埃克西爾能源 (XEL) 2016 Q3 法說會逐字稿

Good day and welcome to the Xcel Energy third-quarter 2016 earnings conference call. Today's conference is being recorded. At this time, I would like to turn the conference over to Paul Johnson, Vice President of Investor Relations. Please go ahead, sir.

Good morning and welcome to Xcel Energy's 2016 third-quarter earnings release conference call. Joining me today are Ben Fowke, Chairman, President and 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, initiate 2017 guidance, update you on recent business and regulatory developments, and update our five-year capital forecast financing plan and rate-based growth.

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.

Thank you, Paul, and good morning, everyone. Today, we reported third-quarter GAAP and ongoing earnings of $0.90 per share, compared with $0.84 per share last year. Year to date, we are $0.07 per share ahead of last year, and as a result, we are narrowing our 2016 guidance range to $2.17 to $2.22 per share from the previous range of $2.12 to $2.27 per share. We still anticipate earnings in the middle of the range. We're also initiating 2017 earnings guidance of $2.25 to $2.35 per share, which is consistent with our long-term EPS growth objective of 4% to 6%.

We had a productive quarter, and we continue to make progress on investment plans and regulatory initiatives. I'll briefly touch on some of the highlights. Today, we are updating our five-year capital forecast, and you will notice a significant increase in renewable investments. Therefore, I'm going to spend a few minutes discussing our steel-for-fuel strategy.

Our service territory is unique in its concentration of renewable, rich resources. For example, the capacity factors for wind generation are approximately 50% in Minnesota and Texas, and about 45% in Colorado.

When you combine high-capacity factors, a strong transmission network, and the extension of the production tax credit, it all translates into low renewable energy costs for our customers. Today, we can add wind energy which meets or beats the cost of fossil-generation resources.

Because of the strong wind resources in our backyard, we have the unique opportunity to invest in renewable generation in which the capital costs are offset by fuel savings. Therefore, we are lowering the emission profile of our generation fleet with significant fuel savings, which allows us to grow our renewable portfolio with no impact to customer bills.

A prime example of our steel-for-fuel strategy is the Rush Creek wind project in Colorado. In September, the Colorado Commission approved our request to develop the 600-megawatt wind farm with a capital investment of approximately $1 billion. We will start initial work on the project this year, and it's expected to go into service in 2018.

Another example is in Minnesota, where the commission recently approved our resource plan, which includes the early retirements of two coal units at our [Circo] facility and the addition of a significant amount of renewable energy. In accordance with the resource plan, we have issued an RFP to add up to 1,500 megawatts of wind generation.

This week, we filed a self-build proposal to develop 750 megawatts of wind generation, which would meet half of that resource need. We believe that our projects reflect competitive pricing, and are confident that the commission will approve our proposal in the first half of 2017.

We expect both of these wind projects will generate hundreds of millions of dollars in fuel savings for our customers, which will more than offset the capital cost, highlighting the benefit of our steel-for-fuel strategy.

Turning to the operations side of the business, more than a decade ago, we partnered with a group of smaller utilities to form CapEx 2020 and transform the transmission grid in the upper Midwest. That transformation was made a reality with the recent completion and energizing of the 156-mile Hampton-Rochester-La Crosse transmission line. CapEx 2020 has now invested $1.9 billion in completing four high-voltage transmission lines totaling nearly 725 miles.

A fifth project in South Dakota is scheduled for completion in 2017. These transmission projects are addressing reliability needs and increasing access to renewable energy across the upper Midwest.

I'll now turn the call over to Bob to provide more detail on our financial results and outlook, in addition to our regulatory update.

Thanks, Ben, and good morning. Today, we reported GAAP and ongoing earnings of $0.90 per share for the quarter, versus the $0.84 per share earned last year. The most significant earnings drivers in the quarter include higher electric and natural gas margins, which increased earnings by $0.15 per share, largely due to rate increases and capital [right of] recovery for infrastructure investments, along with sales growth and favorable weather.

We also realized a lower effective income tax rate due to higher PTCs from wind projects, which increased earnings by $0.02 per share. Partially offsetting these positive drivers were increased depreciation expense, largely due to capital additions, and reductions in excess depreciation and reserves, which reduced earnings by $0.06 per share, and higher interest in O&M expenses, which combined, reduced earnings by $0.05 per share.

