Alliant Energy Corp (LNT) 2005 Q4 法說會逐字稿

At this time all lines are in a listen-only mode. I would now like to turn the call over to your host, Becky Johnson, Manager of Investor Relations at Alliant Energy.

Good morning. Thank you for joining us today for Alliant Energy's conference call. We welcome those of you who are joining us on the phone and also those who are listening to our webcast. With me here today are Bill Harvey, President, Chief Executive Officer and also our Chairman as appointed yesterday by our Board of Directors; and Eliot Protsch, our Chief Financial Officer, as well as other members of the senior management team.

We issued a news release earlier this morning announcing Alliant Energy's fourth-quarter and annual 2005 earnings. If you haven't seen the release it is available on our website at www.AlliantEnergy.com in the investor section. Also, unless otherwise noted, all of our per-share references on this call refer to diluted earnings per share. We have allotted an hour for this morning's call which will include time to take questions from the investment community following some prepared remarks from Bill and Eliot.

Before we begin I need to remind you that the remarks we make on the call this morning and our answers to your questions include forward-looking statements. These forward-looking statements are subject to risks that could cause actual results to be materially different. Those risks include among others matters discussed in Alliant Energy's press release issued this morning and in our filings with the Securities and Exchange Commission. We disclaim any obligation to update the forward-looking statements. With that said I will now turn the call over to Bill Harvey.

Thank you, Becky. Good morning, everyone, and thanks for your continued interest in our Company. To provide more time for your questions we're not going to restate what has already been communicated in our earnings release. We hope our remarks will assist you in interpreting our reported 2005 performance and provide visibility to the strong results of our ongoing businesses.

We were pleased by the financial performance of our domestic utility business in 2005. That said, our total consolidated earnings were obviously battered by some large charges within our non-regulated businesses. Our 2005 earnings from continuing operations included some significant onetime items which are not related to the fundamental operations of the business going forward.

First, we incurred a total of $1.73 per share of non-cash asset valuation charges related to our Brazil investments, $1.05 of which was in the fourth quarter. We reported the results from these investments in continuing operations as required by the accounting rules. As you are likely aware, we closed on the sale of our Brazil investments on January 26th for $152 million. While the sale resulted in a substantial non-cash charge, we do believe the transaction allowed us to capture meaningful value for our shareowners.

Second, we continued our debt reduction efforts by retiring an additional $379 million of long-term debt at Alliant Energy Resources. This resulted in a $0.29 per share charge computed based on the average shares outstanding in 2005. Eliot will be discussing our 2006 financial plans in more detail a little later, but thus far in 2006 we have already completed the early retirement of the remaining $83 million of the AER 7% senior notes and have given notices to call the remaining $275 million of the AER 9.75% senior notes.

Lastly, our 2005 non-regulated results included approximately $0.11 per share of income related to the reversal of certain deferred income tax asset valuation allowances, and our domestic utility results included $0.08 of income resulting from the impact of issues resolved in a federal income tax audit. We view this income as non-recurring in nature.

Turning to our domestic utility operations, we're pleased with the financial results produced. We generated earnings of $252 million or $2.15 per share compared to $221 million or $1.95 per share in 2004. This was accomplished in spite of significant challenges we faced from unprecedented escalations in fuel and purchased power prices. As noted in our release, while electric utility margins were up significantly in 2005 they were negatively impacted by higher fuel and purchased power costs at Wisconsin Power and Light Company, which accounts for approximately 40% of our retail electric market on a kWh sales basis. We estimate that under recovered retail fuel and purchased power costs at WP&L were approximately $0.23 per share. At Interstate Power and Light Company, which accounts for the remaining 60% of our retail electric market on a kWh sales basis, the cost of rising fuel flows through the energy adjustment clause.

We kept our eye on the ball in 2005 regarding the operational aspects of our domestic utility business and we have many things to be proud of in addition to our financial performance. Our energy delivery business unit had its safest year of performance in five years. In addition, we ranked fourth out of 15 Midwest utilities in the J.D. Powers electric utility residential customer satisfaction study. Our generating fleet remained strong during a demanding summer season. In fact, our fleet grew by one, but -- our 300 megawatts natural gas-fired facility in Sheboygan Falls began commercial operation in June. And we're proud that three of our generating facilities were recognized as the three best performing small commercial power plants in the nation.

