阿莫林 (AEE) 2007 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Ameren Corporation 2007 third quarter earnings conference call. At this time all participants are in listen-only mode. And later we will conduct a question-and-answer session. (OPERATOR INSTRUCTIONS) As a reminder this conference is being recorded today, Friday, November 9th, 2007. (OPERATOR INSTRUCTIONS) I would now like to turn the conference over to Mr. Bruce Steinke, Manager of Investor Relations. Please go ahead, sir.

Thank you, Damian, and good morning, everyone. I am Bruce Steinke, Manager of Investor Relations here at Ameren Corporation. On the call with me today is: our Chief Financial Officer, Warner Baxter, our Vice President and Controller, Marty Lyons, and other members of the Ameren management team. Before we begin let me cover a few administrative details. This call will be available by telephone for one week to anyone would wishes to hear it by dialing a playback number. The announcement you received in our news release carry instructions on replaying the call by telephone. This call is also being broadcast live on the Internet and the webcast will be available for one year on our website, www.ameren.com.

This call contains time-sensitive data that is accurate only as of the date of today's live broadcast. Redistribution of this broadcast is prohibited. I also need to let you know that comments made on this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those of our future expectations, beliefs, plans, strategies, objectives, and financial performance. We caution you that various factors could cause actual results to differ materially from those anticipated in the forward-looking statements. For additional information concerning these factors we ask you to read the forward-looking statement section in the news release we issued today and the forward-looking statements and risk factors section in our periodic filings with the SEC. To assist in our call this morning we have made a slide presentation available on our website that reconciles our earnings per share for the third quarter and first nine months of 2007, to our earnings per share for the third quarter and first nine months of 2006, on a comparable share basis, and a slide that compares our full-year 2007 earnings per share guidance to full year 2006 earnings per share guidance, also on a comparable share basis.

To access this presentation you may look in the investor section of our website under presentations or follow the links for the webcast. Warner will begin this call with an overview of key regulatory and operating matters. Marty will then follow with a discussion of our third quarter 2007 results and 2007 earnings guidance. Warner will then close and open the call up for questions. Here's Warner.

Thanks, Bruce. Good morning, and thank you all for joining us. On line with our expectations, our third quarter earnings were lower than the prior year, primarily because of the Illinois electric rate relief settlement, changes in our Illinois electric summer rate structure, and the rising costs of operating our regulated utility businesses, including increased reliability expenditures. These factors more than offset the benefits of warmer summer weather, higher power sales prices at our nonrate -- regulated business segment and the favorable impact of the Missouri rate order.

Through September, our Illinois regulated business has experienced a significant earnings decline compared to 2006 due to, among other things, our current levels of electric and gas delivery service rates being insufficient to recover our current costs of providing service to our customers and provide a reasonable return on our investments. Our current electric and gas delivery service rates in Illinois are primarily based on costs and investment levels from 2004 and earlier. As you all know, our cost of operating our businesses have risen significantly since that time, as well as our level of investment in our energy infrastructure. As a result, last Friday we filed requests with the Illinois Commerce Commission for $180 million increase in electric, and a $67 million increase in gas rates, for a combined $247 million.

As our recent earnings results and our Illinois regulated business indicates, these rate increase requests are clearly needed and are consistent with our need to recover our costs of providing safe and reliable service to our customers, while earning a reasonable return on our investments. We recognize that our electric customers have experienced sizable rate increases over the past year, primarily because of higher power supply costs. We have taken actions to mitigate the impact of these power supply increases which include providing credits and checks to our customers under the recent Illinois settlement and redesigning our electric rate structure for 2008. We continue to be sensitive to the impact of electric rate increases on our customers. Earlier this year, we pledged to keep the overall annual residential electric bill increases in Illinois less than 10% in the first year for each utility in its next rate filing.

