Ladies and gentlemen, thank you very much for standing by, and welcome to the American Electric Power first quarter 2020 earnings call. At this time, all participants are in a listen-only mode. Later we will conduct a question and answer session and instructions will be given to you at that time.

If you should require assistance during today’s call, please press star then zero and an operator will assist you offline. I would now like to turn the conference over your first speaker, Ms Darcy Reese. Please go ahead..

Thank you, Perky. Good morning everyone and welcome to the first quarter 2020 earnings call for American Electric Power. Thank you for taking the time today to join us. Our earnings release, presentation slides, and related financial information are available on our website at aep.com. Today we will be making forward-looking statements during the call.

There are many factors that may cause future results to differ materially from these statements. Please refer to our SEC filings for a discussion of these factors. Our presentation also includes references to non-GAAP financial information.

Please refer to the reconciliation of the applicable GAAP measures provided in the appendix of today’s presentation. Joining me this morning for opening remarks are Nick Akins, our Chairman, President and Chief Executive Officer, and Brian Tierney, our Chief Financial Officer. We will take your questions following their remarks.

I will now turn the call over to Nick..

our state commissions and governors’ offices, federal and state legislators, FERC, NERC, DoE, DHS, NRC and others. They all have answered the call, and we at AEP thank them. There is much work yet to do, but I believe all have embraced the capital-S for social from an ESG investor perspective.

From the operational side, we have had no disruptions to plant or grid operations while storm activity has been exceptional, given the significant storm activity in several of our operating company territories and considering the additional COVID-19 related safety precautions.

There has not been a delay in the north central wind facilities construction and the regulatory cases regarding this project have continued on schedule. As well, future rate cases are on track to be filed, including in Ohio and Kentucky. On the regulatory front, it has been a busy quarter.

In fact, we have already received approvals for 96% of the budgeted regulatory recovery for 2020. In March, the Indiana Regulatory Commission authorized a $77 million revenue increased based on a 9.7% ROE. The Commission approved IN’s proposed distribution system investments and full tracking of FERC transmission costs.

The company had also sought an adjustment to reflect the reallocation of capacity costs associated with termination of certain wholesale contracts which was denied by the Commission. We have filed for re-hearing on this matter.

In January, the Michigan Commission approved the settlement of the base rate case resulting in an increase of $36 million based on a 9.86% ROE.

In April, the PUCT - Public Utility Commission of Texas issued a final order approving the settlement agreement in the AEP Texas base rate case, allowing for a 9.4% ROE with a 42.5% equity layer on the company’s $5 billion asset base.

Also in April, we filed a DCRF - distribution cost recovery factor to add approximately $440 million in assets to the rate base for distribution investments we made to benefit our customers in AEP Texas. A T-cost filing - transmission cost filing was also made to recover $800 million in transmission investments made over a similar time frame.

The company also filed a required base rate case in Virginia as part of the state’s annual review. In that filing, the company asked for a 9.9% ROE on a 50/50 cap structure on a $2.5 billion base, resulting in an increase of $64.9 million. Rates would be effective at the end of January 2021. There is no question that these are unprecedented times.

I think it goes without saying that we will need to ensure that utilities and commissions work together to devise creative solutions to the challenges we all face.

Tony Clark, former Commissioners at the Federal Energy Regulatory Commission prepared and submitted a white paper to NERUC recognizing the unique challenges the energy industry is facing and the need for regulators to be creative to new solutions.

In that article, he called for policymakers at both the federal and state level to be proactive in both the short and long term by targeting measures that support both customers and utilities.

Collectively with our legislators and our commissions, we need to work together to recognize the importance of protecting customers and ensuring utilities are able to invest in their systems and maintain the level of service that our communities depend upon, whether through deferrals or preferably riders or forward-looking test years, because cash is king again for utilities to be able to adequately invest in critical infrastructure.

Two examples within our service territory where the Commissions have taken a proactive view have been in Texas and Ohio. We believe both are steps in the right direction. In Texas, the Commission approved the COVID-19 Electricity Relief Program for residential consumers who are having difficulty paying their bills.

A rider has been put in place to fund the ERP that enables AEP Texas to access cash to begin the program cost. In Ohio, Commission staff recommended approval of the regulatory asset deferral for future recovery and recovery of the demand ratchet program costs through the existing economic development rider.

This will help lessen the impact to industrials who are key employers within the state and protect utilities. We believe both are examples of progressive moves by states to help mitigate the risk associated with COVID-19 to both customers and provide certainty for utilities.

Moving on to the North Central project, we continue to make progress on this landmark project that provides significant benefits for our 1.1 million customers in our PSO and SWEPCO states. We received approval of the unanimous settlement in Oklahoma as well as FERC approval in the first quarter.

We expected May to be an important month for the project for the remaining jurisdictions, and I’m pleased to report that yesterday the Arkansas Public Service Commission approved the 155 megawatts, or approximately 10% of the total project along with the flex-up option.

As you recall, the flex-up option allows Arkansas to increase the megawatt allocation should another SWEPCO state reject the application. The Commission in that order determined that SWEPCO should use it’s formulative rate rider to recover its costs.

