阿莫林 (AEE) 2013 Q1 法說會逐字稿

Greetings and welcome to the Ameren Corporation's first quarter 2013 earnings call. At this time all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentations.

(Operator Instructions)

As a reminder, this conference is being recorded. Its now my pleasure to introduce you host, Doug Fischer, Senior Director of IR for Ameren Corporation. Thank you, Mr. Fischer. You may begin.

Thank you, and good morning.

I am 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 one 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 investor's 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 statement section in the news release we issued today and the forward-looking statements and risk factors sections 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 volumes and new rates for Ameren Missouri Electric and Ameren Illinois Transmission Service, both effective in January of 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, non-fuel operations and maintenance expenses were higher at Ameren Missouri. Marty will provide more details on our end in a few minutes.

Moving to page 4, today we also established 2013 earnings guidance for continuing operations in the range of $2.00 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 expected to reduce these Parent Company and other costs to $0.10 to $0.15 per share in 2014, and to reduce them even further in 2015. This is expected to be achieved by refinancing the $425 million of Parent Company senior notes due in May 2014, and rationalizing operating costs that were previously allocated to the Merchant Generation business.

Turning to page 5. Our most significant first quarter development was the March agreement to divest the Merchant Generation business to an affiliate of Dynegy. We believe this transaction clarifies our strategic direction and value proposition to investors. It allows Ameren to focus exclusively on its rate-regulated Electric, Natural Gas, and Transmission businesses. The divestiture reduces Ameren Corporation's business risk, and is expected to substantially improve the predictability of future earnings in cash flows. These factors support our ongoing efforts to grow our earnings base and provide a solid, sustainable dividend.

The transaction removes $825 million of Genco senior notes from Ameren's consolidated balance sheet. Also, it will result in an estimated $180 million at present value of deferred tax assets, which are expected to be substantially realized in 2015. These tax benefits more than offset the cash requirements associated with the transaction. As a result, the rating agencies have stated that the merchant generation divestiture is credit positive for Ameren. In fact, Standard & Poor's upgraded Ameren Corporation's rating to BBB, shortly after the announcement of the transaction.

We are working diligently with Dynegy to complete this transaction. In April we filed the request for the approval of the vestiture with the Federal Energy Regulatory Commission. And today we plan to file with the Illinois Pollution Control Board for the required transfer to Dynegy of the variance related to the Illinois multi-pollutant standard that we were granted in 2012. We continue to anticipate closing the transaction in the fourth quarter of this year. In addition, we have hired an investment bank to assist us in the sale of the three gas-fired energy centers that we retained with the exercise of the Genco Put Option, and we have begun marketing these assets. We expect to complete the sale of these plants to a third party by year-end, subject to separate approval by the FERC.

Moving to page 6. In addition to posting solid first quarter earnings from continuing operations and advance of the pending divestiture of our Merchant Generation Business, we are also making progress on our plans to invest substantial additional capital in FERC-regulated electric transmission projects. These projects will benefit customers through a more reliable and efficient electric system.

Constructive, forward-looking, formula ratemaking that is in place for these projects provides a reasonable opportunity for us to earn fair returns on our investments and recover our costs on a timely manner. We plan to invest a total of approximately $2.2 billion in these FERC-regulated transmission projects over the five-year period ending in 2017.

Our single largest planned transmission investment is the Illinois Rivers Project. This approximate $1.1 billion MISO-approved regional multi-value project involves the construction of a new high-voltage transmission line across the state of Illinois. It will enhance electric system reliability and create new construction jobs in the state.

Our request for a Certificate of Public Convenience and Necessity for the approximate 400-mile transmission line is pending at the ICC. In late March, the ICC staff filed initial testimony in response to this request, and we are pleased that the ICC staff recommended a Certificate be granted for the project, subject to certain further considerations. We filed testimony last Friday to address the remaining concerns of the ICC staff. Hearings are scheduled for May 13 through May 17 with an ICC decision expected by August 20 of this year. Upon receipt of the certificate from the ICC, we will begin to acquire rights-of-way for the transmission line, with a full range of construction activities expected to begin in 2014.

Turning now to page 7, we also continue to pursue enhancements to the state regulatory frameworks for our utilities in both Missouri and Illinois. We are focused on improving our ability to invest in our utilities and states for the benefit of customers, communities, and investors.

Turning first to Missouri. We, along with every other investor-owned electric utility in the state, strongly support the Infrastructure, Strengthening, and Regulatory Streamlining Act, commonly referred to as Electric ISRS, which is currently pending in the Missouri General Assembly. It is largely fashioned after the Infrastructure Recovery Statute that has been utilized by the water and gas utilities in the state for nearly a decade.

