ALLETE Inc (ALE) 2009 Q1 法說會逐字稿

Good day, everyone, to this conference call announcing Allete's first quarter 2009 financial results. Today's call is being recorded. Your lines will be muted for the presentation, and then we will conduct a question-and-answer period.

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This conference may contain forward-looking statements within the meaning of federal securities laws, including statements concerning business strategies and their intended results, and similar statements concerning anticipated future events and the expectations that are not historical facts. These forward-looking statements are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. The forward-looking statements in the earnings release distributed this morning reflect management's best judgment at this time, but all such statements are subject to numerous risks and uncertainties which could cause actual results to differ materially from those expressed and/or implied by the statement therein. Additional information concerning potential factors that could affect future financial results is included in the Company's Annual Report, and from time to time in the Company's filings with the SEC.

At this time, I would like to introduce the Chairman, President and Chief Executive Officer, Mr. Donald J. Shippar. Please go ahead, sir.

Thank you. Good morning, everyone.

As you know, we reported our first quarter results this morning, $0.55 per share compared to $0.82 a year ago. The year-over-year comparison was affected by a couple of nonrecurring items, which our CFO, Mark Schober, will detail in a few moments. During the quarter, we mitigated the impact of lower margins from our industrial customers by re-marketing our surplus energy to other power suppliers. Based on what we know to date, we expect total 2009 demand nominations from these customers will be at least 40% lower than in 2008. We estimate we have mitigated 85% of the annual earnings impact through our re-marketing efforts. Now, these efforts are ongoing and together with operating expense reductions, our goal is to offset the remaining earnings exposure for this year. Demand nominations from industrial customers for the final four months of 2009 will occur during late summer.

On April 3rd, the Minnesota Public Utilities Commission deliberated and voted on our $40 million retail rate increase request. Based on their hearing, we estimate final rates will be increased by $21 million annually. The MPUC allowed Minnesota Power a 10.74% return on equity, and a 54.79% equity ratio. We expect to receive a formal written order by May 4th.

Primarily because of the results of the retail rate filings, we have revisited the high end of our 2009 earnings guidance. Allete expects earnings per share to be within a range of $2.10 to $2.25 per share, on net income of $67 million to $72 million. Our guidance excludes the 2008 portion of the interim rate refund, which Mark will comment on in a minute.

I'll call on Mark now, and I'll have additional comments before we take your questions.

Thanks, Don, and good morning, everyone.

We filed our 10-Q this morning, and I encourage you to refer to it for the details of the first quarter. As Don mentioned, we reported quarterly earnings per share of $0.55 on net income of $16.9 million. For the first quarter of 2008, we earned $0.82 per share on net income of $23.6 million. The difference between this year and last can basically be explained by three items. First, due to the issuance of common equity over the past year to pre-fund our capital expenditures program, we had about $0.04 per share of dilution compared to the first quarter of 2008. Secondly, last year's first quarter included a $3.7 million nonrecurring net gain, or $0.12 per share, from the sale of securities held within our employee benefit plans. And finally, this year we recorded a $3.4 million after-tax charge equivalent to $0.11 per share, which represents the portion of rate refunds on interim rates collected between August 1st and December 31st, 2008. If you factor out these three nonrecurring items, first quarter 2009 earnings per share would be similar to last year.

Net income for our regulated operations segment was $17.7 million this quarter compared to $20.1 million last year. The decrease is primarily due to the $3.4 million rate refund related to 2008 that we booked this quarter, higher depreciation expense due to a growing asset base, and higher interest expense from the funding of our capital expenditures program. We expect to invest more than $1.2 billion in the regulated operations over the next five years.

Total operating revenue for regulated operations decreased $12.2 million from 2008. Fuel and purchase power recoveries were $13.5 million lower than last year. We also recorded estimated rate refunds for the August 1st, 2008 through March 31st, 2009 time period. Higher interim retail rates net of current year estimated refunds increased revenue by about $4.8 million, and higher FERC-approved wholesale rates increased revenue by $2.2 million.