We reduced the overall risk profile of our domestic utility businesses by completing the sale of WP&L's interest in the Kewaunee Nuclear Power Plant. And just last month IP&L closed on the sale of its interest in the Duane Arnold Energy Center. Through these transactions we've reduced the operational and financial risk for both customers and shareowners. Both WP&L and IP&L have entered into long-term capacity and energy contracts with the new owners, allowing nuclear energy to remain a key component of our diverse energy supply portfolio.

Switching over to our transmission business, as of December 31 WP&L's investment in the American Transmission Company was approximately $152 million. This reflects approximately a 21% ownership interest in that business. IP&L continues to own its transmission assets, the book value of which was approximately $442 million as of December 31st. We're currently evaluating options for participation of our IP&L assets in an independent transmission entity be it the American Transmission Company or some other like entity.

Finally, we continue to make progress on the divestiture of our modest Illinois utility operations and we expect to complete this transaction in late 2006. Given Calpine's recent bankruptcy, let me briefly discuss WP&L's contracts with Calpine's subsidiaries. WP&L has purchased power agreements with Calpine subsidiaries for our RockGen and Riverside generating facilities. Currently the RockGen facility is part of the bankruptcy proceeding, but the Riverside facility is not. We utilize RockGen primarily for its capacity value. We're evaluating our options should the RockGen PPA be rejected by the bankruptcy trustee.

Let me now turn to our non-regulated business where we've make progress executing asset sales. These sales have contributed to significant debt reduction efforts which I touched upon earlier. In 2005 we sold our energy services, synthetic fuel and oil gathering pipeline investments as well as our biomass facility. On the international front, we have sold our interest in four plants in China and continue to work with our advisors on the sale of our interest in the remaining six facilities. We expect to complete all of our remaining China divestitures by the end of the second quarter.

In addition, we repatriated approximately $72 million from China during 2005. Efforts to sell our Laguna Delmar property in Mexico have generated considerable interest in the property. We anticipate requesting bid proposals before the end of the first quarter and we intend to complete the sale no later than the third quarter of 2006. The carrying value of our Laguna Delmar investment was approximately $90 million as of December 31st. Finally, we expect to complete the sale of our two gas gathering pipeline systems by the end of the second quarter, carrying value of our investments in these pipelines was approximately $15 million as of December 31st.

Next, Brazil. In January we announced and completed the sale of our Brazil investments for a purchase price of $152 million. Historically this investment has created uncertainty and added to the volatility of our financial performance. Completion of this transaction removes that cloud of uncertainty.

Lastly, let me touch on New Zealand. Our equity interest in TrustPower and Infratil have been very successful investments. Based on the exchange rates and trading prices as of December 31, our investments in TrustPower and Infratil had an aggregate market value of $342 million compared to our carrying value of $116 million. We continue to explore our options for monetizing this investment. Our relationship with our partners remains positive and constructive.

Consistent with our actions since 2002 proceeds from our non-regulated asset sales have been used to retire debt at Alliant Energy Resources. The future of our non-regulated business platform includes a relatively small portfolio of low-risk, mature businesses which have historically been accretive to earnings but not significant users of capital.

In closing, let me summarize our accomplishments during 2005. As noted, we were able to retire early an addition $379 million of ADR parent debt. The continued progress we have made in improving our financial profile was recognized by Standard & Poor's. Last month they removed the negative outlook on our companies and upgraded the senior unsecured debt of our utilities by one notch. In January our Board of Directors approved an increase in our quarterly common dividend of almost 10%. This increase is both competitive and sustainable. It represents another step towards our targeted dividend payout ratio of 60 to 70% of utility earnings. We are bullish on our ability to attain this payout level sooner rather than later.

We remain focused on providing safe, reliable and environmentally sound energy to our Midwestern utility customers. We have become a lower risk and more stable investment for our shareowners. We will make prudent investments in our infrastructure and do have opportunities for future growth with our plans to add generating facilities to meet increasing customer demand. We expect to deliver stable, regulated earnings and cash flows commensurate with our risk profile. Let me now turn the call over to Eliot to provide us with a financial overview. Eliot?