Our Illinois electric rate filings fulfill that promise. This self-imposed rate increase limit could result in approximately $30 million of the increase request not being phased in until the second year if the granted increase exceeds the limit. This limit only impacted AmerenIP's electric rate increase filing. It is also important to point out that our rate increase requests only applicable to the delivery service portion of our customers' rates which represent about one-third of the average residential customer's bill. Power costs to our Illinois customers are passed through dollar for dollar with no mark-up. Our electric and gas filings included a request to return on equity of 11%, with an aggregate electric base of approximately $2 billion and an aggregate gas rate base of approximately $900 million. Costs were primarily based on a 2006 test year, certain known and measurable updates.

We have also requested rate adjustment mechanisms for bad debt expenses and certain electric infrastructure investments, and the decoupling of natural gas revenue requirements collection from sales volumes. The Illinois Commerce Commission has 11 months to make a decision on our filings. Bottom line is that the outcome of these rate cases is very important to our Illinois regulated business. These rate increases will provide this business with the necessary cash flows to strengthen its financial position, so that we may continue to invest in our energy infrastructure on a timely basis and provide our customers with safe and reliable service.

As I stated previously, the significant item that negatively impact earnings in the third quarter was the initial implementation of the electric rate settlement agreement in Illinois. As most of you probably know, the Illinois governor signed the enabling legislation for this settlement in late August. Electricity customers of the Ameren Illinois utilities, AmerenCILCO, AmerenIP and AmerenCIPS, will receive $488 million in bill credits and refunds and other relief through 2010 as part of an approximately $1 billion statewide relief package. The Ameren companies will be funding $150 million of this program over a four-year period. The total impact to Ameren's earnings per share is expected to be about $0.45 per share spread across four years, including $0.26 per share in 2007. We began sending checks and providing bill credits in September and recorded $0.18 per share of these costs in the third quarter.

Other key aspects of the settlement are currently being implemented, including those related to the procurement of power for the future. As you know, the legislation established the Illinois Power Agency, a new agency that will begin procuring power for our Illinois utilities in 2009 and beyond. The state of Illinois has already begun recruiting a director for the Illinois Power Agency and other planning activities have commenced. In addition, the Ameren Illinois utilities recently filed a proposed power procurement plan with the ICC for the period June 1st, 2008, through May 31st, 2009. Under this plan, the Ameren Illinois utilities will only be purchasing through a competitive bidding process monitored by an independent third-party administrator. Any remaining power requirements from June 1st, 2008, May 31st, 2009, period after which the IPA will procure power. Our power supply needs through May 31st, 2009, are not extensive as most of those requirements have already been procured. It is important to note that the swap agreements that were entered into as part of the Illinois settlement will hedge a significant portion of our Illinois utilities outstanding base load requirement needs through 2012, especially for our residential customers.

Finally, the ICC recently approved a revenue neutral modification for our electric rate designs to assist our all-electric customers. The primary effect of this modification will be to reduce the winter bills of these customers and spread the cost to summer months and other customer classes. In Missouri, we continue to pursue a settlement with state authorities for all liability matters related to the Taum Sauk plant incident. The parties continue to negotiate in good faith. And we are hopeful we will be able to reach a constructive resolution to the matter. In August we received FERC approval to rebuild the upper reservoir of the Taum Sauk facility.

Recently we have hired the contractors necessary to rebuild the facility subject to a satisfactory settlement with state authorities. At this time we expect Taum Sauk to be out of service until at least the fall of 2009. The process of establishing the rules for an environmental cost recovery mechanism in Missouri continues to progress. We expect these rules to be available, subject to the Missouri commission's approval, in the first half of 2008. Finally, with respect to Missouri, with escalating costs, particularly for fuel and transportation and reliability improvements, we continue to evaluate the timing of our next electric rate case filing. I will now turn it over to Marty to walk you through our third quarter earnings.

