埃克西爾能源 (XEL) 2012 Q1 法說會逐字稿

Welcome to the Xcel Energy 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, April 26, 2012. I would now like to turn the call over to Paul Johnson, Vice President of Investor Relations and Financial Management. Please go ahead.

Thank you and welcome to Xcel Energy's first quarter 2012 earnings release conference call. With 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 and Group President, Scott Wilensky, Senior Vice President and General Counsel, and George Tyson, Vice President and Treasurer. This morning, we will provide you with an update on recent business developments, discuss results, review our 2012 earnings guidance, highlight our strong corporate governance, and take your questions. As a reminder, there are slides that accompany today's call which are available on our web page. In addition, some of the comments we make will 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. I'll now turn the call over to Ben Fowke.

Thank you and good morning. Today, we reported first quarter earnings of $0.38 per share, compared with $0.42 per share in 2011. I'm sure you were aware that weather was significantly warmer this quarter and that had an adverse impact on our results. However, we've initiated actions to help offset the impact of warmer weather and lower than forecasted electric sales. As a result of our efforts, quarterly O&M expenses came in roughly flat with last year. Looking ahead, we continue to expect 2012 earnings to be in the lower half of our earnings guidance range of $1.75 to $1.85 per share. Teresa will discuss our quarterly results and earnings guidance in greater detail in a few moments.

I'll now provide you with a few updates beginning with the review of our regulatory developments. In Minnesota, we are pleased that the commission approved our rate case settlement at the end of March. The annual rate increases of $58 million in 2011, $15 million in 2012 are based on a 10.37% ROE. The settlement also includes a $30 million reduction through depreciation expense. As part of the settlement in the Minnesota electric case, the settling parties recognized that NSP-Minnesota would file a petition seeking deferred accounting for 2012 property tax expense above the level approved in the rate case. In December, we filed a petition requesting a deferral of incremental 2012 property taxes, which are currently estimated at $24 million. In April, the Department of Commerce recommended that the Commission deny the request. However, a coalition of large industrial customers and the Chamber of Commerce were supportive of our deferred accounting request.

Our earnings guidance reflects the assumption that we are able to defer incremental property taxes in Minnesota. We believe we've met the criteria for deferred accounting treatment. Last week, we filed our response to the Department's concerns, which provide strong support for our request. We expect the Minnesota PUC to rule on this request during the second quarter. In Colorado, we arrived at a comprehensive, multi-year rate settlement agreement with the PUC staff, the Office of Consumer Counsel, and several other intervenors. The agreement reflects a $73 million electric rate increase in 2012, an incremental $16 million increase in 2013, and a $25 million increase in 2014, based on a 10% ROE and a 56% equity ratio. In addition, the settlement enables us to defer incremental property taxes. We believe this is a constructive settlement that provides revenue and regulatory certainty for both our customers and our shareholders while establishing a regulatory framework for a multi-year plan. Hearings were held on Tuesday and the Commission is deliberating on the settlement this morning and may rule later today.

Turning our focus to 2013, in June, we plan to file an electric and natural gas case in Wisconsin. During the second half of the year, we plan to file several cases, including electric cases in Texas, New Mexico, and North Dakota. Finally, we plan to file an electric case in Minnesota where we are anticipating pursuing a multi-year plan. Together these cases will drive earnings in 2013. One final regulatory item. In March, we asked the Minnesota Commission to reaffirm that increasing generating capacity at our Prairie Island nuclear plant is in our customers' best interest. We are seeking a reaffirmation as much has changed since the Commission issued the certificate of need for the Prairie Island uprate in 2009. Key changes since 2009 include a more lengthy approval process at the Nuclear Regulatory Commission, less expected incremental output from the planned uprate, higher project costs, lower natural gas prices, as well as lower demand growth.

When circumstances change significantly after an initial regulatory approval, as with this project, our approach is to step back and take another look before continuing. It's prudent to have this review now rather than after completing the project. This is consistent with our focus on stakeholder alignment. We anticipate the Minnesota PUC will rule on this request later this year or early next. We also continue to make good progress implementing our transmission strategy. Notably, the Minnesota Commission granted the last siting and routing permit needed for the CapEx 2020 lines in Minnesota. The Right of First Refusal Bill was signed into law in Minnesota. We began Phase 2 of the Fargo-St. Cloud line and the construction of the Brookings-Hampton line. And in Texas, we reached the settlement for the route of the Tuco-Woodward line. Clearly our transmission projects remain on track.