In early March, we filed the unanimous settlement in Louisiana for 268 megawatts or approximately 18% of the total project, which also included the flex-up option. We expect a decision by the Louisiana Public Service Commission in the May or June time frame.

Lastly, after concluding our hearings in February, we expect a proposal for commission decision for the Texas ALJs in late May. With approvals in Oklahoma, Arkansas and FERC under our belt, the project has what it needs to go forward at 846 megawatts of the 1,485 megawatt project.

Of course, the project can move forward with even more savings for customers and the full $2 billion investment opportunity if either the LPSC approves with the flex-up option or the LPSC and the Public Utility Commission of Texas approves their portion of the full project. Now let’s talk to the equalizer chart.

Most of these are weather related, but for AEP Ohio we’ve had the roll-off of some of the legacy fuel and capacity carrying charges. They rolled off, so we expect the trend for the ROE to be at the authorized levels of around 10%. Presently, it’s at 9.9% for quarter 2020.

In APCO, the ROE for APCO at the end of first quarter is 8.7%, and that’s driven by lower normalized usage and higher depreciation from increased capital investments, and of course unfavorable weather. Virginia’s first triannual review was filed in March 2020, as I mentioned earlier, and it covers the 2017 to 2019 periods.

An ROE of 9.42% would be used for the triannual review with 70 basis point bandwidth of 8.72% to 10.12% ROE. Kentucky Power, the ROE for Kentucky Power at the end of first quarter was 6.7%, and that’s primarily driven by loss of load from weak economic conditions, loss of major customers along with higher expenses and unfavorable weather.

We also have been in a stay out provision associated with rate filings, but that goes away here soon and we expect to be filing in Kentucky in the July time frame.

I&M, the ROE at I&M is at 10.5%, and we’ve been implementing new rates for Indianan which will take place in the second quarter, but we fully expect to be at the authorized areas of around 9.7% to 9.86%. Then for PSO, PSO is at 9.2% primarily driven by unfavorable weather.

SWEPCO at the end of first quarter was 6.2%, and that was because of a loss of load, unfavorable weather, and continued impact of the Arkansas share of the Turk plant, which accounts for about 112 basis points.

The Arkansas base case settlement went in place in December 2019 and is effective January 2020, approved a $24 million revenue increase there. In AEP Texas, it’s at 8% and that’s due to a lag associated with the timing of annual filings and one-time adjustments from our recently finalized base rate case.

Favorable regulatory treatment has historically allowed us to file annual DCRF and biannual T-cost filings to recover our cost, and I mentioned those earlier, so there’s a lag associated with those but we should see a pick-up there and drive more toward a 9.4% ROE in the long term.

Then the transmission holdco at the end of the first quarter was 11.5% and it was driven by higher revenues due to differences between actual and forecasted revenues, so we fully expect the transmission ROE to be in the mid-10% range in 2020.

With that, when there is a pandemic like the one we’re experiencing today that has not occurred in 100 years, and this nation’s economy has been effectively shut down for months, there is no question that everyone is challenged and AEP is no exception.

We are up to the challenge to recognize not only the role that this company has in the resiliency and restart of our economy as well as the provision of electric service no matter where our customers are working or living, but also the importance of the consistency and quality of earnings and dividends to our shareholders that makes our work possible.

We will strike that balance, respond to challenges, and I’ll stick with a boxing analogy with a Sylvester Stallone movie, Rocky, where the music is playing, the theme from Rocky and he’s running up the steps that represent the adversity of reaching a goal.

I believe at the end of the year, we all - AEP, the communities we serve, our customers and our shareholders - will be at the summit, raising our arms in victory.

Brian?.

Thank you Nick, and good morning everyone. I will take us through the financial results for the quarter, provide some insight in how we’re thinking about 2020, including an update on April load, and finish with a review of our balance sheet and liquidity.

Let’s stop briefly on Slide 7, which shows the comparison of GAAP to operating earnings for the quarter. GAAP earnings were $1.00 per share compared to $1.16 per share in 2019. There is a reconciliation of GAAP to operating earnings in the appendix. Let’s turn to Slide 8 and look at the drivers of quarterly operating earnings.

Operating earnings for the first quarter were $1.02 per share or $504 million, compared to $1.19 per share of $585 million in 2019. Looking at the drivers by segment, operating earnings for vertically integrated utilities were $0.50 per share, down $0.13.

Earnings in this segment declined primarily due to warmer than normal winter weather and lower normalized retail load. Other small decreases included higher depreciation, higher tax expense and lower wholesale load, AFUDC, and off-system sales. Favorable drivers included rate changes and higher transmission revenue.

The transmission and distribution utilities segment earned $0.24 per share, down $0.08 from last year primarily driven by the 2019 reversal of a regulatory provision in Ohio. Other smaller drivers included higher depreciation, the roll-off of legacy riders in Ohio, and unfavorable weather.

These items were partially offset by higher rate changes, normalized retail load, and recovery of increased transmission investment in ERCOT, as well as lower O&M. The AEP transmission holdco segment continued to grow, contributing $0.28 per share, an improvement of $0.03 over last year.

Net plant increased by $1.5 billion or 18% since March of last year. Generation and marketing produced earnings of $0.07 per share, down $0.02 from last year. The renewables business grew with the acquisition of multiple renewable assets.

