TXNM Energy, Inc. (TXNM) Q1 2020 Earnings Report, Transcript and Summary

Good day, and welcome to the PNM Resources First Quarter 2020 Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Lisa Goodman. Please go ahead.

Thank you, Jason, and thank you everyone for joining us this morning for the PNM Resources First Quarter 2020 Conference Call. Please note that, the presentation for this conference call and other supporting documents are available on our website at pnmresources.com. Joining me today are PNM Resources Chairman, President and CEO, Pat Vincent-Collawn; Chuck Eldred, Executive Vice President of Corporate Development and Finance; and Don Tarry, our Senior Vice President and Chief Financial Officer. Before I turn the call over to Pat, I need to remind you that some of the information provided this morning should be considered forward-looking statements pursuant to the Private Securities Litigation Reform Act of 1995. We caution you that all of the forward-looking statements are based upon current expectations and estimates and that PNM Resources assumes no obligation to update this information. For a detailed discussion of factors affecting PNM Resources' results, please refer to our current and future annual reports on Form 10-K, quarterly reports on Form 10-Q, as well as reports on Form 8-K filed with the SEC. With that, I will turn the call over to Pat.

Thank you, Lisa. Good morning everyone, and thank you for joining us today. Our socially distance skeleton crew today the tier is safe and healthy, and we sincerely hope that that is the case for you, your teams and your loved ones. I know, it's unusual for me to start on such a serious note, but these are certainly unusual times. One thing, I've been told is that it helps to get some normalcy to hold on to any sense of routine. So in that spirit, we're holding our previously scheduled earnings call today, even though we provided our earnings results earlier this month to provide transparency on COVID-19 impacts in the first quarter. Today is May 1st, which is obviously May Day, but I've also prepared a list of things that might help you out if you're continuing to stay at home in May. I know a lot of you have been cooking some more, so I have some menu planning options for you. May is National Barbecue month, National Egg month, Hamburger month, Salad month, Salsa month and Strawberry month. If I were you, I'd spread it out and not try all those things in one meal. So that is about the only thing that's going to be similar to our usual earnings call this morning. Nothing has changed in the earnings results that we reported on April 13. Our typical earnings slides are in the appendix, but we aren't planning to cover those today. You can reach out to Lisa with any questions. I know she enjoys hearing from you all. Instead today, we will provide you with an update on the COVID-19 impacts that, we've seen across our service territory, what we're doing to help manage those impacts for our customers, our communities and our company and how we are moving forward on regulatory items, and our key strategic initiatives. So let's begin on slide 4. COVID-19 has reminded us just how essential electricity is to our lives, whether we're talking about electricity at hospitals or at our homes. It's also reminded us as a company that our communities look to us for more than just that electricity. We have been a proud partner of local economic development efforts and both the company and our employees have donated money and time to various non-profits across New Mexico and Texas, who need us now more than ever. Our team has not disappointed. Not only have they transitioned to changing work environments, they continue to go above and beyond to help those in need. They are truly our most important assets and this is why their safety is our top priority. We know that power lines bring electricity to customers, but we rely on our team to do everything from maintaining those lines, to working closely with customers, to find a payment solution. It's our team that develops creative solutions to bring before our regulators and that dives into resource modeling to figure out, how we can achieve our environmental goals. They remain focused on our essential operations and move us forward even when much of the world has paused. There's no question, why their safety is my top priority and not just during this pandemic. We're doing a lot of the same things that other utilities across the country are doing and our utility network is a great resource for sharing best practices for business continuity plans and pandemic protocols that we all hoped, we would never have to use. We're limiting access to critical control rooms, staging backups and minimizing employee exposure. In New Mexico, the governor is looking to begin a gradual and safe reopening. Three of our PNM team members are participating on subcommittees for the governor's economic recovery council to help determine the best approach for reopening our state. In Texas, a Phase three opening is already beginning. While many of our employees are considered critical for our essential operations and are leaving their homes each day for work, other employees are working from home, while trying to balance child care and online education. Regardless of the situation, we've recognized that our folks need flexibility to care for their families and we have made the necessary job arrangements to facilitate this right now. We're extending that same flexibility to our customers also. In Texas, we worked with regulators to develop a program