Thanks, Bill. I'd also like to thank all of you on the phone for joining us today and for your continued support of our Company. Bill has touched upon our financial highlights, thus my focus here this morning will be on our contemplative financings and our 2006 financial guidance. We will have time in the Q&A session to cover specific questions about our reported results and the guidance.

As Bill mentioned, we continue to make great progress in our debt reduction efforts within our non-regulated businesses. By the end of the first quarter of 2006 we expect to have retired all non-regulated debt at AER parent company other than our 403 million PHONES senior notes which have a coupon rate of 2.5% and mature in 2030. After the divestiture of our China, Mexico and gas pipeline investments, we expect to have additional cash at our non-regulated and Alliant Energy parent companies. We continue to evaluate the best use for this cash. These are the kinds of issues we enjoy spending our time on.

In addition to our PHONES debt, as of 12/31/2005 we have 164 million and 114 million of nonrecourse debt at our New Zealand and non-regulated generation subsidiaries respectively. This debt is supported by the cash flows from these businesses.

Switching over to the utility business, the proceeds from the sale of DAEC have also contributed to debt reduction during 2006 in the form of $110 million of short-term debt retirement at IP&L for the terms of the IUV order approving the sale IP&L will dividend $110 million to its parent, Alliant Energy, as an extraordinary dividend representing the approximate equity component of the book value of this asset. In addition, we no longer have our nuclear decommissioning liability or our nuclear fuel capital lease obligation.

Our 2006 guidance reflects our plan to issue minimal amounts of new equity through our equity incentive plans as we will switch to market purchases for both our dividend reinvestment and 401(k) plans. The objective is to minimize dilution for 2006. By comparison we issued approximately $29 million of new common equity in 2005.

Page 6 of our earnings release reports the details of our 2006 earnings guidance for continuing operations, so I won't take time reading that to you. With that said, let me share the key takeaways regarding a comparison of our 2005 utility results with our 2006 utility guidance. The first item is Wisconsin fuel and purchased power costs. As we noted in our earnings release, our 2005 earnings were negatively impacted by approximately $0.23 per share as a result of the under recovery of fuel and purchased power costs from our Wisconsin retail customers.

While commodity price levels and our ability to collect all of these costs are difficult to predict, we do expect a negative impact on our earnings to persist in 2006 albeit to a lesser degree. We are also continuing our dialogue with various stakeholders to implement a rate recovery solution for these costs that is both fair -- it is fair to both customers and shareowners. We are aggressively managing Wisconsin fuel recovery issues and will update you quarterly in these calls on the implications for earnings. I would also call your attention to the investor’s page of our website where we have provided some commentary to frequently asked questions regarding the fuel recovery process in Wisconsin.

The second item is income taxes. As noted in our earnings release, our 2005 results included $0.08 per share of what we believe to be nonrecurring income from the impact of a federal income tax audit. After adjusting for the impact of the onetime tax benefit realized in 2005, we are projecting a similar effective tax rate for our utility operations in 2006 to that which we experienced in 2005.

The third takeaway is recovery of deferred charges. You may be aware that the Public Service Commission of Wisconsin disallowed two elements of deferred costs in a recent rate case for our joint plant partner in the Kewaunee Nuclear Power Plant. First was one-half of the loss incurred on the sale of the asset and the second was the deferred cost associated with a protracted outage at the plant.

With regard to the former, our 2005 results reflect the impact of such potential disallowance. Nevertheless, we expect to pursue the recovery of these costs in our next rate case. With respect to the deferred outage costs, our prospects for recovery are better as unlike our joint partner we did not earn in excess of our authorized return.

The fourth item is the impact of the sale of our two nuclear facilities. Our guidance reflects a modest negative impact as a consequence of these sales. The fifth item is depreciation expense. We have reflected in our 2006 guidance the lower depreciation rates implemented as a result of a new depreciation study for IP&L. The sixth item is weather. While it was warmer than normal during the 2005 summer season, our 2005 results were not significantly impacted because of our use of a summer weather hedge. Gas margins for 2005 were also not materially impacted by weather due to our hedging practices. We expect to continue our practice of hedging for a significant portion of the impact of weather on both our winter and summer sales volumes. Finally, the last item is based rate increases. At this time we don't expect any material changes in non-fuel related base rates in 2006 in either of our two main utility jurisdictions.