Increases in retail margins were more than offset by timing around income taxes and lower generation sales due to lower energy prices and plant retirements.

Finally, corporate and other was up $0.03 per share primarily driven by lower taxes relating to a prior year income tax adjustment and other consolidating items that were reversed by year end, other variances related to higher interest expense, and lower O&M.

Earlier in the call, Nick indicated that we are reaffirming our 2020 operating earnings guidance range of $4.25 per share to $4.45 per share and would likely be in the lower half of that range.

Let me give you some of the detail that leads us to that outcome on Slide 9 and then I’ll provide more detail on each of the key assumptions in the following slides. Our economic forecasting group uses Moody’s analytics as a key input to our models.

In April, Moody’s published a county-level forecast that included the projected impact of COVID-19 on our service territory. We used this new data along with updated assumptions from our customer service engineers to come up with revised retail sales projections for the year.

We now expect residential sales to increase 3% over 2019 levels largely driven by all of the activity that has taken place in residences rather than in places of work or in the classroom. Conversely, we are anticipating commercial sales contractions of 5.6% and industrial sales declines of 8% over 2019 levels.

Many businesses have shifted their operations to a mostly online platform while other employers have had to make the difficult decision to furlough or reduce employee headcount until market demand is restored. These retail forecasts lead us to expect an overall decline in sales of 3.4%.

This updated load would impact our prior forecast negatively by $0.15 per share. We have already discussed our year to date negative impact from mild weather of $0.11 per share.

In response to these circumstances, we have taken action to reduce untracked operations and maintenance expenses by an additional $100 million, resulting in a positive expectation of $0.17 per share for the year.

The net result of load, weather and O&M reductions would have a negative $0.09 per share impact for the year, leaving us inside but in the lower half of the original operating earnings guidance range. We realize moratoriums on disconnects and the economic impact to our customers may have on our cash receipts.

In response to this, we have initiated a shift of $500 million of capital expenditures out of 2020 to be placed into the future years of 2021 to 2024. As we made these deferrals, we were mindful of customer and reliability impacts.

In fact, about $200 million of these investments were in our competitive renewables business and about $100 million were corporate investments. The shifts can be ramped up or down going forward in response to how events play out in real time.

With this moderate level of capital shifting, we are able to reaffirm our 5% to 7% long term growth rate off of our original 2019 operating earnings guidance range.

Regarding potential increases in bad debt across our jurisdictions, we have already received orders in Texas, Arkansas, Louisiana and Virginia to set up regulatory assets related to COVID-19 costs. Other states where we have filed for recovery of COVID-related deferrals include Ohio, Michigan, Tennessee, and Oklahoma.

We have tried on this slide to provide some of the detail for how the coronavirus and oil and gas events will impact AEP’s operating earnings for 2020. Instead of taking you through the details of our scenario planning, let me highlight some of the items that could positively and negatively impact our view as we make our way through the year.

On the positive side, a sharp V-shape recovery that is more dramatic than the gradual recovery from the second quarter low point that we have assumed would improve results. Additionally, mitigation of coronavirus infection rates leading the economy to open up sooner than we have assumed would improve results.

A greater increase in residential sales and an improvement in commercial and industrial sales would further improve our outlook. We have experienced a mild winter. If that carried forward into a warmer than normal summer, that would have positive earnings implications.

Another positive would be if we could garner incremental savings to what we have assumed at the $2.7 billion level of untracked O&M expenses. The items that would create negative impacts to our assumptions are largely the opposite of the positives. A prolonged U-shaped or a dramatic L-shaped recovery would be more negative than our assumptions.

Increased coronavirus infection rates could lead to weaker economic conditions for longer periods than we have assumed, potential impairing our outlook for the year. In addition, continued mild weather and/or O&M expenses beyond our control, like for storms, could negatively impact the outlook for 2020.

We have tried our best using data, experience and judgment to update and share our outlook with you for 2020. We have tried not to be unreasonably optimistic nor pessimistic. This outlook allows us to reaffirm our 2020 operating earnings guidance range with a view that we are likely to be in the lower half of the range.

Now let’s turn to Slide 10 and provide an update on our system load, focusing on our outlook for the balance of the year. Our first quarter normalized load was down seven-tenths of a percent compared to last year. Our residential and industrial sales were both down for the quarter while commercial sales were essentially flat.

Our original guidance for the year assumed half a percent normalized load growth. Clearly a lot has changed since that forecast was developed. Since then, we have taken a fresh look at our forecast and now expect our total load to end the year down 3.4% on a weather normalized basis, with meaningful changes in customer mix and related margins.

For 2020, we anticipate a significant contraction in the second quarter followed by a gradual recovery over the balance of the year. In the upper left quadrant, we raised our residential outlook for 2020 to 3%. We are seeing significant increases in our residential load during the stay-at-home period.

Even after our states begin to reopen their economies in the second quarter, it is our expectation that many employees will continue to work from home. Having said this, we expect the strongest residential growth in the second quarter with some tapering off during the second half of the year.

Moving clockwise, our commercial sales outlook is now assuming a 5.6% decline from 2019 levels.