Thanks, Warner. I would now like to refer you to the slide presentation on our website as I provide a more detailed discussion of our earnings for the third quarter of 2007. This presentation reconciles our earnings per share for the third quarter and first nine months of 2007 to our earnings per share for the third quarter and first nine months of 2006 on a comparable share basis. In addition, this presentation includes a slide that compares our 2007 GAAP and nonGAAP earnings per share guidance to full-year 2006 earnings per share, again, on a comparable share basis. For the third quarter of 2007, we reported net income of $ 244 million, or $1.18 per share, compared to net income for the third quarter of 2006 of $293 million, or $1.42 per share. Net income for the first nine months of 2007 was $510 million, or $2.46 per share, compared to $486 million, or $2.37 per share in the first nine months of 2006.

NonGAAP earnings per share of $1.36 for the third quarter of 2007 compared to nonGAAP earnings of $1.52 per share in the third quarter of 2006. There were two major items that we have excluded from GAAP earnings in the third quarters of 2007 and 2006 to arrive at the nonGAAP earnings. In this year's third quarter, we excluded the $0.18 per share of costs associated with the Illinois electric settlement that Warner discussed earlier. In last year's third quarter, we excluded $0.10 per share of costs associated with severe storms. Overall, Ameren's earnings in the third quarter of 2007 were negatively impacted by changes in our Illinois electric summer rate structure, increases in fuel and related transportation costs, reliability expenditures, plant maintenance, labor and benefits, depreciation, and financing costs. These negatives were more than off -- these negatives more than offset the positive effect on margins of higher power prices for sales from our nonrate regulated generation business segment, warm summer weather, and the impact of the Missouri rate order, which was effective in June 2007. More specifically, in the third quarter of 2007, Illinois regulated margins were $0.39 per share lower than the year-ago period. This was primarily because of the change in rate structure and to a much lesser degree, reduced demand after excluding the effect of weather. Prior to 2007, our Illinois residential electric rates were designed to be lower during the winter heating periods and higher during the summer cooling periods. Throughout 2007, we have been billing electric revenues based on rates designed to be the same throughout the year.

Consequently, while full year Illinois margins are expected to be only modestly lower year-over-year, our summer electric margins were lower and winter electric margins have been and will be higher in 2007 when compared to 2006. In other words, we anticipated a third quarter decline in our Illinois regulated margins and we expect our electric margins to be higher in our Illinois regulated business in the fourth quarter, as they were in the first quarter due to this rate change. The Missouri rate case added $0.09 per share in the third quarter 2007 compared to the year-ago period. This includes the benefit of higher rates, lower depreciation, and decreased taxes pursuant to the Missouri Public Service Commission order. Other electric margins increased $0.39 per share in the third quarter of 2007, primarily as a result of the previously mentioned higher sales prices for the output of our nonrate regulated generation fleet. Higher costs for fuel and related transportation, primarily in our Missouri regulated operations, reduced electric margins by approximately $0.09 per share in the third quarter of 2007 compared to the year-ago period.

As noted, weather was a positive for native load electric margins in the third quarter of 2007, improving margins compared to the same period in 2006 by an estimated $0.10 per share. Cooling degree days increased 16% in the third quarter of 2007 compared to the same period in 2006 and were 30% above normal. The benefit weather contributed to native load demand was reduced by lower interchange sales which are included in other electric and gas margins, as less low-cost power was available for sale in the energy market. Labor and benefit costs increased $0.04 per share in the third quarter 2007 from the third quarter of 2006. In the third quarter of 2007, higher levels of power plant maintenance work reduced earnings by $0.04 per share. Increased expenditures for distribution system reliability and maintenance reduced earnings by another $0.04 per share compared to the year-ago period. Depreciation and amortization expenses also continued to trend higher. These expenses increased $0.04 per share primarily because of increased capital addition and amortization of a regulatory asset associated with the recovery of AmerenIP acquisition integration costs which began in January of 2007.

