埃克西爾能源 (XEL) 2004 Q2 法說會逐字稿

Good morning, my name is Matthew. I will be your conference facilitator. I would like to welcome everyone to Xcel Energy's second quarter 2004 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer period for the analysts only. Please limit your question to one per caller. To ask a question during that time, simply press star then the number one on your telephone keypad. To withdraw your question, press star and then the number two.

Thank you, I would like to turn the call over to Mr. Richard Kolkmann. Sir, you may begin.

Thank you, welcome to the Xcel Energy second quarter 2004 earnings release conference call. I'm Dick Kolkmann, Managing Director of Investor Relations. And with me today is Ben Fowke, Vice President and CFO of Xcel Energy.

We also have several others here to help provide answers to your questions. Some of the comments that will be made contain forward-looking information. Significant factors that could cause results to differ from those anticipated are described in our earnings release and Xcel Energy filings with the Securities and Exchange Commission. Now I will turn the call over to Ben Fowke.

Thanks, Dick. This morning, I plan to discuss our second quarter financial results and some key issues relating to Xcel Energy. We have a simple, straight-forward story. And we continue to be on-track to meet our financial goals.

I am very pleased to report that Xcel Energy recorded solid earnings from continuing operations of 20 cents per share for the second quarter of 2004, compared with 13 cents per share for the second quarter of 2003.

Total earnings for the second quarter of 2004 were 21 cents per share, compared with a loss of 71 cents per share for 2003. The loss in 2003 relates to write-downs at NRG, which has been divested from Xcel Energy.

I plan to spend my time during this call discussing our earnings from continued operations. Our earnings release provides details on earnings from discontinued operations.

So let's start with the core of our business. Our utility subsidiaries provided earnings of 21 cents per share for the second quarter 2004. This compares with earnings of 19 cents per share for the second quarter 2003.

The improvement in earnings is largely due to lower depreciation expense that increased earnings by 4 cents per share, favorable short-term wholesale trading margins that increased earnings by 2 cents per share, and lower financing costs that increased earnings by 2 cents per share.

These favorable results were partially offset by higher O&M expenses, which decreased earnings by 2 cents per share, and other items including quality of service penalties in Colorado, a higher effective tax rate in 2004 and dilution, which together reducing earnings by approximately 4 cents per share. This summarizes our second-quarter earnings.

Let me provide you more detail on a few of our significant drivers, starting with the top of the income statement and moving down. As you review the details of our earnings release, you will notice that while weather-adjusted retail sales increase by 2.4%, our base electric utility margin was flat for the quarter. This was driven by two regulatory accruals. The first regulatory accrual didn't impact our net income.

In the second quarter of 2003, we recognized 10 million of revenue for renewable development costs, which are recovered through one of our fuel clause mechanisms. At the same time, a corresponding $10 million of depreciation expense was recorded. Since this is a pass through cost, it had no impact on our financial results.

However, since the 2004 renewable costs were less than last year, it creates a negative deviation in the comparables for electric margin and depreciation, for both the quarter and the year-to-date results.

The second regulatory accrual, which reduced electric margin and net income, relates to our quality-of-service plan in Colorado. In the second quarter, we filed updated performance results for service quality measures with the Colorado Commission.

Based on this updated information, we accrued for customer refunds for 2002-2004. The net impact of this accrual is an $8 million reduction in base electric utility margins, when compared with accruals for customer refunds during the second quarter of 2003.

We are focused on improving our performance in these areas. Our strategy is to build the core. This translates into incremental investment at a core utility.

Last year, we developed an action plan to increase our spending and improve reliability in both Minnesota and Colorado. While this will take time, we are making progress and we'll continue to take appropriate actions to improve reliability and customer satisfaction.

Offsetting the flat base electric utility margins were short-term wholesale margins that continue to be strong. Our generation fleet has performed extremely well over the last several years. This has allowed us to meet our native load requirements and sell excess generation into short-term markets.

As a result, short-term wholesale and trading margin was $14 million higher for the second quarter of 2004. Some key drivers include higher on-peak and off-peak prices, particularly in the Map region; plan availability; and cooler temperatures, which freeze up more of our generation capacity for wholesale sales.