Our third-quarter electric sales came in stronger than expected, and increased 1.6% on a weather-adjusted basis. We saw positive sales growth in the residential and C&I classes. We continue to experience strong customer growth of approximately 1% for both our electric and our natural gas businesses.

While we're happy to see a quarter of strong sales, it's a little early to call it a trend, and our year-to-date weather-adjusted electric sales remain relatively flat. Therefore, we remain cautious on the sales outlook and anticipate flat year-over-year sales.

We're very focused on managing our cost structure for the benefit of our customers. Our year-to-date O&M expenses are approximately 1% above last year. We experienced higher strom costs and maintenance expense in the third quarter, and expect full-year O&M to be slightly above 2015 actuals. We continue to mitigate O&M increases through our efforts to improve productivity through capital investments and the use of technology, and we expect to carry this effort into the future.

During the quarter, we made significant progress in a number of proceedings across our territories. You'll find more details in our earnings release, but let me provide some highlights.

Consistent with our strategy to implement longer-term rate plans in our jurisdictions, we reached a preliminary settlement with the majority of parties in our Minnesota electric rate case, which would provide revenue certainty through 2019. Key terms for the four-year plan include an ROE of 9.2% and an equity ratio of 52.5%, an annual sales true-up, a continued use of all existing riders, a four-year rate-case stay-out provision, a property tax true-up, and a capital true-up mechanism.

We expect an ALJ report in March of 2017 and a final commission decision in June of 2017. As a reminder, interim rates subject to refund are in place while the commission considers the case.

We're pleased to announce that we've reached a settlement and agreement in principle in our Texas rate case, and hearings have been vacated. We're working on documenting the settlement and plan to file it in the fourth quarter. Although we can't provide any details until the documentation is finalized, we believe that the settlement is positive and reflects a growing constructive regulatory environment in Texas and New Mexico.

Finally, we also have a pending rate case in Wisconsin, where we requested a revised rate increase of approximately $35 million between electric and natural gas. Just yesterday, the Wisconsin Commission verbally approved a combined increase of approximately $27 million, which reflects complete recovery of our requested natural gas rate increase and an adjusted electric rate increase. Final rates will be implemented in January.

Turning to earnings guidance, based on our year-to-date results, we are narrowing our 2016 ongoing earnings guidance range to $2.17 to $2.22 per share. Previously, the range was $2.12 to $2.22 per share. We are also initiating our 2017 ongoing earnings guidance of $2.25 to $2.35 per share, which is consistent with our objective of growing EPS of 4% to 6% annually.

Please note our guidance ranges are based on several key assumptions, which are detailed in our earnings release. However, a couple of the 2017 assumptions are worth mentioning.

We assume constructive regulatory outcomes in all proceedings. We're assuming sales growth of 0% to 0.05% in 2017, and O&M expenses are expected to stay flat with 2016 projections. This will mark a third year in a row of near flat O&M, reflecting our commitment to continuous improvement of our cost structure.

Finally, we've updated our capital forecast and now expect to invest $18.4 billion over the next five-year period of 2017 through 2021. This forecast drives annual rate-based growth of 5.4% using 2015 as a base. The capital plan reflects $3.5 billion of renewable investments, including the Rush Creek wind farm, our proposal to add 750 MW of wind in the upper Midwest, and incremental renewable generation to capitalize on our steel-for-fuel strategy.

Again, it's important to point out that our capital investment in renewable generation is offset by fuel savings, so there's no impact on the customer bills. Further, we don't plan to issue equity to fund this capital plan, due to our strong balance sheet and credit metrics.

In summary, we continue to execute on our strategic financial and operational plan. We had a strong quarter and are on track to deliver ongoing earnings within our guidance range for the 12th consecutive year.

We reached a rate settlement in Minnesota and settlement in principle in our Texas rate case. We're executing on our steel-for-fuel strategy with the approval of the Rush Creek wind project and the submittal of our 750-megawatt wind proposal in Minnesota and North Dakota.

