Paul A. Johnson - Vice President of Investor Relations & Business Development Benjamin G.

S. Fowke - Chairman, Chief Executive Officer and President Teresa S.

Madden - Chief Financial Officer and Senior Vice President

Paul B. Fremont - Jefferies LLC, Research Division Travis Miller - Morningstar Inc., Research Division Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division Greg Gordon - ISI Group Inc., Research Division Paul Patterson - Glenrock Associates LLC Julien Dumoulin-Smith - UBS Investment Bank, Research Division Andrew Levi

Good morning and welcome to Xcel Energy's 2013 Year-End Earnings Release Conference Call. Joining me today are Ben Fowke, Chairman, President and Chief Executive Officer; Teresa Madden, Senior Vice President and Chief Financial Officer; Dave Sparby, Senior Vice President, Group President and President and CEO of NSP-Minnesota; Scott Wilensky, Senior Vice President and General Counsel; George Tyson, Vice President and Treasurer; and Jeff Savage, Vice President and Controller.

This morning, we will review our 2013 results and discuss our 2014 priorities, update you on recent business and regulatory developments and reiterate our 2014 earnings guidance. Slides of the company today's conference call are available on our web page.

In addition, we will post a brief video of Teresa Madden summarizing our financial results 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 in our filings with the SEC. Today's press release refers to both ongoing and GAAP earnings.

2013 GAAP earnings of $1.91 per share included a $0.04 per share charge as a result of a 2013 FERC decision regarding fuel cost -- fuel and cost allocations at SPS. These issues relate to complaints by parties dating back to 2004 and 2006.

While we are pursuing reconsideration of these orders, they resulted in a refund liability for prior periods. And consequently, we took a $36 million pretax charge during the third quarter of 2013.

2012 GAAP earnings of $1.85 per share included a $0.03 per share tax benefit associated with federal subsidies for prescription drugs planned that were previously expensed. Both items are excluded from ongoing earnings.

Management believes ongoing earnings, provides a more meaningful comparison as representative of Xcel Energy's Fundamental core earnings power. As a result, our comments will focus on 2013 ongoing earnings of $1.95 per share compared with 2012 ongoing earnings of $1.82 per share.

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

Well, thank you, Paul, and good morning. I'm pleased to announce another successful year at Xcel Energy.

In addition to delivering on our annual financial objectives, we executed on several initiatives that position Xcel Energy for continued financial and operational success in the years to come. Let me start by discussing some of our 2013 highlights.

Once again, we delivered strong financial results. Ongoing earnings grew over 7% to $1.95 per share.

This marks the ninth consecutive year with net books [ph] exceeded our earnings guidance. In the fourth consecutive year, we have delivered earnings in the upper half of our guidance range.

We also raised our annual dividend $0.04 per share or nearly 4%. We completed rate cases in several jurisdictions, which helped us to achieve our financial objectives in 2013.

Looking back on 2013, we're especially proud of the commitment to customers that our employees demonstrated again and again. A series of severe weather events, including blizzards, high storms, thunderstorms and floods, brought out the company's best efforts.

We also completed several major construction projects, including the effort to extend the life of our Monticello nuclear plant, and we placed steam generators at our Prairie Island nuclear plant. Our Sherco 3 coal fire unit is back in service after sustaining major damage in 2011.

We brought Jones 4 online in Texas and in time for higher summer load and to help serve the continued industrial growth we're seeing in the region. Colorado.

We made great progress on the Clean Air-Clean Jobs Act projects, including the Cherokee combined-cycle plant and adding SCRs and scrubbers to Ponne, as well as SCRs at Hayden. Overall, these projects remain on time and on budget.

Another major focus in 2013 was our ongoing work to increase the strength and reliability of the electric grid. We're making significant investments to ensure the system is ready to accommodate renewable energy, interact with new technologies and withstand major weather events.

Strong energy grid ensures that we're able to meet the growing and changing energy needs of our customers. We are set to increase our future wind production by 40%.

And given the current price of wind energy, this is an excellent way to protect our customers from rising fuel costs. The American Wind Energy Association recognized our efforts to promote wind production when they named us The Utility of the Year.

