埃克西爾能源 (XEL) 2013 Q3 法說會逐字稿

Ladies and gentlemen, welcome to the Xcel Energy third quarter 2013 earnings conference call held on October 24, 2013.

(Operator Instructions)

I would now like to hand the conference over to your host, Paul Johnson, Vice President of Investor Relations and Business Development. Please go ahead, sir.

Good morning. Welcome to Xcel Energy's 2013 third quarter 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 third quarter results, update you on recent business and regulatory developments, discuss 2013 and 2014 guidance, as well as update our long-term earnings growth and dividend growth rates. 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 our website.

Please note some of the remarks made 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.

In addition, today's press release refers to both ongoing and GAAP earnings. 2013 third quarter GAAP earnings of $0.73 per share reflect a $0.04 per share charge as of a result of August 2013 FERC decisions regarding certain fuel and cost allocations at SPS. This issue relates to complaints by parties dating back to 2004 and 2006. These orders resulted in a refund liability for prior periods and consequently we took a net $35 million pre-tax charge during the quarter. Details of this order are found in today's press release and 8-K, which we filed in August. Management believes ongoing earnings, which remove the impact of issues and charges related to prior periods like the refund liability associated with the FERC orders, provides a more meaningful comparison. As a result, the comments on today's call will focus on third-quarter ongoing earnings of $0.77 per share.

With that, I will turn the call over to Ben.

Well, thanks, Paul. Good morning. Today, we are reporting 2013 third-quarter ongoing earnings of $0.77 per share. A $0.01 per share decrease compared to $0.78 per share we reported one year ago. While weather was a $0.05 benefit this quarter, it was even great in last year's third quarter at $0.08 per share. On a year-to-date basis, ongoing earnings are $1.65 per share compared to $1.54 per share last year. While the final rate case in the Minnesota electric case was less than expected, the combination of favorable weather, and Management actions have positioned us to deliver 2013 ongoing earnings in the upper half of our guidance range. This would mark the ninth consecutive year of meeting our annual earnings guidance. We are also initiating our 2014 ongoing earnings guidance of $1.90 to $2.05, which Teresa will discuss in more detail in a few minutes.

As you may recall, eight years ago, we announced our EPS growth objective of 5% to 7%, along with a dividend growth objective of 2% to 4%. I'm pleased to say we met these objectives on both a GAAP and an ongoing basis. During this time, we also improved our credit rating and our operational capabilities. As we look beyond 2013, we see EPS and dividend growth targets of 4% to 6%. While the components of our value proposition have changed, we remain positioned to continue to deliver an attractive and competitive total return for many years to come. We are in the process of updating our capital forecast and we continue to have excellent opportunities to invest in our utility operations. We will provide more clarity on our updated capital plan, as well as our plans to continue to reward our shareholders at our analyst day in December.

I'd now like to share a few recent operational successes with you. On our second-quarter conference call, I discussed our successful storm recovery capabilities in Minnesota. Little did we know that those capabilities would be put to a test again so soon. In Boulder, on September 9, it began raining and it didn't stop for a week later. Officially, 17 inches of rain fell, with certain parts of the region receiving over 20 inches. Now, previously, the wettest September has been 5 1/2 inches. The rainfall caused catastrophic damage to Boulder, as well as adjacent communities.

I'm proud to say that we again demonstrated our ability to restore customers quickly and safely in a very challenging situation. This storm caused extensive damage to critical infrastructure, including our natural gas delivery system in the Boulder area. We have identified approximately 20 miles of natural gas pipe and thousands of natural gas and electric meters that required replacement due to water damage. We are working diligently and safely to get service restored to all of our customers in the region, and have restored everyone that can be connected at this time. In some cases, we're making temporary repairs, with permanent repairs scheduled for next year.

On the generation side of our business, we recently brought back two of our base load plants. Our Monticello nuclear facility returned to service in August following an outage where we had completed life extensions in the extended power upgrade projects. This fall, Sherco 3 returned to service following the unit's catastrophic failure in late 2011. As a result, Sherco 3 will return to use and useful status in our 2014 Minnesota rate case, which should resolve an issue from our last case. It's important to note that the majority of the restoration costs will be covered by insurance. Therefore, the cost of repairs will not impact customer bills.

Turning to our current projects, we recently began a scheduled outage at our Prairie Island nuclear facility, which is necessary for the 20-year life extension. During this outage, we replaced the steam generators at Unit 2. As you know, we have already successfully replaced the steam generators at Unit 1. As we mentioned last quarter, we are pursuing the addition of up to 1,900 megawatts of wind across all of our jurisdictions. Adding these resources today creates long-term value that could save our customers over $800 million in fuel costs over the next 20 years.

