Xcel Energy Inc. (XEL) Q2 2013 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the second quarter 2013 earnings conference call. [Operator Instructions] This conference is being recorded today, August 1, 2013. I would now like to turn the conference over to our host, Mr. Paul Johnson, Vice President of Investor Relations and Business Development. Please go ahead, sir.

Thank you. Good morning, and welcome to Xcel Energy's 2013 Second Quarter Earnings Conference Call. Joining me today are Ben Fowke, Chairman, President and Chief Executive Officer; Teresa Madden, Senior Vice President and Chief Financial Officer; 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 second quarter results, update you on recent business and regulatory developments, reiterate our 2013 guidance. Slides that accompany today's call are available on our webpage. We will also post a brief video of Teresa Madden summarizing our financial results on the webpage. As always, some of our comments during this morning's conference call may contain forward-looking information. Significant factors that cause results to differ than those anticipated are described in our earnings release and our filings with the SEC. I'll now turn the call over to Ben.

Well, thanks, Paul. Today, we reported second quarter earnings of $0.40 per share compared with $0.38 per share in 2012. New and interim rates in several jurisdictions, combined with positive weather, contributed to our solid quarterly earnings. We also remain positioned to deliver earnings within our guidance range of $1.85 to $1.95 per share. In a few moments, Teresa will discuss our financial results and regulatory developments in greater detail. I'll now comment on a few recent events, starting with some operational items. I believe the foundation of a strong utility is how it responds to adversity, particularly large-scale storms. In June, we had an opportunity to demonstrate our capabilities when Minnesota experienced several severe thunderstorms and high winds that impacted over 600,000 of our customers. Advanced preparation for these types of events enable us to successfully coordinate a workforce of 1,100 linemen and hundreds of support personnel, including crews from several other utilities. As a result, 96% of our customers were restored within 3 days, and everyone was back online by the sixth day. I'm proud that our dedicated employees, contractors and utility peers completed this enormous effort in an orderly, safe and timely fashion. In addition, I want to thank all the other utilities who provided employees to assist us with storm restoration. The Mutual Assistance Program is an outstanding way for utilities to leverage our workforces, to respond to significant storms in a cost-effective and efficient manner. I'd now like to discuss the completion of a long-term project to upgrade and extend the life of our Monticello nuclear plant. In July, we brought our Monticello nuclear plant back online after completing a scheduled refueling outage, which included work to allow the plant to operate safely through 2030 and increase its output by 71 megawatts. Scope of this project changed several times as we worked to meet evolving NRC standards for safety, increased the reliability margin and address emergent issues that were discovered during the construction. Our cost for the project are approximately $655 million, which is above the estimate provided in our 2008 Certificate of Need filings. We have committed to an after-the-fact prudence review. We expect that the overall cost and benefits of the project will be reviewed in the context of our 2014 rate case. We believe that even with the cost increases, this project will deliver great value for our NSP customers, providing 600 megawatts of reliable, cost-efficient and emission-free generation for the next 2 decades. We also are pursuing plans to substantially increase our emission-free wind resources. We're always looking for options that work for both customers and investors. Consistent with this approach, we're seeking to add as much as 2,000 megawatts of wind resources across our service territory at very attractive pricing. These projects allow us to take advantage of the expiring production tax credits, meet state renewable standards and provide significant fuel savings to our customers. To this end, we submitted a proposal to regulators to add 600 megawatts of wind resources in Minnesota and North Dakota. Our proposal includes adding 3 200-megawatt projects, including 1 ownership project. At SPS, we're seeking to add 700 megawatts of wind power through PPAs. In Colorado, we're proposing adding 200 megawatts of new wind through our PPA. In addition to these 1,500 megawatts of proposed wind projects, the Colorado PUC will decide this fall on whether or not to approve 350 megawatts of new wind PPAs. We're also evaluating our 150-megawatt project in North Dakota that we would own. This project may be brought to the North Dakota and Minnesota Commissions relatively soon. Adding wind resources today creates long-term value and could save our customers an estimated $800 million to $1 billion in fuel costs over the next 20 years. We anticipate commission decisions on each of these proposals later this year. We also have RFPs outstanding to add thermal resources at both NSP-Minnesota and PSCo. We submitted bids in Minnesota and Colorado, and expect commission decisions this fall. We hope to update you on these proposed projects during our third quarter earnings call. Next, I'd like to comment on regulatory developments in Minnesota. Teresa will cover our pending 2013 rate case, but with large investments and our steam generator replacement at Prairie Island and the 2014 impact of the Monticello project, as well as other cost increases, we will need to file a sizable rate case later this year for 2014. We plan to pursue a multi-year regulatory plan in Minnesota. Recently, the Minnesota Commission issued an order for multi-year ratemaking, which could serve as a template for constructive regulation, providing revenue and regulatory certainty for both our customers and our shareholders. The framework includes the following guidelines: A multi-year rate plan must cover up to 3 years, with the first year representing a fully filed rate case; companies may recover specific capital costs and appropriate O&M costs in the second and third years; the ROE authorizing the rate case will be used for the entire multi-year period; and finally, companies will need to file for fixed rates over the period, with certain costs subject to refund. And the parties have filed for clarification on certain items in the multi-year order, and we expect the commission to issue a final order later this year. We believe a multi-year plan may allow us to obtain timely cost recovery of our capital expenditures while eliminating the need for multiple rate cases given the substantial investments we continue to make in Minnesota. So with that, I'll turn the call over to Teresa.

