Ben Fowke - President & Chief Operating Officer Dave Sparby - Vice President & Chief Financial Officer Teresa Madden - Vice President & Controller Scott Wilensky - Vice President of Regulatory & Resource Planning George Tyson - Vice President & Treasurer Michael Connelly - Vice President & General Counsel Paul Johnson - Managing Director of Investor Relations & Assistant Treasurer

Ali Agha - SunTrust Danielle Seitz - Dudack Research Jonathan Arnold - Deutsche Bank Angie Storozynski - Macquarie Capital Tom O’Neil - Green Arrow Paul Patterson - Glenrock Associates Neil Kalton - Wells Fargo Securities Dan Jenkins - State of Wisconsin Investment Board

Good morning, ladies and gentlemen and thank you for standing by. Welcome to the Xcel Energy fourth 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, Managing Director of Investor Relations and Assistant Treasurer; please go ahead, sir.

Thank you and welcome to Xcel Energy 2009 year end earnings release conference call. I’m Paul Johnson. With me today are Ben Fowke, President and Chief Operator Officer; Dave Sparby, Vice President and Chief Financial Officer; Teresa Madden, Vice President and Controller; Scott Wilensky, Vice President, Regulatory and Resource Planning; George Tyson, Vice President and Treasurer; Michael Connelly, Vice President and General Counsel. Today we planned to cover our 2009 results and accomplishments. Please note that there are slides accompany the conference call, which are available on our webpage. Let me remind you that some of our comments may contain forward-looking information. Significant factors that could cause results to differ from those anticipate are described in our earnings release and our filings with the SEC. You’ll notice that today’s press release refers to both GAAP and ongoing earnings. 2009 ongoing earnings were $1.50 per share, compared with $1.45 per share in 2008. 2009 GAAP earnings were $1.48 per share, compared with the $1.46 per share in 2009. As you may recall in 2007, we reached a settlement resolving a dispute with the IRS regarding our Company Owned Life Insurance program, also known as COLI. Our 2009 GAAP earnings included a charge of $0.01 per share, for a legal cost associated with our claims against insurance providers and brokers of the COLI policies. In addition, we incurred a discontinued operations charge of $0.01 per share related to tax expense and legal accruals for previously divested businesses. Our 2008 GAAP earnings include a $0.01 per share benefit from discontinued COLI programs. Management believes that ongoing earnings, which removes the impact of COLI and discontinued operations provides a more meaningful comparison. As a result, we will discuss ongoing earnings during this call. Please see note six in today’s earnings release for a detailed reconciliation of GAAP and ongoing earnings results. I’ll now turn the call over to Ben Fowke.

Thanks Paul and good morning. I’m pleased to announce that Xcel Energy had another successful year. This morning, we’ve reported 2009 ongoing earnings of $1.50 per share compared with $1.45 per share in 2008. Proud to deliver our earnings results at the midpoint of our 2009 earnings guidance range of $1.45 to $1.55 per share, despite unfavorable weather, which reduced earnings by $0.05 per share and decline in electricity sales due to sluggish economy, which reduced earnings by $0.03 per share. To offset the impact of unfavorable weather and lower sales, we took actions to reduce expenses and reached constructive outcomes in seven State rate cases in order to deliver earnings within our guidance range. Resolution of these cases as well as two rate cases also provides greater regulatory certainty as we began 2010. We have a relatively light docket this year with two smaller rate cases pending, a Minnesota gas rate case on a per coal sale rate case in Colorado. In addition, we plan to file our wholesale case in a retail reopened case in Wisconsin. Operationally, customer satisfaction and reliability improved in 2009. We completed major construction projects like MERP and Fort St. Vrain. We also made significant progress on the construction of Comanche 3. Final testing is being completed and we expect this plant to go in service in February. Comanche 3 will deliver tremendous value to our customers with the construction cost of approximately $1500 per KW. I’ll now turn the call over to Dave Sparby, who’ll walk you through the year end results and also give you a regulatory update.

