Ameren Corporation (AEE) Q3 2013 Earnings Report, Transcript and Summary

Greetings, and welcome to the Ameren Corporation's Third 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 Investor Relations for Ameren Corporation. Thank you. Mr. Fischer, you may begin.

Thank you, and good morning. I'm Doug Fisher, 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 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, 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. Tom will begin this call with an overview of third quarter 2013 results and our updated 2013 earnings guidance, followed by a discussion of recent business developments. Marty will follow with a more detailed discussion of third quarter 2013 financial results, other financial matters and pending rate cases. We will then open the call for questions. Before Tom begins, I would like to mention that all per share amounts discussed during today's presentation are presented on a diluted share basis. 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 earnings from continuing operations for the third quarter of 2013 of $1.25 per share. This compares with $1.28 per share for the third quarter of 2012. The reduction in earnings from continuing operations was primarily the result of lower electric sales volumes, reflecting temperatures that were much cooler than those of the prior year period. The impact of milder weather was partially offset by a rate increase from Missouri Electric Service effective in January of this year, higher Illinois electric delivery earnings recognized under formula ratemaking and disciplined cost management. While Marty will provide details on our earnings in a few minutes, the bottom line is that we had a solid quarter from an operations and earnings perspective. Moving now to Page 4. Today, we also updated our earnings guidance. We now expect 2013 earnings from continuing operations to be in a range of $2 to $2.10 per share compared to the prior range of $2 to $2.15 per share. This update incorporates the negative impact of cooler-than-normal weather in the third quarter. Guidance continues to include approximately $0.20 per share of parent and other costs, including certain costs that were previously allocated to the merchant generation business. However, we expect to reduce these costs to $0.10 to $0.15 per share in 2014 and to reduce some further in 2015 as we refinance parent company debt and rationalize operating costs. Turning now to Page 5. I would like to briefly review our strategy for achieving financial success and appraise you of progress in a few key areas. This page outlines some of our key strategic objectives. Our first objective is to reduce our business risk by completing the divestiture of our merchant generation business. The resulting shift to a fully rate-regulated business is expected to substantially improve the predictability of future earnings and cash flows. In a few moments, I will update you on our divestiture efforts. A key second strategic objective is to invest in and operate our businesses in a manner consistent with existing regulatory frameworks. We do this because healthy financial performance is critical to our shareholders, just as it is to our ability to undertake the significant operating and capital spending needed to meet customers' energy needs and expectations. To meet this objective, we have been requesting and obtaining rate increases as needed, as well as aligning operating and capital spending consistent with regulatory outcomes and existing frameworks. As a result of these and other operational and cost containment initiatives, our electric rates have remained low, delivery service system reliability has been enhanced, energy center availability has remained strong and earning returns at our utilities have improved. To be positioned to invest so that we could meet our future energy needs and expectations, we have also been aggressively working to enhance regulatory frameworks, which is our third strategic objective listed here. Modern, constructive regulatory frameworks, such as those we have in place for our FERC-regulated transmissions and Illinois-regulated energy delivery businesses support investment in utility infrastructure, benefiting our utilities and the communities we serve. The final strategic objective I will mention is that of developing additional rate-regulated opportunities for investment and growing rate base. Over the last few years, we have identified in advance several new attractive opportunities, including our Modernization Action Plan, which is accelerating improvements to Ameren Illinois' electric and natural gas delivery systems and new FERC-regulated transmission projects designed to improve reliability and efficiency. We expect successful execution of our strategies to result in meeting our customers' future energy needs and expectations, earning fair returns on our investments and earnings and dividend growth, driven by projected rate base growth of approximately 7% annually through 2017. Moving to Page 6. I would like to update you on our progress toward achieving the first strategic objective I mentioned, exiting our merchant generation business. After many months of tremendous work by people across our organization and close coordination with Dynegy, this exit is nearing