Solution and financing costs in the third quarter of 2007 were higher than the year-ago period as a result of continued funding of higher energy infrastructure and power generation investments, as well as higher borrowing costs resulting from credit rating downgrades. These downgrades were largely associated with the legislative uncertainties in Illinois. Following the Illinois settlement agreement in August, three major rating agencies upgraded their credit outlooks for Ameren and certain of its subsidiaries, but have not changed their credit ratings. Reduced costs in the third quarter of 2007 associated with the Taum Sauk plant upper reservoir breech improved earnings by $0.04 per share relative to last year. Decreased emission allowance sales in Ameren's nonrate regulated generation business segment also reduced earnings by $0.04 per share compared to the prior year period. Finally, other items netted to a negative $0.06 per share.

Turning now to our 2007 earnings guidance, which we reaffirmed earlier this week. We continue to expect GAAP earnings to range between $2.80 and $3.05 per share, and nonGAAP 2007 earnings to range between $3.15 and $3.40 per share. The 2007 nonGAAP earnings per share guidance excludes the following items: the negative $0.09 per share impact resulting from the severe January 2007 ice storms, the estimated negative $0.26 per share impact in 2007 of the settlement agreement among parties in Illinois to provide comprehensive electric rate relief and customer assistance, the positive $0.05 per share impact resulting from the reversal of accruals made in 2006 for low-income energy assistance and energy efficiency program funding commitments in Illinois, and the negative $0.05 per share impact of a federal energy regulatory commission order retroactively adjusting prior year's regional transmission organization costs. Ameren's earnings guidance for 2007 assumes normal weather for the balance of 2007 and is subject to among other things: regulatory and legislative decisions, plant operations, energy market and economic conditions, severe storms, unusual or otherwise unexpected gains or losses, and other risks and uncertainties outlined in Ameren's forward-looking statements.

There is, of course, a range of outcomes that could occur around each of these vary handles and our segment results. For the sake of simplicity, however, we have provided range only for total earnings per share and total net income. I don't plan on going through the line items on page four of this presentation in too much detail, because we have not changed our overall guidance. The most significant change to margins was the result of weather. We have increased the expected impact of weather on earnings because of the increased native load demand versus normal conditions. Conversely, the warm summer weather reduced the level of low-cost energy available for sale in the interchange markets which is reflected in other electric and gas margins. We have also reduced Illinois regulated margins as a result of lower than expected demand. In addition, we have increased the expected costs for distribution system maintenance as we move forward with our plans to improve reliability for our customers. We have also revised the expected costs for plant maintenance, bad debts, depreciation, financing and other costs.

Moving to our segment guidance, we are now forecasting a slightly lower nonGAAP net income contribution from our Illinois regulated segment and a higher contribution from the other segments. The nonGAAP contribution to 2007 net income for Ameren's Missouri regulated business segment is now expected to be an estimated $310 million. The Illinois regulated business segment is expected to be an estimated $90 million, and the nonrate regulated business segment is expected to be an estimated $280 million. This completes my prepared comments. I will now turn it back over to Warner to wrap up our discussion.

Thanks, Marty. It was great to visit with many of you at the EEI financial conference earlier in the weak. At the conference we provided some insights of some key trends that we expect to impact our business beyond 2007. We continue to face a rising cost environment in many aspects of our regulated businesses, including fuel and transportation costs. These cost increases, combined with our incremental expenditures for environmental projects and to improve reliability, caused our earned returns on equity to be less than our allowed returns until rate relief is granted. Consequently we expect to be entering into a period over the next several years for more frequent rate cases will be necessary. We will remain laser focused on achieving constructive outcomes in our rate cases, so that we may continue to invest in our energy infrastructure on a timely basis for the benefit of our customers, as well as to provide solid long-term earnings growth for our shareholders. In our nonrate regulated business we face many of the same challenges we are facing in our regulated business.