Thanks Ben and good morning. Let’s take a look at the details of 2009 starting with a review of the annual results at each of our subsidiaries. For the year, earnings at PSCo decreased by $0.04 per share. The decrease was largely due to the negative impact of weather and raising cost, which was partially offset by new electric rates that went into effect last July. In NSP-Minnesota, earnings decreased by $0.01 per share. The decline result of largely from cooler than normal summer temperatures and timing of nuclear outage expenses. The decrease was partially offset by an electric rate increase that went into effect in January 2009. NSP-Wisconsin, earnings were flat for the year. Increased costs were offset by better fuel recovery and new rates that went into effect in January 2009. At SPS, earnings increased by $0.08 per share, the improved financial results were due to 2009 electric rate increase, in Texas and New Mexico and the resolution of fuel cost issues. Finally, our investment in WYCO, our natural gas pipeline in Colorado generated $0.02 per share of incremental earnings. Next I’ll discuss the drivers that affected various lines of the income statement, beginning with retail electric margin. Electric margin increased by $297 million during 2009. This was largely driven by rate increases in Minnesota, Colorado, Texas, New Mexico, and Wisconsin, which increased electric margin by $218 million. Conservation revenue, non-fuel riders, and MERP riders also to increase retail electric margin by a total of $113 million, increases in the conservation revenue, however, are largely offset by higher conservation in DSM expense. Some of the factors that offset these increases include purchased capacity costs, primarily at SPS, which reduced margin by $44 million, cool summer temperatures, which reduced margin by $6 million, and a decline in weather adjusted retail sales, which reduced margin by $22 million. Turning to expenses, 2009 O&M increased about $130 million or 7%, some of the contributing factors to the O&M increase included higher employee benefit cost, which increased $90 million, the increase was due to performance based incentive expense, active health care costs, and pension expense in 2009. As you recall, we didn’t accrue any incentive compensation in 2008. An increase in nuclear outage costs of $30 million, the increase was the result of the Minnesota commission’s approval of the change in a recovery of nuclear refueling outages in 2008 and finally, higher nuclear plant operations expenses, which increased $21 million primarily due to higher security costs and regulatory fees. Fees and other items were partially offset by lower consulting costs and lower bad debt expense. For the year depreciation expense decreased by $10 million, the decrease was largely the result of regulatory decisions, which extends the lives of our nuclear plants for the purposes of determining depreciation and decommissioning expense. Next, I’ll touch on some of the regulatory developments, starting with the cases that wrapped up at the end of the year. We recently completed our 2010 Colorado electric case. In that case, the commission improved an electric rate increase of $128 million based on authorized ROE of 10.5% and an equity ratio of 58%. Subsequent to the commission’s approval of the rate increase, it became apparent that Comanche 3 would not be in service at the end of 2009. We filed a proposal with the commission to phase in the rate increase to reflect the actual in service date of Comanche 3. The CPUC approved our proposal and as a result, the rate increase will be phased in over three steps. A rate increase of $67 million was implemented on January 1. Electric rates will increase another $54 million, when Comanche 3 goes into service currently expected to occur in February and finally, rates will increase another $7 million in January 2011 to recover property taxes associated with Comanche 3. The phase and due rate reduces the impact on our customers and we’ll have minimal earnings impact on PSCo or Xcel Energy. Last June, we filed a request to increase Wisconsin retail electric rates by $30 million based on an REO of 10.75% and a 2010 forecast test year. In December the Public Service Commission of Wisconsin approved an electric rate increase of approximately $6.4 million and no change in gas rates, based on 10.4% ROE and 52.3% equity ratio. The major differences between the amount requested and the authorized includes a variety of items that do not affect our earnings such as, savings from the life extension of the Prairie Island nuclear plant for purposes of determining depreciation and decommissioning and a significant drop in forecast fuel cost. The major earnings related adjustments were lower ROE and equity ratio. Last June we also filed a request to increase South Dakota Electric Rates by about $19 million based on an ROE of 11.25% and a 2008 historic test year with adjustments for known and measurable changes. Earlier this month, the South Dakota Commission approved a rate increase of $10.9 million. The difference between the requested increase and the settlement amount related to a lower ROE use of a 20 year life for Prairie Island nuclear plant, which reduces the revenue deficiency and expense accruals by a corresponding amount. New rates went into effect earlier this month. After completing an ambitious regulatory effort in 2009, we enter 2010 with an improved regulatory certainty and only two pending rate cases. In November, we filed a request with the commission to increase Minnesota gas rates by $16 million in 2010. The request is based on an ROE of 11% and equity ratio of 52.5% and a rate base of $441 million. Interim rates of $11.1 million went into effect in January. We expect a decision late this year. In 2009, PSCO filed an increase Colorado wholesale rates by $30 million, based on a 12.5% ROE, a 58% equity ratio, and a rate base of $315 million. We are in settlement discussions with our wholesale customers and expect rates to go into effect later in 2010. Before we go to Q-and-A, Ben has a few closing remarks.

