Xcel Energy Inc.

Good day and welcome to the Xcel Energy third quarter 2019 earnings conference call. Questions will only be taken from institutional investors. Reporters can contact media relations with inquiries and individual investors and others can reach out to investor relations. 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.

Good morning and welcome to Xcel Energy's 2019 third quarter earnings conference call. Joining me today are Ben Folk, Chairman, President, and Chief Executive Officer, and 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 2019 third quarter results, discuss earnings guidance, update our financial plans and objectives, and also update you on recent business and regulatory developments. Slides that accompany today's call are available on our website. As a reminder, some of the comments 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 our findings with the SEC. On today's call, we will discuss certain metrics that are non-GAAP measures, including ongoing earnings and electric and natural gas margins. Information on comparable GAAP measures and reconciliations are included in our earnings release. With that, I'll turn the call over to Ben.

Well, thank you, Paul, and good morning, everyone. Let's start with earnings. Today, we reported third quarter earnings of $1.01 per share, compared to 96 cents per share last year. Three quarters of the year behind us, we are on track to deliver earnings in the upper half of our guidance range. Consistent with our third quarter tradition, we've updated our investment plan, which now reflects $22 billion of capital expenditures over the next five years. This represents rate-based growth of 6.7% off a 2019 base year. Our updated capital forecast is, of course, driven by our investment in renewables as we continue the clean energy transition. The forecast also includes investment in our advanced grid initiative, expenditures to improve the customer experience, additional investment in the transmission system to maintain asset health and reliability, and a natural gas combined cycle plant and our SHRCO facility to ensure reliability as we retire coal plants. This represents a base capital forecast, and we are also confident that there are likely additional upside investment opportunities not included in this base plan. We're also initiating 2020 guidance of $2.73 to $2.83 per share. which is consistent with our 5% to 7% long-term EPS growth objective. We're very excited about our plan, which provides customer value, delivers attractive returns for investors, and keeps customer bills low. Next, let me update you on our PPA buyouts and wind projects. In September, the Minnesota Commission denied our proposal to acquire the Mankato Combined Cycle Plant as a rate-based asset. Over its life, we believe the Mankato asset brings tremendous value and reliability to the system, especially as we retire coal plants. As a result, we have filed to acquire Mankato as a non-regulated asset and assume the existing PPAs with NSP Minnesota, which run through 2026 and 2039. We anticipate the acquisition will generate utility-like returns over the life of the asset. However, we expect the non-regulated returns will be lower in the near term as the benefits are back-end loaded. We've made wholesale generation filings at FERC and affiliate interest filings with the Minnesota Commission, and we expect approval in December or January. We believe that our PPA buyout strategy can provide significant customer benefits. As a result, we'll continue to evaluate customer beneficial acquisition opportunities and we'll proactively work with our stakeholders to identify the costs and benefits of the transactions. Please note, our capital forecast does not include any incremental PPA acquisitions. Our two proposed wind PPA acquisitions, Long Road and Maurer, produce significant savings for our customers, and these benefits are front-end loaded as the PTCs would flow back to customers in the first 10 years. We expect a Minnesota Commission decision on Long Grove by the end of the year and Maurer in the first half of 2020. We continue to achieve important milestones in our nation-leading wind expansion. We have completed the development phase of our 522 megawatt Sagamore wind project in New Mexico, with construction slated to begin later this year and commercial operation expected by the end of 2020. In the Upper Midwest, a developer scaled back the Crown Ridge wind project by 200 megawatts due to increased MISO transmission and interconnection cost. We had planned to own 100 megawatts of Crown Ridge as a built-owned transfer project. While this has an immaterial impact on our capital forecast, it does highlight the need to expand transmission investment to address congestion and ensure the viability of future renewable projects. So as a result, we, like the Blues Brothers, are on a mission to put the band back together again. And we are working with the original CapEx 2020 utilities, which built over $2 billion of transmission projects in the Upper Midwest over the last 10 years. We expect similar constraints and investment opportunities in SPP and Colorado as well. While it's not in our five-year forecast, and it will take some time to develop and implement plans, The need for additional transmission highlights the long runway for capital investment for Xcel Energy. With that, let me turn the call over to Bob. He'll provide more detail on our financial results and outlook and a regulatory update.

