Paul A. Johnson - Vice President-Investor Relations Benjamin G. S. Fowke - Chairman, President & Chief Executive Officer Teresa S. Madden - Chief Financial Officer & Executive Vice President.

Ali Agha - SunTrust Robinson Humphrey, Inc. Travis Miller - Morningstar Research Christopher J. Turnure - JPMorgan Securities LLC Michael Weinstein - UBS Securities LLC Paul T. Ridzon - KeyBanc Capital Markets, Inc. Paul Patterson - Glenrock Associates LLC Andrew Levi - Avon Capital/Millennium Anthony C. Crowdell - Jefferies LLC.

Good day, and welcome to the Xcel Energy Third Quarter 2015 Earnings Conference Call. Today's conference is being recorded. And at this time, I would like to turn the conference over to Paul Johnson, Vice President of Investor Relations. Please go ahead..

Thank you. Good morning and welcome to Xcel Energy's 2015 third quarter earnings release conference call. Joining me today are Ben Fowke, Chairman, President and Chief Executive Officer; and Teresa Madden, 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 update you on recent regulatory and business developments, review our 2015 third quarter results, discuss our 2015 and 2016 earnings guidance range. In addition, there are slides that accompany today's call that are available on our webpage. We'll also post a video on our website of Teresa summarizing financial results.

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. I'll now turn the call over to Ben..

the retirement of Sherco Unit 2 in 2023, Sherco Unit 1 in 2026; the addition of 800 megawatts of wind and 400 megawatts of large-scale solar between 2016 and 2020; the addition of 1,000 megawatts of wind and 1,000 megawatts of large-scale solar between 2020 and 2030; and finally, the addition of a 230-megawatt combustion turbine unit in North Dakota and a 780-megawatt combined cycle unit at the Sherco site in the mid-2020s.

While this is an exciting plan that has widespread stakeholder support, it also is a continuation of our proactive environmental leadership strategy, which leaves us well positioned to meet the requirements of the EPA's Clean Power Plan. And I believe this plan will create ownership opportunities for Xcel Energy as well.

The recently-passed legislation, our proactive resource plan filing and our plans to file a multi-year rate plan in Minnesota are all part of our strategy to streamline the regulatory process so we can focus on longer-term energy policy issues. In early November, we plan to file a rate case in Minnesota.

The rate case is driven by capital investment and will incorporate key provisions of the legislation into the filing. While we won't discuss the specifics of the request prior to the filing, I do want to provide you with the overall framework of the case. We are filing a three-year multi-year rate plan.

We're also providing an option to extend that three-year plan to five years. In addition, we will be requesting interim rates for both 2016 and 2017. While the case could take over a year to complete, we are going to see if we can see if we can settle the case or offer mediation to shorten the timeframe to reach a final decision.

I believe the combination of the legislation, the resource plan filing, stakeholder outreach and the optionality of the multi-year plan fling put us in excellent position to achieve a constructive outcome in the Minnesota rate case. So now, let me focus on investment opportunities.

We've previously discussed our plans to step into the development of the Courtenay Wind project. During the quarter, we received approvals from both the Minnesota and the North Dakota Commission. As a result, we're moving forward with the project, which will now be included in rate base versus a PPA, which was the original plan.

Now, this an example of our Steel for Fuel strategy where we take a pass-through cost, move it into rate base and cause a minimal, if no impact to the customer bill. Next, let me give you a quick update on our efforts to rate base natural gas reserves.

In August and September, the Colorado Commission held informational meetings to examine the long-term supply of natural gas and approaches to managing prices, including the rate basing of natural gas reserves. The meetings were very helpful and informative.

We plan to submit a regulatory filing before year-end that will establish a formal framework and incorporate feedback from the meetings. Following the Commission's decision on the preferred framework, we anticipate filing for the approval of potential investments during the second half of 2016.

Finally, this week SPS is filing to transfer about $100 million of transmission facilities located in Kansas and Oklahoma from SPS to one of our Transcos. SPS no longer provides retail electric service in Kansas and Oklahoma. So, this is a good opportunity to seed one of our Transcos with some assets.

SPS will make various regulatory filings at both the state and federal levels and final approval is expected to take about a year. So, you can see it's been an exciting and successful quarter. I will now turn the call over to Teresa, who will provide more details on our financial results and outlook in addition to our regulatory update.

Teresa?.