In summary, despite the fact that our projected profitability is still somewhat hampered by the anticipated impact of our Wisconsin retail fuel and purchased power collections, we are projecting approximately 4% growth in utility earnings for 2006. This is based on the mid point of our 2006 utility earnings guidance compared to an adjusted $2.07 earnings per share in 2005 after backing out the $0.08 of nonrecurring tax income.

While we expect our domestic utilities to be the primary driver of our future growth, we also expect our remaining non-regulated businesses to successfully contribute to the bottom line in 2006 as well as to our future earnings growth. The results of our non-regulated businesses should also be much less volatile than they have been in the past given the continued streamlining of this portfolio and the nature of the businesses remaining.

I would also like to call your attention to the line in our guidance titled "remaining interest expense allocation". Our practice is to allocate our AER interest costs to our various businesses based on the cumulative net capital deployed. We have a net shortfall in the proceeds realized from the assets of various non-regulated businesses versus the actual amount invested. Consequently we expect a $0.09 to $0.11 per share drag associated with that interest expense in 2006 with approximately $0.06 to $0.08 of this allocated to our international businesses and the remainder to other non-regulated businesses.

Our overall AER parent interest expense has been decreasing over time as we continue to narrow our portfolio and effect the resulting debt reductions. We expect this interest allocation to be lower again in 2007. Excluding debt premiums we are expecting our non-regulated businesses to make a positive contribution to earnings in 2006 and to our long-term aspirational goal of 5% earnings per share growth. This is in spite of the impact of the continued drag on earnings from the allocation of non-regulated interest expense.

Moving on to cash flow, for 2006 we expect our cash flows from operations to be in the range of $475 to $525 million. Reduction from 2005 is attributable largely to taxes due on asset sales and other changes in working capital. We are projecting total capital expenditures of $475 million and $600 million in 2006 and 2007, respectively. The increase in 2007 is driven by largely by the initial spending associated with the next phase of our generation build-out program as well as an increase in our anticipated environmental related capital expenditures.

Approximately 94% of our 2006 capital expenditures are related to utility operations. We plan to finance the majority of our 2006 capital expenditures with internally generated funds supplemented with proceeds from asset sales, external debt issuance and/or equity infusions from the parent company if necessary.

In closing, we appreciate your continued support of our Company and look forward to seeing you again this year in connection with our various Investor Relations activities. At this time we plan to participate in the Midwest utility seminar in Chicago in April and the AGA and EEI in May. I will now turn the call back over to the operator to assist with the question-and-answer portion of our call.

(OPERATOR INSTRUCTIONS). David Parker, Robert W. Baird.

Good morning and congratulations on a very constructive year. I use that term talking about a lot of repositioning in international waters, but earnings came through nicely and surprisingly well as well. So congratulations. A couple questions. First off -- thanks, Eliot, for running through all the ins and outs on the 2006 guidance, particularly on the utility side because it looks as if that $0.23 gain -- or drag from the under recovery on fuel -- I would hope that would get reset. But could you just maybe update us on what's happening in Wisconsin? Because my impression was that the fuel cost got reset at the beginning of the year and we sort of wiped that slate clean and we shouldn't expect much of a drag unless fuel prices spike up again?

David, first of all ,I would refer you and others to the explanation posting on our website because that describes the monitoring period, the averaging process, etc., etc. The net effect of that is it never really gets wiped clean when the factor is reset because it is reset on the basis of an average for a test year. And when such average is implemented later in the test year when you have already incurred costs, there is sort of a flushing of expenditures that you cannot get back.

So in essence the drag that we've built into our '06 guidance reflects the affect of the way in which that process works and the affect that it will have on our books for the year as well as our forecast for the second half of the year where that factor, barring a change in the rules, will continue on -- or will continue to apply to us for the second half of the year until it is reset and the connection with our next rate case in Wisconsin which will likely be in the '07 test year.

Also I guess the year-over-year comparisons of '06 with '05 you mentioned Duane Arnold. And if my recollection was correct, that property -- that plant earned you something in the neighborhood of $0.08 to $0.10 a share, was that about right?

That's approximately correct. Probably a little bit more toward the $0.08 than the $0.10 as it's depreciated over time. But keep in mind that the sale was constructed in such a way that the costs are basically neutral to our customers. And while the rate base amounts will be declining, the expense on the income statement will be replaced by a PBA, with of course there's a modest interest offset.