In addition we will be managing a significant environmental capital expenditure program to meet current environmental rules. To mitigate challenges we will remain focused on improving our plant's productivity. In addition, we will seek to capitalize on marketing opportunities as the ancillary and capacity markets further develop and as the power markets potentially tighten. Of course, one key issue that will affect both our regulated and nonregulated businesses will be the impact of any new legislation that will limit the emission of greenhouse gases. We continue to actively participate in this important debate. Along those lines, we will be issuing a report on climate related issues in mid-December. In closing, we look forward to providing you with further insights on these key trends and other factors impacting our business at our analyst meeting on January 17th at the Sheraton, New York. We hope to see many of you there. We will now be happy to answer your questions.

Thank you. Ladies and gentlemen, at this time we will conduct a question-and-answer session. (OPERATOR INSTRUCTIONS) One moment, please, for our first question. Our first question comes from the line of Doug Fisher with Wachovia. Please go ahead. Mr. Fisher, your line is open.

Can you hear me?

Hello, Doug, this is Warner. We can now hear you.

Can you hear me?

We can hear you now, Doug.

Okay, sorry about that. Any comment on weather impact on gross margin across all the businesses versus normal? I know that native sales and margins were helped and interchange hurt by the much warmer than normal third quarter. Any comment on that from a gross margin for the three months and the nine months?

Yes. With regard to -- so basically we've outlined, Doug, the impact of weather in our reconciliation there. You can see that compared to the prior year of about $0.20. Is your question getting to how that may have unfavorably impacted our interchange margins?

Weather versus normal, not versus last year.

Actually, as it turns out for the quarter, and I guess compared to for the year, at $0.20 impact is generally pretty close to the impact year to date, on a weather normalized basis on Ameren as a whole.

So plus $0.20 on a consolidated basis --

Yes.

-- is the plus?

Basically what that implies is that through year to date our weather on the system as a whole was generally normal at this time last year.

Okay. And then any comment on where -- what portion of the range that you have for '07 things might be shading for, given the assumptions that you've laid out for the balance of the year?

Is your question what assumptions that we have for the rest of the year which may be --

No, where would you -- where do you think you're more likely to fall in the $3.15 to $3.40 range, given the assumptions that you have laid out, assuming normal weather for the balance of the year, etc. Can you give us any color on where in that range you're more likely to fall?

No, Doug, I understand your question now. No, not -- I think historically, and we provided the range, the range sort of stand as they are. We don't give any guidance as to whether the upper or lower end. Certainly the midpoint of that range is around $3.27, something like that, so no specific color other than that.

Okay. And then any -- how -- final question. Just how might you approach the Missouri -- potential Missouri rate filing, given the fact that we will have a governor's election next year?

Well, generally, Doug, when we look at the next Missouri rate case filing, one of the things that we'll pay most careful attention to is really our earned returns compared to what our allowed returns are, and we'll -- what will drive those issues, as I said, the incremental reliability investments that we're making in the system, as well as the rising cost environment that we're seeing across the board. That will be the primary driver. Of course, we'll be mindful of the progress of the environmental cost recovery mechanism rules. Those are certainly important aspects. And certainly we recognize as a gubernatorial election next year we'll be mindful of those issues, but I would characterize the first two matters as important issues for us to pay careful attention to in the broader picture.

Okay. Thank you, Warner.

Good enough.

Our next question comes from the line of Andrew Levi with Brencourt Advisors. Please go ahead.

Hey, guys. Good morning. Just to understand, I guess no better way to put it, you had some type of summer/winter rate differential because of the rate settlement, is that correct? Is that kind of the way to put it? And that you'll make that up in the fourth quarter, or some of it up in the fourth quarter?

Sure. The one thing I would say differently, it it wasn't due to the rate settlement. It was not part of this settlement that we just finished in Illinois. In fact, the rates were really the redesigned as part of our DST rate case last year.

Okay.

And so having said that, we do believe that, as Marty alluded to in his statement, our returns and our margins were higher during the winter months, and so we experienced some increases in the first quarter, during the summer months they're off, but we do expect to regain incremental margins, and as a result of that rate designed here in our fourth quarter for our Illinois regulated business.