Thanks, Ben, and good morning. Today, I will discuss second quarter results, provide you with an update on recent regulatory development, review our financing plans and update you on our 2013 earnings guidance. I'll begin by reviewing the second quarter results at each of our 4 operating companies. Earnings in NSP-Minnesota increased $0.03 per share, largely due to interim electric rates subject to refund in Minnesota and North Dakota, and a rate increase in South Dakota. In addition, higher natural gas margins due to cooler weather and lower interest expense also helped to improve profitability. Second quarter earnings at PSCo were flat. Higher electric and natural gas margins and lower interest charges were offset by higher O&M and depreciation expense. Earnings at NSP-Wisconsin increased $0.01 per share, reflecting higher electric and gas rates effective in January 2013, as well as the effect of higher natural gas margins due to the cooler weather. SPS earnings decreased $0.01 per share, as higher O&M expenses, depreciation and interest charges were partially offset by a rate increase in Texas that was effective in May 2013. I'll now discuss some of the key drivers of our consolidated earnings results, beginning with retail electric margin. Second quarter electric margin increased $26 million. Primary drivers of the higher margin were $56 million from new rate increases and interim rates subject to refunds in certain states. This amount includes the reserve for revenues subject to refund of approximately $31 million at NSP-Minnesota and $10 million from increased transmission revenue net of expenses. These positive drivers were partially offset by several smaller items, including a $9 million refund at PSCo as a result of estimated earnings test obligation, a $9 million reduction in conservation and DSM incentives and $8 million decrease in firm wholesale revenue and various other items. Second quarter weather normalized retail electric sales decreased 0.2%. As been noted, we experienced a series of storms in Minnesota in June that impacted over 600,000 customers. We estimated that the impact of these storms reduced our quarterly electric sales by about 22,000 megawatts or 0.1%. Second quarter natural gas margins increased $21 million, primarily as a result of a $12 million impact from cooler weather and a $7 million increase from higher retail sales growth. Based on year-to-date trends, we now forecast weather-adjusted firm natural gas sales to increase 2% in 2013. Previously, we forecasted a 1% decline. Turning to expenses. O&M increased 5.3%. The primary drivers of the increase were $12 million of other electric and gas distribution expenses, largely due to increased maintenance activities; $9 million related to higher nuclear plant costs associated with operational initiatives and other smaller items. Through the first 6 months of 2013, O&M expenses increased 4.5%, which is consistent with our original guidance. We continue to forecast an annual increase of 4% to 5%, but we will closely monitor our O&M levels to determine if we have to take actions to change spending levels, which will be dependent on circumstances in the second half of the year. Depreciation and amortization increased $17.3 million or 7.6% due to our ongoing investment in our systems. We continue to forecast D&A to increase approximately $75 million to $85 million. Other taxes increased $2.4 million or 2.4%, largely due to increased property taxes in Minnesota, Colorado and Texas. As a result of updated forecast, we now expect our consolidated property taxes will increase between $20 million to $25 million, which is lower than we previously projected. I'll now provide an update on regulatory developments, beginning with our pending rate case in Minnesota. We will be in front of the Minnesota Commission next week, so we will keep our comments limited. In early July, the Minnesota ALJ issued a report and recommended a rate increase of approximately $127 million based in an ROE of 9.83%, an equity ratio of 52.56% and an electric rate base of $6.2 billion. The recommendation also included an estimated $51 million of deferrals related to Sherco 3, the Monticello upgrade and pension cost. We estimate these recommended deferrals would have a $34 million impact on our 2013 earnings. From a pretax earnings perspective, the recommendation is nearly $100 million lower than our most recent revenue requirement request of $259 million, including $50 million of proposed deferral