Thanks, Ben, and good morning. Today, we reported ongoing earnings for the third quarter of $0.84 per share, which compares with $0.73 per share last year.

The most significant drivers in the quarter were improved electric margin, which increased earnings by $0.14 per share and was largely due to new rates and higher rider revenues driven by infrastructure investments that provide long-term value to our customers. The incremental revenue also reflects the impact of favorable weather.

Offsetting the higher electric margin was increased depreciation, lower AFUDC earnings, higher property taxes and higher interest expense. Turning to sales, our year-to-date weather-normalized electric sales were down 0.2%, driven primarily by lower residential use per customer, partially offset by customer growth.

We continue to experience healthy economies in our service territories with an average unemployment rate of 3.6% compared to a national rate of 5.1%. Our customer additions remain solid at about 1%. We have adjusted our electric sales assumption and now anticipate flat sales growth for 2015, reflecting our year-to-date results.

We will continue to monitor sales and customer usage and will take appropriate management action if we determine this represents a longer-term trend. It is important to note that in 2016 we will be implementing decoupling for the residential and small C&I customer classes in Minnesota, which should address any declining customer usage trend.

Next, I'll provide an update on several regulatory proceedings. Additional details are included in our earnings release. In Colorado, we have a pending natural gas rate case and we are waiting for an ALJ recommendation, which we should receive shortly. The Commission is expected to rule in January 2016.

As a reminder, interim rates were implemented in October. In New Mexico, we re-filed our electric rate case, which seeks an increase of $45.4 million based on an ROE of 10.25%, an equity ratio of about 54% and a historical test year adjusted for known and measurable changes.

A Commission decision and implementation of final rate is anticipated in 2016. Finally, in our Texas electric rate case, in mid-October, we received the ALJ recommendations, which reflected a $1 million rate increase and compares to our requested increase of $42 million.

The ALJ's recommendation was based on an ROE of 9.7% and an equity ratio of almost 54%. We reviewed the recommendations and believe there were errors in the filing and, therefore, sent a letter to notify the Texas Commission of our concerns. Late yesterday, the Texas staff revised the recommended rate increase to $14.4 million.

Please note that due to the timing of this update, our earnings release does not reflect this revised revenue recommendation. In addition, we have not had a chance to analyze this subsequent filing. The ALJ's recommendations are somewhat mixed.

We've prevailed on a number of key items such as cost allocation issues that, if supported by the Commission, will establish solid precedent and should eliminate these disputes in future proceedings.

Unfortunately, the ALJ's recommendations did not vary from the historic test-year precedent and rejected our forward-looking adjustments for post-test year planned additions planned additions and FPP cost, which represented a significant portion of our request.

We believe these adjustments relate to policy decisions about the best way to alleviate regulatory lag, which needs to be addressed by the Commission.

While the Commission isn't required to implement provisions of the recently-passed legislation in this case, we remain hopeful that the Commission will be more open to addressing regulatory lag, taking into consideration the intent of the legislation in making its final decision in this case.

The Commission is expected to rule by year-end with new rates effective by January 2016. In our earnings release today, we also announced that we will start using market share purchase to fund our dividend, reinvestment and benefit programs in 2016.

This will eliminate an annual equity issuance of about $75 million and reflects the continued strength of our balance sheet and projected cash flows. This morning we are narrowing our 2015 ongoing earnings guidance range to $2.05 to $2.15 per share. Previously, the range was $2.00 to $2.15 per share.

We are also initiating our 2016 ongoing earnings guidance range of $2.12 to $2.27 per share, which is consistent with our objective of growing EPS 4% to 6% annually. Please note our guidance ranges are based on several key assumptions, which are detailed in our earnings release.

I would also like to mention that we will be hosting an Analyst Meeting at the New York Stock Exchange on December 3.

At the meeting, we plan to update you on our plans to achieve our 50 basis point in earned ROE, our regulatory plans, our plans to meet the requirements of the EPA's Clean Power Plan, our five-year capital forecast including potential incremental investment opportunities. And finally, we will update our rate base growth estimates and financing plans.

With that, I will wrap up my comments. We had an excellent quarter and are on track to deliver 2015 ongoing earnings within our guidance range for the 11th consecutive year. We are on track to deliver O&M consistent with our zero to 2% objective.