And we obviously the appreciate the designation, but we're particularly satisfied that we've determined how to make wind energy an affordable option for customers. In another effort that leverages our environmental leadership for customer gain, we were able to announce in 2013 that we're on track to exceed our goal of reducing carbon emissions from our power plants, 20% by 2020, compared with 2005 levels.

We are well positioned on this run in part because we acted early in converting and refurbishing power plants and because we have such a solid portfolio of renewable energy sources. With a successful 2013 behind us, we're ready to make 2014 another good year.

Our focus will be on ensuring that Xcel Energy is the energy provider that our customers prefer and value. We have initiatives underway to achieve productivity improvements through technology and to leverage employee engagement.

We will continue our efforts to strengthen the energy grid, build our portfolio of renewable energy resources and reduce emissions from our plants. Part of our effort to strengthen the grid, we plan to invest $4.5 billion on transmission projects over the next 5 years.

We've proven that we can design, cite and construct transmission for less than our competitors. And we see significant opportunities right in our backyard.

We believe forming a Transco will provide multiple benefits, including enabling increased flexibility to support our operations in the post-FERC Order 1000 transmission investment environment. Depending on regulatory treatment, we believe that our planned projects in the Southwest Power Pool fit nicely into a Transco.

The necessary regulatory filings will be submitted later this year, and we hope to have approvals by late 2014 or early 2015. Another key priority for us is to deliver constructive outcomes in our regulatory proceedings and to improve the overall regulatory construct.

In 2014, we hope to put in place multiyear-rate plans in Minnesota, Colorado, North Dakota and potentially other jurisdictions, which will provide revenue certainty for shareholders and cost certainty for our customers. Achievement of our 2014 priorities will allow us to deliver on our objectives and provide an attractive total return to our shareholders.

I'll now turn the call over to Teresa.

Thanks, Ben, and good morning. As you can see from our earnings release, we had another strong year.

On a consolidated basis, 2013 ongoing earnings grew $0.13 per share or 7% to $1.95. This resulted in a consolidated ROE of 10.5% on an ongoing basis.

The improvement in profitability was primarily the result of new interim rates implemented across several jurisdictions, positive weather and lower interest expense. These positive factors were partially offset by higher O&M and depreciation expenses.

More specifically, I wanted to provide you with some insight into several drivers for the year. First, weather was very favorable in 2013, increasing earnings almost $0.11 per share compared to normal, and $0.06 per share compared to 2012.

Sales growth was slightly stronger than expected for 2013. Weather-adjusted retail electric sales increased 0.4%, and firm natural gas sales increased 3.8%.

However, sales growth varied by operating company. On a weather-adjusted basis, our electric sales growth by OPCO was: NSP-Wisconsin, 0.8%; PSCo, 1%; SPS, 1.7%; and NSP-Minnesota declined 0.8%.

The economies in our service territories continue to improve. Overall, compared to the national average, we had higher job growth and lower unemployment in our service territory.

Finally, at SPS, we sold 2 small segments of transmission lines that were no longer needed to support our customers. As a result, we recognized a $0.02 per share gain on the transaction after sharing with customer.

Next, I will provide some detail on the financial results of each of our operating company. At NSP-Minnesota, ongoing earnings grew 13% to $0.79 per share, primarily due to new rates going into effect in Minnesota and South Dakota, and interim rate in North Dakota.

Cooler winter weather and lower interest charges also served to improve 2013 earnings. Even with the benefit of positive weather at NSP-Minnesota, our earned 2013 ROE of 9.2% was well below our authorized level.

We have filed a propose multiyear-rate plan in Minnesota in an effort to close this gap. Earnings at PSCo increased $0.01 per share in 2013.

The primary drivers were higher electric and natural gas rates, cooler weather and lower interest charges. These positive factors were partially offset by higher depreciation, O&M and customer refunds related to the 2013 electric earnings test.

Similar to 2012, in Colorado, we over-earned our authorized electric ROE of 10%. As a result, we recognized a refund obligation to customers.

After accounting for this refund, as well as the under-earnings in our natural gas business, PSCo earned a consolidated ROE of approximately 9.7% in 2013. At SPS, earnings increased $0.01 per share to $0.23 for the year.