mechanisms. We recently filed exceptions and clarifications to the ALJ report, which supported many of our initial positions. Specifically, we sought different outcomes on several items that affect the revenue requirement, including the sales forecast and ROE. Deliberations are scheduled for August 6 and 8. The MPUC is expected to vote on many of the key issues at their meeting on August 8 and issue an order in September 2013. In North Dakota, we are seeking a $16 million rate increase based on a 2013 forecast test year of 10.6% ROE, electric rate base of about $378 million and a 52.56% equity ratio. On July 17, the staff filed direct testimony recommending a rate decrease of $2 million, based largely on a change in cost allocations and ROE. While this is a disappointing recommendation, we are cautiously optimistic that we will ultimately reach a constructive outcome in North Dakota. In Wisconsin, we recently filed for an electric rate increase of $40 million and a natural gas rate increase of $4.7 million. The requests are based on an ROE of 10.4%, a 52.5% equity ratio and a 2014 forecasted electric rate base of $895 million and a natural gas rate base of $90 million. Staff and intervenor testimony is scheduled for October 4. We anticipate a final decision before year end, with the new rates effective in January 2014. At PSCo, we are seeking a $65 million multi-year gas rate increase covering 2013 to 2015, based on a 10.3% ROE, an equity ratio of 56% and a rate base of $1.3 billion. Rates, subject to refund, will go into effect on August 10. An ALJ recommendation is expected later this month, and a CPUC decision is expected in the third quarter. Finally, at SPS, in New Mexico, we are seeking a $43.3 million rate request based on a 2014 forecast test year and a 10.65% ROE, rate base of $480 million and an equity ratio of 53.9%. We anticipate a commission decision by year end, with the new rates going into effect during the first quarter of 2014. I'll now update you on the progress of our 2013 financing plans. During the second quarter, we continue to leverage our strong credit ratings and the low interest rate environment issuing $850 million of debt at favorable rates. At NSP-Minnesota, we issued $400 million of 10-year first mortgage bonds, with a coupon of 2.6%. At the holding company, we issued a $450 million 3-year note at just 75 basis points. The latter financing, combined with the equity proceeds from our first quarter ATM issuance, enabled us to call the $400 million 7 6/10% holding company junior subordinated note. Based on the successful execution of our financing plans, we now project a $40 million to $45 million decrease in interest expense during 2013. Looking ahead, we plan to issue $100 million of first mortgage bonds at SPS during the third quarter. Upon completion, the issuance of this SPS bond should wrap up our 2013 financing program. However, financing plans are subject to change depending on capital expenditures, internal cash generation, market condition and other factors. In closing, we delivered another successful quarter, both financially and operationally. We continue to expect to deliver earnings within our guidance range of $1.85 to $1.95 per share. This is based on strong year-to-date performance, lower interest expense and property taxes, a lower effective tax rate, constructive outcomes in all regulatory proceedings and a final decision in the Minnesota's 2013 electric rate case that is consistent with the ALJ recommendation. At our Analyst Meeting in December 2011, we discussed the potential for our EPS growth rate to moderate post-2013. This was based on lower rate base growth, sluggish sales and the potential for compression in authorized ROE. While we remain on track to deliver 2013 earnings consistent within our guidance range, we believe these factors, particularly the lower ROE recommendations we have received in several of our pending rate cases, will make it more challenging to achieve EPS at the upper end of our targeted 5% to 7% range beyond this year. We are positioned to continue delivering an attractive total return, should earnings growth taper as a result of these factors. With a payout ratio below 60%, we have the flexibility to grow our dividends at a faster rate than we have in the past. We plan to provide more clarity on our long-term EPS and dividend growth objectives later this year. This concludes my prepared remarks. Operator, would you please provide instructions for the Q&A session?

