Good day, welcome to the Xcel Energy 2018 year-end earnings call. Today's conference is being recorded. At this time, I would like to turn the conference over to Paul Johnson, Vice President of Investor Relations. Please go ahead, sir.
Good morning, welcome to Xcel Energy's 2018 year-end earnings conference call. Joining me today are Ben Fowke, Chairman, President, and Chief Executive Officer, Bob Frenzel, Executive Vice President and Chief Financial Officer. In addition, we have other members of the management team available to answer your questions. This morning, we will review our 2018 results and update you on recent business and regulatory developments. Slides that accompany today's call are available on the website. On today's call, we will discuss certain ongoing earning metrics that are non-GAAP measures. Comparable GAAP measures and a reconciliation are included in our earnings release. As a reminder, some of the comments used during today's conference call may contain forward-looking information. Significant factors that could cause results to differ from those anticipated are described in our earnings release and are filed with the SEC. I'll now turn the call over to Ben.
Well, thank you, Paul, good morning. I say good morning, as you all probably know, it is brutally cold here in Minnesota, I'd like to thank the men and women of Xcel who've worked so hard to keep the gas flowing and the electricity on over these last few days. I'd say with just a few exceptions, our system has held up remarkably well, that's due to their dedication and commitment. Thank you. 2018 was an excellent year with a long and impressive list of accomplishments. Let me share a few of them with you. We reported ongoing EPS of $2.47 in 2018, this was our 14th consecutive year of meeting or exceeding our earnings guidance. We increased our long-term EPS growth target rate to 5%-7%.
We raised our dividend by $0.08, which represents the 15th straight year we've increased our dividend. We completed our equity issuances for the five-year forecast period and don't plan any additional equity beyond our dividend reinvestment and benefit programs. Our stock hit an all-time high closing price of $53.68 in December. We secured approval for over 1,000 megawatts of new wind in Texas and New Mexico, our Colorado Energy Plan, and 300 megawatts of wind in South Dakota. We completed construction of our 600-megawatt Rush Creek wind farm on time and under budget. We reached agreements to purchase the 760-megawatt Mankato natural gas combined cycle plant for $650 million and to acquire 70 megawatts of repowered wind farms for $135 million. We expect both acquisitions to be approved later this year.
Our nuclear plants combined to achieve a capacity factor of almost 96% while reducing O&M costs by almost 3%. We filed an electric vehicle pilot program in Minnesota. We resolved tax reform proceedings in most jurisdictions with a final resolution in North Dakota expected later this year. I'm also very proud that our actions have been noticed by others, resulting in numerous awards, including being recognized by Fortune Magazine as one of the world's most admired companies for the fifth consecutive year, being honored by the Military Times as Best for Vets Employer for the fifth consecutive year, and being named Utility of the Year by Utility Dive. 2018 was a great year, but we're now focused on 2019 and beyond.
Leading the clean energy transition continues to be a strategic priority for us as we carry out Xcel Energy's vision to be our customers' preferred and trusted energy provider. Also helping us to achieve two other strategic priorities, keeping our customer bills low and enhancing the customer experience. We're a national leader in wind energy through our Steel for Fuel strategy, which adds renewables while at the same time lowering bills. As a result, we've made outstanding progress, achieving a 39% reduction in carbon emissions from 2005 levels. We want to do even more, which is why we set a vision to reduce carbon emissions by 80% by 2030. Longer term, we expect to deliver our customers 100% carbon-free energy by 2050.
These are the most ambitious carbon goals within the electric power industry, and I'm confident with supportive public policy, we can achieve the 80% interim goal while keeping our bills affordable and our product reliable. Technology's come a long way in the last ten years, and it gives me confidence that our 100% carbon-free goal can be met as well. We look forward to working with our regulators, legislators, and stakeholders to implement our plans across the jurisdictions we serve. We're also very focused on our customers. Earlier this month, we entered into agreements to provide electric service to a proposed new Google data center located on property adjacent to our Sherco plant in Minnesota. As you may remember, back in 2015, we announced our intention to close two of the Sherco coal units.
This particular location for the new data center will create jobs, bring investment to the state, and benefit all of our customers. Consistent with our goal to lead the clean energy transition, we are planning to serve the data center's energy needs with 100% renewable energy, and I believe our environmental leadership will lead to even more economic development opportunities over time. We also recently filed to expand our pilot Renewable Connect program in Minnesota. Renewable Connect allows customers to choose how much of their energy comes from renewable sources. It's been extremely popular and has commission approval in Minnesota, Colorado, and Wisconsin. This is yet another way for us to add renewable energy and meet the needs of our customers.