The positive impact of an electric rate increase in Texas and the sale of transmission assets to Sharyland were partially offset by higher depreciation expense. Our ongoing ROE was 9% at SPS.

We continue to make progress on regulatory front, getting writers put in place and the use of a forward test gear in New Mexico. Texas and New Mexico offers substantial organic growth opportunities due to the continued expansion of the oil and gas industries located within our service territory.

As a result, we've identified certain attractive infrastructure investments that will help develop this part of the country. Getting the rules in place to ensure timely recovery, as well as establishing an alternative investment structure that Ben discussed, will be an important part of our future.

We've made great progress at SPS and we're excited about the opportunities ahead. Finally, earnings in NSP-Wisconsin increased $0.02 per share, as a result of higher electric and natural gas rates, cooler winter weather partially offset by higher O&M and depreciation.

Our earned ROE at NSP-Wisconsin was 10.6%, slightly higher than our overall authorized level. I'll now comment on several of our pending regulatory proceedings.

Additional details related to these and other proceedings are included in today's press release. As you may recall, last November, we filed a 2-year electric rate case in Minnesota.

In December, the Minnesota Commission unanimously approved our request to file and granted a $127 million or 4.6% interim rate increase, which went into effect earlier this month. The Commission also agreed that our request to accelerate the theoretical depreciation reserve amortization was permissible.

The procedural schedule for the Minnesota case was established this week and is included in the earnings release. Intervenor testimony is due in June, hearings are scheduled for August, the ALJ report is due in December, and a final decision in this case is expected in the first quarter of 2015.

In our North Dakota electric rate case, we reached a comprehensive multiyear settlement agreement with the staff, which includes a 4-year rate plan with 5% annual increases in retail revenues for the first 3 years and no rate increase in the final year. This settlement also includes a gradually-increasing ROE during this multiyear period.

Hearings on the settlement were held last week, and a final decision is expected from the North Dakota Commission this quarter. At SPS, our New Mexico requested $32.5 million rate increase is pending Commission's decision.

On January 23, a hearing examiner provided a recommended decision, which included an ROE of 9.73% and a requested equity ratio of 53.9%. The recommendation did not include a revenue requirement calculation, but our initial analysis indicates a reduction to our base rate request of about $6 million, which results in a base rate increase of approximately $15 million.

The recommended decision did not address the renewable writer. The Commission's decision is expected in April.

In Texas, we recently filed for a net increase in electric rates of $52.7 million or 5.8%. We have requested the implementation of interim rates of $32.6 million, effective on March 1.

Intervenor testimony is due in May and hearings are planned for June. We anticipate a final decision and the implementation of final rates in the third quarter.

Turning to our financing plans. Today's press release summarizes our 5-year financing plans related to our $14 billion capital expenditure forecast.

We plan to issue the following post-mortgage bonds during the first half of the year: approximately $300 million of both NSP-Minnesota and PSCo; approximately $150 million at SPS; and approximately $100 million at NSP-Wisconsin. We also have plans to issue equity during the next 5 years.

While we don't plan to provide you with the specific timing of the equity issuance, I will point out that our CapEx program is front-end loaded, and we anticipate our equity issuance will likely be similar. With that, I will wrap up.

Once again, we delivered 2013 earnings at the upper end of our guidance range. We're proud of our track record of generating the financial results that our investors expect.

Operationally, we continue to provide our customers with a high level of service, even when faced with several severe weather events. We continue to make important investments in our system that position our company for long-term operational success, and will allow us to provide strong customer value for many decades to come.

We are positioned to continue to deliver attractive shareholder returns well into the future. In summary, we're proud of our 2013 achievements and look forward to updating you on future successes in 2014.

This morning, we are reaffirming our 2014 ongoing earnings guidance of $1.90 to $2.05 per share. Please note, we've updated certain guidance assumptions to reflect 2013 actual results.

Details of these changes can be found in today's press release. In particular, we have revised our depreciation assumption to reflect our proposed moderation plan in the Minnesota rate case.