[Operator Instructions] And our first question comes from the line of Greg Gordon with ISI Group.

So I guess I'm not going to -- I won't ask you to articulate your rationale on, sort of, tweaking of the total return expectation because you plan on giving us more meat on that later this year; is that fair?

Greg, if I could, first of all, let me just apologize to everybody on the call. We have significant construction going on outside, and I think that might have interfered with some of the broadcast. I don't know if you could hear it, Greg.

It's way in the background. I think you're okay.

Okay. I think we're just reiterating what we've been saying all along, Greg, that after this year, it's likely that our growth rate will modulate a bit as our capital expenditures start to levelize off. And you look at where ROE's are going in the trend and it certainly says that we're probably correct in that, but more to come.

Okay. You obviously have the ability to accelerate growth in the dividend payout ratio, given that it is way below industry average.

Absolutely. And as you and I have talked many times before, Greg, as we went through this construction mode, we wanted to be more conservative with our dividend for a number of reasons. And I think that gives us dry powder in a different -- maybe a unique way that we reward shareholders going forward.

Okay. And let me ask you a question with regard to the announcements you've made in the last few days over -- around procuring the 2,000 megawatts wind resources. If you should be successful in procuring the wind at the mix that you are proposing, which is the majority of it being PPAs, some being owned by your utility subs, is that also going to then require you to have to reassess and increase the amount of transmission spend in order to bring all that power to market? And so would that be an ancillary impact of getting that 2,000 megawatts into the portfolio?

No, it really wouldn't. I mean, we're going to make use of transmission lines and capabilities that are already in place. I think the one issue that we have with the additional 150-megawatt project in North Dakota is making sure that the transmission will be available there at a reasonable cost. And -- but it won't drive any additional major capital expenditures on transmission, Greg.

And our next question comes from the line of Neil Mehta with Goldman Sachs.

If you look at post-2013, are you still assuming that O&M growth rate decreases from 4% to 5% to the 3% to 4% O&M range? And what would have to happen for you to get to lower end of that O&M long-term growth rate?

Neil, this is Teresa. I mean, yes, we're definitely assuming that we will taper down, and we are working on several initiatives that involve productivity improvements, I mean, really across the company. And we do think we'll be able to execute on those that will tend to lower the trend in terms of the overall growth rate.

Got it. And can you talk to the timing of the next Minnesota rate case and the next Colorado electric case, when you expect them to be filed and when do you expect the rates to actually going to effect?

In terms of the next Minnesota rate case, we plan to file later this year for 2014, and we expect it to be a multi-year case. Now whether that will be a 2- or 3-year case, we have not developed all the details on that. In Colorado, as you know on the electric case, we're in a 3-year multi-year, which is '12, '13 and '14. So we would expect to file a case in Colorado for '15 around the middle of 2014.

Got it. And the last question, Teresa and Ben. We're seeing some strength in weather-normal natural gas sales across the U.S. This is the first time in a long time we've seen this. Is there something structural going on here? It certainly exceeded your forecast this year as well.

Let me chime in and then, Teresa, please add. But I think it's too early to tell. We certainly saw across our board, particularly in this last quarter, significant increase in gas usage. But weather has also been a little bit unusual, too. And sometimes that -- especially when it's up and down within a month, that can create some problems with our weather normalization models. But it's positive trend, and I hope it continues. But I think it's too early to tell. Teresa, you agree with that?

I totally agree with that. And I think these aberrations in the weather on a shoulder month, as you indicated, we need to watch that.

And our next question comes from line of Travis Miller with MorningStar.

I wonder if you could help me clarify one thing in the release Note 2, where you break down the electric margin. You show that $131 million for the first 6 months. I just want to make sure that excludes the $47 million that you've reserved related to Minnesota.

Yes, it's net of it. Correct. It's net.

So at what level does that $131 million suggest in Minnesota? Is that to the $209 million that you've recommended, or does that go down to, say, somewhere around the ALJ ruling, that you're actually recording in earnings?

I would say -- well, it is around the ALJ.

Okay, okay, great. And then separate subject. When shall we start -- expect to start seeing any kind of financial impact from the Boulder situation, near term or long term?

Well, I mean, Travis, this is Ben. I think what you're seeing right now is some legal costs sort of thing. But as far as the overall impact, are you assuming should Boulder actually municipalize?