that puts customer protections in place across the ERCOT market. In New Mexico, we are working with customers individually to create more flexible payment plans. We're utilizing our foundation to provide grants to non-profits and we're doing things like purchasing large takeout orders from local restaurants to deliver to first responders. We've delivered masks and meals and especially in the areas of the state that have been hit the hardest. And we're keeping the power on. We're staying in close contact with vendors and suppliers to ensure that we'll have the materials we need to maintain our own system reliability at the same time working to make sure efforts are coordinated regionally and across the entire industry. Before I move on, I have to say our teams have executed our business continuity plans perfectly. I continue to stand in amazement as I watch what they have accomplished. Turning to slide five, we've also revisited our regulatory plans for filing a general rate review in the second quarter. A full rate review would result in increases to customer rates to reflect our planned capital expenditures and rate base under a future test year, inflationary costs, and true-up recovery on our current investments. However, given the challenges that customers are facing in this pandemic, this doesn't make a lot of sense right now for our customer-focused business. So, instead we've narrowed our current focus to the critical ratemaking components that are important to the long-term financial health of the utility. We are planning to file in May for a full decoupling mechanism for residential and small commercial customers. This will help to correct the fluctuations in recovery of our fixed costs and address the shortfalls inherent in our current ratemaking. Assuming the commission works with us to address this critical ratemaking issue, we can subsequently hold off and look to a more appropriate time to address the other components of a full rate review when there is greater certainty around COVID-19 impacts. We've also joined with other utilities in New Mexico to ask the commission permission to track and defer COVID-19 costs that are incurred. This is consistent with orders from other commissions across the country. Recovery of these costs would be determined in a future rate review. At TNMP, I've already mentioned the electricity relief program that supports the entire ERCOT system by creating an initial fund to keep retail electric providers solvent while providing bill reprieves to customers in need. We're also making use of the recovery mechanisms in Texas that encourage investment without the need for a full general rate review. We received approval for our first 2020 transmission cost of service filing and implemented the approved rates in March. We made our first distribution cost of service filing in early April with rates expected to be implemented in September. On slide six, we continue to focus on executing our strategic initiative to transform PNM generation to be emissions-free by 2040. A foundation of cost-effective baseload resources continues to be important to meet the amount of demand that is constant on our system. Beyond that amount there is increasing value for flexible resources that can be adjusted up or down based on usage patterns. As we work to transform our portfolio, we will be balancing that level of baseload resources that are needed for reliability with the availability of low-cost renewables and other flexible cleaner resources. Our plans will not only meet the state's growing renewable portfolio they will also have real savings for customers and real environmental benefits. By utilizing the Energy Transition Act, we can further those customer savings through securitization financing and we can also provide some financial relief to the individuals and communities that are impacted by the closure of coal plants. The New Mexico Commission approved the abandonment and securitization of the San Juan Generating Station on April one and now they are working on determining the replacement power portfolio. The hearing examiners have brought forth a proposal to separate the replacement power into two parts. And in the first part they recommended approval for the two hybrid solar and storage PPAs that were included in our proposed replacement resource scenario. While these contracts had overwhelming support from the parties, the commission determined that they should wait to consider a recommended decision from the hearing examiners on a full replacement power scenario. The hearing examiners previously indicated they would have a recommended decision on the remaining proposed resources by the end of June. Next, we'll look to eliminate the last of our coal ownership by exiting the Four Corners Power Plant. While the current ownership and coal supply agreements do not expire until 2031, we've made it clear that we are looking at opportunities to exit sooner. The remaining lease capacity that we have at Palo Verde provides another opportunity to evaluate current baseload generation resources against flexible lower-cost resources. We will look to decide on the 114 megawatts of our remaining lease capacity in Palo Verde within the coming months. Each of these items provides us with an opportunity to provide benefits to our customers, communities and the environment. With that, I'm going to turn the presentation over to Chuck to talk about our scenario analysis and financial planning in light of COVID-19. And then Don will provide some more information about how we are managing those impacts. Chuck?