When we originally issued our guidance assumptions in the third quarter, it was prior to our filing of the Minnesota rate case. So we reflected a total then-expected increase in depreciation expense.

The moderation plan, if approved, would reduce both revenue and depreciation expense by approximately $81 million, but wouldn't impact earnings per share. Therefore, this assumption change doesn't impact our guidance outlook.

So with that, Calvin, we'll now take questions.

I'm just trying to better understand the change in the depreciation guidance. If you look at your Slide 7, it looks like you take the impact of a customer bill of $127 million, which I think is the interim rate relief, add the $81 million and the $16 million to get to a pretax impact on operating income of $224 million.

So it looks from the slide, as if the $81 million is incremental to the $127 million, but that's -- but you said the opposite, I think, in terms of how we should think about it.

Well, if you start at the top of the $274 million, that's the growth request. And then we took out the $81 million, so that gets us to $193 million.

So we've lowered the revenue, that's doing that, but the bottom depreciation expense were also. So we come to a net kind of cash more impact on the customer bill with a couple of those other items.

But then, we also lowered depreciation expense. So we're basically lowering revenue and we're lowering depreciation expense, which gets us to that new -- that net $224 million.

But -- okay. So for modeling purposes, because your drivers don't give the amount of rate relief, we should add -- or we can make an assumption of $127 million interim increase or whatever you think you're going to get in the case plus the $80 million, right?

Exactly.

Okay. And then second question I have is there looks like there is a liability that's set up for a customer refund against the Sharyland gain of $7.6 million.

Over what time period is that money refunded?

It's not determined. But it'll probably be likely in the next year or so.

It -- they have just been -- we just reached those agreements with the Texas and New Mexico.

Okay. And last question for me is, what's the approximate timing of your next Colorado electric rate filing?

We probably anticipate mid-year.

I was wondering if you could talk about the interest expense. Obviously, you did some issues in 2013 that were very favorable relative to what you redeemed, and you've got what you mentioned in terms of first half financing.

What are your thoughts on how interest rate -- interest expense develops here in 2014?

In terms of -- well, we had some replacements. And particularly, we no longer have any more 8% debt.

That was all basically retired in 2013. So we would expect with our new financings that we would be pretty comparable.

We wouldn't expect to see such a significant decline as we did between '12 and '13.

Okay. And that's because you've also got the incremental financing?

We do have the incremental. But net-net, it's still is beneficial.

Right, okay. And the second, on the weather impact, could you break that down in terms of the revenue benefit and then with the higher cost related to the weather was in 2013?

Well, the higher cost, that would be difficult. I can tell you in terms of the company that, that would help you how the weather benefit went.

Sure. Yes, you put the EPS obviously in there.

I just wondered how that breaks down.

Travis, this is Ben. The higher cost directly attributable would be the storms that we had that you could generally attribute to hotter, more volatile weather.

But as we've also done, we also always pick the opportunity when we have weather to put -- a favorable weather -- to put some more money back into maintenance and those sorts of things, so we have a strong system going forward. It's a little bit harder to quantify.

A couple of questions. One is, on loan growth, I see that you folks -- weather normalized, as I'm assuming 0.4% or so in '14.

However, fourth quarter was up 1.1%, and I know it's just a quarter, but are you seeing a pickup in load growth? Is that a sign of optimism there?

Can you just elaborate a bit on that?

Ali, I'll start it off and then Teresa can add. I mean, I -- we did see a pickup in the quarter.

But I think you have to -- we're always pretty cautious about a quarter, particular a quarter that's experienced some pretty volatile weather. Not only in total, but how it occurred within the month.

And so you have to be a little bit careful. However, it is a favorable trend.

I step back and compare the quarter to the overall year, and I think what we're seeing -- we'll continue to see SPS and PSCo do better than the North, and that we don't anticipate that trend will change into '14. You break it out a little bit further.

Residential, generally, usage-wise, it would be flat -- PSCo's flat with usage. Every other jurisdiction's declining in usage.

However, we're seeing customer additions again, consistent with where we were prerecession, so that's a good sign. But you put it all together and it still results in fairly flat residential revenues.

And then on the C&I side, again, much more activity in the South and the West, and not so much in the North.

