埃克西爾能源 (XEL) 2013 Q4 法說會逐字稿

Good day, ladies and gentlemen, thank you for standing by. Welcome to the fourth-quarter 2014 (sic - see press release, "2013") earnings conference call. During today's presentation all parties will be in listen-only mode. Following the presentation, the conference will be open for questions.

(Operator Instructions)

I would now like to turn the conference over to Paul Johnson, Vice President of Investor Relations. Please go ahead.

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 that accompany today's conference call are available on our webpage. 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 and 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 costs, fuel and cost allocations at SPS. These issues related 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 pre-tax 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 plans that were previously expensed. Both items are excluded from ongoing earnings. Management believes ongoing earnings provides the 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 turn the call over to Ben Fowke.

Thank you, Paul, and good morning. I am 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 we have met or exceeded our earnings guidance and 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 are especially proud of the commitment to customers that our employees demonstrated again and again. A series of severe weather events, including blizzards, ice 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-fired unit is back in service after sustaining major damage in 2011. We brought Jones 4 on-line in Texas, and in time for a 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 Pawnee, 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 are 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 are 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 appreciate that designation, but were particularly satisfied that we have 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 are 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 front, 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 are 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 en-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. As part of our effort to strengthen the grid, we plan to invest $4.5 billion on transmission projects over the next five years.

We have proven that we can design, site, 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 might 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 deliver constructive outcomes in our regulatory proceedings and to improve the overall regulatory construct. In 2014, we hope to put in place multi-year 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 will 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 and interim rates being 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 OP-CO was: NSP-Wisconsin 0.8%, PSCo 1%, SPS 1.7%, and NSP-Minnesota declined 0.8%.

The economies in our service territories continued to improve. Overall, compared to the national average, we had higher job growth and lower unemployment in our service territories. Finally, at SPS, we sold to 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 customers.

Next I will provide some detail on the financial results of each of our operating Companies. 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 rates 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 proposed multi-year 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-rates 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 riders put in place and the use of a forward test year in New Mexico. Texas and New Mexico offer substantial organic growth opportunities due to the continued expansion of the oil and gas industry located within our service territory.

As a result, we have 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 have made great progress at SPS, and we are 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 will 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 two-year electric rate case in Minnesota. In December, the Minnesota Commission unanimously approved our requested file and granted $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, multi-year settlement agreement with the Staff, which includes a four-year rate plan, with 5% annual increases in retail revenues for the first three years, and no rate increase in the final year. The settlement also includes a gradually increasing ROE during this multi-year period. Hearing 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 decision. On January 23, the hearing examiner provided a recommended decision, which included an ROE of 9.73% and our 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 rider. A commission 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 at $32.6 million, effective on March 1. Intervenor testimony is due in May and hearings are planned for June. We anticipate a file decision in the implementation of final rates in the third quarter.

Turning to our financing plan, today's press release summarizes our five-year financing plans related to our $14 billion capital expenditure forecast. We plan to issue the following first mortgage bonds during the first half of the year: approximately $300 million at 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 five 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 issuances 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 are proud of our track record of generating the financial results that our investors expect. Operationally, we continued to provide our customers with a high level of service, even when faced with several severe weather events.

We continued 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 are 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 when we reflected the total then-expected increase and 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 will now take questions.

Thank you. We will now begin the question-and-answer session.

(Operator Instructions)

Our first question comes from the line of Paul Fremont with Jefferies. Please go ahead.

I am 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 the 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.

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

If you start at the top, at 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 have lowered the revenue. That's doing that, but the bottom depreciation expense, we are also -- so we come to a net cash impact on the customer bill, with a couple of those other items.

Then we also lower depreciation expense, so we are basically lowering the revenue and we're lowering depreciation expense, which gets us to that net $224 million.

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, correct.

Okay, second question I have is there looks like there is a liability that is set up for a customer refund against the Sharyland gain of $7.6 million. Over what time period is that money refunded?

It is not determined, but it will probably be likely in the next year or so. We reached those agreements with Texas and New Mexico.

Okay, and last question for me is what is the approximate timing of your next Colorado electric rate filing?

We would probably anticipate mid-year.

Thank you.

Our next question comes from the line of Travis Miller. Please go ahead.

Good morning, thank you. 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 have 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?