Thanks, Dave. In closing, in a year largely defined by sluggish electric retail sales and unfavorable weather. I’m proud that we were again able to deliver on our financial objectives. On the regulatory front, we received constructive outcomes in our rate cases. These outcomes enable Xcel Energy to continue to make prudent investments across our service territories. Our successes in 2009, demonstrate our commitment to achieving our financial objectives, while delivering quality service to our customers. Finally, we are reaffirming our ongoing earnings guidance of $1.55 to $1.65 per share for 2010. I’ll now turn it back over to Dave and we’ll open it up for questions.

(Operator Instructions) Your first question comes from Ali Agha - SunTrust. Ali Agha - SunTrust: Given all the rate cases that you all have completed in ‘09 and as you mentioned fairly light regulatory activity in 2010, if you look at your utility portfolio today and you compare, the ROE’s that you are earning currently versus aloud, would you say that the regulatory lag is pretty much eliminated now? Or how would you categorize that actual ROEs versus authorized ROEs at this point.

We continue to make improvement every year as you know. Ali, we’ve added significant amounts to our ability to recover through riders as well as we’ve improved the timing of rate cases. So we’ve seen some lag, we managed to reduce it and we see ourselves continuing to reduce that lag further over the next couple of years. Ali Agha - SunTrust: So you would not say that you’re pretty much earning authorized returns across the portfolio yet? That is still more to be done?

We’ll earn close to 10% across the portfolio. We do have some of our op those more opportunities to earn closer to that average. We see ourselves continuing to make progress in that regard. Ali Agha - SunTrust: Just to be clear, the 10% you expect would be for the 2010?

Yes. Ali Agha - SunTrust: What was the number for ‘09?

It was in the 9.6 to 9.7 range. Ali Agha - SunTrust: One other question, as you look at your CapEx program going forward and you look at your external capital needs, when do you believe or think that you would need to raise more equity as part of this plan?

We don’t have any plans to raise equity in 2010. We’ll continue to evaluate the need for equity based on expenditures and market conditions following that period.

Your next question comes from Danielle Seitz - Dudack Research. Danielle Seitz - Dudack Research: I was wondering it seems that the O&M increase continues to be at the 6% and 7% range and could you explain when an increase is still coming from benefit increases, or if it includes also the effect of Comanche 3.

It reflects two primary components. The first was the effect of the Commission’s decision in 2008 to move to a different means of recording our outage expenses, Danielle. That had an impact on increasing costs in 2009 versus 2008. Also is reflected the difference between not paying out any incentive compensation in 2008 as compared to 2009. Those differences account for a big part of that change in our O&M expense. It’s also important to consider that we continue to add rate base over that period of time. We’ve added a lot of projects like our pre-go projects, which is our Buffalo Ridge transmission project. So we continue to add rate base and operating plan. Danielle Seitz - Dudack Research: In terms of 2010 outlook, it seems that you’re anticipating roughly the same amount. Is this more due to the new unit again coming in, or is it again mostly due to benefits?

It is in part due to the addition of Comanche 3. We see higher chemical costs as well as the last tranche of expense related to our nuclear outage cost as a result of the deferral and amortization method approved by the Minnesota Commission.

Your next question comes from Jonathan Arnold - Deutsche Bank. Jonathan Arnold - Deutsche Bank: I was going to ask on sales trends it seems that as you look at the fourth quarter in isolation on a normalized basis both in residential and C&I things ticked down a little from the third quarter. Can you talk about what maybe going on in those numbers in the context of your outlook for 2010, and just some commentary of trends across the regions and on the sales front?