Bob? Thanks, Ben, and good morning, everyone. We recorded third quarter earnings of $1.01 per share compared with $0.96 per share in 2018. The most significant earnings drivers for the quarter include Higher electric and natural gas margins, which increased earnings by 8 cents per share, including various regulatory outcomes and riders to recover our capital investments. Lower O&M expenses increased earnings by 2 cents per share. In addition, our lower effective tax rate increased earnings by 3 cents per share. However, the majority of the lower effective tax rate is due to an increase in production tax credits, which flow back to customers through electric margin, and tax reform impacts, both of which are largely earnings neutral. Offsetting these positive drivers were increased depreciation, interest, and other taxes, reflecting our capital investment program, which reduced earnings by $0.04 per share. And lower AFUDC due to projects going into service decreased earnings by $0.04 per share. Turning to sales, our year-to-date weather-adjusted electric sales declined by 0.3%, reflecting continued strong customer growth offset by lower use per customer and expected discrete declines in certain large customer usage due to cogeneration. Year-to-date weather-adjusted natural gas sales increased 3.2% as a result of strong customer growth and higher use per customer. For 2019, we anticipate relatively flat electric sales and natural gas sales growth of 2% to 3% growth, reflecting year-to-date performance. Turning to O&M, and consistent with our expectations, our quarterly expenses decreased by $13 million, reflecting lower costs in our nuclear and fossil plant operations. Our year-to-date O&M expenses are above last year, largely due to expense timing, but also due to higher than expected storm costs. We expect lower costs for nuclear operations and fossil plant outages in the fourth quarter. And as a reminder, we increased O&M spending in the second half of 2018, due to the impact of hot weather as well as environmental remediation and business efficiency improvements. Accordingly, we expect our full year 2019 O&M expenses will decline by 1 to 2% from 2018 levels. Let me provide a quick regulatory update. Earlier this month, we filed rebuttal testimony in our Colorado electric rate case and revised our request. We are now seeking an increase of $108 million based on a current test year with a capital reach forward through June 19 and an equity ratio of 55.7% and an ROE of 10.2%. Intervenors filed testimony and the Commission staff recommended an ROE of 9% and an equity ratio of 55.6% in a current test year with a capital reach forward through June 2019 with an average rate base. Hearings start in November, and we expect a commission decision in December, with new rates effective January of 2020. We also have electric rate cases in New Mexico and Texas. SPS is seeking an increase of $51 million in New Mexico based on a historic test year with a capital reach forward and an equity ratio of 54.8% and an ROE of 10.35%. While in Texas, SPS is seeking an increase of $136 million based on a historic test year, an equity ratio of 54.7% and an ROE of 10.35%. The request largely reflects investment for the Hail Wind project as well as other capital to support strong growth in the region. Both cases are in the discovery phase with not much to report. As a reminder, both the Texas and New Mexico Commissions previously granted a certificate of need and current recovery mechanisms for Hale. We anticipate final rates going into effect in 2020. Earning to earnings guidance. In the fourth quarter, we expect favorability in O&M, margin, and sales. In addition, depreciation and amortization expense will moderate due to the timing of lower levels of prepaid pension amortization in Colorado. As a result, we are narrowing our 2019 earnings guidance range to $2.60 to $2.65, per share, which represents the upper half of the original guidance range of $2.55 to $2.65 per share. As Ben noted, we are initiating our 2020 earnings guidance range of $2.73 to $2.83 per share, which is consistent with our long-term EPS growth objective of 5% to 7%. Please note that the 2020 EPS guidance is based on several assumptions, which are detailed in our earnings release. I wanted to highlight a couple of items. We assume constructive regulatory outcomes in all proceedings. We expect electric and natural gas sales growth of approximately 1%, which includes the impact of leap year. We anticipate an effective tax rate of approximately 0%, largely driven by wind production tax credits, which are credited to customers and have no impact on earnings. Finally, we expect O&M expenses to increase 2%, which reflects increased costs for new wind projects coming online. Please note wind O&M is recovered in riders and most jurisdiction is offset by fuel savings. In our earnings release, you'll find more details about our updated $22 billion five-year capital forecast, which reflects investments to support continued customer growth, improvements in safety and reliability, the enablement of renewable generation, and automated metering for our customers. Our capital plan results in annual rate-based growth of approximately 6.7% using 2019 as a base. Importantly, the rate-based growth rate would be 7.3% if we'd maintained 2018 as the base year. Our updated capital investment plan is supportive of our 5% to 7% long-term earnings growth objective, and our goal is to deliver EPS and dividend growth in the upper half of the range. We've also updated our financing plan, which reflects the combination of internal cash generation and operating company and holding company debt to finance the majority of our capital expenditures. In addition, we expect to issue $1 billion of incremental market equity over the next three years and $400 million of drip and benefits equity to fund our capital plan and support our credit ratings. The financial plan reflects incremental capital investment of approximately $2.5 billion for the period of 2020 to 2023, is compared with our previous capital forecast. This incremental equity will allow us to fund accretive capital investment opportunities, which benefit our customers, while maintaining our solid credit metrics and favorable access to the capital markets. With that, I'll wrap up. We're continuing to make progress on our wind development efforts and our PPA buyout strategy with the recently announced Maurer project. We're going forward with the Mankato acquisition due to the strong value the asset provides over the long term. We are well positioned to deliver earnings in the upper half of our 2019 earnings guidance range. We've announced a robust, updated capital investment program, which provides strong, transparent rate-based growth and customer value. We've initiated 2020 EPS guidance of $2.73 to $2.83, which is consistent with our long-term objective. Finally, we're very confident that we can deliver long-term, EPS growth in the upper half of our 5% to 7% objective range. This concludes our prepared remarks, and operator, we'll take a few questions.