We've established 2017 earnings guidance consistent with our long-term growth objective of 4% to 6%. And finally, we've updated our five-year capital forecast, which supports continual infrastructure investment in our service territory and delivers rate-based growth of 5.4%.

This concludes our prepared remarks. Operator, we will now open the phone for questions.

Thank you.

(Operator Instructions)

We'll take our first question today from Julien Dumoulin-Smith with UBS.

Hey, Julian.

Good morning, everyone.

Good morning.

First quick question, if I could follow up, you talk about the 5-4 rate base. Can you elaborate a little bit on your earned ROE expectations as you start to get some clarity here between settlements across your jurisdictions into 2017 and onward?

Are you talking about the ROEs we'll earn on the actual incremental renewable?

Yes, basically, where are you with respect to your ability to get your earned ROE up, vis-a-vis what you guys have talked about at the last analyst day?

Okay. Julien, you remember when we set a goal that we were going to cut the lag that we experienced between actual and authorized by 50 basis points by 2018, and that goal is still something we're very focused on. Some things have changed, of course. Authorized ROEs have fallen a bit, as you well know.

So I think for us to continue to improve ROEs, we'd really have to cut that lag by more than half and get closer to actually earning the authorized ROEs, which is, I think more realistic for us than before because of some of the settlement agreements we've entered into. So count on us to show steady ROE improvement as we proceed down the five-year path.

Great. Excellent, and can you comment real quickly on the renewal bucket of CapEx there? It seems if I do 19% times the new CapEx number, it might be a little higher than I think the $2 billion you'd previously discussed for renewables allocated. Can you walk down what's changed a little bit in the CapEx, specifically on that element?

To walk you through it, and we previously were at 15.2 base camp. So the first thing that we did was update it for our -- the approval of Rush Creek project, and then what we've done is we had placeholders, as you may recall, Julien, at NSP Min for some renewable additions. We took those placeholders out and put in the actual CapEx we believe we'll get with the approval of these 750 megawatts of wind. That adds another $700 million to the forecast, so that should bring you up to about $16.7 million, and then you add $1.5 billion for more steel-for-fuel opportunities that I think we have across all of our jurisdictions. That should, if I've done the math right, get you close to where we are.

Got it, so basically, just to be clear though, there are additional undefined opportunities baked into (inaudible) that you anticipate disclosing or pursuing at another point in time?

Yes, that's right, roughly about $1.5 billion. And, Julien, I think we're confident that those opportunities will become reality, because the whole premise of steel-for-fuel is you can do things on an economic basis cheaper than the fossil alternative. In reality, the environmental benefits are the icing on the cake. When you're not impacting customer bills and you're driving environmental leadership, it's really a unique position for us to be in.

Great. Thanks, guys.

We will take our next question from Ali Agha with SunTrust.

Thank you. Good morning.

Hey, Ali.

Good morning, Ali.

Good morning. First, I wanted to clarify as you mentioned, Ben, your outsized ROEs, specifically, I'm thinking Minnesota obviously have come down, part of the settlement. So when we run the math now and we look at your blended [rated] authorized ROE with a 9.2 number from Minnesota baked in there, versus what you've earned over the 12-month period, what is the lag right now that you have in the overall utility system?

The overall utility system or NSP Min?

I'm curious for the overall, but the NSP Min specifically as well.

Well, I think this year, Ali, we'll probably earn around 9%. So I think if you blended all of our authorized ROEs, it would probably be about 9.6%, roughly around there. So you've got -- so that would be 60 basis points of lag. That's less than what we had before. Remember, when we first initiated that closed the gap, it was more like 100 basis points of lag.

So I think the challenge in the opportunity for us, Ali, is to -- with for example in Minnesota, it was clearly that was a compromised 9.2 is not the ROE we would have preferred to have. However, when you look at the comprehensive settlement, we have a much better shot than we've ever had before of actually earning our allowed returns. And you recall that in Minnesota, we had been lagging, and frankly even more than 100 basis points.

So we'll get at it differently. We've got a lower blended ROE base, but I think with multi-year plans, comprehensive multi-year plans, we can probably do better than just cut the lag in half, and that's the plan.

And then in Minnesota strictly, where would you ending the year (inaudible)?