We initiated 2016 earnings guidance, which is in line with our 4% to 6% long-term earnings per share growth rate objective. We filed our revised resource plan in Minnesota, which is designed to reduce carbon on the NSP System by 60% by 2030. We have received all regulatory approvals for the Courtenay Wind project.

We completed the Commission informational meeting on the rate basing of natural gas reserves in Colorado. We've made progress on several regulatory dockets and intend to file our Minnesota multi-year rate case next week. Finally, we eliminated all equity issuances from our forecast beginning in 2016. So, operator, with that, we'll now take questions..

Of course. And we'll take our first question from Ali Agha at SunTrust..

Thank you. Good morning..

Hey, Ali..

Hi, Ali..

Morning.

On Slide 10, where you give us your 12 month – or last 12-month ongoing ROE, which has the total OpCo at 9.02%, can you just remind us what is the weighted average authorized to compare it to, just to get a sense of how much lag there is on this last 12-month basis?.

Ali, I mean, on average, we utilize like – our proxy is about 9.8%..

9.8%. Okay.

And Teresa, also in the 2016 guidance, what's the embedded earned ROE that you've budgeted there?.

In terms of the regulated companies it's just north of 9%, about 9.1%..

So, you're not assuming much improvement between 2015 and 2016?.

Well, remember, we have some weather embedded in 2015 and other things. So, we've taken those out of our 2016 guidance..

Okay. Because I thought year-to-date weather was like a negative penny from your disclosures. It was just normal. I didn't think it was a big factor..

It is a small factor. But we've taken that out..

So, Ali, I mean you – I think what you're getting to is the 2018 goal of reducing lag by 50 basis points, because we typically have 100 basis points of lag. And we're going to make improvement in 2016. We're very confident. Clearly, we have to execute on our regulatory plans and our cost control. But we're confident we're going to do that.

And I mean you should be confident that we're going to meet that goal by 2018 and we'll show incremental improvement in 2016, 2017, and then meet it by 2018..

Okay.

So Ben, just to be clear, I mean if through the September quarter, you're at 9.02%, is that a good proxy of where you're going to end calendar 2015 as well given that your big quarters are now behind you?.

I'm not quite sure I can answer that question, Ali. I will tell you that we narrowed the guidance range. You probably can do the math. And I think there's symmetry, so as there is with the 2016 guidance. So, I mean, I think it's pretty transparent where we're going..

Okay. And then, the load growth trends as we look at how the year-to-date numbers are going and now we're assuming flat load growth this year.

What's the visibility or confidence that you can move up to 0.5% to 1% growth next year? What's sort of changing? What do you expect to change to see that pick up?.

Well, the first thing I would remind you, Ali, is that we have less sensitivity as far as earnings goes with the decoupling mechanism that we've put in place starting in 2016 in Minnesota. So, keep that in mind. We are still seeing good customer growth, about 1%. So, that's a good thing, particularly when you combine it with the decoupling mechanism.

What is it? Teresa, I think the third quarter was a bit better?.

It was better. I mean, the second quarter is where we actually saw the greatest decline in this year. And so, we actually were positive in terms of our electric growth in the third quarter..

Last question, coming back to the gas reserve process, what's you sense, when – do you think that the Commission will have formalized their plans by the end of the first half that would allow you to come in, in the second half? Recent meetings I've had with some of the Colorado Commission suggests that they may take up to a year to figure out what their plan is, so by end of 2016 as opposed to earlier than that.

Just curious what your thoughts are on when that is firmed up?.

Well, I mean, it could take longer, Ali, but we're going to make our filing. And then, I think we certainly don't want to see market opportunities slip away. And I think everybody realizes it's a pretty good time to do these investments.

So, I think the compelling economic arguments will drive us to be able to be in a position to move forward as we've outlined..

Thank you..

And we'll take our next question from Travis Miller at Morningstar..

Hey, Travis..

Good morning. Hi. Good morning. Thank you. I was looking at slide 18. First question here, the slide 18 where you have the ROE sensitivities, could you walk real quickly through which of those have the opportunity, I guess, to realize those changes in the next year or two? Obviously, Minnesota Electric, I would assume, you'd have an ROE proposal there.

What other jurisdictions there would have the opportunity to go plus or minus on that ROE?.

Well, I mean, obviously, Minnesota. I mean, in terms of Colorado, in terms of how we come out, we do have our three-year plan. So, we will actively manage that. We have several rate cases that are proceeding or coming to closure so there could be some opportunity with those as well..

