Greetings, and welcome to the Ameren Corporation Fourth Quarter 2014 Earnings Call. At this time, all of the participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Mr. Doug Fischer, Senior Director of Investor Relations for the 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 Warner Baxter, our Chairman, President, and Chief Executive Officer; and Marty Lyons, our Executive Vice President and Chief Financial Officer; as well as 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 one year on our Web site at ameren.com. Further, this call contains time-sensitive data that is accurate only as of the date of today's live broadcast, and redistribution of this broadcast is prohibited. To assist with our call this morning, we have posted on our Web site a presentation that will be referenced by our speakers, who may use terms or acronyms that are defined in the presentation. To access this presentation, please look in the Investor section of our Web site 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, events, conditions, 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 sections in our filings with the SEC. Warner will begin this call with an overview of 2014 results and our outlook for 2015 and beyond. Marty will follow with a more detailed financial and regulatory update. We will then open the call for questions. Before Warner begins, I would like to mention that all per share amounts discussed during today's presentation, including earnings guidance are presented on a continuing operations and diluted share basis, unless otherwise noted. Now here is Warner, who will begin on Page 4 of the presentation.

Thanks, Doug, and good morning everyone, and thank you for joining us. Today, we announced 2014 earnings of $2.40 per share, within the upper end of our 2014 guidance range. This represents a 14% increase over 2013 results. This strong earnings growth reflected increased Illinois electric delivery and FERC-regulated transmission earnings under formula ratemaking, which were driven by infrastructure investments made to better serve our customers. The earnings comparison also benefited from increased rates for Illinois natural gas delivery, decreased interest charges, the substantial elimination of parent company costs previously allocated to the divested merchant generation business, and the absence of Missouri fuel adjusted clause-related charge taken in 2013. Marty will discuss these and other 2014 earnings drivers in a few minutes. Turning to Page 5; last year at this time we discussed how excited we were about our strategy for investing in and growing our rate-regulated electric and gas utilities in order to provide superior value to our shareholders and customers. Today, I'm pleased to report on our successful execution of the strategy in 2014. The first element of our strategy is to invest in and operate our utilities in a manner consistent with existing regulatory frameworks. Towards this end, in 2014, we allocated significant amounts of discretionary capital to those businesses where investment is supported by regulatory frameworks that provide fair, predictable, and timely cost recovery. Our customers are seeing tangible results from these investment activities. In particular, we invested more than $1 billion in our FERC-regulated transmission in Illinois electric and natural gas delivery infrastructure to better serve our customers. Ameren Transmission Company of Illinois, or ATXI began construction of the Illinois Rivers project and achieved all planned 2014 milestones. Plan rights were obtained for approximately half of the properties along the projects route. Construction was begun…

Thanks, Warner. Turning now to Page 11 of our presentation; as Warner noted, today, we reported earnings of $2.40 per share for 2014compared to $2.10 per share for 2013. Key drivers of this increase are listed on this page. Factors favorably affecting the earnings comparison included increased Illinois electric delivery and FERC-regulated transmission earning totaling a $0.11 per share. And I will note that this amount is net of a reserve for a potential reduction in the allowed return on equity for our FERC-regulated transmission businesses. The reserves stems from the pending compliant cases at FERC which have the potential to reduce the current 12.38% base allowed ROE for these services. A reserve calculation assumed the FERC we use the methodology similar to that used in this 2014 order for ISO New England. Further this reserve reflected an ROE reduction retroactive to November 2013 when the initial compliant case was filed. Other factors positively affecting the comparison of 2014 earnings to prior year results included increased rates for Illinois natural gas delivery service effective January 2014 as well as decreased interest charges. A latter reflected the May 2014 maturity of high coupon parent company notes which was funded with lower cost short term debt. Interest charges also declined as a result of a December 2014 Illinois regulatory decision allowing recovery of the majority of the debt redemption cost initially disallowed in charge to earnings in 2013. I addition the absence of the 2013 charge related to Missouri FAC treatment of certain prior period wholesale sales had a positive impact on the earnings comparison. Finally, temperatures had a estimated $0.01 per share positive effect on earnings compared to 2013 of a colder winter in early 2014 was largely offset by a milder summer. Factors having negative effects on the earnings comparison…

Thank you. [Operator Instructions] Our first question today comes from the line of Julien Dumoulin-Smith with UBS. Go ahead with your question, please.