Say that again, Ali, you broke up.

Sorry. So 9% you said you'd earn across your portfolio, but what would be the ROE earn in just NSP Minnesota?

For what period?

For this year, for your 2016 (inaudible).

I think it's roughly around 9% as well.

9%. Okay. So relative to 9.2%, you pretty much caught up there then?

Yes, I think -- we do -- I will say that we do have a regulatory amortization asset in 2017 that will create a bit of a headwind in Minnesota, all things equal. So when we look at 2017, the blended utility ROE is blended. For all of our ROEs, your probably roughly around 9% again.

But again, that amortization falls off in 2017, our cost initiatives continue to gain traction. And we continue to stay focused on two critical aspects of shareholder value: growing rate base with our steel-for-fuel strategy and keeping our costs as low as they possibly can be, as we've done over the last three years, while not sacrificing reliability and not deferring unnecessary maintenance.

And then second, on the CapEx numbers, I just wanted to clarify two things. One is if I'm hearing you right, previously, the bucket that you had put out there as growth potential CapEx, I think, at that time was $2.5 billion, $1 billion was the Colorado wind and $1.5 was everything else. If I'm hearing it right, that's all now part of the base program and then you extended it by a year. First of all, I just want to be clear, is that correct?

Yes, Ali, I think that is right on the capital program. This is Bob. On the capital program, we had the base case and the upside capital that we used to disclose. And for clarity purposes, we put it all in one capital forecast. As we've talked historically about, I think we realized most of that upside case capital, and then we've put additional wind and renewable development opportunities in our forecast.

Ali, I don't have it in front of me, but that $2.5 billion, you are right, it had Rush Creek, it had like, I think about $300 million of gas reserves. Of course, we're not going to do that now. It had some advanced grid opportunities, I believe, associated with the north in Minnesota. And then we had, I think, other renewable opportunities.

So to Bob's point, we basically have achieved the upside CapEx just with renewables. Again, the clarity we've seen with steel for fuel is really unique for us, and I think we'll continue to look for opportunities to transition the fleet, achieve remarkable carbon emission reductions at no additional price point to the consumer.

That's what I wanted to clarify, the grid modernization and some of the other buckets. Are those no longer being pursued? As you mention, it's all now renewables or are those still out there somewhere?

No, they're -- we anticipate advanced grid in both Colorado and Minnesota. There might be some upside to this capital forecast, but I would -- but basically that's been captured in the 18.4 that you're looking at.

I see. Last question also and relative to now your new rate-based growth forecast of 5.4%. If I equate that to your EPS growth aspiration of 4 to 6, so it looks like you no longer need a lot of ROE improvement to get there. As long as you can sustain ROE, rate-based growth should drive you, at least through the midpoint maybe higher end of the growth forecast. Am I thinking about that correctly or how are you thinking about that now?

Ali, I think you're spot on. I think you take that growth rate, we don't need to issue equity. We have an incredibly strong balance sheet. And so if we can see the ROE improvements, that will just drive you beyond the 5.4%.

Got it. Thank you.

Thank you.

We will take our next question from Greg Gordon with Evercore.

Good morning, Greg.

Good morning. These guys nailed most of the questions I wanted to ask, which just to be clear, looking at your CapEx forecast now versus your prior CapEx forecast, you've got -- the biggest delta is renewables and that includes the plant that you've already had approved.

The remaining CapEx is the assumption that you get the 750 megawatts self-build approved, or is it that you get the 750 megawatt self-build approved and then there's other placeholder CapEx for further renewables in the plant?

To get you to the 18.4, you're right about Rush Creek in Colorado, which is approved. It also assumes that we have the opportunity to build half of the RFP. We think that our self build-proposals are very compelling. We could also get there, through, potentially build-on transfer. But the assumption is that the capital associated with that RFP, half of that accrues to our shareholders and rate base.

That leaves a delta of about $1.5 billion, which are opportunities that we think are spread across all of our jurisdictions. We certainly could do more than 50% in Minnesota. I think there's more opportunities to do more in Colorado, and frankly, Greg, when you look at the economic price point that we believe -- that we are seeing with wind, I think we have opportunities potentially in Texas and New Mexico to adjust on the economic merits alone.