Importantly, Renewable Connect does not negatively impact the bills of non-participants. We anticipate that future expansions at Google and the Renewable Connect program will create potential renewable ownership opportunities for Xcel. With that, let me turn the call over to Bob, who'll provide more detail on our financial results and outlook and a regulatory update. Bob?
Thanks, Ben, and good morning, everyone. My comments today will focus on full-year 2018 results. For details of our fourth quarter results, please see our earnings release. As Ben discussed, we realized another strong year of operational and financial performance. We recorded 2018 ongoing earnings of $2.47 per share, compared with $2.30 per share in 2017, representing the top end of our original guidance range of $2.37-$2.47 per share. Weather was certainly a positive factor, contributing $0.07 per share compared to normal in our annual results. We also incurred additional O&M expense, which offset the weather benefit.
Looking at the income statement, the most significant drivers for the year include higher electric and natural gas margins, which increased earnings by $0.44 per share, largely due to favorable weather and strong electric and natural gas sales, as well as rate increases in riders to recover our capital investments. Higher AFUDC equity, which increased earnings by $0.07 per share, reflecting growth in capital investments. Partially offsetting these positive drivers were higher O&M expenses, which decreased earnings by $0.10 per share, increased D&A expense as a result of our capital investment program, which reduced earnings by $0.10 per share, and higher interest expenses, property taxes, and other items combined to reduce earnings per share by $0.14.
Turning to sales, our weather-adjusted electric sales increased 1.3% in 2018, reflecting strong economies in the states we serve and favorable sales to commercial and industrial customers, as well as solid residential sales growth. Our electric sales growth was strongest at our SPS business, with 4.1% growth, driven by the oil and natural gas sector in the Permian Basin. Weather-adjusted natural gas sales increased 2.4% in 2018 as a result of continued customer growth and increasing customer use, largely in the commercial and industrial customer segment. For 2019, we are anticipating relatively flat electric sales, which reflect some specific declines in large customer usage, more modest oil and natural gas-driven growth, and expectations of lower use per customer in the residential sector. For natural gas, we expect slightly positive sales in 2019, reflecting continued growth in C&I and residential loads.
Turning to expenses, O&M increased by $82 million, or 3.6%, reflecting additional spend for vegetation management and system maintenance due to the hot summer. Business systems costs, investments to improve and enhance business processes and customer service, as well as damage prevention and remediation costs. We remain committed to our long-term objective of improving operating efficiencies and taking costs out of the business for the benefit of our customers. While we continue to face rising costs in certain strategic areas, including the impacts of adding incremental renewable generation, improving cybersecurity, and enhancing the customer experience, we are focused on delivering 2019 O&M expenses at levels that, in aggregate, are consistent with 2017. Let me provide a quick regulatory update. We had a very busy and productive year in which we filed and resolved multiple rate cases, in addition to tax reform proceedings in all of our states.
In 2019, we're planning to file a Colorado electric case in the spring, rate cases in Texas and New Mexico in the summer, a Minnesota rate case in November, and a Minnesota resource plan in the summer. We anticipate that new rates from these cases will go into effect in 2020. With that, I'll wrap up. In summary, 2018 was another great year for Xcel Energy. We delivered ongoing earnings within or above our guidance range for the 14th consecutive year. We increased our dividend for the 15th straight year. We completed our equity issuance for the five-year time period. We continue to execute on our Steel for Fuel strategy, receiving regulatory approvals for new wind in Texas and New Mexico and South Dakota, as well as the Colorado Energy Plan.
We entered into agreements to acquire the 760-megawatt Mankato natural gas plant and buy out 70 megawatts of wind PPAs in Minnesota. We are well-positioned to deliver on our 2019 ongoing earnings guidance range of $2.55-$2.65 per share, our 5%-7% earnings growth objective, and our 5%-7% dividend growth objective. This concludes our prepared remarks, operator will now take some questions.
Thank you. If you would like to ask a question, please signal by pressing *1 on your telephone keypad. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Questions will only be taken from institutional investors. Reporters can contact Media Relations with inquiries, individual investors and others can reach out to Investor Relations. Again, it's *1 to ask a question. We'll take our first question from Julien Dumoulin-Smith of Bank of America. Please go ahead.
Hey. Good morning. Can you hear me?