Okay.

Is there anything beyond this kind of a 2016-2017 range where you think there could be opportunities there?.

You know, Travis, I think, I mean, this is just a sensitivity graph, and just showing you the impact of 100 basis points change. I think really – I mean, if we – as you know, we typically have been under earning 100 basis points.

And if we – we're still online, right, Travis?.

Yes..

Sorry, we just had a screen go blank here. So, if can't improve that position, we're going to be at the low end of our CAGR EPS growth rate. If we achieve our goal, we're going to be in the middle to upper end.

And if we can close that gap completely, and what I think this chart is trying to show you, then we would actually exceed our CAGR growth rates. So, what's going to be the big driver on that? Well, obviously, Minnesota is going to drive a lot of it. And this five-year or three-year, whatever we end up with, is going to be a big driver in where we are.

But there's other places. Colorado, we've been over-earning so the multi-year plans have worked for both investor and consumer alike. And then, the unknown is Texas. We can continue to improve that regulatory compact, take advantage of the new legislation.

Continue to move the regulatory compact, combine that with the transmission riders we have, that'll push it all up in the upper end. So, it's getting better – it's getting better alignment with our regulators, combining that with cost control. We don't need to issue equity, and that's great. And I think we've got a robust CapEx pipeline.

So, I don't want you to get too caught up on this chart here, because that really is just to show you just numerically what 100 basis points movement does..

Okay. Got it. Thanks. That's helpful.

And then, conceptually here, with the Clean Power Plan, the resource plan and Minnesota potential rate case over a three- or five-year period, what are thoughts generally on customer rate impact, if you were to get to that type of goal, that kind of 60% of clean energy type of level?.

Hey, Travis. I've got to tell you that's a great question, because it's something we really focus on, because I mean you – rate base growth is great. And that's why we're focused on Fuel for Steel or Steel for Fuel, whatever – whichever way you like it. It's basically – the good thing about it is it doesn't impact the customers very much.

So, to specifically answer your question, obviously, when you look at 2030 or through 2030, it's going depend upon what set of assumptions you buy into. I think we're in an environment where gas prices are going to be pretty stable.

I think we're in an environment where renewables are going to continue to fall, even if they're not as supported robustly with – at the federal level with ITC and PTC.

So, really, when I look at it, I think that meeting this – exceeding the Clean Power Plan, reducing our emissions by 60% here in the Upper Midwest, can be done over a cumulative 15-year period with no more than perhaps a 2% cumulative increase over that timeframe, so negligible.

Right? And so, the real issue is going to be, can we build out infrastructure, can we do these other things and not have that pace exceed customer affordability. And I think the answer to that is, yes, we can. Getting into multi-year compacts is the way you do. Cost control is the way you do that.

Discipline about your capital investments is the way you do that. And we're spending a lot of time on that, and I'm very confident this plan is going to be affordable..

Okay. Great. Thanks so much. Appreciate the thoughts..

Yeah. Travis, I'd just say, all you have to do is look at some of the wind assets and other assets we're bringing on there. They're right on parity with fossil. And I think they will be too even with the expiration of tax credits..

Okay. Great..

Thank you..

And we'll go next to Chris Turnure at JPMorgan..

Good morning, guys. You recently increased your dividend growth guidance to 5% to 7% and you established that payout target of 60% to 70%. I just wanted to get a sense going forward, you eliminated the DRIP in 2016 and beyond, I guess.

And in the event that there's less opportunities to deploy your capital, how do you think about the trade-off between kind of increasing the dividend more, upping that payout ratio to the higher end of the 60% to 70% range versus maybe buying back debt or deleveraging?.

Well, let me just say it's nice to have a lot options and that's what we've created for the investor, I believe.

I'd take a little bit of – I'll argue a little bit, I think we've got a pretty robust capital forecast ahead of us and I'm very optimistic beyond the five-year plan we'll continue to have that pipeline as we implement Clean Power Plans and other things across all of our service territory.

And we will give you some more clarity on that at our Analyst Day. So, could we do more? Sure. And we're going to – our stated goal is to grow the dividend at 5% to 7%. We have a lot of runway. But I mean, right now that's what we're focused on, the 4% to 6% EPS growth, 5% to 7% dividend growth.