So when you came up -- it goes beyond the current approval on the self-build of proposal. Was that some top-down assessment of market opportunity with a risk weighted? Did you start with a market opportunity and say, we think this is the potential pie, this is what we can achieve on a risk-weighted basis over time or how did you come up with that number?

Okay. You broke up at the very beginning. You're just asking how we derived that we can have half of the 1,500 megawatts?

How did you come up with the remaining $1.5 billion placeholder CapEx as being a realistic expectation?

Look, there is almost infinity when you're saving customers money and achieving environmental benefits at the same time. It's just really, I think, just an analysis of the additional opportunities, transmission constraints, operational-type considerations. And when we go across all of our jurisdictions, I think it's a very realistic opportunity.

Great. Last question. What's the outside date in terms of timing for getting the approval on the self-build option in the two jurisdictions?

Well, we already have approval in Colorado so that's done. And then in Minnesota, we expect to have that decision I believe it's the second quarter of 2017, correct?

That's our goal, yes.

Fantastic. Thank you, guys.

Thank you.

We will take our next question from Chris Turnure with JPMorgan.

Good morning. I wanted to focus on rate-based growth, like some of the other questions, but in particular the, I think, accelerated nature of that rate-based growth within in a potential 2016 to 2021 plan. So if you look at your Minnesota RFP, you have anticipated start of construction for some of those projects in the middle of 2017 and then them coming online loosely before 2020.

Is there a potential to, if you're successful there, do that faster? And then when you combine that with the Colorado wind project coming online, in I think the fourth quarter of 2018, really frontload or find that some of the rate-based growth is front-loaded toward the 2018 to 2019 period?

Maybe something in 2019, but I think the practical realities of construction seasons, et cetera, probably -- I think we've got our best estimate.

Okay. And secondly, on the dividends, when you look at your capital plan here that's increased a lot since the prior one, and you combine that with the fact that you don't need, I think, any equity internal or external, how do you think about your 5% to 7% dividend growth guidance that you had previously laid out?

Well, I think it's pretty safe and pretty sustainable. I think, as you know, this was a deliberate strategy that we had. We embarked upon an aggressive, at the time, aggressive CapEx spend a decade ago and we deliberately, during that timeframe, grew our dividend slower than our earnings growth. And that created a fortress balance sheet for us.

Now we have a modest payout ratio of 60%, 61% payout ratio. I think that's pretty low compared to our peers. It gives us a lot of what I would call dry powder. So count on the 5% to 7%.

What we would have is if interest rates start to rise and you see the industry headwinds that would come with that, we certainly could step back and work with our Board and determine if there's something else we need to do. I'm not saying we're going to do that, but it's just when you have a strong balance sheet, deliberately created, it creates far more opportunities to reward shareholders, and that's something we're pretty proud of quite frankly.

Okay, and then just one more real quick, if I could. When you think about rolling forward your EPS growth CAGR, potentially, on the fourth-quarter call, what constraints might there be there on the regulatory front or on the Minnesota RFP front that might be taken into consideration by you there?

I'm not quite sure --

In terms of anything of what could hold you back in releasing that number or caveats to the growth rate as a result of waiting for regulatory decisions.

Chris, I think the guidance we provide today is going to -- we expect it to be consistent with fourth quarter and any roll forward in terms of capital and earnings and dividends. We don't expect that to change, consistent with past practices. So we do expect regulatory outcomes that are reasonable. We lay out a host of assumptions that go into our 2017 guidance and our long-term earnings guidance in our earnings release today, and we expect those are the assumptions for 2017.

Okay. Thanks, guys.

Thank you.

We'll take our next question from Travis Miller with Morningstar.

Hey, Travis.

Good morning. Thank you.

How are you?

I am good. I was wondering, in terms of regulation around these renewable projects or rate regulation around these, what's the current method that you expect to go forward with? Is it just your traditional backward-looking type of freight filings? Or is there potential there to convince regulators that with these multi-billion-type of investments, you could get rate riders or some return on quip, something like that?

