American Electric Power Company Inc (AEP) — Q1 2020 Transcript

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.

Okay, thank you Darcy. Welcome and thank you all for joining AEP’s first quarter 2020 earnings call. I want to take a moment to extend our sympathies to all those who have been personally impacted by the COVID-19 pandemic. At AEP, we understand that we are all in this together. The AEP Foundation has contributed to charities across our footprint to ensure that we are part of the solution for the customers and communities. In addition to providing our employees with the personal protective equipment they need to do their jobs, we have donated masks, gloves, and other essential items needed by hospitals across our service territory. To further assist those in need within our communities, our customer service representatives have provided assistance in fielding questions on how to secure small business loans. Throughout these challenging times, I continue to be extremely proud of our employees who have done an outstanding job demonstrating their capacity for being adaptable and exercising the agility needed to meet the challenges of a rapidly changing situation. As we continue to adapt to the ongoing challenges imposed by COVID-19, we remain committed to keeping our employees safe and keeping America powered through these unprecedented times. Certainly, as we headed into March during the first quarter, the story for the quarter would have been one in which we have all heard before, mild weather impacted the first quarter, but as we’ve also heard before, a quarter does not make a year and there is plenty of time to recover from a mild winter. We adjust to these types of issues all the time. But I’m sure you’re more interested in the last half of March and what April tells us about the future. I’ll get into all that in a minute, but first let’s just do the headlines, the financial headlines for the quarter. For the first quarter, we came in with operating earnings of $1.02 per share. We are reaffirming our 2020 operating earnings guidance range of $4.25 to $4.45 per share and our 5% to 7% long-term growth rate. AEP is doing this because, regardless of whether we forecast a V-shaped, a U-shaped, or W-shaped COVID-19 recovery, we see our service territory as an arbitrage between residential load and commercial industrial load that is defined really by a pendulum between the financial characteristics of working from home versus the restart of commercial and industrial businesses. With all of this considered along with capital, O&M, credit metrics, and updated load forecasts and actions we have taken, we expect to be in the lower half of our guidance range. We are shifting $500 million of capital spending, substantially contracted renewable business and corporate-related capital for the time being to maintain our commitments to solid credit ratings. We are reaffirming our $33 billion of capital over the five-year period, however. We believe this to be the smart play given our ability to adjust capital quickly to respond to market conditions. We give all of this guidance insight given an exhaustive review county by county of our service territory from a load perspective through April, weather impacts thus far in the year, and expense control measures already put in place to respond to present conditions. We will continue to refine these assumptions as data become available. Certainly, weather, customer load mix, pace of economic recovery, and continued O&M related actions will dictate further positive progress within the guidance range. Brian will get into more detail about these assumptions, but I want to reaffirm for you that our balance sheet is strong, credit metrics are good, and liquidity is secure as we move forward. Let’s move on to the specifics related to COVID-19 and its implications to our operations and our financials as we see the year progressing. As many have heard, there is a famous boxing quote from Iron Mike Tyson that is truly appropriate here: “Everyone has a plan until they get punched in the mouth.” Well, that’s what we have faced in the end of this quarter and will face probably for the rest of the year, but I’m here to tell you, yes, we’ve been challenged a little bit, but we are very much still in the match because of our quick responses and agility to be in the position to reaffirm our existing guidance range. I’ll start by discussing our employees’ commitments to our customers, communities, and our shareholders as we move through the crisis that I referred to at the beginning of my presentation. First, I want to recognize all the healthcare and first responders who have put themselves in the line of fire to help us all to be more safe and healthy. As a critical infrastructure service company, the frontline employees of our utility have also taken on risk by ensuring we are out in the field responding to substantial storm activity to ensure the resiliency and reliability of electric service so that our hospitals, critical businesses, and customers who are under stay-at-home provisions can continue to benefit at least from some degree of comfort in these challenging times. We have instituted protection measures for these employees that reflect CDC guidance regarding physical distancing, including smaller work teams, proper hygiene, and appropriate PPE and testing to minimize risk of contact with the virus. Approximately 12,000, over 70% of AEP’s employees have been working from home for several weeks now and will continue to work from home even after stay-at-home provisions are lifted to ensure further precautions are taken both at home and at the office for employees who must return for various reasons. We have instituted specific COVID-19 adjustments to our health plans and benefits for employees, and as a critical infrastructure business have continued to pay our employees as they work from home. For most field-level employees, we have also awarded additional days off with pay to enable more time with their families during this time. We have over 82% of our call center employees working from home, and as they not only answer customer questions, they are also helping our small businesses get back on their feet by helping them navigate through the SBA loan provisions of the Cares Act. Regarding our customers, we recognize the hardships that this pandemic has brought on and have temporarily suspended all service disconnects for non-payment, and our team of call center professionals have been working diligently to administer more flexible payment arrangements for our commercial and residential customers. Some states have mandated this, but we do so voluntarily and our state commissions have fully supported these actions through the establishment of deferred accounting and other measures, which I want to take the time to thank them for addressing these issues. Regarding our communities, the AEP Foundation has donated over $3 million to support basic human needs to help address hardships from food security, housing, clothing, and other issues during this time. We have donated over 9,000 N95 masks, 110,000 gloves, and disposable surgical masks, and 1,200 face shields from our warehouse stocks and 3D printing facilities within our innovation labs. In my 37 years of being in this business, I have never seen the level of coordination and concern by multiple agencies to do the right thing for our customers, our employees, our businesses, and communities. While much focus on this call is on the financials, it is important to remember the part we play in the broader social fabric as a critical infrastructure business. Our effectiveness is defined by the level of cooperation and support from all of the agencies that we deal with: 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 increase 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 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 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 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 capital 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 with 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 on 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 expect 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 its 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 timeframe. Lastly, after concluding our hearings in February, we expect a proposal for commission decision for the Texas Administrative Law Judges 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 about 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 the quarter of 2020. In APCO, the ROE for APCO at the end of the 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 period. An ROE of 9.42% would be used for the triannual review with a 70 basis point bandwidth of 8.72% to 10.12% ROE. Kentucky Power, the ROE for Kentucky Power at the end of the 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 timeframe. I&M, the ROE at I&M is at 10.5%, and we’ve been implementing new rates for Indiana 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%. For PSO, PSO is at 9.2%, primarily driven by unfavorable weather. SWEPCO at the end of the 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 into 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 or $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, along with 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 details 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-shaped 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, potentially 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 of 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 known 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 Slide 15 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 flowback 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.

