埃克西爾能源 (XEL) 2017 Q3 法說會逐字稿

Good day, and welcome to the Xcel Energy Third Quarter 2017 Earnings Conference Call. Today's conference is being recorded.

At this time, I would like to turn our conference over to Paul Johnson, Vice President of Investor Relations. Please go ahead, sir.

Good morning, and welcome to Xcel Energy's 2017 Third Quarter Earnings Conference Call. Joining me today are Ben Fowke, Chairman, President, Chief Executive Officer; and Bob Frenzel, Executive Vice President and Chief Financial Officer. In addition, we have other members of the management team in the room to answer questions.

This morning, we will review our third quarter results, discuss earnings guidance, update our financial plans and objectives, and 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.

With that, I'll turn the call over to Ben.

Well, thank you, Paul, and good morning, everyone. Today, we reported third quarter earnings of $0.97 per share compared to $0.90 per share last year. We're very pleased to report another solid quarter.

With the first 3 quarters of the year behind us, we are narrowing our full year guidance range to $2.27 to $2.32 per share. We're also initiating 2018 earnings guidance of $2.37 to $2.47 per share. We're also updating our 5-year capital forecast. And as you know, we're making significant capital investments in renewables. So let me provide you an update on our steel-for-fuel investment strategy.

In August, in response to our resource plan, we filed a stipulation agreement to create the Colorado Energy Plan. The proposal is a bold step in the continued transition of our generation portfolio and contemplates the early retirement of 2 coal units at our Comanche Plant, and the addition of up to 1,000 megawatts of wind, 700 megawatts of solar and 700 megawatts of natural gas and/or storage. As part of the agreement, we have an ownership target of 50% of the renewable additions and 75% of natural gas and storage investment, which could lead to an incremental investment of up to $1.5 billion. We believe this is a great opportunity for all stakeholders. Our Colorado business could achieve 55% renewable energy by 2026 and carbon emission reductions of 60% from 2005 levels. And we believe the plan can be implemented without cost increases to customers. We expect the Commission decision by the summer of 2018. Continuing on the steel-for-fuel theme, in September, we proposed the Dakota Range project, which is a 300-megawatt wind farm that we are planning to build and own in South Dakota. This is the first announced wind project that will go into service in 2021. With total capital cost in the range of 1,200 kw to 1,300 kw, this project is cost-competitive even with the PTC at the 80% level. Improvement in wind technology and supply chain are expected to continue and proves that wind can be economical beyond the PTC period. As with our other wind projects, there are significant cost savings to customers from the Dakota Range project. We've requested that the Minnesota Commission approve the project by March of 2018.

Next, I'll provide a quick update on our SPS wind proposal. As you will recall, we have proposed to add 1,000 megawatts of self-build wind in 2 locations in Texas and New Mexico. In addition, we have proposed a 230-megawatt power purchase agreement. Our proposal provides significant cost savings and environmental benefits, which our customers will realize as soon as the wind farms go into operation. In October, intervenors provided initial testimony, and as expected, they pushed back on our cost recovery mechanisms. Now this project is a $1.6 billion investment, and represents approximately 40% of SPS' rate base. Because this is a substantial investment, and our stakeholders will realize immediate benefits in savings, we need some form of current recovery to offset regulatory lag in order to go forward with these wind projects. This week, we filed our rebuttal testimony in Texas, and proposed some measures to address intervenor concerns. We've had many meetings with our stakeholders, and are cautiously optimistic we can reach a settlement that works for everyone. We expect final decisions on this proposal by the end of first quarter in 2018.

As the company has progressed on our clean-energy transition and steel-for-fuel strategy, there's been a lot of investor focus on our long-term earnings growth target. After careful consideration of our plants, we've tightened our long-term EPS target to 5% to 6% annual growth. I feel very confident we can deliver EPS growth within this range based upon our current plans. And of course, as always, we are focused on delivering earnings at the top end of that range.