completion. We expect to close the divestiture of our Ameren Energy Resources merchant generation business to Dynegy affiliate, Illinois Power Holdings, by the end of this year. This transaction received approval from the FERC in October. The divestiture agreement requires that Illinois Power Holdings receive a variance to the Illinois multi-pollutant standard from the State Pollution Control Board with the same material conditions as the variance issued to our merchant generation business just last year. Certain Ameren subsidiaries in Illinois Power Holdings filed a variance request in July of this year. The Pollution Control Board is expected to issue its decision by the 21st of this month, and we continue to expect a positive outcome. In addition, our efforts to sell the 3 merchant gas-fired energy centers we retained with the exercise of the Genco put option are nearing a successful conclusion. In October, we announced an agreement to sell the 3 energy centers to an affiliate of Rockland Capital. The expected sale proceeds are more than sufficient to ensure that the sale does not negatively impact Ameren's earnings or cash flows. Genco has received $137.5 million for the assets and is expected to receive up to an additional $15 million of after-tax net proceeds from the sale 2 years following the close of this transaction. The sale of the 3 plants is expected to close by year end, subject to FERC approval. Turning now to Page 7 of our presentation and shifting to transmission. I would like to update you on the approximately $1.1 billion Illinois Rivers project. This MISO-approved multi-value project is nearly 400 miles long and it consists of a high-voltage transmission line running west to east across the State of Illinois. In August, the Illinois Commerce Commission or ICC approved the need for the Illinois Rivers project and granted key portions of the project a certificate of public convenience and necessity. The ICC indicated that it did not approve certain line segments and substations due to a lack of time and evidence to determine the most cost-effective segment routes and substation locations. We and certain other parties filed with the ICC requesting a rehearing. In October, the ICC granted a rehearing to determine the routing of 4 of the 9 mine segments, including 2 granted a certificate in the initial order, and the location of 6 of the 9 substations. We do not expect this rehearing process to delay the project or significantly change our investment plans. The ICC is expected to issue an order on rehearing by March of next year, and we expect a certificate to be granted for the remainder of the project. Meanwhile, we've begun to acquire rights of way for those portions of the project that are not subject to rehearing. The Illinois Rivers project and in fact, all of our Illinois transmission business operates under FERC, constructive, forward-looking or formula ratemaking framework. This ratemaking provides an opportunity for us to earn fair returns on our investments and recover our costs on a timely basis. I will now turn the call over to Marty.

Thanks, Tom. Turning to Page 8 of our presentation. Today, we reported third quarter 2013 net income, combining results from both continuing and discontinued operations of $1.24 per share compared to third quarter 2012 net income of $1.54 per share. As Tom previously mentioned, our third quarter 2013 earnings from continuing operations were $1.25 per share, compared to $1.28 per share for the prior year period. On Page 9, we outlined key drivers of the variance between earnings for the third quarter of this year compared to the third quarter of last year. The earnings comparison was negatively impacted by lower electric sales volumes due to temperatures that were much cooler than those of the prior year period. These cooler summer temperatures reduced 2013 third quarter earnings by an estimated $0.15 per share compared to the third quarter of 2012 and by an estimated $0.03 per share compared to normal temperatures. Last year, third quarter temperatures were very warm, with cooling degree days 21% higher than normal. This year, third quarter temperatures were milder, with cooling degree days 5% lower than normal. The quarter-over-quarter temperature-related earnings variance was offset by several positive factors, including increased rates from Missouri Electric Service effective in January of 2013. That rate adjustment favorably impacted third quarter 2013 earnings by $0.08 per share compared to the prior year period. Results were also favorably impacted by higher Illinois electric delivery earnings, benefiting earnings by $0.08 per share compared to the prior year period. These higher earnings reflect the timing differences among each year's quarters, increased rate base and higher allowed return on equity recognized under formula ratemaking, reflecting higher 30-year treasury bond yields. Several other factors resulted in a negative $0.04 per share net impact on the earnings comparison. Moving to Page 10. I would like to provide information to assist you in thinking about earnings for the balance of the year. As a starting point, fourth quarter 2012 earnings from continuing operations were $0.04 per share. On this page, we have listed select items that are expected to impact fourth quarter 