Right. One thing that I didn't pick up. You identified how much cash you'll have on hand in 2006 after the asset sales, what was that number again, 200 something?

I don't know that we explicitly identified that, David. But we were talking kind of generally about our debt balances and some anticipated asset sales and carrying value. So you can do the math on what it means for continued debt reduction.

Okay.

And then of course our K will be coming out that will lay out a number of those balances, but there have been some transactions with debt and asset sales since the close of the year.

(indiscernible) debt paid on opportunities, you're getting some of the higher cost debt. I don't know what can be done with the PHONES or other opportunities. If you could talk about that a second and maybe what debt is left at the parent.

Well, the only comment I would make about PHONES is that for those who follow that instrument, it was a hybrid security and had an exchangeable feature tied to the MacLeod Stock which has now declared bankruptcy for the second time with the common shareowners being wiped out. So one should think of that bond as a pure debt security with a 2.5% coupon and hence we know where it should trade given that feature. That will be the only outstanding debt instrument that we have at AER other than a number of project finance debt instruments at New Zealand, Sheboygan Falls and our Needham power plant.

Okay. I think that's all the questions I have right now. Thank you.

Thank you, Dave.

Mike Weinstein, Zimmer Lucas Partners.

My question is in the guidance I'm wondering what kind of ROE you're assuming at the utilities. It says utility guidance for domestic utilities is $2.05 to $2.25 and I'm wondering what kind of ROE is implied in those numbers?

First of all, hello, Mike, and thank you. But we are not earning our authorized rate of return in Wisconsin. And in the case of Iowa, when you compute the financial ROE at the end of the year we're coming close. I think the assumption in our guidance that you should take away is that Wisconsin will continue to be a struggle because of the fuel clause. And in Iowa we are managing very close to our allowed rate of return.

Okay, thank you very much.

Jeff Corvella (sic), Duquesne Capital.

Just wanted to -- I guess going back to Mike's question on the ROE shortfall in Wisconsin, is there any way to quantify that on an average basis? Is it a percent, half a percent?

I don't think there's a way that we can quantify it for you on this call. I think suffice it to say that we expect the shortfall against the authorized return to be modest and certainly a gap which could be closed were we to realize dollar-for-dollar recovery under the fuel adjustment clause which we don't believe we will.

Sure. I guess to the extent that the energy prices or the commodity prices start to trend down as opposed to this over the last year or so they've been consistently trending upward, is it possible that that under recovery is corrected?

It's possible that it could be reduced somewhat from what we have in the guidance, but we have substantially hedged both our fuel and purchased power positions for the entirety of this fiscal year. So you should not expect that if there is some dramatic decline in the forward prices of natural gas and indirectly forward prices of energy that we would be able to capture all of the goodness associated with that decline because we have hedged.

And my final question relates to the CapEx in 2007 and ongoing spending for (inaudible) utility. I was wondering if you could point us to what that -- exactly the new generation is in '07 that the 110 million relates to. And then going forward, would you expect that to -- I expect it to go up following that, is that indeed the case?

It's really comprised of two components. One, the anticipated development of a wind farm by our utility business and early stage expenditures associated with the construction and licensing of a base load facility at Wisconsin Power and Light Company.

Jeff, this is Eliot. On that fuel clause question, I really would encourage you to read the posting we have on our website as to how the mechanics of that Wisconsin clause works because of that averaging concept over the test year does have an effect on what the impact of declining fuel prices might be in Wisconsin for the year, just because of the mechanical nature of the way that process works.

Will do. Thank you very much.

David [Crumhaus], Copia Capital.

Good morning and congrats on a great year. A couple questions for you. On your 2006 guidance, your table here, you talk about Brazil exit costs of $0.02 to $0.04. Is that onetime stuff? Is that part of the debt allocation? What is in there?

It is onetime stuff. It is selling costs associated with simply closing out the entirety of our position and our operations in Brazil. So it is onetime.

You talked about the drag on the remaining nonreg debt, and I think you said it was $0.09 to $0.11 and that some of that was in the international. You showed the $0.06 to $0.08 in this guidance table. Can you just walk through that again?