Next, I'd like to provide you a brief environmental update. During the last year, EPA continued today pursue it's regulatory agenda, which significantly raises the bar for environmental compliance. In most cases, our proactive environmental strategy has dramatically reduced our cost of compliance with EPA's new mandates. For example, in late 2011, EPA finalized its Mercury and Air Toxic Standards Rule. While we'll have to make some emission control investments under this Rule, our cost of compliance is lower than the rest of the industry, primarily because the actions we implemented over the last decade. EPA also proposed to approve a regional haze plan for Colorado this year. That plan incorporates our clean air clean jobs emission reduction program, a plan which mitigates the cost of EPA regulation for our customers.

As a result of our proactive environmental actions, Xcel Energy is well positioned to meet various environmental challenges over the next decade. We believe our customers and shareholders have benefited from these actions. The biggest environmental challenge we are currently facing is EPA's Casper Rule. Because of the short compliance window, Casper was unusual in that it had a significant impact on Xcel Energy and our customers. As a result, we joined other utilities in several states in challenging the rule and seeking its stay. Late last year, the Court of Appeals stayed the rule, while it continued to consider the merits of our challenge. Last month, the Court listened to arguments over the legality of the rule. We expect a ruling sometime this summer and remain optimistic that this litigation will result in better environmental regulation. Clearly, public policy will continue to impact our capital spend. Our five-year capital forecast includes approximately $470 million for Casper compliance and $300 million for the Prairie Island uprates.

So changes in timing or compliance with Casper, as well as the Minnesota Commission's decision on the uprates at Prairie Island, could potentially reduce our capital forecast. If these projects are modified or canceled, we still project strong rate-based growth over the next five years. In addition, a reduction in our capital forecast would reduce our financing requirement and provide us with increased flexibility. One final comment before I turn the call over to Teresa. The continued low price of natural gas is a hot topic for our industry. With fuel clauses or recovery mechanisms in all of our states, low natural gas prices are very beneficial for our customers and for Xcel Energy. This is especially true as we make investments to modernize our system. Our customers see lower bills and a lower share of their income is spent on energy consumption while we make investments in our system to provide our customers with long-term value. Our mission is to provide our customers with clean, safe, reliable energy at a competitive price. Lower fuel prices certainly help us achieve that mission. I'll turn it over to Teresa.

Thanks, Ben, and good morning. Today I will discuss first quarter results 2012 earnings guidance and a shareholder proposal included in this year's proxy. Let's begin by reviewing our first quarter results at each of our four operating companies. As Ben indicated, warm weather throughout our service territory negatively impacted our first quarter results, most notably in Minnesota, which experienced the warmest March in over 100 years. For the quarter, earnings at PSCo decreased by $0.01 per share due to lower sales as a result of the warmer weather, decreased wholesale revenue due to the expiration of the Black Hills contract, higher depreciation and interest expense, partially offset by higher gas revenues resulting from new rates that were effective in September 2011.

At NSP-Minnesota, earnings decreased by $0.03 per share due to weather, final rates which were lower than interim rates last year, higher property taxes, and higher O&M expenses. These negative drivers were partially offset by a lower effective tax rate, which I will discuss in a few moments. Earnings at NSP-Wisconsin and SPS were both flat for the quarter. Quarterly results at both companies were positively impacted by new rates effective in January 2012, offset primarily by the negative impact of weather. Let's take a closer look at the drivers of the affected various line items in the income statement, beginning with retail electric margin. Our first quarter electric margin decreased by $25 million. Primary drivers of the reduced margin were $22 million from the estimated impact of weather and $11 million from lower firm wholesale revenue, largely driven by the expiration of the Black Hills contract. These negative items were partially offset by higher transmission revenue, retail rate increases in several states, and other smaller items.

Weather normalized retail electric sales grew 0.3% and had a negligible impact on electric margins. However, this modest increase included the benefit of an extra day of sales due to leap year. Without the extra day, first quarter electric sales declined 0.8 of 1%. You might recall that our fourth quarter sales were also slightly negative. This is a disappointing trend and as a result we now expect our weather-adjusted annual sales growth to be flat for 2012. Natural gas margins decreased by $19 million in the first quarter, primarily due to warm winter weather which reduced margin by $21 million. Turning to expenses, first quarter O&M expenses were essentially flat for the quarter. In January, we began a comprehensive review of our O&M expenses with a goal of not compromising reliability or customer service.

