埃克西爾能源 (XEL) 2013 Q2 法說會逐字稿

Good morning, ladies and gentlemen, thank you for standing by. Welcome to the second quarter 2013 earnings conference call. During today's presentation all parties will be in a listen-only mode. Following the presentation the conference will be open for questions.

(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 web page. We will also post a brief video of Teresa Madden summarizing our financial results on the web page.

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 three 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 are our Monticello Nuclear Plant. In July we brought or 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. The scope of this project changed several times as we worked to meet evolving NRC standards for safety, increase the reliability margin and address emergent issues that were discovered during construction.

Our cost for the project are approximately $655 million which is above the estimate provided in our 2008 certificate of needs filings. We have committed to an after the fact prudence review. We expect that the overall costs 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 two 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 three 200-megawatt projects, including one 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 a 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 in 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 rate making 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 guide lines. A multi-year rate plan must cover up to three 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 authorized in 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 limiting 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 developments, review our financing plans and update you on our 2013 earnings guidance. I'll begin by reviewing the second quarter results of each of our four 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 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 refund in certain states. This amount includes the reserve for revenue 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 for fabrications, a $9 million reduction in conservation and DSM incentives, an $8 million decrease in firm wholesale revenue, and various other items.

Second quarter weather normalized retail electric sales decreased 0.2% As Ben 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 six 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 action 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 system. 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 forecasts, 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 her report and recommended a rate increase of approximately $127 million based on 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 costs. We estimate these recommended deferrals would have a $34 million impact on our 2013 earnings. From a pre-tax 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 allocation 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 were 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 intervener testimony is scheduled for October 4. We anticipate a final decision before year-end with 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 equity ratio of 53.9%. We anticipate a commission decision by year-end with new rates going into effect during the first quarter of 2014.

I'll now update you on progress of our 2013 financing plan. During the second quarter we continued to leverage our strong credit rating 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 three 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% holding company junior subordinated note.

Based on the successful execution of our financing plan 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 of 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 with any non 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 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-based growth, sluggish sales, and the potential for compression in authorized ROEs. 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 the payout ratio below 60% we have the flexibility to grow our dividend 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.

Thank you.

(Operator Instructions)

And our first question comes from the line of Greg Gordon with ISI Group. Please go ahead.

Hello, Greg.

Good morning, Greg.

Good morning, guys. So I guess I'm not going to -- I won't ask you to articulate your rationale on the tweaking of the total return expectations because you plan on giving us 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 was 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 ROEs 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. 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. I think that gives us dry powder and maybe a unique way to reward shareholders going forward.

Okay. 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. I really wouldn't. We're going to make use of transmission lines and capabilities that are already in place. 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.

Okay. Thanks, guys.

Thank you. And our next question comes from the line of Neil Mehta with Goldman Sachs. Please go ahead.

Good morning.

Good morning, Neil.

As you look out 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 the lower end of that O&M long term growth rate?

Neil, this is Teresa and 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 we'll 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 go into 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 two or three year case, we have not developed all the details on that. In Colorado as you know on the electric case we're in a three 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 then last question, Teresa and Ben, we're seeing some strength in weather normal natural gas sales across the US. This is the first time in a long time we've seen this. Is there something structural going here? Certainly it's 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 a significant increase in gas usage, but weather has also been a little bit unusual too and sometimes that can -- 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 show of a month as you indicated we need to watch that.

Got it. Thank you very much.

Thank you. And our next question comes from the line of Travis Miller with Morningstar. Please go ahead.

Good morning, thanks.

Morning, Travis.

Wonder if you could help clarify one thing in the release note two, where you break down the electric margin, show that $131 million for the first six months. I was wondering, 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 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. Great. And then separate subjects, when should we start -- expect to start seeing any kind of financial impact from the Boulder situation -- near term or long term?

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?

Yes, I'm assume no impact right if status quo.

First of all, you probably wouldn't see the impact of that for three to five 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 in making sure we received the reimbursement that we're entitled to if they were to municipalize. Don't think it's be a big impact.

Okay. Thanks a lot, appreciate the help.

Thank you. And our next question comes from the line of Paul Patterson with Glenrock Associates. Please go ahead.

Hello. How are you?

Good.

Morning.

Just in terms of -- if you could give us a little bit of a flavor in terms of if you were to boost your pay out, would you guys be thinking of doing it in a growth over multiple years or just a step function just move it up depending on what your growth outlook is? Do you know what I'm saying -- just philosophically? I mean I know the Board decides it - but do you know what I'm saying? I mean in some cases you see an actual sort of like -- hey, we're going to change it here or it's 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 what we've already said. 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 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 your mentioning these rate cases, I'm just wondering, in terms of your sales growth forecast longer term. Could you give us a flavor maybe just for at least Minnesota or Colorado what the long term growth forecast is -- and with respect to Minnesota and the multi-year plan, is there a -- you mention O&M and other factors, but if the sales growth fluctuates, would that potentially also be adjusted under the multi-year plan that Minnesota's looking into here?

I think, Paul, I think there's a lot more to come on that. As I said in my remarks, the parties are seeking clarification and even with clarification I think that those are the 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 a three-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 as you mentioned you guys have a big -- you guys have a wide geographical reach. What is the -- 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 decline and then I would say Colorado is about flat and we're seeing the strongest growth in actually SPS in NSP-Wisconsin.

I would agree with that over the next five years -- maybe just as a 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 this situation in Boulder, but Minneapolis also seems to be looking into this. Is this just coincidence that these guys -- or are is there any other trend here in terms of municipalization? Could you just give us a little bit of a flavor as to local politics situation or is there something else going on?

