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 Fowke, 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 filings with the SEC. On today's call, we will discuss certain metrics that are non-GAAP measures, including ongoing earnings, electric and natural gas margins. Information on comparable GAAP measures and reconciliations are included in our earnings release. With that, I will 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 $0.96 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 have updated our investment plan, which now reflects $22 billion of capital expenditures over the next five years. This represents rate base growth of 6.7%, off of 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 initiatives, 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 at our Sherco 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 are 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 are very excited about our plan, which provides customer value, delivers attractive returns for investors and keep 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 base 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,…

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 $0.08 per share, including various regulatory outcomes and riders to recover our capital investment. Lower O&M expenses increased earnings by $0.02 per share. In addition, our lower effective tax rate increased earnings by $0.03 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 cost in our nuclear and fossil plant operations. For 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 cost for nuclear operations and fossil plant outages in the fourth quarter. And as a reminder, we increased O&M spending in the second half…

[Operator Instructions]. And we will take our first question from Greg Gordon with Evercore.

Thanks. Great outlook guys. Just a couple questions. You have 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 with interest rates this low that the direction of travel on ROEs might still be modestly lower than where we are today?

I think, Greg, that's a great question. I mean we do recognize that we have some modest risk for which we have incorporated into our range. I think we got a lot of things going for us. First of all, we are very much aligned with our commissions on what we are 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 a reasonable ROE. So we always know we don't everything we ask for, of course. And I think we are very comfortable with the guidance we have set for us.

Okay. That was my only question. Thank you. Have a great day.

Thanks Greg.

Moving on, we will hear from Christopher Turnure with JPMorgan.

Good morning Chris.

Good 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 is 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 are successful here, is there kind of upside to those renewables numbers?

Well, that's two parts to the question. I guess as the last part, we don't have any renewables scheduled because we try to sync up that renewable portfolio with our IRP plan. And as you know, Chris, we expect to retire coal plants in the mid-2020s and that's when this next round of renewables, which will be very significant, will come through. One of the benefits we have had with our Steel for Fuel program is, we have created headroom on the consumer bills to do more investment in grid infrastructure and the investment we are 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 are getting the band back together again. This is asset health. This is the reliability. And this is to support some of the renewables that we already have out there.

Okay. That's good to hear. And then the 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?

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

Okay. Thanks for that guys.

Thank you.

And next up, we will take a question from Ali Agha with SunTrust Robinson Humphrey.

Thank you. Good morning.

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-year. But even for the years that are complete in both, what's the main upside to the numbers? And in the past, you have talked about your base plan and then you have 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 with the previous call, the transmission and distribution spend, those are things that are really the normal course of business. And we have a lot of opportunities to invest in our grid. I have 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 do things like Steel for Fuel and our efficiency initiatives and take advantage of falling commodity prices, you create that headroom. So we are quite confident in the $22 billion. Now I think your second part was and correct me if I am wrong, you wanted to know about upsides in the capital forecast?

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

Yes. Ali, this is Bob. I think that's the right way to think about it. We recognize that in the back years of our plan, we may have structurally under-forecasted some items. And I think we spent a lot of time with the operations in 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 are 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 have melded base and what we may have historically called upside or unidentified. I do think though and I think Ben was going to comments 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 have got 10,000, 11,000 megawatts of PPAs that the company procures today from third-party owners and we still think that there is opportunities out there to find customer beneficial acquisitions. None of that's included in the $22 billion.

Got you.

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

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

I will take a stab at it and maybe Bob will augment it. First of all, when we have had good quarters, we tell you don't think that as a trend. When we have a little bit off, we tell you don't take that as trend. But we did know, as Bob mentioned in his remarks, that we did have some of C&I customers that were self generating through cogen, et cetera. And that was planned. We knew about it. So that's the big issue there.

Yes. Ali, the only thing I would add to it is, we have seen some softness in the sand mining industry and fracing in Wisconsin, some of that attributable to competing products around the country and some softness in the gas markets broadly.

Got you. Thank you.

Thank you.

Next question comes from Angie Storozynski with Macquarie.

Thank you. Okay. So one question. In you prepared remarks, you didn't mention anything about a potential settlement in your Colorado rate case. Should we still expect it? I see that there is an October 30 deadline for filing. Could you comment on that?

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

Okay. And secondly, this Mankato acquisition on a non-regulated basis, at least caught me by surprise. And you are mentioning those buyouts of existing renewable PPAs. Would those be also unregulated? Or are you talking about basically converting PPAs into rate base 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 base. In the case of Mankato, the department and ultimately the commission decided that the benefits were too back-end loaded, some variances in how we modeled those benefits and they decided that they didn't want it in rate base. 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 base approach. But Angie, this isn't a change in strategy or anything else. We always want to see this. We wouldn't bring something to our commissions that we didn't think had a customer benefit. If there's disputes along the way, then we have to adjust to that depending on the situation. But that's always going to be Plan B, not Plan A.