Yes. The way to think of it is that the debt at AER finances the equity in some of the other businesses that are listed in the transportation RMT and non-regulated generation line. So, therefore, some of the capital cost or the interest costs associated with the AER debt is allocated to those businesses, as well as the international businesses. But once the international businesses are gone, then to the extent that the debt is still outstanding and we are incurring cost, it represents a drag because it is not financing anything but a balance on the balance sheet.

And that 6 to 8 assumes the resources debt, the 9% that you're taking out or the 9.75% that you're taking out.

Right.

The drag on that for the first couple quarters (indiscernible).

Only PHONES will be left after those calls are complete.

Okay, that's helpful. With Brazil you obviously realized 152 million in cash proceeds. Are there tax cash proceeds that you debt, or because it's international you don't realize the lost there?

Yes, there are.

Can you tell us what the extent of those are?

We haven't disclosed them historically, I don't believe, in connection with the operations in TrustPower.

Okay. But there should be a tax write-off that you can take as a result of this?

The effect of the -- the accounting at year-end reflecting the sale having occurred has been tax effected to account for the value of the capital loss tax deduction which would be offset by capital gains elsewhere in the business.

Okay. For the target debt to capital, obviously you talked about more improvements coming this year, where do you want your -- at a holding company want your debt to cap at as you move forward?

The way I would respond to that, David, is that first of all we were at around 47% on a consolidated basis at year end and the gating factor on all of our debt measures is really our commitment to maintaining our investment bond grade, or bond rating -- investment grade bond rating. You know those metrics, you know how they evolved, and we're very attentive to making sure that we preserve the sanctity of that rating.

And lastly, one more shot on this fuel and recovery. You said it was $0.23 this year. You expect a negative impact in '06 but to a lesser degree. Does that negative mean you expect it to be $0.15 this year or $0.05? Can you get us any closer on that?

The answer is, no. I know you'd like us to, but the fact of the matter is what's going to happen to natural gas prices, what's going to happen to wholesale power prices is difficult to predict. It's difficult to predict what's going to happen in connection with the ongoing discussions that are occurring among the Wisconsin utilities and with the Wisconsin regulators and other stakeholder interest groups in terms of potential modifications to the fuel clause here in Wisconsin.

So it would be a little better than a guess were we to try to characterize that number to you. We do have something obviously reflected in our guidance, but the fact of the matter is that can be very volatile and we are hopeful that it -- to the extent that it's volatile it will be volatile in a favorable way rather than a negative way because we've tried to be conservative.

And as we said in our prepared remarks, you should expect this will be a subject of discussion in upcoming earnings calls because of its material impact on our overall consolidated results.

Terrific. And congrats again on a really good year.

Steve [Rountos], [Talon] Capital.

Good morning. Bill, you were talking about the dividend and a payout ratio of 60 to 70% of utility earnings. And if we just take that and apply it to your utility earnings for '06, obviously the dividend comes out to be higher than where it is today. What's the next opportunity to raise the dividend?

Our Board reviews our dividend payment policy and dividend level on a regular basis throughout the course of the year.

Okay. And how soon -- you said sooner rather than later to get to those payout ratios. How soon is sooner? Is it a year, is it two years --?

It's (multiple speakers) Later. Not to be facetious, but we obviously have a multitude of constituencies that we take into consideration and our Board does as it makes dividend policy decisions. Those constituencies include shareowners, they include rating agencies. So that's something that the Board considers on a regular basis. That's the best we can do at this juncture.

When is the next Board meeting scheduled?

The end of March.

Okay, great. And then Eliot, on the financial '05 results and '06 guidance, what is in there for ATC earnings in both years?

Give me a second to look that up here, but basically our equity income in 2005 was 21 million and I believe '06 -- some modest growth, probably up to 23, 24.

And of the 475 of CapEx total for '06, how much of that is ATC equity investment?

$12 million is embedded in the -- where we put it is in the other miscellaneous utility property. It probably merits a line by itself, but it's $12 million for '06 and that's kind of the run rate for '07 as well.

Got it. Great, thank you.

Danielle [Wright], Dahlman Rose.

Many of my questions have been answered, but I just was wondering if you could elaborate on your decision on the New Zealand assets? Do you anticipate to make that decision relatively soon or is it something that is not really on the front burner?