In general, second quarter on-peak prices in Map were 20% higher than last year, while off-peak prices were 30% higher than last year. This made our low-cost coal generation very attractive. Forward prices for the third and fourth quarter are running ahead of last year's pace.

As a caveat, however, it should be noted that these prices are volatile and can change materially. And while our goal is to maximize the value of our wholesale margin, our first priority is to serve our retail load.

Therefore, we can we can only capture additional short-term wholesale margins if we have incremental capacity to sell after meeting our Native requirements. Thus, we have limited ability to lock into these higher price margins in advance.

That being said, we're ahead of last year's pace and expect that we will end the year with higher short-term wholesale margins than our 2003 levels.

I would like now to shift the focus to our operating expense. As expected, our second quarter 2004 regulated O&M expenses were higher by $14 million or 3.8%, this is largely due to increased spending on reliability initiatives and lower pension credits.

On a year-to-date basis, the O&M increased about 4% over last year's level. However, we continue to expect that our 2004 O&M levels will be relatively flat compared with 2003 levels. Our average regulated O&M quarterly spend rate was approximately $380 million for the first three quarters of 2003.

In contrast, for the first two quarters of 2004, our O&M expenses averaged $393 million per quarter. While this seems to indicate that our O&M expenses for 2004 for will end up significantly higher than 2003 (ph) levels, it should be noted that our O&M expenses spiked up to $431 million in the fourth quarter of 2003, due to year-end true up accruals for incentive compensation and other items.

We don't expect this to reoccur in 2004. Therefore, again, we continue to believe O&M expenses are on track with our business plan. And our current forecast supports our guidance of relatively flat O&M expense.

Depreciation expense was another positive factor, continuing the trend of the last few quarters and contributing to our favorable results. Depreciation expense for the second quarter of 2004 was $26 million lower than 2003 levels, largely due to several regulatory actions.

As I mentioned earlier in the call, depreciation was $10 million higher in the second quarter of 2003 for the renewable fund accruals. In addition, as I've discussed in the past, there are two other regulatory actions that will reduce overall depreciation expense in 2004.

We're experiencing the full-year impact of a rate change in Colorado, which will lower depreciation expense by $10 million in 2004. We're also benefiting from life extension at the Prairie Island nuclear plant and the move to a completely external decommissioning fund. These actions are expected to reduce 2004 depreciation expense by $18 million.

These regulatory adjustments more than offset the normal incomes we typically see in depreciation expense. As a result, we continue to expect our annual 2004 depreciation expense will decline between 1 to 2% from 2003 levels.

The decline in depreciation expense will be experienced primarily in the first three quarters of 2004 because as you may remember, we recorded an annual depreciation adjustment in the forth quarter of 2003 to reflect the Prairie Island ruling.

Moving now to interest expense, as we have mentioned in the past, we expected our financing costs would decline in 2004. Our financing costs for the second quarter of 2004 were almost $14 million lower than 2003 levels. This is largely due to the refinancing activities we completed last year.

Looking at the full-year, we now expect our interest expense will be $20 million to $25 million less than last year due to our refinancing activity last year and higher levels of capitalized interest.

The decline in financing costs during 2004 will be more prevalent in the first and second quarters of this year since the majority of the refinancing activity took place in the summer of 2003. That covers our utility operations.

Let's turn our attention to our non-regulated and holding Company results. Other non-regulated subsidiaries and holding Company costs resulted in a loss of 1 cent per share for the second quarter 2004. This compares with a loss of 6 cents per share for last year.

Our results for 2003 reflect restructuring charges related to NRG and losses at Planergy and utility engineering. The 2003 restructuring charges include financial and legal costs incurred by Xcel Energy, relating to the NRG situation. From a GAAP basis, these costs are not considered discontinued operations.

In 2003, Utility Engineering results reflected losses partially due to project write-downs. Utility Engineering has essentially broken even for 2004.