Thank you, Pat and good morning, everyone. I'll get started on slide 8 with a reminder of the scenario analysis that we introduced back in March. We're looking at COVID-19 through three different stages based on how long the environment lasts and the level of impacts that we're seeing. So starting with stage one is where we currently are. We certainly see some changes in load patterns across our customer class as stay-at-home orders and other restrictions are in place. We're not experiencing any significant workforce disruptions due to absenteeism nor any disruptions in our supply chain needed to keep our projects plans in place. In stage two, we analyze the business under the assumption that the impacts of stage one continue to trend into the summer months of June and July, when the largest portion of our earnings are generated by higher customer usage and also seasonal rates in New Mexico. And of course in stage three, we assume that after strict state restrictions are lifted the economy does not return to a normal level and we are left with very slow recovery resulting in reduced usage across both our utilities. In this stage, we believe that we could also see changes in our capital plans stemming from disruptions to our supply chain. Now let's turn to slide 10. In March, we provided transparency into scenario analysis. In mid-April, we came out early with our Q1 results and March load trends associated with COVID-19. Now that we're ending April, our first full month under COVID-19 restrictions, we're providing you with more recent trends and updates in our analysis. We are lined up with some virtual investor conferences in early June so expect to be back in another month with the continued updates into what we are seeing in our business. Summer temperatures will really be key to how things shape up over the coming months and how we phase in our cost contingency plans and we will continue to evaluate results and communicate with you. So don't be alarmed if we're providing more updates than usual. We believe that we can all benefit from frequent and transparent communication at this time. Now moving on to slide 10. I want to emphasize that our business fundamentals continue to remain intact through this pandemic. We are targeting 8.9% rate base growth through 2023 based on our capital investment plans. Our typical capital slide is in the appendix. And while there have not been any significant changes, I will note that PNM T&D capital increased by a small amount again this quarter to facilitate new customers still expected to come online this year. We continually evaluate our capital needs to ensure safe and reliable service and balance those needs with the impacts on customer rates. Part of this process is an allocation of capital between our generation and T&D business. If changes to our San Juan replacement power plants or any other items were to free up additional capital, we would be able to rebalance those priorities and allocate additional dollars to T&D projects that have been put on hold and bring them into our plans. In Texas, we continue to see new service requests across the service territory that play into ERCOT Regional Planning Group's assessment for future transition system needs and we're not anticipating any changes to our capital plans at TNMP. In particular, we have received a number of questions about West Texas due to oil and gas prices. We continue to monitor and evaluate the situation across our service territory. And capital projects for the region are largely tied to ERCOT's regional transmission planning groups to take a longer-term view of the region. We have very few capital projects that are specific to individual customers. And if those were to change, we have the opportunity to utilize that capital across the business. We have also targeted 5% to 6% earnings growth through 2023. Our earnings power slide is included in the appendix without any changes since our last call. We may see some adjustments in the earlier years that you would expect from the change in our rate case plans at PNM, which will be offset by some recovery of fixed costs through decoupling. Our plans continue to support our long-term view and growth target. For the current year, we're affirming 2020 guidance and Don will walk through those assumptions. We have a proven history of maintaining flexible financing plans and that we can responsive to changes in weather and load changes like we are seeing in COVID-19. We'll walk -- we'll talk through these plans as we've moved through the year. Our dividend growth is expected to mirror earnings growth. Our Board of Directors declares a dividend quarterly, but they maintain a long-term view of the business when considering changes to the annual dividend in December of each year. We do not anticipate any changes to our long-term earnings growth or liquidity situations. So there's no need to reevaluate the dividend. Sufficient liquidity is important during times of uncertainty and we have taken steps to secure a position to support the long-term needs of the business. Our forward equity offering in January and the completion of our financing plans in April have contributed to our strong liquidity position. Now turning to Slide 11, shows $1.2 billion we have available under our multiyear revolving credit facilities cash balances and the forward equity, which could be drawn down before December if necessary. By assessing the capital market – accessing the capital market in April at both PNM and TNMP, we were able to pay down our short-term balances and fund capital investments with these new facilities while keeping our $1 billion of liquidity available. Now turning to Slide 12, highlights our financial areas of focus as we navigate the impacts of COVID-19. Don will walk through each of these scenarios a little more detail. For guidance, we will talk about how we are mitigating the impacts of load trends as we work through each stage. We'll continue to monitor load trends and provide updates to what we're seeing in the projected impacts to earnings. We'll pursue appropriate regulatory pass to account for incremental COVID-19 costs along with the recovery investments in ways that support our customers. These areas require attention and we'll continue to focus on ways to navigate the current environment without losing sight of long-term goals and strategic direction that support customers and communities and provide shareholder value. Don I'll turn it over to you now.