I'd now like to update you on where we stand with our proposals to add wind, as well as thermal resources. At NSP, we are proposing to add 400-megawatts of wind through power purchase agreements and 350 megawatts of wind that we would own. The Minnesota Commission approved these wind projects last week and the North Dakota Commission is expected to rule later this year. We will also need the results from a final MISO study to determine the transmission inter-connection costs for the project, which we do expect to receive in the first quarter of 2014. The transmission study is important to ensure that the final costs remain economical for our customers. For the natural gas RC in Minnesota, we recommended that the lowest cost option for our customers would be a 215 megawatt CT plant addition at our Black Dog plant, and a power purchase agreement with either Calpine or Invenergy. We anticipate an ALJ recommendation by year end with a final Commission decision in the first quarter of 2014.

Colorado, we filed a proposal with the commission to add 170 megawatts of solar, 450 megawatts of wind, and 317 megawatts of low-cost natural gas generation. All of these requested resources would be acquired via power purchase agreements. In October, we received Commission approval for the wind power purchase agreement. These additions will bring PSCo's total wind capacity in Colorado to more than 2,600 megawatts. The Commission is expected to decide on the solar and natural gas generation proposals in early December.

Financially, operationally, we remain on track and positioned for future success. With that, I will turn the call over to Teresa.

Thanks, Ben. Good morning, I will begin by providing a brief overview of our third-quarter results at each of our four operating companies. Third-quarter ongoing earnings at PSCo decreased $0.03 per share primarily due to higher depreciation and O&M expenses, and cooler summer weather. Ongoing earnings at NSP Minnesota increased $0.03 per share for the quarter. Quarterly results were positively impacted by electric rate increases in Minnesota and South Dakota, North Dakota interim electric rate, and lower interest charges. SPS ongoing earnings decreased $0.01 per share for the quarter. A rate increase in Texas didn't fully offset higher O&M expense, depreciation and interest charges, and the impact of cooler summer weather. Finally, third-quarter ongoing earnings at NSP Wisconsin increased $0.01 per share, due to higher electric and gas rates that were implemented in the first quarter of this year.

I will now review the key drivers on the income statement, beginning with retail electric margins. Despite $46 million in retail rate increases across several states, third-quarter gas, electric margins decreased $24 million. As Paul noted in his introductory remarks, we took a net $35 million pre-tax charge during the quarter related to the August SPS FERC re-hearing order. Of this amount, $26 million was related to electric revenues for periods prior to 2013, $5 million was related to 2013 electric revenues, and approximately $4 million was for interest charges. We are excluding the $26 million associated with years prior to 2013 from our ongoing electric margin. Adjusted for this reclassification, electric margin increased $2 million during the quarter. Going forward, we anticipate the annual revenue impact of these orders could be up to $6 million in 2014, decreasing to $4 million in June 2015.

Other factors that contributed to a decrease in third-quarter electric margin were a $20 million estimated impact from cooler summer weather versus last year, $17 million from decreased conservation and DSM incentives, and $11 million from an estimated earnings test refund obligation at PSCo. Third quarter weather normalized retail electric sales increased 0.3%. On a year-to-date normalized basis, electric sales increased 0.1%. We are tracking remarkably close to our internal projections. Our 2013 electric sales guidance is for 0% to 0.5% growth. Natural gas margins rose $5 million, primarily due to an interim rate increase in Colorado.

Turning to expenses, O&M increased $43.8 million, or 8.2%, during the third quarter, and $90.9 million, or 5.8% for the year-to-date period. Several factors drove the higher O&M expense during the quarter, including electric and gas distribution expenses associated with vegetation management, storms and outages, nuclear outage amortization and other nuclear expenses, and higher employee benefits, related primarily to increased pension expense. We continue to project that our 2013 annual O&M expenses will increase 4% to 5%. Depreciation and amortization expense decreased $10.6 million or 4.4%. As part of the final electric rate case order in Minnesota, NSP Minnesota reduced depreciation expense $24 million during the third quarter. This reduction was offset by increased depreciation from normal system expansion.

I will now provide an update on a few of our regulatory proceedings. In Minnesota, we plan to file a multi-year electric rate case in early November. The primary drivers of the request will be related to our significant capital investment program. We intend to file a 2-year rate case. The first year will be a full 2014 test year. The second year will consist of a step increase primarily for specific capital projects but also for related property taxes and chemicals for emission controls. Consistent with the commission's multi-year plan order, we intend to reduce our use of riders and instead recover certain investments through the multi-year plan. Our recently-approved wind investments will be included in the 2015 portion of our request.