Planergy also experienced losses in 2003. The majority of Planergy's operations were closed in 2003, with the remaining operating units sold in January 2004. Our results from Seren and Eloigne were consistent with 2003 and are tracking with our expectations for 2004. That covers our results for the quarter.

Turning our attention to the rest of 2004, we're maintaining our earnings guidance range of $1.15 to $1.25 per share. A few of the key assumptions have been updated and are included in our earnings release.

For the first six months of the year, we have experienced negative weather-adjusted firm gas sales growth, reflecting lower usage as customers react to higher natural gas prices. Based on this trend, we expect that our annual weather-adjusted gas sales will decline approximately 1% for the full year. We view this decline as a short-term trend and expect that our gas business will continue to grow in the long run.

In the quarter, the Colorado PUC granted us $20 million of revenue recovery in the form of a capacity cost rider to offset our increased capacity costs. Although this was less than our request of $27 million, we are pleased that we have resolved this issue in a positive manner.

Our short-term wholesale margins are ahead of last year's pace, and we expect we will end 2004 with higher margins than last year. The incremental short-term wholesale margins will help offset the declining natural gas sales and the 3 cents of adverse weather we have experienced this year compared with normal weather conditions.

We have also updated our assumptions for interest expense and our effective tax rate, as reflected in the earnings release. With half the year successfully completed, we continue to be on track with our business plan. We will continue to monitor our performance for the remainder the year and will adjust guidance if and when we think it's appropriate.

While we've discussed this in the past, I think it's important to spend a few minutes on our corporate strategy. Xcel Energy is truly a pure play utility. Our strategy is simple and transparent -- build a core business and earn a reasonable return on that investment.

Our core investment is at a run rate of $900 million to $950 million per year. Net of depreciation, our planned investment would typically grow at $100 million to $150 million per year. Through 2009, we propose to make more than $2 billion of incremental investment in the generation side of our business, to add nearly 1300 megawatts of capacity.

The majority of these dollars will be spent on the Minnesota Metro Emission Reduction Project, also known as MERP, and the proposed Colorado coal plant.

As most of you know, late last year, the Minnesota commission approved our MERP plan to invest and recover a $1 billion investment in three coal plants. Two coal plants will be converted to combined cycle CTs and a third will be refurbished and have state-of-the-art emission control equipment will be installed.

We've received all the regulatory assurances we need from the Minnesota commission to proceed with the MERP plan, which includes a rate rider that provides a cash return on our investment starting in 2006.

We are also proposing to build a 750-megawatt coal plant in Colorado. Our share would be 500 megawatts and our investment is projected to be about $940 million. We have asked the Colorado Commission to grant us a cash return on the investment in the proposed coal plan as we make the expenditures.

We also plan to work with the Commission and interested parties to develop an appropriate regulatory treatment, which addresses the impact of imputed debt on our credit profile as determined by the credit rating agencies for power purchase contracts. Without regulatory assurance that our shareholders will be made whole, we will not proceed to build the plant.

In July, the Colorado Commission established a procedural schedule, which is included in the earnings release. Based on this schedule, we're positioned for a Commission decision by the end of the year or early next year. We'll keep you posted on any significant developments.

Our financial objective is to deliver an average total return of 7 to 9% per year. Our build a core strategy will provide long-term earnings growth of 2 to 4%, which when combined with our dividend yield, we believe provides an attractive total return for our investors.

We've recently established a dividend policy that is sustainable and contributes to a competitive total return for our shareholders. We determined that an appropriate long-range targeted dividend payout ratio is between 60 to 75%.

In May, the Board approved an increase of 8 cents to the annual dividend, which is equivalent to an annual dividend of 83 cents. It's our goal to deliver modest annual dividend increases in our dividend.

So with that, I will wrap things up. Again, our goal is to provide a total return to our shareholders of 7 to 9%. We have a strategy of investing in our core utility business. We're working with our respective commissions to ensure we earn a reasonable return on that investment. We're pleased with our year-to-date results. We're on track with our business plan and are positioning to deliver solid results for 2004.

We'll now open the line for questions.

