Greetings and welcome to the Ameren Corporation's First Quarter 2013 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Doug Fischer, Senior Director of IR for Ameren Corporation. Thank you, Mr. Fischer. You may begin.

Thank you, and good morning. I'm Doug Fischer, Senior Director of Investor Relations for Ameren Corporation. On the call with me today are Tom Voss, our Chairman, President and Chief Executive Officer; Marty Lyons, our Executive Vice President and Chief Financial Officer; and other members of the Ameren management team. Before we begin, let me cover a few administrative details. This call is being broadcast live on the Internet, and the webcast will be available for 1 year on our website at ameren.com. Further, 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. To assist with our call this morning, we have posted a presentation on our website that will be referenced by our speakers. To access this presentation, please look in the Investors Section of our website under Webcasts and Presentations and follow the appropriate link. Turning to Page 2 of the presentation, I need to inform you that comments made during this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those about future expectations, beliefs, plans, strategies, objectives, conditions, events and financial performance. We caution you that various factors could cause actual results to differ materially from those anticipated. For additional information concerning these factors, please read the Forward-looking Statements section in the news release we issued today and the Forward-looking Statements and Risk Factors section in our filings with the SEC. Tom will begin this call with an overview of first quarter 2013 results and our 2013 earnings guidance, followed by an update on recent business developments. Marty will follow with more detailed discussions of first quarter 2013 financial results and financial and other matters. We will then open the call for questions. Now here's Tom who will start on Page 3 of the presentation.

Thanks, Doug. Good morning, and thank you for joining us. Today, we announced first quarter 2013 net income from continuing operations of $0.22 per share compared to first quarter 2012 net income from continuing operations of $0.15 per share. First quarter earnings from our rate-regulated utilities were in line with our expectations. Reflecting our March agreement to divest our merchant generation business to an affiliate of Dynegy, the results of this business are now classified as discontinued operations in our financial statements. The increase in first quarter 2013 earnings from continuing operations compared to first quarter 2012 reflected improved earnings from Ameren Missouri and Ameren Illinois. Colder winter weather which drove higher electric and natural gas sales lines and new rates for Ameren Missouri electric and Ameren Illinois transmission service both effective in January 2013 were key drivers of the earnings improvement. The comparison also benefited from the absence in 2013 of a required donation that was made in 2012 associated with the implementation of formula-based electric delivery rates in Illinois that year. These favorable factors were partially offset by a reduction in weather normalized revenues recognized in this year's first quarter by Ameren Illinois under electric delivery formula ratemaking. In addition, nonfuel operations and maintenance expenses were higher at Ameren Missouri. Marty will provide more details on our earnings in a few minutes. Moving to Page 4. Today, we also established 2013 earnings guidance for continuing operations in the range of $2 to $2.20 per share. The presentation of guidance on a continuing operations basis reflects the classification of the merchant generation business as discontinued operations in the first quarter. Also, this guidance incorporates approximately $0.20 per share of parent company and other costs, including certain costs that were previously allocated to the merchant generation business. We expect to…

Thanks, Tom. Turning to Page 10 of the presentation. Today, we reported a first quarter 2013 net loss, combining results from both continuing and discontinued operations of $0.60 per share, compared to first quarter 2012 net loss of $1.66 per share. The first quarter 2013 net loss included a loss of $0.82 per share from discontinued operations, incorporating an impairment charge to write-down the merchant generation business to its estimated fair value based upon the terms of the divestiture and other exit related after-tax charges. These after-tax charges were $195 million or $0.80 per share for the first quarter of 2013. Those charges will be reviewed as we move through 2013 with adjustments recorded in our financial statements as needed. We currently expect that the total after-tax charges will be less than the approximately $300 million we estimated when we announced the divestiture. As Tom previously discussed, Ameren recorded first quarter 2013 earnings from continuing operations of $0.22 per share, compared with first quarter 2012 earnings of $0.15 per share. On Page 11, we list the key factors that drove the $0.07 per share improvement in earnings. Factors favorably impacting first quarter 2013 earnings compared to those of the first quarter of 2012 included a return to normal winter weather compared to much warmer than normal weather in the first quarter of 2012. This boosted electric and natural gas sales lifting earnings by an estimated $0.10 per share and has estimated $0.07 in Missouri and $0.03 in Illinois. In addition, new rates from Missouri electric and Illinois transmission service increased earnings by $0.05 per share. And the absence in 2013 of a required nonrecoverable donation made in 2012 associated with the implementation of Illinois formula ratemaking for energy delivery service boosted earnings by $0.02 per share. These positive factors were…

[Operator Instructions] Our first question comes from Paul Patterson with Glenrock Associates.