This proposed legislation is intended to modernize the Missouri electric regulatory framework by providing for more timely recovery investments in place and serving customers between rate cases. Further, it will also make important incremental investments in our aging infrastructure to meet our customers' future energy needs and expectations, as well as create well-paying jobs. If enacted, this legislation would streamline regulation, as well as enhance many of the consumer protections in the current water and gas infrastructure laws, which already include very strong oversight by the Missouri Public Service Commission.

Late last evening, the Missouri senate debated the Electric ISRS legislation. A final vote was not taken on the bill. We will continue to work with legislative leaders and other key stakeholders to see if we can move this legislation forward. Having said that, consumer advocates and certain industrial customers are opposing this effort to modernize Missouri utility regulation.

However, we consider such opposition to be rooted in a very short-sighted approach to state energy policy, and we continue to aggressively communicate why enacting this legislation would be good for our customers and the state of Missouri. The time for Senate and House action is limited, since the Missouri legislative session ends on May 17. We will continue to work tirelessly to pursue this important legislation for the state of Missouri.

Turning to page 8 and Illinois. In 2011, the Illinois General Assembly enacted the Illinois Energy Infrastructure Modernization Act. This act was intended to spur a decade of investment in electric delivery reliability, improved customer service, and job creation. Last year, Ameren Illinois began selecting infrastructure projects and opened a smart grid training facility in Belleville, Illinois. The ICC also approved our Advanced Metering Infrastructure Initiative. We continue to maintain that formula ratemaking can be constructive if properly applied.

However, in our view, the ICC misapplied the Act in our 2012 electric delivery formula rate orders. Therefore, we strongly support Senate Bill 9 -- a legislative solution that clarifies application of the Act regarding rates, while maintaining strong consumer protections. Senate Bill 9 makes clear that year-end, not average rate base, and weighted average cost of capital, not a short-term interest rate, should be used in electric delivery formula ratemaking. And we are pleased that the Illinois General Assembly has overwhelmingly confirmed their legislative intent and approved this legislation. The bill is now on Governor Quinn's desk, and he must act on it by May the 20.

As part of a two-pronged approach to ensure that the goals of the Energy Infrastructure Modernization Act are realized, Ameren Illinois has also appealed the 2012 electric rate orders to a state appellate court. In addition, we support Illinois legislative efforts to enhance the ratemaking framework for gas delivery services. This too would allow us to accelerate infrastructure investment, deliver improved customer service, and create jobs.

Turning to page 9. I would like to close my prepared remarks with a summary of our planned investment in our rate-regulated utilities for the benefit of our customers, communities, and investors. This is reflected in our regulated capital investment plans which translate into expected rate-based growth of approximately 7% annually in 2013 through 2017. With this growth, most rapid in regulatory jurisdictions with constructive formula ratemaking, we are moving forward on a path that will enhance our ability to earn fair returns on a growing level of utility investment.

I will now turn the call over to Marty.

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 -- an estimated $0.07 in Missouri and $0.03 in Illinois. In addition, new rates for Missouri Electric and Illinois Transmission Service increased earnings by $0.05 per share. And the absence in 2013 of a required non-recoverable 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 partially offset by reduced first quarter 2013 weather-normalized Illinois electric delivery revenues, which lowered earnings by $0.08 per share, compared to the first quarter of 2012. Reduced revenues are the result of variation in the timing and amount of expected full-year recoverable costs between this year's first quarter and the year-ago period.

We expect this variation to result in lower weather-normalized earnings in the second quarter of 2013, and higher earnings in the third and fourth quarter of 2013 compared to the same periods in 2012. For the full year 2013, we expect weather-normalized Illinois electric delivery earnings to increase compared to 2012, primarily reflecting increased investment for the benefit of our customers.

Finally, higher operations and maintenance expenses at Ameren Missouri reduced first quarter 2013 earnings by $0.03 per share net of certain rate recoveries, compared to the first quarter of 2012. These higher expenses were primarily due to startup expenses related to the second quarter 2013 Callaway Nuclear Energy Center Refueling and Maintenance outage, and higher storm-related costs.

Turning now to page 12. I want to remind everyone that second quarter 2013 comparative results will be impacted by a few significant items. The first of these will be the second quarter 2013 expenses for the just mentioned Callaway Nuclear Energy Center Refueling and Maintenance outage, which began in April. These expenses are estimated to be approximately $0.10 per share. There was no Callaway refueling outage in 2012.