Angie, these are all still long-dated PPA contracts from the asset to one of our regulated operating companies, in this case NSP-M. 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 the Mankato one. On the wind projects, our preference is to own them in rate base. I think they are really beneficial for the customers. But if they don't, we have made a preemptive filing at FERC to move those to wholesale as well. But again, as Ben said, I don't this is a strategic shift. It's just a recognition of their good assets that serve our customers and we are willing to own them.

Yes. And we still see plenty of opportunities, as Bob previously mentioned, to find those PPA buyout opportunities. And of course, we are in eight states, not just one or two. So they are across all of our jurisdictions.

It's just that and I obviously accept your explanation. It's just that in a sense, you are acting as a financial investor here and typically when we see these types of acquisitions, contract base to what's 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's a superior growth profile, at least from a risk perspective. And I understand that Mankato could be a one-off. But you are basically saying that that's not the case here, that that was just an exceptional situation here?

Well, Angie, I have to tell you, I think we have the most transparent growth of our organic system which is the $22 billion that we put forth and we think even beyond the forecast period, we will continue to see excellent opportunities to grow the system. We are create 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. The PPA buyout strategies which is pure upside to a very robust base capital plan. And this is not a strategic change. You are not going to see us look for opportunities to come in as a financial investor. This is situation where we had some modeling differences on the benefits. Bob mentioned, we have two other wind proposals in front of the commission. The difference there is, these benefits are very much front-end loaded. And I think there is a preference in Minnesota to own renewables over gas. So we will see where that goes. But again, I think we are quite proud of the pure play vertically integrated regulated utility we are.

Awesome. Thank you.

Thank you Angie.

Next, we will hear from Steve Fleishman with Wolfe Research.

Hi Steve.

Hi. Good morning. Just could you just may be talk a little bit more on what is happening with the MISO transmission situation on renewables and how congested it is? And just what is needed in your region to have renewables up more reasonable cost access?

Well, 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 are 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 are looking at those opportunities. And of course, some of the transmission that we are building in the next two years will help with that as well.

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

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

Okay.

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

It does sync up very nicely to our plans to retire coal plants. So our emphasis, particularly on MISO, will be more heavily towards solar which leads the initial tranches 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 think the settlement timeline is really in the next like week or two and it sounds like you can't really talk about whether you are going to be able to settle or not. But if we don't see something by then, should we then assume you are probably not going to be able to settle?

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

Steve, there is a real benefit to the settlement, but there is also from a timing perspective, the hearings are first week in November. Commission decision is 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 Julien Dumoulin-Smith with Bank of America Merrill Lynch.

Hi. Good morning team.

Hi Julien.

Hi, howdy. Perhaps if I can just follow-up on the last set of questions just real quickly on the MISO transmission piece. Interconnection queue issues have been around and accelerating of late. It 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 is talking about MVP again. We have 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?

I think there is still a bit of uncertainty, Julien, around the MISO transmission planning process. We are obviously a large transmission owner of MISO and are participating with them in the process. Our own group, I will 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. 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 is going to change in the next year 12 to 18 months in terms of congestion in the MISO region. And we are 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.

And Julien, remember when this does get built, we have pretty attractive right of first refusal legislation in some of our key states. So we are excited about the opportunities at the bill 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 plan in the meantime.

Excellent. And if I can go back to the Mankato stuff just with respect to the fuel type. 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 the weighing of the benefits. I think renewables definitely have a preference with our commission than gas, but I think it also comes down to the modeling and we are 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, Julien. But let me just step back, the IRRs of Mankato are good for shareholders. We think we would prefer 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 and we will see what the, I am not going to speculate on what the commission does with our wind projects, but I will tell you that we are comfortable with ownership, prefer ownership on the regulated side, but it's not bad in a portfolio either. And remember, when Bob talks about 10,000 megawatts, they are across all eight states. And it just so happens, these initial PPA buyouts came in Minnesota. But remember, we had Calpine in Colorado before and there are other opportunities in other states. And I just want to reiterate and I hope I am 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 right. Well, thank you guys very much. I appreciate it.

Thank you.

Up next, we will hear from Travis Miller with Morningstar.

Good morning. Thank you.

Hi 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 ParentCo versus project versus utility?