Thank you. And if you would like to ask a question, please signal by pressing star 1 on your telephone keypad. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, please press star 1 to ask a question. We'll pause for just a moment to allow everyone an opportunity to signal for questions. And we'll take our first question from Greg Gordon with Evercore.

Thanks. Great outlook, guys. Just a couple questions. You've got a lot of rate cases pending, and when you think about the range of potential outcomes in terms of things that might influence financial results like return on equity, how do you – sort of flex for that when you think about the guidance range? And do you contemplate, you know, with interest rates this low that, you know, the direction of travel on ROEs might still be, you know, modestly lower than where we are today?

Well, I think, Greg, that's a great question. I mean, we do, you know, we do recognize that we have some modest risk, which we have incorporated into our range. But I think we've got a lot of things going for us. I mean, first of all, We're very much aligned with our commissions on what we're doing with the clean energy transition. It's good to have their support with that. I think second of all, if you think about it, we certainly don't have above-market ROEs today. And then finally, if you look at some data points on some of the cases that we have decided recently, they kind of point to reasonable ROEs. You know, we always know we don't get everything we ask for, of course, and I think we're very comfortable with the guidance we set forth.

That was my only question. Thank you. Have a great day. Thanks, Craig.

Moving on, we'll hear from Christopher Turner with J.P. Morgan.

Morning, Chris.

Morning, Ben and Bob. Increasing transmission investment is a little bit of a newer theme for you guys or kind of a return to maybe an older theme. Just wondering if there's higher risk to this plan due to size of projects being larger or regulatory approvals that are needed here. And I know your renewable investments really tail off in the next two or three years, but I guess to the degree that you're successful here, is there kind of upside to those renewables numbers?

Well, two parts to the question. I guess the last part, we don't have any renewables scheduled because we try to sync up that renewable portfolio with our IRP plans. And as you know, Chris, we expect to retire coal plants in the mid-20s. And that's when this next round of renewables, which will be very significant, will come through. One of the benefits we've had with our Steel for Fuel program is we've created headroom on consumer bills to do more investment in grid infrastructure. And the investment we're talking about, Chris, isn't really going to require the regulatory approval because it's not the big transmission lines I referred to when I said we're getting the band back together again. This is asset health, this is reliability, and this is to support, you know, some of the renewables that we already have out there.

Okay. That's good to hear. And then the, I guess, incremental $1 billion of equity needs are technically over the five-year plan. Can you kind of give us a sense as to the timing and maybe structure of that within the five-year range?

Yeah, Chris. In my prepared remarks, I mentioned we'd probably do it over the next three years and You know, historically the company has looked at, you know, a bunch of different products. You know, we've used ATM programs. We've used, you know, block deals in the past. I think we look at, you know, a various mix of products. I think it will come in, you know, obviously more than one offering. And so I just think we'll be measured about it and we'll execute it in line with our cash needs as we look forward over the next three years.

Okay. Thanks for that, guys.