Prior to the COVID outbreak, we experienced consistent improvement in our commercial sales class over the past year; however, once the stay-at-home provisions were in place, we experienced significant declines in our sales to traditional retail stores, hotels, restaurants, churches and schools.

However, not all commercial load was negatively impacted by the outbreak. Sales to hospitals and government support offices were up substantially in the first quarter.

When you consider the challenges many businesses will face trying to introduce social distancing protocols into their normal operations, we are projecting a difficult second quarter for commercial sales with modest improvement through the remainder of the year.

Finally, in the lower left chart the outlook for industrial sales has changed significantly. We now expect 2020 industrial sales to come in 8% below 2019 levels. A number of factors have changed the outlook for this class, but the biggest driver is the overall drop in economic activity.

Over the past several weeks, we have learned a number of large industrial customers that were either idling their production or reducing their output temporarily until market conditions improve. In addition, a number of expansions we had previously assumed to come online later this year have been delayed or postponed.

These delays should be reversed as the economy gradually recovers. Since nearly 30% of our industrial sales come from the oil and gas sectors, let me explain recent sales trends in this sector. Surprisingly, sales to the oil and gas sectors in the first quarter increased by 9.7%, which was the strongest quarter we’ve experienced since 2016.

Most of that growth came from the pipeline transportation sector which was up 28% for the first quarter. Going forward, we expect some reduction in oil and gas extraction that will be offset by growth in the midstream and downstream operations.

We don’t normally report on monthly load numbers, but since we had the data, let’s take a look at April load on Slide 11. Total normalized retail load for April was down 4.3% with the relationship between the retail classes being similar to what we assumed for the balance of the year.

Not surprising given the number of people relegated to their homes, normalized residential sales were up 6% for the month. Equally not surprising, normalized commercial sales were down 7.7% for the month, with the biggest declines being in schools, churches, restaurants and hotels. Industrial sales were down 10% for the month.

The biggest decline was in sectors that support the automotive industry, while we experienced strong sales growth in pipeline transportation and food manufacturing sectors.

Looking at April’s results, the relationship between the classes, also know as sales mix, as well as the levels of sales in each class are consistent with the assumptions we have made for the second quarter of our balance of year assumptions.

Moving on to Slide 12, let’s discuss some load sensitivities and highlight some of our rate recovery mechanisms. The three pie charts show that by segment and in total, about half of our non-fuel revenues come from the residential class.

Applying the 3% growth we are now projecting for residential sales in total to the sensitivities we provided at last year’s EEI financial conference, we would pick up $0.12 a share from higher residential sales.

Repeating the same calculations for the projected load loss in the commercial and industrial classes would produce a drag of approximately $0.11 and $0.16 per share respectively. When you add these three impacts together, you get the $0.15 per share impact we identified on Slide 9.

Finally, retail rate design has a couple of features that stabilize our revenues during an economic downturn. First, most of our large industrial tariffs include demand provisions designed to cover the fixed portion of utility costs. These provisions remain in place even when volumes are down.

Second, in our residential customer class we have had some success over the years better aligning the fixed portion of customer rates with fixed costs. Together these rate considerations provide a stabilizing effect on our revenues even when sales volumes decline. Turning to Slide 13, another key assumption is the weather.

As mentioned earlier, weather in the first quarter was extremely mild. The green bar in the first quarter shows that mild weather cost us $71 million compared to normal, which was $65 million worse than the first quarter of last year.

While our outlook assumes normal weather for the remainder of the year, this chart shows that weather can change significantly, as evidenced by last year’s experience. If we were to have another warm summer like we did in 2019, it could offset the $0.11 drag for weather in the first quarter that we showed you on Slide 9.

Our management team has a proven track record of adapting our plans to changing conditions as necessary. In years when the weather has provided a tailwind, we have accelerated spending to provide stability to our earnings in line with our 5% to 7% growth targets.

In years where weather has been less accommodating, we have been able to shift our spending to future years to achieve the same goal. You can expect this management team will react similarly this year.

Turning to Slide 14, you can see that for nine years now, we have maintained O&M discipline and kept spending net of offsets in a tight range of between $2.8 billion and $3.1 billion. We had originally planned to drive down O&M costs in 2020 to $2.8 billion.

In response to the expected decline in sales, we now plan to reduce O&M spend by an additional $100 million. Plans like the Achieving Excellence program and additional one-time and extraordinary reductions will help us to achieve those reductions. Now let’s move on to Slide15 and review the company’s capitalization and liquidity.

Our debt to total capital ratio increased during the quarter from 59.8% to 61.8%. The increase in the debt component is attributable to financings to support our ongoing investment program and to fortify our liquidity position to ensure smooth operational financing during this period of market volatility.

As you would expect, the increase in debt combined with the ongoing pressure associated with the flow back of ADIT resulted in pressure on our FFO to debt metric, which at quarter end stood at 12.5% on a Moody’s basis.

The decline in the metric is also temporarily influenced by the $1 billion 364-day term loan the company proactively obtained in late March. Despite the temporary decline in this metric, rating agencies view this enhanced liquidity as credit positive. Adjusting for this facility and associated cash balances, the metric would be 13%.