So I guess kind of the way to look at it, the years over, I think consensus is around $0.51. If you kind of take the midpoint, you're probably closer to $0.60 for the quarter, I would guess. I don't know if you're willing to give any guidance or anything like that.

Well, as you know, we don't give specific guidance for the quarter, but I think when you look at our overall earnings guidance you can see on that, on the second slide there that, generally speaking, our Illinois regulated margins we have a negative $0.05 per share, even though we're a negative $0.21 per share year to date, and that negative $0.05 is principally being driven by loss in demand, relatively speaking.

Alright. Okay. So loss of demand, ex what we were just talking about. So that's more of a fundamental.

I'm sorry, Andy, you broke up there.

I'm saying loss of sales demand. Right. Is that what you're saying?

Yes.

But that's a function of the higher rates.

Right. And that's just simply scaling back a little bit.

How are you doing with receivables? Are you -- do you have a lot of late bills still, or is that kind of now with the settlement kind of petered off, or was there some effects in the third quarter from that?

Certainly when we spoke to you all about in this the second quarter, we had high levels of receivables. They have been mitigated somewhat since we began providing credits and bills -- excuse me, checks to our customers. They are still higher than they were at this time last year, but they are -- that fact is reflected in our guidance going forward already.

Okay. And that also, I assume, effective third quarter, but you didn't quantify that, right?

Yes.

Okay. Thank you very much.

Quantify the bad debt expense, certainly.

Oh, you did? How much was the bad debt expense?

We reflected the change in bad debt expense. And the impacts bad debt expense are principally driven year-over-year by Illinois regulated operations.

Okay. Thank you very much.

You're welcome.

Our next question comes from the line of Paul Ridzon with Keybanc. Please go ahead.

Good morning, Warner. How are you?

Hi, Paul. How are you?

Just looking for clarification. Previously you had seasonality in your rate structure. Now rates are flat across the year?

Generally speaking, that's correct.

And that's being picked up in the pass-through mechanism at the utility, and that's why we're getting whip-sawed around relative to last year?

I don't know if I would call it through the pass-through mechanism. It's part of the DST rate structure, but by and large where you're seeing it, that's correct. Again, as we pointed out, some of those rates will being again redesigned going into 2008 to try and alleviate the impact on customers from a winter perspective.

Okay. So we get to do this again next year.

Yes. I'm afraid that's right. And as we come out in our January meeting and the analyst day we'll try and provide some additional guidance around that to try and help you all through that from a quarterly perspective. Again, it's just taking the same dollars and splitting the pie up a little bit differently between periods.

So the fourth quarter we should see more or less the $0.16 pickup on Illinois regulated margins.

I think that's a fair statement again. If you look at our year to date result for Illinois regulated margins, we have a negative $0.21 per share year to date, and we've stated then on our guidance line through the end of the year that we expect Illinois regulated margins to be only a negative $0.05 per share.

And can you just remind us when new Missouri rates kicked in?

Sure. They kicked in effective June of this year.

So we'll also get a fourth quarter pickup there.

Year-over-year, you will, that's correct.

And then lastly --

-- electric order, Paul, consisted of three major items which drives the particular line item that we show on the chart there. Number one, electric rates did change. They did go up. And from a margin perspective, that $0.09, about $0.05 of that was due to the increase in electric rates. And then also, depreciation rates were lowered as well as income taxes. And so you had a pickup of about $0.02 per share in that $0.09 per share item related to depreciation, another $0.02 related to income taxes. So when you look at your income statement you may see the impact of the Missouri rate order in three different spots, both on the margin side, on the depreciation side, and on the income tax side.

So the rates will be volume metric, but the DNA and taxes will be kind of pro rata through the year?

That's correct.

Warner, I think it was 2000 the last time you had an analyst meeting. What's driving you to do this, and kind of what can we look for?