Thank you. Next up, we'll take a question from Ali Agha with SunTrust Robinson and Humphrey.

Thank you. Good morning. Hey, good morning. Ben, I may have missed it right at the opening, but when you look at that $22 billion five-year capex, obviously you roll forward, so it's not apples to apples with your last five years, but even for the years that are completed in both, what's the main sort of upside to the numbers? And in the past, you've talked about your base plan, and then you've laid out, quantified your upside plan, et cetera. This time, it looks like everything is in one plan. So are all of these projects now approved and ready to go, or are there certain placeholders in this $22 billion number?

I think for the most part, this is stuff we know we can execute on. As I mentioned on what the previous call, the transmission and distribution spend, those are things that are really in the normal course of business. And we have a lot of opportunities to invest in our grid. I've always said, as you know, that those sorts of investments are always capped at the willingness for the consumer to pay. So to the extent we can we can do things like steal for fuel and our efficiency initiatives and take advantage of falling commodity prices, you create that headroom. So we're quite confident in the $22 billion. I think your second part was, and correct me if I'm wrong, you wanted to know about upsides in the capital forecast?

Yeah, I guess there was kind of two parts as well. One, in your existing $22 billion, what has gone up versus what you were thinking when you at last put out your CapEx and then you know, this time you don't have like a base case, upside case. So is everything now, you know, all in one plan?

Yeah, Ali, I think this is Bob. I think that's the right way to think about it. You know, we recognize that, you know, in the back years of our plan, we may have structurally underforecasted some items. And I think we spent a lot of time with the operations and the businesses this year looking at their asset needs and trying to get everything into a single plan to make it simple and easy for the investor to understand. So I think what you're seeing here is the compilation of probably six months worth of good work by the company trying to identify projects in the back part of the plan that maybe might not have gotten identified in previous plans. So I think we've melded base and what we may have historically called upside or unidentified I do think, though, and I think Ben was going to comment on upside, and I think there are items that aren't embedded in this plan. I think Ben mentioned one, which is a continuation of our PPA buyout strategy. We think we've got 10,000, 11,000 megawatts of PPAs that the company procures today from third-party owners, and we still think that there's opportunities out there to find customer beneficial acquisitions. None of that's included in the $22 billion.

I got you. And it's clear, you know, while renewables that we put into our capital forecast usually come out of an IRP process, we believe there might be some opportunities to add some renewables too, but just not identified yet, which is why they're upside.

Got you. And one other question. You know, when I look at your better normalized sales trends, you know, broken out on a quarterly pattern, you know, third quarter we saw a pretty big negative trend. you'd been trending positive through the first two quarters on the electric sales side. So anything that has changed that caused the negative run in the third quarter?

I'll take a stab at it, and maybe Bob augmented. First of all, I would never – you know, when we've had good quarters, we tell you don't take that as a trend. When we have a little bit off, we tell you don't take that as a trend. But we did know, as Bob mentioned in his remarks, that we did have – some CNI customers that were self-generating through Cogen, et cetera, and that was planned. We knew about it. So, you know, that's the big issue there.

Yeah, Ali, the only other thing I'd add to it is we have seen some softness in the sand mining industry and fracking in Wisconsin, some of that attributable to competing product around the country and some softness in the gas markets broadly.

Gotcha. Thank you.

Thank you.

Next question comes from Angie Storzinski with Macquarie.

Thank you. One question, in your prepared remarks, you did not mention anything about a potential settlement in your Colorado rate case. Should we still expect it? I see that there is an October 30th deadline for filing. Could you comment on that?

Well, listen, the time that we would get to enter into settlement discussions, Angie, would be after rebuttal. So that's the period now. And, you know, there has been some outreach and some work being done. But, you know, we don't have anything to report to you, or we would. And as you know, it's scheduled for hearings, I think, in the first week of November. So, you know, maybe something will come up in that timeframe. But, you know, if we have something to report, we would tell you.

Secondly, this Mankato acquisition on an unregulated basis at least caught me by surprise. You are mentioning those buyouts of existing renewable PPAs. Would those be also unregulated or are you talking about basically converting PPAs into rate-based renewables?

