, the environment, and the economies of the states involved. Given our critical service to customers and communities, AEP has a public trust to balance the needs of our investors, customers, and stakeholders. We are at a pivotal moment for this project, and it is essential for AEP, our customers, and regulators to see it through. Allowing this exceptional hedge against the market to pass would be a significant loss, and I remain confident that we will succeed in this endeavor. All rate cases are progressing. We have received constructive commission orders in Texas and Kentucky, and we are awaiting decisions in Indiana, Michigan, and Oklahoma, as well as the ESP case in Ohio. Each of these cases is moving as planned, and the next few quarters will provide clarity on many rate-related and ROE issues in these areas. We're hopeful that the Oklahoma commission will revise the ALJ's recommendations in the rate case, reinforcing that Oklahoma is open for continued business and allowing AEP to keep investing in energy infrastructure. As previously mentioned, we have the best customer satisfaction, service quality, and competitive rates. We just need a fair return on investments in Oklahoma. Following a disappointing prior rate case and the ALJ's unfavorably current recommendation, we hope for a positive outcome that will help change this negative trend. With an authorized ROE of 9.5% but only recovering a 6% ROE, and a potential approval of ALJ’s recommendation at just 5%, these results would be unattractive compared to AEP’s other investment opportunities. Particularly as PSO is currently on negative credit outlook with Moody’s, it is vital to achieve a favorable outcome. Now I'll transition to the equalizer graph and explain the ongoing cases. Overall, we have maintained a 9.5% ROE, though some delays during 2017 impacted our timeline, along with weather conditions. You'll hear this reflected in various cases as we move across the equalizer graph. For AEP Ohio, the ROE at the end of the fourth quarter 2017 was 14.2%, but this includes legacy issues resolved from earlier global settlements. When looking at the seed-adjusted ROE, we are around 10% in AEP Ohio, which is a good position. These legacy issues will phase out over time, with some rolling off in 2018 and others in 2019, allowing the bubbles to merge moving forward. As for APCo, the ROE at the end of the fourth quarter was 8.9%, up from 8.4% at the end of the third quarter, indicating progress, though weather throughout the year has played a role. Kentucky Power saw a slight increase from 4.5% to 5.1% ROE, which should improve further now that we have the final order approving a $12.4 million rate increase, with adjustments reflecting tax reform impacts. While this is a constructive outcome, the long-term solution for Kentucky Power involves more than just rates; economic development is also progressing in our regions, which we expect to positively influence outcomes moving forward. I&M ended the fourth quarter with an unchanged ROE of 8.4%, and we anticipate outcomes from the rate cases filed in Indiana and Michigan in the coming quarters. Regarding PSO, we've discussed their status; their fourth quarter ROE saw a slight increase to 6.2% from 6.1%, and we hope for an adjustment from the Oklahoma commission to the ALJ's current recommendations. This would bode well for the Wind Catcher project, which is also advancing in Oklahoma. Regarding SWEPCO, the fourth quarter ROE improved to 6.4% from 5.9%, and we received a constructive final order on the PUCT case, which we expect will support further ROE improvement. Please note, however, the 88 megawatts of Turk continues to be a slight drag on SWEPCO’s overall ROE. As for AEP Texas, the ROE at the end of the fourth quarter was at 10%, down from 10.3% last quarter, largely due to a tax refund affecting the calculation. AEP Transmission maintained a consistent ROE of 12.6%, slightly down from 12.7%, and we continue to see promising developments here. In summary, we have a regulated operations ROE of 9.5%, and we can identify areas needing improvement and those engaged in rate cases, expecting outcomes in the upcoming quarters to guide our investment decisions. The fourth quarter of 2017 was outstanding, and our annual results showcase the dedication of AEP’s employees to deliver consistent earnings and quality dividends despite any headwinds. We take pride in 2017, and as we enter 2018—focusing on tax reform, Wind Catcher, rate cases, Smart Cities, Ohio’s PowerForward project, and other innovative initiatives—we are setting a solid foundation for the years ahead. I'll now pass it over to 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 plans 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.