Our rate case is driven by our investments in steam generator replacement projects at Prairie Island, the Monticello upgrade and life extension, the return of Sherco 3 to service, as well as increases in our nuclear O&M costs and property taxes. For these reasons, we expect this to be a sizable request. As a result, we intend to propose a rate plan to moderate the level of rate increases and keep it within a more predictable range for our customers over the next several years. We know that there are inherent challenges associated with filing back-to-back rate cases. Therefore, we've been meeting with stake holders to help provide them with an understanding of the key drivers of our costs and the need to file at this time. We believe the parties are open to discussing a longer-term framework, and we will continue to work with them on this approach. Finally, we plan to file a more comprehensive set-up testimony and information to provide additional support for our position, and to assist the various parties with their review of our case.

Also in Minnesota, we made our prudent filing related to our Monticello life extension and power upgrade project. As Ben mentioned, the project was recently completed, and Monticello is back up and online. We expect that the NRC will issue licenses for the plant to operate at the higher output level later this year or early next year. The Monticello life extension power upgrade project was a highly complex undertaking that in many ways was more complicated than the original plant construction. The initiative, which dates back to 2003, involved the replacement of hundreds of pieces of equipment, required thousands of workers, and resulted in a largely rebuilt plant. The cost of the project evolved from the original estimate of $320 million in 2008 to $665 million, due to increased federal regulatory standards and schedules, higher installation costs, and a broader scope than originally anticipated. Completing the project took longer and cost more than we anticipated, but it was essential that it be done right and we believe we made reasonable decisions along the way. Finally, it is important to recognize that the upgrades to Monticello will benefit customers for years to come, and were completed at a cost consistent with similar projects at other nuclear facilities across the country.

Turning to Colorado, on October 22, the ALJ issued her recommended decision in the Colorado natural gas case. The report is 159 pages, and doesn't include a specific revenue requirement calculation. As a result, it will take us a few days to analyze and determine the recommended rate increase. However, some of the ALJ recommendations are consistent with PSCo's position and include a prepaid pension asset remains in rate base, approval of PSCo's pension expense adjustments, approval of PSCo's annual incentive plan costs, approval of PSCo's pro forma historical test year property tax adjustment of $7.1 million, and an equity ratio of 56% based on an actual year-end capital structure. Additional recommendations include PSCo's revenue requirements will be based on a historic test year not a forecast test year. The rate case should be based on a single year not a multi-year rate plan and an ROE of 9.72%. It is important to recognize that these are recommended decisions. We plan to file exceptions to the report on November 1. The Colorado Commission makes the final decision and it is expected to rule on the natural gas case before year end.

Details regarding our regulatory proceedings in Wisconsin, North Dakota, and New Mexico, can be found in our earnings release.

Before we open up the call for questions, I would like to comment on our earnings guidance for 2013 and 2014. Our strong year-to-date results position us to deliver ongoing earnings in the upper half of our $1.85 to $1.95 per share guidance range. If achieved, this would represent the fourth year in a row in which our ongoing earnings have been in the upper half of our guidance range. We continue to expect GAAP EPS will be within our guidance range.

Looking ahead, we're initiating 2014 ongoing earnings guidance of $1.90 to $2.05 per share. This range assumes constructive outcomes in all rate case and regulatory proceedings, including the implementation of interim rates. Other key guidance assumptions are detailed in our earnings release. We've provided a $0.10 EPS guidance range ever since 2004 when our guidance range was $1.15 to $1.25 per share. As our projected earnings approach the $2.00 per share level, we think it is appropriate to widen the guidance range to $0.15 per share to capture the natural variability of earnings. We also think it is appropriate to have the low end of the range start at the midpoint of our 2013 guidance range, or a normalized EPS of $1.90 per share, which represents the starting point for our 4% to 6% EPS growth objective.

In closing, we are pleased to deliver another strong quarter, which positions the Company to meet our earnings objectives for the ninth consecutive rate year. That concludes my prepared remarks. Operator, we will now take questions.

(Operator Instructions)

Kit Konolige, BGC.

On sales growth outlook, I believe you said that you're expecting 0% to 0.5% in 2013. Can you discuss the breakdown by states on that? Maybe any color about commercial versus industrial versus residential? Also give us a view of the longer-term sales outlook that you are seeing at this point?