Well, our approach is always going to be let's find customer beneficial acquisition opportunities through PPAs, and let's offer them to our customers. And so our plan is always to put them in rate-based. In the case of Mankato, the department and ultimately the commission decided that the benefits were too back-end loaded, some, you know, variances in how we modeled those benefits. And they decided that they didn't want it in rate-based. However, we still believe it's a very valuable asset and that it belongs in our portfolio. So we went forward with a non-regulated-based approach. But, Angie, this isn't a change in strategy or anything else. You know, we always want to see this. We wouldn't bring something to our commission so that we didn't think had a customer benefit. If there's disputes along the way, then, you know, we have to adjust to that depending on the situation. But...

That's always going to be plan B, not plan A. You know, Angie, these are all still long-dated PPA contracts from, you know, the assets to one of our regulated operating companies, in this case, NSPM. So we do like the credit counterparty. We do like the optics of the transaction. I think it works for shareholders and customers alike. And so you should expect us to move forward with this, with the Mankato one, On the wind projects, you know, our preference is to own them in rate base. I think they're really beneficial for the customers. But if they don't, we've made a preemptive filing at FERC to move those to wholesale as well. But again, as Ben said, I don't think this is a strategic shift. It's just a recognition that there are good assets that serve our customers and we're willing to own them.

Yeah, and we still see plenty of opportunities, as Bob previously mentioned, to find those PPA buyout opportunities. And Of course, we're in eight states, not just one, two, so they're across all of our jurisdictions.

It's just that – and I obviously accept your explanation. It's just that, you know, in a sense, you're acting as a financial investor here, and typically when we see these types of acquisitions – contract-based with seemingly similar economics, at least I would take it as a sign that you are running out of growth options in the regulated base because that is a superior growth profile at least from a risk perspective. And I understand that Lanketo could be a one-off, but you're basically saying that that's not the case here, that that was just an exceptional situation here.

Oh, Angie, I have to tell you, I think we have the most transparent growth off our organic system, which is the $22 billion that we put forth. And we think even beyond the forecast period, We'll continue to see excellent opportunities to grow the system. We're creating headroom with things like Steel for Fuel to keep bills low so that we can make those investments and not overburden customers. I think that's a very important consideration. You know, the PPA buyout strategies were just pure upside to a very robust base capital plan. So, And this is not a strategic change. You're not going to see us, you know, look for opportunities to come in as a financial investor. This is a situation where we had some modeling differences on the benefit. Bob mentioned we have two other wind proposals in front of the commission. You know, the difference there is these benefits are very much front-end loaded. And I think there's a preference in Minnesota to own renewables over gas. So we'll see where that goes. But, again, I think I'm quite proud of the pure play vertically integrated regulated utility we are.

Awesome. Thank you.

Thank you, Angie. Next, we'll hear from Steve Fleischman with Wolf Research. Hey, Steve.

Hi. Good morning. Could you just maybe talk a little bit more on, what is happening with the MISO transmission situation and renewables and how congested it is and just what is needed in your region to have renewables have more reasonable cost access?

Well, you know, the work we did with CapEx 2020 opened up the door for a lot of renewables, but it's starting to your point to get constrained. And I do think long-term we're going to need more transmission development in the region to make sure we can continue to see renewables come into the MISO market. That said, Steve, I think we have some opportunities in the interim to squeeze out, if you will, the transmission capacity that is available. And we're looking at those opportunities. And, of course, some of the transmission that we are building in the next few years will help with that as well.

Okay. Is this something where you can kind of expand transmission on existing footprints or you need to get access to kind of new areas?

Well, I think you certainly, there's obviously a lot of work done with the new FERC rules on how that relates to, you know, existing transmission and repurposing. And, you know, there's, I think there'll be some opportunities in the market around that.

Okay. Can I speak to Steve longer term? I mean, this is, you know, a longer term issue. issue that we're working on. And when Ben said we're getting the band back together, you know, CapEx 2020 was a very successful consortium of transmission owners in MISO that came together and formulated a plan and executed on it very successfully. I think that that group is back together, put out a press release on it three or four weeks ago, trying to come up with solutions in partnership with MISO for longer-term, you know, transmission access, and this is going to be probably not in our current capital plan, but more like in years 5 through 15 of where we're going to see much more regional. We expect to see more regional transmission to enable exactly what you're talking about.

Yeah, which does sync up very nicely to, you know, our plans to retire coal plants. So our emphasis, particularly in MISA, will be more heavily towards solar, which At least the initial tranches of which have a better planning capacity, Steve, if you will, than wind, which is by far the best energy type source.