Hi, good morning. Can you hear me?

Yes, Julien, this is Marty. You're a bit weak, please do speak up.

All right, indeed; excellent. So perhaps the first quick question on the CAGR, if you will, just why not roll forward and have a consistent rate-based EPS CAGR; anything in particular as you think about earnings in '19 or was this just kind of a fluke?

Well, I would not call that a fluke. Now look, we felt it would be good to continue to provide updates to the guidance that we provided last year. We put a stake in the ground that we expected to grow earnings in 7% to 10% from '13 to '18. And I think it's certainly important that we continue to let you know where we track against that. So as I said on the call, longer term we really believe that growth in this business is driven by a rate-based growth and longer term, certainly plan to provide in the rate-based growth outlook that we've provided. So we think that's a good basis going forward to continue to provide longer term outlook.

Okay, fair enough. Moving on to some of the details here, as you think about gas, and specifically the new rider, is there a kind of a full year contribution here in '15 or should we think about this somewhat lagged in the '16 as kind of the benefits fully accrue?

Again, you're talking about the gas business in Illinois, the rider we're using there?

Yes.

Really the benefit should be primarily realized this year as we utilize that rider. There is a very small lag associated with that rider. It's only a couple of months. So the benefits really realized beginning in 2015 and using that rider.

Great, and then a little nitpicky here; but why the reserve now on the ROE for the transmission side, what triggered that, I suppose, if I can ask?

Yes, what really triggered that is as we looked at we certainly study the orders that FERC has given, not only in ISO New England, but with other companies that come before them. There was a December order that FERC issued relative to another company, which we believe gave better clarification as to how the FERC is going to think about computing the ROEs for the various refund periods that exist with respect to these complaint filings. So using the ISO New England as well as the guidance provided at the FERC order, we felt that we could reasonably estimate a reserve to book, thought it was prudent to do so, prudent to get that reserve booked and behind us, and so therefore we've done that. You didn't ask specifically about the amount, but I can tell you that the reserve that we recorded get you to an ROE about at the same place that the FERC landed in the ISO New England order.

Got you, excellent. Well, I'll get back in the queue. Thank you.

Our next question comes from the line of Stephen Byrd with Morgan Stanley. Go head with your question, please.

Good morning.

Good morning, Stephen.

I wanted to just talk about the resource plan and EPA regulation [ph]. Assuming that later this year we do receive a plan that looks a lot like the draft plan that we received, could you talk a little bit about how you think and your constituents think about the timing for actually executing the plan? There's always litigation around big plans such as this from the EPA, but curious in the face of that, do you see a need and a desire to try to at least start to move forward with your plan, to move towards compliance? Or would there be a delay before moving forward, given the litigation? How do you think about that?

Stephen, this is Warner. Of course if the EPA issues a Clean Power Plan, which is identical to what the rules are as they've even proposed today, of course, we will move forward to be in compliance with that plan recognizing as you rightly pointed out there will be litigation we believe surrounding this plan for several years, which is as you probably know one of the issues that not just we, but many in the industry have raised. But we will do our best to drop rate under that, but as we've raised that to others, we have concerns with not just the economic impacts, but I think what you're starting to see in these hearings at the Federal Energy Regulatory Commission are conducting, there are real concerns about reliability risks, significant concerns. So we're hopeful that the EPA is listening very carefully to the concerns that we're raising, those concerns that are being raised in the industry, but also by those that are experts in the industry to ensure the reliability, and frankly those outside of the industry. So we're hopeful that the EPA and listening to that will make modifications that will make it acceptable if that will ultimately withstand the legal challenges.

Great, that's helpful; and just switching over to transmission, just curious as you think about integrating other utilities in. I'm thinking about Entergy, but more broadly, additional transmission planning. It looks like you're prosecuting well on existing projects, but maybe just at a high level, if you could speak to potential for additional transmission spend?