2013 earnings compared to the prior year period. The first item I would like to mention is weather. Weather had little net impact on earnings in the fourth quarter of 2012 versus normal conditions. And of course, our earnings guidance assumes normal conditions for the fourth quarter of this year. Second, we estimate that Illinois electric delivery earnings recognized under formula ratemaking will increase fourth quarter 2013 earnings by approximately $0.03 per share compared to the prior year period. This increase is expected to result from timing differences among each year's quarters, increased rate base and a higher allowed return on equity, reflecting higher 30-year treasury yields. This is a good place to note that our full year 2013 earnings guidance now incorporates an average 30-year treasury bond yield of 3.44% and therefore, a formula allowed return on equity of 9.24%. Third, the earnings comparison is expected to benefit by approximately $0.06 per share from increased Missouri electric and Illinois transmission service rates, both effective in January of this year. Finally, we expect results to reflect continued disciplined cost management. Turning then to Page 11. 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 and dividends. For 2013, we continued to anticipate negative free cash flow of approximately $450 million. The guidance continues to include merchant divestiture-related cash outflows of approximately $100 million, including the $25 million of cash that is currently on Genco's balance sheet. These divestiture-related cash outflows are more than offset by expected transaction-related cash tax benefits with a present value of approximately $180 million, which we expect to substantially realize in 2015. Moving now to Page 12. I would like to update you on Ameren Illinois' 2 pending Illinois energy delivery rate cases. In our gas delivery rate case, we have requested a $47 million annual increase based on a 2014 future test year. The ICC staff has recommended a rate increase of $27 million or $20 million less than our request, with a primary difference related to the return on equity level that should be incorporated into rates. The Illinois industrial energy customers has also filed a return on equity testimony in the case, supporting the level that falls between the ICC staff's position and our request. In addition, the Illinois Attorney General and Citizens Utility Board recommended that the ICC use a higher forecast of revenues from gas transportation, a lower forecast of employee headcount and various other adjustments. However, they did not file return on equity testimony. In total, the Attorney General, Citizens Utility Board adjustments would reduce the rate increase amount by approximately $11 million compared to our request. The ALJ's recommendation is expected as soon as today or tomorrow. A final ICC decision is due no later than December 19 of this year, with new rates expected to be effective late this year. Turning to Page 13. In addition to the pending gas rate case, in April of this year, we made a required annual electric delivery rate update filing. Our filing supports a net actual rate decrease, reflecting the decrease for the 2012 revenue reconciliation under formula ratemaking, partially offset by an increase to reflect 2012 recoverable cost and expected 2013 net plant additions as prescribed by the rate formula. The ICC staff is recommending a larger net rate decrease. The ICC ALJs are expected to issue their recommended order soon and the final ICC decision is due no later than December 15 of this year. New rates are scheduled to take effect in January of next year. I would note that the midpoint of our 2013 earnings guidance reflects an outcome to this electric delivery case, with cost of service adjustments that are similar to those made by the ICC in our 2012 rate orders. Moving to Page 14 of our presentation. We plan to provide 2014 earnings guidance and comment on our multi-year earnings outlook when we release fourth quarter 2013 earnings in February. But here, we list some key items to consider as you think about next year. Ameren Missouri will remain focused on enhancing its regulatory framework. At this time, we continue to have discussions with numerous stakeholders in an effort to develop a specific legislative proposal. Our focus is on enhancements that will reduce regulatory lag, allowing us to increase discretionary investments in our aging Missouri infrastructure, advancing our ability to meet the energy needs and expectations of our customers and create jobs. While the exact timing has not yet been determined and assuming no change in the regulatory framework, we expect to file electric service rate case in Missouri in the second half of 2014, with new rates expected to be effective in 2015. Key drivers of this filing include the need to reflect in rates the approximately $320 million to $370 million investment we are making in a new reactor head for the Callaway Energy Center and enhanced pollution control equipment, electrostatic precipitator upgrades at the Labadie Energy Center. The reactor head replacement, a project which has been successfully completed at many U.S. nuclear generating plants, is scheduled for the fourth quarter of 2014 when the plant will be shut down for a