Okay. And then just on the Colorado case, I know that I think the settlement timeline is really in the next week or two. And it sounds like you can't really talk about whether you're going to be able to settle or not. But if we don't see something by then, should we then assume it's you're probably not gonna be able to settle?

Well, I think you had the timeframe right. The time for settlement is right after rebuttal, but before hearings. So we've got that week or two window to try to get something done. If I had something to definitive report, I would, but I don't want you to think that we're not interested in pursuing a settlement.

There's real benefits to settlement, but there's also, from a timing perspective, the hearings are first week of November, commission decisions expected in December, and new rates in January. So the timeline is relatively compressed anyway in terms of when we go from hearing to final rates. So the clock itself is not a driver.

Okay. Thank you.

Next question will come from Julian DeMullen-Smith with Bank of America Merrill Lynch. Hey, good morning, team.

Hey, Julian.

Hey, howdy. Hey, perhaps if I can just follow up on the last set of questions just real quickly on the MISO transmission piece. You know, Internet connection queue issues have been around and accelerating of late. Sounds like you guys are really working on this. Can you talk a little bit about the timeline? You talk about this Transmission 2020 effort. MISO's talking about MVP again. We've heard this from other peer utilities. Can you elaborate a little bit on what this process would look like, whether at MISO or with your peers and that process? Again, you talk about the five to 15-year plan, but even more tangibly in the planning process in the next 12 months, how does this play out?

You know, I think there's still a bit of Uncertainty, Julian, around the MISO transmission planning process. We're obviously a large transmission owner in MISO and are participating with them in the process. Our own group, I'll call it the CapEx 2020 group, getting back together is still in its early days in terms of identifying timelines for engineering studies and how this might progress. I don't think this is a very quick process. process. I think this is going to take at least five years through planning before we start getting into real capital plans and construction timeframes. And so I don't want to suggest that something's going to change in the next 12 to 18 months in terms of congestion in the MISO region. And we're seeing similar stuff in SPP as well in terms of just congestion and queues being backed up and projects being assessed with significant upgrade costs.

Julian, remember, when this does get built, we have some pretty attractive right of first refusal legislation in some of our key states. So we're excited about the opportunity to build transmission. And without getting too specific in the details, we do see some opportunities to utilize existing transmission and other existing queue access to not slow down our plans in the meantime.

Excellent. And if I can go back to the Mankato stuff, just with respect to the fuel type, I mean, I suppose my initial reaction was thinking that this might be more of a gas versus renewable question. Can you talk or elaborate a little bit more about the context behind this decision? Obviously, I think Angie said it before, she was surprised. How would you characterize it? Is there any specific angle here to be focused on in terms of understanding this decision versus the others proposed?

Well, I mean, it's just a weighing on the benefits. You know, I think renewables definitely have a preference with our commission than gas, but I think it also comes down to the modeling. And, you know, we're working with the department to make sure we have a more consistent modeling approach as we go into the IRP process. I think that's important, Julian. But let me just step back. The IRRs of Mankato are important. are good for shareholders. We think we would have preferred to have Mankato owned by our customers, because that's always our first preference, and that's our core strategy. But we didn't want to walk away from this asset. We want it in the portfolio. And so I think shareholders will benefit, you know, and we'll see what the – I'm not going to speculate on what the commission does with our wind projects, but I will tell you that we're comfortable with ownership, prefer ownership on the regulated side, but You know, it's not bad in a portfolio either. So, and remember, when Bob talks about 10,000 megawatts, you know, they're across all eight states. And, you know, so, you know, we're just not just, it just so happens these initial PPA buyouts came in Minnesota. But remember, we had Calpine in Colorado before. And, you know, there are other opportunities in other states. And I just want to reiterate, and I hope I'm answering your question. we are not having a strategic change. We are definitely focused on the great organic growth opportunities we have as a regulated utility in the upper Midwest all the way down to Texas.

Awesome. All righty. Well, thank you guys very much. I appreciate it.

Thank you. Up next, we'll hear from Travis Miller with Morningstar.

Good morning. Thank you.

Hey, Travis.

Hi, so just to stick on that subject real quick here on the PPA buyouts and potential growth there, would you do the financing structure any different in terms of parent co versus project versus utility?