I think you covered that well, Ben. And I would agree, one quarter is probably not a trend.

Okay. And then on the weather, I know we're early in the year.

But any sense of how much cushion, if you will, this very cold January has given you guys as you're looking into '14 right now?

Well, Ali, I would say that Minnesota's been really cold. But Colorado's had some really warm days, too.

So anybody watch the Bronco game.

So we've been following the New York forecasts, too. I would agree with Teresa, it's been incredibly cold in Minnesota but pretty generally tempered in Colorado.

And so you get the benefit, as we've always talked about, with a big portfolio of diversity. And weather is part of that diversity and sort of was a bit canceling each other out, to Teresa's point.

Right. Maybe it was slightly up, but it's not as much as everyone in Minnesota would think.

Our misery indicated here would...

Right, right. We've been hearing about the Minnesota weather.

But last year you had $0.11 of benefit versus normal. Just thinking, again, given what you're seeing so far, are you comfortable that you can match that so that weather doesn't become a headwind for you this year?

I mean, in terms of matching it, I mean, it's so early. Things can change in the weather, and I just wouldn't -- I think it's too early.

If you notice -- I mean, our guidance, as you know, assumes normal weather, and that's what you have to count on. A little bit of positive in the first month.

But the summer, it weighs on as much heavily than the winter, generally. So we just have to see how that plays out.

We can't count on $0.11, that's for sure.

Right, right, right. And last question, Ben and Teresa.

Remind us again, as you're looking at this Transco potential on the SPP region, et cetera, was that baked into your long-term earnings, growth guidance, the 4% to 6%? Does it move the middle further?

Is it already in that? Can you just remind us how that fits into your outlook?

I mean, Ali -- I mean, it will allow us to continue to potentially invest in transmission. And that it's depending on how the rules actually play out in a FERC 1000 world, but this is -- the book of business that we talked about at analyst day is really based upon what we have today.

So we're just putting these things in place. So several years down the road, we can continue to be as successful in building transmission as we already are.

And it's, as I said and Teresa has said, it's another arrow on our quiver, and we need to have options because the future is always uncertain.

Well, it doesn't cause you to go above 6% or so. It still keeps you in that 4% to 6% range as you look at it today?

I mean -- I think, today, that would be the case rate.

As I look at the capital expenditure forecast you've laid out that underlies the 4% to 6% average earnings for that expiration, I observed that it is somewhat front-end loaded. A lot of that capital spend happens in the first couple of years and then there is sort of a dramatic drop towards the back end.

If you were to fully execute on all of those, all that spending in the first 2 years, even with the financing costs, the equity, as long as you're successful in your regulatory strategy, why wouldn't it be possible for you to earn towards the high end of the guidance range over the next few years?

Why wouldn't it be possible, is that what you just asked?

Yes. I mean, because you've got more capital, more rate base growth on the front end of the plan than the back end.

Well, I would just say in terms of exceeding it, we do have assumptions around rate cases. There still continues to be some regulatory lag in some of our jurisdictions, but we expect to see it be in our 4% to 6% growth range.

And then what makes you comfortable that the regulatory strategy you've implemented in Minnesota is going to drive a better outcome than the last case? I mean, so far, what could you point to in terms of your dialogue with your -- with the important counterparties in that case that gives you comfort you'll be able to get most of what you're asking for this time around?

Well, there's a lot of subjective and qualitative. But I think I'd point to the fact that interim rates were approved and without a lot of controversy.

I think we're hearing qualitatively, that the quality of the data submission was very strong. The outreach efforts, the rate mitigation plan, I think, has been understood and, I would say, generally accepted by our stakeholders.

They understand what we're doing. And remember, Greg, we -- while this, we're not asking for a 5-year plan.

We've been talking to stakeholders what a 5-year plan looks like. And they understand that it's -- the pace of our rate increases that we've asked for, as we did things like extend the life of our nuclear plants for 20 years, it's going to start to level off.

And so they understand that this isn't going to be a trend forever.

I would just add to that. I mean, the way we think about 2013, there were 3 significant things in that case that were in isolation, which we believe have been resolved.