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 is, 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, we are very comfortable with the guidance we've provided. Oklahoma is one of our smaller jurisdictions, but we still anticipate a positive outcome there. Regarding your second point, in our previous case, we focused on repairing the balance sheet and ensuring that PSO continues to progress positively from an investment perspective. After the last rate case, we withdrew several hundred million dollars of investment from Oklahoma, and if the commission adopts the ALJ's unhelpful recommendation from the current rate case, it would send a negative signal about investing in Oklahoma. We have other opportunities for our capital, and if conditions don't improve, Oklahoma could end up being a less favorable investment, similar to Kentucky. This is something we take seriously because we want to invest in Oklahoma, which is a well-managed utility. The performance of PSO relative to its customers and the rate-setting process does not justify the ROE recommendation or the current outcomes in Oklahoma. We need to assess the overall situation. However, it's important to note that this is only an ALJ recommendation, and the final decision rests with the commission. We hope that necessary adjustments will be made, and we expect that to happen. While you mentioned potential responses, such as withdrawing capital from Oklahoma or exploring strategic options, we prefer not to consider those just yet. We’ll await the commission's decision, as I believe they will be responsive. Let's wait and see what the final order entails.

Okay, thank you guys. Have a great day.

Good morning guys.

How you doing, Jonathan?

Good, thank you. I appreciate the clarity you've provided this morning. Can you give us an idea of where you expect the rate base to be over the next few years compared to the 13.1 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 remain unchanged.

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

True.

So you are now discussing mid-teens as your FFO to debt target. One of the slides from EEI indicated mid to high teens. Can you provide the hundreds of basis points net effect that you anticipate for 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 consume 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 have 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 preference 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.

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 believe the schedules are still aiming for April. We experienced a two-week delay in Texas due to tax reform implications, but the other jurisdictions have remained largely unchanged. Therefore, we are still looking at the same timeframe, and it’s essential that we receive those responses to make decisions regarding other commitments related to the project. Overall, we are still in a good position.

Yes, regarding your conviction level on this, it appears that the recommendations so far have generally not been very strong in any of the states, perhaps with the exception of one. However, you mentioned the possibility of settlement discussions in certain states. Could you provide more details on which states are involved and explain why you believe progress can still be made?

Many of the recommended rejections have included conditions, emphasizing that if we proceed, certain protections must be implemented. This is often the main focus of the discussions and testimony. These cases tend to provoke frustration for me, as they often revolve around minor arguments rather than the substantial benefits of the projects and the associated hedge. Much of the conversation centers on risk adjustments related to the project, which are essential for ensuring customer protections in line with the project benefits. We are definitely encouraging all stakeholders to present their proposals for approval. As we engage with these stakeholders, it's crucial to have open discussions, particularly in Oklahoma and Texas, where these talks are ongoing. While I can't disclose specific details due to confidentiality, we have outlined additional guarantees and rebuttal testimony as a framework for these customer protection mechanisms, indicating where our dialogue is focused.

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

Oh yes, that’s really where the framework originated along with the rebuttal testimony. It’s a critical part of the Wind Catcher timeline, especially during this period when the testimony has been completed, allowing for those kinds of discussions. Regarding confidence levels, I’m still very pleased with how this project is shaping up, even with the impact of tax reform. Often, the conversations get stuck on what we refer to as our ultra-low gas case, which isn't even a true gas case. We developed it by taking our low gas scenario and stress-testing the project at 50% of those gas costs, which is significantly lower than the current NYMEX prices. That’s why I believe many of the arguments are based on fringe issues that haven’t actually occurred. If we can steer the dialogue toward a more reasonable discussion, then we’ll be in a solid position. I testified in a case in Oklahoma in the 90s regarding a rail spur in the northeastern part, and the Oklahoma commission approved it, allowing us to recover capital for the project, which ultimately benefited fuel costs. This situation is no different. In fact, we have implemented more customer protection mechanisms in our rebuttal than we’ve previously had, so when you examine this case, we have taken the initiative to address the concerns raised by the interveners. While they certainly recommended rejection, they also acknowledged the importance of refining these customer protection mechanisms, and that’s exactly what we have accomplished.