Yeah, you're a little faint, but good morning, Julien.
Well, I appreciate it. Good morning. Congratulations again on the results.
Thank you.
Maybe just to touch base a little bit, I know there's a litany of different regulatory, more importantly, legislative angles for this year. Can you touch base a little bit on them by state, specifically Texas, Colorado, and the status of Minnesota? I know something just came up there as well, just to go through across the three.
There's a whole bunch of them. There's a lot of things. It's a pretty busy legislative agenda. Why don't I touch on a few that we're looking at, and if I miss one, please ask a follow-up question, Julien. Starting in Texas, of course, we're interested in the AMI legislation. That would basically allow non-ERCOT companies to get the same regulatory treatment that ERCOT companies receive. Concurrent recovery is particularly important. It's important to note there that in our CapEx, in the CapEx in the forecast period, we anticipate about $80 million spend of AMI. Wouldn't increase the capital too much there, Julien, but the recovery would be great, and we're optimistic about that. Over in New Mexico, of course, we're following the RPS standard to see where that goes and watching the securitization bill as well.
Moving up to Colorado, there is a number of different things proposed in Colorado. The securitization bill is one that we're following. Our thoughts there is, it could be another tool in the toolbox, if you will. That said, some of the things that we've already accomplished, leading the clean energy transition while keeping bills flat, taking care of our community is something I'm particularly proud of, taking care of our employees. I think we've shown we can do it and achieve pretty remarkable results. Devil's always in the details, if the securitization bills, it can become a valuable voluntary tool, that'll be great. Minnesota, there's just a number of things going around. Some of it addresses the community solar gardens. Most of the legislation, I would say, in Minnesota is in earlier stages. If there's something specific that you're interested in in Minnesota, just follow up.
Did I catch everything you're interested in, or did I miss anything, Julien?
No, I think you did. I'm more curious, as you think about some of these playing out, are there any specific capital items that are coming out of these that you would be focused on for Colorado or otherwise? I know there's a lot. That's why I wanted to get the priorities from you, if you will.
I don't know if any of those bills will drive much incremental capital. There's an EV storage bill that could be helpful to us, and would allow us to do more with basically seeding what I think is going to be a very interesting development in the future, and that's the electrification of transport. That could drive some CapEx. A little early to put anything hard dollars on the table, Julien.
Great. Just a quick clarification if I can. On the capital investment forecast at EEI, you provided an incremental case of $1 billion in additional capital.
Yep.
Obviously, you're changing around slides every update. Is there anything to read into that?
Well, I think we shifted some things from 2019 and 2020. We put the Mankato and the wind farm into our base forecast now. The overall spend is still roughly the same, I believe, in that timeframe. In those out years, we are still looking to achieve that incremental case, which would grow rate base by about 7%. I think we can get there in a number of different ways. Of course, we continue to look for opportunities to buy out PPAs and other opportunistic things. That and the fact that if you look at history, Julien, the out years tend to be more capital intensive as the out years become forward years.
Excellent. Thanks for clarifying. All done.
Thank you.
We'll now take our next question from Ali Agha of SunTrust. Please go ahead.
Morning, Ali.
Thank you. Good morning. First question. I wanted to just clarify, Ben, I think you mentioned you're expecting both the Mankato and the 70-megawatt buyout approval to happen, did you say by the third quarter? I just wanted to clarify when you're expecting that.
Yeah, Ali, I think that's a good timeline to think about. End of the second quarter, early third quarter.
Okay. With the $20.1 billion five-year CapEx, that does equate to a 6.5% rate base CAGR, as you had previously shown us. Is that correct?
Correct.
Okay. If I think about the long-term earnings goal aspiration of 5%-7%, to hit the high end of that 7%, does that assume that you would get that incremental $1 billion so that rate base could also be growing at 7%? Or do you think the high-end growth rate can be achieved just based on the CapEx as you've laid out to date?
I think the incremental CapEx would certainly be helpful. There's other levers as well. Improvement in regulatory outcomes, specifically higher ROEs. That would also be very helpful. Sales. We had a good year in 2018. We expect it to be a little bit flatter in 2019 and beyond. If we got some pickup there, that would be helpful, and of course, we continue to look for cost efficiencies in the business. There's multiple levers. The incremental CapEx just being one.
Okay. I guess looked another way, Ben, assuming you do get that incremental CapEx, we should not expect the 5%-7% growth rate to change as a result of that. That would just make it easier to perhaps hit the higher end. Is that the way to think about it?
