Ben Fowke - Chief Financial Officer Paul Johnson - Managing Director, Investor Relations

Greg Gordon - Citi Investment Research Dan Jenkins - State of Wisconsin Investment Paul Ridzon - KeyBanc Daniele Seitz - Dudak Research Group Ishar Khan [Ph] - INCO Sara Ingram - Wachovia

Good morning ladies and gentlemen. Thank you for standing by. Welcome to the first quarter 2009 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) I would now like to turn the conference over to Mr. Paul Johnson. Please go ahead, sir.

Thank you and welcome to Xcel Energy’s first quarter 2009 earnings release conference call. I am Paul Johnson, Managing Director of Investor Relations and Assistant Treasurer. With me today is Ben Fowke, Executive Vice President and Chief Financial Officer of Xcel Energy, and several others who can help answer your questions. Today we plan to cover our first quarter results and provide a business update. In addition, we are reaffirming our 2009 earnings guidance. Please note that there are slides that accompany the conference call which are available on our web page. Let me remind you that some of the comments 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. You will notice that today’s press release refers to both GAAP and ongoing earnings. Since there was no material difference between GAAP and ongoing earnings, we will refer to GAAP earnings during today’s presentation. With that, I will turn the call over to Ben Fowke.

Thanks Paul and welcome everyone. We are pleased to report first quarter 2009 earnings were $174 million, or $0.38 per share, compared to $153 million or $0.35 per share in 2008. I will start with a quick review of the quarterly results of our subsidiaries. First quarter earnings at PSCo declined by $0.05 per share, largely due to the declining sales growth, unfavorable temperatures, and rising costs. As many of you know, we have reached a settlement in our electric rate case in Colorado, which is pending commission approval and rates are expected to go into effect in July. In Minnesota, we also have a pending rate increase; however, interim rates which are subject to refund went into effect in January. These interim rates provided incremental revenue and cost recovery. As a result, earnings increased $0.02 per share for the quarter. At SPS, earnings increased by $0.03 per share for the quarter. We are seeing improved financial results due to initiatives to resolve fuel cost allocation issues and regulatory lag, and while we aren’t earning our authorized return at SPS, we have taken a step in the right direction. At NSP, Wisconsin, earnings increased by $0.01 per share, due to improved fuel recovery. Finally, our investment in WYCO, which owns a new gas pipeline in Colorado that began operating in late 2008, contributed earnings of $0.01 per share. Next, I thought it would be helpful to discuss a handful of the key drivers and events that influenced the consolidated quarterly results and may affect the rest of the year. First, our quarterly O&M expenses increased at a lower rate than our projected annual rate, due to management actions and the timing of cost recognition in 2008. Second, our weather adjusted sales growth was negative for the quarter and below our expectations. While this didn’t have a significant impact on the quarter, it is a trend we will need to monitor very closely. Third, we continue to see constructive regulation in our jurisdictions, as evidenced by the rate case settlements we recently reached in Texas and Colorado, and in an agreement in principle in New Mexico. In addition, the Minnesota Commission granted a certificate of need for our CapEx 2020 transmission project. Minnesota Office of Energy Security also issued testimony in our rate case, and while we don’t agree with all aspects of their testimony, the recommendations were generally balanced and constructive. Fourth, as a result of our strong balance sheet and constructive regulation, we continue to make significant capital investments in our utilities, which will provide long-term value and benefits to both customers and shareholders. Finally, our business plan remains on track and we are reaffirming our 2009 earnings guidance of $1.45 to $1.55 per share. With that overview, let’s take a closer look at our consolidated results. First quarter 2009 earnings increased by $0.03 per share, compared to last year. This was primarily due to higher electric margins, which increased earnings by $0.11 per share. Offsetting the positive impact of electric margins were several items, including lower natural gas margins, which reduced earnings by $0.02 per share, higher O&M expenses which