As we planned out during the call, this is Warner again; no, we think that the opportunities are really twofold. Number one, well we've talked a lot about the FERC 1000 projects, we sit there, sit among the seams [ph] of SPP, we have opportunities within MISO especially with the addition of Entergy and of course within the seams of PJM. And because of all of those, we believe that there continue to be robust opportunities for us to make proposals and combine that with our operating experience and our knowledge of the system, we believe we have a very good opportunity to enhance our transmission spend and investment because of those. I wouldn't stop there. We've taken a hard look [technical difficulty] and we continue to do so in terms of just local reliability projects to continue to improve the system for our customers here within both Missouri and Illinois, as well as in opportunities that would enhance just within MISO. So, Stephen, I see that with -- putting those things combined, we see meaningful investment opportunities in the transmission business, and especially, that's fruitful when you have a framework which is supportive of investment in transmission.

Great. Thank you so much.

Our next question comes from the line of Steve Fleishman with Wolfe Research. Go ahead with your question, please.

Yes. Hi, good morning guys.

Hi, Steve.

I had a couple specific questions related to your ROE and interest rate assumptions. So first on the Illinois business, it looks like in '15 you're using a 3%, 30-year. So if you assumed it stayed flat through 2018, I assume your core base is off like the four curves for the 30-year or something? Is that how you…

Yes. When we do our planning, certainly we look to blue chip estimates of economists that are out there in terms of where they see the interest rates going, which is where we get the 3% honestly is looking at consensus forecast for interest rates for 2015, and then they obviously project out beyond them.

But if you stayed at 3% over your five-year growth period, you'd still be within your range but at the lower end maybe or lower half? Is that what you're saying?

Yes. Fair question, Steve. The answer to that is yes. I mean if you took the ROEs that are embedded in our guidance this year for 2015, and you held those constant out through 2018, we project that we would be within that 7% to 10% range as you mentioned, albeit at the lower end of the range perhaps, but clearly within the range.

Okay. And then a little more explicitly on the FERC transmission ROE aspect and the reserve you're taking and assumption. So you mentioned you're using the FERC New England methodology, and it happens to come up with roughly a similar actual number range. Is that what clarifies -- is that what you said?

Yes, Steve, that's right. I think that obviously we've got an ongoing case. We don't think that we want to get into the details of the computation, and we will let our testimony in that case speak for itself over time, but I didn't want to give some sense for the accounting reserve that we booked, and I would tell you that the reserve we booked reflects in ROE similar to the outcome of that ISO New England case.

Okay, and then how about in terms of the incentive aspects? So you're adding the 50 BPs adder, but you're also including the similar incentive cap that was in that case?

I would say that, Steve, so for the historical [technical difficulty] 2014 back to late 2013, we didn't reflect any kind of an adder, any kind of 50 basis point adder. Going forward, however, in '15, what has been embedded in our guidance is I would say take that -- approximately take that ISO New England outcome, add 50 basis point adder, and that's about what we get reflected in our guidance for 2015.

Okay, and just to sum up on all of this, if you, on the FERC transmission business and ROEs, as you go through the period, if you're assuming higher interest rates, as you are in Illinois, do you assume you go back into FERC and seek higher ROEs? Or do you assume it stays at this reduced level that you're reserving at?

Steve, over time we will have to assess that. We will have to see how these cases come out and then assess through time how we will go about updating FERC ROEs [technical difficulty]. So I don't want to get into exactly what we got embedded in our 7% to 10% growth in our own plan going forward for FERC. As I mentioned if you took the current ROEs, embed in our 2015 guidance and held them constant through 2018 without any change, you would stay within that 7% to 10%. You would have to believe, I guess what I would agree with you on is that over time if we see cost of capital rising, if we believe it's prudent to adjust the ROEs upward, we certainly take action and pursue that with the FERC.

Okay, great. Thank you, I appreciate, I just want to make sure I understood those aspects. So I appreciate going through all of it.

Yes, absolutely.

Our next question comes from the line of Paul Patterson with Glenrock Associates. Go ahead with your question, please.

Hi. I just want to touch basically on just to clarify exactly what was sort of settled on Monday in Missouri, and what was left out; you guys are asking for 180 million, you broke out the components of that pretty well. I'm just trying to get senses to what was settled and what wasn't settled in the case if you could just elaborate a little further on that on Monday, the non-unanimous settlement that you guys filed?

Sure. Paul, this is Michael Moehn. In terms of what was settled and it is public and so you can get the stipulation agreement. There were a lot of issues of payroll and incentive compensation, advertising board fees, and…

I guess what I was wondering is what's not settled, I guess, or what's -- if you followed what I'm saying, what's still contested that you guys has left open? Do you follow me?