With that, let me turn the call over to Bob to provide more detail on our financial results and outlook and a regulatory update. Bob?

Thanks, Ben, and good morning, everyone. We had another solid quarter with earnings of $0.97 per share compared with $0.90 per share last year. The most significant earnings driver for the quarter include higher electric margin, which increased earnings by $0.02 per share, largely due to rate increases in nonfuel riders to recover our capital investments, offset by production tax credits that flow back to our customers; lower O&M expenses, largely due to timing, increased earnings by $0.06 per share; and finally, a lower effective tax rate increased earnings by $0.07 per share. The lower effective tax rate increased -- reflects increased wind production tax credits, the resolution of past appeals and an increase in research and experimentation credits. Keep in mind that PTCs flow back to the customers through base rates. Riders of the fuel clause don't have a material impact on net income. Offsetting these positive drivers were increased depreciation expense, reflecting our capital investment program, which reduced earnings by $0.05 per share. Higher taxes, other than income, primarily property taxes, which reduced earnings by $0.02 per share. And higher conservation and DSM expenses, which reduced earnings by $0.01 per share. Those expenses are offset by higher corresponding revenues.

Turning to sales, on a weather and leap year-adjusted basis, our year-to-date electric sales improved 0.2%, reflecting approximately 1% growth in the number of customers across most customer classes and jurisdictions, offset by lower use per customer. Natural gas sales increased 1.8% year-to-date on a weather and leap year-adjusted basis, reflecting continued customer growth, partially offset by decline in use per customer. Our year-to-date electric sales are growing consistent with our annual growth forecast of 0% to 0.5%, while our natural gas sales are growing a little bit better than expected.

We continue to focus on our O&M expenses. Quarter-over-quarter, O&M cost declined $49 million, while year-to-date, O&M expense were $58 million lower. The quarter and year-to-date O&M underrun largely reflects the timing of plant outages and transmission and distribution line maintenance. We expect most of the year-to-date underrun to reverse in the fourth quarter. In addition, we expect incremental pension and benefit costs in the fourth quarter. And as a result, we expect annual O&M to be consistent with 2016 with some potential favorability. This would be the fourth consecutive year of near-flat O&M expenses.

Next, I'll provide a regulatory update. Please note that there are additional details on each case including in our -- in each case included in our earnings release. In Wisconsin, we have a pending request to increase electric rates by $25 million and natural gas rates by $12 million. Gas and intervenor testimony has been submitted and hearings have concluded. We anticipate a Commission decision in December, and final rates to be effective in January of 2018.

In Texas, we have a pending electric case, seeking a net increase of $55 million. We anticipate a Commission decision in the third quarter of 2018, with final rates to be implemented retroactively to January of 2018. And in Colorado, we filed a multiyear natural gas case, seeking $139 million increase over 3 years. Interim rates will be implemented in January and final rates are expected to be effective in March of 2018.

We also recently filed a multiyear electric case in Colorado, seeking $245 million increase over 4 years. Final rates are expected to be effective in June of 2018. In addition, we're also planning to file a New Mexico electric case later this week.

Turning to earnings guidance based on our year-to-date results, we're narrowing our full year 2017 earnings guidance range of $2.27 to $2.32 per share. Our previous guidance range was $2.25 to $2.35 per share. And while our year-to-date earnings are $0.12 per share, ahead of last year, keep in mind that we expect our year-to-date O&M underrun to largely reverse in the fourth quarter. We are also initiating our 2018 earnings guidance range of $2.37 to $2.47 per share, which is consistent with our revised long-term EPS growth objective of 5% to 6% annually. Please note that our 2018 EPS guidance is based on several assumptions, which are listed in the earnings release. I want to highlight a couple of them here. We assume constructive regulatory outcomes in all proceedings. We expect modest electric sales growth of 0% to 0.5% per year. And finally, we expect O&M expenses to remain flat, but we'll work to continually improve efficiency and drive cost out of the business.