As you know, Ali, we always take a look at that. I think what you just said is a good assumption.
My last question, can you just, I guess give a little more detail? As you mentioned, your electric load growth weather normalized was north of 1% in 2018, but you're assuming flat growth in 2019. Can you just elaborate a little bit more on why you're expecting that to slow down in 2019 versus 2018?
Yeah. Ali, we had good solid growth in 2018. A lot of it was driven by large C&I demand and some oil and gas growth in our SPS business. We think that year-over-year, we have a couple of discrete instances where we know we have lower demand from some of those C&I customers, and we don't expect as aggressive growth in the oil and gas industry as we saw in 2018. Obviously, if we had upside, as Ben mentioned, to the sales growth and some of our expectations, if we exceeded the flat forecast, it would obviously be upside for 2019 earnings.
I see. Lastly, the DRIP program, does that support about a $75 million sort of annual run rate for equity issuance? Is that good for modeling purposes?
Yeah. 75 to 85 is a good number.
Got you. Thank you.
Thanks, Ali.
Thank you. We'll now take our next question from Christopher Turnure of JPMorgan. Please go ahead.
Good morning.
Good morning, guys. I wanted to follow up on one of the earlier questions on the incremental capital plan. You mentioned PPA buyouts are one thing that you're looking at there. What's the next milestone that we might see in that process, and is there anything else that you're looking at there where we could see some kind of information nearer term?
I think we've talked about the universe of opportunities, and it's going to be obviously case by case. Our corporate development team's hard at work looking for those opportunities and making sure that there's a good deal for the buyer and seller, and just as importantly, our customers. There aren't really time frames on that, but we are optimistic that there will be transactions to talk about in the future.
Okay. On the PSCo CapEx shift to 2019 from 2020, what was behind that? When we think about modeling for 2020 and feeding in the 500 megawatts of wind from the Colorado Energy Plan, how should we model that CapEx and rate base and potentially earnings growth within the 2019 year?
Yeah, Chris, it's Bob. On the shift, when we filed our CPCN for the Colorado Energy Plan and the wind farm there, we had originally contemplated that being a build, own, transfer, where the developer would construct it and transfer it to us at COD. Through the process of the fourth quarter and negotiations with the developer, we opted to step in, buy the land and development rights, and build the project ourself. The shift in capital is just a pull forward from that wind farm. You see incremental capital in 2019 in Colorado, then probably slightly less capital in 2020 for the same wind farm.
Got you. Net between the two years, really no total change, just a pull forward of the CapEx and potentially earnings power as well.
That's right. We'd have CapEx pulled forward, AFUDC pulled forward, and slight interest expense pulled forward, but in total, in aggregate across the two years, the same amount.
Okay. Got you. Just, I guess to kind of summarize that and the impact on 2019, that looks like a positive. Since you introduced guidance at third quarter earnings, you also have the Mankato project, you have the wind repowering elsewhere, flat load growth assumption for the year, and maybe a little bit of a weather benefit, at least to kick off the year here in the first 30 days or so. Is that kind of the correct way to think about the puts and takes around guidance since you originally put it out there?
Yeah. You certainly talked about some of the upside levers actually across the entirety of the system for the month. We'll see how it comes in. The upper Midwest is certainly very cold, but the rest of our jurisdictions have been relatively benign in January.
It's going to be 40 degrees here on Sunday. That's above, not below.
Yeah, I think you hit some of the positive sensitivities for the year.
Okay, great. Thanks, guys.
We'll now take our next question from Travis Miller of Morningstar. Please go ahead.
Hi, Travis.
Good morning. Thank you. Hi.
Morning.
This is a bit of a higher-level strategy question, but I was wondering if you could give your take on the idea of the SPP transmission area westward expansion, your thoughts there.
I'm not quite sure what your question is. David, do you have No?
I guess the Mountain West Transmission Group discussions.
Oh, you're talking more about Colorado now, aren't you?
Yeah. It'd be Colorado and I believe Texas, part of your Western Texas would be involved.
You probably know, Travis, that we looked at joining Mountain West, at the end of the day, the cost-benefit analysis really didn't pencil out for the benefit of our customers the way we were hoping it would. Doesn't mean we're not open to looking at those things in the future, the math didn't work for us, at least in this round.
Okay. Would renewables be involved in that? Is that a big part of that?
It was certainly something we were looking at as one of the I'm sorry, Travis. Go ahead. I cut you off.