Total retail and municipal kilowatt hour sales were down 18% from a year ago, but total kilowatt hour sales were about the same. Industrial sales were down primarily due to reduced sales to our taconite customers, but were offset by sales to other power suppliers.

Equity earnings from our investment in the American Transmission Company were $800,000 higher than last year, because of our growing investment balance. At the end of the quarter, we had an equity investment balance in ATC of $79.7 million.

The investments and other segment recorded a net loss of $800,000 compared to a net income of $3.5 million a year ago. The $3.7 million nonrecurring gain last year is the main reason for the difference. Results were similar year-over-year for BNI Coal, and Allete Properties recorded a $1.1 million net loss for the quarter compared to a $500,000 net loss a year ago.

The effective tax rate for the quarter was 39% versus 37% for the first quarter of 2008. We do expect the effective tax rate at year end will be 36%. Our balance sheet is in good shape, with $98 million of cash and a 43% debt to capital ratio.

Don?

Thanks, Mark.

We first saw two main challenges as we began 2009. First, how would we respond to reduced sales to our taconite mining customers, and second, how would we manage our way through the regulatory process with respect to rate increase requests? We feel we have responded well to the downturn in the taconite industry. As I mentioned earlier, we have wholesale power agreements in place for 2009 that will offset about 85% of the currently expected annual financial impact from lower sales to our taconite customers. Minnesota Power's competitively-priced electricity and its transmission access have worked to our advantage. Our goal is still to completely offset the impact by continuing the re-marketing efforts and by implementing expense reductions.

With respect to regulatory rate relief, we're satisfied with our wholesale rate results and with the retail rate increase at Superior Water Light & Power. The $21 million annual increase from Minnesota Power's current retail rate case is less than we built into our original earnings guidance. We will analyze the MPUC's written order when received, and determine our next steps. We do expect to file for additional rate increases as our significant capital expenditures program continues over the next several years.

Looking forward to the rest of the year, we expect our investment in ATC will grow by $5 million to $7 million from 2008. Year-to-date through April, we have already invested about $3.5 million. We intend to maintain our ownership percentage in ATC by participating fully in future capital calls.

Minnesota Power's also making progress with its North Dakota wind initiative. We currently own or lease land in North Dakota, which has some of the best wind energy potential in the United States. Minnesota Power announced earlier that it intends to build several hundred megawatts of wind generation in North Dakota over the next several years, and transport that renewable energy into its service area over an existing DC transmission line that we are in the process of acquiring. We plan to file for Minnesota regulatory approval on the acquisition of this asset soon, and expect to close on the $80 million purchase of the line later this year.

The first phase of the wind generation development will be a 75-megawatt project, with about half of the turbines in service during 2010 and the remaining half in 2011. We filed a current cost recovery petition with the MPUC on March 23rd for this first phase. As we develop the wind generating facilities, we will gradually, over a number of years, reduce our take of coal-generated energy from the Square Butte plant. At the completion of the North Dakota wind initiative, we expect to meet the Minnesota state renewable energy mandate of 25% by 2025.

Now at this time, I'll ask the Operator to open up the lines for your questions.

Thank you.

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We'll take our first question from Larry Solow at CJS Securities.

Hi, good morning, guys.

Good morning, Larry.

Good morning.

Could you maybe just give a little color, I don't know how much quantification you can, but on just how you're kind of making up -- I guess it's kind of like a $15 million revenue difference on the lower rate case, and maybe just help me understand it a little better? I guess it's kind of a rate of return, so if it's a lower rate of return, I guess it implies that your costs should be lower. I guess that's part of the makeup. But can you maybe give me a little more color on that?

If I understand your question, Larry, what we're trying to do to make up the difference between our interim rates and the final rate order?

Right, and how you're kind of still -- you bumped down guidance a little bit, but it's still kind of in the same ballpark.

Couple things going on there, we did reduce guidance significantly, about $0.15, so that takes up a significant portion of it. And then looking forward, there certainly could be some items for reconsideration here. We need to see the final order before we decide on where we're going on the individual items.