Sure. Well, we do retain some slight optimism of course for 2010. Overall, we’re seeing about a 1% increase in sales. The optimism is really generated from our look at some regional and local indicators, including things like housing starts, employment prospects, as well as that purchaser managers’ index. Now, we’re seeing more of that come back in the C&I class in 2010 and then of course part of that is because sales retreated a little further on the C&I than on the residential class, but of course, overall, the states we serve have remained pretty strong in ‘09 when you look at employment prospects and others and we think that they’ll be some of the first to recover here.

Your next question comes from Angie Storozynski - Macquarie Capital. Angie Storozynski - Macquarie Capital: Two questions, one about your Comanche 3 plans. How should we think about it? You said that the plans should be online in February. Any estimate as to will it be the beginning of the month or simply don’t know. Should we think that the other increase in revenues will be prorated depending on when the plan actually goes online?

Angie, this is Ben. The plan has had a few startup issues, primarily with some of the wells, but we think we have that fixed and we anticipate probably in service in the middle of February. Of course we’ll update that, it could be earlier or it could be later, but that’s the best estimate we have right now. As far as the revenue, as soon as it goes in service, we pickup the piece of the revenue that was associated with Comanche 3, which we aren’t receiving right now. With the settlement, as you know it was designed to be earnings neutral for us while we were seeing some delays with Comanche 3. Again as I said on the call, a $1500 KW price, I mean that’s a sensational price point for our customers. It’s going to be a great value for our customers and it’s a very efficient modern plant, which allows us to take a look at some of our less efficient plants. Angie Storozynski - Macquarie Capital: Also any updates regarding your environmental CapEx, especially the wind farms, any ownership plans for the future, any update on this front?

Angie, they all continue to go well. We’ve received the necessary approvals from the Minnesota and Wisconsin commissions and all other prospects are positive for those facilities, including the work with the transmission. Angie Storozynski - Macquarie Capital: Given the fact that there seems to be a couple of distressed wind assets in the region, your still prefer a new build to acquiring existing assets?

I’m not aware of any distressed wind asset sales in the region and our plans are to continue with the construction of these assets. Their economic in perspective of our resource acquisition plan.

Your next question comes from Tom O’Neil - [Green Arrow]. Tom O’Neil - Green Arrow: I just had a question regarding 2010 guidance relative to 2009. I guess 2009 on a weather adjusted basis is $1.55. So I guess just without any rate cases hanging in the balance in 2010. I’m just curious the thinking on the range and is it mainly the economy that keeps you a little more conservative?

Certainly the economy is something that we follow very closely. Now, Tom, you also can’t simply take the weather that we didn’t see in 2009 and add it to 2010. That brought with it some natural hedge for us. Units that have maintenance based on number of starts and running hours, for example as well as the lack of escalated operations in our distribution system are events that we wouldn’t expect to see repeated in the event that we had more weather.

Your next question comes from Paul Patterson - Glenrock Associates. Paul Patterson - Glenrock Associates: I want to touch basically on two things. First of all, the Minnesota Attorney General, I think along with the State Senator has introduced legislation with respect to I guess the riders or what have you through the interim increases and what have you? Do you feel that legislation has lags or can you give perspective as to that? As I recall, we also saw something in Colorado a year or two ago, where they apparently had some sort of issue associated with automatic or not automatic, but more abbreviated rate increases?

In Minnesota, what we have is a regulatory framework that matches up very well the States policy objectives and that’s allowed us to do what we’ve been able to do in terms of managing carbon and increasing DSM and the like. So I don’t expect that legislation to pass because it’s been a very significant part of what we’ve been able to do here. There certainly will be some discussion about it. It is not a policy session at the legislature and consequently, I don’t expect that to be enacted or looked at in great deal detail this coming session. Paul Patterson - Glenrock Associates: The situation in Colorado what is that over with now? I don’t remember what happened actually there?