Thanks, Chuck and good morning, everyone. I'll pick up on Slide 14, with a discussion on how we are thinking about earnings guidance for this year. We are affirming our guidance range of $2.16 to $2.26 per share based on the current state guidelines and the COVID-19 stage one impacts that we have assumed. On the left-hand side, you will see the monthly EPS impacts that we expect for changes in load from COVID-19. While we started to see some offsetting trends in how our different customer classes use energy in March, the net impacts only reflect part of the month and were not significant to first quarter earnings. April was the first full month under the stay-at-home orders in New Mexico and Texas. And we begin to see a better picture of low trends. At PNM, overall load is coming in lower while at TNMP we are seeing increase in volumetric load that largely offsets decreases from demand-based customers. Based on these trends, we would expect to see a $0.04 impact over April and May. On the right-hand side you can see some of the offsetting impacts that give us some comfort within the guidance range at this stage. We've been able to take advantage of lower interest rates in the market and overall reduced financing costs. We also had a relatively normal weather in the first quarter and we have begun to experience some warmer days in both New Mexico and Texas in April, which will also help to offset the load impacts. We've been able to hold our O&M costs flat through this period and built contingency plans to work from as we move throughout the year. As we think about moving into Stage two, the expected EPS impact for load are bigger because customers use more energy as we get into warmer months and higher seasonal rates begin in June at PNM. As Chuck mentioned, monitoring the weather and the total impacts to load during the second quarter will be key to our decision-making, as a hotter summer can make a big difference. We'll also consider any decisions that the New Mexico Commission makes on our request to defer incremental COVID-related costs to a regulatory asset. Based on these outcomes we may need to actively move towards phasing in our cost contingency plans. Obviously, if all these things work against us or we see more decreases to load beyond the trends we've identified, it may become difficult to manage the low end of the guidance range. On the other side of things, we would see load patterns that start to trend back up, some businesses reopen and a hot summer could mean that we are able to balance these pickups against any contingency plans that we've developed. We are not in a position to predict how things may progress with COVID-19. However, we have provided the transparency into our analysis and we will continue to provide updates as we work through each month and additional trends develop. Turning to Slide 15. I'll talk more about the load trends that we have seen in April. We have already layered these into the scenario analysis that I've covered on the last slide. April was the first full month of the stay-at-home restrictions and business limitations. In New Mexico, we saw load trending lower than our original Stage one projection. Residential customers showed higher usage as expected and so we have maintained the expectation for their usage to remain at an increase of 5%. Commercial customers on the other hand saw greater impacts as the state restrictions reduced operations for certain businesses and resulted in full closures for others. We have updated our expectations for the commercial class usage in our analysis to 15% reduction compared to the 10% we were previously assuming in Stage 1. The rule of thumb per load impacts to New Mexico is that a 10% change in either residential or commercial load equates to a $0.02 monthly impact in April and May. This increases to a $0.03 to $0.04 impact in the months of June through September based on the higher volumes and rates during these months. You can find this information in the appendix. In Texas, data coming out of ERCOT supports our analysis that overall load has not been impacted as strongly as we anticipated. We've updated our assumptions for demand-based load to a reduction of only 5% versus the 10% we were previously assuming, as we've not seen as large a decline in demands in April. We've maintained our assumption for a 5% increase in volumetric load, which is primarily residential customers. The rule of thumb for Texas load is that a 10% change in either volumetric or demand-based load equates to $0.01 of monthly EPS. The volumetric amount increases to $0.02 per month during June through September due to high volumes during these summer months. We would expect that the load impacts at TNMP will remain steady or improve slightly as the phased reopening of businesses begin. As we work through the following slides, I'll provide some additional color on how to think about impacts for each region of our service territory. We will continue to monitor the trends and load and incorporate any changes into our analysis as we communicate with you around current year guidance. Warmer temperatures could provide some additional comfort to our range and we would have better visibility on this in the latter part of Stage 2. Now let's turn to slide 16 for a look at New Mexico's profile. The state's largest employers include government and health care industry, and the economy also includes a large presence of small and local businesses. As you might expect, this means lower load coming from certain customers and steady load coming from others. As Pat mentioned earlier, the governor is planning for a gradual and safe reopening, so we will see different stages of reopening for different sectors. I do want to point out that the construction industry has been considered essential business from the start allowing for building permits to be issued and projects to move forward. Our residential customers comprise the largest percentage of our revenues at 46% and have increased their usage based on the stay-at-home order. Commercial customers, especially our small business are the ones whose load has been negatively impacted by restrictions, as businesses across the state have been limiting operations or closed their doors during this time. Industrial load only provides 10% of our revenues, as they have significant lower rates tied to their higher usage per customer and we have not identified any impacts to their usage based on COVID-19. These customers include semiconductor manufacturing and data center operations that are considered essential services and have not had to reduce operations. As Pat mentioned earlier, fluctuations in load at PNM can lead to challenges in recovery in the fixed cost of the business. While our filing for decoupling will not address the immediate impacts of changes in load due to COVID-19, it is important to address this issue for the long term and work to remove some uncertainty from our business. Now turning to slide 17. Our Texas service territory is well diversified in geographic location type of customer as well as the type of rate mechanisms that are used to recovery our investments. Our transmission recovery mechanism reduces the exposure to changes in load and demand. 