Well, we had some replacements; and particularly, we have 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 significant decline as we did between 2012 and 2013.

Okay, and that's because you've also got the incremental financing?

We do have the incremental; but net-net, it still was beneficial.

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

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

Sure, yes. You put the UPS, obviously, in there. I was just wondering how that breaks down.

Travis, this is Ben.

The higher cost that's directly attributable would be the storms that we had that you could generally attribute to hotter, more volatile weather.

But as we have always done, we also always take the opportunity when we have 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.

Okay. Great, thank you. a lot.

Thank you, and our next question comes from the line of Ali Agha with SunTrust. Please go ahead.

Good morning.

Hello, Ali.

How are you? A couple of questions.

One is on [load] growth, I see that you folks weather normalized still assuming 0.4% or so in 2014. 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 elaborate a bit on that?

Ali, I will start it off, and then Teresa can add. We did see a pickup in the quarter, but I think you have to -- we are always pretty cautious about a quarter, particularly a quarter that has experienced some pretty volatile weather, not only in total, but how it occurred within the month.

And so you'd 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 are seeing, would continue to see SPS, NPS do better than the north. And we don't anticipate that trend will change into 2014.

You break it out a little bit further, residential, generally usage-wise what they -- PSCo is flat with usage; every other jurisdiction is declining in usage. However, we are seeing customer additions again, consistent with where we were pre-recession, so that's a good sign.

You put it all together, and it still results in fairly flat residential revenues. And then on the [CNI] 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 are early in the year, but any sense of how much cushion, if you will, this really cold January has given you guys as you're looking into 2014 right now?

Ali, I would say in Minnesota it has been cold, but Colorado has had some really warm days too -- so if anybody watched the Bronco game.

By the way, go Broncos.

We have been following the New York forecast too. I would agree with Teresa; it has been incredibly cold in Minnesota, but generally temperate 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. So, a bit canceling each other out situation.

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

As our misery indicator here would indicate.

I've heard about the Minnesota weather. Last year you had $0.11 of benefit versus normal.

I'm 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?

In terms of matching it, it's so early, things can change in the weather and --

Our guidance, as you know, assumes normal weather; and that is what you have to count on, a little bit of positive in the first month. ¶

But the summer weighs on us much heavily than the winter generally, so we just have to see how that plays out. You can't count on $0.11, that's for sure.

Right and last question, Ben or Teresa, remind us again, as you are looking at this transco potential in the SPP region, et cetera, was that baked into your long-term earnings, growth guidance, the 4% to 6%?

Does it move the needle further? Is it already in there? Can you remind us how that fits into your outlook?

Ali, it will allow us to continue to potentially invest in transmission. And depending on how the rules actually play out in a FERC 1000 world.

But the book of business that we talked about at Analyst Day is really based upon what we have today. So we are just putting these things in place, so several years down the road, we can to continue to be as successful in building transmission as we already are.

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

But 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 think today that would be the case, right.

Yes.

Thank you.

Our next question comes from the line of Greg Gordon with ISI Group. Please go ahead.

Hello, guys, how are you?

Hello, Greg.

Hello, Greg.

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

If you were to fully execute on all of those, all that spending in the first two years, even with the financing costs, the equity, as long as you are 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 asked?

Yes, because you have got more capital, more rate-based growth on the front end of the plan than the back end.

Well, I would 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 be in our 4% to 6% growth range.

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

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 that we are hearing though, 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 are doing.

And remember, Greg, we are not asking for a five-year plan.

We have been talking to stakeholders what a five-year plan looks like. And they understand that it is the pace of rate increases that we've asked for as we did things like extend the life of our nuclear plants for 20 years, is going to start to level off. And so they understand that this isn't going to be a trend forever.

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

Starting with the Monticello Plant and the uprate. The uprate is complete. The plant has been operating since that.

The Sherco Plant, we had the catastrophic failure; that refurbishment is also been complete.

And then we had the sales forecast request in terms of, actually, decline I should say. And we feel that we have much better forecasting that we will do better on in this case.

So I think that those three things are behind us, and so we feel better about this case going forward.

I will add, Greg, as we talked on Investors Day, we are offering great predictability, moderation. We have addressed the issues up front, and the investments largely reflect our carbon-free generation, which has been a preference of our customer.

So that's whyI think this case is different.

Thank you, guys. Take care.