Our liquidity at the end of the quarter remained strong at $2.8 billion. Since then, our commercial paper balances have dropped to $1.6 billion and our liquidity position has increased to $3.1 billion. Our qualified pension funding increased approximately 4% to 93%, and our OPEB funding decreased approximately 15% to 130%.

Pension and OPEB equity returns were negative 23% and negative 22% respectively for the quarter and were the primary reasons pensions and OPEB funding decreased. Fixed income returns of approximately 7% and 6% in the pension and OPEB respectively served to offset some of the equity losses.

We have worked hard over the years to focus on pension and OPEB funding and are pleased with how the asset portfolios have performed in spite of recent market volatility. Let’s wrap this up on Slide 16 so we can quickly get to your questions.

In response to the economic downturn and related implications, AEP has responded to quickly reduce our O&M spending by an additional $100 million for 2020. This action combined with our updated load forecast allows us to reaffirm our existing operating earnings guidance of 2020 from $4.25 to $4.45 per share.

In addition, in response to uncertainties about cash flows related to reduced customer demand and potential delays in customer receipts, we are shifting about $500 million in capital expenditures out of 2020 and into the period 2021 to 2024.

We can adjust the timing and size of this shift in reaction to how events play out relative to our assumptions. Because of our ability to continue to invest in our own system organically, we are confident in our ability to grow the company at our stated long term growth rate of 5% to 7%.

We continue to make progress on obtaining approvals for our $2 billion North Central wind project in Oklahoma and plan to proceed when approvals are obtained. With that, I will turn the call over to the operator for your questions..

[Operator instructions] Our first question comes from the line of Steve Byrd with Morgan Stanley. Please go ahead..

Hi, good morning. Hope you all are doing well. .

Morning Steve..

Thanks for the update on a lot of topics. Wanted to talk first just about two of your rate cases, Indiana and Michigan, where I believe the test year is going to be a 2020 test year.

How do you think about that sort of test year in light of COVID - you know, load adjustments, COVID-related expenses as you think through that rate case, and sort of how to approach 2020 given it’s such an unusual year?.

In at least Indiana, we have forward test year views, and I think it’s probably going to be particularly important as we go in for these cases for there to be an understanding that we are dealing with a COVID-related year if it is a test year.

Wherever you have forward test years, though, you can account for that going forward in the rate making, but we’d be tuned into the process whether you pro forma in or do other things.

I think there’s probably at least opportunities for discussion about that because COVID--you know, 2020 is going to be an usual year and to be used for test years would be particularly challenging. You have to really go to some form of pro forma view that has the level of investments, the level of business activity that you would normally see.

So, I would expect our commissions to be reasonable in that approach. .

You know, in both those cases, Steve, we had forward-looking test years and we do have orders effective in both of those jurisdictions..

Okay, that’s helpful. Yes, it makes sense that you’d sort of try to work to the adjustments. It makes sense. On North Central wind, some great progress there. That’s really encouraging. I guess I had sort of two related questions on North Central.

If you do get those additional approvals that you’re waiting for, such as in Louisiana, Texas, can you quickly flex the plan to go to the higher megawatt level? Then relatedly, you’ve obviously deferred some capex.

Do you have that flexibility to deploy whatever capital you need to, to make this a bigger project, or does your capital position caution against significant ramp-up in capex this year? Just thinking through the growth at North Central..

Yes, so originally North Central was not in our capital plan, and so when we get approval for that, that’d be dealing with a different financing model associated with that.

As far as the megawatt level and the amount of investment, yes, if we get approval for Louisiana for example, and Louisiana also approves the up rate which is in a settlement arrangement, then we would have the full $2 billion investment opportunity there.

We already know we’re going forward with the project - that was the importance of Arkansas approval, so the project is moving forward.

The question is what size, and then when Louisiana approves that, and hopefully with a flex-up as well, then that’s the full $2 billion, or if Texas takes their portion, then all operating jurisdictions will be taking their particular portions as we go forward. Now, there is additional opportunity for renewables in those areas.

The integrated resource plans have the capability for that, but we felt like, as we originally said about this project, there is sort of a break point between the opportunities that existed around the wind farm project and the pricing, and we wanted to make absolutely sure that the pricing was very effective and produced very positive savings for our customers.

So, we can always go out for a bid again to fill the rest of that from a resource planning perspective. .

Steve, we’ll be full speed ahead on the capex associated with North Central wind one way or the other. Nick mentioned that it’s not in the $33 billion that we had previously identified for the five years, 2020 to 2024, and we previously said that we anticipate an equity component of that investment to be between 50% and 66%. .

That’s super helpful. I’ll let others ask questions. Thank you. .

Thank you..

Thank you. Our next question comes from the line of Durgesh Chopra with Evercore. Please go ahead..

Hey, good morning guys. Thanks for taking my question. I have two.

The first one on 2020 guidance range here, the $0.15 EPS hit, what are you assuming in terms of decline trends for the rest of the year? I guess what I’m asking is are you--as you make some amount of recovery in Q3 or Q4, just curious as to what you’re assuming in terms of profiling for the rest of the year..

Sure, so we are assuming that the second quarter would be the lowest quarter for load, and that there would be a gradual recovery over the balance of 2020 and into the first quarter of 2021..

Got it, perfect.