reduced earnings by $0.02 per share, dilution from our September equity issuance, DRIP and benefit plans, which reduced earnings by $0.02 per share, and other items which combined to reduce earnings by a total of $0.02 per share. One of the cornerstones of our strategy is constructive regulation, which was a key factor in electric margins increasing by $77 million in the quarter. Electric rate increases in Wisconsin and New Mexico and interim rates in Texas and Minnesota combined to increase electric margin by $45 million. Riders associated with MERP, transmission, renewable energy and conservation, combined to increase the electric margin by a total of $32 million. For the past several years, we’ve incurred cost disallowances and recorded accruals related to fuel cost allocation issues which have depressed returns at SPS. As a result of various regulatory initiatives and settlements, we’ve largely resolved these issues and are starting to see financial improvement. One area where that is clearly apparent is lower regulatory accruals at SPS, which increased electric margin by $12 million. Finally in 2008, we made filings to improve fuel cost recovery in Wisconsin which increased margin by $9 million. Partially offsetting these positive factors were higher purchase capacity costs, which reduced margins by $18 million, and warmer temperatures, resulting in lower electric sales which reduced margins by $6 million. We also experienced negative weather adjusted electric sales growth, which reduced margins by $2 million. The decline in sales growth was most pronounced in the commercial and industrial class; however, because our large customers pay a demand fee, the impact of declining sales was mitigated to a certain degree. Unfortunately, we didn’t experience the same positive margin trends on the natural gas side of our business, where margins declined by $14 million for the quarter. This was largely due to warmer weather, which reduced gas margins by $10 million and declining sales and other items that combined to reduce natural gas margins by an additional $4 million. Turning to expenses; first quarter O&M expenses increased by $11 million or 2.4%, largely due to higher employee benefit expenses related to increased pension and medical costs. The O&M increase for the first quarter was lower than the projected annual trend for two reasons management’s actions to reduce costs, and O&M timing in 2008. As part of our effort to reduce costs, we have deferred the annual merit increase for non-bargaining employees, and have taken steps to reduce consulting and employee costs. These cost reductions are reflected in our annual O&M guidance and will not affect customer service or reliability. As you develop your quarterly models, you should be aware of a couple of items that affected the timing of our 2008 O&M costs. First of all, in the third quarter of 2008, we reduced our incentive compensation accruals based on expected year end results. This resulted in a year-to-date true-up of previously accrued incentive expenses. Second, and also in the third quarter of 2008, the Minnesota commission approved our deferral and amortization accounting recommendation for nuclear refueling outages effective January 2008. This decision also resulted in a year-to-date true-up of previously accrued O&M expenses. As a result, O&M expenses were higher in the first half of 2008 and lower in the second half of the year, so O&M comparisons will tend to be more unfavorable in the second half of this year. That explains the significant quarterly deviations. Now I’d like to discuss current sales trends and our forecasts for the remainder of the year. Six months ago, we had forecasted our 2009 sales would be roughly flat due to the recession. On a consolidated basis, first quarter weather normalized sales decreased 1.2%. We saw declines in both our residential and commercial and industrial classes. The decline was more pronounced in the C&I class, as weather normalized sales fell 1.4% for the quarter. As a result, we’ve reduced our 2009 retail electric sales forecast to reflect a decline of approximately 1%. Since the economy is on everyone’s minds these days, I will review with you the economic health of the jurisdictions we operate in. One factor that works in our favor is the diversity of industries throughout our service territory. For example, our 10 largest customers operate in seven different industries, and only generate about 9% of our total electric retail sales. In addition, unemployment in our jurisdictions was 7.7% at the end of March, which was below the national average of 9%. This trend existed at each of our