This is Scott Wilensky. The commission did express some concern about the number of riders we had and it as us to address those in a series of rate cases. We actually did that and I think there’s a comfort that is grown that these riders are actually facilitating some of the public policy goals in the state and are a necessary mechanism to keep the investment going. I think that it moving through the series of rate cases, we’ve dealt with those issues. Paul Patterson - Glenrock Associates: Finally on Comanche 3, you that basically just start up issues, you don’t have any expectation that those will be operational issues? Is that correct?

You mean things we’ll be living with for some time? Paul Patterson - Glenrock Associates: I mean in other words to the steam to problem I think it was I am really it exactly what it is but there’s a mechanical issue there I am just wondering that.

We’re if I canning it and we’re fixing it right and the vendor that was responsible and these were factory welds is step up in this is taking them so this going to be some kind of performance or operational issue that plague us post startup very much on top of that actually.

Your next question comes from Neil Kalton - Wells Fargo Securities Neil Kalton - Wells Fargo Securities: Just a question on transmission. We’ve seen it in other regions throughout getting pushback turn on the economy I want to do comment on your portfolio projects are you seeing is there any change in the thought process in terms of timing or it same pretty much moving along 18 months ago.

Neil, as we look across our service territory, all of the transmission projects continue to move forward very well. When we look at CapEx, which is our regional approach in the north, and you look at each one of those lines, we see we’re well into the routing of those lines. The acceptance has been good and continues to make good progress when we look at the nine lines that are a part of the SD 100 project in Colorado. It’s really only one line where we’re facing some resistance. All lines continue to move forward through the process when you look down to SPS, whether it’s the seven rivers to PSCo project or any of the others we also ten to good progress so that’s moving along as we expected. Neil Kalton - Wells Fargo Securities: Would there be any concern if sort of loads didn’t do what you thought this year might that threaten so many projects in terms of timeframes?

You kind of faded out if I understood the question would we expect to change our plans if loads continue to be low this year? These are very long term projects, looking at bringing very competitive renewable energy as well as addressing some reliability issues in the region. So, I wouldn’t expect our plans to change.

Your next question comes from Dan Jenkins - State of Wisconsin Investment Board. Dan Jenkins - State of Wisconsin Investment Board: I was curious first on the South Dakota rate case decision; it mentions on the slide that it was a black box settlement. Does that mean there’s no authorized ROE that we can kind of use as a guide there or how should we think about the ROE for that rate case?

None stated, Dan. Dan Jenkins - State of Wisconsin Investment Board: As far as your Minnesota case, what was the, you filed for 11% ROE what was the last allowed ROE for the Minnesota gas?

That was 9.71% when our last 2007 natural gas case. Dan Jenkins - State of Wisconsin Investment Board: Then I was curious if you could give a little more color on in your earnings guidance, you mentioned 1% electric retail sales growth. Are you expecting any differences between various geographies or are you seeing more or less growth than the various customer classes?

We are seeing some differentiation, Dan. There’ll be more growth for example in Colorado CNI than the remaining CNI classes. Although it’s not a material amount relative to what we’re seeing and other PSCo probably last growth than the other PSCo in the class in Wisconsin. So there are some differences they’re not real significant and, when we talk about growth, it’s important to consider that in the context of our DSM objectives in 2010 because they’re also very aggressive in Minnesota, for example our demand side management objective will be to save about 1.1% energy for our customers. So as you look at these growth rates, we would suggest you put that in that context.

Your final question comes from Danielle Seitz - Dudack Research. Danielle Seitz - Dudack Research: I was wondering if you had a number for the amount of you got through the riders in ‘09 and how much did you assume for 2010?

Danielle, this is Paul Johnson. Why don’t you give me a call afterwards and I’ll get you those numbers. The increase for 2010 is expected to be about $30 million, but the absolute amount; we don’t have at our fingertips here.

There are no further questions at this time. I will turn the conference back to Dave Sparby for closing remarks. Please go ahead.

Well, thank you all for attending our year end and quarter close. If there are any follow up questions, please refer them to Paul Johnson and our IR Team.

Ladies and gentlemen, that does conclude the conference for today. If you like to listen to a replay of today’s conference, please dial 303-590-3030 or 1-800-406-7325. The access code is 4195322. ACT we’d like to thank you for your participation. Have a pleasant day. You may now disconnect.