Sort of to the Missouri legislation, I mean, given that we got the May 17 deadline sort of showing up here and sort of the lack of movement over the last several weeks, how should we think about the potential for its passage? And if it doesn't pass, given the substantial amount of CapEx and rate-base growth that you guys have, how should we think about your ability to manage regulatory lag, if -- in its absence?

Sure. Paul, this is Marty. I think I'll let Warner Baxter, who's here with us, President of Missouri Operations. Go ahead and answer that question.

So a couple of things. First, your first question is related to the prospects for the passage of legislation. And you're right. And certainly, as we sit here today, it's difficult to predict really whether the legislation be passed at this time. And as we've talked about in the past, it's always a challenge to try and pass legislation. And certainly, with only 2 weeks left in the legislative session, and that challenge is going to be greater, especially in light of the continued opposition from certain consumer groups and certain large customers. But having said that, our team is going to continue to work closely with legislative leaders and other key stakeholders to see if we can move this legislation forward. And should we not get that legislation passed this session, we will continue to work tirelessly to get constructive legislation passed in the future to address, as you said, some of the additional capital expenditures that we may be making in the future and to address regulatory lag in Missouri. And the bottom line, we think this legislation and this path represents good long-term energy policy for Missouri, and it's going to help us address the aging infrastructure and certainly meet our customers' long-term needs and expectations. And the legislation we had before, the legislature today certainly has robust consumer protections. So we're going to continue to advocate for that policy because we think it's simply the right thing to do. Now with regard to the questions in terms of how we handle regulatory lag. We're going to continue to do what we've done in the past, and that we're going to continue to be very disciplined in our cost control and how we allocate capital in our business and certainly among all the Ameren businesses. And we're going to do what we've done also in the past and that's aligning our spend with the regulatory policies, outcomes and economic conditions. When the need arises, we will continue to file frequent rate cases to recover those investments. And as I said before, we're going to continue to pursue changes in the regulatory framework that will support investment because we are convinced that is the absolute best policy for the state of Missouri in the future.

Okay, I hear you. But just in general, I guess, there is a lot of opposition and I mean, in the absence of a change in regulatory policy, should we be thinking about sort of a ROE lag as we go forward, if there is no improvement, or -- I mean, I'm sure you guys are working hard or whatever, but just in general, I mean, how -- if you could just -- I don't know if you can address that or not, but just how should we think about that? And then just also sort of related, SB 9 sailed through the legislature in Illinois very, very well, but the gas stuff, the gas legislation seems to be sort of held up. I was just wondering if you could compare and contrast that.

Paul, this is Marty. I'll maybe try to tack on to what Warner said. I think as you look at what we've been able to accomplish over the past number of years in terms of Missouri regulation and Missouri earnings, certainly, over a series of rate cases, we've been able to achieve use of various riders and trackers for fuel or for energy efficiency or things of that nature, which have provided us a better opportunity to earn our allowed returns and we have meaningfully closed the gap between earned and allowed returns. Clearly, in the absence of some better framework for capital investment, it's hard to be able to earn those alloweds on a regular basis, if you're deploying significant amounts of capital. When you look overall at our plan going forward and you look at our 7% rate base growth plans across the enterprise, a heavy focus on those jurisdictions with formulaic ratemaking with the kinds of frameworks that allow us to make the investment for the benefit of our customers to grow jobs and to grow that rate base. If you look at the trends we put out in the past while we're investing still -- planning to still invest substantially in Missouri, the growth is at a much lower pace, again, providing ourselves the opportunity to earn something closer to our alloweds. And again, as Warner said, making sure that we continue to control our spending in order to position ourselves for success there. Now transitioning over to Illinois, you're right, the formulae -- the changes or the modifications to the formulaic rates for electrics did pass both chambers with very strong majority of votes there, and that's now before the governor. And then as it relates to the gas legislation, things have -- I'd say stalled a little bit there. I think legislative interest has moved somewhat away from the gas formula ratemaking and is focusing maybe on something more like an infrastructure rider or something of that nature. May I remind you that with respect to gas in Illinois, we do have the use of 4 test years. We've got a gas rate case pending right now and incorporates those 4 test years and it's where things kind of stand in Illinois.