I think what we're talking about here in Minnesota, we'd be eligible for rider recovery. We've had those mechanisms in place for a while, so I think recovery will be concurrent. The $1.5 billion that I talk about, that will just depend on what jurisdictions we do that in. Some will be eligible for riders, some we might propose some enhanced-type recovery mechanism, as you suggest, Travis. So I think we're in really good shape with the renewable spend and getting recovery that doesn't have lag associated with it.

Yes, similarly, Travis, in Colorado the recovery of the Rush Creek wind farm is through riders as well.

Okay. And one more general question. Obviously, the fuel-for-steel is a nice strategy for you guys. Is there any pushback on the regulatory front? Is there anybody saying, no, we shouldn't be doing this, we shouldn't be allowing Xcel to be doing this?

I don't know. I think people are pretty excited about it actually. We -- when you can -- let's talk about the upper Midwest. When you can show regulators a plan that could achieve 60% carbon reduction and do that at no incremental price point from a more traditional plan, it's pretty exciting.

No, we haven't seen pushback at all. We have seen a lot of the excited. In fact, I expect people to say, can you do more? Which is usually the way these things works. And so, no, I think it's created really good alignment with our stakeholders quite frankly.

Okay. Great. Thanks so much.

We will take our next question from Paul Ridzon and with KeyBanc.

Hey, Paul.

Good morning. How are you?

Good.

You said one of the drivers in the quarter was a lower tax rate because of higher PTCs. Was that a function of, I think the wind was a little weaker than normal last year and it was more normal this year?

Paul, this is Bob. We put two wind farms into service in 2016, so year-over-year effective tax rate is just going to be lower due to the PTCs for those two farms.

There's not -- I'm not sure how the rate making works, but is there exposure to a low wind regime if you have a particularly weak quarter or does that flow through the fuel cost?

There is [no exposure]

Okay. Thank you very much.

We will take our next question from Angie Storozynski with Macquarie.

Hey Angie. Good morning.

How are you. Good morning. So just going back to the renewables being added to the rate base versus the lack of growth in power demand. I understand that renewables look cheaper than conventional power plants, but what happens with the assets that you have in the rate base and when there is no growth in power demand and you keep adding generation assets?

Well, Angie, I think that's a really good question, but let me try to answer it this way. I think what we're really doing with wind particularly is just really buying the fuel we're going to use tomorrow on sale today. So when you think about it, it's not that it doesn't open up a dialogue for early retirement of coal plants, but essentially what you're doing is you're displacing fossil fuels with wind. You might still have the generation plant, the fossil generation plants, but you don't have to use it as much natural gas, even coal, when you're displacing that fuel with wind fuel. Does that make sense to you?

It completely does, just my question would be more, you could buy this wind power from an outside provider that could probably use higher leverage on that project. And granted, the cost of capital would be probably slightly higher than yours, but again, the leverage ratios would be higher. So net-net, the cost of that power would probably be similar.

I know that would be an earnings-neutral exercise for Xcel, but I'm just trying to figure out wondering from a regulatory-risk perspective if adding renewables at a rate base in the absence of low growth is actually a low-risk growth strategy.

I think whether it's contracted for or added to rate base, I don't think that influences very much your concern. I think broader based, I don't think our rate-based self-build proposals are going to -- -- they're going to be cost competitive, even with the leverage that others use towards banking on our strong balance sheet to support that. There is an element of that, and I think our regulators are well aware of that and appreciate the benefits of utility ownership. I really think that when you pencil out the numbers, you see how compelling, particularly when you do it on a fully holistic basis, how compelling our proposals are.

And Angie, it's also important to recognize that there is -- some of these wind resources are being added to reflect the fact that there are coal plants being retired in the future. So we're just taking opportunity to capture the full PTC, so maybe the wind comes on service a little before some of the coal retirements, like [Sherco]. So I think we're trying to accomplish that.

Angie, I think that's a -- Paul made a great point, because when we're talking about early retirement of coal plants, this is our resource plant. We're the ones that are leading the decarbonization of our fleet. I think we will show that we can build wind competitively, and I think we've earned the right to own wind in our backyard and it's all part of an overall plan. Again, I think it does require alignment with your regulators, but I think we have it.

Good. Thank you.

Thanks, Angie.

Will take our next question from Joe Zhou with Avon Capital Advisors.