Ladies and gentlemen, if you have a question at this time, please press the star then the number 1 on your telephone keypad. Remember, today's question-and-answer session is for analysts only and we do ask that you limit your question to one per caller. Again, star then the number 1 for a question. We will pause for just a moment to compile our Q&A roster. The first question comes from Misher Khan (ph) with FA Capital (ph).

Good morning, congrats on the good quarter.

Thank you sir.

Could you elaborate on this quality-of-service plan and why the targets are being a little bit missed? And what is the potential that you might have to put a little bit more for the remaining six months of this year?

First of all, I think it's important to note that the targets are aggressive targets. Those are targets that we plan on achieving. We have plans in place to achieve those targets. We've accrued for 2004 approximately $5 million based upon where we are today.

Again, we're optimistic that the measures we put in place will pay dividends in the course of the year and we'll turn the situation around. It's the focus. To answer your question, if the trend line continued, we would incur another $5 million of penalties.

What is the timeframe that these get returned to the customers?

I don't have that answer. We have Dave Sparby with us. Annually?

Annually. Okay. I guess the wholesale is much above budget, among all your assumptions and you said the prices are continuing to be strong. So do you expect you that will pick up further on this for the remaining six months?

Well, I mean, we do expect that we are going to finish the year higher than where we finished 2003 levels. That is a change from our original forecast assumption. Prices are strong.

But you have to keep in mind that the retail load has first call. We don't lock in any of those prices, so it's volatile. We also have an extended outage planned for our Prairie Island nuclear plant later in the year.

We look at all of those things and have baked it into our overall guidance which, again, stays at $1.15 to $1.25.

Thank you very much.

Your next question is from Carrie Stevens from Morgan Stanley.

Hi, I have two questions, just following up on LTM results. If I'm calculating them right, I'm getting $1.34. And just curious, I know you just mentioned the Prairie Island extended outage, but is there anything looking at second half of '03 versus second half '04 that I should factor in as to why you're still maintaining kind of the same guidance when LTM results are very good?

Well, I think we're giving realistic guidance. If you want to address the wholesale side, Carrie, keep in mind we entered into last year, in the third quarter, a contract with a Canadian utility in response to some drought conditions in Canada.

Okay.

And that continued into the first quarter of this year, so that is a difference.

Okay.

And, again, we think our guidance is realistic. We have had some positives, certainly. And we are pleased with where we are.

Okay.

You have things like gas sales, et cetera, that are below average on expectations.

Real quick looking out to '05, you know, you guys have had a couple of changes in depreciation and other types of regulatory decisions that have impacted '04.

I want to kind of remember if there is anything I should be thinking about, looking out to '05. I know the Colorado capacity rider was put into place mid-year, but is there going to be any other kind of D&A or other regulatory treatments that we should be aware of going into '05?

None that we haven't already disclosed.

Okay. So D&A remains on track and no other changes for revenues. I mean for the MERP project, when does that start to contribute?

Well, the MERP project, we are going to spend $43 million roughly on it this year, I think 100 odd million next year. So until '06, we'll pick up income on an AFUDC basis, then we get the cash rider in '06, as you know.

Right.

Our estimate for depreciation expense, et cetera, that will be part of the '05 guidance that we will release in the third quarter of this year.

Okay. Great. Thank you.

Your next question is from Charles Fishman with A.G. Edwards.

Hi, could you give a little more color on the effective tax rate for the second quarter, why it was 14% instead of the 30? I believe it's 30% --is your guidance for the full-year.

Yeah, 30% is the full-year guidance. I think we're about 27% year-to-date. There's two things. We did have a, I think it was a $3 million auto (ph) adjustment -- positive adjustment which impacts that. But the big thing is we take tax credits ratably through the course of the year and because the second quarter is one of, is, we like to call it the low-tide quarter, it tends to distort that effective tax rate a bit.

Okay. Thank you.

Your next question is from Ally Ague (ph) with Wells Fargo.

Ben, going back to the earlier point you were making, I wanted to clarify on the wholesale business being stronger than expected so far during the year. You may have addressed this and I may have missed it.