Our next question comes from Michael Lapides with Goldman Sachs.

I understand this week that the Missouri legislation actually hit a little bit of a speed bump. Just curious, are there specific concerns the industrial customers have and is there ways the legislation could be tailored to alleviate some of these concerns?

Michael, this is Warner again. The bill was debated last evening, as Tom said, and they ultimately did come to a vote. Certainly, there've been concerns cited by some of the industrial customers in terms of impact on rates and those types of things. And there have been efforts made to try and address that in the legislative -- in the legislation, and we will continue to have those discussions with those customers and other stakeholders to see if we can get something across the finish line. So we're going to continue to push to see if we can get something constructive done during these last 2 weeks.

Got it. And turning to Illinois, assuming that SB 9 is eventually made into law and assuming the litigation around the prior rate case kind of turns in your favor and upholds the law passed in 2011, is there still any remaining structural lag that exists for your Illinois distribution businesses? Meaning, are there are still some level of costs that simply aren't recoverable in rates? And if so, could you kind of quantify that level. Lots of state commissions don't allow things like incentive compensation or regional or local marketing costs, donations, that type of thing. Just trying to think about kind of what are the remaining drivers of lag, if any, once the whole legislative and litigation process plays out and assuming it plays out in your favor?

Sure, Michael. Thanks. There are some of those costs. And if you look back to our slides from our year-end call, we did outline some of those sort of structural things, if you will, that were there. When the law was passed in Illinois, while it did provide for formulaic ratemaking for the vast majority of costs that are incurred. Historical ICC ratemaking adjustments were preserved by that legislation. So we outlined some of those nonrecoverable costs. I think it was on Slide 13 of our year-end slide. Some of those nonrecoverable costs did include about $8 million of historical ratemaking adjustments. Those are the kinds of things that would be impactful going forward. This year, we identified some other things like $7 million of certain electrical system rework costs. Those, we expect to be -- they've occurred over a couple of years, last year and this year but we do expect those to diminish and to go away. So there are a little bit of things that continue to be there and then we have the opportunity and we'll continue to focus on those costs and make efforts to control and reduce those to the extent possible. But for the most part, Michael, the costs we incur in serving our customers, improving our service and reliability, are recovered through the formulaic process.

Got it. And then a broader transmission question. We've seen in some regions of the country, in New England and Colorado and California, intervenors come in and file at the FERC to dramatically lower the base ROE in some of the RTOs. We haven't seen that type of Section 205 or --- I think it's 206 litigation yet in the MISO or in the SPP, I don't think. But just curious, if it did play out and if you saw lower authorized base ROEs for transmission, how would that impact your views in terms of dedicating as much capital as you're planning to interstate transmission projects?

Sure, Michael. You're right in terms of we haven't seen that type of push here. I think as you know, our FERC-authorized ROEs aren't really incentive ROEs like you might see in some jurisdictions. But to your question, I mean, to the extent that the ratemaking treatment or the ROEs were changed, it detracts from the incentive that exists today in investing in these large regional projects. They are significant amounts of capital deployment. They do like -- do have risks associated with them. We believe that the ROEs that we've got are appropriate. And to the extent that ROEs were reduced, it certainly would affect ours and I think other companies' thought process is about the investment opportunity. Whether they were abandoned or not, I certainly won't speculate. I'm just saying that it certainly becomes less attractive and there is less incentive there to take on these big projects.

Our next question comes from David Paz with Wolfe Research.

I just have a question on the utility guidance or, I guess, overall guidance. But it seems that the midpoint of your guidance $2 to $2.20 reflects a utility midpoint of $2.30. Is that fair?

Yes. I think that is fair. The -- when we provided the guidance, which is now guidance from continuing operations of $2 to $2.20, we also mentioned that we expected for the full year parent and other costs of about $0.20. And so that would -- if you do the math as you've done, that would imply for the regular utilities about $2.30.

Okay. And then just, I guess, what's driving that $0.05 increase in utility side?