F Yes, I'd assume no impact, right, if status quo?

First of all, you probably wouldn't see the impact of that for, I don't know, 3 to 5 years. And then as we've talked about before, it's -- in the big picture of Xcel Energy, it's not a large portion of our sales. And of course, we would aggressively defend customers outside of Boulder and our own shareholders and making sure we receive the reimbursement that we're entitled to, if they were to municipalize. So I don't think it's going to be a big impact.

And our next question comes from the line of Paul Patterson with Glen Rock Associates.

Just in terms of the [indiscernible] little bit of a flavor in terms of if you were to boost your payout, would you guys be thinking of doing it in sort of a growth over multiple years or sort of as a step function, just move it up depending, of course, what the growth outlook is? Do know what I'm saying, just philosophically? I mean I know the board decides it. But do you know what I'm sort of saying? I mean, in some cases, you see an actual, sort of, like, hey, we're going to change it here or it's sort of like, you know what, we're just going to accelerate the growth of the dividend.

Yes. Paul, at this point, I can't give you any more flavor to that than we've already said. And more to come on that as the year progresses, and we get more input into what our expenditures are going to be and all the other factors that you consider with the board to your point in making a dividend recommendation.

Okay. In terms of the sales growth, the 0% to 0.5%, going down from 0.5%, is that weather adjusted, or is that just because of what you see in terms of the weather so far this year?

It's weather adjusted.

Okay. And then in terms of -- you're mentioning these rate cases. I'm just sort of wondering, in terms of your sales growth forecast longer term, could you give us a flavor maybe just for at least Minnesota or Colorado sort of what the long-term growth forecast is? And with respect to Minnesota and the multi-year plan, is there a -- you mentioned O&M and other factors. But if the sales fluctuates, would that potentially also be adjusted under the multi-year plan that Minnesota is looking into here?

I think, Paul, I think, there's a lot of more to come on that. I mean, as I've said in my remarks, the parties are seeking clarification. And even with clarification, I think that those are the kind of elements that become part of the discussion on how we would go forward. I mean, just as an FYI, sales in Minnesota are not very strong, and they're tracking pretty much to our expectations. We didn't expect it to be a strong year, and that's the way it's turning out. So whether or not there would be true-up mechanisms or you would just live with it remains to be seen in the 3-year plan. But...

Okay, I understand. It's early days. But just in general, how should we think about the sales growth, let's say -- I mean, as you mentioned, I mean, you guys have a big -- you guys have a wide geographical reach. What is sort of the look -- what is the sales growth longer term with everything that you know so far, obviously, versus Minnesota, versus Colorado, for instance, or your other jurisdictions?

I would say that Minnesota is probably the most sluggish and we're seeing the most declines. And then, I would say that Colorado is about flat, and we are seeing the strongest growth in actually SPS and NSP-Wisconsin.

I would agree with that. Over the next 5 years, maybe just as rule of thumb, our growth we're projecting to be at, consolidated, up to 1%. But Ben is actually -- he's very correct in terms of Minnesota, we're seeing the most erosion in sales.

Okay. And then just finally, obviously, we've got the situation in Boulder, but Minneapolis also seems to be looking into this. Is this just coincidence that these guys are -- or is there any sort of trend here in terms of municipalization? Could you just give us a little bit of a flavor as to -- this is a sort of local politics sort of situation or is there something else going on?

Well, I think each city is unique, but we do live in communities that very much want to advance their Clean Energy agenda. As you know, Paul, we're very much advanced in the Clean Energy agenda, but we're doing so with economics and price point in mind. There's actually, today, a public hearing on the municipalization discussion in Minneapolis. And they will -- there'll be a vote, I believe, on August 16, by the Council as to whether or not to put this out for public vote in November. The issue is that the city has a climate action plan. We're actually ahead of many of the goals that the climate action plan calls for. We'll have a 30% carbon reduction in the upper Midwest by 2020. So we're just going -- I think at the end of the day, we're going to sit down, work with the city. And I think everybody recognizes the cost and risks and -- the enormous cost for Minneapolis to go forward with something like that. So it is an election year. It has been an issue that's been brought to the attention, and it's gotten a lot of media play. And we look forward to working with the communities, the cities, the stakeholder groups. And we've been a partner for 100 years; I suspect we'll be a partner in Minneapolis for another 100 years. In terms of Boulder, that's farther along. And while I think the -- I don't think it would benefit the customers, we will find out more. The city had a -- the first readout on this in July, wasn't it, Teresa?