Well, sure, Kit. Let's start with the 2013 by the states. Minnesota, we're still projecting a decline of about 1.2%. NSP Wisconsin, just a slight decline. Then, the other two jurisdictions, PSCo slightly up and SPS at about the 1.2% range. All of it netting to within the up to 0.5%.

When we look to the future, we are looking at about, as we indicated in our guidance, up to 0.5%. Those are narrowing. Not such a great degree, in terms of the decline, in NSP Minnesota. In terms of the various classes of customers, it does vary by jurisdiction. I will say that CNI, we see the most growth in Texas with the oil and gas industry boom.

Kit, I would just add that our forecasting abilities for sales have really been very, very accurate this year and we believe heading in next year, too. I think we really got our arms around what is happening with the economy and how that relates to our sales growth.

So you're expecting -- is it fair to summarize it as saying are you expecting netted around the various states roughly flattish to slightly up sales growth over the middle to longer term?

Yes, that's correct.

That's lower, obviously, than historically. What trends are you attributing that to? Just economics, energy efficiency?

All of those, yes.

Okay. Well, it sounds like I have that part of the note written already then.

Good. (laughter)

Okay, thank you very much.

Neil Mehta, Goldman Sachs.

A couple of questions. First on O&M, the O&M growth imbedded here in 2014 guidance is 2% to 3% versus the 4% to 5% from this year. What is driving the lower sequential rate? Is that pension? Or is it also process improvement? Should we take that 2% to 3% and extrapolate that as the long-term growth rate that you're targeting?

Well in terms of the 2% to 3%, yes, pension is contributing to that. We did say that 2013 was going to be our high mark. Also, we are assuming that likely we will have some uptick in the discount rate, but we are also seeing some -- we are working towards improvement, process improvements on the operational side of our business. In terms of our overall growth rates, if we look to the future, we do intend to keep them lower than our historical 4% where we have been at.

Okay. Great. On the wind project, if that is approved, when will the CapEx impact? Is that 2015, or is there any CapEx imbedded in 2014? Can you provide some more clarity on this MISO study? What specifically is the scope of what they're looking at?

Well, let's start in terms of the wind projects, there is a very small amount in 2014. The lion's share of the estimated spend will be, actually, it is in the latter part of 2015, around the third quarter, because they're anticipated to go in service by the end of that year. The MISO study is really related to some inter-connections and some paths primarily: what will be required. We need to have the completion of that study to ultimately determine what the costs will be for those transmission paths: what will be required.

Perfect. Last question is, the major objectives for the analyst day on December 4. Is that when we can expect the CapEx refresh for Xcel?

Yes, that is right, Neil. You can expect that, as Teresa mentioned, these wind projects will drive some CapEx needs, we will refresh everything. As I said in my remarks, I think we continue to have a lot of opportunity to invest in our utilities and we will update you on that. We will update you on where we see the value proposition, and give you a general operational and financial update.

Terrific. Thank you very much.

Paul Fremont, Jefferies.

My first question is, you talk about a potentially substantial filing in Minnesota. The last filing I think was close to $300 million. Should we be looking at something in that range? Can you remind us what percent was the $285 million that you were requesting in terms of a percentage increase?

I think the $285 million, correct me if I'm wrong, Scott or Teresa. I think the $285 million was 11%?

Yes, it was in the 10%s.

Okay. At this point, we don't want to get any more specific, other than to tell you we now it will be a significant case. We know putting rate moderation programs in place are going to be very beneficial to helping making the outcome of the case constructive and successful. Obviously, it reflects a lot of capital costs, and nuclear related, as well as just general infrastructure.

So, I think we're in pretty good shape. It is going to be significant. We've talked about that before. It is the reason why we also are sharing with our stake holders what it looks like over a five-year horizon. We think the pace of rate increases will moderate significantly in the next few years.

I know a year ago that the Commission had talked about changing the rules for the -- or the requirements for the interim increase. Were any changes made or is it essentially the same as it would have been when the $250 million went into effect in January?

Well, it's a couple of things that have changed. One, as you know, they changed how the methodology of calculating the refund obligation works. We did have a court order that essentially gives the Commission a little more flexibility in how they grant interim rates. Frankly, we're aware of that, and we have incorporated that into our rate moderation plans.

Okay. The wind projects that have already been approved in Colorado and in Minnesota, can you give us a dollar amount of construction associated with the approved projects?