No, just saying, you heard it correctly, the renewables for SPP in general. Is that part of?
Yeah.
The idea there?
The advantage of joining Mountain West would be potentially a larger footprint, which is good for renewable integration. Certainly seen the benefits of that with MISO and other regions. Again, there are costs and other trade-offs, and when we added up the pros and the cons, we thought it was not enough of a benefit for our customers to move forward with it. Again, these things need to be periodically revisited, and that's what we'll do.
Okay, great. Then there's another higher-level question. When you think about Minnesota and the programs you have there, you talked about the Renewable Connect and the EV pilot, and obviously the renewables on the system. What's your view in terms of how that state looks in your system in, say, three to five years, as you get through the later part of your capital spending and even operating spending potentially?
It's absolutely amazing how quickly renewables, I think it's by 2022, if not 2021, renewables will be the biggest source of energy across all of our eight states, and that includes the upper Midwest and Minnesota. I believe around the mid-20s, we cross the line, and renewables will be 50% of our energy mix. It's absolutely phenomenal. Travis, as I mentioned in my prepared remarks, this is also affordable. It's creating a brand for the state, which I think is helping to attract economic development. We're really excited about Google. I don't think that'll be the last data center that we were able to obtain. I do think what we're doing with leading the clean energy transition can become a strategic asset for the state and our other states as well.
Okay, great. Appreciate it.
Thank you, Travis.
We'll now take our next question from Greg Gordon of Evercore. Please go ahead.
Greg?
Hey, guys. Actually, you guys answered all my questions from prior analysts. I'll give you the time back. Thank you.
Thank you.
Thanks, Greg.
We'll now take our next question from Angie Storozynski of Macquarie. Please go ahead.
Thank you. I have a really big-picture question. I'm looking at the slides from your EEI deck with the PPA roll-off, and I heard you mention the potential early buyouts of some of the PPAs. Now, given what we're witnessing in California now with this whole discussion about how expensive renewable power PPAs have inflated customer bills, I'm just wondering if you can give us a sense, for instance, if there is any kind of a rule of thumb, what kind of CapEx opportunity do you see as these PPAs roll off? Just before I let you answer it, I'm just wondering if it's the same type of rule of thumb that we have for O&M savings that some other utilities mentioned that, for instance, $1 of O&M allows to spend anywhere between $6 and $7 of CapEx.
Is the same rule of thumb applicable to those peak expiring PPAs? Thanks.
The CapEx rule of thumb would hold true to that if you're buying out a PPA and putting in a rate base, that's a good rule of thumb. We've got a large universe of power purchase agreements. There's a slide that you're probably looking at from the EEI deck, I don't have it in front of me now. We anticipate about 4,000 megawatts of those PPAs would, half of it in renewables and wind, I believe, and the other half in fossil fuels, might be something that we could look at. Whether or not we can pull the transaction, again, it has to work for us, it has to work for the seller, and it has to work for our customers. We've had some success with that, and we anticipate future success.
Either way, Angie, when these PPAs roll off, most of them are at higher dollars than what the market prices would be now. That, at the very least, is going to help us with our very important objective of keeping bills low and create headroom for investment at that leverage point that you're talking about. It's really kind of a version of Steel for Fuel, if you will. We don't have quite the same high-price type PPAs that I think PGE might have. The reality is energy prices have fallen over the last 10 years. As things we did 10 years ago roll off, it's going to create opportunities either for buying or at the very least, keeping bills low for customers. All of which is good.
I'm just going back to that slide. Again, I know you're not seeing it right now. I'm looking at it. Is it as simple as I'm just basically looking at the expiration of those PPAs, and I see that you guys are showing us rough pricing of those PPAs? Basically, in the absence of that expense, I'm multiplying that benefit by, say, six and seven times, and that's the incremental CapEx I can spend?
Bob, I don't think we quite will look at it that way.
When we think about the impact on customer bills and the headroom of that higher price PPAs rolling off create, it factors into how we think about our capital investment program. As Ben says, we could invest in grid-like infrastructure to a significant degree, and we talk about what replacement costs. In the same deck, we talk a little bit about what replacement costs for the grid would look like. We're throttled by that usually at the pace of what we think that our customers would or should afford as we increase the capital plan. Fuel and purchase power reductions enable the company to invest in capital to the benefit of our customers while keeping bills low. I don't know if we're using a specific multiplier there, Angie, but your thesis is correct.