Right.

And there'll be another vote on that also in August, whether or not they proceed with condonation proceedings. Again, that's a long process. There'll be another vote in November on debt [indiscernible] to how much all this would cost, and I think there still continues to be work on how we could work with this city and avoid municipalization. But it is what it is, and -- but stepping back to answer your question on a more macro level, we're going to -- I think it's important in this world that we continue to offer more choice to citizens, communities, cities, and we're going to continue to do that. Look for us to do more of that. But also look for us to do that in a way that's fair to people -- to all citizens, all communities and all cities. And that's a really important principle. And so sometimes, I'm talking maybe too much here, Paul, but sometimes we're the middle-of-the-road kind of people where we try to do things that are reasonable and smart, and sometimes you get hit by traffic on both sides of the road when you do that. But I think it's the right way to go for our customers.

And our next question comes from the line of Ashar Khan with Visium Asset Management.

Can you just -- you started off in your remarks regarding the wind and then just going to the conversation regarding people wanting to see more renewables. My first question is, utilities all around are now buying either solar or wind for tax purposes and other stuff. That's also another new thing, which, of course, you can't utilize, I guess, for the reasons. But why bid out these PPAs? Why not build ourself, because that is what the constituents and everyone wants? Why give this capital away to someone else who would utilize our balance sheet and credit ratings? Why not, Ben, be more aggressive in being this wholly owned and for our own self, for our own shareholders, rather than bidding it out? That's question #1. Question #2 is what you mentioned on the Slide 2, is this incorporated? You are mentioning even in North Dakota some wind plant. Is this all incorporated in the 5-year CapEx, I guess, which I have from the beginning of the year? Is that incorporated in the CapEx numbers or not? 2 different questions.

To answer your second question, it's not.

That's correct.

So that would be incremental capital spend. To answer your first question, which is far more complicated, obviously. Obviously, we have a process that we need to go through, Ashar. And we need to justify what is the right decision for our customers to our commissions, as we should. We like to build more, but you have to recognize that -- not unlike when you make a decision to buy a car. If you're going to hold that car for a long time, almost always it's a better decision to build. But as you know, your initial monthly payments would be higher and ownership versus a lease. So we're trying to seek a blend that allows for ownership, which we do think over the long term has a better long-term value for our customers, but also blend it in with PPAs that have that levelized cost. And I think we're seeking the right balance there. And I suppose we could be more aggressive, but I will tell you, the important thing in my mind is that we get these deals done and our customers save $1 billion of fuel over the next 20 years. And while we might not get the direct benefit of that, I think benefiting our customers will always come back to benefit us.

Okay. And then how much -- can you just elaborate if you are successful to what you said this morning, how much of additional CapEx is that, please?

Do you want to take that, Teresa?

Sure. Well, in terms of this, if we just have one, we could be around the $350 million; at 2 would be potentially closer to $600 million.

And that would be in the next 2 years, Teresa, is that the right frame, 2014, '15?

Yes, minimal spend this year. Most of it is in '15.

Ashar, that's also based on just kind of taking an average dollar per kilowatt times the 200 megawatts. That's an estimate. It's not necessarily indicative of the actual price.

Right.

Okay. And then, if I can just conceptually understand the Minnesota case. When is a decision on the multi-year plan? Ben, you mentioned you're going to have a decision later this year; what is the timeframe of that? Is that September, October or something like that?

Well, they already came out and stepped the framework for a multi-year plan, Ashar. The additional clarifications will be later this year. I don't think there's any set timeframe. But we anticipate we'll get that clarification prior to filing of 2014 rate case, which would include a multi-year proposal.

Okay. So if I look -- as you mentioned in your 8-K earlier and today also, weather and all those things helped us to be able to be within the guidance range, assuming the Minnesota PUC rules next weeks or so in line with the ALJ. So am I correct then for next year, we will probably have interim rates in effect starting beginning of the year or so. The impact of any -- whatever the commission's decision is really doesn't have a follow-through effect going forward next year, because the interim rates should be effect from the beginning of the year, and we should be able to be asking for what they didn't give us this time into that next filing; is that a clear way to think of it?