If we are at the upper end of our EPS growth rate, we'll never really exceed that 60%. We'd stay – the payout ratio today would stay about the same, which would give us more flexibility. So, it's really – I think we're kind of in a great position to have a lot of levers to reward shareholders.

And one of the things everybody worries about is rising interest rates. And if and when that ever happens, it's great to be able to do more with your dividend to perhaps offset that risk, and we've got that flexibility..

Okay. Great. And then, I wanted to drill a little bit more into the situation in Texas right now. Teresa, you gave a bit of detail in your comments on your requests for a forward-looking test-year based on what the legislation had suggested or allowed for.

But could you give us maybe more context here? I think it's difficult to understand the mandate or lack thereof on the Commission and what kind of recourse you would have, what kind of next steps you would have there, if in fact the final decision said no on that..

Well, maybe we'll start with it wasn't a forward test year in terms of what we had filed. It was basically a historical test year with known and measurable adjustments. So, that was our baseline. The ALJ's recommendation came back excluding those.

We do think this is a policy decision and that that would be something that the Commission would make, not necessarily ALJs would make.

So, as I've indicated, we're hopeful that when the Commission actually rules on this that they will take into consideration the new legislation that was passed earlier this year to include the post-test year adjustments. Now, they wouldn't be required but we're very hopeful, because it has been basically implemented with the new legislation..

So, I think Teresa is right. I mean, the ALJs probably would be more reluctant to make a policy call. And as you know, this is the last rate case we filed prior to that legislation. But the legislation exists, so you would like to think the Commission would look towards that as they review the case. But we're going to know by the end of the year..

Okay.

And do you think the fact that the case was filed before the legislation was passed is a significant issue?.

I mean, clearly, the legislation was not in place when we filed that case. So, that is a factor..

Okay. All right. Great. Thanks, guys..

So, Travis (sic) [Chris] (29:20), just to be clear, this is the last case where essentially the Commission has discretion. On future cases, the decision will be based on the legislation that was passed..

And we'll take our next question from Michael Weinstein at UBS..

Hi. Good morning. Hey, I was just curious about if the Minnesota – the next big rate case is going to be multi-year and the Clean Power Plan portion of the IRP is going to be during that – probably some of the construction would be occurring during that period – during a plan that's already been filed and in place.

Is there any – can we expect to see some of the construction that's in the IRP before the IRP is approved within the upcoming rate filing in Minnesota?.

Maybe I'll start with that and then Ben you can jump in. The things in terms of additional construction potentially and particularly ownership, we do have renewable riders available for infrastructure investment. So, we would think it would be not part of that base rate case plan if that helps explain in terms of how this could play out..

And also, I'm sorry if I missed this before, but have you guys – have you had any indication so far from other parties about what kind of a – the length of a plan that might be accessible?.

Are you talking about now in Minnesota with the three-year plan we filed with the option to go five year?.

Yes. I mean, was there a lot of opposition to five years or – I'm just curious of what the climate is..

I think anytime you do something new, you're going to get some resistance. I mean, that's just the way things go. But I have to tell you, I had the opportunity to talk to the Commission, as I've made in my opening remarks, and I think they were pretty interested in learning about it.

I think everybody knows there's – we should be looking at more efficient ways to process the recovery of our infrastructure investments. And I think there's compelling reasons to go to five years. That said, I mean if it's three years, it's three years.

The key is to have the longest runway possible and to close the regulatory gap and to really – one of the things too is I really want to have more dialogs with all stakeholders and certainly policymakers and regulators about the kinds of opportunities and the things that we need to do to advance the ball here in Minnesota.

And that goes for all of our jurisdictions as well..

What do you think is the key portion of regulatory lag that you're experiencing that you expect to reduce by 50 bps by 2018?.

Well, I mean it's going to – it depends. But I mean, Minnesota is the biggest place. Right? That's where most of the – I know it's the biggest jurisdiction that has some lag. So, a lot of it has to do with the fact that we filed a – we broke ground with a multi-year plan in this last rate case, but it wasn't a comprehensive multi-year plan.

We didn't get – it was – we were able to step into large capital projects in that second year, but that meant all the traditional projects, we had to wait. So, that creates lag on that. We've had some property tax increases. We've had forecasts for sales that didn't quite live up to expectations in Minnesota.

So, a lot of that – well, some of those – (33:14) sales is taken through with the decoupling mechanism. And the other pieces will pick up in this more comprehensive multi-year plan that we now have available to us via the legislation.