Thank you Greg.

Our next question comes from the line of Paul Patterson with Glenrock Associates. Please go ahead.

Good morning.

Hello, Paul.

With respect to Sharyland, I know 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 Cap Rock, who used to be a wholesale customer. And 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?

How do you see that shaking out? Do you see opportunities outside in DC, potentially competitive threats within your jurisdiction? Do you follow me?

Yes, we have right of first refusals, for example, in Minnesota. But to your point, I think it is pretty clear FERC doesn't particularly care for those right of first refusals; so we are not sure how that is 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 ROEs. 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 will have to follow that. ¶ My personal opinion, I think you will see some gap closure between a FERC ROE and what a typical state ROE is, but hopefully not too much because I think ROEs hopefully will improve at the state level. ¶ So hopefully, maybe FERC goes down a little bit and state goes up; but we're prepared. And that's what the transco does for us; we're prepared for different scenarios.

What I was really actually thinking about, with respect to the return and cost of capital, was really actually on the competitive side. In other words, if FERC opens this all up to competition, do you see private equity investors or something like that coming in and perhaps using a variety of means to potentially come up with different return outlooks?

And I was wondering if that is something -- I know it's early and what have you, but I was wondering if you are hearing anything about that?

I am not really hearing probably any more than anybody else, but I think you raise a good point. 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 are 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, that could happen, and again, that's a scenario that I think we are preparing for.

Okay, great. Finally a housekeeping thing: I noticed that it looked on page 7 that residential sales were helped by weather considerably; yet there is 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?

It's a small item, but I was wondering; it was a little unusual.

I don't think there's anything specific going on; it's 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 will be really cold in a front part and warmer, that they are not perfect.

Keep in mind that our larger industrials are -- generally, their weather doesn't do much for them.

Right, sure. Thank you so much.

You're welcome.

(Operator Instructions)

Michael Weinstein with UBS. Please go ahead.

It's actually Julien here.

Hello, Julien.

So a quick question actually following up on the last year on the Transco front. Really quickly, how has your thinking evolved about: A, the usage of partners, as you alluded to? And then, B, how would you structure this as it relates to FERC versus state level of returns and utility structures?

Julien, I guess I just have to repeat that we are 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 we will see how it evolves.

In the meantime, we are going to focus on state recovery-type transmission, make sure that we improve the returns. You are 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 are really not thinking at this point that we are going to do a transco and bring in passive partners, etc. Paul had asked earlier, is that a possibility?

And sure, I see the market evolving that way. We just want to be ready for it if it goes that way. And again, meantime, we have got great defined, developing projects that are real that we are 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 would be curious as you think about your normalized sales-growth numbers, obviously, there's been some commotion around solar and metering?

How does that impact your thinking on growth in the state? Is it, at this point, immaterial to think about that; or does it have any?

It's not immaterial.

Teresa, you and I were talking about this a couple days ago. What did we estimate? It's about two-tenths of 1 percentage point that it shaves off our growth opportunities?

Right, it's not substantial, but if you -- so longer-term, it will grow. But it is still not substantial.

And that two-tenths, that's for next year, you are saying, in Colorado?

That is roughly. It's taking what we have seen and what we anticipate and what that would do.

But it's already baked into the forecast. 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 is 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 rooftop.

And so that is 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.

Should we read, on the utility scale side, anything into this latest RFP around the Black Dog and putting forward a solar project in Minnesota?

Is that something that frankly, at this point, you would pursue a separate RFP on the renewable side if it came to it? Or how are you thinking about that right now?

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.

We understand that there is going to be solar in Minnesota, and we support that.

But we think there are better ways to acquire it, and that is 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 just filed for reconsideration to that ALJ recommendation.

Other -- the Department, for example, agrees with us. There are a number of technical things that went the ALJ's decision.

What they were looking at for 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. It's $100 million; it is 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 a MISO interconnection study that was still pending for one of your new self builds; where does that stand?

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

I think it's supposed to come in mid-year.

First quarter-ish.

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

Great, thank you.

Thank you.

Thank you. Our next question comes from the line of Andy Levy with Avon Capital Advisors. Please go ahead.

Andy, hello.

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

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

Thank you, everyone.

Thank you ladies and gentlemen. That does conclude the fourth-quarter 2013 earnings conference call. You may now disconnect.