We were able to implement several initiatives, such as deferring merit increases for non-bargaining employees, reducing incentive comp accruals, postponing new hires, cutting training and other items to offset the impact of lower than forecasted sales, and warm weather. As a result of these actions, we now expect O&M expenses to increase between 0% and 1% for the year. Previously, our guidance reflected an annual O&M increase of 3% to 4%. Other taxes increased approximately $9.1 million or 9.4%, largely due to increased property taxes in Minnesota. As Ben discussed, we've requested deferral of incremental property taxes in Minnesota for 2012. However, we'll continue to expense the incremental property taxes until the Minnesota Commission rules on this issue. If our request is approved, we would retroactively defer these incremental property taxes to the beginning of the year.

You may have noticed we had an effective tax rate of 29% for the quarter. The effective tax rate was primarily due to the recent completion of a tax planning analysis regarding the eligibility of certain expenses that qualified for an extended carry back. As a result of the differential between a higher tax rate in prior years and the current tax rate, we recorded a tax benefit of approximately $15 million in the first quarter. As a result of this tax benefit, we've adjusted our projected effective tax rate for 2012 to a range of 34% to 35%. This has been a challenging year with very warm winter weather and declining normalized sales. However, we've taken steps to at least partially offset these impacts by managing O&M expenses and implementing a tax planning strategy. Clearly, we still have a lot of work to do. With our management action, normal weather the rest of the year, and assumed constructive outcomes in our regulatory proceedings, including Commission approval of our settlement agreement in Colorado and our deferred property tax request in Minnesota, we continue to expect to deliver earnings in the lower half of our guidance range of $1.75 to $1.85 per share.

Before we open up the call for your questions, I'd like to draw your attention briefly to this year's proxy statement, which includes a shareholder proposal for Xcel Energy to adopt a policy where the Chairman of the Company would be an independent director. Our Board of Directors recommends a vote against this proposal. Xcel Energy has demonstrated sound corporate governance principles for many years, including annual election of directors, 10 independent, non-employee directors among its 11 members, an annual election of a lead, independent director, board committees composed entirely of independent directors, and committee chairs review and approve agendas for committee meetings.

These practices have served our shareholders well. Xcel Energy has consistently delivered on its operational and financial objectives. This strong track record is reflected in a cumulative total return to shareholders that exceeded our peer group of the EEI investor-owned electrics, and the S&P 500 index for the five-year period ended December 2011. The Board believes that it is in the best position to evaluate the current and future needs of the Company and to judge how the capabilities of the Company's directors and executives can collectively be most effective in meeting those needs. The Board believes that maintaining flexibility to decide the appropriate leadership structure of the Board is consistent with effective governance, best serving the shareholders' interests and that this proposal would deprive the Board of its ability to govern the Company in the manner it deems most effective. We request that you consider these factors as you vote your proxy in the coming weeks. For more details, I urge you to review the Board's response to this shareholder proposal and our proxy statement. If you have any questions or comments regarding the content of this year's proxy, please contact our IR team. That concludes my prepared remarks. Operator, we will now take questions.

Thank you. (Operator Instructions) Travis Miller, Morning Star.

Thanks, good morning.

Hey, Travis.

Morning.

I want to go to Minnesota here for a little bit. The -- if you get that property tax deferral there, do you think you can earn the allowed return that's 10.37% in 2012 and corollary there, is that embedded in your guidance, weather-normalized?

Well, the deferral of the property taxes is embedded in our guidance and the reality is, Travis, even with the accounting order for the deferral of property taxes, we won't earn the allowed return of 10.37%. I think we anticipate NSP-Minnesota would probably be in the low 9s%.

What's the biggest thing driving that? The capital side or the operating cost side?

Well, I mean it's -- the erosion of sales that we've seen in Minnesota, which has been probably the most pronounced in all of our jurisdictions. You know, this is really the -- essentially the second year of staying out of a rate case and so there's a number of factors like that have pushed that down.

You know, Ben, I would just add to that the greatest impact of our weather is in the Minnesota company, so --

And then third on that, what risks do you see if you file in November? Do you expect, based on the negotiations from the previous year, so the risks I'm thinking of are an ROE cut potentially from even that 10, 3, 7, disallowance of some kind of operating cost, disallowance of potential capital costs. What are the key risks based on settlement negotiations, et cetera, from the previous case that could go into the November 12 case? Well, I mean, I think the issues that you raised are always the issues whenever you file a rate case. I mean, so I would probably say that, you know, the ROE, we would always have to -- you know, that's one of the key things we defend. Capital, Travis, tends to be a much easier sell particularly because it's pretty easy to see the value that we're doing. This is a year again, I didn't talk about it on the call, but we're starting the year off very strongly and with reliability and all the operating indicators that are so important to our customers and it's really a reflection of the money we've been putting into our system.