Then, can you comment on just your--you know, assuming that you hit your lower half of the EPS guidance range for this year, where would that put you in terms of credit metrics [indiscernible] debt versus your targeted metrics? Then any color that you can provide us with your recent conversations that you have had with Moody’s on some of the changes that you’ve made to your plan?.

We’ve really been--we anticipate year end being FFO to debt in that 13% to 14% range. We’ve communicated that with S&P and Moody’s, had dialogues with them as late as yesterday. They understand where we are and what we’re doing.

I think they were encouraged to see us flex a little bit our capex for the balance of the year in response to anticipated lower cash flows than what we had anticipated, and they’re supportive of that.

They were--they viewed what Julie and her team did around the term loan facility as being credit positive, and they are fully aware and apprised of what we’re doing. You should ask them, but I think their answer would be supportive..

Great, that’s all I had, guys. Thank you very much..

Thank you, Durgesh..

Thank you. Our next question comes from the line of Julien Dumoulin with Bank of America. Please go ahead..

Hey, good morning team. I hope you’re all well. Perhaps just to pick up where the last question left off to start here. On guidance and the 2020 lower half, how do you think about the reduction in capex? I just want to reconcile this.

It seems as if you’re not really changing FFO to debt expectations as you are bringing down capex altogether, but why do that relative to no change in earnings? Can you walk through the thought process there? Then also, it seems as if it doesn’t necessarily have too much of an earnings impact given the corporate nature of some of the capex, so I just want to make sure we’re thinking about that correctly as well..

one, lower customer demand, and then two, we have eliminated disconnects currently, and so we think that customers will pay us slower than what they have in the past.

We’re not seeing the impact of that in a significant way yet - it’s too early, but in anticipation of lower cash flows to maintain those FFO to debt metrics, we felt it was prudent to at least engage the motor on our ability to scale back capex.

In regards to the no impact on future earnings, we tried to do it in places that have either lower regulatory lag or the increase in earnings isn’t as great.

Nick mentioned that some of that reduction is in the competitive renewables space and some of that reduction is also at corporate capital, things like IT and things like that, that are much slower to flow into customer rates during rate cases.

Things that we are careful not to cut were things like transmission, where we’re spending on customer resilience and reliability and we have those formula-based rates to update and get that capex into rates on a fairly efficient basis.

We were really thoughtful about how we cut that or shifted that small amount of capex, and made sure that it wasn’t impacting earnings..

Julien, I think you’re reading it right, though - we’re being as transparent as we possibly can be through this process using the latest information.

Matter of fact, we got the load information, April load information yesterday, so we’re trying to be as transparent as possible, but also taking the right, smart, appropriate steps to ensure that we’re able to be agile enough to do what we need to do. I think you’re reading that right.

We obviously would put that capital back in as quickly as possible and then, as Brian mentioned, we’re not only mitigating any impacts to the earnings capability but also thinking ahead in terms of where we deploy that capital in the future. Then we also have North Central coming about, so those things are occurring.

We’re trying to manage through this year in a very positive fashion and really a defensive posture, and then set ourselves up for the future years, in ’21 and beyond.

We’ll continue that approach, and obviously if we get a hot summer, for example, we’ll throw capital back in - there’s all kinds of things we can adjust, and then from a residential standpoint, you heard our residential load for April was 6%, and we’re saying 3%, so we don’t know exactly how this is going to play out, particularly with changing dynamics of business cases themselves changing.

I mean, we had Nationwide recently come out and say that their people are going to be working from home, and we have 17,000 employees and 12,000 are working from home.

We may be looking through our Achieving Excellence program, which we have already accelerated, to look at how you look at people working from home and maybe the whole business cases changes from that perspective and also reduces O&M further. So we’re in the process of doing all that, but we’re just trying to be as transparent as possible.

But you’re reading the tea leaves right..

Got it, excellent. Let me just clarify this from the transcript - you all reaffirmed intentions to file rate cases in various geographies.

This doesn’t shift timing necessarily, it sounds like, nor--at the same time, I don’t want to tie one to the other, does it shift any expectations with respect to asset sales, disposals, strategic reviews? Just want to make sure we’re on the same page there, and there could be some further capital needs..

No, it doesn’t change. As a matter of fact, we’ll continue those cases. Obviously, as I mentioned, in Kentucky we have a stay out provision. We need to file a case, and we’ll do that when that stay out provision is lifted, and then that would be effective January 1 of 2021. Then for Ohio, obviously we’re due to file a case there as well.

It’s a pretty moderate case, but nevertheless. As far as we can tell, everything is going exactly like we had planned. Now, you may see some procedural schedules change, but the end result and the end dates aren’t changing, so that’s where we’re at today..

Great, thank you..

Thank you. Our next question comes from the line of Michael Lapides with Goldman Sachs. Please go ahead..

Morning Michael..

She did a better job pronouncing my last name than most people do. .

I have the same problem..

I had a handful of questions. One, I’m going to be a little more specific on capex, so $500 million cut, $200 million is at the non-regulated renewable--.

Michael, $500 million shifted. .

Shifted - my bad. .

We’re sensitive about that!.

Five hundred shifted, 200 is at the non-regulated renewable, 100 is at corporate.