I'd say that's the biggest thing, wouldn't you, Teresa?.

Yeah. No. I would agree. And some of the lag historically has been tied to specific issues. And Ben was mentioning like property taxes, but Monticello in terms of some exclusions of the investment, I mean that's behind us in terms of resolving that issue.

Even going back a couple of years, the Sherco, the catastrophic incident that caused some lag as well. But those big issues we think are behind us. And as Ben indicated, this will be a comprehensive filing that we think will well position us..

Yeah. And just to build on what Teresa said is, I mean, this is a case that's very straightforward. It's a recovery of capital investments. So, I mean it's a capital-based case. I mean there's a very little O&M in this filing. So, I mean, that's been one of the things we wanted to do, is bring down our operating expenses and we're accomplishing that..

So, would it be safe to say that you're being conservative when you project, say, was it a 9.1%, I think, for next year ROE?.

Yeah, I mean, I'm not quite sure. I wouldn't get fixated on that number..

Yeah. Okay..

I think we're going to be – our guidance is symmetrical, so you can kind of do the – we've got as much upside as downside to be in the middle of the range. We're going to make improvement in 2016, and then it's going to be steady improvement.

I mean, there's – how much and what we can accomplish in 2016 is going to – Minnesota is going to move the needle, obviously, what happens there, but there's other jurisdictions as well. But I think we're in a really, really good shape to achieve our reduction of 50 basis points lag by 2018..

All right. Well, thank you very much..

Thank you..

And we'll go next to Paul Ridzon at KeyBanc..

Good morning.

Have you – maybe it's early in the process, but have you kind of quantified what your annual – how much you'd like the rate base in Colorado for natural gas?.

We've never really quantified it and we're going to start relatively small and build on that. But I mean, if we just look at the LDC requirements in Colorado, and if you assume we did about 25% of that through gas – natural gas reserves in rate base, I think over a decade you're probably looking at about $500 million, okay, could be more.

Obviously, you could more than 25% and you could obviously expand that beyond just the LDC requirements in Colorado.

Does that help?.

Just so do you think you would do it as chunky or kind of do the same size annually or...?.

I don't think you want to do it all at once..

Right..

But I mean I think there's probably logistical things you would have to consider.

So, I don't think it would just be – I think it would be semi-chunky, how's that?.

Obviously, it just depends on the asset opportunities and how big they are..

That's what I – that's better said..

Thank you very much..

You're welcome..

And we'll go next to Paul Patterson at Glenrock Associates..

Good morning.

Are you there?.

Good morning. Yes, we're here..

Okay. Sorry. I just wanted to make sure. A couple of things. You guys put a pretty compelling story up for the multi-year plan and what have you, I missed that (37:10).

But I'm just wondering if it were not to happen, are there other levers that you guys are contemplating for, perhaps, closing the ROE lag or potential ROE lag, going forward?.

I mean, we're obviously going to do everything we can to achieve our earnings goals. So, we'd have to see. I mean I'm pretty confident that we're going to be able to get a multi-year plan in place. It'd rather be five years, it could be three years. And I think there is a lot of openness to that.

So, I think we're getting into really hypothetical situations. We'd have to react to whatever the Commission, as we always do, gave us. And the point is we're going to – we'd have to be even probably more disciplined on the cost side.

But you start to get – you can achieve earnings goals, but at some point I think they cut into some of your other objectives with building out the infrastructure, modernizing it, getting customers better options, achieving environmental excellence; all those things that are kind of the hallmark of Xcel Energy.

So, I don't think that's a bridge we're going to have to cross, Paul..

You know I would agree with you. I mean, frankly, we've already completed one multi-year plan, so we have the precedent behind us..

You're right Teresa. It'd be a real step back..

Yeah. And we have the new legislation. So, I mean, that seems like minimal risk that we would not be able to complete a multi-year. It's just how many years..

Okay. Then the second question, and I apologize I just didn't get this completely. You guys mentioned I think transferring assets transmission assets from SPS to a Transco.

Could you elaborate a little bit more on that in terms of the size of the assets, what have you?.

So, these are assets that are in Kansas and Oklahoma, where we no longer serve retail load there. You might recall we sold those jurisdictions off a few years ago. So, we think it's an opportune time to move those assets, and specifically they're worth about $100 million, into one of our Transcos and seed those Transcos with some assets..

