埃克西爾能源 (XEL) 2009 Q4 法說會逐字稿

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 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's 2009 year-end earnings release conference call. I'm Paul Johnson. With me today are Ben Fowke, President and Chief Operating 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, and Mike Connelly, Vice President and General Counsel. Excuse us for that. Today, we plan to cover our 2009 results and accomplishments. 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 our comments may contain forward-looking statements, 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. 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 $1.46 per share in 2008. As you may recall, in 2007, we reached a settlement resolving our 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 the legal costs associated with our claims against the 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 reported 2009 ongoing earnings of $1.50 per share compared with $1.45 per share in 2008. We are proud to deliver 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 a decline in electricity sales due to a 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. The resolution of these cases, as well as two FERC rate cases, also provides greater regulatory certainty as we begin 2010. We have a relatively light docket this year with two smaller rate cases pending. A Minnesota gas rate case and a FERC wholesale rate case in Colorado. In addition, we plan to file a wholesale case and a retail reopener 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 now expect this plant to go in service in February. Comanche 3 will deliver tremendous value to our customers with a construction cost of approximately $1,500 per KW. I'll now turn the call over to Dave Sparby who will walk you through the year-end results and also give you a regulatory update. Dave?

Thanks Ben, and good morning. Let's now 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 rising costs which was partially offset by new electric rates that went into effect last July. At NSP-Minnesota, earnings decreased by $0.01 per share. The decline resulted 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. At 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 increases in Texas and New Mexico and the resolution of fuel cost issues. Finally, our investment in WYCO, a 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 the MERP rider all served to increase retail electric margin by a total of $113 million. Increases in the conservation revenue, however, are largely offset by higher conservation and 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 $26 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 costs which increased $90 million. The increase was due to performance-based incentive compensation expense, active healthcare 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 the 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. These and other items were partially offset by lower consulting costs and lower bad debt expense. Now for the year, depreciation expense decreased by $10 million. The decrease was largely the result of regulatory decisions which extended 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 an 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. As a result, 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 1st. 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-in of new rates reduces the impact on our customers and will have minimal earnings impact on PSCo or Xcel Energy.

Now last June, we filed a request to increase Wisconsin retail electric rates by $30 million, based on an ROE 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 a 10.4% ROE and a 52.3% equity ratio. The major differences between the amount requested and 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 costs. 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. The 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%, an 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.

Now 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. Now, before we go to Q&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 will open it up for questions.

Thank you. We will now begin the question and answer session. (Operator Instructions) Our first question comes from the line of [Ali Ahga] from SunTrust. Please go ahead.

Good morning.

Good morning.

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 allowed. Would you say that the regulatory lag is pretty much eliminated now? Or how would you characterize 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've managed to reduce it, and we see ourselves continuing to reduce that lag further over the next couple of years.

Okay. So you would not say that you're pretty much earning authorized returns across the portfolio yet? That there is still more to be done?

Yes. We'll earn close to 10% across the portfolio. We do have some of our [OPCOs] with more opportunities to earn closer to that average. And we see ourselves continuing to make progress in that regard.

I see. And there, just to be clear, the 10% you expect would be for 2010?

Yes.

And what was the number for '09?

It was between about -- in the 9.6% to 9.7% range.

And 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 will 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.

I see. Thank you.

Thank you.

Our next question comes from the line of Daniele Seitz with Dudack Research. Please go ahead.

Thank you. I was wondering, it seems that the O&M increase continues to be at the 6% and 7% range. Could you explain if this increase is coming from benefits increases? Or if it is -- it includes also the effect of Comanche 3?

It reflects really 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, Daniele. And 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, and 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 BRIGO project which is our Buffalo Ridge transmission project so we continue to add rate base and operating plan.

Yes. And 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 also see some 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.

Great. Thanks.

Our next question comes from the line of Jonathan Arnold with Deutsche Bank. Please go ahead.

Good morning.

Good morning.

I was hoping to ask on sales trends. It seemed 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 may be 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 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. We're seeing more of that come back in the C&I class in 2010, and of course, part of that is because sales retreated a little further on the C&I than on the residential class. 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.

Thank you.

Our next question comes from the line of Angie Storozynski, MacQuarie Capital. Please go ahead.

Thank you. Two questions. One about your Comanche 3 plans. How should we think about it? You said that the plant should be online in February. Any estimate as to -- will it be the beginning of the month? Or you simply don't know? And should we think that the increase in revenues will be prorated depending on when the plan actually goes on -- online?