Well, I think overall, as we go through the year, we've certainly seen -- I'll comment on a few things since you've opened the door on guidance, which I appreciate. First, on the -- I'll talk about maybe about the parent and other of about $0.20 that we see there. What's driving that is that -- as you go through sort of the accounting for continuing operations or discontinued operations, you've got to take costs that maybe were previously allocated to the merchant business. And to the extent that those aren't naturally going away with the business you're disposing of, you would continue to classify those in continuing operations. So some of the things driving that $0.20 are interest on the parent company that of about $425 million of parent company that -- which is about $0.10 of interest or so, and then there is G&A cost previously allocated to that merchant business that will be retained. For the time being, once the segment, the divestiture is actually completed, we'd certainly have the opportunity then to reduce and drive some of those costs out. And then there are other just sort of parent company costs that have existed through time that are in that $0.20. Then overall, with respect to utility results for the first quarter, as we talked about a lot of the improvement of last year was really driven by weather. We saw about a $0.10 improvement from weather overall. But when you strip out the weather and you look at weather normalized sales, overall, those were positive during the quarter. Overall, we saw residential and commercial sales up about 2% on a weather normalized basis across the company. And that was a positive sign and a little ahead of our expectations. We were expecting sort of little growth this year. We haven't really modified our expectations for the remainder of the year. We still expect little growth for the remainder of the year, but the quarter was a positive from that perspective. The sales versus normal, I mean -- meaning weather versus normalized, I should say, was a neutral. We didn't see much impact from weather versus normal conditions. So -- but we did see on the weather-normalized basis a bit of a pickup. And we would also expect to see for the remainder of the year some positive variances versus expectation in O&M, and we're also -- they are also expecting to see some positives from further infrastructure investment rate base growth in those areas where we have the formula ratemaking. So those are some of the drivers on the regulated side. I'd say that those -- we give the $2 to $2.20 guidance. It's $0.20 range. That parent company and other $0.20 is an approximation. I'd say probably, there's a little bit of a rounding up there. And so therefore, you derive $2.30. I'd say there would be a little bit of a rounding up there, too, in terms of the regulated midpoint.

Okay. Just so I heard right, you said weather-adjusted -- weather-normalized sales were up 2% residential?

Yes, residential and commercial combined across the company. And we were pleased to see it. We saw a little bit of a positive growth in the same categories in the fourth quarter of last year though, you may recall, I think others do, in the third quarter last year, they were down. So weather normalization is an approximation. And when we looked over the course of last year, we had some ups and downs during the quarters over the course of the year. We actually saw residential and commercial sales down a little bit versus 2011 levels. So we're happy to see this trend. It's good to have this starting out the year, a little bit of a positive trend, but we'll -- I think we've still got a cautious view for the remainder of the year.

Got it. I appreciate walking -- you walking me through those steps. Just one quick question on the dividend. What is the way we should look at dividend growth going forward from here?

Yes. We've talked in the past about payout targets in the 55% to 70% of regulated earnings range. And we've given out specific guidance on when to expect increases going forward other than to say that we do have the 7% growth rate planned in rate base. With that, we would expect to grow our regulated earnings over time. And as we grow those regulated earnings, we would expect also to be in a position to be able to recommend to the board increases in the dividend.

Okay. So that 55% to 70% is regulated earnings, excluding the $0.20 or whatever that ultimately becomes of parent drag?

Yes. I think that's a fair way to think about it.

Our next question comes from Julien Dumoulin-Smith with UBS.

Kind of following up on the last one, actually. So you talk about $0.20 this year. You've talked about that abating somewhat. How much of that is due to the interest expense refi-ing in '14 and, I suppose, midyear and onwards. And how much of this is fundamentally just being able to reduce the G&A over time with the merchant gen segment out of the way now?

Sure. A good question. So the $0.20, as I broke it down, was probably about -- the $0.20, probably about $0.10 of interest and then $0.10 of G&A previously allocated to the merchant business, as well as some corporate overhead cost that we've had historically. So when you think about that parent company debt, as you know, $425 million of debt, 8.875 percentage or straight [ph]. In today's market, we'd be able to reduce that substantially, I think, better than -- cutting that better than 50%, Julien, maybe even by 2/3. So on an annualized basis, decreasing that $0.10 by $0.06 or so wouldn't be unrealistic on an annualized basis. You're right. The refi for that would be a May time frame of next year. And then with respect to some of these other costs like the G&A costs that are in the parent company number this year that historically have been allocated to the merchant business, that's probably about $0.06 over the remainder of this year. And we certainly can't reduce or eliminate those costs until the divestiture is completed. But then we we'd expect to be able to reduce those through time. We talked a couple of calls ago about the expectation that we believe we could eventually eliminate those fully. That may take through the end of '15 to be able to get there when they're fully gone. But we would expect to be able to begin to reduce those substantially next year. And so what we've said is we expect that $0.20 this year to go down to a range of $0.10 to $0.15 next year. And then those would -- those costs would further diminish the year after that as you get the full year benefit of the refinanced parent company debt and you fully reduce the drag from those G&A costs previously allocated to the merchant business.