In our earnings release, you'll find our updated 5-year capital forecast, which reflects investment of $19 billion in our base capital plan and drives the annual rate base growth of 5.5%. Our base capital plan includes the SPS wind proposal and the Dakota Range project. Our base capital forecast does not include any potential investments for the recently proposed Colorado Energy Plan, which could result in incremental capital investment of up to $1.5 billion. This incremental capital investment would result in approximately 6.3% annual rate base growth through 2022. We've also updated our financing plan. In addition to reinvesting our cash flow back into infrastructure in our operating companies, we'll issue operating company and holding company debt to fund our capital plan. And for the past several years, we've used market purchases for our DRIP and benefits programs. However, going forward, we expect to issue approximately $75 million to $80 million of DRIP and benefits equity per year. This will allow us to maintain our solid credit metrics with an expanded capital investment program. Additional details are included in our earnings release.

And finally, tax reform is back in the news. In September, Republican leadership and the administration released the high-level framework that would serve as a template for legislation that we expect to be released in draft form next week. There's a lot of uncertainty on the potential outcome, given the complicated nature of comprehensive tax reform. But our position on tax reform hasn't changed. We believe a lower corporate tax rate is good for the economy, our customers, Xcel Energy and the utility sector. And we believe that the preservation of interest deductibility in lieu of bonus depreciation or expensing of capital is in the best interest of our customers.

And finally, we believe that transition rules are important to the implementation, and we'll work within to ensure any new legislation and regulation is implemented in a manner that best protects our customer interest. While any final legislation could take many forms, we're confident that we can manage the impacts of potential tax reform and deliver on our earnings and dividend growth objectives.

With that, I'll wrap up. Overall, it was an excellent quarter. We filed our proposed Colorado Energy Plan, which approved, would continue our clean-energy transition and add substantial renewable generation and significantly reduce emissions with no incremental cost to our customers. We proposed the Dakota Range project, which represents the first wind project plan for 2021 and is cost competitive and results in customer savings, even with the phasedown of the production tax credits. We progressed our regulatory initiatives, and are engaged in rate proceedings in Colorado, Wisconsin, Texas and soon-to-be New Mexico. We provided updated capital plan, that provide transparency and support our 5% to 6% earnings and 5% to 7% dividend growth objectives. And finally, we posted strong financial results for the quarter and are well positioned to deliver earnings within our narrowed guidance range of $2.27, $2.30 -- $2.32 per share.

This concludes our prepared remarks. Operator, we'll now take some questions.

(Operator Instructions) We will take our first question from Julien Dumoulin-Smith from Bank of America.

Perhaps just first quick question. You never stop asking for more, I suppose, but congrats on moving the guidance range up. But I suppose the first question, I'd love to hear you spell out the plan in a little bit more detail is on the upside case of Colorado, just the timing of the capital there. And ultimately, the regulatory recovery scheme and how you're thinking about that phasing in. Basically, at what points in time will you be filing or at what point in time do you expect to actually see that capital play out? And at what point would you eventually get comfortable to put that into the plan?

Okay. Well -- here's where we are, Julien. We have request for proposals out. We expect to get those proposals in and be in a position to make a recommendation to the Commission in the first quarter of next year. We're hopeful for a favorable decision in the summer of 2018. As far as timing goes, I think a lot of that will depend upon the proposals themselves and what comes in and what make sense. So you're probably starting to -- I mean, I could just estimate it for you, you're probably in the 2021, '22 time frame. But how that would lay in, I think we've got to see what is presented to us, and then we'd have a better handle on that.

Got it. All right, fair enough. And then turning back to Texas, New Mexico. Just recovery there of the plan, et cetera. Can you talk about, perhaps, at a high level, how you're thinking about moving forward with those projects, and ultimately, I'll leave it at high level as asking expectations on earned ROEs through the construction project and what is sort of palatable to you all in both those jurisdictions?