45% of the TNMP revenue in 2019 were related to recovery of our transmission investments and expense. Wholesale transmission revenues are approved through TCOS filings and recovery over transmission investments. Any changes in demand would be included in the next TCOS filing, therefore minimizing load impacts and overall regulatory lag. The remaining portions of the transmission revenue provides for recovery of transmission expense billed to TNMP by other T&D providers. This revenue is collected under our rate rider which is trued up twice a year eliminating any regulatory lag. The remaining 55% of TNMP's revenue represents non-transmission charges from retail customers. These customers are split about equally between those that are billed per kilowatt hour and the other half that is billed based on peak demand usage. The majority of customers billed on peak demand also have a billing ratchet within their rates. And they are billed on the greater of their demand for the current month or 80% of the peak over the previous 11 months, which helps ensure our fixed costs are being recovered. Also as Pat mentioned, we filed our first DCOS filing in Texas in April. The filing requested an increase to our distribution rates of $14.7 million. This rate mechanism allows us to true up our distribution rates for new investments and load impacts related to the previous year. We expect those rates to go into effect in September. These considerations and rate mechanisms tell us that changes in load in Texas don't necessarily equate to the same change in revenues. The regional breakout on the map shows that 35% of our revenues come from the North and Central region of Texas with 50% coming from the Gulf Coast region and only 15% from West Texas. I also wanted to note that the stay-at-home order in Texas expired yesterday and businesses will begin to reopen at limited capacity. Texas also deemed construction business as essential allowing for projects across the state to continue over the last several weeks. Now let's turn to slide 18 and I'll walk you through the load and economic considerations for each of these regions beginning with West Texas. This region has been in the headlines lately and is known for its oil and gas productions. I wanted to emphasize that the 15% of revenues that come from this region half of that amount comes from transmission recovery that is trued up semiannually. In addition, 25% of the revenues from West Texas are from customers taking high-voltage service and we continue to see their peak demands trend higher than 2019 levels. Recent oil and gas prices have dropped to record lows and we've seen the headlines from companies that are making changes to their plans for the year. While much of this region is tied to oil and gas industry not all of our customers are producers. For those that are in the Delaware Basin a specific area within the Permian Basin continue to have one of the lowest breakeven points in the country. Many operators here do not have utility service and efforts to electrify the area will further reduce their production costs. As Chuck mentioned earlier capital projects for this region are mostly tied to ERCOT's regional transmission planning initiatives that take a longer-term view of the region. We've had very few capital projects that are specific to individual customers. And if those were to change we have other opportunities to utilize those resources across the business. Moving on to Slide 19 and the region of TNMP service territory in North and Central Texas, we have a very different customer mix. The city of Dallas and Fort Worth do not fall within our service territory but those cities have grown so large over time that we have seen significant sprawl from people moving out to the surrounding cities which do fall within our service territory. As those communities have built out we have a pretty even mix of revenues from residential customers and revenues from communities and businesses that support these residents. From a COVID-19 perspective, we see offsetting impacts as volumetric increases as people stay at home and demand load decline as some businesses are restricted. The Gulf Coast region shown on Slide 20 is often tied to the Houston oil refinery economy, not all of our largest customers are refineries though. The region also has several large petrochemical companies that ultimately lead to the production of everything from chewing gum and cleaners to plastic and surf boards. The TNMP region actually has our largest portion of residential customers has sprawl from Houston has moved into our service territory similar to the situations around Dallas. 60% of the region's revenues come from residential customers who have been staying at home and using more energy. The rest are mostly larger businesses some that fall into the rate classes that are trending down and some that are trending at a steady level. For example the petrochemical companies have boosted their production of chemicals used in medical PPE and hand sanitizers. We hope that in detail -- we hope that this detail provides you with a better picture of what makes up our TNMP business in each of the regions and how they are offsetting factors that keep us from experiencing an immediate negative impact on the business in the current environment. Now let's turn to Slide 21 where I'll address bad debt considerations. PNM was part of a joint filing on Monday with other utilities in New Mexico to request the incremental costs related to COVID-19 being tracked and deferred into a regulatory asset. At the Commission's open meeting on Wednesday commissioners recognize that there would be a financial impact from the ongoing situation for utilities that they regulate and noted that other states were taking action to track and account for additional costs bad debt expense and lost revenues. They expressed support for taking action to ensure that utilities are able to provide support to customers, so that more flexible payment arrangements could be offered. So we will be watching that docket over the next month. We have been reaching out to customers to ensure that they know how to access any support that is available to them and for the customers that are impacted by the pandemic to talk with them about the type of payment arrangements that fit their individual situations. In the event that we do ultimately see increases to bad debt expense at PNM we currently estimate them to be in the range of $0.01 to $0.02 on an annual basis for Stage one and two as our percentage of bad debt has been under 0.5% of revenue in historical years. In Texas the risk of bad debt at TNMP has been mitigated by COVID-19 electricity relief program that the PUCT quickly implemented in late March. Keep in mind that TNMP's customers are technically the retail electric providers who receive payments from end users. Under a PUCT order TNMP is also tracking and deferring other costs related to COVID-19. I'll wrap up on Slide 22 with the decoupling filing that PNM plans to make in May in lieu of a general rate case this year. This would be a full revenue decoupling for residential and small commercial customers meaning that any change in usage is trued up to predetermined levels. We would request an order by the end of the implementation at the beginning of 2021 which we believe is reasonable. Under the proposal the difference between the authorized revenues needed to recover our fixed costs based on a cost per customer and the actual revenues collected based on customer usage will be trued up. This better aligns rates with fixed costs of our business and provides some separation of our revenues from the fluctuating amount customers use each month. Currently over 90% of the cost to serve PNM residential customers is fixed, but only about 12% of the fixed cost is collected through a customer charge with the remainder collected under a volumetric rate. Similarly for PNM small power customers over 90% of the cost is fixed but only 10% of the fixed cost is collected through customer charge. The decoupling proposal addresses this disparity and ensures that the fixed cost portion of these customer bills are recovered. Our other classes of PNM's customers already have a demand component in their rates so they're already recovering a large portion of their fixed costs. By ensuring that our fixed costs will be recovered we will be in a better position to promote energy efficiency or conservation programs that reduce customers' variable costs that would otherwise impact our ability to earn our authorized return. To emphasize Pat's earlier point, we are opting to make this filing instead of a full rate review because it's a much better solution for customers in light of the challenges created by COVID-19. As Chuck indicated, this will obviously create some fluctuations in the trajectory of our earnings growth in the near term, but it does not change our focus our ability to meet our targeted earnings growth of 5% to 6% through 2023. With that I'll turn it over to you Pat.