I mean, starting with the Monticello plant and the upgrade, the upgrade is complete. The plant has been operating since then.

The Sherco plant, we had a catastrophic failure, that refurbishment is also complete. And then we had the sales forecast request in terms of the -- actually, decline, I should say.

And we feel that we have much better forecasting that we'll do better on in this case. So I think that those 3 things are behind us, and so we feel better about this case going forward.

I'll just add, Greg. As we talked on investors’ day, we're offering great predictability moderation, we have addressed the issues upfront and investments actually reflect a carbon-free generation, which has been a preference of our customer.

So that's why I think this case is different.

Just with respect to Sharyland, I noticed this is an ongoing earnings, is there any other opportunity that you guys are seeing with that in terms of monetizing any other potential transmission assets?

In terms of divestiture?

Yes.

No, not really. That was a very unique circumstance in terms of Sharyland and Caprock, who used to be a wholesale customer.

And we just -- the transmission line, we didn't need it any longer. So...

Okay. I was wondering if you could tell me, with respect to the FERC Order 1000 and the right of first refusal, if you see any potential impact associated with competition, with respect to, perhaps, CapEx, or return or anything.

I mean, how do you see that shaking out? Do you see opportunities outside?

And do you see potentially competitive threats within your jurisdiction? Do you follow me?

Yes. I mean, we have right of first refusals, for example, in Minnesota.

But to your point, I think it's pretty clear FERC doesn't particularly care for those rights of first refusal. So we're not sure how that's going to play out.

Right now, we don't see any immediate threat. But when you get out in the latter part of the decade, potentially, you could see the threat.

And that's why, Paul, we want the Transco, because it allows us to compete on an even-keeled basis. It doesn't mean that, that threat will ever emerge.

You can make a similar argument down in SPP in Texas and New Mexico. You also asked about ROE's.

I mean, I think everybody knows that there are a number of pending cases in front of FERC to lower ROEs. That remains to be seen.

Our FERC recoveries right now are not dependent upon -- or rather, our transmission recoveries now aren't really dependent upon FERC ROEs, but we'll have follow that. My personal opinion, I think you'll see some gap closure between a FERC ROE and what a typical state ROE is.

But hopefully, not too much, because I think there's -- ROEs, hopefully, will improve at the state level. So hopefully, maybe FERC goes down a little bit and the state goes up.

But we're prepared. And that's what the Transco does for us.

We're prepared for different scenarios.

Okay. I guess I was sort of really actually thinking about what you said to the return, and cost to capital was really actually on the competitive side.

I mean, in other words, if FERC opens this all up to competition, do you see, I don't know, private equity investors or something like that coming in and perhaps using a variety of means to potentially come up with different return outlook? And I was wondering if that's something you have.

I mean, I know it's early and what-have-you, but I was just wondering if you're hearing anything about that or...

I don't. I'm not really hearing probably any more than anybody else, but I think you raised a good point.

And -- I mean, infrastructure funds would love to invest in transmission. But a couple of things about that.

If you look at the rules to the extent they're out now and how competitive bidding would look, your track record, your performance, your operational standing, those are going to be very, very important criteria on who wins those bids. So maybe what you're suggesting, Paul, is that in a Transco or a partnering-type arrangement, could you have more passive partners along with a more active partner?

Yes. I mean, that could happen.

And again, that's a scenario that I think we're preparing for.

Okay, great. And then just, finally, sort of a housekeeping thing.

I noticed that it looked on Page 7, that residential sales were helped by weather considerably, yet there's sort of a slight hurt to weather for industrial and commercial. Is that because of where those customers are, and there were different weather impacts for different customer classes simply on location?

Or is there something else going on sort of a small item? I was just wondering if it was a little unusual.

I don't think there's anything specific going on in across the jurisdictions. I will say, the weather normalization is more art than science.

And when we do have extremes, and it's been said, particularly in a month, it would be really cold in the front part and warmer, that they're not perfect.

And keep in mind that our larger industrials aren't -- or generally, their weather doesn't do much for them.

It's actually Julien here. So a quick question actually following up on the last year on the Transco front.