When I look at the electric trading margin year-over-year comparison, that's significantly lower from last year. Are those issues tied together or are those separate issues?

I'm not sure -- the electric -- electric trading margin is higher this year.

I'm looking at your income statement on the operating revenues -- 2004 versus 2003 for the three months ended June 30.

You're looking at the table that breaks everything out?

Yeah, it's your first consolidated income statement.

Okay. Well, is your -- let me just answer it this way and see if I got your question. Our wholesale margins and our trading margins have been far better through the first six months of '04 than they were in '03.

Okay.

We don't expect that you can -- you can't trend line that for the balance of the year because of the reasons I just said. We -- our retail out (ph) always has first call. We know we have some plants that are on extended outage. Last year, we did enter into a contract in the third quarter of '03, and that contract continued to the first quarter of '04. So I think that's, I mean that's the big ticket there. I don't know if I have answered your question.

I want to make sure I'm looking at the numbers right. It's the very first table in your income statement under operating revenues. There is a line-item called electric trading margin and that was 5.6 million last year and it's less than a million this year.

Oh, okay. That, that relates, I think, specifically to the proprietary margins that we produced,.which is really a small component of our overall short-term wholesale margins.

So the rest of it will show up in the electric utility results.

Yeah, if you look at, I think it's page 5 of the press release, there is a table that breaks out electric utility and commodity trading margins. You should focus on the short-term wholesale column.

Okay. My second question, unrelated to that, was as you look at the regulatory investment that you're making right now, or plan to be making, when you look at it in terms of when the cash may come back to you versus the cash outflow from your pockets, is that an issue that you look at when you look at your dividend policy and maintaining the dividend going forward that I would say the regulatory lagged between how the cash flows move?

We certainly look at the timing of our cash flows. As you know with the MERP project, which is the billion-dollar project we do have approval for, we'll receive cash recovery in '06. The other key thing there, too, and this will apply to the coal plant if and when we get approval, is that we'll have regulatory assurance that the cash is coming. That's a very important factor as well when you decide on your dividend policy.

Right. So assuming you have that, even though there may be a couple of years lag, you should -- you would still be comfortable with your dividend payout policy.

Our goal is to produce the financial results. And certainly the MERP and the coal project play into that, that would allow our board to vote for modest dividend increases.

Okay. Thank you.

Okay.

Your next question is from Paul Debbas with Value Line.

Hi, you mentioned higher capitalized interest earlier in the call as one of the reasons for your lower overall interest expense, and I wanted to know if you have any estimate of what you would expect capitalized interest and AFUDC taken as a group to be this year?

We probably, unless somebody has that answer, we'll probably have to get back with on you that one. It's about, I think it's roughly -- the variance is roughly about a penny.

Okay. And if I could ask another quick question. Is the decline in gas usage, is it just elasticity?

We think so. One of the things that happened in Colorado, and it's a reason why we're recommending to the Commission we go to a monthly reset mechanism, is that we had -- we are currently on a six-month reset. And given that rapid spike and rise in gas prices, it really created some rate shock for our customers. And I think it's human nature to adjust pretty dramatically when you have such a shock like that. So I -- you're right.

Thank you.

The next question is from Elizabeth Parrella with Merrill Lynch.

Thank you. I wanted to ask, Ben, you indicated a week or two ago you that had discovered an issue with some gas meters in Minnesota. And I think you were indicating that you might accrue for some potential exposure there in this quarter. I was going to ask if you can quantify that for us.

Yeah, we can. We've accrued $2.4 million, which is our best estimate based on where we are. We continue to test the meters. And, actually, Elizabeth, we're finding the error rates as we go through the testing are less than the original testing indicated. However, we're not done with the testing. But I think 2.4 is pretty good estimate.

That was all in this quarter?

Yeah.

And that's a pre-tax number?

That's a pre-tax number.

Okay. I would like to ask, going back to the short-term wholesale trading margins, I wanted to ask again, the contract that you referred to, it was signed in the third quarter of last year.

Uh-huh.

Was that in effect for the entire third quarter of last year?