Yes. So the large issues that are obviously return on equity, we have some tax issue, that are open today, obviously the trackers, the FAC, the office of public counsels proposing to renew that track or change the sharing percentage. Staff is proposing to remove the storm tracker. There are some meaningful depreciation issues that are still open today, and there are few amortization issues that are at risk as well.

So the bid on the ask between staff and you, do we have an updated number on that?

No, Paul, we don't have, really I can't say a good point estimate for where the staff is today. We did put sort of baking the ground in terms of our own [technical difficulty] which is obviously we know our own position, which is in the back you will see $190 million, $100 million of that's net energy costs, about $90 of its other costs. I can tell you that [technical difficulty] the original case that we filed to the case that we have today, our non-fuel ask is down about 45 million. That's probably 25 million to 30 million due to lower rate base primarily bonus depreciation. The other 15 million to 20 million due to updates of pension, post-retirement, medical, and active medical, so lot of those costs will actually go through rider and trackers, but it gives you a little bit of a sense for how our position move from the original position to where we are today. Michael provided you some of the color on some of positions that the other parties have taken. We've provided an overview or summary of that in our materials as well in the appendix. [Technical difficulty] as I sit here today an exact bid ask spread.

Okay, and then you mentioned the seams opportunity that you guys have, which makes a lot of sense. But as you know, there's also a proceeding or a couple -- well I guess a generalized, generic proceeding with respect to MISO PJM on capacity transfer and day ahead and a whole variety of other things. And although it's been moving slowly, in some respects, it's moving. It appears to be at least. And FERC has recently put out an order and stuff on it, and I'm just wondering do you think -- do you have any perspective on that? And could that impact your transmission opportunities, depending on how that unfolds? Or are those transmission opportunities there, pretty much regardless of what happens with this generic PJM MISO seams proceeding…

Yes, Paul. I'm sorry, I didn't mean to interrupt you Paul, anything else?

No, no. That's what I want to talk.

I appreciate that. Maureen Borkowski, who is the President of our Transmission Organization [ph], she will probably touch on some more of the details around those current proceedings, so Maureen?

Yes, this is Maureen. Hi, Paul. I think you are correct that certainly the thing that go on in that capacity and the resource adequacy marketplace do affect the opportunities and the transmission business. Obviously we've been continuing to be active participants in PJM solicitations for internal projects, but also if you continue to look at any kinds of cross-border transmissions projects between MISO and PJM, that would improve power transfers, both energy and capacity. So I think you are right on that there are definitely opportunities there.

Okay, and then just on the Missouri legislation, where do we stand on that and how does it look vis-a-vis last year's efforts?

Yes. Again, Paul, this is Michael Moehn. As Warner said, I mean it is similar legislation. The Senate Bill 310 and House Bill 925 are very similar to last year. I think we are early in the session, so it's difficult to speculate sort of the outcome. We are spending a lot of time with various stakeholders, again, explaining, there are lot of freshmen legislators there, explaining the importance of this legislation, the need to modernize the regulatory framework to get working on the aging infrastructure issue. And we are certainly mindful that all of the utilities in Missouri are in for rate cases, and so this is a factor that we have to be aware of, but as we said in the past we're going to continue to pursue this, and be relentless about trying to get it across the finish line, but I think it's probably a bit premature to speculate the outcome.

Okay, anything specifically different than last couple of years, basically that we should be thinking about?

I'm sorry.

Anything specifically different than couple of years, I mean you guys made these efforts before; is there anything in the environment that you might want to point to as being perhaps more constructive for you to get this?

I think the environment is really about the same at this point. I think there is probably better understanding of the issue today as we continue to spend more and more with folks about how seriously the structure issue is and trying to address it. But beyond that, the environment is very similar.

Okay.

I'll add one other thing, Paul, which I think is helpful is we are certainly in the conversations that we had in Missouri. We point to the success that we continue to have with constructive legislation in Illinois, not how it's only improving the liability, not only how Richard and the Illinois team continue to hit their metrics, but also how they are creating jobs. So all of things are right across the river, and those are important conversations that we continue to point out, because we see that as really the opportunity [technical difficulty] to do something in the future. So we got a [technical difficulty] we think that is another important aspect of our conversation today.

Excellent. Thanks a lot, guys.

Sure.

Our next question comes from the line of Brian Russo with Ladenburg Thalmann. Go ahead with your question, please.