So if I hear you're right, call it a run rate around '15 time frame, $0.20 minus $0.06 with interest expense, at least minus another $0.06, once you fully eliminate the allocated cost, so less than $0.10 easily.

Yes, less than a $0.10 is what I'm getting as well.

All right, fantastic. And then going over to the ATX side of the world, perhaps a little bit similar to the last question. When you're thinking about your successes on developments, what are the next important data points? And as you think about it, how do you feel about the execution on the -- just deploying capital, if you will? And maybe a secondary question off that, also looking at CapEx, how would EIMA change your CapEx outlook, too? Your EIMA, yes.

Yes. I think I missed the first part of your question. What was the base part of your question?

Well, the base part was more ATX, how do you feel about deployment, what are the next key milestones in terms of it? I mean, it seems like there have been some developments in the quarter.

Yes, no, there would, so -- in terms of outline, there have been good development. So certainly filed for the ICC Certificate of Public Convenience and Necessity as it relates to the Illinois Rivers project, which is sort of a big centerpiece, multi-value project that we've got planned over the next several years, $1.1-billion project. As we updated, the staff filed some initial testimony. Overall, we saw it as positive, where the staff overall was recommending that the ICC grant a certificate for the project. We've recently, as you know probably, filed rebuttal. For the upcoming dates there, our ICC hearing is in the May time frame. And we're still expecting an order. And we're optimistic that we'll see the -- get the ICC certificate and be able to move forward then late this year with the right-of-way acquisition and next year with that full-range construction activities. So we're anxious to begin deploying capital relative to that project. We feel like the testimony we provided in response to ICC and others' testimony, we hope, was responsive. And we hope to see the ICC approval and begin to move forward. So there is -- those are some of the key milestones. Certainly, those -- the expectation of being able to move forward with that project on sort of the time frame I just outlined is really key to the overall plans we have to grow rate base at that 7% rate that we talked about earlier.

Great. And then EIMA, just I'm curious, like how much CapEx upside are we talking there?

Well, there -- what we did, we really -- if you look at our CapEx plans, we didn't substantially change those as a result of the ICC order the last year. We eliminated about $30 million of the planned capital spending for this year but didn't really substantially change the plans that we have longer term. We're certainly optimistic that we will see the appropriate modifications made to the legislation to provide the clarity about the legislative intent. And at that point, we'd be in a position to add back that $30 million of reduced capital spending to our forecast.

Our next question caller is from Ashar Khan with Visium.

I think most of my questions have been answered. Warner, I just wanted to -- just going back to the legislation, we know that end date of the thing. But what is like -- right, it has to first get passed from the Senate then go to the House? And if I'm right, is the bill in the House the same right now? Or does it have to go to a committee? Can you just walk us through what the path could be for approval? How does it go from one to the other and then get approved?

Sure, sure, Ashar. This is Warner. One, there are several vehicles that are still available in both the House and the Senate. You have your original bills, which are HB 398, House Bill 398, and then Senate Bill 207. If those bills would be approved, they would have to go through committees on either side of the House to move forward. And so a likely path to move forward now, between now and May 17, would be to amend and approve Senate or House Bill. Once -- so say a House Bill is on the Senate side and that has been amended by the Senate and sent back over to the House, then simply, the House can take that bill and vote it up or down. It does not have to go through all the committee process. And indeed, that's certainly an approach that's being considered in both the Senate and the House right now. So is it possible to get something done in the next 2 weeks utilizing those vehicles? The answer is yes. But as we said before, you have 2 weeks. And that still takes time to get through some of the processes. But it isn't as extensive as the original bill process we have today.

Okay. But just practically thinking, we have to see, say, some movement by the 12th or 13th of May. Is that a good point because it has to pass the Senate? Or can it all be done on 1 day, the last day?

Well Ashar, the only thing I've seen in Missouri politics and the legislature, it is pretty amazing how things can get done in the last few days. Having said that, the more time you have to move things, the better you are. And certainly, every day is precious when it gets down to the last 2 weeks. So I can't say there is a specific cutoff date one way or the other, but there are hosts of -- there are vehicles. But just because there are vehicles doesn't mean that there still aren't some challenges to get through both sides of either the House or the Senate.