Yes, of course, the ones that are on the power purchase agreements, they're in the -- a better way to describe that to you is what their levellized prices are, and that's in the $25 to $35 range. In terms of the ones that we have the opportunity to own, I think we're looking at just rough figures, in -- what is it? 1,700 to 2,100 of KW, something around that.

Yes, it's around there.

1,750 per KW installed is an average cost that you see in the industry. You can take that times the 350 and come up with an estimate of the capital.

It works out to a very good levellized cost for our customers. Again, these prices are so compelling that -- I mean the energy associated with it is less than what you can do lock in a 20-year gas strip for. Hence the $800 million plus of fuel savings. We're getting the environmental, we're getting the capacity savings that these projects bring. So, we are really excited about it.

The last thing, the 2014 guidance, I assume, carries forward the ongoing impact of the FERC order, and is there a possibility of getting that overturned?

Yes, it does include the ongoing impact or potential impact from that. We have filed for rehearing. We think our positions are strong, so we feel good about that. We do have that incorporated into our projections for 2014.

Thank you very much.

Ali Agha, SunTrust.

First question, before the 6% long-term EPS growth rate, what time period roughly should we thinking about that? Is that a five-year growth rate? Three years? What associated rate-based growth should we assume is imbedded in that growth rate target?

Ali, it is long term, so we could say three to five years. In terms of the rate base growth, really no different than we've been talking to you on the front end over the five years, potentially up to like 5%.

There is still the front-end load. This year we have high capital to spend. We'll start to taper down. We'll have some moderation, assuming we would move forward with the 15 wind projects. And, we are assuming we will move forward pending the final approvals. But that is really what the landscape looks like.

Also, are you assuming pretty much flattish trends in terms of earned ROEs over that period, or any improvement? How should we think about that?

Generally, pretty flat over that period.

Ali, as you know, the last several years, we have been around that consolidated ROE of 10%. Given the macro economic environment we are in, I think that is a pretty good assumption going forward.

Okay. On the dividend policy, I wanted to get a little more insight. I know you guys have been saying in the past that as the earnings growth starts to taper down, you start to get more aggressive on the dividend. We see that the dividend growth is now in line with EPS; previously it was slightly below. The fact of the matter, Ben, as we said, that your payout ratio is still probably lower than your payer group, and so if you keep dividend in line with earnings, you keep it at that payout ratio. Any thoughts on that? I would have thought you may have wanted to grow the dividend at a faster pace than earnings. Any insights in your thinking there?

I think we started with giving you the clarity that the dividend growth rate objective is now 4% to 6%. We know that our dividend payout ratio is modest compared to our peers, and that's a good thing. We've got lots of options going forward. What we do and how we do it and the various options you can reward shareholders, obviously, that is a very important topic that we will discuss with our Board.

We will look at a number of factors: CapEx, macro economic conditions, credit rating objectives. You name it, we look at it. I'm excited that we can continue to offer such a compelling value proposition. I think it is a hallmark of what we've been able to accomplish. One thing, as I pointed out in my notes, we actually do hit our objectives. We've got a history of that. So, I hope everyone takes comfort in that.

Last question, Ben, when you had laid out the last five-year CapEx program, in there you had imbedded, I think it was about $800 million of equity, or it is about $400 million with this after-market program that you put out there. As you think about these new wind projects, assuming they do come in, and I think you have said that you assume that they do come in. Doing the math, another $650 million, $700 million of CapEx, what does that do to your thinking about equity in the mix, as you look forward now?

You want to take that one or do you want me to?

Maybe the short answer, Ali, is we really do plan to discuss the whole, complete plan at our analyst day. So, we will be revising and refreshing all of that when we meet with you at that time.

Is it fair to say we should assume more equity just given the additional in CapEx and the balance between equity and that? Is that fair to think about?

Let's first of all, let's make sure the projects are finally approved, and we will share that capital forecast. As you know, timing of the capital forecast is pretty important when it comes to any equity needs. I think the bottom line is our equity needs are very modest going forward, so I don't think that will be a big issue. But we certainly can give you more clarity at the analyst day.

Yes, I agree with that.

Thank you. Thanks a lot.

Travis Miller, Morningstar.

A quick follow up on the dividend. Have you guys given out a payout ratio guidance or just the growth rate?

At this point, just the growth rate.

Growth rate? Okay. Is it fair to assume that implied 60%, if we go out to the guidance 2014 and apply the growth rate, is that about where you're comfortable?

Well, I think we're comfortable right now, on the 4% to 6%. We are going to, obviously, as I said previously, we will discuss various ways we can reward shareholders within that target with our Board. Again, we know we have a modest payout ratio. We also have outstanding credit ratings and excellent opportunities to continue to invest in our utility operations.