We have agreements in place with our partners in New Zealand, I almost said Brazil. The good news is I don't have to talk about that anymore. But we have arrangements in place with our very good partners in New Zealand that do impose restrictions on our ability to liquidate any positions that we have in New Zealand. We are engaged in discussions and evaluations concerning our New Zealand properties and anticipate making decisions about the future of that investment during the course of this year and even perhaps early next year.

The best we can commit do you at this juncture is that we will keep investors fully apprised of any decisions that we do make during the course of this year or early next year relating to that investment. But as I indicated in my prepared remarks, our relationships with our partners in Brazil who have done a wonderful job for us are very positive and very constructive.

And the contribution to earnings on average was approximately how much?

From New Zealand?

Yes.

I believe our guidance is $0.04 to $0.08 and that, again, reflects the implementation of some nonrecourse financing that we instituted in 2005 against the value of that investment. So that $0.04 to $0.08 is net of the effect of the interest and anticipated currency fluctuations and dividend policies at Infratil and our equity in our earnings at TrustPower.

And on the other side, your CapEx level, do you anticipate that it will be 600 for quite a while because of the additional expenditures you will encounter in the co technology?

We would anticipate that for the near term foreseeable future those capital expenditures would remain relatively consistent with that level. But as we move into the latter parts of this decade and begin the actual construction process for new base load generating facilities we would expect those capital expenditure levels to go up, but we view that as a good thing because that will help us meet customer requirements as well as create earnings growth potential for the utilities.

And construction in order -- I think that you were shooting for 2012. Construction has to start when in order for you to make that deadline?

The latter part of '07 or early part of '08.

Okay. And do you need the 'okay' from all of your commissions first and set up a system of return on construction work in progress?

Yes, we do. We would anticipate that process will begin in the latter part of '07 and complete hopefully in the early part of '08.

Thank you.

David Thickens, Deephaven Capital Management.

Most of my questions have been answered. Just one question about the mechanics of ATC. Can you explain how the governance of ATC works as far as any decisions being made about the future of that Company? Is it the ten members of the -- the ten Board seats require a majority of that, or is there one vote for each of the 27 or 28 or whatever the number is of contributing utilities that would be required to take the Company public?

Good question, David. There are ten Board members, they each have one vote. The more broad-based membership participation that you refer to, there are not votes associated with those members. It is a ten member Board, five of which are, if you will, insider Board members in that they are representatives of large customers of ATC. The other are what I would characterize as five independent nonutility affiliated Board members.

Okay, thank you much.

(OPERATOR INSTRUCTIONS). Ashar Khan, SAC Capital.

Good morning. It if I understand -- you mentioned adjusted earnings for the utility business was $2.07 for the year 2005, and you had a $0.43 drag in there. And so if you add the $0.23 it would have been $2.40 and, if I heard right, under that scenario you would be earning equal to your ROEs allowed in Wisconsin as well as you mentioned that you are pretty close to your ROE in Iowa. Is that a correct statement? Would that be a correct statement?

Ashar, the first thing we would, of course, discourage investors from doing is to add back that 23 in developing any expectations for 2006 because of the mechanics and dynamics associated with the Wisconsin fuel clause, the energy markets and our contemplated dispatch curve going throughout the year. I guess the point I was trying to make is $2.07 is net of what we believe to be a onetime taxed item and just simply taking the mid point of our guidance for the utility is what we, at this point in time, expect to occur.

I'm not trying to play dodge ball with your question as much as just to illustrate the dynamics associated with that Wisconsin clause. But you are correct in your assumption that it is that fuel clause that is holding us back from reaching the allowed rate of return in Wisconsin. Of course, there are other factors that come into that equation, but your math is correct. I just would caution you on some of the assumptions that would lead you there.

Okay. And then if I can, Eliot, pursue how much is organic growth for you guys each year and how much is rate base growing '06 versus '05? Could you just mention something?

In terms of customer growth and then ratebase growth (multiple speakers)?

Yes.

But 1 to 1.55 (multiple speakers).

Our sales growth unit volumes in Wisconsin is on the order of 3% a year, it's about 1% or there abouts with respect to our Iowa jurisdiction.

And how much of ratebase growth are you having in 2006 versus 2005?

I don't have that number at my fingertips right now.