Hey, Travis, this is Bob. I think our base plan is to finance it at the parent company with a mix of parent company, holding company debt and equity. I think our long-term capital structure is the right way to look at any of these assets. So 60-40 debt equity ratios is how we think about financing the business.

Okay, great. And then I wonder if you could talk both on a holistic basis across the industry and then also what you guys are seeing in terms of the PTCs and the ITC for the solar parts industry. in that 2022 to 2024 time period? How do we fill in those holds and think about those tax credits if the tax policy stays the same for you guys and for the industry broadly?

That's a great question. It's one of the reasons why we accelerate it and really put the pedal down on our steel for fuel program and the biggest wind expansion in the country that we've had now because we did want to lock in those PTC credits before they expire at the 100% level and even at the 80% level. You're right. I think the wind industry will take a little time to adjust, quite frankly, Travis, when the PTCs roll off. Of course, there's a chance they won't. You know, our approach to the solar piece of this is that I think the cost curve on solar continues to decline pretty quickly. And so we think that even the absence of the roll-off of ITC, or the most of it anyway, will be more than offset by just gains in the solar itself. And we think that times up very, very nicely to the retirement of our coal plants in the mid-20s. So we don't see a need to go out and lock anything in because we think the cost curve will more than offset the ITC reduction. We'll clearly wait to see if there's, you know, legislation, et cetera, might change that.

Okay. Just real quick, a follow-up. I know you guys and a lot of other companies have been talking about solar is the next thing, a lot of solar investment. It would be a little extreme here, but what saves wind, you know, beyond 2022 and 2023? Yeah.

Well, first of all, I think wind will recover and will be attractively priced. And I think wind will always compete very nicely against solar on an energy basis. And, you know, I think you'll find as more and more solar becomes on the system, the planning capacity might fall off a little bit. So I think wind's always going to be there. We just so happen to want to focus on solar as we're retiring our coal plants. Solar has some advantages. Just think about it. I've had farmers come up to me and say, gosh, if we didn't have a wind farm on our land, we might have gone under. You can still farm the land when you have a wind project on there. Solar, not so much. Basically, the land is being repurposed. And then, of course, there are different characteristics with when the wind blows versus when the sun shines. And so I think the two will complement each other in our clean energy transition very nicely. And I think there is going to be wind indefinitely.

Okay, great. I appreciate the thoughts.

Thanks. Just one comment on that, too. You've got to remember, we are in the wind belt of the United States. So it's one of the reasons why our steel for fuel strategies work so well, And so we're always going to have that inherent advantage.

Yep, yep.

Okay, thank you.

Our next question will come from Paul Fremont with Missoula.

Thanks. Not to beat a dead horse to death, but when you revised your ask in Colorado, does that improve in your mind the possibility of reaching settlement in that case?

Yeah, the short answer is yes.

Okay.

I think, you know, these, you know, look, you look at what we're asking for in the case, you look at, you know, what we did with rebuttal. I mean, we have a distinct possibility, but, you know, but possibilities versus something I can talk to you about explicitly, we're not there.

Okay. And then I guess a couple of questions on the CapEx revisions. I'm assuming for 2019 that the number that you previously had would come down by $650 million for Northern States Power because the Mankato acquisition would be done through sort of a non-regulated entity. Is that fair?

Yeah. Paul says, Bob, for the rate-based assumption, that's correct. But for the capital assumption, you know, we're still going to spend the capital to procure that asset.

Right. So it would like go into other, right, I would assume.

Correct.

Okay. And then it looks like there's a $735 million pickup for Northern States Power Minnesota in 2020. Can you sort of give us, you know, what's driving that?

I think the largest driver of that is sort of wind movements across plan years. So previously, we were going to have a field-owned transfer project with our Cheyenne Wind Project. We moved a big – we're going to build that ourselves, and we moved a bunch of that capital into 2019 to get it built in time for 100% PTCs. In 2020, some of the wind has moved from 19 into 2020, and so that's probably the bigger pickup. in the NSPM territory. In total, capital for 2019 is expected to be in line with our original guidance of $5.1 billion.

And then there's another sort of big pickup of almost a billion dollars in your spend in 2022. Can you give us some ideas as to what's driving that?