Just really quickly, how has your thinking evolved about, A, the usage of partners as you just alluded to? And then, B, how would you structure this as it relates to FERC versus state level of returns and utility structures, if you will?

Julien, I guess I just have to repeat that we're not proposing any kind of structure at this point. We just want to have the Transco option in our back pocket so that we can react to how the market may evolve.

And I -- we'll see how it evolves. In the meantime, we're going to focus on state recovered-type transmission, make sure that we improve the returns.

You're going to see us continue to try to advance the regulatory construct in that regard, as with when we filed in Texas. And it really relates to revenue crediting and some -- I don't know if they're technical, but some real rate-type issues.

And if we get that, a lot of our transmission spend in Texas and New Mexico will be recovered essentially outside of state retail mechanisms. So we don't -- we're really not thinking at this point that we're going to do a Transco into bringing passive partners, et cetera.

But, I mean, Paul had asked earlier, is that a possibility? And sure, I see the market evolving that way.

And we just want to be ready for it if it goes that way. And again, meantime, we've got great defined developing projects that are real, that we're going to get good recovery on in all of our jurisdictions, primarily at the state level right now.

Got you. Excellent.

And then looking at Colorado, I'd just be curious, as you think about your normalized sales growth numbers, obviously, there's been some commotion around a seller in that meeting. How does that impact your thinking on growth in the state?

I mean, is it, at this point, immaterial to think about that? Or does it have any kind of...

It's not immaterial. I mean, Teresa, you and I were just talking about this a couple of days ago.

What do we estimate? Like there's that 0.2 percentage point that it shaves off our growth opportunity?

Right. Yes, it's not substantial.

But if you -- for longer term, it will grow. But it's still not substantial.

I mean -- and that 0.2, that's for next year, you're saying, in Colorado?

Yes, that's roughly. It's taking what we've seen and what we anticipate and what that would do.

But it's already baked into the forecast. So that's -- so you should be aware of that.

The issue with net metering is getting the rules right, so that the policy is sustainable for the long run. Today, it's not all that noticeable.

But if the aspirations of the rooftop solar industry are met, it would be extremely noticeable to customers that don't have a rooftop. And so that's what the whole industry is rallying around and understanding that we have to get the right rules in place so that the technology can compete on an equal basis and not disadvantage one customer for the benefit of another.

And should we read on the utility scale side? Or anything into this way, just RFP around the Black Dog and putting forward a solar project in Minnesota?

I mean, is that something that, frankly, at this point, you're going to -- you would pursue a separate RFP on the renewable side if they can do it? Or how are you thinking about that right now?

Well, we've got a statue that we have to meet, and we take that seriously. And it's 1.5% by 2020, most of which would -- or at least 10% carved out for rooftop, the rest based upon our recommendations, essentially.

So we understand that there's going to be solar in Minnesota, and we support that. But we think there's better ways to acquire it.

And that's what our contention is. We think that we can do better for our customers if we did a separate RFP.

Right. Yes, we still believe that the Black Dog is the right, based on the current updated, 300-megawatt load is the right approach.

And we just filed for reconsideration to that ALJ recommendation. So...

Yes, and I think others -- the department, for example, thunders. It agrees with us.

I mean, that there's a number of technical things that went behind the ALJ's decision. What they were looking at were actual load needs versus where we are today, what they were, how they were valuing solar as far as some societal benefits, et cetera.

A number of things. Bottom line is, we haven't removed Black Dog from our CapEx.

I mean, it's $100 million, it's fairly small. But it's because we think that this thing will get sorted out.

Got you. And then quickly on the wind side.

I believe, last time you guys discussed the MISO interconnection study that was still pending for one of your new self-builds. Where does that stand?

We're still waiting for the results, but we're confident. We're, I should say, optimistic that it will come in where we expect it to come in.

I think it does come in mid-year...

Yes. Well, first quarter-ish, yes.

Yes. From what we're hearing, we're more optimistic today than we were yesterday, put it that way.

Actually, I'm all set, but thank you very much.

Well, with that, thank you for all participating in our year-end earnings call this morning. Please contact us, Paul Johnson and the IR team, with any follow-up questions.

Thank you.

Thank you, everyone.