Okay. Great. Quick on the gas usage growth, you guys have posted really good gas usage growth for the last several quarters. I was wondering if you could characterize that continuing trend, whether you see that continuing, or if there is fundamental developments there? What's going on over the last few quarters to drive that 4% to 5%?

I think I would characterize it as maybe an aberration. We were watching it. I would say that our weather normalization is very cold. It's primarily in PSCo in the early part of the year. We may have some aberrations with that. As you can see, when we look to 2014 we are actually projecting some decreases. I wouldn't say it is a necessarily. We'll continue to watch an ongoing, long-term trend to see that uptick at that level.

Do you think there has been a material response given the decline in gas prices? Do you think that is a driver and that if you got gas prices going to $6, $7, that you could see a significant pull-back? Or is that not necessarily relevant?

I think in general, with anything when prices go up, people will potentially monitor their use. So, depending how much and when.

Sure. Okay. Thank you.

Neil Kalton, Wells Fargo.

Just a quick question on EPS guidance for 2014, and specifically the low end, which is flat with 2013 really. What has to happen to see flat year over year? What should we specifically be looking out for?

There are several things that could affect next year, but we talked about the Minnesota case and all our rate cases that we have out there. We are assuming, as we always do in terms of when we initiate guidance, and constructive outcomes, in terms of those rate cases. Now, if there was some deviation from that, that could be a factor. But there's other things, too: O&M variation, sales, the whole list of things that could occur.

Teresa said it, but I also just think we didn't achieve what we started out to achieve this year with the Minnesota rate case. I think everybody knows that. As both myself and Teresa have talked about, we had the fortunate uptick for weather. That mitigated a lot of it.

We had some management initiatives that mitigated the rest of it, positioning us very well for this year. Of course, you can't count on weather next year. While I think we are as best positioned as we possibly can be for this 2014 case, it's certainly going to be a big driver of our success next year.

Got it. Thanks a lot.

Julien Dumoulin-Smith, UBS.

This is Paul Zimbata from Julien's team. Just a quick question on the Minnesota multi-year rate case. If you could just talk about the decision to file in November with running at the sub-optimal level and without the NRC license? If you think that that will have any kind of implications?

Sub-optimal level? I'm not sure I understand what you're talking about.

Saying that you were --

The Monticello. I'm sorry. I misheard you. I'm sorry, Paul. First of all, the Monticello, we expect -- the shutdown delayed it a bit, but we expect the Monticello license, the first piece of it, to come through in late November, possibly early December, with the approval for the final piece, maybe as early as March, 2014. I don't think that the NRC license will be a significant factor in the rate case. Did we answer your question? Because I apologize for not understanding it initially.

That's okay. Yes, that was it. Thank you very much.

Chris Turnure, JPMorgan.

I have a question in that vein, but more specifically on the Monticello up-rate prudence case. Is the NRC license going to impact the timing of how that progresses? Second there, is there a precedence that we can look to understand how they are going to treat and look at that overrun versus the original estimate?

Let me tick it off and we've got the expert sitting by my side here. First of all, I don't think the NRC timing of that won't impact the prudence proceedings. I also think there is a number of different ways that historically commissions look at prudence review. The traditional way, we've made decisions at various points in the project life, I think we feel pretty comfortable about.

We did have overruns, but if you look around the industry, so did everybody else. These upgrades have turned out to be much more expensive. Finally, despite the increased costs, we certainly would have gone forward with the project at $11 gas, when this project started, and frankly, it still makes sense for our consumers today. I think we're in pretty good shape there.

The key component in our portfolio mix, as we look forward, and we think nuclear adds to this position versus what --

Carbon free. I mean Dave or Scott, I don't know if you want to add anything?

I think you got it.

Okay. The second question is around the mitigation efforts going into the general rate case in November. You gave a little bit of color in the press release today, but I was just wondering if you could talk more about that, flesh it out a little bit and give more color around how the discussions with the intervenors are progressing so far?

I'll start and then you guys can -- in terms of we did, as you know, in the 2013 case, the Commission made an adjustment relative to theoretical reserve and an 8-year amortization, so we are looking at some alternatives around that. That would be a primary one. Then, potentially some, we have some BLE refunds. That would be the second. More to come on that, as we go forward. Do you two want to talk about the stakeholders?