service territories, where unemployment was 7.9% at NSP, 7.8% at PSCo, and only 4.5% at SPS. Finally, our regions fared better with respect to mortgage foreclosures. According to realty track, the foreclosure rate through March remains below the national average in each of our service territories. While we aren’t immune to the effects of recession, our service territories are diverse and are doing better than the nation as a whole. I’d now like to comment on recent developments on the regulatory front. In November 2008, we filed a request to increase electric rates in Minnesota by $156 million or a little over 6%. Interim rates of $132 million went into effect at the beginning of January. Earlier this month, interveners submitted testimony. The Office of Energy Security recommended a revenue increase of $72 million, based on an ROE of 10.88% and an equity ratio of 52.5%. They also recommended a 10-year life extension of the Prairie Island facility, which results in a $40 million decrease in depreciation and decommissioning. While this adjustment would not affect net income, it would affect cash flow. They are either scheduled for June and a decision is expected in October. Last November, PSCo filed an electric rate case in Colorado. In March, we filed rebuttal testimony, seeking a rate increase of $159 million. Included in our request was approximately $40 million of return on CWIP for Comanche 3. We recently reached a settlement agreement with most of the interveners, which provides for $112 million rate increase, based on a black box settlement. The key difference from our request is that we removed the return on CWIP and instead will continue to record AFDC until Comanche 3 goes into service. While it is based on a series of compromises, we are pleased with the settlement, as it provides us with regulatory certainty and the opportunity to earn a reasonable return in 2009 while we make significant investments in Colorado. The settlement is pending commission approval, and a decision is expected this summer. Finally, rates are projected to go into effect on July 1. We’re also making progress at SPS. In January, we reached a unanimous settlement, which provided an electric rate increase of $57 million in Texas. Interim rates subject to refund went into effect in February. We achieved a settlement in just over seven months, which significantly reduced the lag that would have incurred from litigation. The settlement is pending commission approval, and we expect commission approval later this spring. Last December, SPS filed to increase electric rates by about $25 million or 6% in New Mexico. In addition, we requested interim rate relief of $7.6 million for capacity cost, associated with the Lea Power Partners project. The New Mexico commission approved an interim rate increase of $5.7 million, effective in May. In April, we reached an agreement and principle on some of the key issues in our New Mexico electric rate case. We will discuss the details of the settlement when it is finalized towards the end of May. As you can see, we are making progress at SPS. The proposed rate increase in Texas and the settlement in our New Mexico electric rate case, should allow SPS to earn an ROE closer to 8% in 2009. While we aren’t earning our allowed ROE, it is roughly double what SPS has earned in recent years. In other regulatory news, the Minnesota commission granted the utilities participating in CapEx 2020, a certificate of need to construct three 345 KV transmission lines. The commission also approved provisions to up size the transmission lines to double circuits. The decision illustrates Minnesota’s support for upgrading the region’s transmission system to meet customer demand and to increase access to new resources, including renewable energy in Minnesota, North Dakota, and South Dakota. Applications for route permits are currently under state review or in development and decisions are expected in 2010. Similar regulatory approvals will be pursued in Wisconsin, North Dakota and South Dakota. Permits in those states will be filed in 2009, with decisions expected in 2010. Federal permit applications will also be filed in 2009. We are obviously quite busy on the regulatory front; however, I think you will agree that despite a challenging environment, we are seeing evidence of constructive regulation in connection with our major electric rate cases. In summary, with a solid first quarter and good progress on our regulatory initiatives, we remain on track to achieve our objectives and we are reaffirming our annual guidance range of $1.45 to $1.55 per share. So with that, let’s open it up for questions.