Hi, good morning.

Good morning.

You mentioned the 3%, 30-year Treasury rate assumption in the 2015 guidance. Could you just remind us, I assume that's at the midpoint of your guidance, but if interest rates were to change, say 25 basis points relative to that 3% assumption, what's the EPS impact?

Fair again, 25 basis points, probably a penny and penny and half. We actually did provide a sensitivity, when you take a look at Slide 13, some kind of small print, I recognize, but in the Illinois -- Ameren Illinois electric delivery section, we note that a 50 basis point move in EPS, [technical difficulty] about 2.5 cents, so obviously 25 [technical difficulty] half of that.

Okay, got it.

Pretty small in the grand scheme of the earnings guidance for this year.

Right, and if we were to use 2014 actual EPS or weather-normalized EPS as a base, would your EPS CAGR be more of like 6% to 9.5% versus 7% to 10% off the 2013 base?

Oh, you are talking about -- what year do you want to measure for '14 looking out to '18.

Correct.

Yes. So, last year somebody had asked, "Hey, what's the growth rate off of '14?" And we replied 6 to 9.50. At that time, when you look at our '14 guidance with midpoint was 235. The weather normalized results for 2014, they're $2.37. So that's 69.5 numbers and it still holds. Basically 69.5 of a '14 out through '18 is a CAGR, is equivalent to the 7 to 10 off of '13.

Okay, great, and it seems like you mentioned the $300 million less rate base in the Missouri operations. But it looks like your CapEx in 2015 is higher, is like -- and you reiterated the 6% rate-base CAGRs. When we look to 2018 and 2019, do you still fall in the same spot you previously were?

You raised a good point. When you look at CapEx for this past year, we really came in right where [technical difficulty] at we would. We forecasted to be it about 1.850 billion finish the year, nearly 1.8 billion. So it's pretty much on top of where we'd expect it. We're expecting a little bit of an uptick in 2015 in terms of capital expenditure up about another 175 million as we reported on the call to about 1.960 billion. And that level is little bit of an uptick mainly due to [technical difficulty] timing of our projects. But if also you take a look at the slide 16 that we provided where we lay out our expected capital expenditure over the five year period, we're projecting $8.9 billion of regulated infrastructure investment over this period and that's actually up over the prior year five-year period. So we back in last year we'd said '14 through '18 was going to be about 8.3 billion. Now we've moved up to 8.9. We have added about $600 million of the overall capital expenditure the five-year to this five-year plan as compared to the old one. So we have added expenditures, we've added expenditures that we translated to rate based growth in amount of is roughly doubled what we see as the negative impact of bonus depreciations. We're more than [technical difficulty] with identified additional projects to invest in for the benefit of our customers. On Slide 9 that's where we actually show then our expected rate base growth and basically [Technical difficulty] rate base 6% from '14 to '19. That's a very similar rate to what we had before for 2013 to 2018. But you can see because of that added capital expenditures over the five-year period that the ending rate base of projected rate base 15.5 [technical difficulty] about 9% more than what we had last year [technical difficulty] at the end of '18. And one should not assume either that the CapEx that we added has backend loaded. It's really been added throughout the period of an ultimately [technical difficulty]rate base number at the end of '19 was just about 9% higher than what we had then projecting for '18.

Okay, great that's very helpful. And then just lastly, you mentioned reg lag in Missouri impacted 2014 results in that jurisdiction. Is it possible to quantify what your earned ROE was in Missouri in '14?

When you get the 10K, I think you can calculate it may be able to calculate of stats page. We earned pretty close of slightly below the allowed ROE in Missouri. What we're really talking about lag and the call though was more about '15. We put a number of projects and service at the end of 2014, those begin to be depreciated and we no longer capitalize in return on those. So [technical difficulty] early '15 we do experience a lag until we can get the rates reset to our reflect recovery of those costs and rates that reflects an appropriate return on those investments. That's the lag I think we're really [technical difficulty].

Is it possible to quantify that lag in terms of basis points of the allowed?

No, I don't have that foray. It's basically we will have that lag for the first five or so months of the year but don't have an exact quantification of that.

Okay, thank you very much.

For 2014, we do file these surveillance reports with the Missouri Public Service Commission and we earned 9.71 in 2014 in Missouri.

Good, thank you.