What’s the other 200?.

There’s another $75 million to $100 million that is in our distribution at our opcos, and then the other $100 million is spread across our organizations but not in the transmission side of the business. .

Got it, okay. That’s fine.

The other question is, is there any scenario where you could delay, given all that’s going on in the world, all the uncertainty about demand, about the impact of disconnects, is there any regulatory scenario where you could actually postpone or push out the AEP Ohio rate case?.

No, we don’t see that happening because obviously we’re required to file a case, and actually it’s a pretty moderate case, so I think that there really isn’t any reason to delay it at this point..

Michael, I think Nick’s answer earlier was there could be a delay in the procedural schedule. We would still expect to get the result of the case when we originally had..

Yes..

Got it. Then final question--.

And everybody knows about it as well, so it won’t be a surprise to anybody. There’s a pretty negligible impact on customers too in that case..

Yes, that makes a ton of sense. Then last question, you all have done a great job in managing down O&M for the last four years, and you’ve taken a lot of O&M out of the company. It saves the customers money, it’s good for shareholders.

At what point do you think the long term rate of change in O&M management starts to flatten out, meaning the curve, the ability to keep taking out more or become more efficient just starts to flatten out, the pace of change slows..

You know, we’ve had a lot of conversations about that, but every day you’re surprised by some new innovation or something that can change the trajectory of O&M expense.

We spend $4 billion a year, I think $2.8 billion is not tracked, and when you look at some of the opportunities that are available, and actually I think if there is a silver lining in the coronavirus pandemic, it is that we can really re-evaluate what it means to get our business done, because we’ve been very effective at the people working from home and actually productivity has not suffered as a result.

We still have obviously the field employees that are still out there working as well, but you see the innovations that are occurring. I think we have years ahead of us to continue to optimize O&M expense, and when you think it’s going to level out, something new comes about and I think that’s going to be a continual opportunity for us.

We actually--and you probably we announced we have a new senior vice president over our--actually, the digital experience, our Chief Information and Technology Officer who is joining the company, we wanted to make sure that we put technology and the customer experience, and certainly our charge innovation hub and those kinds of things together to really focus the organization on what the future holds and what it can mean in terms of O&M in the future.

I think we don’t know the answer to that, and really you don’t want to know, you want to just keep pressing forward, and we’ll do that..

Got it, thank you Nick. Much appreciated..

Thank you. Our next question comes from the line of Jeremy Hulme [ph] with JP Morgan. Please go ahead..

Hi, good morning. Thanks for having me here. I could be wrong, but I think in the past you might have provided a multi-year view of financing needs in the earnings deck.

I think I might have missed that here, so didn’t know if there any changes to how you’re thinking about funding capex going forward here, and is there any interplay with where Moody’s is at right now as you think about this?.

Jeremy, there’s really no change in how we’re funding capex. I think the big thing we did really with the last call was give some insight into how we were going to fund more Central wind and the idea that we’d be doing that between 50% and 60% equity.

We’ve always been fairly conservative in our balance sheet management, and we’re going to continue that going forward. .

Got it. That’s it for me. Thanks for taking my question..

Thank you..

Thank you. Our next question comes from the line of James Thalacker with BMO Capital Markets. Please go ahead..

Hey, how are you guys? Thanks for taking my call..

Sure. .

Just following up on Jeremy’s question, just wondering, Brian and Nick, as you guys are getting closer to North Central wind approvals, have you sharpened your idea on how you’re thinking about financing that, and especially have you looked a little bit more maybe some cycling some current assets, as opposed to accessing the capital markets specifically?.

James, we do have a little bit of time for that, right? The smaller portion of North Central wind is going to come, about $300 million at the end of ’20, which would really make the financing of that a ’21 event.

Then we have really until the end of ’21 to go forward with that, so how we come up with the equity portion of that, whether it’s capital rotation or whether it’s the equity capital markets, are still things that we have plenty of time to work through.

I think the important assumption was the range of percentage of equity that we’d use for that project, and that’s where we talked about being in the 50% to 66% of the project..

Yes, and really probably the main message is all the options that were available to us before are still on the table and still being considered. There hasn’t been any change from a timing perspective in our ability to get that done, so I’d say we’re still at the same place we were and we’re ready to execute.

I think it’s just a matter of us getting the ducks all in a row to ensure that we’re at the right place at the right time..

Sure. I just wasn’t sure if you guys were looking at the potential for augmenting some of the equity with the recycling of assets, if there became a regulatory proceeding or something like that, that would have to be taken into consideration ahead of time just because of--.

Yes, and we’ve said for really over a year now that with capital rotation, but also sale of assets is on the table as part of that process. We’re obligated to do that from a shareholder perspective, and we will certainly do that..

Got it. Thank you very much. Appreciate the time..

Thank you. Our next question comes from the line of Sophia Karp with Keybanc..

Morning Sophia..

Hi. Good morning, thank you for taking my question. A couple of questions here for me.

Can you remind us if North Central wind was contemplating tax equity financing as part of the plan?.

It is not. .

Okay, so then maybe another one for me. I know you guys have a pretty decent chunk of your workforce that was on track to retire within the next, call it five, seven years maybe.