Angie, I think the way you have to look, and maybe we could take some of this offline, but I think the way you have to look at it is, if it has a positive NPV for the customer, and we can negotiate the transaction with that in mind, the opportunity is to put that CapEx, and you can probably do the math on 2,000 megs of wind and 2,000 megs of fossil, where that would roughly be. You'd be putting that in rate base, and you'd get the earnings power off of it. That's the universe, I think is, of how we would look at it.
Okay. I understand. Just one follow-up. Can you give us a sense if you're running into any issues with finding good sites for future wind farms, and if you're close to reaching a point where solar is becoming cost competitive or attractive versus incremental wind?
Yeah. There are sites out there, we've had, I think, pretty good success in finding sites, and I think the results speak for themselves there. Those sites will continue to be available. As far as solar becoming more competitive, you're absolutely right. I think my thought, Angie, is solar is going to continue to see significant cost reductions, more than offsetting, in my opinion, the falloff of the ITC. I think that marries up really nicely with the actual coal plant retirements that we're looking at, because as you know, solar has far higher planning capacity than wind does. Wind's more like fuel. Solar is kind of a mixture of the two. I think the stars are aligning very well for us in that regard.
Great. Thank you.
Thank you, Angie.
We'll now take our next question from Jonathan Arnold of Deutsche Bank. Please go ahead.
Hey, Jon.
Oh, good morning, guys.
Morning.
Hello?
Can you hear us?
I can hear you. Can you hear me?
Yeah, we can hear you loud and clear.
Hello. Can you hear me now?
We can hear you.
Okay. All right. We got kicked off the call for a little bit and then came back, so I'm going to apologize if you already answered this one.
Must have been bad behavior, Jonathan.
Something was sensed. O&M, you're targeting flat to 2017 levels, which means getting sort of back down to just under $2.3 billion, as I read the face of the numbers. You've been saying for a while that you want to be flat out through 2022 at that kind of a $2.3 level. Is the kind of reduction in 2019 just kind of getting back down to plan, having been a little over in 2018, or is it a precursor to maybe starting to push for something that's a bit better than flat? I was just curious if you can maybe speak to the 2018 number and then that guidance.
Jonathan, one of the things to think about is we are adding a significant amount of new wind onto our system in advance of retiring any legacy generation. That new wind causes O&M upward pressures. I would say that the balance of the base business is we continue to bend the cost curve on the base business while we absorb the incremental O&M from the wind. As we absorb lots of new generation, we've had some cost pressures in O&M. I think generally keeping it flat is us bending the cost curve except for the new wind it adds.
Is the forecast still like that $2.3 billion numbers out through the program, or has that changed a little bit?
Yeah, I think that's still a good assumption. That's still our guidance.
Okay, great. That was it. Thank you.
Jonathan.
We'll now take our next question from Paul Patterson of Glenrock Associates. Please go ahead.
Good morning.
Paul, how are you?
Morning.
All right. Just one sort of quick question here. Could you follow up a little bit on the use of securitization as being one of the tools in the toolbox, as you guys are indicating? What do you mean by that in terms of just how should we think about if the legislation were to pass, what might happen with that or how you guys might use that?
In Colorado and in securitization in general, one, there's two things it has to have. It has to be written in a way that technically you can actually do the bond programs off of it. Two, one of the things we'd be looking at is things like utility ownership of the generation that's been securitized. If those things come together, and remember, in Colorado at least, it's a voluntary tool, then it might be something we look at. I think the important thing, as I mentioned, Paul, earlier, is that we've achieved the goals of securitization through our own efforts, and that includes taking care of both the communities and the employees and keeping our bills flat. That's what we've achieved. We don't need securitization to keep doing that. If it's something that makes it even more attainable, then we're all for it.
Okay. I guess I'm sort of wondering, in the case of New Mexico, I can see with PNM what people are sort of thinking about. Is there any particular project or issue that securitization would address that I'm just missing? I apologize for just being dense on this.
No. That's why I think it's just that tool in the toolbox. Down the road, it might be something we would want to look at, but there isn't anything we're specifically thinking about today.
Okay, great. That's it for me. Keep warm.
Oh, we will. Thank you.
Thanks, Paul.
Thank you. It appears there are no further questions at this time. Mr. Frenzel, I'd like to turn the conference back to you for any additional or closing remarks.
Well, as always, thank you all for participating in our earnings call this morning. Please contact our investor relations team with any follow-up questions.
Thank you.
This concludes today's call. Thank you all for your participation. You may now disconnect.