(Operator instructions) And our first question comes from the line of Greg Gordon with Citi Investment Research; please go ahead. Greg Gordon - Citi Investment Research: Thanks. Good morning Ben.

Good morning to you. Greg Gordon - Citi Investment Research: So cutting to the chase and going to note six of the press release and just comparing it to note six from the fourth quarter year end call, there’s changes in five line items, you are now assuming weather adjusted electric sales down 1% versus flat. You talked about that in the comments. A $20 million of improvement in your O&M picture, and then you’re also assuming D&A will be $20 million lower; AFUDC will be low or flat versus down and; I’m assuming that’s because of the rate treatment in Colorado?

On the AFUDC? Greg Gordon - Citi Investment Research: Yes.

Yes, it’s really a function Greg, of just adjusting for the actual expenditures and when things come in service, more budgeting true-up than anything else. Greg Gordon - Citi Investment Research: Okay, so the D&A and AFUDC, that’s just as we move through time, you’ve got a better read on it and it’s not a cause on the effect thing with the Colorado decision?

Precisely. I think depreciation by the way, we have going down $30 million Greg. Greg Gordon - Citi Investment Research: Interest expense, you have down $5 million, I’m presuming we heard this across the board from other companies on earnings calls over the last two days, that just your short term debt expenses and financing costs are projected to be lower.

Yes, that’s right. I think we saw significant improvement in working capital in the quarter, almost $300 million of improved working capital. So you also obviously need less short term debt to carry that, plus the forecasts for the inherent interest rate is lower than it actually has turned out to be. Greg Gordon - Citi Investment Research: Okay great. So unless the economic climate were to decelerate further, you’ve been able to compensate so far for everything you’ve seen.

That’s correct. Greg Gordon - Citi Investment Research: Thank you.

Thank you, Greg.

Thank you. Our next question comes from the line of (Inaudible) with CVP US [ph]; please go ahead.

Hi Abala.

Hi, good morning, Ben. One thing I want to make sure of; I think in your analyst meeting here in New York, back in December, we talked about the capital program and if I remember the numbers properly, they basically had been brought down to an approximate level of about $1.8 billion on average, over the next few years, which is expected to be roughly in line with internal resources. Can you just review sources and uses right now, the way you are thinking about things?

Yes Abala, the 1.8 was related to this year. When we look at the out years, 2010 and 2011, it’s more like $2.3 billion. I think we probably talked about it at that analyst meeting that we will continue to review our capital forecasts and our capital expenditures and adjust them where it makes sense to adjust them with economic conditions, but our forecast in the out years is a bit higher than what you have.

And based on what you are seeing right now, as I recall, most of your capital program is not very lumpy in terms of items. There is a composition of many different items. So in terms of being able to adjust that down, do you anticipate at this point that a modest revision downward for the capital program is probable given the economic outlook, etc or do you feel like that it can be supported at this point?

Well, first thing I’d point out is that one of the reasons why CapEx goes up in 2010 and 2011 Abala, is because we’re building two wind farms, one in Minnesota, one in North Dakota, which is approximately a $900 million spend over that time frame; and as you know, we have great recovery and we’re excited about earning some of our renewables. So when you back that out, then you look at the spend and it’s related to the generation transmission and the other items. A couple of things, I would say. We’ll certainly make sure that we’re taking advantage of the declines in the commodities markets, and making sure that our forecasts reflects the fact that while we are still seeing customers grow, and our customer accounts in the first quarter would increased over the 12-month period by about 1% or around 30,000 customers, it’s slower than where it was. We’ll make sure that we have that. Then we will look at economic conditions and what they suggest for long term sales growth and we’ll take a look at some of the generation plans that we have. There might be an opportunity to push some of those things out. So I guess the good news is I think we have some flexibility. I think the extra good news is because we’ve been proactive and kept the balance sheet strong, we don’t have to strip out things like wind and other things that we want to do, and that we think are an important part of our strategy.

And two last things and I’ll let someone else ask; one with regards to the $900 million of wind, because of the time period in which it’s being put in for, the 30% cash opportunity from the economic stimulus package and how would that be treated? Secondarily, given the equity offering that was taken last September, if the capital program remains at current levels, how long does that take you out in terms of the not needing issue equity beyond basically DRIP programs?

Well, let’s answer the first question and that I think you’re referring to the opportunity to take ITC versus PTC for the wind investments, and you’re right, that’s a 30% credit after you back out certain items. We are certainly looking at that Abala, but we’ll also balance that against what makes most sense for our customers. In regards to equity, you are absolutely right too; having gotten that equity out last year, I think that we certainly don’t see the need for equity in the next couple of years. You get beyond that and let’s just see where the economy goes, but I think we’re in very good shape.

Thank you very much.

Thank you.

Thank you, and our next question comes from the line of Dan Jenkins with State of Wisconsin Investment; please go ahead.

Hey Dan. Dan Jenkins - State of Wisconsin Investment: Hi, how are you?