You know, I don't know when it was signed in the third quarter. It did have a positive impact for the second half of the year, not only in short-term margins but there was some impact on the proprietary side as well. For the 2004 it was roughly worth about $17 million of margin to us. And, again, this was in response to some drought conditions, which have turned around.

And I'm sorry, the 17 million was for what period?

First quarter of '04.

Okay. I mean is that something that we can sort of try to use to gauge what the 2003 benefit might have been? Or would there have been some real seasonality that Q1 might have looked --?

I think it's close. I think the amount is a little less. The number's probably closer to $11 million in '03.

For all of the three?

Yeah.

Okay. Okay. Thank you.

Next question is from Vedula Murti with Zimmer Lucas.

Good morning Vedula.

A few things. One, looking to your earnings release here, can you talk a little bit about the electric department earnings test proceeding? And you indicate here about the potential exclusion of certain interest costs and, you know, you don't anticipate that will end up having a negative effect? Can you elaborate a little further or that?

I can elaborate some. We're preparing our response to that now. Clearly we have a different view, but let's look at what the press release says. I think it's -- the OCC is a $7 million disallowance and the staff is recommending 12. That's associated with an earnings test in 2002. And, even at those levels, there would be no refund in 2002. There was no earnings test in 2003.

And going forward, if you look at what we earned on a regulatory basis, I think it was a little bit over 9% for 2003. So don't anticipate that that would create any refund mechanism for '04 either.

All right, so even if you excluded this, you still wouldn't be crossing (indiscernible) kinds of ROE thresholds here?

Certainly not for '02 and '03, and we don't expect for '04 either.

Okay. Going back to Page 5 of your release here, you go through the margins. I'm wondering, given that the actual retail sales are up 2.5% here, why gross margins have not shown, or are basically flat?

For the quarter?

No, year-to-date.

Some of the same items apply that I talked about in the first quarter -- for the second quarter. You just have to go through that list. I mean the big driver is purchase capacity cost, which, remember, we put the rider in place in June of this year. So we didn't begin receiving recovery until then.

So, I think that explains the bulk of the $15 million variance that we list there. We talked about the renewable development fund, the quality-of-service obligations. We do have some unfavorable weather impact. I think it's just, you know, the cumulative impact of all of those items.

All right. Thank you very much.

Your next question is from David Grumhaus with Copia Capital.

Good morning. Two questions. One, with regards to the depreciation, just so I'm making sure I understanding this, year-to-date that's down about 42 million. And I think you had expected about an $18 million improvement in Minnesota and $20 million in Colorado. Because you took the Minnesota in the fourth quarter last year, is that going to reverse itself?

Well, what we're expecting for the full year is a 1 to 2% decline from '03 levels.

Okay.

And I think you hit upon the point that I was going to make. In the fourth quarter of last year, I believe we took a $30 million adjustment associated with the Prairie Island extension at NSP.

Okay. So that will reverse itself out to some degree in the third and fourth quarters, especially the fourth, it sounds like.

Yeah, getting us back to the level I mentioned.

On the investments, the MERP plan and the coal, just so I'm clear how you are going to recover this. You will get AFUDC on these cash investments as you make the expenditures, and then you said that you would start getting a cash return. I assume that's also an earnings return beginning in '06.

Yeah, you get an earnings pickup from the AFUDC in the '05 timeframe. In the case of MERP, we will get a cash – a rider mechanism that will be place that will give us cash recovery based upon the AFUDC amount. We'll receive it in the form of cash and not just have booked earnings. We have similar mechanisms proposed for the Colorado coal plant.

Okay, and you will start seeing the actual cash then in '06?

For the Colorado coal plant?

For the MERP plant.

For the MERP plant, that's exactly right.

And the coal plant, when it comes on line or...?

No, I mean it's a little bit -- first of all, it's in the proposal stage.

Right.

We've proposed a number of things there. We want -- we are on record as saying that we will file a rate case in '06. Recall that's when a number of our riders expire.