The second item is a favorable 2012 FERC order related to a disputed Missouri power purchase agreement that expired in 2009. That order resulted in a non-recurring gain of $0.07 per share in the second quarter of last year. Finally, as previously discussed, variation in the timing of revenue recognition for Ameren Illinois' electric delivery service is expected to result in a decline in weather-normalized earnings in the second quarter of 2013 compared to second quarter of 2012, though again, the full-year comparison is expected to be positive.

One other item is worth mentioning. We expect the Missouri Court of Appeals to issue a decision this year, possibly in the second quarter, in its review of the Missouri Public Service Commission Fuel Adjustment Clause Order issued for Ameren Missouri in 2011. This court decision may impact comparative second quarter 2013 financial results. However, we believe potential financial impacts are accommodated by our earnings guidance range.

Turning, then, to page 13. We move from earnings to a discussion of our updated 2013 free cash flow guidance. We calculate free cash flow by starting with our net cash provided by operating activities and subtracting from it our capital expenditures, other cash flows from investing activities, dividends, and advances received for construction. For 2013, we now anticipate negative free cash flow of approximately $500 million, compared to our February 2013 guidance of a negative $435 million.

The updated estimate also includes merchant divestiture-related cash outflows of approximately $100 million, including the $25 million of cash that is currently held at Genco. These divestiture-related cash outflows are more than offset by expected transaction-related cash tax benefits of approximately $180 million in present value, to be substantially realized in 2015.

Finally, on page 14 of our presentation, I will conclude my prepared remarks by summarizing key year-to-date accomplishments. In our view, first quarter financial results from continuing operations were solid, with utility results in line with our expectations. Operating performance and service to customers has remained strong.

We announced the divestiture of the Merchant Generation business to Dynegy, and have begun taking the regulatory steps needed to close this transaction in the fourth quarter of this year. The divestiture will allow us to focus exclusively on our rate-regulated utilities, and is expected to improve the predictability of our future earnings and cash flows.

Our rate-regulated utility investment plans provide the foundation for growing our rate base at a compound annual rate of approximately 7% over the five-year period ending in 2017, and Ameren's $1.60 per share annualized dividend rate is well covered by expected 2013 earnings from continuing operations, and provides investors with a very attractive current yield of approximately 4.5%.

That concludes my prepared remarks. We now invite your questions.

Thank you. We will now be conducting a question-and-answer session.

(Operator Instructions)

One moment, please, while we poll for questions. Our first question comes from Paul Patterson with Glenrock Associates. Please proceed with your question.

Hello, guys.

Hello, Paul.

The Missouri legislation -- given that we got the May 17 deadline showing up here, and for 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-based growth that you guys have, how should we think about your ability to manage regulatory lag, in its absence?

Sure. Paul, this is Marty.

I think I'll let Warner Baxter, who is here with us -- President of Missouri Operations -- go ahead and answer that question.

Yes. Good morning, Paul. How are you doing?

Good morning.

So a couple things.

First, your first question related to the prospects for the passage of legislation. And you're right. It certainly -- as we sit here today, it's difficult to predict really whether that legislation will be passed at this time.

And as we've talked about in the past, and it's always a challenge to try to pass legislation. And certainly with only two weeks left in the legislative session, 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 need to be making in the future, and to address regulatory lag in Missouri.

Now, 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 have before the legislature today certainly has robust consumer protections. And so we are 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 are going to continue to do what we've done in the past; in that we are 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 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 are 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, there is a lot of opposition. And, in the absence of a change in regulatory policy, should we be thinking about an ROE lag as we go forward, if there is no improvement? Or -- I am sure you guys are working hard, or whatever -- but just in general -- how -- if you could just -- I don't know if you can address that or not. But how should we think about that? And then also related, SB9 sailed through the legislature in Illinois very well. But the gas stuff -- the gas legislation seems to be held up. And I was just wondering if you could compare and contrast that?

You know, Paul, it's me, Marty. I'll maybe try to tack on to what Warner said.

I think as you look at what we have 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 are deploying significant amounts of capital.

When you look overall, at our plan going forward, and you look at our 7% rate-based growth plans across the enterprise, 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 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 know, you're right. The changes or the modifications to the formulaic rates for electric did pass both chambers with very strong majority 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 use of [four] forward-test years. We have got a gas rate case pending right now and -- incorporates those forward-test years. And, you know, that's where things stand in Illinois.

Great. Thanks a lot.

Our next question comes from Michael Lapides with Goldman Sachs. Please proceed with your question.

Yes. 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 those concerns?

Well, Michael, this is Warner again.

The bill was debated last evening, as Tom said, and they ultimately did not come to a vote. Certainly, there have 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 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 two weeks.