Our next question comes from Neil Kalton with Wells Fargo.

Just a question -- a follow-on on ATX and the CPCN process. First question is, could you elaborate a bit on the staff position, what that kind of came back with it? And how you responded to it? What were the concerns? And the second question and separate from this is, I believe you're pursuing a couple of other meaningful projects with ATX in Illinois. And I want to know how you think about the likelihood and timing of these projects? What do we need to see happen to sort of push these into being -- happening? Would it be low growth, coal unit retirements, et cetera?

Sure, Neil. This is Marty again and -- one thing I'd refer you to overall what I thought was a good piece of testimony is the president of our transmission company, Maureen Borkowski, and the testimony that we filed recently in response to the ICC, to interveners in the case. But Maureen's testimony, I think, provided sort of an overview of the issues that have been raised or concerns that have been raised and the overall ATXI response to those. And she summarized well, I think, both the concerns, as well as the comments that we were providing back. And I think, Neil, overall, in my view, the interveners I mentioned earlier, the staff in particular, overall recommended that the ICC go ahead and provide the certificate. But there were questions raised about the need for certain specific substations. There were concerns or questions raised about the paths for certain segments of the overall project and the lines. And in that regard, we have provided testimony supporting why the substations we proposed are needed for reliability or other reasons and why the routing that we proposed makes sense. And I think there were also a number of stipulated sort of settlements reached with a number of parties that had raised questions along the way as well. And those were also, again, summarized in Maureen's testimony. So again, by and large, in summary, I felt like, looking at it, that overall that the project was certainly needed. The question was about the path and the need for certain elements. But again, we feel like we've largely addressed those in the testimony. So I think that's the Illinois Rivers project. The MISO has already approved a number of other multi-value projects back in December of 2011, the Spoon River project, the Mark Twain project. And then there are some other pending projects, like the Big Muddy River Project. All those projects, again, have been approved by MISO as multi-value projects and -- so the plan would be to go ahead and move forward with those projects over time. And I don't know that there is really anything pending in terms of further demonstration of need for the project. It's just a matter of sequencing the projects and moving forward on them.

So just to clarify then, with those projects that have been approved by MISO, should we sort of expect those from an end-service date as being sort of outside the 5-year period. Kind of get the Illinois Rivers through and done and then as you kind of go in and go for other projects as well over time?

Yes, that's -- I think that's largely a way to think about it. I mean, within the 5 years, there could be certainly some spending on those projects. But the overall transmission growth plans that we have certainly do extend beyond the 5-year window that we're presenting.

Our next question comes from Mitchell Moss with Lord, Abbett.

Just a quick question on the Genco business. There's been some talk on the other -- from some of the other conference calls today that there's been some basis issues. Could you talk about whether or not you've seen any basis issues for some of your plants?

Yes, sure. I think that -- over time, I do think that the -- historically, at the Illinois hub location, there has been some basis discount to Indy hub, which is typically looked at as a more liquid trading hub in our region. And what we've been seeing any way in the recent, say, 12-month time frame for the merchant business is probably a basis discount to Indy hub around the clock of about 12% or so. And we've seen those basis differentials certainly fluctuate over time.

Did you see it widen at all in the first quarter?

It -- I can't comment specifically on the first quarter, but it has fluctuated over time. And a 12% kind of basis differential isn't historically out of the norm or abnormal when you look back to say that's some of the 2011 data and the like. So they just -- it does fluctuate over time.

Okay. And was it -- do you see it as a general transmission constraints? Are there, I mean, just line outages over time? Or are there any other unique issues going on that you've observed?

I can't really pinpoint any unique issues as it relates to our system. The things you mentioned are things that historically have impacted basis differentials. So certain generator outages or transmission line outages, load fluctuations, all of those things can affect basis differential from time to time. We'll see basis differentials differentiate seasonally based upon demands on the system. So all of those things you mentioned, certainly, are contributors from time to time.

Our next question comes from Andy Levy with Avon Capital.

Most of the questions were asked, but just to kind of do some math here. I don't know if you'll be willing to walk through it with me, but -- so kind of based on starting in that $2.20 to $2.40 range at utility earnings that you kind of talked about for this year, right. I mean, that's...

Yes, well, what we did is we gave guidance for $2 to $2.20. And we said the parent and other were approximately $0.20, which would imply approximately $2.30 for the utilities.

