Paul Johnson - Vice President, Investor Relations Benjamin Fowke - Chairman, President and Chief Executive Officer Robert Frenzel - Executive Vice President and Chief Financial Officer David Eves - President and Director, PSCo

Julien Dumoulin Smith - Bank of America Ali Agha - SunTrust Travis Miller - Morningstar Stephen Byrd - Morgan Stanley Christopher Turnure - JPMorgan Jonathan Arnold - Deutsche Bank Angie Storozynski - Macquarie Capital Paul Ridzon - KeyBanc Capital Markets Paul Patterson - Glenrock Associates

Good day, and welcome to the Xcel Energy Third Quarter 2017 Earnings Conference Call. Today's conference is being recorded. At this time, I'd 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 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 earning 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 earning 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 and renewables. So let me provide you an update of 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 and the continuing transition of our generation portfolio and contemplates the early retirement of two coal units at our Comanche Plan 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 rather dollars. 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 our commission decision by the summery 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 to 1,200 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 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 approved 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, interveners provided initial testimony and as expected, they push 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 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 intervener 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 firth quarter in 2018. As the company has progress 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 of 5% to 6% annual growth. I feel very confident, we can deliver EPS growth within this range based up 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 driver 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 recovery our capital investments, offset by production tax credits that flew 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 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 back to the customers through base rates, riders of the fuel cost don't have a material impact on net income. Offsetting these positive drivers where increase 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 0.2%, reflecting approximately 1% growth in the number of customers across those customer class and jurisdictions offset by lower use per customers. Natural gas sales increased 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 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. The quarter and year-to-date O&M underrun largely reflects the timing of plan 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 cash included in our earnings release. In Wisconsin, we have pending request to increase electric rates by $25 million and natural rates by $12 million. Gas and intervener testimony since submitted and hearings that's 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. And in Colorado, we filed a multiyear natural gas case seeking a $139 million increase over three years. NM 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 $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 were narrowing our full year 2017 earnings guidance range $2.27 to $2.32 per share. Our previously 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 also initiating our 2018 earnings guidance range of $2.37 to $2.47 per share, which is consistent with our revise 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 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 result an 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, operating company and holding company there to fund our capital plan. And for the past several years, we've used market purchases for our benefits programs, however going forward, we expect 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 back in the news. In September where public and leadership and the administration release the high-level framework that would service a template for legislation that we expect to be released in draft form next week. There is a lot of uncertainly 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. And we believe the preservation of interest deductibility and bonus depreciation are expensing a capital is in the best interest of our customers. And finally we believe the transition rules are important to the implementation and we work within to ensure any new legislation and regulation is implemented in a matter that best protect for customer interest. 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 ramp 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 submissions with no incremental costs to our customers. We proposed the Dakota Range project which represents the first wind project plan 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 objective. 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, $2.32 per share. This concludes our prepared remarks. Operator, we'll now take some questions.

Thank you. [Operator Instructions] We will take our first question from Julien Dumoulin Smith from Bank of America. Please go ahead.

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 expose but congrats on moving the guidance range up but suppose the first question I love to hear you and spell out the plan 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 in time do you expect to actually see that capital play out and what point would you eventually get comfortable put that another plan?

Okay, well, here is 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 are 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 makes sense. So you know you are probably starting so I mean could just ask the native for you probably in the 2021, 2022 timeframe, but how that would lay in, I think we got to see what is presented to us and then we have better handle on that.

Got it. Alright, fair enough. And then turning back to Texas, New Mexico just recovery there, the plan et cetera, 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 intervener 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 PTs will be eligible for the PTCs, in this case a 100%. And I think we're - 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 rather an operation, we'll enjoy the PTC and any market sales of the project that included 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.

Got it. So you think kind of 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 et cetera 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 your 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.

And our next question comes from Ali Agha from SunTrust. Please go ahead.

Thank you. Good morning.

Good morning.

If the Colorado project does get approved and you add the 1.5 billion CapEx to you 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 the 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 - July on the prior call, I think it has to do with - we would have to look at the timing of when that 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 significant pick up 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 a regulated ROEs and where we've been on objective is to close ROE gap. I think we've done a reasonable amount of 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 have been trending fairly, nicely and positively through the first half. Anything to read into that is that have any implication as you're looking at load growth going forward?