So at the end of the day, you know, I mean, it's litigated, I have intervenors that see it another way, but I think at the end of the day we've got a track record that demonstrates that, you know, we get constructive outcomes and I think one of the advantages of going to a multi-year plan, like we did in Colorado, is we get that regulatory certainty and we get a little pause. I mean, you know, I think -- you know, we've recognized that when you modernize an infrastructure, you file a lot of rate cases. So, I think it would be nice to get a multi-year plan or something close to it and kind of get our marching orders and move on with it.

Okay. Great. Thanks so much.

Ali Agha, SunTrust.

Thank you, good morning.

Hey, Ali.

Hey, how are you?

Hi, Ali.

Good morning, Teresa. Ben, if you look at Colorado and as you [mean] you do get the settlement approved, at least in Colorado, should we assume that that gives you the tools to earn your authorized returns or are there still going to be lags there as well?

Well, Ali, there still will be some lag. I mean, you know -- but I think we'll close it a bit and I think we have a little more control of our destiny and, you know, I mean -- Ali, we didn't get everything we wanted, you know. That's kind of the way it goes when you do a settled agreement, but I think we made a lot of progress. We set the precedent going forward for multi-year plans and I think if we manage expenses and capital and our business well, that we can help eliminate some of that lag that's plagued us in Colorado, but we won't -- we won't cut it out completely, by any stretch.

Okay. And, I mean, along those lines, if you look at your two biggest jurisdictions, Minnesota and Colorado, you know, you're looking at multi-year plans, you get interim rate increases, you got that in Minnesota as well. You know, from a logistic point of view, is that a particular functional change that is still required in both of those jurisdictions to be able to earn an authorized ROE? What needs to -- in broad terms, what big item needs to change for you to eliminate the lags in Minnesota and Colorado?

Well, I mean, it would help if sales bounced back. I mean, that would be one thing that helps in between rate cases. You know, Ali, you know, it's some of the expenses that we've had, you know, the pension amortization, which hopefully starts to level off, I think, in 2013 and beyond. That will help. And, you know, I mean, as we start to -- as our capital forecast starts to flatten out, albeit at a relatively higher amount than we've seen historically, I think that will be helpful, too, and, I don't know, Teresa, if you want to add anything to it.

I think you've covered the major items.

Okay. And last question, looking more near term, the --

Ali, can I just -- never mind. Never mind. I was going to add something, but I'll take it back. Go ahead.

Okay. I was just going to say, you know, near term when you look at the trends that you reported in the first quarter, including the tax benefit, was that sort of plugged in to your, you know, budget for the year? In other words, was Q1 pretty much on track? Because if you took the tax benefit out, you know, that's about a $0.03 swing right there. So just wondering, was that a positive offset to some other slowdown or how should we be thinking about that in the context of your own budget?

Well, I guess I'll let -- let me start in and I'll have Teresa add. I mean, the planning -- we knew we were planning around this tax benefit. The question was going to be what quarter we take it in, which is, you know, why we don't do quarterly guidance. So, you know, it was always in our guidance range of the $1.75 to $1.85 and we -- you know, we knew we had that when we talked about it. So as far as the timing of it, I think that's a function of when the planning was completed and some things like that. Teresa, I don't know if you want to add anything to it.

I mean -- you're exactly right, Ben. We had assumed a certain level in terms of the tax planning strategy. We actually completed the work at the end of the first quarter. Obviously, we consulted with our auditors about just our methodology, the approach, and the amount, and including the timing and, in fact, you know, we determined it was the most appropriate to recognize it in the first quarter. So again, the short answer is, yes, we had assumed a level in our guidance and the quarterly estimates, there was some variability in that. So --

But to be clear, you call out that, you know, you're budgeting at 34% to 35% effective tax rate for the year. Remind me, was that not the original plan or is it down from what your original plan was for the tax rate for the year?

It's down -- it was 34% to 36% originally and we just narrowed it to 34% to 35%.

Keep in mind, Ali, we expected that this would possibly come in, but we weren't necessarily sure on the timing and the ultimate magnitude of it.

Got it. Got it. Thank you.

Anthony Crowdell, Jefferies.