Angie, this is Ben. We -- the plant has had a few startup issues, primarily with some of the welds and the boiler tubes, but we think we have that fixed. And we anticipate it will probably be in service in the middle of February. Of course, we will update that. It could be earlier. It could be later. That's the best estimate we have right now. As far as the revenue, as soon as it goes in service, we pick up the piece of the revenue that was associated with Comanche 3 which we are not receiving right now. With that settlement, as you know, 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 $1,500 KW price. 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.

Okay. And also, any updates regarding your environmental CapEx? Any -- 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.

But given the fact that there seems to be at least a couple of distressed wind assets in the region, you still prefer 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. They are economic as in perspective of our resource acquisition plan.

Okay, thank you.

Our next question comes from the line of Tom O'Neill, Green Arrow. Please go ahead.

Good morning. I just had a question regarding 2010 guidance relative to 2009. I guess what strikes me is that 2009 on a weather-adjusted basis is $1.55. 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.

Got it. Okay. Thank you.

Our next question comes from the line of Paul Patterson, Glenrock Associates. Please go ahead.

Good morning. Can you hear me?

Yes.

I wanted to touch base with you on two things. First of all, the Minnesota attorney general along with a state senator has introduced legislation with respect to the riders or what have you. The interim increases and what have you. Do you feel that legislation has any lags? Or can you give some perspective as to that? As I recall, we also saw something in Colorado a year or two ago where they were investigating something similar. They apparently had some sort of issue also associated with automatic -- or not automatic -- but more abbreviated rate increases.

Sure. In Minnesota, what we have is a regulatory framework that matches up very well with the state's 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 detail this coming session.

Okay. And the situation in Colorado -- did that -- 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 asked us to address those in a series of rate cases. We actually did that. And I think there's a comfort that has 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. So I think that, in essence, by moving through this series of rate cases, we've dealt with those issues.

Excellent. And then finally on Comanche 3, the problem that you are encountering with the start-up, those are basically just start-up issues? We shouldn't -- you don't have any expectation that those will be operational issues? Is that correct?

You mean, things that we'll be living with for some time?

Yes. The steam tube problem. I'm not really clear exactly what it is. There's some mechanical issue there. Is that something -- ?

We're fixing it, and we're fixing it right. And the vendor that was responsible. And these were factory welds, has stepped up and is fixing them. This isn't going to be some performance or operational issue that plagues us post-start-up. Very much on top of that, actually.

Great. Appreciate it. Thanks a lot.

Our next question comes from the line of Neil Kalton, Wells Fargo Securities. Please go ahead.

Good morning, everyone.

Good morning, Neil.

Just a question on transmission. We've seen it in some other regions. Projects getting pushed back because of what is going on with the economy. And I wondered if you could comment on your portfolio projects. Are you seeing there any change in the thought process in terms of timing? Or things pretty much moving along as expected 12 to 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 continue 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. And when you look down to SPS, whether it's the Seven Rivers to Pecos project, or any of the others, we also tend to make good progress. That's moving along as we expected.

Would there be any concerns if loads didn't do what you thought it was going to do this year? Might that threaten some of these projects in terms of time frames?

Neil, you kind of faded out, but 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.

Thanks very much.

(Operator Instructions) Our next question comes from the line of Dan Jenkins, State of Wisconsin Investment Board. Please go ahead.

Good morning.

Good morning, Dan.

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 use as a guide there? Or how should we think about the ROE for that rate case?

None stated, Dan.

Okay. As far as your Minnesota case, what was the -- you filed for an 11% ROE. What was the last allowed ROE for the Minnesota gas?

That was 9.71%, when our last 2007 natural gas case.

Okay. And 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 will be more growth for example in Colorado C&I than the remaining C&I classes. Although it's not a material amount relative to what we're seeing in other OPCOs. Probably less in the other OPCOs in that class in Wisconsin. There 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.

Okay. Thank you. That's all I had.

Our next question is a follow-up question from the line of Daniele Seitz. Please go ahead.

I apologize. I was wondering if you had a number for the amount of returns you got through the riders in '09? And how much did you assume for 2010?

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

Great, thanks.

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'd like to listen to a replay of today's conference, please dial 303-590-3030 or 1-800-406-7325. The access code is 419-5322. ACT would like to thank you for your participation. Have a pleasant day. You may now disconnect.