Hi, it's Andy Levi. How are you guys doing?

Hi Andy.

You're happy to hear from me. That's always a good things. You guys are doing a great job, as well.

It depends on your question, Andy.

That's because we love you.

You guys are really doing a good job. We appreciate it. Actually just two small questions. One is just more around the amount of debt that you plan to issue over the next several years. In the whole scheme of things, it's not that important.

But just why is it $5 billion because we're coming up with a little bit less, likely $3.5 billion just based on your cash flows. Are deferred taxes coming down a little bit on the cash flow statement or what's -- just based on the numbers that we're running, I'm just wondering why $5 --?

Hi Andy. This is Brian Van Abel. I think it could be part in terms of the tax utilization over a couple of years about when you think that we're going to start using that deferred tax asset, that could be part of it. But overall in the slide that we show, we show our cash from operations that we generate. So the number we have in there is consistent with our expectations.

We come up with a little bit less, but not a big deal. Then the second question for Ben.

So once you get through this final order in Minnesota, obviously, it seems that the ROEs are improving, you have tremendous amount of opportunities on the CapEx side. It seems that you, as a Company, your managers have very good visibility as far as O&M costs and other operational costs and seem to be doing a very good job there, both currently and going forward.

You have a growth rate out there. As you get into 2017 and 2018, what are your thoughts on the growth rate? Does it generally stay the same? Are there opportunities to potentially raise the growth rate or at least raise the bottom end of it as your ROEs improve and the projects come online?

Well, I think Andy, as you know, I think we've got -- if we can execute on both the rate-based growth and the ROE improvement, we're going to be at the top of that range, maybe potentially beyond it, and that's what we're going to focus on in the next year and the years to come as driving that. We'll let things fall into place as they may.

Great. Thank you very much, and you guys, again, are doing a great job.

Thanks, Andy.

We'll take our next question from Paul Patterson with Glenrock Associates.

Good morning. How are you? I wanted to, first of all, just on the Minnesota case, is there any possibility that the people who haven't come on board with the settlement could be coming on? Is there any potential that you could wrap up the regulatory process before the schedule that you have now? If it could be accelerated at all?

That's a question I ask my regulatory team all the time. There's always a possibility, but I think the reality is because it wasn't a unanimous settlement, you've got to go through the process and we're going through that process right now. So we'll look for those opportunities, but quite frankly I think it's just on the schedule that we put forth.

Okay, and then with the steel for fuel, I would like to just review this a little closer. So when you say that the steel renewables are cheaper than the fossil fuel, that includes, for the renewables the production tax [credits] and everything there. It doesn't include a cost of carbon. Is that correct? Or does it?

That's correct. No, it doesn't.

Okay. And it's really only the fuel component that you're talking about? Piggy-backing off of Angie's question, it's the fact that you're just not burning the fuel, that, in and of itself, that pretty much is the offset?

Yes. I think the fundamental, when we look at it, it's just swapping fuel for, in this case, wind fuel. But what it sets up going down the road, Paul, is the dialogue that you can have, and we've already made -- we've had some of that dialogue already in Minnesota, about retirement of coal plants. And then you talk about how are you going to replace those coal plants?

Our thought is that you do it with gas generation. You don't necessarily have to do megawatt for megawatt; that's a function of your sales forecast. But the fuel swap alone will work, but then it sets up the dialogue about ultimately what your portfolio is going to look like.

That anticipated my question actually, so I want to let you keep going there. So when we're thinking about this, it would sound like there may be additional benefits if there was a cost of carbon. If there is a replacement in terms of actually O&M perhaps or any other incremental things, so it could actually be more than just an offset, it could actually be seen, if you took other things into account, a net benefit for customers. Am I wrong?

No, I think you're right. Now cost of carbon, of course, it's an exercise outside of the pure economics, right?

Right.

So you're implying a societal benefit and that sort of thing, which were not opposed to, but what we're focused on is just the straight-up numbers of what we can do, capturing 100% PTC with wind, with fuel. And then that can allow you to have further dialogues around, as I mentioned, the earlier shutdown of coal plants, the O&M and all the other things that go with that.