Good morning. Some questions mainly related to Minnesota and I guess the regulatory environment. You guys planned to file, I guess, later this year a rate case and when you see how sales and also weather had impacted you guys, is there a potential for -- I don't know even if it's allowed, for like revenue decoupling or something like that in Minnesota? And the second question is what type of premium does the regulators in Minnesota historically have given for a multi-year rate plan?

There's not -- I don't think there's ever been a multi-year rate plan in Minnesota, so this would be, you know, groundbreaking. And what was your -- what was the first part of your question, I'm sorry?

The first question was if there's any ability to get some revenue decoupling or somehow you guys -- you're so impacted by either weather or just flat sales, if there's some way that you could be made whole for stuff like that?

I mean, that's always something that -- that's a conversation that potentially we could have, but there's a lot of trade-offs with that and then here's a lot of devil in the details with those sorts of things. So I think we need to continue to evaluate that and, you know, there's other ways that I think accomplish something close to that, too, that maybe aren't as dramatic. So we'll keep looking at all of those options.

And Anthony, just a point, too. While we haven't implemented a multi-year rate plan in Minnesota, we have done step increases, which is essentially a two-year rate increase. We've done that both in Minnesota, North Dakota, and Texas in the last year, so that's progress toward that multi-year plan.

It just seems that with flat sales or declining sales, it -- and I know you're getting these step-up increases, but it's tough to have a stay out of longer than a year maybe two just because you're -- there's really no incentive, whereas if they gave you, say, a premium return or some type of premium, like a 50 basis point premium, maybe there's an incentive to book something longer than a year, but with these sales, it just seems that you're going to always under earn. Is that a right rate of this situation or no?

Well, it depends how big the step increases are and what sales forecast is embedded on that and what kind of, you know, exits you have. I mean, we do have, for example, in Colorado some, you know, exit ramps, albeit, you know, they're not without their pain, but that's the benefit, I think, you know, that's the trade off and along with it goes the benefits of multi-year plans. So hopefully you get your three-year plan right and you've got some true-up mechanisms and other things that -- for things that maybe are outside of your control.

Maybe just so add to that in terms of the Minnesota sales, the compression we've seen has really just been in the last two quarters and is two quarters a trend? Potentially, but we're continuing to watch that. So it may be a little bit early for that large of a jump. So as Ben said, that's why we're looking at alternatives.

Great. Thank you.

Dan Jenkins, State of Wisconsin Investment Board.

Hi. Good morning.

Hey, Dan.

Yes, I have some questions related around the regulatory issues and rate cases as well. First on Minnesota, you know, you mentioned part of the impact in the first quarter was due to the approved rates being lower than the interim rates a year ago and I was wondering how do you, I guess, flow through that over recovery? Will that be over 12 months or how is that done just mechanically and how long -- you know, and how long should we expect that impact, the year-over-year in comparison?

Well, when we were collecting early on the interim rates, we set up the revenues subject to refund and in essence those are -- you know, we've had all the true-ups relative to the income statement, so they were not being given back to the customer, so -- so we will not see any more income statement impact from the revenue subject to refund.

It's really, Dan, just the timing of the quarter. First quarter this year to first quarter last year. Because in first quarter of 2011, we were recording at the higher end of rates level. Subsequent to that, as Teresa mentioned, we made adjustments to recognize that.

And really why we were recording, we were recording at the ROE of 10.88% and the big driver down was 10.37%, so --

Okay. Do you -- I notice that you also had a similar outcome in North Dakota. Will that have any impact?

No.

Okay. And then I just wanted to verify, I think you said that you expect later this year you're going to file electric cases. Did you say Texas, New Mexico, and Minnesota? Were those the ones you said?

Correct.

Yes.

What about a gas case in Minnesota? What was your ROE there, you know, especially given the weak weather-related sales and what's your plan for gas rates in Minnesota?

Dan, are you -- are you talking about our regulated 2011 return for our gas utility?

Right.

We don't file that until next week with the regulators.

Okay. Do you -- do you, you didn't mention anything about gas. Do you have any plans at all that you might be filing?

Well, we'll have to -- we're going to -- you know, we'll evaluate our gas business. I mean, keep in mind, Dan, that you really don't -- you know, if you have warm, mild winter weather, it doesn't impact your revenue requirements when you file a rate case because it's normalized.

Right.

So you're absolutely right that, you know, our gas operations will be under-earning more than we anticipated because of the weather but there's a number of other factors we have to consider before we file a rate case.