Hi, this is Scott. I would just say that we have been trying to work with folks to get them to understand why we're coming back here in November, make sure they understand the drivers of our costs, and which plants are affecting that, which plant additions. I think that, overall, people are working with us, receptive to the fact that we are looking at a moderation plan, and understanding that our costs are increasing in a period that is peakish and that we will try to smooth that out.

Great. Thanks.

Angie Storozynski, Macquarie.

First of all, I wanted to actually thank you for finally giving us a sense of what has been new long term growth rate for earnings, because with your comment in the past that there would be a deceleration in earnings growth past 2014, we were kind of scrambling. Is it 2%? Is it 3%? So, I think that provides a lot of clarity, the 4% to 6%.

Now, on the, again, the Minnesota rate case, the multi-year aspect of it, how should we think about it? I mean did you hear from intervenors that they would be receptive to a multi-year rate case? Also given the less than satisfying outcome of the last rate case, should we expect that if this rate case doesn't go well, there is going to be another one filed just after the current one? Are we basically -- is the strategy to basically to file rate cases until you get what is required to have a profitable business in Minnesota?

Let me take a stab at this. We're working with stakeholders now because we don't want to be in that continual rate case loop; neither does the commission, the staff or our customers. That said, I don't think anybody thinks that the capital we're spending and the expenses we're incurring aren't for good use. It's pretty much evident in what we were able to accomplish here over the summer. We had half of our customers out.

So, we are making the right investment decisions. I think a multi-year plan, and Scott alluded to it, helps moderate rates today, recognizing that the pace of rate increases modulate significantly the further out in time you go. Our plan is to be successful in this case, and to replicate what I think has been a pretty good model and I think it has been pretty successful in Colorado for all stakeholders: shareholders alike and customers alike. It's not our plan to file rate cases continuously.

Maybe, Ben, I would just add to that, in terms of the stakeholder input that we receive. They were actually suggesting the two-year case. Clearly, we are having, I would say, positive dialogue and we have taken some of their input and that's in part why we're filing two-year case instead of potentially what was allowed, the three-year case.

Essentially, to Teresa's point, it is a five year look-see. I think everybody is open to what we're trying to accomplish. I also think, too, we've got some, I think, very good programs to continue to be more efficient. We recognize that is what we need to do.

Teresa mentioned, we will see our pace of O&M and certainly out by pension, but it is going to be also helped by a lot of productivity improvements through process improvements et cetera, which I'm not talking about deferred maintenance. I'm talking about improved processes. Obviously, it is a big case, but I think, based upon what we've heard to date, we are cautiously optimistic it will go well.

I know that you're not providing any details about the filing, ahead of it, but how big of an impact roughly speaking would it have on electric bills? Would the increase be significantly above the inflation level?

Well, what is inflation today? (laughter)

Yes, well, optimistically, let's assume 2% to 3%. (laughter)

I think you are going to find our rate moderation plans are going to be in that zone of reasonableness that stakeholders would be open to.

Okay. Thank you.

Jonathan Arnold, Deutsche Bank.

A quick one, I appreciate your comments on the gas sales forecast for 2014. You'd said maybe some of the growth had been a bit of an aberration in the weather numbers perhaps. Is negative 2% just giving back some of that noise? Or is that a better handle on what you see as underlying growth?

I would probably go with the former, potentially. It's a little bit hard to say.

So is it -- once you've adjust for maybe what was surprising this year, is your underlying outlook more flattish like for electric?

Yes.

Okay. Then if I might, just on the sales topic, you're obviously talking 0% to 0.5%. Ben, I heard your comments about feeling you've got your arms around the drivers. Let's just say it was 0% to negative 0.5%. Would that be enough to put you outside of your trajectory on 4% to 6%? Or do you think you have enough other things you could do to maintain it in the event that you did see sustained modest shrinkage?

I don't think so, would be my initial reaction.

I would agree. Put us outside of the range? We could --

It would leave you to the bottom of it, but not outside? Is that?

It would be really difficult to give you an answer to that, because there are so many other factors: where it would occur, what our regulatory mechanism where. I think we've got far more flexibility than just a 50 basis point movement in sales significantly altering our long-term growth expectations.

Thank you very much.

Andy Levi, Avon Capital.

We were also happy to see you get the growth rate out there as well, because there was definitely a lot of concern. So, 5% is pretty good.

Just a couple of questions. On the 4% to 6%, what gets you to the high end, what gets you to the low end? Can you go into that? Obviously, you talked a little bit about some flexibility you have as far as sales volumes, and actually the customer class, too. Just any color you can give us on high end versus low end of the growth rate?