And maybe just to supplement that, it's about 230 miles of transmission line. It is 345 kV, and it's the line plus some additional equipment that goes with the line..

It sounds pretty small. So, the purpose of this – I mean, obviously, you might want to prefer them in (39:59) Transcos. Like you said, it's to seed it, so therefore you could expand on it, you think, in a more effective way.

What are some of the more effective way than where it currently is?.

Well, I mean it's small, but I bet you a lot of other people would love to have that opportunity, as everybody competes for that. And I think there is some value too to have some actual assets inside a Transco. As I think it gives you more gravitas, if you will, when we get into the FERC 1000 bidding process..

Yeah. It will help in terms of establishing the public utility status in Kansas for the Transco..

Yeah..

So, there's several benefits of seeding it..

Okay. So, I guess, we'll stay tuned on that. And then, on wind versus fossil, and you made some intriguing comments that way (40:49) that I think without the tax credit, you think it will be competitive.

Could you just elaborate a little bit more on that or just quantify that slightly to me in terms of what you're – how competitive you're seeing in terms of fossil?.

Well, I mean let's start with what we have today. Okay. And I'll stick with wind, which does enjoy the production tax credit, which is worth about $22 a megawatt hour. So, with that credit in mind, we're see wind deals that have come to us across all of our regions in the mid-$20s megawatt-hour levelized 20 years.

Now, compare that, Paul, to what we could go out today and buy a strip of natural gas future contracts for. I mean, even in this low gas price environment, if you took those gas reserves, took it, times it by the applicable heat rate, I think you'd find $25 a megawatt hour for wind would be on parity, if not in the money.

So, essentially, what we're doing when we're buying wind is hedging natural gas volatility. Now, obviously, if you take away $22 from the equation, you're not looking at $25, you're looking at $47. It's a little bit out of the money. Of course, natural gas prices are at historic lows.

And then, I would say that – and this applies to solar as well, is that they continue, these technologies, at large scale, to become more and more efficient. And so, I don't think their pricing's going to go up. I think if – wind, if anything, will stay flat.

But I mean we've seen – gosh, in just five years, we've seen capacity factors go from the mid-30%s to now the low-50%s. So, they've seen steady improvements. We all know the story with solar. So, I'm optimistic about it..

Okay. And I guess, we're just looking at a pure megawatt-hour. We're not talking about the benefit of dispatch or anything like that. You're just saying if you look at it from a pure megawatt-hour perspective and with technology....

Yeah..

...you're thinking that you can get somewhere close to that..

Yeah. But Paul, I mean, that's a really good question and I'd be happy to talk to you more about it, because I was just looking at that – I used wind as an example, because I think it's easy to get your arms around. Wind, today, you still have a – you still build a gas plant, right? Okay.

But whether you fire up that gas plant with natural gas or you idle it and have it ready to go, but you displace that natural gas with wind is the equation I was talking to you about. It gets a little more complicated when we talk about solar.

And the way I'd look at it briefly is that probably the capacity value that you bake into that is the difference between a combined cycle plant and a combustion turbine plant, roughly. I mean, it gets a little bit more complicated and we probably can take it offline..

Okay. Sure..

But it's pretty exciting economics. And then, you get the ancillary costs as you get more on the system. It's one of the reasons why we're studying more and more of what batteries can do for us. It's not like batteries are in the money for us today, but neither was solar 10 years ago.

And so, we want to be ready for when the technology moves into the value part of our sweet spot..

Great. Makes sense. Thanks a lot..

Okay..

And we'll go next to Andy Levi at Avon Capital Advisers..

Hey Andy..

Andy..

Hi. Good morning. Actually, I think I'm all set. But maybe just a couple housekeeping stuff. Just on the stock issuance or lack of it.

So, even the DRIP is eliminated, so the shares should kind of stay where they are for the next couple of years, there would be no increase in the shares at all or there are some type of employee plans or...?.

That's correct, Andy..

Okay. Good. Okay, because I had a couple of million a year. Okay. And then I think it's called the Courtenay Wind Farm.

Is that correct?.

Yeah..

I got that right? What's the status of that?.

All approvals have been received and we're in the construction mode. It's going very well..

Okay.

And that'll come online the end of 2016?.

Yeah. Towards the end of 2016, a little before the end of 2016..

Okay.