Couple of other things that Don kind of hinted at, as we look forward, though, we are looking hard at our O&M costs, and looking to take out costs as appropriate. We are looking at incremental sales of energy as those opportunities come forward. And then some of these costs that our regulators threw out or did not allow our costs that are really accounting-driven, so we can change our accounting to match what our regulators want, and so some of the adjustments will not have a bottom line impact. So through the combination of those items, that's why we're maintaining our guidance at least at the low end at this point.

Right, and then I know you guys expressed confidence, you know, in 2010 and beyond for solid growth on the utilities side. And there's -- does kind of the lower rate case, does that dampen your enthusiasm at all, or how does that come into play?

Well, I think the 2010 and beyond is going to be more driven by just the economy. I mean obviously we're hoping for, I think like everyone is, a recovery to kick in here perhaps later this year, and certainly into next year, and that the taconite production will start to come back. So I would say it's much more driven by that than, if you will, the results of the rate case.

Okay, and it doesn't sound like it I guess -- I know you mentioned you still plan to spend $1.2 billion over the next five years, so it doesn't sound like you've really curtailed your -- at least your CapEx growth expectations.

We've made some adjustments to our CapEx, Larry, but it's really within that timeframe. So we pushed things out a little bit, but overall the total CapEx is right about where we planned.

Got you.

We're incurring it a little bit later.

Got you. Then last question, any anecdotal evidence? I think US Steel reported this week, and I think they mentioned maybe that the inventory at the steel makers has certainly dropped and, you know, any color, anything you're hearing from your company as opposed to -- you know, for their last trimester nomination?

Well, nothing obviously formal, and of course they won't give us their nominations until later this summer. But I think you hit on probably the biggest issue, is inventories do seem to be declining, and that's certainly a good sign that at some point they will have to look to replenish those inventories.

Okay, great. Thanks a lot.

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We'll go next to Eric Beaumont at Copia Capital.

Good morning, guys.

Good morning, Eric.

Just wanted to touch base on a couple of things. One, on the amount of equity, I know you had one view in December, and if I just kind of look at the numbers that you gave for net income in your guidance, it appears that you're either going to be issuing later or less shares than you might have initially thought. Is that accurate?

That's accurate. A couple things going on. As I mentioned a moment ago, we are deferring it and pushing out some of our capital expenditures, so because of that, we will be issuing less equity, and I don't have an exact number, and the equity we issue will be later.

And so the equity, in combination with potential cost savings and getting some of the energy contracts, all rolled together to help defray some of the loss demand charges, at least on an earnings per share basis?

That's correct, Eric.

Okay. And kind of going forward, you know, you had some good potential growth in the future off of additional plant for taconite expansion. Is that still looking on track? Has that shifted? Any color you can give around that?

Well, I think it probably has shifted some, in that I think some of the plans that the -- that the owners had have probably been pushed out. We don't -- we don't see any indication that they will be totally abandoned or canceled, but I think it's fair to say that they probably have moved those out, and they largely will be driven by recovery generally in the steel industry.

Okay. So I guess just as we were thinking, kind of there's going to be more spending towards 2011, and it seems that spending's going to be there, but likely shift in maybe a year or so, would be the current expectation at this point?

I don't know about the year or two. That's a hard one for us to gauge, but I think safe to say beyond 2011.

Okay. That's helpful. Thank you, guys.

We'll take our next question from James Bellessa from D.A. Davidson & Co.

Good morning.

Good morning.

The guidance range, the top end has been shaved off by $0.10, yet I heard Mark say in the first caller's response that there was a $0.15 reduction. Can you explain the difference?

It wasn't $0.15 cents, Jim. I think where they are going is our interim rates that were in effect were like $35 million, and the final rates, at least with our interpretation of the order, is $21 million. So the question is what are we doing to make up the difference between interim rates and the rate order as we understand it today.

And was the rate order a $0.15 impact?

The rate order, at least our interpretation of the vote that occurred on April 3rd, allows us [now] a rate of $21 million. What we had in our estimate that we gave you was interim rates for the full year which were at $35 million.