Our next question comes from the line of Michael Lapides with Goldman Sachs. Go ahead with your question, please.

Hey guys, congrats on a good 2014 and thank you for taking my questions. One small one; what do you assume in guidance for costs at the holding Company or parent level?

Yes, sure. Good. Michael, good morning by the way; this is Marty. Good question. So last year we had guided that I guess in 2013, we'd had about $0.18 or so of parent other cost. We had projected to drive those down in '14, which we were successful of doing. We said to $0.10 below which is where we ended up including I'd say the effects of dilution. We probably had about $0.09 of drag and we expect that we will be able to reduce that further in 2015. Of course you know that we get the full year benefit of that maturity at their parent company where we had the high cost stat. so we do expect another $0.04 or so of interest savings. So expect to drive that number down to maybe about $0.05 depending upon taxes and things like that, maybe even a hair lower. But we're expecting $0.05 or little bit under in terms of parent company drag in 2015.

Got it, and when thinking longer term in Illinois, do you think there is a -- whether it's legislative or whether it's done via the regulatory process, there is a transformative-like investment opportunity on the gas delivery side, like what's happened on the electric delivery side for both you and Commonwealth Edison in Illinois in terms of the legislation that was passed a few years ago and what it did to both capital spending, rate-based growth, investment in the system, employment, et cetera.

I don't know, Michael whether there's anything more transformative. I think when you look at the gas business in Illinois, we've already ramped up some investment there because we do see that as constructive environment as it exist today. As you know we have the ability to use forward looking tax years for our gas rates and the rate case that we have pending today as we mentioned on the call looks out to 2016 uses 2016 projects cost and rate base we think that's constructive. And then we began to be able to use basically a rider for qualifying infrastructure projects so that we can actually adjust rates monthly between rate cases to reflect the return of and return on those qualifying projects. We believe there's been enhancement made to the framework which is actually allowing us to step up investments and we're replacing meter modules and gas business alongside the meter replacement program that we've got going on the electric portion of the business and it's allowing us also to make some necessary investments in that business to ensure safety as well as reliability of the gas business. I think more of [technical difficulty] that may reflect or spare investment over time, we think the infrastructure --we think again that framework is good, but it will be whether we see some additional safety rules that come out at the national level or apply at may drive actually investments spending. And but we do believe that we have the framework in place that if we're required to make those investments that will be treated absolutely fairly in terms of the regulatory process.

Got it. Thank you, Marty. One last one and little bit of a housekeeping item here; can you break up -- the slide's confusing a little bit, what the ATXI transmission rate base is at the end of 2014 or the average rate base versus the Ameren Illinois transmission rate base? And then that same question, but on the CapEx side for 2015.

Yes, Doug is going to see if he can pull that out. If he can pull that out -- I don't have that in front of me. If he can pull it out readily, Michael that's certainly something that we can follow up and provide to you. I will tell you that just in terms of the earnings for 2015 I think we're looking at may be about $0.05 or so earnings [technical difficulty] from ATXI in 2015. That sort of embedded in our guidance and that…

Michael, I don't have it at my fingertips but we did give you some websites at the back of the presentation that show our attachment old filings for the total is about 1.4 billion average rate base for '15, but the breakout; it is public in there [technical difficulty] don't have that rate in front of me.

No problem, I'm getting a little granular, and sorry to be a pain. I'll follow up, I'll take this one offline guys.

Thank you, Michael. Thanks for your questions.

Thank you, guys.

Our next question comes from the line of Andy Levi with Avon Capital Advisors. Go ahead with your question, please.

Hi how you doing? Actually, I think I'm all set, but thank you. Everything looks good.

Thanks, Andy.

If you give me -- this is Doug, if you give me just a second here; I think I may have found that information here, Andrew is going to help me here for a second. Yes, thanks. It's about half a billion for ATXI, and about 900 million for Ameren Illinois is the number here I'm getting.

Thank you, Mr. Fischer. I would like to turn the call back over to you for closing comments.

Doug, closing comments, please.

Yes. Thank you for participating in this call. Let me remind you again that a replay of the call will be available for one year on our Web site. If you have questions, you may call the contacts listed on today's release. Financial analyst inquiries should be directed to me, Doug Fischer. Media should call Joe Muehlenkamp. Our contact numbers are on today's news release. Again, thank you for your interest in Ameren, and have a great day.