I think big picture, Ben, talked about a lot of that, and it's a lot of investment in our networks, whether it's transmission, distribution, and gas networks. That's a big spend year for us for our advanced grid initiative, and that's when we start spending additional dollars in the gas networks as well. So, Again, we spent a lot of money in renewables over the last three or four years. We've created a significant amount of customer bill headroom, and we're starting to look at the networks businesses a little more carefully, and we've seen both need and opportunity there.

Great. I think that's it in terms of questions.

And our next question will come from Sophie Karp with KeyBank Capital Markets.

Hi. Good morning. Thank you for taking my question. I was just wondering about Minnesota and following the Mankato docket, and I think you have a rate case, you have a rate case there coming up. Is your regulatory strategy changing in that state? Is there any considerations that maybe you would approach differently?

No, I don't think so. You know, we plan to file for interim rates first week of November. Don't see anything too controversial with that. Expect the rates to go into place, and then we'll process the case. We still see the same alignment with our strategy, and we expect a constructive outcome. I'd answer your question, Sophie. I want to make sure I do.

Yeah, so it sounds like you don't expect your Moncada acquisition that you're now doing as a merchant asset to color the rate case proceeding in any way?

Oh, no. No, not at all. No, there's no, I mean, there's no strained relationship at all around that. It's just the difference of you know, of the commission deciding, you know, we don't think there's enough benefit and, you know, we think there was a lot of benefit and still do. But no reflection upon a strain in the relationship.

All right. Thank you.

Thank you. Next we'll hear from Paul Pedersen with Glenrock Associates.

Hey, good morning. How are you doing? Good morning. So I wanted to touch base with you on the transmission. As you know, there have been some voices concerned about cost containment and what have you in that area. And we've recently had FERC put out an order and some comments as well, I guess, from certain commissioners about that FERC Order 1000 really hasn't worked out as they thought it would in terms of providing the level of competition that they wanted to. And so I was just wondering if you could sort of talk about how you see that issue or those issues related to competition in transmission and I think it was last week we had it for a quarter as well, sort of associated with touching on this as well, how we should think about what the outlook might be with respect to this reported concern.

Well, I think that's a really good question. You know, I don't think the barrier to getting transmission done, which is really what we're trying to get accomplished, is not about the competitive process. I mean, in fact, if you look at the biggest transmission build, it was done with CapEx 2020, as I mentioned. And that was utilities of all sizes and municipalities and co-ops coming together to form a plan that works. with an idea of how costs would be allocated. Because the real barriers to getting transmission billed is who pays for it, and then of course the permitting and everything else that goes with that. So I think my personal opinion, Paul, is that FERC 1000 and that whole process really clouds it. And it's not necessary. And we'll see where that goes. But as I mentioned, as you know, we've got a right of first refusal in Minnesota. We have it in other jurisdictions. We're not in an RTO in Colorado. I think there's some real advantages to that. But we'll get this transmission built. But we're being realistic in the time it takes to get it built.

Okay. Great. Thanks. Thank you.

And next we will hear from Vidula Murthy with Avon Capital.

Hey, Vidula. Hi. Good morning. Just to follow up a little bit on the Mankato discussion we've been having, you referenced the strong internal IRRs. How does it compete in terms of just picking more from a capital allocation perspective versus other capital opportunities you have across the system in terms of choosing this capital allocation?

The Mankato project is certainly – the returns are certainly above our cost of capital and attractive from a shareholder's perspective as a result. I don't know if you want to add anything to that.

No, I mean, I think the expectation is over the life of the asset, it looks like our utility-like returns are consolidated corporate returns. We've stated that it's a little bit lower on the front end, a little bit higher on the back end. just given the structure of the contracts. But otherwise, I agree with Ben's comment.

Let me just add that when we talk about utility-like returns over the life, that is with very, in our opinion, very conservative modeling. I do think that the trend towards anti-gas makes existing gas assets valuable. And we are retiring coal plants, and we're keenly focused on reliability. So The doula, we really thought it was important to keep it in our portfolio because I think that the value of existing gas assets is only going to grow. And this is a CC plant that we've modeled very, very conservatively. So it's the reason why we did not want to walk away from this one.

Okay. Thank you very much.

There are no further questions. I'll turn the conference back to Bob Frenzel for closing remarks.

Thank you very much for your participation in our call today. As always, if you have any questions, please follow up with Investor Relations.

And ladies and gentlemen, that does conclude today's conference. We thank you for your participation. You may now disconnect.