Thanks Don. Before I open it up for questions, I want to again thank all of our team members here at PNM Resources, PNM and TNMP for the resilience and dedication that they have shown through all of us. There will be brighter days ahead and we'll get through all of these challenges and come out even stronger. There will certainly be some lasting impacts and changes to the way we work, but eventually we will return to our offices, stores, restaurants and bars. So, Jason, let's open it up for questions.

Thank you. [Operator Instructions] The first question comes from Julien Dumoulin-Smith of Bank of America. Please go ahead.

Hi. Good morning team. I hope you are all doing well.

Good morning, Julien. Hopefully you are too.

Thank you. Indeed. So if I can start out what's the history of the Commission with respect to decoupling? Can you give us a little bit of context as to the background for filing for decoupling at present? And then subsequently kind of from the same line how do you think about this fitting into a wider eventual rate case there as been well?

Yes. And Julien, I'll give you a little history here and then I'll let Don talk about decoupling. When the Efficient Use of Energy Act was passed and then amended, it called for the use of decoupling to help encourage us to promote energy efficiency and conservation and it actually had language in there specifically saying that we couldn't have an ROE deduct for that. And so that's the basis on which we're looking at it. And we've talked about decoupling before with the Commission, but we've never really had with staff. We've never really had any evidence of load loss, because there was a little bit after the financial crisis and then we grew again. And now we have the situation. Staff had always said well let's see some load loss. So it's kind of the background of it. And the gas company has a modified decoupling here. So they do have experience with it. So, we have Don sort of talk to you about how this fits in with a wider rate filing.

Yes. Good morning, Julien. We're still in the process of developing a filing as we talked about and we will file that at the end of May. But to give you kind of a little bit of an example, I mean, as Pat alluded the legislation does provide that the Commission not reduce ROE for decoupling which is a good thing. To kind of give you a feel of impact as this flows through and kind of give you an example, we would seek approval to happen by January 1. If you've kind of think a little bit about the rate case, that approval would have happened and rates would have gone into effect the midyear of 2021. And a little bit of feeling of how it work is, if you look back at our 2015 rate case, which was our last fully litigated cost of service, we've seen a decrease in our use per customer on the residential front from there to now of about 4% to 5%. And this is driven by energy efficiency and rooftop solar. So if you kind of try to get a model or mindset to this and you kind of look at that decline, that would be about a $2 to $3 impact per our month per our residential customers. And so if you take our 470,000 customers you'd look at a range of decoupling in the range of about $11 million to $17 million just looking at how that shifted due to use per customer since 2015.

Got it. If I can follow-up a little bit, how do you think about this? You've always pretty been very thoughtful and a leader in providing disclosure across the industry frankly. But how do you think about decoupling in 2021 relative to the different stages that you could see a load loss in 2020 here, i.e. to what extent would that help roll back some of the more acute impacts that you could see in 2020 and limit them from being ongoing impact? How would you frame that if you will given the time line for limitation next year? And some great impact.

I think Julien, and if I don't answer your question please let me know is that, obviously, the decoupling in 2021 doesn't do anything for us in 2020 and we will work to manage if we have impacts in terms of O&M cuts. I can tell you Chuck is doing his part. His expense report for April was only $36.99. So we are set for the rest of the year in cost reductions. But it would allow us to keep investing as we go forward and to keep our capital plans up and recover what we are putting in our system just, because of the way that fixed and variable costs are set as Don said. And we are still seeing a fair amount of construction here. So we will still have new customers coming online but it will protect us against that what I think is a permanent decrease in use per customer that started long before COVID-19 just given stronger buildings and codes and better appliances and energy efficiency programs. Is that what you're looking for?

Yes. I mean, some level of confidence on earned returns in 2021 as well. The converse of that right? So as bad as it could get in 2020 Stage II, Stage III, you could see some of that roll back in 2021 based on these new rates under a decoupling mechanism potentially. Again the exact details pending.

Yeah. And Julien, kind of, walk through a little bit on earned returns and EPS. We haven't come up with guidance or came out with guidance for 2021 yet. We usually do that in December. But again as you think of the frame of reference, you would think if decoupling is approved and goes into place in January, the rate case would have came in, in midyear. There's some benefits as you look at the timing of those elements associated with it, so…

Got it. Super quick last question if I can. There's, obviously, been a lot of noise about your replacement power dockets pending. What's your confidence as it stands right now that say by October, we get clarity about your ownership piece in whatever is to be done? And I'll leave it as broadly as that.

Okay. Julien, we're very confident about getting that decision. One could argue for looking at the portfolio as a whole, which is what the commissioners decided they wanted to do or pulling those two PPAs out. But from where we sit a PNM perspective, looking at it as a whole makes a lot of sense. The hearing examiners have talked about having that second piece out in June, which -- but now that will also include those PPAs. And that gives the commission plenty of time to take a look at that portfolio. And one of the things that we were pleased about in the commission's discussion, is that they were talking about potentially reopening and rebidding the case and that would have harmed our ability to get those replacement power in on time. And they decided not to do that. And so we think that is a very good sign that they're going to look at the portfolio or the different portfolios that we have submitted as we submitted multiple portfolios and decide on one of those in the appropriate time frame. I think they just wanted to look at the whole picture at one point in time as opposed to bifurcating it.

Excellent. Thank you.

Thank you, Julien.

The next question comes from Durgesh Chopra from Evercore ISI. Please go ahead.

Hey, good morning team. I want to compliment you the detail on TNMP is just super. Thanks for putting that out there. Can I just ask you and I appreciate the peak charge and minimal impact to revenue, but in terms of just the demand trends, can you quantify what are you seeing in terms of demand drag or demand destruction in West Texas and the Gulf Coast areas?