Got it. And turning to Illinois -- assuming that SB9 is eventually made into law, and assuming the litigation around the prior rate case turns in your favor and upholds the law passed in 2011 -- is there still any remaining structural lag that exists for your Illinois REC distribution businesses? Meaning, are there still some level of costs that simply aren't recoverable in rates? And, if so, could you quantify that level? Lots of state commissions don't allow things like incentive compensation or regional or local marketing cost, donations -- that type of thing. Just trying to think about 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.

You know, there are some of those costs. And if you look back to our slides from our year-end call, we did outline some those 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 non-recoverable costs. I think it was on slide 13 of our year-end slide. Some of those non-recoverable 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 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.

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 have 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, 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 have risks associated with them. We believe that the ROEs that we've got are appropriate. And to the extent that the ROEs were reduced, it certainly would affect ours, and I think other companies' thought processes about the investment opportunity. Whether they were banned or not, I certainly won't speculate. I'm just saying that it certainly becomes less attractive, and there's less incentive there to take on these big projects.

Got it. Okay. Thanks, guys. Much appreciated.

Our next question comes from David Paz with Wolfe Research. Please proceed with your question.

Good morning.

Good morning.

Actually, a question on the utility guidance -- or, I guess, overall guidance. But it seems that the midpoint of your guidance, $2.00 to $2.20, reflects a utility midpoint of $2.30. Is that fair?

Yes. I think, yes, that is fair. When we provided the guidance, which is now guidance from continuing operations of $2.00 to $2.20, we also mentioned that we expected for the full year, you know, parent and other costs of about $0.20. And so that would, if you do the math, as you have done -- that would imply, for the regulated utilities, about $2.30.

Okay. And then just -- sorry, back to what's driving that nickel increase on the utility side?

Well, I think, overall, as we go through the year, we've certainly seen -- I will comment on a few things, since you've opened the door on guidance, which I appreciate. First on the -- I'll talk maybe about the parent and other of about $0.20 that we see there. What's driving that is that, as you go through 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 debt of about $425 million of parent company debt, 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 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 over 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, 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 little growth this year. We haven't really modified our expectations for the remainder of the year. We still expect a little growth for the remainder of the year, but the quarter was a positive from that perspective. You know, the sales versus normal -- I've been meaning weather versus normal, I should say, was a neutral. We didn't see much impact from weather versus normal conditions. But we did see on a weather-normalized basis is 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 expecting to see some positives from further infrastructure investment, rate-based growth -- in those areas where we have the formulaic ratemaking. So those are some of the drivers on the regulated side.

You know, I would say that those -- we give the $2.00 to $2.20 guidance. It's a $0.20 range. That parent company and other of $0.20 is an approximation. I would say, probably, there is a little bit of a rounding up there. And, you know, so, therefore, your derived $2.30, I would say there would be a little bit of a rounding up there too, in terms of the -- you know, the regulated midpoint.

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

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 of 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, you know, we are happy to see this trend. It's good to have this starting out the year. A little bit of a positive trend. But 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 dividends. 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 no 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 to also 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.

Okay, great. Thank you so much.

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

Good morning, guys.

Hey, Julien. How are you?

Not too bad, thank you. And yourselves?

Good.

Excellent. 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 re-fiing in '14 -- and I suppose mid-year 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?

Fair. Good question. So, you know, the $0.20, as I broke it down, was probably about -- the $0.20 -- $0.10 of interest and then $0.10 of G&A previously allocated to the merchant business as well as some, corporate overhead costs that we've had historically. So when you think about that parent company debt, as you know, $425 million of debt, 8.875% interest rate. You know, in today's market we'd be able to reduce that substantially. Cutting that better than 50%, Julien, maybe -- and maybe even by two-thirds. 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 re-fi 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'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.

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 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 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 a dime, easily?

Yes. Less than a dime 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 are 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 CAD -- just deploying capital, if you will? And maybe a secondary question off that -- also looking at CapEx, how would EMIA 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?

The base part was more ATX. How do you feel about deployment? What are the next key milestones in terms of it? Seems like there have been some developments in the quarter.

Yes. No, there would. In terms of outlining those, there have been good developments. So certain -- we 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. So the upcoming dates there are ICC hearings in the May time frame. And we're still expecting an order, and we're optimistic that we'll get the ICC certificate and be able move forward then late this year with right-of-way acquisition, and next year, with that full range of 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 those are some of the key milestones. Certainly, the expectation of being able to move forward with that project on 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 EMIA. Just, I am curious. Like -- how much CapEx upside are we talking there?