I would say it's partially correct. The -- there's a -- first of all, we have to file for interim rates and we would -- we have been receiving interim rates. But there's some limitations on what you can base your interim rate request on, Ashar. So -- and I've got Teresa and Scott here. I think it could have some impact. But the concept that you speak to is generally correct. So to the extent, as we've mentioned, that we have deferral mechanisms, those deferral mechanisms this year will fall right into '14 and would be part of our overall rate request in 2014.

It could. And if, for example, the commission's order is different than the ALJ, that could also affect the change in terms of the level of what we're requesting in '14.

Okay. And then, if I can end up...

Ashar, we've got several other people on the lines, I think we're going to have to move on. And if you want other questions, go back and we'll get you at the end.

And our next question comes from the line of Stephen Byrd with Morgan Stanley.

Most of my questions have been answered. I did just want to hear a little bit about what you all are seeing in terms of economics for wind projects these days and as you look out sort of in the latest data points that you're seeing. And as you think about the PTC extension versus not being extended, how that would factor in to the volumes, to the outlook for wind growth?

Well, I think it's -- I can't speak to whether or not it's sustainable, but we're seeing phenomenal pricing on wind, Stephen. And enough so that when we price of these things out, you can just make these things work economically on a fuel basis. So today, we could not lock into a 20-year strip of natural gas, with an assumed heat rate for less than we can lock in on wind projects for 20 years. So we're talking about prices, depending on the jurisdiction, in that $25 to $35 kind of megawatt per hour range. That's phenomenal. And of course, if I were to lock in a 20-year strip with natural gas, I wouldn't get any of the capacity value. And while we don't plan for wind because I have a big capacity value, so the economics aren't really based on its capacity. I can tell you what our analysis is showing is that in some of the peakiest, warmest summer days, the wind is blowing. And so we are getting capacity value out of it. So this is just, in my opinion, a home run for our customers. And we're happy to do it. And I think the other thing we've got going for us is that we were in a position where we didn't have to take any of these bids. So we were not a price taker; we could be a price maker. And again, that'll benefit our customers. And I think in the long run, anything that benefits our customersbenefits shareholders, provided it's not a little over ROE.

Understood, understood. And maybe just conceptually on ROEs more broadly, as we think about your ROE position now and the timing of your rate case, I guess, at a big picture, sort of thinking about the movements in interest rates since the last -- in the last several months. And as you look at the ROEs here and you look at them the way that the jurisdictions are calculating ROEs, is this sort of -- should we think of this potentially as a trough in the sense that rates have been increasing since then, mechanically, would -- the timing would appear to have been a trough relative to where we are today as you look out at where interest rates are headed? Or is that not a fair characterization?

I think interest rates rising could -- would be supportive of your trough issue. There's other factors that go into that. But I think -- as you probably know, I think there's a notional amount of return that investors want as well. So again, Teresa or Scott, if you want to comment on that?

No, I mean, I agree with the premise as well.

And our next question comes from the line of Ali Agha with SunTrust.

A couple of quick questions. Ben, one is in the earnings release, when you talk about keeping to your guidance, you talk about the favorable weather, and then you talk about certain other items as well. Can you just remind us what are those certain other items, and what favorable impact they are giving you?

How about if I turn that over to Teresa.

Yes, Ali, if you look at the, actually, the specific earnings guidance items, a number of them we have changed that are favorable. And the key ones are property taxes, AFUDC equity, interest expense and the lower effective tax rate. So a combination of all of those are the certain other items.

I got it. Okay. And then also in Minnesota, you're going through this big rate case right now and, right on the heels of that, the multi-year rate case is coming. And can you talk a little bit about the sensitivity in terms of the timing of one big case ending and the next one starting? And we heard some ramblings from the commission that they're not too happy with that. Just wanted to get your perspective.

We certainly understand that concern and that criticism, and it's -- there's a lot of things coming at once. Our nuclear investment for the next 20 years is a big part of that. But there's a whole host of things that we are investing in to make sure that we are prepared for the future and have a resilient distribution system, have the right amount of transmission. So there's a lot coming. I do think it starts to levelize off. So I think that dialogue, hopefully, we can have, is how we can make sure that we get adequate recovery of those investments but also be responsive to the pace of the regulatory filings that we're making. So more to come on that. We understand the issue. We understand that everybody wants this capital we spend, and we have to work with stakeholders, the commission, their staff, to figure out the best way forward. I think a multi-year framework is a good place to start with that. That gives us an opportunity to, I think, do some longer-range planning.