With regard to the analyst meeting, obviously, we're very frequently on the road meeting with analysts, but what we thought it was probably time, now that the Illinois situation had calmed down, for us to get out there and provide some input to analysts in terms of, not just with regard to our 2008 guidance, but really some of the key factors that I mentioned in my talking points and what we talked about at EEI in terms of what the business looks like going forward beyond 2008, actually looking out into 2009 and 2010. Because, frankly, we could have given a little bit of insight or had an analyst day and talked beyond 2007 at the beginning of this year, but because of the great uncertainty in Illinois, it's been rather difficult to really project much beyond 2007. And so we think it's an opportune time to come out there and speak to you all as well as bring some of our other senior management team to talk about some of these trends that we see prospectively for our business.

I guess we'll just wait until January and get those drivers then.

You bet. I'll give you more insight at that point.

Our next question comes from the line of Michael Lapides with Goldman Sachs. Please go ahead.

Hey, guys. Just a question for you in Missouri. Can you kind of help us understand what the earnings impact, not in dollars, but just how it would work, and the cash flow impact of the environmental rules that are being discussed in Missouri?

Well, Michael, I guess with regard to the earnings impact, it's really -- it's hard to say how that would impact. Certainly the environmental rules, as they stand now, will provide for more timely recovery in our rates of potential capital expenditures, as well as O&M costs. Of course, the rules are still in a draft stage. They're not finalized. The commission has to review those. And there will be hearings, and I'm sure many of the key stake holders will provide commentary on the existing rules that are before the commission. But in general, an environmental cost recovery mechanism will mitigate the regulatory lag for O&M expenditures, as well as capital expenditures and the returns on those capital expenditures. They will mitigate that with regulatory lag. And so, therefore, it should, overall, benefit the overall cash flows of the enterprise and potentially earnings as well. On potential earnings, just recover the costs on a more timely basis. It doesn't give you anything incremental from that perspective.

I want to make sure I understand something. Are you going to be allowed to earn on the pollution control investment, or just recover the cost, both operating and capital? I mean, is it rate based or is it not?

Sure. And, Marty, you can comment, because you're closer to some of the rules, but we would earn a return on those investments as they stand today, is that correct?

That's right. It would be our expectation to get return of and return on, Michael.

Got it. Okay. Thank you, guys.

Our next question comes from the line of Yiktat Fung with Zimmer Lucas Partners. Please go ahead.

Good morning. Most of my questions have been answered. I just have a couple of follow-up questions regarding -- first of all regarding the Illinois summer rate structure change. With regards to the negative $0.39 that was experienced this quarter, that was related to Illinois regulated margin, how much of that was due to this rate design change?

I would say when you look at the negative $0.39, I would say they were driven by two principal factors. One is the rate design change, which is the vast majority of it. I would say that was $0.30-ish, relatively speaking. Then some demand destruction, which was probably $0.03 or $0.04, and then you have a few other cats and dogs in there to get to $0.39, but those are the principal drivers.

Okay. And on an unrelated topic, in some of the other slides that the company has put out, one slide details the impact of the Missouri rate order, and there's a, I guess, pretax income effect of $112 million. Part of that effect was due to this income tax method which you've laid out at $25 million. In terms of what the actual after-tax impact of that, do we have to make an adjustment to the income tax method change, or do we not have to since it's already a tax item?

If this answers your question, this is Marty, I think on that slide that we presented, we had grossed up the income tax change to get to a pretax number. The $25 million is a pretax number that you would have to tax-effect to get to the impact on the income tax line item.

Alright. That's all my questions. Thank you very much.

Any additional questions, Mr. Fung?

No, I do not have any additional questions.

Thank you. Our next question comes from the line of David Grumhaus with Copia Capital. Please go ahead.

Morning, guys.

Morning, David, how are you?