Good. Dan Jenkins - State of Wisconsin Investment: A couple of questions on your slide three where you show the electric margin change. In the first line there, on the rate increases; can you split that up between the states, Minnesota, Texas, Wisconsin and New Mexico; what the affects were?

Yes; you’re talking about the $45 million? Dan Jenkins - State of Wisconsin Investment: Right.

Yes. I can do that for you, but it might take a few minutes. The interim rate increase in Minnesota is probably the lion’s share of it, Dan. It’s about $30 million. The Texas rate increase is about $9 million; Wisconsin is about $4 million and New Mexico is about $1 million. Dan Jenkins - State of Wisconsin Investment: Okay, and then on the three lines that show the riders the second, the fourth and the sixth lines, the MERP was all Minnesota right?

Yes. Dan Jenkins - State of Wisconsin Investment: And how about on the conservation DSM riders and the non fuel ones?

The conservation rider is primarily in PSCo for $15 million. Dan Jenkins - State of Wisconsin Investment: Okay, how about the non-fuel riders?

Let’s see, primarily Minnesota. Dan Jenkins - State of Wisconsin Investment: And then for all of those rate increases and the riders, are those kinds of increases, things we can expect as the quarters going forward?

Well, of course the interim rates are subject to refund and the pending commission approval, as we discussed. Conservation continues to be an important part of our business, so you will continue to see that. The MERP riders stay into effect and those plans, they are completed and the projects are completed very successfully I might add, and those riders remain in place until we file our next rate case in Minnesota and then it gets rolled into the rate base. So the short answer is yes. Dan Jenkins - State of Wisconsin Investment: Okay, that’s all I have. Thanks.

Thanks Dan.

Thank you. Our next comes from the line of Paul Ridzon with KeyBanc; please go ahead.

Hey Paul. Paul Ridzon – KeyBanc: Hey Ben, how are you?

Great. Paul Ridzon – KeyBanc: Is there a sensitivity around what 100 basis points of sales does? I know there’s obviously mixed issues in there, but what that does to EPS?

Paul, that’s a great question. Typically, I would say that 1% is about $30 million, but what we’re finding is we really need to peel it back and look at what customer class it is in, what jurisdiction it is in, because we didn’t have much of an impact this quarter with declining sales, and we’ve done a lot of analysis on that and it’s really because as I mentioned briefly in the remarks that that decline is with customers that the majority of our recovery is demand versus energy based. So, now I think that might change with seasonality, as we get into seasonal rates and the mixed naturally changes, so that’s why we need to continue to monitor it. So typically it’s $30 million, but it really depends on where it’s occurring. Paul Ridzon - KeyBanc: So $30 million is kind of, if it was uniform across the board?

That’s what we generally have used as our back of the envelope calculation, but we are finding that you really have to drill down on it to break it out, to get a good answer. Paul Ridzon - KeyBanc: And can we expect trend towards a forward test year in Colorado kind of being the standard?

Well, I think that’s always going be a commission decision and this settlement wasn’t specific about it. I think it certainly has elements that would suggest that it’s something that is gaining acceptance. Paul Ridzon - KeyBanc: And then, Abala touched on with the ITC, but is there any pickup that you could see in the stimulus bill around bonus depreciation or other opportunities?

Yes, I think there’s definitely bonus depreciation. As I mentioned, we are looking at the ITC, and there’s plenty of grant monies available for some projects and we like I’m sure every other utility in the nation, is looking at those opportunities. We’ll make sure, though that we spend that money wisely, because most of those grants are matching, so you really need to make sure that it’s something that is going to be of value. So we’re scrubbing that and expect us to file applications like I’m sure everyone else will, and try to get some of that money for our customers. Paul Ridzon – KeyBanc: Thank you.

Thanks.

(Operator instructions) And our next question comes from the line of Daniele Seitz with Dudak Research Group; please go ahead.

Hey, Danielle. Daniele Seitz - Dudak Research Group: Hi. I just was wondering, what is going to be your AFC numbers assuming that you are not going to replace it with rate increases in total in Colorado?