And we will address -- what we want to do at that time is address the imputed debt issue. We want to address that beginning now by funding the initial capital expenditures, which aren't real onerous in '05, with 100% equity in the AFUDC calculation to start to push that metric up. Then we're proposing a cash rider recovery going forward, similar to the, what I described in MERP.

Okay. Great. Thanks for the time.

Thank you.

Your next question is from Daniele Seitz with Maxcor Financial.

Good morning. I wanted to know, I know you, I just think you have given the, what you estimate, the AFC number will be next year and this year. Do you have any -- should I just take, you know, Cap Ex and then the average cost of the capital?

Well, I think we do break out what the AVC (ph) equity component is in the press release. You probably – (multiple speakers)

Okay. For next year, do you anticipate it to grow sizably next year?

You know, we're going to have to work through that. Obviously, our capital expenditures, if you look at what we're planning, are going to go up. That will be one of the factors we look at when we put together '05 guidance.

Okay.

We don't have an estimate for that at this point.

Okay, and to finance this construction project, do you anticipate to start issuing equity in the near future?

No.

Are you waiting for the agreement from both commissions to start?

Well, we believe our cash flow is sufficient. And we've presented this at some conferences previously, so can you find some of the information on our website. We believe we have sufficient cash flow in the next several years not to have to go to the equity markets outside of just our normal [short] programs.

Keep in mind that we're receiving a significant tax benefit of about $125 million a year going forward associated with the worthless stock deduction we received for the NRG investment. We have strong cash flow from operations, so we're pretty comfortable being able to stay out of the equity markets.

And assuming that you obtain a return -- construction, sort of work in progress, would you -- have you estimated roughly how much the rate increases will be, starting in '06, when these transformed into revenues/

For which particular project?

For the MERP, for example, and, I guess, since it will start also later on, for Colorado.

I think for the MERP project, I think it's somewhere -- I'll ask Dave Sparby to correct me if I'm wrong, but I think it's 4 to 5% roughly. I think that's a similar amount for the coal plant as well.

And this will come up in '06 mostly, you anticipate?

For the MERP project, we begin receiving a cash rider in '06. Yeah, you would start to see an impact right away. I don't think it's at the full 5% level.

Uh-huh.

(indiscernible) stays in, which is one of the benefits of pay as you go, if you will.

Right. Right. Does AFC -- will continue, but on almost a slot basis as you will (technical difficulty), touching up on the one year of construction? Is that how you visualize it over the long-term?

Yeah, I think there will be a one-year lag.

Right.

-- because we would true it up. What we did in '06, we'd collect in '07, if that's what you're referring to.

Yeah, right. Just to get a picture of the programs being implemented. Thank you very much.

You're welcome.

Our next question comes from Michael Worms with Harris Nesbitt.

Thank you, good morning. Two questions for you. One, I believe you indicated that O&M expenses for the year will be kind of flat with last year. And yet, I guess you have to at some point start to, or continue to spend money on improving reliability. And you also talked about the extended nuclear outage later this year. Can you kind of help me understand how O&M is kind of flat for the year under those circumstances?

Well, the -- we have, by the way, started spending on those increased reliability initiatives. So you're already seeing that continue to believe will be flat. You know, we are, I think, very good at controlling costs. We're going to make sure we put the right amount of money into our plants and into our distribution system and into our programs to make sure we have customer satisfaction. And we're pretty aggressive looking for cost improvements in every other area.

The one thing, as I mentioned in the call you that have to keep in mind, is in the fourth quarter of last year, O&M went up to $431 million. We don't anticipate that happening again in the fourth quarter of this year.

And you also mentioned the outage. The costs associated with that outage are largely capital in nature verses O&M in nature.

Okay, fair enough. Secondly, with regard to the Minnesota plant in '06, are the recovery of these costs -- is there any kind of regulatory review? Or how does this ultimately play out in terms of prudence and things like that?

Well, the way that works is we have got a bandwidth. If we come in at budget, the regulated return is 10.86. If we come in under budget, our return improves to 11.47. If we come in over budget, the return can fall down to -- I believe it's 9.97%. So there is a bandwidth already established that gives us an incentive to bring the project in on budget.