Hi Travis, this is Bob. I think our base plan is to finance 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 to equity ratio 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, how those and ITC for the solar parts in that 2022 to 2024 time period? How do we fill in those holes and think about those tax credits if the tax policy stays the same for you guys and for the industry broadly?

Well, that's a great question. It's one of the reasons why we accelerated and really put the pedal down on our Steel for Fuel program and the biggest wind expansion in the country that we have now because we did want to lock in those PTC credits before they expired at the 100% level and even at the 80% level. You are right. I think the wind industry will take a little time to adjust quite frankly, Travis, when the PTCs roll-off. Of course, there is a chance they won't. 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 most of it anyway will be more than offset by just gains in the solar itself and we think that times of very, very nicely to the retirement of our coal plants in the mid-2020. 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. And again, we will clearly wait to see if there is legislation, et cetera might change that.

Okay. And then just real quick, a follow-up. I know you guys and a lot of other companies have been talking about solar has been exiting, a lot of solar investment. Being a little extreme here, but what saves the wind beyond 2022 and 2023?

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 I think you will find as more and more solar that comes on the system, the planning capacity might fall off a little bit. So I think wind is always going to be there. We just so happen to want to focus on solar as we are retiring our coal plants. Solar has some advantages. Just think about it, I had farmers come up to me and say, gosh, you know, if we get we didn't have a wind farm on our land, we might have gone under. So you still farm the land when you have a wind project going there. Solar, not so much. I mean you 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 wind indefinitely.

Okay. Great. I appreciate your thoughts. Thanks.

Just one comment on that too. You have 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 are always going to have that inherent advantage.

Yes. Okay. Thank you.

Our next question will come from Paul Fremont with Mizuho.

Good morning Paul.

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?

Yes. The short answer is yes.

Okay.

Look, if you look at what we are asking for in the case, you look at what we did with rebuttals, we have a distinct possibility, but possibilities versus something I can talk to you about explicitly, we are not there.

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

Yes. Paul, this is Bob. For the rate base assumption, that's correct. But for the capital assumption, we are still going to spend the capital to procure that asset.

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

Correct.

Okay.

That's the way to think about it.

And then it looks like there is a $735 million pickup for Northern States Power Minnesota in 2020. Can you sort of give us 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 build-own-transfer project with our Cheyenne wind project. We are going to build that ourselves. And we moved a bunch of that capital into 2019 to get it built in time for 100% PTC. In 2020, some of the wind has moved from 2019 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 is another sort of big pickup of almost $1 billion 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 investments in our network for the transmission, distribution and gas networks. That's big spend year for us for our advanced grid initiatives. 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 have created a significant amount of customer bill headroom and we are starting to look at the networks businesses a little more carefully and we have 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 KeyBanc 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 there coming up. Is your regulatory strategy is changing in that state? Is there any consideration that maybe you would approach differently?

No, I don't think so. We plan to file for interim rates in the first week of November. I don't see anything too controversial with that. We expect the rates to go into place. And then we will process the case. I am not sure, we still see the same alignment with our strategy and we expect a constructive outcome. So that answers your question, Sophie. I want to make sure I did.

Yes. So it sounds like you don't expect your Mankato acquisition that you are now doing as merchant asset to color the rate case proceeding in anyway?

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

Great. Thank you.

Next, we will hear from Paul Patterson with Glenrock Associates.

Hi. 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 the cost containment and what have you in that area. And we have recently had FERC put out an order and some comments as well, I guess, from certain commissioners about the 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 a FERC order as well 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. I don't think the barrier to getting transmission done, which is really what we are trying to get accomplished, is not about the competitive process 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 cost would be allocated because the real barriers to getting transmission build 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 will see where that goes. But as I mentioned, as you know, we have got a right of first refusal in Minnesota. We have it in other jurisdictions. We are not an RTO in Colorado. I think there is some real advantages to that. But we will get this transmission built. And we are being realistic in the time it takes to get it built.

Okay. Great. Thanks.

Thank you.

And next, we will hear from Vedula Murti with Avon Capital.

Hi Vedula.

Just wanted to follow-up little bit on the Mankato discussion we are having. You referenced the strong internal IRRs. How does it compete in terms of just picking more from capital allocation perspective versus other capital opportunities you have across the system in terms of choosing this capital allocation?

Well, the Mankato project is certainly, the returns are certainly above our cost of capital and an attractive from a shareholders' perspective as a result. Bob, I don't know if you want to add anything to that?

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

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 are keenly focused on reliability. So Vedula, 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 modeled very, very conservatively. So it's reason why we did not want to walk away from this one.

Okay. Thank you very much.

There are no further questions. I will 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.