Got it. And last question, as we look at the results so far, perhaps either on an LTM basis or based in the '13 guidance, can you remind us in which jurisdiction are you seeing the biggest regulatory lag right now?

It would be at our SPS jurisdictions, where we don't have forward test years.

Exactly.

South Dakota.

Yes, it's wherever we have a historical test year. SPS, we're doing -- Texas, we're doing better but it's still the biggest lag, continues to be.

And the best performing from a lag perspective or lack of lag perspective would be?

Colorado, Colorado Electric.

I mean, Ali, one of the things you'll notice is we had an earnings test in Colorado, and we had a refund back to customers, which tells you that we're slightly earning above our authorized return in 2013 for Colorado.

In '12.

'12. Excuse me, I meant in '12.

And our next question comes from the line of Paul Fremont with Jefferies.

I guess, my first question has to do with the 5% to 7% growth rate. For what period of -- or out to what period of time does that 5% to 7% apply?

Well, as I tried to indicate, at least, in my comments that clearly, it's applying to '13. We expect that to continue. After we get past '13, because of all the factors like pressure on ROEs, we could see that moderating down some. But more to come because we're in the middle of rate cases right now, and there's several other factors.

So when you were talking about being in the low end of that range, that would only apply to '13 then?

We said -- I talked about after '13, not being able to achieve the high end of the 5% to 7%.

Okay. Second question would be, what is the PSIA portion of the increase request that you have in Colorado? So in other words, if you just strip out the PSIA piece for '13, how much is that?

Yes, it's $26 million, $27 million.

Okay. And then last question for me is, what's driving the increase in AFUDC relative to your guidance? Is it that you're accelerating the amount of your investment? Or is the AFUDC rate higher than what you were assuming?

It really has to do -- it's the construction timing and the amount of it. It's the combination of those and how much short-term debt we have outstanding. In terms of less short-term debt, it tends to drive up the AFUDC rate, the equity rate. And so that -- those are the biggest drivers.

And our next question comes from the line of Dan Jenkins with the State of Wisconsin Investment.

I just had a couple of questions related to this Minnesota multi-year plan. So is it -- I guess, I'm wondering, a lot of other states, they've had to pass legislation to implement this type of thing. Is there -- is the current utility legislation fully compliant with implementing the multi-year plan or get some parties...

No, we've already had that pass through the legislative process.

And the commission is just buying...

So the mechanics were -- for the commission to determine, and that's what the -- it did earlier this year, they just established the framework.

So -- and then, do you expect this to be in place, then, prior to your 2014 case, you said; is that correct?

The framework is in place, so -- I mean, it is in place. And as you go through this the first time, there's always going to be questions about the mechanics and some of the more detailed rule -- rulings within. And that's the process we're in right now.

So do you see it working similar to how they do it in Wisconsin or can you give us a little more...

Wisconsin is by statue, is you file it every 2 years. So this, I think, would be a little bit different in that you can have a longer period of time, there's different rules. And you've got capital and some O&M costs that you can recover in potentially the second and third years.

Right. If you file that all initially in Minnesota, where Wisconsin you come in every other year, but you have to reopen her.

Right.

And our next question comes from line of Ashar Khan with Visium Asset Management.

Yes, I guess, it's a timing question. Ben, you guys have always given us, like, the next year's guidance on the third quarter call. So is it fair that we should get this new growth rate and guidance on the third quarter call?

Yes, I mean, we'll have a number of opportunities. We've done it in the third quarter. I think we've done it at EEI. We've done it at different times. But we will definitely keep you updated as this thing develops.

And I am showing no further questions. I will turn the call back to Ms. Teresa. Please go ahead.

We appreciate your participation in our second quarter earnings call. Please call Paul Johnson and the IR team with any follow-up questions. And thanks.

Thanks, everyone.

Thank you. Ladies and gentlemen, this concludes the second quarter 2013 earnings conference call. If you would like to listen to a replay of today's call, please dial 1 (800) 406-7325 or (303) 590-3030 and enter access code 4628633, followed by the pound sign. We'd like to thank you for your participation, and you may now disconnect.