I wouldn't read too much into that it's more of a function, we had a pretty solid Q3 last year and so relative comparison in 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 multi-year period, we're still very much in line with our expectations. So Q3 of 2016 was probably a stronger quarter and the relative comparison is down.

I see. Thank you

Thank you.

Our next question comes from Travis Miller from Morningstar. Please go ahead.

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 four your 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's going to - it would take a long time for kick at the 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 as that dry powder and 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, dividend projections. so that we can continue to reward shareholders on a number of different scenarios.

Okay Great. Appreciate it.

Our next question comes from Stephen Byrd from Morgan Stanley. Please go ahead.

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 by 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 there's no way I would have ever thought it would be possible eight years ago. So I never short change what technology can do. Right now though Stephen, it is batteries and are relatively low-cost jurisdictions don't compete economically, there might be some opportunities in some areas deploy then, 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. And from a planning capacity, there are differences between a battery and something that is 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 will be positioned to make sure that becomes increasingly more of a mainstream part of our portfolio, while at the technology move at the speed of the 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 reliability, 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 made the right economic decisions for our customers.

That's very, very helpful color. And just longer term we 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 you 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 a 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 we're 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 about your demand response programs et cetera making sure that you can shift load to a degree. Where the practical limitations on renewable and on the system and I can tell you I'm working with our operational people and learning all about system and things like that because I mean at some point as you know you can't - with today's technology, you cannot truly be one 100% renewable within your own grid. You always have to have another place to move and excess 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 and in Minnesota 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 out of the 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 understand but it sounds like stay tuned but it - my sense 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.

Very good. Thank you.

Our next question comes from Christopher Turnure from JPMorgan. Please go ahead.

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 are 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. We could - I think when I made those comments that you referred to, it's really about how much great investment you do and while those great investments are credibly 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 deal - the Dakota Range budget as an example of that. So I have no doubt that we will need our rate base growth projections.

Okay.

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 do 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 dove tails with the commissions kind of investigation of that is 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 where that - 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 the staff really sidestep 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 there kind of just in general the direction that they're going in despite what just asset?

Yeah, 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 the gas revenue requirement is really a capital driven. We're investing very significantly and the basic system but also in all the integrity work and part of this plan is to replace the PSIA with for a test year multi-year plan. So I think it's set up well.

Okay. That makes sense. Thank you.

Our next question comes from Jonathan Arnold from Deutsche Bank. Please go ahead.

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 - 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 dollars 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 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 and 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 like in 2018 or is it more the back end of the plan?

Sorry, we expect 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. All right, 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. SoI 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 it 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.

Our next question comes from Angie Storozynski from Macquarie Capital. Please go ahead.

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 investment, but we're starting to see first indications that intervene 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 our shutdown some and appreciate coal plant or gas plants that currently existing of rate base along with the additions of new wind farms?

Well, I can't speak for all of the Midwest utilities but speaking for itself, 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, one and two 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 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 plans 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's happened and the CapEx deductions are extended, would you consider using a tax equity investors to monetize the PTC's 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 it 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 scenario that I think 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 as a deeply, deeply in the money hedge against gas prices. So there's room for these projects to get essential 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 mention it probably would get more expensive. So 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 periods between when the asset would start operations and we could actually get the rates. But how would that help you increase of 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 to the ROE as opposed 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 tax 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. And 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 associate with those particular projects.

Okay. Thank you.

Next question comes from Paul Ridzon from KeyBanc Capital Markets. Please go ahead.

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 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. And 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 are that 2020, 2021 and 2022?

Sorry 2020, 2021 and 2022.

Okay. Thank you.

Our next question comes from Paul Patterson from Glenrock Associates. Please go ahead.

Good morning.

Hey Paul.

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 incidence doesn't happen or what have you, you have to have both in Mexico and Texas for those for the SPS when proposals 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 the Mexico for approvals for both projects.

So Paul, you are asking 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, but as we mention 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 it - there was a problem in New Mexico or something is that, would that basically - with that 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. But 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 been answered. Thank you.

Thank you, Paul.

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 in Orlando.

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