Well, if you saw our rebuttal testimony that we filed in Texas, you see that we're -- I think we've addressed the intervenor concerns and are willing to do reasonable, symmetrical cost gaps, reasonable performance guarantees. Certainly, if we get a decision, when we want the decision, we can make sure that the PTCs will be eligible for the -- the PTCs, in this case, 100%. And I think we were -- our revised idea for recovery is one that I think makes all the sense in the world, that before they go into rate base, but while they're in operation, we'll enjoy the PTC and any market sales of the project that will accrue to the benefit of our shareholders. So if you put all that together, then that would be the kind of return that we would need to be able to move forward with this.

Got it. So you think, kind of, a consistent level of earned return in that jurisdictions still?

Well, we want to see the returns get better...

Okay. So you think it's possible, maybe, just in light of what you're proposing in rebuttal, et cetera, to see an improving ROE and see that capital deployment happen, said differently?

Yes, the short answer is yes. This is 40% of the SPS rate base and we'd get better recovery of investments than we typically get now, which, as you know, are in historic test-year mode. Even in New Mexico, where there was a forward test year, but to date, the Commission has found a way to throw those cases out.

Our next question comes from Ali Agha from SunTrust.

If the Colorado project does get approved and you add the $1.5 billion CapEx to your plan, what does that do to the 5% to 6% EPS growth rate?

Let's start with rate base. It would take rate base up to -- from 5.5% to about 6.3%. So that clearly gives -- and that is, as you know, the engine for EPS growth rate. So 6.3% is at the top end of the 5% to 6%.

Okay. But would you assume more equity in the mix to kind of dilute some of that rate base falling all the way to EPS growth?

I think there's a lot of variables that go into that, Ali. I mean, right now, we're comfortable with the DRIP program. And again, as I mentioned to Julien on the prior call, I think, it has to do with -- we'd have to look at the timing of when that -- those capital expenditures would take place.

Okay. Okay. Also, within your base plan, Ben, what have you assumed in terms of the trend line in your earned ROE? Have you assumed a significant pickup? Or -- to just remind us, what's the lag and what do you assume happens to the lag over that 4, 5-year period?

Ali, it's Bob. Look, when we look at our regulated ROEs and where we've been on our objectives to close the ROE gap, I think we've done a reasonable amount of progress in that regard. But as the headline, allowance have come down slightly. I think where we are year-to-date and where we expect to be for the forecast period, it's somewhere in that high-8s range of earned ROEs in the regulated operating companies.

Okay. So Bob, in other words, you are assuming your earned ROEs remain relatively steady or flattish over this period?

That's correct.

I see. Okay. And then lastly, looking at load growth, just for the third quarter, we did see a decline in weather-normalized electric sales. You've been trending fairly nicely and positively through the first half. Anything to read into that? Does that have an implication as you're looking at load growth going forward?

I wouldn't read too much into that. It's more of a function of we had a pretty solid Q3 last year. And so relative comparison, Q3 over Q3 looks a little bit down. Through the full year, we're still slightly up and within our guidance range. And if you look at the trend over a multiyear period, we're still very much in line with our expectations. So Q3 of '16 was probably a stronger quarter and the relative comparison is down.

Our next question comes from Travis Miller from Morningstar.

I was wondering on the Colorado, we'll stay with Colorado here for a second. Is there any kind of overlap between the multiyear, especially when you go out to '20 and '21 and the energy plan?

Is there any kind of overlap in...

Just in terms of infrastructure build or anything that would be necessary to support that energy plan.

Yes, I don't know if there's really an overlap. I don't know if you're referring to recovery. We do have David Eves here that runs our Colorado operations. So David, if there's any additional detail you could...

Yes, the electric rate case that we filed 4-year plan through 2021 doesn't include any projections or cost recovery for the Colorado Energy Plan. Those would be covered under the recovery mechanisms we proposed in the plan, like through the ECA.

Okay. Okay. And then quick dividend question...

Bottom line, then, you get proposing concurrent recovery.

Okay. For the energy plan?

Yes.

Yes. Okay. And then a quick dividend question. I think, if I recall, you had set the 60% to 70% payout target for the next couple of years. And was wondering how that might be affected with any of the incremental investment that you might get in, particularly the Colorado investment?

Travis, we haven't changed our guidance on either dividend growth or dividend payout expectations with regard to the base-case forecast or with regard to the Colorado Energy Plan.

Okay. So you still think you could potentially go up to that 70%, that you're still the 60% to 70% range?

I mean, I think if we grow earnings at where we think they are along with the projected dividend thing, that's going to -- it would take a long time for it to get to 70%. But stepping back, Travis, and I think you've heard me say this before, the modest payout ratio that we have, I think gives us that dry powder. And in the event you start to see rates rise, we can do more to reward our shareholders by rethinking the pace of our dividend increases. I'm not saying we're going to do that. But it's, kind of, all part of our plan to make sure that we don't -- we always have dry powder, whether it's on the operational side, the financial side, the dividend projections, so that we can continue to reward shareholders on a number of different scenarios.

Our next question comes from Stephen Byrd from Morgan Stanley.

I wanted to talk about your Colorado Energy Plan. And you mentioned the potential for either gas or storage. When you think about the economics of gas-fired generation relative to storage, what is your sense of the trend, the likelihood that over time storage will become so cheap that it's likely to become even more advantageous as a resource relative to gas-fired generation? What's your sense for where you might end up there?

I'll tell you what, when you look at what we're doing now with renewables, and our steel-for-fuel and the price point that they're coming in at, those are prices there is no way I would have ever thought would be possible 8 years ago. So I never short-change what technology can do. Right now, though, Stephen, it's batteries, in our relatively low-cost jurisdictions, don't compete. Economically, there might be some opportunities in some areas to deploy them. But I think it's important to recognize that they are going to continue to fall in price. Will they ever be the new peaker? I think there's going to be system-grid-reliability limitations on how much of that could happen. And from a planning capacity, there is -- there are differences between a battery and something that is -- can be fired up 24/7 for days at a time. But you're going to see more batteries on our system. That's the bottom line. And we'll be positioned to make sure that, that becomes increasingly more of a mainstream part of our portfolio. We'll let the technology move at the speed of value. And in the meantime, we'll do things like we are doing, which is pilot programs, et cetera, to really understand all the various economics, the grid capabilities and reliabilities battery bring -- batteries bring to the table. So long-winded answer to your question. We'll see what the resource plan brings to us, and then we'll make the right economic decisions for our customers.

Very, very helpful color. And just longer term, you've been having great success with the growth of renewables. Is there a point at which storage needs start -- or gas or both become, sort of, incrementally much more significant or do you think it's fairly linear? In other words, do you reach a point where you get such a degree of renewables that you have to significantly step up a gas-price generation and/or storage? Or do you think it's more just, sort of, a steady progression that we'll see?

Well, I think what we're going to do is, I mean, we're going to have more renewables on our system, I believe, than anybody else in this time frame. Certainly, more wind. And so you do have to have load-following resources. And I think that's what you mean by the gas technology. I think that's where batteries can play a role. I think it also requires you to start rethinking about your demand-response programs, et cetera, making sure that you can shift load to a degree. Where are the practical limitations on renewable on the system? And I can tell you, I'm working with our operational people and learning all about the system, inertia and things like that. Because, I mean, at some point, as you know, you can't -- today is with today's technology, you cannot truly be 100% renewable within your own grid. You'll always have to have another place to move and access power and bring in power when you need it. But you can get really, really close. And I think if you look at what we're talking about in our [Vision] case in Minnesota, what we're talking about in Colorado, I don't think anybody would have thought these things would have been practical 5, 10 years ago, and certainly, not at a -- the price point that doesn't raise cost for customers. Did I answer your question?

Yes -- no, it does. I mean, I guess I'm thinking about longer term. It sounds like you're doing a lot of assessment in terms of how your grid is going to change, and thinking about items like inertia, which are way beyond my capability to understand. But the -- it sounds like stay tuned. But it -- my sense is it sounds like storage and load volume is going to important part of that equation.

All of the above is going to be important.

Our next question comes from Christopher Turnure from JPMorgan.

I -- if I remember correctly, last year, when you started to have success on the Minnesota renewable front, and you were, kind of, discussing the impact on your overall rate base growth and CapEx plan, you deferred some other spending, I mean, at least hypothetically, to limit the positive impact there. If I, kind of, reverse the situation now and say, you have 5.5% rate base growth through the plan, let's say, you are not successful with any of the unapproved renewable projects, you might get down below 5%. Are there other things that you can pull forward that are on the back burner right now, that would bring you up to a slightly more competitive rate base growth level?

The short answer is yes. We could -- I think when I made those comments that you referred to, it's really about how much grid investment you do, and while those grid investments are incredibly beneficial to our customers, it does come with a price tag. So we want to be very mindful of that. But we have other capital we could bring forward or other opportunities that we could seek. I mean, look at the deal -- the Dakota Range project as an example of that. So I have no doubt that we will meet our rate base growth projections.

Keep in mind though, too, the base case does not include the Colorado Energy Plan, which is $1.5 billion. So that could very easily move into base, which would potentially offset any departures of other capital.

Sure. Yes, certainly, there are plenty of ways to win here. And then switching gears to the Colorado gas case. I think this has been one area where lag has been a bit more pronounced, if I'm not mistaken. Could you maybe help us understand how the staff recommendation as it pertains to forward-looking rate making and maybe the multiyear angular lack thereof, dovetails with the Commission's, kind of, investigation of that as ordered back in June? I think maybe they ordered the ALJ to look into the further potential for forward-looking and multiyear rates.

Yes, I'm going to turn it over to David Eves again. But I think the success we've had with our multiyear plans on the electric case gives me a lot of optimism that we can do the same on the gas side. Particularly, when you look at where that -- those -- what those investments are which is making sure that our gas system is reliable and safe.

Christopher, this is David. The commissioners, when they referred this to the administrative law judge, he made it pretty clear that they wanted the policy and full consideration of future test years in a multiyear plan. We're disappointed that the staff, even though OCC addressed it somewhat, the staff really sidestepped the issue and did not address the future test years in the multiyear plan. We still think we have a really good case and we'll address that in our rebuttal coming up on November 3.

Okay. But it sounds like you're confident in the Commission, and they're kind of just, in general, are they -- the direction that they're going in despite what the staff said?

Yes, I think we're confident. I think we have -- we feel like we have a really strong case. And you'll see that with our rebuttal. It's also -- I mean the gas revenue requirement is really a capital-driven. We're investing very significantly in the basic system, but also in all the integrity work. And part of this plan is to replace the PSIA with the forward test year of multiyear plan. So I think it's set up well.

Our next question comes from Jonathan Arnold from Deutsche Bank.

Question on the -- so you've put the DRIP in the plan now. I see the financing plan, which was not there before, and presumably, that's probably a function of the higher CapEx. But did you make a specific tax-reform assumption in there? That was one question. And then secondly, should we -- when should we assume you switch it on? Is it, sort of, later in the plan or is it more linear?

Jon, it's Bob. Yes, I don't think we made any direct considerations on tax reform with respect to turning on the DRIP. If you remember, the share repurchase program was initiated when the capital environment was $4-ish billion, less than it is today. So with consideration for credit and everything else, I think, we wanted to make sure that we had a very conservative plan that maintained our credit ratings and a modest amount of DRIP equity annually was enough in our opinion to maintain those -- that profile. When you ask about when do you turn it back off, I think, it just depends on what the future capital profile and opportunities for investment for the company. We see a long runway for capital investment at this rate. And so at this point, we would consider keeping it on and including the...

Actually, Bob, my question was when do you turn it on? Do you turn it on like in '18 or is it more at the back end of the plan?

Sorry. No, we expect to turn it on in 2018.

Okay. And then -- so then, by extension, if you do incremental CapEx that's outside of the current plan, is it reasonable to assume you'd address that through stepping up DRIP? Could you do more or might you look for another type of equity?

I think as Ben mentioned earlier on the call, we think that even with the Colorado Energy Plan, we think the DRIP would be sufficient equity for our financing plan for the 5-year period.

It depends, Jonathan, on the timing of when that CapEx would come through.

Okay. And -- but this level of DRIP, this is presumably not what you could have raised. And you could do more than that on the DRIP, I would guess.

No. Because DRIP -- I mean, DRIP is -- when we say DRIP, we're talking about dividend reinvestment plans. So that's going to be what it is. And our benefit plans as well. And that's -- so it's not really. I mean, it's that $75 million, $80 million, kind of, equity issuance every year.

Okay. All right, great. And then can I just -- on the, sort of, revised proposals in -- I may have missed this, I apologize if I'm going over some of your comments. But what's your level of confidence that what you've put on the table in Texas now for the SPS wind project -- it's kind of going to tick the boxes you need to tick and that you can stay on time?

I think it's -- first of all, Jonathan, you're very quick to summarize that rebuttal testimony. So I enjoyed your report. But I think it's -- I mean, I think it's very responsive to the concerns while still recognizing that we need to have better recovery for this level of investment, particularly when you look at the compelling customer benefits that come along with it.

Okay. Could I have just one, sort of, point of detail on that. When you guaranteed the 100% PTC, is that in the sense of in case the project's delayed beyond the deadline to get the full PTC? Or is that more around this deferred tax issue and the fact that you want customers to get the full benefit, even if you are not able to fully realize it on a concurrent basis?

No, it has to do with getting it in-service in time to make sure it qualifies for the 100% PTC eligibility. Now we do ask in that testimony, as you know, that our willingness to do that is based upon a Commission decision, I believe, in March of '18, which would allow us the time we need to actually get it constructed.

Our next question comes from Angie Storozynski from Macquarie Capital.

So just looking at Midwestern utilities pushing for more renewables in the rate base. I mean, I understand the energy aspect of the appeal of these investments. But we're starting to see first indications that intervenors want some offset to the existing generation capacity, because these assets do have some megawatts as well as the energy components. And so, I mean, how likely is that, that we could see some detriments to the rate-base growth, because you would be forced to, for instance, either write down or shut down some underappreciated coal plants or gas plants that currently exist in your rate base along with the additions of new wind farms?

Well, I can't speak for all of the Midwest utilities. But speaking for Xcel, I think, we've done a very good job of developing comprehensive plans that when we do talk about shutting down plants and, for example, in Minnesota, our Sherco 1 and 2 units, that we get the recovery associated with that shutdown. And in fact, Angie, if you look at what we're talking about in Colorado, we contemplate accelerating the depreciation of those -- of the Comanche 1 and 2 plants to a -- what's known as the RESA mechanism. So that, that is taken care of. And the cost of all of that, in both of those plants, still comes in at a price that's great for consumers. So we definitely look at that risk and we address it in the plans that we put forward to our stakeholders.

Okay. My second question, so assuming that the tax reform does happen and the CapEx deductions are extended, would you consider using a tax-equity investors to monetize the PTCs, especially under the scenario where you, in a way, shared its benefit upfront and then the cash true-up of that benefit from your perspective would be delayed if the, in effect, bonus depreciation were to be extended?

I mean, I think you'd have to see what sort of scenarios roll out. But I think under the scenario that we've, I think, been pretty successful advocating for, I don't think we have the need to do that. You got to keep in mind, Angie, that this -- the way I look at these wind proposals is they deeply, deeply in the money hedge against gas prices. So there's room for these projects to get essentially a little more expensive under different tax reform scenarios, and still be deeply in the money. We have a great cost of capital. And I -- and tax equity, as you probably know, is very, very expensive. So -- and of course, under those scenarios you mentioned, it probably would get more expensive. So I think putting in a rate base and delivering the, kind of, levelized cost of energy to our customers that we anticipate is the right path forward.