What our AFUDC numbers are going to be? Daniele Seitz - Dudak Research Group: Yes.

Well, they are very close to what the CWIP recovery was. So we’ll continue to recognize AFUDC until Comanche 3 goes into service in the second half of this year and then as you know we’ll have a 2010 rate case that we’ll be filing in the next couple of weeks; that will pick up Comanche 3 with AFUDC, and we hope to get a decision there before the start of 2010. Anybody else want to add anything?

Yes, Danielle, I think if you look at last year’s trend for AFUDC I think it’s going to be relatively close to that for the year. Daniele Seitz - Dudak Research Group: Okay. Similar. Thank you.

Thank you, and our next question comes from the line of Ishar Khan with INCO; please go ahead. Ishar Khan – INCO: Hi, how are you doing Ben?

Good. Ishar Khan - INCO: You just mentioned that SPS is going to be about 8% ROE for 2009. Will you be able to maintain that going forward and I guess what is the plan to get it to the required number as you go forward?

Well yes, I’m confident we’ll be an 8%, maybe even a little bit better if things go right, but your question of going forward, that remains to be seen. Where I have some optimism Ashar, as you and I talked about is we really have put these fuel issues behind us; our customers are customers again, not plaintiffs and we are working with them, and I think we have a lot of support from our large customers. We are getting things like interim rates put in place. We’re looking at transmission opportunities there, and we are working with our customers and whenever you have that situation occurring, you’ve got to be a little more optimistic than where we were just a year ago. So time will tell, but the SPS is certainly improving and we are pleased with the progress. Ishar Khan - INCO: I saw for the first time, you started providing results by each of the subs. Is that some information which we can get for the historical years?

Well as you know, we always file separate Ks and Qs for each of the subs, so it’s always been available. We’re just highlighting it this quarter, because we thought it would be useful to you, sounds like it is, and it’s consistent with increasingly how we’ve taken an optimal approach to our strategy and more importantly the execution of that strategy. Ishar Khan - INCO: Okay, and if I could just end up, what type of ROEs are you expecting at the other subs in 2009.

Overall, we’ll probably be in that 9% to 10% range. Ishar Khan – INCO: So at PSCo and SPS both, between 9% and 10%.

Yes, I mean just general. If you have SPS in the 8%s, he other ones will do in the 9% to 10%. Ishar Khan - INCO: Okay. Thank you very much.

Thank you. And our next question comes from the line of [Sara Ingram] with Wachovia; please go ahead. Sara Ingram – Wachovia: Hey, good morning.

High, Sara. Sara Ingram – Wachovia: Looking at the OES’ recommendation for the 10 year life extension of Prairie Island, you mentioned that it wouldn’t necessarily have an earnings impact be maybe a cash flow impact, but just from a regulatory standpoint, if you don’t get that rate stabilization plan, what kind of impact would you say that might have going forward?

Well, the rate stabilization plan was to help us have recovery and potentially avoid the need for filing rate cases as we started to operate our nuclear plants, and so we’ll have to work through that and obviously we always had the option of filing rate cases in Minnesota, and as you know that are interim and forward test year based, but that was the goal of that. So we’ll just have to reassess it. Scott, do you want to add anything?

I think if the current proposals remain, we would just look to how rate case is timed. They are a very large investment and they’ll be easy to time in terms of trying to seek the recovery and that’s the way we manage it. Sara Ingram – Wachovia: Okay. Thank you.

Thank you, and management, I show we have no further questions at this time.

Okay great. Well, thanks for participating in our first quarter earnings call and I look forward to seeing many of you in person next week at AGA. In the meantime, if you have any follow-up questions, call Paul Johnson or the rest of the IR team and hopefully they’ll answer your questions. Thank you.

Ladies and gentlemen, this concludes the first quarter 2009 earnings call. If you would like to listen to a replay of today’s conference, please dial 303-590-3000 or 800-405-2236; using the pass code 1112907#. ECT would like to thank you for your participation. You may now disconnect.