Right, midpoint.

Yes, so the midpoint, right. So we didn't give out that specific rate.

Okay. I follow you. I apologize. I said bear with me here. But then you seem to have like rate base growth of about 7% a year, if I'm not mistaken, which probably turns into about 5% earnings growth. And I know you haven't given guidance. But is that kind of a good ballpark to kind of think about?

Well, you're right. We haven't given that out. What we've talked about is that 7% growth rate in rate base and -- but I think if you model it out, you should see some sort of similar trend rate with respect to earnings. But certainly, I'm not commenting on specifically the 5%.

I've got it. So if you kind of did that and you kind of go back to Julien's -- answers to Julien's questions, I mean, you probably could look at earnings in the $2.50 type range for '15 and that's kind of what I'm thinking. But kind of what you said on the rate base kind of helps me with that. So I appreciate it. That was my question.

Our next question comes from Paul Ridzon with KeyBanc Capital.

First of all, you indicated the Illinois timing issue should be a headwind in the second quarter. Can you kind of quantify that?

Yes, sure. Thanks for the question. So we did talk a little bit about one of the headwinds we saw in the first quarter compared to last year. It wasn't unexpected from our perspective but was just the timing of revenue recognition this year versus last year as it related to the Illinois delivery -- electric delivery service. So in Q2, we expect that to maybe a $0.03 negative versus last year.

Is this going to continue to whipsaw around? Or do we lap this at some point and it stabilizes?

Yes, hopefully, we'll see it stabilize next year versus this year. Maybe I can -- I'll try to describe for you sort of the phenomenon that's causing this though, which is that we're -- obviously, our earnings for the full year, our revenues for the full year, are ultimately determined by our actual costs incurred in that year. As we got into -- the last year was the first year, obviously, that we were accounting for this new regulatory regime, if you will. Going into last year, we projected what our cost of service was going to be. We projected what the ROE was going to be based on 30-year treasuries, and we had an expectation of how the Illinois law would be applied by the ICC. So as we went through the first couple of quarters last year, we were recognizing revenue based on those overall expectations. As we got into the third quarter of last year towards the end, we saw that the cost of service was less than the -- cost to service for the full year was going to be less than we had previously estimated. We had an ICC order, which changed our expectations. And the 30-year treasuries were coming out as well lower than expectations. Therefore, in the third quarter, we had a downward revision to the revenues that have been recognized over the first half of the year and then a further adjustment in the fourth quarter. So those -- the accounting model is still in place and we're still, say in this first quarter, recognizing revenues based on our full year expected cost of service for that business. So there still could be some volatility from year to year. But I would expect that to dampen over time. Last year was the first year where we're kind of working through this new process and, I think, probably bigger fluctuations this year versus last, than we should see moving forward. So in Q1, we estimated that the impact was about $0.08 in terms of negative impact versus last year. Due to that, as I mentioned, about $0.03 in the second quarter. We expect that, that then will reverse. As I mentioned, last year in the third quarter, we had a downward revision. We expect that then, year-over-year in the third quarter of this year, we would see a benefit. And it could be in the range of as much as $0.10 of positive impact in Q3, another $0.04 in Q4 so that over the course of the year, you're up a few cents versus last year.

And what's the order of magnitude of the Missouri Appeals Court depending on how that goes?

Yes. So that could swing either way. And you'll recall that we have actually recognized a charge in the prior year of about $18 million or $0.04. So that could reverse. On the other hand, if that goes against us, it could be a negative of up to about another $26 million or $0.06. So it's a range of about a plus $0.04 to a minus $0.06 on that.

And you would keep that in ongoing earnings or...

Yes. We have historically had that in ongoing earnings. And I would say on the minus $0.06, that would really be dependent upon how things ultimately played out with the commission on those remaining costs, so that we do have before the commission a request for accounting authority order on that to be able to defer and recover some of those costs. But we'll just have to see how all of that plays out.

We have no further questions at this time, Mr. Fischer. So I would like to turn the floor back over to you for closing comment.

Thank you for participating in this call. Let me remind you again that this call is available for 1 year on our website. You may also call the contacts listed on the release. Financial analyst inquiries should be directed to me, Doug Fischer, or Matt Thayer, my associate. Media should call Brian Bretsch. Our contact numbers are on the release, as I said. Again, thank you for your interest in Ameren, and good day.

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