Hi, good morning. Hope you all are doing well. 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 Indiana, we have forward test year views, and it's crucial to recognize that if it's a test year, we are dealing with a COVID-related year. In places with forward test years, you can account for this moving forward in the rate-making process, and we will pay attention to whether you pro forma in or take other approaches. There are likely opportunities for discussion about this because 2020 was an unusual year, making it particularly challenging to use as a test year. It will be necessary to adopt some form of pro forma view that reflects the level of investments and business activity typically seen. Therefore, I expect our commissions to align reasonably with this 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.

Good morning, everyone. I appreciate you taking my question. I have two inquiries. First, regarding the 2020 guidance range and the $0.15 EPS, what are your assumptions about the decline trends for the remainder of the year? Specifically, I'm interested in your projections for recovery in Q3 and Q4 and how that informs your expectations 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.

Can you comment on your projected EPS for this year, specifically if you achieve the lower end of your guidance? What impact would that have on your credit metrics in relation to your debt compared to your target metrics? Additionally, could you share any insights from your recent discussions with Moody’s regarding changes made to your plan?

We expect the year-end FFO to debt ratio to be in the 13% to 14% range. We've communicated this with S&P and Moody’s and had discussions with them as recently as yesterday. They understand our situation and our actions. They were pleased to see us adjust our capital expenditures for the remainder of the year in light of anticipated lower cash flows than we originally expected, and they support this decision. They view the actions taken by Julie and her team regarding the term loan facility as positive for our credit standing, and they are fully informed about our plans. While it's best to ask them directly, I believe they would express their support.

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

Thank you, Durgesh.

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?

Sure, Julien, thanks for the question. We are anticipating there to be some reduction in cash flow this year associated with two things: 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 those types of things 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 case 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 clarify from the transcript that you all reaffirmed intentions to file rate cases in various geographies. This doesn’t necessarily change the timing, but I don’t want to imply a connection between them. Does it affect any expectations regarding asset sales, disposals, or strategic reviews? I just want to ensure we're aligned, and there may be some additional 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. 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.

Morning Michael.

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

I have the same problem.

I had a few questions. First, I want to be more specific about capital expenditures; we are cutting $500 million, with $200 million related to the non-regulated renewable sector.

Michael, $500 shifted.

We’re sensitive about that!

Five hundred shifted, my bad.

There’s another $75 million to $100 million that is in our distribution at our operating companies, 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?

We’ve had many discussions about this, and every day brings new innovations that can alter our O&M expenses. We spend about $4 billion annually, with approximately $2.8 billion that isn't tracked. Looking at the opportunities available, the coronavirus pandemic has given us a chance to rethink how we operate. We’ve successfully adapted to remote work without losing productivity. Our field employees are still active, and we’re witnessing ongoing innovations. We have years ahead to further optimize our O&M expenses, and just when we think it might stabilize, something new emerges, creating continuous opportunities for us. We recently announced a new senior vice president focused on the digital experience, who is our Chief Information and Technology Officer. This role aims to integrate technology with customer experience, particularly through our charge innovation hub, to better prepare the organization for future O&M developments. While we don't have all the answers yet, our goal is to keep pushing forward.

Got it, thank you Nick. Much appreciated.

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 are 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.

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 at 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 was uncertain if you were considering the possibility of enhancing some of the equity through asset recycling, particularly in light of any regulatory proceedings or similar factors that would need to be taken into account beforehand.

Yes, and we’ve said for really over a year now that with capital rotation, but also the 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.

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?

I often receive that question from employees. As we focus on the operations and maintenance costs and aim to reduce them to the $2.7 billion level and beyond, we consider many factors. However, we need to be cautious because offering certain incentives can lead to losing valuable employees, especially among our frontline staff, where we require every individual given the competitive landscape for talent in those sectors. This is something we must handle delicately. If it becomes part of our normal operations to evaluate groups and find efficiencies in resources, such as through vacancies, retirements, or severance offers, we will manage our resources based on the existing workload. Typically, we approach this in a targeted manner instead of a broad strategy. I anticipate that we will maintain this approach moving forward.

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?

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, that 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 happens. Thank you.

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

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?