Okay. And then I was a little curious in your write-up about the rate case in South Dakota. You mentioned that the staff actually lowered the cost of debt, which is usually, you know, an embedded cost. What was -- was there a new issue or something that wasn't incorporated that they included that would cause them to lower the cost of debt?

You know, Dan, I think you stumped the team. I suspect it has to do with capitalization of short-term and long-term and some other, you know, capital ratios, but we'll probably have to take that offline and get back to you.

Okay. And then I was curious, you know, once you take out the effect of the leap day, the commercial and industrial sales were down almost 1%, weather normalized. I was wondering if you could give a little more color on what you're seeing, you know, since those sales typically aren't as impacted by weather and what -- you know, what's going on with your business customers?

Well, in terms of -- I would say for our large industrial customers in Minnesota, you know, one of our large industrial customers is a paper mill and they've discontinued a line of paper, they've closed the facility, so you're right, they're not impacted by weather. We're just seeing some in their business. Business plans change. In Colorado, our big customers are pretty much just moderating as they -- as they have been. We're not seeing big increases, but we're not seeing decreases either.

The biggest decreases are in the small C&I and the residential and that's really across almost all of our jurisdictions. It's most pronounced here in Minnesota. You know, it is a bit perplexing, Dan, because, I mean, if you look at the unemployment rates, job growth, et cetera, I mean, we typically, in all of our jurisdictions, but we typically do a bit better than the national average. So, you know, I mean, it could be a number of factors that we're trying to analyze that are causing this trend. One of which might be more shadow -- shadow effect of our own demand and conservation programs which we know probably, you know, take off about 0.8 of 1% of sales. Now, we're compensated for that, but maybe there's more of an impact than even we realize. I think the economy continues to impact customer behavior and then we're also looking at things like are we starting to see appliances get refreshed and, you know, maybe, you know, seeing some efficiencies there that perhaps we don't have our -- a full handle on. So those are a lot of things that we're looking at right now.

Okay. And then the last one I had was just related to you mentioned at PS Colorado the impact from losing the -- the expiration of that wholesale contract with Black Hills. Is that going to be a continuing year-over-year negative, you know, for the rest of this year? Or when did that contract expire?

The contract expired at the end of the year, but what we're -- what we need is a shift from a cost recovery from wholesale to retail customers and that is then incorporated in our Colorado settlement. So assuming we get new rates the first of March, then that will cover that.

Okay.

That's first of May.

Excuse me, May. Sorry.

Oh, that reminded me, so you mentioned that, you know, that you had the comprehensive settlement with multi parties there. Are there -- what parties are not part of that settlement? Or are there any, you know, disputed issues that --

In Colorado?

Right.

You know, you -- all the major intervenors signed off on it, Dan. You always get a few outliers that won't, but again, we expect to have a decision out of the Commission today. Potentially it already happened, but -- so it all should be -- we should have full clarity on that very shortly.

Okay. Well, thank you.

Thank you.

(Operator Instructions) Timothy Yee, KeyBanc.

Good morning. Just to be clear on the Minnesota property tax proposal, relative to your guidance, do you think you would still have additional room to find offsets if the deferred property tax in Minnesota is not granted?

Well, I mean, as I -- we said in the call, I mean, I think in the absence of the Commission not giving that, $24 million is a pretty big hit to overcome, so I don't think we could get it without sacrificing things that we won't sacrifice as far as, you know, maintenance of the system. So it would be tough. Now, that said, there's always backup plans. We could ask for reconsideration or we could consider filing our planned rate case in Minnesota early. I mean, those aren't the preferred routes, obviously.

Okay. Fair enough. And just one other question regarding the updated earning guidance assumptions. Were there any changes to your CapEx this year, kind of driving the lower depreciation expense and the lower AFUDC equity or is that kind of more a function of the expected regulatory outcome?

We haven't had any changes yet in terms of our CapEx this year. While it's a very small increase, remember in the Minnesota case we agreed to a $30 million annual reduction in our depreciation expense, so that's -- we're seeing that reflected in this period, the first quarter's expense.

It also reflects updates in in-service dates and timing and things like that that impact those lines.

Okay. Great. Thank you.

Thank you. There are no further questions in queue. I would like to turn the call back over to Teresa for closing remarks.

I want to thank you all for participating in our first quarter earnings call this morning and if you have any follow-up questions, Paul Johnson and our IR team are available to take your calls. Thanks a lot.

Thank you.

Thank you, ladies and gentlemen, that does conclude our conference for today. We'd like to thank you for your participation and you may now disconnect.