I think each city is unique, but we do live in communities that very much want to advance a clean energy agenda. And as you know, Paul, we're very much advancing a 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 there will 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. You know, the issue is that the city has a climate action plan we're actually ahead of many of the goal 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 costs and risk -- 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, you know, 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 the first readout on this in July wasn't it, Teresa?

Right.

And there will be another vote on that also in August. Whether or not they proceed with condemnation proceedings again that's a long process. There will be another vote in November on debt limits to how much all this would cost. I think there still continues to be work on how we could work with the city and avoid municipalization. But it is what it is and -- but stepping back to answer your question in 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 it's fair to people, to all citizens, all communities, and all cities and that's a really important principle. And so sometimes talking maybe too much here, Paul, but sometimes we're the middle of the road 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.

Great, thanks for the answer. I really appreciate it.

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

Good morning.

Hello Ashar.

You know you start 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 -- and 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 we can't utilize I guess for other reasons, but why bid out these PPAs? Why not build our self, because that is what the constituents and everyone wants? Why give this capital away to someone else who will utilize our balance sheet and credit ratings? Why not, Ben, be more aggressive in being these wholly owned and for our own self, for our own shareholders rather than bidding it out?

That's question number one, question number two is. What you mentioned on the slide 2, is this incorporated -- you were mentioning even in North Dakota some wind plant, is this all incorporated in the five year CapEx, I guess, which I have from the beginning of the year? Is that incorporated in the CapEx numbers or not? Two different questions

To answer your second question it's not.

That's correct, yes.

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 -- it's 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 in ownership versus a lease.

So we're trying to seek a blend that allows for ownership which we do think over the long term is a better long term value for our customers, but also blend it in with PPAs that have that levelized cost. 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?

Want to take that Teresa?

Oh, sure. Well in, terms of this, we just have one we could be around the $350, million at two would be potentially closer to $600 million.

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

Yes. Minimal spend this year, most of it's in '15.

Ashar and that's also based on just 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 the decision on the multi-year plan, Ben, you mentioned you are going to have a decision later this year, what is the time frame of that? Is that September October or something like that?

Well, they already came out and set the framework for a multi-year plan, Asher. The additional clarifications will be later this year. I don't think there's any set time frame, but we anticipate we'll get that clarification prior to filing a 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 have helped us to be able to be within the guidance range. Assuming the Minnesota PSC 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 the beginning of the year. So the impact of whatever, any -- if the ALJ -- whatever the commission's decision is, really doesn't have a fallout to affect going forward next year because the interim rates should be a fact from the beginning of the year? And we should be able to be asking for what if 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. There's a -- first of all, we have to file for interim rates and we would just, 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 mentioned that we have deferral mechanisms, those deferral mechanisms this year would fall right into '14 and would be part of our overall rate request in 2014.

It could and if, for example, the commission ordered 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 line, I think we're going to have to move on. And if you want other questions, go back in and we'll get you at the end.

Okay.

Thank you, Asher.

Thanks.

Thank you. And our next question comes from the line of Stephen Byrd with Morgan Stanley. Please go ahead.

Hello Stephen.

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

Well, 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 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 a wind project for 20 years. So we're talking about, prices depending on the jurisdiction in $25 to $35 megawatt per hour range. That's phenomenal.

Of course, if I were to lock in a 20 year strip with natural gas, I wouldn't get any of the capacity value. While we don't plan for wind to 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. 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 will benefit our customers and I think in the long run anything that benefits our customers benefits shareholders -- provided it's not a little ROE. (Laughter)

Understood, understood. 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 thinking about the movements in interest rates since the -- in the last several months as you look at the ROEs here and you look at them the way that the jurisdictions are calculating ROEs, is this -- should we think of this potentially as a trough in the sense rates have been increasing since then. Mechanically would the timing would appear to have been a trough relative to, to where we are today. As you look out to where interest rates are headed or is that not a fair characterization?

You know, 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. You know, again, Teresa or Scott if you want to comment on that.

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

Great. Thank you very much.

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

Hello, Ali.

Hello, good morning, how are you?

Good.

A couple 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're giving you?

How about if I turn that over to Teresa.

Yes, Ali, if you look at the actually -- or the specific earnings guidance items, a number of them we have changed that are favorable. 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. Can you talk a little bit about the sensitivity in terms of the timing of one big case ending and the next one starting? We heard some rumbling's 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 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're investing in to make sure 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 the 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 spent 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 do some longer range planning.

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

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

Exactly, yes it's where ever we have a historical test year, SPS we are 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.

Ali, one of the things you noticed 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.

And '12.

Yes '12, excuse me. I meant '12.

Right, got it. Thank you.

Thank you. And our next question comes from the line of Paul Fremont with Jefferies. Please go ahead.

Hello, Paul.

I guess my first question has to do with the 5% to 7% growth rate. For what period -- 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 on the low end of that range that would only apply to '13, then?

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

Okay. Second question would be, what is the PSIA portion of the increase requests 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 a 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's -- those are the biggest drivers.

Okay. Thank you very much.

Thanks.

Thank you. And our next question comes from the line of Dan Jenkins with State of Wisconsin Adjustment of Investments.

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

No. We've already had that passed through the legislative process.

Okay --

And the commissions isn't [fighting] it -- (multiple speakers)

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

So and then 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. As you go through this the first time there's always going to be questions about the mechanics and some of the more detailed rulings with it 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 statute. You file every two years.

Right.

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

Okay. That's all I had. I just wanted to get a little more clarification on that. Thanks.

Thanks, Dan.

Thank you. And our next question comes from line of Ashar Khan with Visium Asset Management. Please go ahead.

Yes. I guess it's a timing question. Ben, you guys have always given us 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 on third quarter. I think we've done it at EI. We've done it at different times.

At the Analyst Meeting.

We will definitely keep you updated as this thing develops.

Okay. Okay, okay Thank you.

Thank you. 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.