Sure, and good morning Durgesh. I'll have Don take that one for you.

Yeah. So our demand categories in West Texas are large demand customers. We call them our primary customers and we've seen no demand decreases there. In fact they're continuing to produce well and load continues to go up. Our demand continues to go up in those. It's really been those small commercial type demand customers and that's been in that range that we quantified at about 5%. That's being offset by factors associated with -- on the residential side. So we've seen a pretty direct offset between the residential and the smaller demand.

And I think ERCOT set a record peak this last week.

Got it. Thank you. And then maybe, can I ask you in terms of, obviously, if you get into Stages II or III here and it looks like the rate case might get delayed. How are you thinking about the impacts on your credit metrics? And if you've had any conversations with the credit agencies, would love any color from those conversations.

Yeah, Durgesh we're not filing the rate case. We're moving to the decoupling mechanism that we've talked a little bit about. We have ongoing discussions with the rating agencies and walk them through our financial metrics. We just completed a significant amount of financings that lifted our liquidity or positions us well that Chuck alluded to on our liquidity. So we're in good shape from that perspective.

Okay. Thanks guys. That’s all I had. Thank you.

Thank you.

The next question comes from Paul Fremont from Mizuho. Please go ahead.

Good morning, Paul.

Morning. During the NMPRC, sort of, deliberation on your bifurcation request, I mean, it sounded like they were giving more weight to the Energy Transition Act requirement that replacement resources be built in the San Juan District. So if we, sort of, rule out the gasified coal as being really expensive, really environmentally unfriendly and also not necessarily financeable, wouldn't that imply the only alternative that would fit that scenario would be your Scenario 2, which is to build essentially all gas? So wouldn't the alternative potentially result in more rate base and more investment for the company?

So Paul I think from their discussion, it sounded like they were describing a scenario I would say similar to Scenario 2. There could be some tweaks on it and maybe a little more solar up there. But, yes, I think our take of the discussion is that they were putting more weight while the Energy Transition Act's up to, and that there's a preference for I think what I heard the three commissioners expressing was a strong preference for.

Okay. And then, assuming that the modified WRA proposal were to be adopted, what would be the effect on your capital spend and also sort of on your rate base?

The modified WRA proposal that has more gas and some more solar, Don?

Yeah. So, I think it -- modified proposal decreases a couple of units of LM6000s. So I think the way to think about those LM6000s is there are about 25 million per LM6000 related to that. So I mean that would kind of be the balance. You'd see the adjustment. As Chuck alluded to, that we always balance customer rates with additional transmission and distribution projects that we could -- we can align as well to fill the gap associated with that that they're there ready to go.

And then, I guess the last question is sort of confusing with earnings power charts that the sort of the distribution of the numbers and the numbers keep changing from quarter-to-quarter. Can you sort of discuss that at all? Like in 2022, it looks like the numbers are down a little bit. The relationship between corporate and the financing are completely different than the chart that you put out sort of at the fourth quarter.

Paul, maybe -- this is Chuck. It might be better just to talk at least...

Take that off-line? That's fine.

Yeah. Because it's -- we're reconciling some numbers, and that we want to be sure we're clear on what you're looking at and how we can get to an understanding. So let's just take that off-line. And then if there's anything...

No problem, no problem.

Appreciate. Okay. And also I want to add too that in scenario two, you talked about the rate base piece of it just checking the numbers here. It does have the all-gas scenario 440 megawatts of gas versus the combination of gas and battery storage. The scenario one that we recommended is a $298 million rate base add and then the all-gas in one location of 440 megawatts of gas is $304 million. So it's still very close, because the battery storage costs are higher. So I think it doesn't have a whole lot of difference in the standpoint of rate base. I don't want to give any perspectives that they had a rate base is going to be that significant if they go down that path.

Got it. Okay. Thank you.

Thanks Paul. Lisa needs the company. So give her a call.

Okay.

The next question comes from Jonathan Reeder from Wells Fargo. Please go ahead.

Hey, all. Most of my have been answered, but I just wanted to clarify a couple of things. Are the monthly impacts in the Stage 2 and three on slide 14, is that an assumption of full stay-at-home order?

Jon, can you -- it's Pat. Good morning. You broke up kind of on the last part. Would you repeat your last sentence?

Yes. I just wanted to -- full stay-at-home order in the Stage 2 and 3 monthly impacts on slide 14?

Sure. So you're asking if the full stay-at-home orders are in scenarios two and three.

In scenarios two and three, yeah, the sensitivity slide 14. Is that assuming a full stay-at-home order?

Jonathan, good morning. For stage two, it would assume a full stay-at-home order and stage three would assume that we go more into a recession mode and businesses are slow to open all the way through the end of the year.

And stage three also kind of envisions a second wave. I mean we all know I think we're going to have a little bit of an uptick in cases when it opens but stage three would envision the fact that it's a significant uptick in cases.

Okay. Yeah. So I mean obviously now with Texas doing a partial reopening and New Mexico talking about it, it seems like you're kind of ahead of anything contemplated in like a stage two scenario?