You start to design your portfolio to be more load-following, because if you look at where we think we're going to be in 2030 with our carbon reductions, I think we have -- and in the upper Midwest, we'll have 15% of our energy mix from coal. You need to make sure your generation portfolio has been designed in a way that you can accommodate these additional renewable resources without sacrificing reliability. That's all part of our planning process. So the short answer to your question was yes.

Thank you, and then just in terms of this steel for fuel, this is -- your fuel assumptions are the four curves? Is that what we should think about when you're saying that or is there some proprietary fuel? In other words --

I think that's right, that's right. And when I say we can do it cheaper, I'm also talking -- maybe I'm being more aggressive than that. You couldn't go out today and lock in a 10-year strip cheaper than we could on gas, cheaper than we could lock in wind.

So and then if you look at fuel forecasts, which the blended -- the forecast that you talk about, tends to have fuel escalating in the future. Quite frankly, I don't know if that's going to happen. But what we have today is so compelling that it almost -- the fuel would have to fall off quite a lot for us to say it didn't actually save customers money.

This is with current technology on the wind side, as opposed some -- as we've seen, improvements in that area. You're not banking anything on that either? There's -- any potential --

I do think -- here's what we believe. We believe solar and wind will continue to fall in price, and the continuous improvement we've seen. However, the PTCs, as you know, start to fall off at 20% each year after this year. And so I think the prices we are hopefully going to lock in for our customers today at 100% PTC, even with the technological improvements, you will not see prices the strong again until probably the -- or this low again rather, until probably the mid-20s.

Okay. Thank you very much.

That's why wind is on sale. Thank you.

We'll take our next question from Stephen Burke with Morgan Stanley.

Good morning, Stephen.

Hey. Good morning. I wanted to, we've covered a lot of topics in Q&A, just in terms of wind. You've had a lot of success in Colorado and Minnesota. And you've mentioned in the past some potential for further growth in wind and some of your other jurisdictions.

Are there milestones, things we should be watching for, ways to think about that opportunity to put a little bit more specifics around that in terms of what you might do there? Or is a little bit further out? Do you need to do a lot more work before that could be realized, or is this something that we should be looking for more near-term?

Define near-term.

Yes, fair point.

Stephen, I would characterize it as if you look at the capital forecast and the earnings release, we put our best guess as to when those dollars could and would be spent. That's our likely -- bake into account, regulatory approval and further work, regulatory approval and construction cycle, those are our best estimates at this point.

Understood. That's really all I had. Thank you.

Thanks, Steven.

We'll take our next question from Shelby Tucker with RBC Capital Markets.

Good morning.

Good morning, Shelby.

In your 2016 financing plan, it seems that now you plan to issue about $800 million of holdco debt in the fourth quarter. I'm guessing that's primary to fund the equity needs of the utilities in the higher CapEx program. How much more debt capacity do you think you have at the parent as you look to fund equity needs over the next five years?

Well, if you take into account the capital forecast that's embedded in the earnings release, you'll see our expected debt issue is against our cash flow from operations. I think that's our best guess for what the capital plan and the financing plan looks like for the next five years.

Shelly, maybe I don't want to be the CFO or the Treasurer here, so please correct me, guys. When I look at our credit metrics under this plan, they stay very strong. And so that, again, I think speaks well to the balance sheet that we have.

And then is there any -- do any of the jurisdictions ever question you on the level of debt you take on at the parent?

No, because it's still, Shelby, it's very modest and as you know, we've always had the philosophy there is a benefit of strength in numbers. You get a -- if you're an operating utility and as part of a larger group, you do get a consolidation benefit, provided there isn't excessive leverage at the holdco, and we're not even close to that.

All of our utilities benefit from being part of a bigger group, and that's always been our approach and that will continue to be our approach. We would never do anything that would be harmful to the credit ratings of our utilities. And I think our track record speaks for itself on that.

Great. Thank you.

Thank you.

That will conclude today's question-and-answer session. I would now like to turn the call back over to Bob Frenzel, CFO, for any additional or closing remarks.

Thanks, everyone, for participating in our call this morning. Please contact Paul Johnson or Olga Guteneva with any follow-up questions.

That does conclude today's conference. Thank you for your participation and you may now disconnect.