But am I correct there's positive ratebase growth?

Yes. I think CapEx in excess of depreciation is around 100 to 125 million.

Okay. And then, Eliot, you mentioned that this drag on the expense would be lower going from '06 to '07, the $0.06 to $0.08, correct?

Yes.

Does this get eliminated at some point?

Only if the debt balances decline to the point where they equal the equity investments in the businesses that they're financing.

But is that something that is -- do you see in your financial analysis two or three years down the road happening?

That would be speculation at this point as to what we might do. I guess what I would point out is having a $402 million principal amount of 2.5% coupon borrowing is a rather attractive investment for our shareowners to have. But as I pointed out earlier, the market value of those bonds ought to be somewhere -- if they're trading at a BBB investment-grade company with a 2.5% coupon 25-year maturity at $0.45 on the dollar, so you can (indiscernible).

And you mentioned, and I've not followed the Wisconsin situation, could you elaborate what you meant by the utilities are trying to go to the commission and trying to address this fuel shortfall? Can you tell me what award is being proposed or where you are in terms of that process?

I think the best way to characterize where it is currently is a work in progress that involves both commissioned staff, various customers, stakeholders from around the state as well as the regulated utilities in the state. There is no one in that stakeholder group that is of the view that in a rising fuel cost environment fuel adjustment clause in Wisconsin works fairly for the regulated industries in the state.

So I would characterize the discussion as constructive, focused on trying to come up with modifications in the way the fuel clause functions in the state of Wisconsin that would be fairer to the industry in this new and more volatile environment. So I'd characterize it as constructive. It's got the right people involved and it recognizes that the clause is not functioning fairly the way it functions today.

So can we expect some results by the end of the year? What is the timing of this effort in terms of any meaningful results?

As you might imagine, given the variety of stakeholders that are involved in the discussion it's possible impossible to predict when there might be a consensus resolution in the discussion or even whether there will be. But I'm pleased to say that the right people are involved and they're having a constructive discussion.

And then could I ask -- Eliot, you mentioned you're going to be issuing -- if I'm right I might have not heard properly that you would be issuing shares through other means not through a direct process. Could you (multiple speakers)?

(multiple speakers) have a number of equity incentive plans that have been in place for a number of years and it is likely, we don't know for sure, but we anticipate that there will be a number of -- there will be some options that could be exercised and there are some performance shares -- I guess some restricted stock that we do know in fact will be issued, but it is very modest. And at this point those equity sales will be in the form of original issue versus market purchases.

Can you just tell us what '06 guidance, what the average share count is based on?

I don't have that in front of me, but let me -- perhaps we have time for one more question, Ashar, and we could pick that up after the question and we'll give you a general number. But it's modest new equity, very modest (multiple speakers).

And you don't expect any -- in your plan for the next three or four years you don't expect much equity issuance, is that correct?

You could safely assume in your modeling and projections and such that we're probably looking at less than 1% dilution for the year.

Okay, thank you.

Steve [Sambuza], Longbow Capital.

Good morning. I was wondering if you might be able to discuss alternatives for your Iowa transmission assets. I believe in your last 10-Q you mentioned that you were exploring the possibility of combining these assets with ATC or another independent transmission SE. Could you comment on where that process stands?

It stands as a work in progress at this juncture both in terms of our evaluating the alternatives that might be available to us and exploring them early as well as obviously engaging in discussions with the very relevant stakeholder groups in the state of Iowa, those being customers, other energy providers in the state as well as the Iowa Utilities Board. The range of alternatives are relatively straightforward from a qualitative perspective. American Transmission Company is certainly an alternative; the creation of another American Transmission Company like entity is an alternative for the status quo -- is an alternative with the assets remaining part of IP&L. But that sort of book ends the range of alternatives that we're exploring.

So those conversations with the various regulatory bodies are ongoing at this time?

That's right.

Thank you very much.

Ms. Johnson, there are no further questions at this time.

With no more questions this concludes our call. Thank you for your participation this morning and for your continued support of Alliant Energy. A replay of the call will be available through February 15, 2006 at 800-642-1687. Callers should reference conference ID 414-4250. In addition, an archive of the call and a script of prepared remarks will be available in the investor section of the Company's website at www.AlliantEnergy.com later today. Thank you.