Are you contemplating offering them, these folks some sort of voluntary early retirement, maybe in an effort to cut O&M? Is that something that we could see on the table?.

Well, I usually get that question from employees. As we look at the O&M and the issues that we’re dealing with to try to reduce O&M to the $2.7 billion level and beyond, we look at a lot of things; but one thing we have to be very careful about is certainly if you offer things like that, you usually lose people you don’t want to lose.

In this day and age certainly in our frontline employee ranks, we need every individual that’s working, and there’s a lot of competition going on for the professionals in those industries. That’s something we have to be really careful about.

Now obviously if it’s part of the--as part of our regular operations that if we evaluate groups and there’s efficiencies in terms of resources, whether it’s vacancies or retirements or even where severance is offered, we’ll continually manage our resource based upon the work that’s in front of us, and we typically do that on a surgical basis rather than some generalized approach.

I suspect that we’ll continue that approach..

Got it, thank you. One more from me, if I may.

On the volumes, first, to what do you attribute the jump in oil and gas volumes? What kind of dynamic on the ground is driving that, and should we expect a reversal of that? As the states begin to sort of reopen, if you call it that, which ones of your service territories would you expect to reopen and maybe be on a faster trajectory sooner than the others [indiscernible]?.

What’s really driving our results for oil and gas has been midstream and downstream, so I attribute a lot of that--it’s pipeline transportation, really, was up 28% for the quarter.

What you’re seeing there is sort of a lag effect associated with all the increases that we’ve seen in oil and gas extraction and then it’s been moving that product from the oil patch to refineries and places where it can be used.

That lag effect is finally catching up with us as we’ve seen people putting in electric compression on pipelines and our having to service that, and so that trend has continued well into the first quarter and even into the month of April. We’ve continued to see increases in pipeline transportation and downstream as well.

The downstream might fall off a little bit as we’re seeing some reductions in refining, and certainly oil and gas extraction itself will be down as people shut in wells and don’t take as much as they previously had. But it’s really been the midstream part of that that’s been driving the growth in oil and gas that we’ve seen. .

Just to go back on your earlier question too, just an example, I probably have the opportunity for a call-out, our Conesville plant is retiring, the plant is retiring this month after over 60 years of service, and that’s typically what we’ve done.

As plants retire, as employees shift from one plant to another and optimize across plants, we’ve enabled that through severance programs and those types of things, so that’s just an example of what you were mentioning before..

Then to our service territories as they open, all 11 of our traditional footprint states anticipate opening in May, and they generally have staged reopenings as we go through the month, but all of ours anticipate opening during this month..

Awesome, let’s hope that happen. Thank you..

Yes, I think our service territory, and it’s really interesting to me because we serve midsized cities and smaller - Columbus, Tulsa are our largest cities, but they’re obviously not New York or Chicago or other areas like that, San Francisco.

That has actually improved the resilience because people are more spread out, and so our states have been able to methodically go through the shut-down provisions and now are methodically going through the restart provisions, and it’s been, I would say, probably more helpful to the recovery process for our service territory..

Thank you..

Perky, I just want to let you know, we have time for one more question..

Thank you. Our final question is from the line of Shar Pourreza with Guggenheim and Partners. Please go ahead..

Hey, good morning guys. .

Morning Shar..

Just one or two questions, more just clarification. Nick, you obviously reiterated guidance, the long term growth rate, 5% to 7% off the original base. I know in prior remarks, you’ve highlighted that you’d be disappointed if you weren’t in the upper end.

Is that still the case, or have the issues around COVID and some of the moving pieces walked you back down a little bit from that?.

Yes, I guess I would still be disappointed, but obviously you have to look at it realistically, and based on the information we have today, I think we’re well placed in terms of that, and we’ll continually update it.

Obviously I’d like to think there’s more upside than downside because we have looked very conservatively and very pragmatically at what we face relative to the business and customer base that we serve, but as we get North Central, I’m still optimistic about those future years where that gets fully layered in, starting in ’21.

So 2020 may be a tread year for the guidance range and then we get the engine back fully on the tracks and get moving again. .

Got it.

Then just one last on North Central, if you take the $2 billion spending around that project and you look at your $33 billion of opportunities in your base plan, as you guys look to layer in North Central spend and you’re looking at different financing opportunities, is there any spending opportunities within the core $33 billion that could be maybe secondary in nature of offsetting with North Central coming online, or should we think about $2 billion from North Central additive to $33 billion? I’m just trying to figure if we’re modeling this, how we should think about that..

And that’s why we’ve kept it outside. It’s additive to the $33 billion..

Got it. Terrific, guys. Thanks so much for everything..

Thank you Shar..

Thank you for joining us on today’s call. As always, the IR team will be available to answer any additional questions you may have.

Perky, will you please give the replay information?.

Certainly. Ladies and gentlemen, this conference is available for replay starting today. Please dial 1-866-207-1041 and enter the access code of 3291585. You may also dial 402-970-0847 and enter the access code of 3291585. Those numbers again, 866-207-1041 and 402-970-0847 and entering the access code of 3291585.

The replay will be available until May 13, 2020 at midnight. Ladies and gentleman, that does conclude your conference for today. Thank you very much for your participation. You may now disconnect..