Is there anything in your 2016 forecast for Courtenay?.

We haven't updated our CapEx for Courtenay, Andy. And of course, that'll be one of the things that we update for you at our Analyst Day..

Okay.

But that would really be – that would be 2017 earnings or you would get some AFUDC from that? Isn't there some type of rider in Minnesota or something like that?.

Yeah. There is a rider mechanism..

Right.

So, I guess, I understand you didn't update the CapEx, but is that incorporated in your forecast that you gave for 2016 or not?.

I mean, it's – that part of it's all embedded in that overall 2016 guidance number we gave you..

Okay. That's great. And then, just one last question on the gas reserves..

Yeah..

Just to understand, you wouldn't strike a deal with a farmer, for no better way to put it, without regulatory approval, is that correct, or would you go to the regulators even though you don't – the scheme itself is not finalized?.

I mean, we wouldn't get ahead of ourselves if that's what you mean. We're going – I mean, I'm not quite sure what your question is. I mean, I think you get the framework....

Well, I guess....

You get the framework established, Andy, and then you – if it then – the specific way you implement that, I think if it's in the framework, you give yourself the leeway so you don't have to run back and have this endless clock running.

But I mean, that's kind of what we're trying to establish now is how you would execute on it and what the model would look like..

Right.

But the framework is not set yet, is that correct?.

That's correct..

Okay..

Right. We're going to file before the end of the year, the framework..

Okay. I got it. Okay. Thank you very much..

But we love doing deals with farmers, so....

There you go. There you go. And I'll leave that alone. I won't talk about those new Colorado farmers, so....

Hey, that's good load, Andy..

Okay.

0.5% I heard, net of growth, isn't it something – but seriously, isn't it like 0.5%?.

Yeah. No, it's not insignificant..

All right. Okay. Thank you very much..

All right. Thanks..

And we'll go next to Anthony Crowdell with Jefferies..

Hey. Good morning. Just a question. It looks like the Street and most of us are expecting the company to narrow the earnings gap from 100 basis points to 50 basis points, and you've been very clear that you hope to get there by 2018.

But if I thought longer term, do you think there's an ability to narrow that gap even more to maybe earning your allowed return in all your businesses?.

That is the goal. So, yeah – I mean, the answer is yes. And we're....

Is it an attainable goal or is it just structural that it's hard to do with large CapEx spend, or...?.

No, I don't think it's – no, it's not a vision that can't be achieved. It's aspirational, I guess, you would say. But it's not pie in the sky, by any means. Look at what we've already done in Colorado with our multi-year plan..

Right..

Look what we're doing in Wisconsin. I hope to be able to report really positive results for you in Minnesota. So, Texas, that's probably going to be harder when you're in historic mode and building a lot of capital. But at some point, you're – that capital profile slows down a bit and so the lag becomes less pronounced.

So, I think it's not impossible at all..

Yeah. I mean I think that's why we were so focused on multi-year plans. The tenants have multi-year plans because it provides flexibility that could allow opportunity to earn a greater return..

Yeah. Cost control, sales, all of that would enter into that at that point..

What do you think the opposite – like as you're introducing multi-year plans in Minnesota, I think, Ben, you had said you met with some of the – I don't know if it was regulators or whatever, and they were very interested in the multi-year plan.

I mean just what would be the opposition to a multi-year plan for the regulators?.

Change..

That's – okay..

I mean that's probably the one word I would use..

I think the multi-year plan just to supplement that, because we are using forecasts and potentially whether it'd be a question of over earnings, and I think we could put things in place to moderate that, if we get in that event..

Yeah. But I mean there's change and then you can sub-bullet points under it. But the reality is it's different from the way we've done it before..

And I guess, in Minnesota, there's always the ability, if the regulator believes you're over-earning in a long-term plan, to call you back in.

Is that correct?.

Every jurisdiction has that ability..

That's right..

Perfect. Thanks so much for taking my questions..

Hey, we appreciate it. Thank you..

Thanks..

And with no further questions left in the phone queue, Teresa, I'd like to turn the conference back over to Teresa Madden for any additional and closing remarks..

Sure. Thank you for all participating in our earnings call this morning. Please contact Paul Johnson and the IR team with any follow-up questions. And we look to seeing you at EEI..

Thanks everyone..

Thanks..

And this does conclude today's presentation. We thank everyone for their participation..