Me and Teresa, I will do the easy part and you can do the other part. (laughter) I think clearly on the top end, what we would want to do is see improvement in our earned ROEs. Of course, in this interest rate environment, authorized ROEs, I would say that would be a stretch.

But you've heard us talk before, if we could close the gap between actual earned and authorized, that would be one piece of it; continue to have a capture rate-based growth opportunities, investment opportunities, would be another. We talked just in the last call with Jonathan about sales growth; of course positive sales growth certainly would be supportive. All of those factors go the other way to get you on the low end.

Right. I think you've covered the key items, but are we linking to --?

O&M?

Oh, sure.

Okay. Thank you on that. Just two more questions. I don't know if I'm just reading into this or is it really just 4% to 6%? On the dividend, you mentioned that there are a lot of options that you'd like to discuss with the Board relative to where the payout ratio is. Could you discuss what those options are?

I think you've heard a lot of the callers trying to understand what the pace of that is going to be: if we're going to have a dividend payout ratio target, et cetera. Again, I don't know we can provide any more clarity. We have discussions, as you would guess, with our Board, routinely, around the dividend because we recognize -- as we do with the other value components of our value proposition. It's an important topic. We'll continue to have these discussions.

The good news is we can have those discussions about how we are going to reward shareholders because we do have a modest payout ratio. We are now aligning our dividend growth with EPS growth. I know everybody wants more clarity, but let's just start with that objective. We will give you more clarity on that as time goes on.

What is the timing on getting that clarity? What is typically the Board meeting that you generally have this discussion?

We have an analyst day in December. We typically have made dividend announcements for the last five years, now, at our shareholder's meeting. You're not bound by that, but that would be the guidance I would give you.

Okay. Your payout ratio right now, based on your 2014 guidance, is around 55%, 56%. Why not take the payout ratio up to 60% to 65%, based on your profile?

I'm just going to repeat what we've said. We know we have a payout ratio that is modest. Of course, we've had that for a number of years now. I think it is extremely important, and I am not going to speak for my Board, but it is extremely important that you have a sustainable, predictable dividend. We've provided that for many, many years now. We'll continue to provide that for many years to come.

I think the other thing I would point out, Andy, is if you look at the midpoint of the 2013 guidance range, the payout ratio is probably more like 58%.

I'm just talking more on 2014 and what type of increase we could see in 2014?

If earnings and the dividend are growing at a similar rate, the payout ratio is not going to change.

Right. The last question has to do with the stock and, again, looking at the midpoint of guidance. Also, if you took that 4% to 6% and you took it out to 2015, the stock itself on a valuation basis relative to the regulator group, so pulling out some of the gassy names that traded much higher multiples, was trading at about 6% discount, despite the 5% earnings growth rate and decent dividend growth rate as well. How as a management do you think you close that gap and get back to where you used to actually trade at a premium to the group now trading at a substantial discount?

I hope, one, continue to remind people that we have had a successful track record of delivering shareholder value. Two, on a prospective basis, making sure we continue to deliver shareholder value. Clearly, I think we've had some overhang with the pace and frequency of our regulatory filings. Going to multi years, I think, we will provide more clarity on that.

So, I think that will be helpful. Continuing to work on closing the gap between earned and authorized ROE would be another process and continuing to make progress. The reality is, we have delivered a pretty good track record here. I think we're positioned to continue to do that, and so I think it is a matter of time before people recognize that.

Great. I appreciate it. I'll see you in the land of Mickey in about two weeks. (laughter)

Ashar Khan, Visium.

Congratulations on a nice quarter and for the year.

Thank you.

Can I just ask you, Ben, we go through this in different states, going through that in New York, over year. I was just looking, Minnesota has a gubernatorial election next year. Can this rate case become part of any issue or no? Or are usually the elections have been immune to what is happening?

That is a great question. I just will tell you that everybody here is shaking their heads no. We do not anticipate that the rate case will be a political issue in this election.

Okay. Fair enough. Thank you, sir.

All right. Well thank you for participating in our third-quarter earnings call. We look forward to meeting with many of you at the EEI Financial Conference in a few weeks. In addition, we hope many of you will attend our analyst meeting at the New York Stock Exchange on December 4. We plan to update you on our efforts to spend the O&M costs FERC found, our Minnesota electric rate case, our nuclear construction projects and rate-based opportunities. Until then, Paul Johnson and the IR team are available to take your calls. Thanks a lot.

See you later, everyone.

Thank you, ladies and gentlemen, that does conclude the conference call for today. Thank you for your participation. You may now disconnect.