Jim, we may have confused -- I think Mark did say $0.15 off the top. It was actually $0.10 off the top of the guidance range. We went from the $2.35 on the top to $2.25.

Very good. And then you've indicated that you've mitigated the taconite downturn by 85% of the earnings impact. That seems like the same wording that you used one or two months ago when you explained this to us. Have you not made any additional sales, forward sales or contracts to be able to mitigate further amounts?

No, Jim, that number -- it's changed a little bit, but we're essentially in the same spot we were when we talked about this a couple of months ago.

Okay.

And what's driving that is we have sold the power that's available today and, as Don mentioned, what we need to look forward then to is what the nominations from our large power customers, what they come in at for the last quarter of the year. So once we get a better handle on that, then we'll look to bring more power to market.

Perusing the 10-Q, I saw where you had some of these contracts extended to 2010.

Some of the sales contracts?

Yes.

Yes, we had a couple that do go over into 2010, yes.

And then in the investment and other segment, the interest expense jumped materially. It was $1.4 million in that segment. Is this -- is there an aberration, or is this the run rate going forward?

I belief that would be the run rate going forward. We talked a little bit about hat as we came out of 2008, Jim. That's just the way we allocate interest amongst our business segments now. So that will be -- should be the ongoing run rate.

Thank you very much.

Thanks, Jim.

A question from Po Cheng at Longbow Capital.

Good morning. Can you elaborate on what assumptions are going into your estimates when you say the 85% has been mitigated? Is that based on the nominations year-to-date and some outlook for the last quarter, or is there -- just based on purely actual nominations?

Well, it is based on year-to-date and a projection of what we think could be the nominations for the last four months of the year. We -- we clearly don't know what those nominations are and won't know what they are until later on this summer, but we do have an internal projection on that, and so we're using that as our basis for the 85%.

And then on -- a follow-up on the contracts that roll into 2010, can you say how much, or quantify in terms of megawatt hours, what you have contracted that roll in?

Yes, it -- right now it's -- they are relatively modest. They are a pretty small portion of our overall energy portfolio.

Great, thank you.

Thank you.

We'll go next to Brenda [Neem] at Levin Capital.

Hi. It's actually Neil Stein. I had a couple of questions.

Hi, Neil.

First, I didn't catch the explanation. You had mentioned less equity for this year, and I was wondering if you could clarify the exact reason why?

We'll be issuing less equity this year, and it's really what's happening in the capital markets. As we looked at our capital spend, we looked hard at our capital spend, reduced it where appropriate, and then we're also deferring some of that capital spend to later in the year, so -- or into later years. So because of that, there will be less equity issued than we originally planned in 2009, and those equity issuances will be later in the year than we originally planned.

And then maybe you'll also be maybe needing more equity in later years, to the extent you're deferring some CapEx from this year into the future, is that --

That would be correct.

Okay. And you haven't quantified exactly how much equity you're going to issue this year?

No, sir.

And would that be through your dribble program, or would you do a marketed offer?

No, it would be through either our dividend reinvestment program or our dribble program.

Got it. And then I was hoping for some more details on some of the mitigating factors that are helping to offset the adverse rate case outcome relative to the interim. You mentioned you're looking for some reconsideration?

We may be looking for some reconsideration. Again, that depends on once we get the final order, we need to analyze that and decide where we want to take some of those issues.

Okay.

Another item in there that was a significant item in the difference between the final order and the interim was [off-system] sales credits. And so, you know, we feel some of that power that isn't going to be consumed on our system can be sold into the market, so that will help us make up some of that deficit also. So, you know, that will be a considerable factor.

And then you also mentioned O&M reductions.

Yes.

Is that a major part of I guess how you mitigated --

It was part of it. We're looking at expenses across the organization, contractors, outside services, employee levels, those kinds of things. So, yes, that will certainly be a part of it.

How much O&M reduction are you including in your guidance?

We haven't put a specific number on that.

Okay, and the type of O&M reduction you do, is it more sort of your -- could we think of it as a one-time expense reduction, and then you'll have to incur these expenses eventually, or you could sustainably reduced the level of O&M?