Yeah. And I think the Governor here is doing a slow reopening. She's reopening the greater parts of the state faster. Unfortunately, a concentration of the cases here in New Mexico are in the Northwest corner where the nation and some of the pueblos and the tribe is. And I think as Don mentioned, we've still been doing construction here. And when I go out for a drive, there's a lot of construction going on here. So I think when we open again and people can move into those spaces, it will be very helpful for us. So...

Okay. And then, the other thing just the modified load impact assumption relative to the original expectations, essentially the higher commercial reductions in New Mexico essentially being offset by the Texas land-based load not being down as much. I mean it kind of sounds like those two almost trade-off from what you're originally thinking.

Yeah. So Texas came down aligned on the residential side in Texas. So we see almost a direct offset in Texas between residential and commercial. On the PNM side, on the New Mexico side, we did see an increase of about 5% up to 15%, total 15% on the small commercial and commercial sector. And our residential state is at 5% in New Mexico. That's what we're seeing in April.

Okay. But the net-net impact to like consolidated PNM. It's a little bit of a headwind overall, but not much?

Yes. It's aligned with the numbers that we have on 14 Jonathan. So...

Yeah. Okay. All right. Great. Thanks so for the additional data. I appreciate it.

Thanks, Jonathan.

[Operator Instructions] The next question comes from Paul Patterson from Glenrock Associates. Please go ahead.

Hey, good morning.

Good morning, Paul.

So, just, I wanted to follow up on Paul Fremont's questions with respect to CapEx. Just on the -- how much of this might be economically sensitive, I guess? And how do you see the economy being impacted? I know its early days and it's unprecedented, so I take it with a grain of salt, but just sort of a sense as to what you guys are feeling there on the ground in terms of the economic outlook. And just, if you could, sort of, remind us sort of what the sensitivity CapEx might be -- that might be economically sensitive, if you follow me.

Yes. And, Paul, our CapEx really isn't economically sensitive. The replacement power is mostly for the nice flexible resources, the renewable resources and the stuff that replaces San Juan. And the day San Juan goes out of rate base and the new resources coming in, customers see a decrease in the bills, because we're securitizing San Juan. Our construction here in New Mexico is for new customers and there is still economic development going on out here. There's some projects that have started that just haven't been announced. And replacing of aging infrastructure here and building some of that transmission. And in Texas, as Don said, most of our capital there is because of ERCOT and its reliability. The last time I was out in -- for this, I started with the Commission in Texas, they encourage us to keep building and doing that because they want to make sure that when customers come, they've got it ready. And then as Don said, a lot of it in West Texas is folks that want to electrify. So it's really not sensitive to the economy.

Okay, great. And then, with respect to -- I know you guys are looking for deferrals and everything, but with respect to like your experience so far on sort of re-urgence and stuff, could you give us a little bit of a flavor with respect to customer -- which is for the commercial and residential deal-paying activities so far?

Yes. So, I mean, we're no disconnect at this point in New Mexico. Again, you alluded to it and we talked about it. We filed with the Commission with all the other utilities, the publicly held utilities in the state, to be able to defer those costs as well as other costs associated with it. And listening to the Commission hearing, they seem very receptive to that because what that allows is flexible payment arrangements as we work with customers. And our customer service group is outreaching on a daily basis to align folks up with payments. We have seen an increase in our -- in the utility we break it down to 30, 60, 90 and you don't write off until 120, because you have the ability to turn off. And a lot of times folks will pay during that window. So we have seen an increase associated with that, which we expected. And it's in line with our assumptions that we've been monitoring. And we've talked a little bit about, if it goes to stage one and stage two, we'd see $0.01 impact for stage one and another $0.01 impact for stage two. So that kind of gives you a feel of how we're monitoring and working through the bad debt.

So just in general, how many like residential customers or what percentage would you say have now -- are not paying their bills that were as opposed to what the normal rate would be? Can you give us a flavor for that?

I don't have that number on me. We've seen it go up and my guess would be 5% or 6% would be the kind of the range that we would see. And again, I mean, the good thing about working in the utility and why utilities have such low bad debt is, they'll eventually -- once we're able to migrate into being able to disconnect, folks will get it working towards making payment arrangements and make their payments. And, historically, in New Mexico we've had very low bad debt. To give you a feel our bad debt ranges every year in total about $3 million, which is about 0.3% of our total revenues. And that's because you have the ability to be able to work with the customers. Eventually, they will pay as you move to disconnect.

And, Paul, the Commission discussion around the tracker and setting it up as a regulatory asset was very positive, because I think the Commission sees that not only is strengthening the utilities' financing, but giving us even more flexibility to work with our customers. So it was -- while they haven't acted yet, it was a very good discussion.

Great. Good to hear. Thanks so much.

Thank you.

There are no more questions in the queue. This concludes our question-and-answer session. I would like to turn the conference back over to Pat Vincent-Collawn for any closing remarks.

Thank you, Jason, and thank you all again for joining us this morning. Please stay healthy and safe and we look forward to the time when we can see you all in person again. Thank you.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.