Great. Thank you very much.

Our next question is from Paul Ridzon with KeyBanc/McDonald.

Just asking for more detail on the Canadian contract -- when you put it on and when it rolls off. Is that put on in the third quarter? Was it a one-year contract?

It was basically about a six-month contract, it's a shoulder-month contract put on in the third quarter. I don't know the exact date in the third quarter. And it rolled off at the end of the first quarter of '04.

We're done seeing that benefit.

Yes.

Then, the 125 million annual NRG tax benefit, how long will that -- how long will you enjoy that?

The total benefit is about $1.1 billion, and we're about halfway through it. By the end of this year we'll be slightly more than halfway through. You roll it out, $125 million a year, I think, takes us to the end of '08.

The strategy is to kind of backfill that drop off with regulated return on new investment.

Well, we're going to use that cash to help fund some of the expenditures I talked about. And then whenever -- you know, we have a return associated with those expenditures. So the answer would be yeah.

Very good. Thank you.

Once again, ladies and gentlemen, if do you have a question, press star then the number 1 on your telephone keypad. We have a question from Neil Stin (ph) with John Levin (ph).

Good morning. I just had one question. Where do you stand at the FERC with getting your market-based rate authority renewed? When would you go through that process?

The filing is due February of '05, and then they would have to set the timetable from that point going forward.

Have you thought about the FMA (ph) screens and how you would do if you applied those screens?

We're in the process of applying those screens. You know, we haven't concluded where we would be on that yet.

Okay. Thank you very much.

Thanks.

We do have a follow-up question from Vedula Murti.

Hi. I just want to make sure I understand in terms of the NRG tax benefits. You're saying we should be getting $125 million a year and that will run annually through 2008? I thought that was only going to be running, I think, through the rest -- through 2006.

No, Vedula, we've -- we received a 2-year carry-back of $328 million. We received that in March of this year, and used that to fund the settlement payment to the NRG and its creditors.

We're taking a carry-forward benefit of about $125 million a year. We already had some of that in '03, so I think we're literally at the halfway point right now. So, you know, which means we have about $550 million more to go. And, you know, that's -- you just do the math.

Okay. And secondly, in terms of Colorado and Minnesota, in Colorado you said you would be having a rate case in '06 and that there are -- several riders have expired at that point in time.

Uh-huh.

Can you quantify, perhaps in aggregate, these riders and whether this is a period, any kind of mismatch in terms of those expiring versus the completion of the rate proceeding?

There are a number of riders and I don't have all the impact of them. You know, we talked about the PCCA rider. There is an AQIR rider; there is the ECA mechanism, incentive mechanism. I think probably the best thing to do, is get together with Dick Kolkmann and Paul Johnson and I'll let them run you through that.

That's fine. In terms of Minnesota, besides the MERP, do you anticipate a rate filing that will cover full cost of service for 2006 in Minnesota as well?

Well, we under-earned in '03. We're in a moratorium through the end of '05. What we'll do is review the situation at that time and make a decision.

Thank you.

With that --

-- I guess we have one more question.

You have one more question from Greg Kolinski (ph) with Alliance Capital.

I apologize; I jumped on the call late here. Can you guys tell us what operating cash flow, funds from operation and Cap Ex were for the quarter?

I think operating cash flow was $700 million. Cap Ex, do we have that? $500 million in Cap Ex.

Okay. Funds from operation, you have a number on that? FFO?

Well, we had $700 million cash from operations. If you want to do the funds from -- the FFO number, I haven't done that calculation. Just call Paul or Dick and they'll give it to you.

Okay, great. Thanks a lot.

Thanks.

With that, I will just turn it back over to Ben for his concluding remarks.

I want to thank everyone for participating on our call. I look forward to seeing many of you in the conferences we plan on attending in the future. If you have any follow-up questions, please feel free to give Dick Kolkmann or Paul Johnson a call and they'll help you. Again, thank you.

This concludes Xcel Energy second quarter 2004 earnings conference call. Thank you for your participation, you may now disconnect.