Great, thank you.

Hey, good morning.

Good morning, how are you doing?

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 agree that we shouldn't jump to conclusions. However, we are optimistic that all states will approve this project. This project is uniquely beneficial due to its size, location in western Oklahoma with a high capacity factor for wind, and the appropriately sized transmission to maximize capacity, which provides significant value to customers. We will need to monitor the outcomes, and if there are any issues with state approvals, we will re-evaluate at that time. There may be other interested parties, so we will see. Moving forward, it’s crucial for us to closely examine the project and understand its benefits, allowing us to make an informed decision based on the responses from the jurisdictions. We aim to advance this project, but we will not proceed if it doesn't benefit our customers and shareholders alike. We have various options for allocating our capital, and it must be done wisely, as emphasized earlier, to achieve our financial goals. Wind Catcher is just one piece of our overall plan, and we will ensure it justifies its own merits. That said, I remain confident.

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.

It's a comprehensive situation, as different states will approach it based on their specific circumstances. Kentucky has already utilized part of the opportunity. We also have options to accelerate depreciation or adjust plant balances, so it’s crucial for us to understand the unique aspects and key points of each jurisdiction. Lowering rates for customers is clearly a vital part of this, but there are also specific chances we've discussed with commissions that can yield positive results for both customers and our progress. This includes capital investments aimed at enhancing customer experience and measures related to plant balances to accelerate depreciation. All these elements will be discussed, and I genuinely believe we will achieve favorable outcomes from the commission's perspective as we move forward.

Excellent, thank you very much.

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.

From the perspective of a rating agency, considering the accretion you had in terms of your FFO to debt, there isn't a need to take action at the end because your metrics are improving, and you already have a cushion. Is that the right way to look at FFO to debt moving 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 point of reference.

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

Thanks Praful.

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.

I want to emphasize that there is no concern regarding the 5 to 7% growth rate being at risk in any way. We continue to view the 5 to 7% growth rate as we have in the past, and we are fortunate to be in a strong position to adapt to tax reform while still confidently discussing our 5 to 7% growth rate.

Understood, thank you guys.

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 as a concern. Other projects will have to stand on their own merits like ours does. Our project is unique because it originates in western Oklahoma with high-capacity wind and ends where the demand is in our area, specifically towards Tulsa. The other projects have different routes, assumptions, and congestion issues, making them quite distinct. While there may be opportunities to examine right-of-ways and some consistency, fundamentally, they are just different. They have different origins and different buyers. There is a lot of wind in Oklahoma and ample opportunities for development, so we can continue to advance this process. The market is large enough to accommodate more than just our transaction, so we support them while also advocating for our own project.

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%.

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.

Good morning. Thank you for the helpful disclosures. Most of my questions have been answered. Taking a step back to look at your growth drivers, I see a few positive aspects. The rate base compound annual growth rate is increasing, you've had favorable results regarding pensions, and while you do need to increase your debt financing a little, that's an effective way to utilize funds concerning the rate base growth. There are certainly a few positives, though Oklahoma remains uncertain and could be concerning, but I appreciate your viewpoint on that. At a high level, I think there’s often confusion between cash, GAAP, and true earnings potential, and I want to ensure I’m considering the key drivers correctly.

Stephen, you're on the right track. When we mention a growth rate of 5 to 7%, we’re drawing from an increase in net plant and its reflection in rates. We discussed at EEI that there's typically a lag between our investments and their inclusion in rates, particularly in our transmission business due to the formula-based annual true-ups in the rate base. Ultimately, that 5 to 7% growth rate relies on our commitment to invest in infrastructure for our customers and see that reflected in rates. Despite challenges like bonus depreciation, a decrease in ADIT, and reduced cash flows, we have managed to maintain our investment levels. While we expect a change of $500 million in the third year of our forecast, sustaining the same level of investment allows us to remain within 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 are 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?