It would be a combination. Again, we're looking at all of our outside services, our -- the use of contractors, our employee levels. So some of it will be essentially one-time, but others -- some of them will certainly be longer term.

Okay. Thanks very much.

We'll go next to Bernard Horn at Polaris Capital.

Yes, good morning, and got a couple of questions. First is, I know we've talked about the re-marketing of the power, but have you discussed how much on a per kilowatt hour basis you've re-marketed that? And does it make up for what, you know, you were selling it to the taconite producers for?

Well, I think within that 85%, I mean we can -- we can sell, if you will, the amount of energy that our customers are taking into the market, that are -- actually selling the energy is not, is not a problem, it's really the price. So the -- where we're saying the 85% to date in essence is really the difference between the price we would have gotten from the retail customers and the price we're getting in the wholesale market.

Yes, okay. So I wasn't -- it wasn't clear from what you explained whether the 85% simply was what you had to re-market, and because they hadn't released or nominated for more energy, that that was going to make up for the difference, so I wasn't quite sure. So it sounds like the 85% of -- does that mean it was, like, 15% less on a kilowatt hour basis as to what you could have sold it to the taconite producers for?

We look at that 85% as the overall earnings impact. So it's a combination of the power that we can bring to market, and obviously then the pricing that we can bring it to market at. So it's a combination of those two. And to date, we have been able through the first quarter, the power we've brought to market has been at comparable prices that we would have sold it to -- to our large power customers.

Okay. So the -- those power customers, it would be my opinion, or my assumption, which may be incorrect, that the power producers -- the large power consumers would get a better price than perhaps what you could re-market it for at the -- at the retail level. Is that incorrect?

Well, yes, I mean the price that our retail customers pay obviously is set by our regulators, and what we bring to market then varies significantly based on time of day, how long a contract that we sign, and forward prices. So it's certainly obviously driven then by the market. So at some points in time they will be better than our retail prices, and at certain points in time they will be worse.

All right. But the 85% I guess is basically saying that you're not getting as much on a mix basis?

Yes, it's a combination of price and quantity.

Yes I think, as Mark said, for the first quarter we pretty much matched what we would have gotten from the industrial retail customers. Projecting out the rest of the year, we don't think we're going to be able to do as well as that.

Okay. But you don't know that yet, because they haven't nominated what they want anyway?

Well, that's right. We've still got that last four months of the year, and we don't know what those numbers are. That's correct. We're just projecting.

Right. So the other question I had is on the wind investments. Have you talked at all about the -- you know, the new Administration's plans and tax incentives and so forth, and how that's going to affect your CapEx program and when you bring this on? I guess the other part of that question is, are there other utilities looking at the North Dakota area to build wind? And is that in conjunction with you or in competition with your locations?

Well, the big advantage we feel we have is the ability to use the DC line that connects the area around Bismark, the [center] of North Dakota, back to our service area in Duluth. So we feel the ability to have that transmission already in place to move the wind energy here is a big plus for us. Certainly there are others out there that are looking and are building wind energy out there, but the challenge of course is delivering it back to the load centers. So, again, there will be a lot of wind built in North Dakota, we expect, over the next several years, but I think the limiting factor's going to be the ability to move it back, and that's where we feel with purchasing the DC line and having access to that transmission gives us that leg up. Mark could comment on the tax side of --

Yes, on the tax side, and the production tax credits, we build that into our models as we look at when we want to incur that capital and when we want to bring that power to market. So it is part of the process that we consider as we look at our wind strategy and when we incur those costs.

I thought that changed a little bit, because there are now some of these convertible ITCs that might bring forward the credits that you get a little bit quicker than they previously had other prior bills. Is that something that you've looked at?

I don't know the details of that, but certainly it will be something we'll look at, yes.

Okay. All right. Thanks. That's all I had.

Thanks.

And with no further questions in the queue, I would like to turn the conference back over to Mr. Shippar for any additional or closing remarks.

Well, thanks for joining us this morning. We look forward to talking to you again after our second quarter results. Good morning.

This concludes today's presentation. We thank everyone for their participation and have a good day.