Good. How are you, Warner? Just a quick one for you. Obviously, the guidance for the year is still pretty wide. Is that more just a custom of not narrowing that, or are there some things in the last six, seven weeks of the year that can really move the numbers that much?

Yes, we understand that the guidance -- I would say it's more of a custom at this point that we just didn't choose to narrow the guidance any further from the first quarter, keeping in mind that we reaffirmed guidance prior to the EEI conference, and we thought it would be more straightforward to just simply, because we weren't going to stay within the range that we announced in the second quarter that we just basically reaffirmed the existing guidance that we had back then.

Okay. That's helpful. That's all I got for you. Thanks.

Sure.

(OPERATOR INSTRUCTIONS) And our next question comes from the line of Dan Jenkins with State of Wisconsin Investment. Please go ahead.

Hi. Good morning.

Good morning, Dan.

First of all, I was wondering, your short-term debt is up to, looks like, $1.2 billion. Do you have any plans to term that out, and if so, at what entity would you be looking to --

Yes. That is true, our short-term debt is at levels that historically we usually don't operate at. And so, yes, over the next, certainly, 12 months we're going to take actions to term some of that out into longer term debt, because most of that is for construction projects that have been either in process or completed at this point in time.

And what entities would you -- would that need to be issued at? Do you --

Well, I think we won't go into specifics of the particular entities, but frankly, when you look at the debt that we've incurred, it's going all across the enterprise. Our Illinois regulated entities are experiencing increases as well as our Missouri and frankly our nonrate regulated. I think the other thing you have to look to there is that we do have our overall cash balances are up a little bit, so you can't look at that particular item only in isolation. But we have a fairly extensive capital program across the enterprise. And so we will be very active in the capital markets to finance those capital projects in the future.

Okay. And then I was looking at your operating statistics, and I was just wondering if you could give a little color on the mix of the generation between the Genco, the AERG, and the EEI has kind of changed around. And I was just wondering if you could give me some color on what's driving those changes year-over-year.

Let us make sure we can answer those, the specific question that you're posing. You say the mix of the generation decreased for AERG and increased for Genco. Is that what you're saying?

Right, and even the EEI is down a little bit as well.

Yes, I think, frankly, what you're seeing is more a function of plant outages, both scheduled. We did, especially at the AERG units, have an extended outage at one of those plants there. And I think that is nothing more than that, as well as EEI having some outages this year. Nothing more than.

Okay, and then the line below that, the appeal cost for KWH. Is that just a function of our coal prices, or is that a function of outages, or what's contained of driving that?

I would say the fuel cost increases, as we've highlighted going into this year, and we continue to discuss, is simply a function of higher commodity and transportation costs we're seeing across enterprise, more so that than it is a function of the plant outage schedules.

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

You're welcome.

Thank you. Thank you. Our next question comes from the line of Danielle Seitz. Please go ahead.

Hi. Just one detail question. Will you use pollution control bonds, and is there an advantage still to use this type of debt financing for the (discover) equipment?

Good morning, Danielle. I have Jerre Birdsong, our Treasurer here, and I'll let him address that question for you.

Thanks.

Yes. Since many of our planned capital expenditures are environmental they will qualify for tax-exempt financing, and we will do that to the extent that we are able.

Is there a -- I mean, from a rate standpoint, is it -- is there a major advantage?

Yes, the tax-exempt rates are significantly less than the rates otherwise would be. So, yes, we would make use of those because of the advantage on the interest rate.

Great. Thank you.

You're welcome, Danielle.

I'm not showing any additional questions at this time. Please continue.

Great. Thank you all for participating in this call. Let me remind you, again, that this call is available through November 16th on playback for one year on our website. The announcement carries instructions on listening to the playback. You can also call the contacts listed on our news release. For those on the call who are financial analysts, please call Bruce Steinke or Teresa [Niswender]. Missouri and national media, should call Tim Fox. Illinois media should call Erica Abbett. The contact numbers are on the news release. Again, thank you for dialing in.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect.