Xcel Energy Inc (XEL) — Q3 2017 Earnings Call Transcript

Good morning, and welcome to Xcel Energy's 2017 Third Quarter Earnings Release Conference Call. Joining me today are Ben Fowke, Chairman, President, Chief Executive Officer; Bob Frenzel, Executive Vice President and Chief Financial Officer. In addition, we have other members of the management team in the room to answer your 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 in our filings with the SEC. With that, I'll turn the call over to Ben.

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 are very pleased to report another solid quarter. With the first three 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 five-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 continuing transition of our generation portfolio and contemplates the early retirement of two coal units at our Comanche Plant and the addition of up to 1,000 megawatts 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% on natural gas and storage investment which could lead to an incremental investment of up to $1.59 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. We believe the plan can be implemented without cost increases to customers. We expect our 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 costs in the range of $1,200 to $1,300 a 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 to prove 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 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 two 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. This project is a $1.6 billion investment and represents approximately 40% of SPS's rate base. Because this is a substantial investment and stakeholders will rely on immediate benefits and savings, we need some of current recovery to offset regulatory lag in order to forward 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 the 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 plans, we have tightened our long-term EPS targets to a 5% to 6% annual growth. I feel very confident we can deliver EPS growth within this range based on 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 drivers for the quarter include higher electric margin which increased earnings by $0.02 per share, largely due to rate increases and non-fuel riders to recover our capital investments, offset by production tax credits that flowed back to our customers. Lower O&M expenses, largely due to timing, increased earnings by $0.06 per share. Finally, a lower effective tax rate increased earnings by $0.07 per share. The lower effective tax rate reflects increased wind product tax credits, the resolution of tax appeals, and an increase in research and experimentation credits. Keep in mind the PTCs will flow back to customers through base rates. The riders of the fuel costs 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. 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 by 0.2%, reflecting approximately 1% growth in the number of customers across those customer classes and jurisdictions, offset by lower use per customer. Natural gas sales increased by 1.8% year-to-date on a weather and leap year adjusted basis, reflecting continued customer growth, partially offset by a 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 costs declined by $49 million, while year-to-date, O&M expenses were $58 million. The quarter and year-to-date O&M underrun largely reflects the timing of planned 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. 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 included in our earnings release. In Wisconsin, we have a pending request to increase electric rates by $25 million and natural rates by $12 million. Gas and intervenor testimony has been submitted, and hearings have included. 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. In Colorado, we filed a multiyear natural gas case seeking a $139 million increase over three years. New Mexico rates will be implemented in January and final rates expected to be effective in March of 2018. We also recently filed a multiyear electric case in Colorado seeking a $245 million increase over four years. Final rates are expected to be effective in June of 2018. In addition, we are 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 to $2.27 to $2.32 per share. Our previous guidance range was $2.25 to $2.35 per share. 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. Finally, we expect O&M expenses to remain flat, but we work to continue improve efficiency and drive costs out of the business. In our earnings release, you will find our updated five-year capital forecast which reflects investment of $19 billion in our base capital plan and drives 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 would 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 and our operating companies, 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 performance is back in the news. In September, where public and 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 is 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 utilities sector. We believe the preservation of interest deductibility and bonus depreciation is in the best interest of our customers. And finally, we believe the transition rules are important to the implementation and we want to ensure that any new legislation and regulation is implemented in a manner that best protects customer interests. While any final legislation could take many forms, we are 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 with an excellent quarter, we filed our proposed Colorado Energy plan which approved, we continue our clean energy transition and add substantial renewable generation and significantly reduce emissions with no incremental costs to our customers. We proposed the Dakota Range project which represents the first wind project planned for 2021 and it is cost competitive and results in customer savings even with the phase down 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 plans that provide transparency and support our 5% to 6% earnings and 5% to 7% dividend growth objectives. Finally, we posted strong financial results for the quarter and are well positioned to deliver earnings within our narrowed guidance range of $2.27 to $2.32 per share. This concludes our prepared remarks. Operator, we'll now take some questions.

Hey, good morning.

Good morning, Julien and welcome back.

Thank you, sir. I appreciate it. Perhaps just first quick question. You never stop asking for more exposure but congrats on moving the guidance range up but suppose the first question I'd love to hear you and spell out the plan a little bit more detail is on the upside case of the Colorado, just the timing of the capital there and ultimately the regulatory recovery scheme and how you are thinking about that phase again, basically at what points in time will you be filing and what point do you expect to actually see that capital play out and what point would you eventually get comfortable putting that another plan?

Okay, well, here is where we are, Julien. We have requests 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 are hopeful for a favorable decision in the summer of 2018. As far as timing goes, I think lots of that will depend upon the proposals themselves and what comes in and what makes sense. So, you know, you're probably starting, so you may just ask the native for you probably in the 2021, 2022 timeframe, but how that would lay in, I think we've got to see what is presented to us and then we'll have a better handle on that.

Got it. Alright, fair enough. And then turning back to Texas, New Mexico just recovery there, the plan, etc., can you talk about perhaps at a high level how you are thinking about moving forward to those projects and ultimately, I'll leave it as high level as asking expectations and earned through the construction project and what sort of palatable to you all in both those jurisdictions?

Well, if you saw our Rebuttal testimony that we've filed in Texas, you see that I think we've addressed the intervenor concerns and you know 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 PTCs, in this case, 100%. I think our revised idea for recovery is one that I think makes all the sense in the world that before they go into the rate base, but rather in operation, we'll enjoy the PTC and any market sales of the project that include the benefit for our shareholders. So if you put all that together, that would be the kind of return that we would need to be able to move forward.

Got it. So you think kind of a consistent level of earn return in that jurisdiction 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, etc, to be improving ROE and see that capital deployment happen said differently?

Yeah, the short answer is yeah. 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 in historic test year mode even in New Mexico where there's a forward test year, but to date the commission has found a way to throw those type those cases out.

Excellent. Well, best of luck and congratulations.

Thanks. Good to have you back.

Thank you.

Thank you. Good morning.

Good morning.

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?

Well, 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 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 in July on the prior call, I think it has to do with - we would have to look at the timing of when those capital expenditures would take place.

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

Hey, Ali. It's Bob. You know, look, when we look at regulated ROEs and where we've been, our objective is to close the ROE gap. I think we've made reasonable progress in that regard. But as the headline allowed to come down slightly, I think where we are year-to-date, where we expect to be for the forecast period is somewhere in that high eights range of earned ROEs in the regulated operating companies.

Okay. So Bob, in other words, you're 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 had been trending fairly nicely and positively through the first half. Anything to read into that? Does that have any implication as you're looking at load growth going forward?

I wouldn't read too much into that; it's more a function, we had a pretty solid Q3 last year and so the relative comparison in Q3 over Q3 looks a little bit down. For the full year, we're still slightly up and within our guidance range. If you look at the trend over a multi-year period, we're still very much in line with our expectations. Q3 of 2016 was probably a stronger quarter, and the relative comparison is down.

I see. Thank you.

Thank you.

Good morning. I was wondering on the Colorado, we stay with Colorado here for a second. Is there any kind of overlap between the multiyear especially when you go out to 2020 and 2021 and the energy plan?

Is there any kind of overlap...?

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

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 is any additional detail, you could?

Yeah. The electric rate case that we filed for four-year plan through 2021 doesn't include any projections or cost recovery for the Colorado energy plan. Those would be recovered under the recovery mechanisms we proposed in a plan like through the ECA.

Okay. Okay. And then quick dividend question?

I don't mind then that you get proposing concurrent recovery.

Okay, for the energy plan?

Yes.

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

You know 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% is still the 60% to 70% range?

I mean I think if we grow our earnings at where we think they are along with the projected dividend thing that it's going to - it would take a long time for us to reach 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 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 part of our plan to make sure that we always have dry powder on the operational side, the financial side, dividend projections, so that we can continue to reward shareholders in a number of different scenarios.

Okay Great. Appreciate it.

Hi, good morning.

Hi, Stephen. Good morning.

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 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 more advantageous as a resource relative to gas generation? What's your sense for where you might end up there?

Well, I 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 prices are something I would have never thought would have been possible eight years ago. So I never short change what technology can do. Right now though, Stephen, batteries and are 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're going to continue to fall in price. You know 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. From a planning capacity, there are differences between a battery and something that can be fired up 24/7 for days at a time. But you can see more batteries on our system, that's the bottom line and we will be positioned to make sure that becomes increasingly more of a mainstream part of our portfolio, while the technology moves at the speed of value. In the meantime, we'll do things like we are doing which is pilot programs etc. to really understand all the various economics, the grid capabilities, and reliability batteries bring to the table. So a 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.

That's very, very helpful color. And just longer term, we've been having great success with the growth of renewable. Is there a point at which storage needs to 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 renewals that you have to significantly step up gas for 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 we are going to have more renewables on our system, I believe, than anybody else in this timeframe, certainly more wind. And so you do 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 your demand response programs etc., making sure that you can shift load to a degree. Where the practical limitations on renewables and on the system and I can tell you I'm working with our operational people and learning all about the system and things like that because I mean at some point as you know you can't truly be 100% renewable within your own grid. You always have to have another place to move excess power and bring in power when you need it, but you can get really, really close. If you look at what we're talking about in our vision case in Minnesota, and what we're talking about in Colorado, I don't think anybody would have thought these things would have been practical five, ten years ago and certainly not at this price point that doesn't raise costs for customers. Did I answer your question?

Yeah, 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 it sounds like stay tuned but it - my sense is it sounds like storage and load volumes, it's going to be an important part of that equation?

All of the above is going to be important.

Hi, Christopher.

Good morning. If I remember correctly, last year when you started to have success on the Minnesota renewable front, then you were kind of discussing the impact on your overall rate base growth and CapEx plan. You deferred some other spending 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 to the plan, let's say you're not successful with any of the on approval 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 well?

The short answer is yes. I think when I made those comments that you referred to, it's really about how much investment you do, and while those investments are incredibly beneficial to our customers, that 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 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 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 keep it in 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 multi-year angle or lack thereof dovetails with the commission's kind of investigation of that as ordered back in June and I think maybe they ordered the ALJ to look into the further potential for forward-looking in multi-year rates?

Yeah, I'm going to turn it over to David Eves again, but I think the success we've had with our multi-year 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 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 an administrative law judge, made it pretty clear that they wanted a policy and full consideration of future test years in a multi-year plan. We're disappointed that the staff even though OCC addressed it somewhat, really sidestepped the issue and did not address the future test years in the multi-year plan. We still think we have a really good case and we'll address that in our rebuttal coming on November 3rd.

Okay. But it's not like you're confident in the commission and their direction that they're going in despite what just asset?

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

Good morning, guys.

Good morning.

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

Yeah, Jon, it's Bob. I don't think we made any direct consideration on tax reform with respect to turning on the DRIP. If you remember, the share repurchase program was initiated when the capital environment was, you know, $4ish billion less than it is today. Keeping consideration for credit and everything else, I think we wanted to make sure that we had a very conservative plan that maintained our credit rating, and a modest amount of DRIP equity annually was enough in our opinion to maintain 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, so at this point, we would consider keeping it on including...

Actually, Bob, my question was when do you turn it on? Do you turn it on in 2018, or is it more the back end of the plan?

Sorry, 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?

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

Yeah, okay.

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, you could do more than that under DRIP on gas?

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

Okay. Alright, great. Thank you. And then could I just on the sort of revised proposals and but I may have missed this, I apologize if I am going over something you covered, but what's your level of confidence that what you put on the table in Texas now for the SPS wind project is kind of going to tick the boxes you need to take and then you can stay on time?

I think it's, first of all, Jonathan, you were 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 to come along with it.

Okay. Can I ask just sort of one sort of point in detail on that, when you guarantee the 100% PTC, is that in the sense of in case the projects 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're not able to fully realize it on a current basis?

No. it has to do with getting in service in time to make sure it qualifies for the 100% PTC eligibility. Now, we do ask in a testimony as you know that our willingness to do that is based upon a commission decision, I believe, in March of 2018, which would allow the time we need to actually get it constructed.

Okay. Great, thank you, Bob.

Thank you. So just looking at, you know, Midwestern utilities pushing 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 component. And so I mean how likely is it that we could see some betterment to the rate base growth, because you would be forced for incidence either write down or shutdown some and depreciate coal plants or gas plants that are currently in the rate base along with the additions of new wind farms?

Well, I can't speak for all of the Midwest utilities, but speaking for ourselves, I think we've done a very good job of developing comprehensive plans that when we do talk about shutting down plants, for example in Minnesota, one and two units that we get the recovery associated with that shutdown. In fact, Angie, if you look at what we're talking about in Colorado, we contemplate accelerating the depreciation of the Comanche one and two plants through a what's known as the reason mechanism, so that is taken care of, and the cost of all of that and 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 the tax reform that happened and the CapEx deductions are extended, would you consider using a tax equity investor to monetize the PTCs, especially under the scenario where you in a way share this benefit up front and then the cash true up of that benefit from your perspective would be delayed if the in-effect bonus depreciation would be extended?

Well, I mean I think you'd have to see what sort of scenarios roll out, but I think one of the scenarios that I think has been pretty successful advocating for, I don't think we'd have the need to do that. You got to keep in mind, Angie, that this, the way I look at these wind proposals is as a deeply, deeply in the money hedge against gas prices. So there's room for these projects to get essentially a little more expensive on the different tax reform scenarios and still bid deeply in the money. We have a great cost of capital 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. I think putting in rate base and delivering the kind of level 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 for SPS, okay so the way I understood it is that you're basically trying to shield the earning during this say 18-month period between when the asset would start operations and we could actually get the rates. But how would that help you increase or realize ROE? I mean that's very, but I mean to me it just seems more like you're basically trying not to have a detrimental impact to the ROE as opposed to making 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 a proposal when it - by the time it's operational, in between operation and in service because we are in historic test year and taxes that we would enjoy the production tax credits in any market sales, that's what you're talking about?

Yes, yeah.

Yeah, well, I think there's some variability in that based on the market sales, but the PTCs would be fairly compelling. Again, I like a rider, a forward rider, but we're also wanting to see these projects get done; they're 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.

Okay. Thank you.

Hi Paul.

Good morning. If 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 that, when it depends a lot on the timing of the proposal that we receive in 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. We look at any changes year-over-year that might be necessary, but the bottom line is assuming it comes in and when we think it would, which is 2020, 2021, 2022, that we'd be able to manage that capital profile.

That was, you said 2020, 2021, 2022, is there a comma between the three numbers, or are those 2020, 2021, and 2022?

Sorry, 2020, 2021, and 2022.

Good morning.

Just to make sure on the CapEx and rate base numbers, does that include all of the SPS wind CapEx? And if the Mexico for incident doesn't happen or what have you, do you have to have both in Mexico and Texas for those SPS wind proposals to happen?

Yeah, Paul, we proposed two projects: one in New Mexico, one 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, you are asking if in the $19 billion, what's included in the base is the assumption that our proposals that SPS go through, so that's in the base. As we mentioned, what's not in the base is the Colorado Energy Plan.

Right. Okay. But just if the full amount of the SPS wind in the base, right?

Yes, including and also in Minnesota, the upper Midwest rather, the Dakota Range project.

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

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

Okay. Okay, that's it. All other questions have been answered. Thank you.

Thank you.

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