Okay. And last question. So the rebuttal testimony in support of those wind investments. So SPS, okay. So the way I understood it is that you're basically trying to shield earnings during this, say, 18-month period between when this -- the assets will start operations and when you could actually get them in rates. But how would that help you to increase the realized ROE? I mean, at a very -- I mean, to me, it just seems more like you're basically trying not to have a detriment to the ROE as opposed to an improvement?

Well, I mean, you're trying to -- I think it depends on how the market conditions would unfold. But you're talking about our proposal to -- when it -- by the time it's operational and between operation and in-service, because we are in a [historic test] year in Texas, that we would enjoy the production tax credits and any market sales. Is that what you're talking about?

Yes. Yes.

Yes, well, I think, there's some variability in that we've based on -- from market sales, but the PTCs would be fairly compelling. And, again, yes, I'd like a rider or forward rider, but would -- but we're also want to see these projects to get done. They are great for our customers. And the mechanism that we talked about, while not our first choice, is something we can live with. And not see lag associated with those particular projects.

Next question comes from Paul Ridzon from KeyBanc Capital Markets.

Maybe you answered this and I didn't pick it up. But if the Colorado Energy Plan were approved, would that $1.5 billion, kind of, push other projects off the stack or delay them or could you fully absorb that along with all the other projects?

Hey, Paul, it's Bob. Our expectation is, is that -- well, it depends a lot on the timing of the proposals that we receive and the recommendations we make to the committee. But I think our proposal would be that we would keep the Colorado Energy Plan as incremental to our base capital plan. And we look at any changes year-over-year that might be necessary. But bottom line is assuming it comes in and when we think it would, which is '20, '21, '22, that we'd be able to manage that capital profile.

That was -- you said '20, '21, '22, is there a comma between 3 numbers there? Or is that 2021 and 2022?

Sorry. 2020, 2021 and 2022.

Our next question comes from Paul Patterson from Glenrock Associates.

Just -- sorry to be a little slow here, but just to make sure, on the CapEx and rate base numbers. Does that include all of the SPS wind CapEx? And if New Mexico, for instance, doesn't happen or what have you -- is it -- do you have to have both in New Mexico and Texas for those -- for the SPS wind proposals to happen?

Yes, Paul, we proposed 2 projects, 1 in the New Mexico, 1 in Texas. But we run the system on an integrated basis, and our approval process would look to go to both Texas and New Mexico for approvals for both projects.

So Paul, are you asking, in the $19 billion, what's included in the base, is the assumption that our proposals at SPS go through. So that's in the base. But as we've mentioned, what's not in the base is the Colorado Energy Plan.

Right. Okay. But just a -- it's the full amount of the SPS wind is in the base, right?

Yes. And including our -- and also in Minnesota, the Upper Midwest, rather the Dakota Range project.

Right. And then -- and just what I was asking, I apologize if it wasn't clear. Is it, let's say, there was a problem in New Mexico or something like that, would that basically -- would that impact -- how would that impact the SPS wind project? Do you follow what I'm saying? Do you need both of them in order for the...

Well, yes, I mean, I guess, we'll cross that bridge when we come to it. But the -- ideally, you get approval from both -- Bob's point, we run the system on an integrated basis. But there have been times where we've allocated a project specifically to a jurisdiction. It can be done, it's not ideal, but it can be done.

At this time, I'd like to turn it back to Bob Frenzel for any additional remarks.

Thanks, everyone, for participating in our earnings call this morning. Please contact our Investor Relations team with any follow-up questions. We look forward to seeing you in Orlando.

And this does conclude our conference for you today. Thank you for your participation. You may disconnect.