Well, there what we did, if you look at our CapEx plans, we didn't substantially change those as a result of the ICC order last year. We eliminated about $30 million of planned capital spending for this year, but didn't really substantially change the plans that we had 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 would be in a position to add back that $30 million of reduced capital spending to our forecast.

Great. Thanks for the time, guys.

All right, Julien.

Our next caller is from -- Ashar Khan with Visium. Please proceed with your question.

I think most of my questions have been answered. One, just going back to the legislation, we know the end date of the thing. But what it's 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, 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 HB398, 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. So a likely path to move forward now -- between now and May 17 -- would be to amend an approved Senate or House bill. 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 two weeks, utilizing those vehicles? The answer is yes. But as we said before, we have two weeks. And there -- still takes time to get through some of the processes, but it isn't as extensive as the original bill process would have to be.

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

Ashar, the only thing I have seen in Missouri politics and the legislature -- it's 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 two weeks. So I can't say there is a specific cut-off date one way or the other. But there are a host of -- there are vehicles. But just because they are vehicles doesn't mean that there still aren't some challenges to go through both sides of -- either the House or the Senate.

Okay. I appreciate the time. Thank you, Sir.

Sure. No worries.

Our next question comes from Neil Kalton with Wells Fargo. Please proceed with your question.

Good morning, everyone.

Morning, Neil.

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

Sure, Neil. This is Marty again.

And one thing I would refer you to, overall, that I thought was a good piece of testimony is -- the President of our transmission company, Maureen Borkowski, in the testimony that we filed recently in response to the ICC -- to intervenors in the case. But Maureen's testimony I think provided an overview of the issues that had been raised or concerns that had 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 intervenors 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 path 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 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 the project was certainly needed. The question was about the path and the need for certain elements. But, again, we felt 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. 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 -- would those projects that have been approved by MISO -- should we expect those from an in-service date as being outside the five-year period -- get the Illinois Rivers through and done, and then go in and go for the other projects as well, over time? And then as you come in and go for the other projects as well over time?

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

Okay. Thank you very much.

Thank you.

Our next question comes from Mitchell Moss with Lord Abbett. Please proceed with your question.

Just a quick question on the Genco business. There has been some talk on the other -- from some of the other conference calls today that there has been some basis issues. Can you talk about whether or not you have seen any basis issues for some of your plans?

Yes, sure. Over time I do think that, 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, anyway, 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 have seen those basis differentials certainly fluctuate over time.

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

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

Okay. Do you see it as general transmission constraints? Are there 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 the demands on the system. So, all of those things you mentioned certainly are contributors from time to time.

Thank you.

Our next question comes from Andy Levi with Avon Capital. Please proceed with your question.

Good morning.

Morning.

Most of the questions were asked. But just to do some math here -- I don't know if you will be willing to walk through it with me, but -- starting in that $2.20 to $2.40 range at utility earnings that you talked about?

Okay.

For this year, right? I mean, that's --

Yes. Well, what we did is we gave guidance of $2.00 to $2.20, and we said that the parent and other were approximately $0.20, which would imply approximately $2.30 for the utilities.

Right. Midpoint.

Yes. So, at midpoint. Right. So we didn't give out that specific range.

Okay. I follow you. Okay. I apologize. I said bear with me here. (Laughter)

But then you seem to have like rate-based 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 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. But I think if you model it out, you should see some sort of similar trend rate with respect to earnings. But certainly not commenting on specifically the 5%.

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

Thank you.

Our next question comes from Paul Ridzon with KeyBanc Capital. Please proceed with your question.

Good morning. Can you hear me?

Yes.

First of all, you indicated the Illinois timing issue should be a headwind in the second quarter. Can you 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. This 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 electric delivery service. So in Q2 we expect that to be maybe a $0.03 negative versus last year. And again, we -- (multiple speakers). Go ahead.

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. I'll try to describe for you the phenomenon that's causing this, though, which is that we're -- obviously, our revenues for the full year are ultimately determined by our actual cost incurred in that year. 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 and towards the end, we saw that the cost of 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 expectation. Therefore, in the third quarter we had a downward revision to the revenues that had been recognized over the first half of the year. And then a further adjustment in the fourth quarter. So that accounting model is still in place, and we're still saying this first quarter, recognizing revenue is based on our full-year expected cost of service for that business.

So, you know, 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 we were working through this new process. So I think, probably, bigger fluctuations this year versus last; then we should see moving forward. 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 year you are 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 will recall that we have actually recognized a charge in a prior year of about $18 million or $0.04. So that could reverse. On the other hand, if that goes against us, that 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 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 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.

Okay. Thank you.

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

Thank you for participating in this call. Let me remind you again that this call is available for one 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.