scheduled refueling and maintenance outage. The Labadie precipitator upgrades are also expected to be in service by the fourth quarter of next year. Before I leave the discussion to Missouri, I want to mention that 2014 earnings comparisons will benefit from the absence of a 2013 charge of $0.07 per share related to the fuel adjustment clause and presumed a normal weather conditions versus mild year-to-date weather in 2013, which is estimated to have negatively impacted earnings by about $0.02 per share. For Ameren Illinois electric delivery service, 2014 will be another year of performance-based formula ratemaking, with the allowed return on equity tied to 30-year treasury yields. For gas delivery service, 2014 will be a year with new rates in effect, rates that will be established based on a 2014 future test year. Further, our gas delivery service plans to participate in Illinois' infrastructure surcharge framework beginning next year. This legislatively enabled framework allows rates to be adjusted monthly between rate cases to reflect investments in qualified gas delivery infrastructure. As a result of these constructive regulatory frameworks, we plan to continue our investment in the electric and gas delivery service enhancements under our Illinois Modernization Action Plan. At our FERC-regulated transmission business, next year is expected to be one of continued investment, a reliability project in Ameren Illinois and advancement of the previously discussed Illinois Rivers project. Finally, as Tom discussed, we expect parent and other expenses to decline in 2014 compared to 2013, and we plan to continue disciplined cost management across the company. Turning to the final page of our presentation, Number 15, I will summarize. Third quarter earnings from continuing operations were solid. We are on target to become a fully rate-regulated utility with our exit from the merchant generation business expected to be completed by year end. Our regulatory frameworks have improved, and we are working to further enhance them, especially in Missouri. We have a well-defined investment plan that is aligned with our regulatory frameworks. And importantly, these investments are needed to meet our customers' energy needs and expectations. This investment plan is expected to lead to rate base growth of approximately 7% annually over the 2013 to 2017 period, a growth rate above the average for regulated peers. And we look for this rate base growth to result in earnings and dividend growth. In addition, as mentioned, we expect the earnings drag of parent company and other costs to decline from the expected 2013 level, providing an additional benefit to earnings in 2014 and 2015 beyond that of rate base growth. Finally, Ameren's $1.60 per share annualized dividend rate provides investors with the yield of approximately 4.4%. That concludes my prepared remarks. We now invite your questions.

[Operator Instructions] Our first question today is coming from Paul Patterson from Glenrock Associates.

Just weather-normalized sales growth. I was wondering if you could tell us where you are year-to-date. I remember you guys are being sort of flattish with your expectations. Just sort of if there's any update in not just the actuals but just the outlook for -- going forward longer term.

Yes. Sure, Paul. As it relates to the sales growth, I think as we came into this year, we talked about, I think, 0 to maybe even 0.5%, however, of growth as it related to residential and commercial sales. And as we sit here today, I'd say we're seeing sort of different conditions in Missouri and Illinois. We're actually seeing that nearly 0.5% sales growth in residential and commercial sales in Missouri despite, I would say, some spending that -- we've increased spending we've had this year in terms of energy efficiency. And we've also seen industrial sales growth in Missouri this year of about 0.7%. So overall, we're pleased, I'd say, with that level of growth. As I said, we are spending quite a bit on energy efficiency, which, I think longer term, will keep that sales growth more muted and down in that 0 to 0.5% range. Some positives, I'd say, we're seeing in Missouri. We have seen, this year, growth in jobs in both services jobs, as well as goods-producing kind of jobs, manufacturing jobs. And I think that's some of what's coming through in terms of improved sales. So we do expect continued moderate growth, but offset by continuing conservation and energy efficiency mitigating some of that sales growth. But year-to-date, happy with that. In Illinois, it's not been -- not quite as positive. We've seen that residential and commercial sales, actually flat to down, about 0.5%, with commercial, in fact, being down a little more than residential. In industrial sales, as we've talked about on prior calls, down about 6.6% this year. And that does reflect, I'd say, some of the conditions we've been seeing in Illinois. We have seen -- in terms of jobs, we have seen goods-producing jobs down, though I would say services jobs have been up in Illinois. But the conditions just don't seem to be as good with some of the industrial sales down. We've seen declines at places like Caterpillar and heavy equipment and some of the metals areas, steel, U.S. Steel, things like that. One important thing to remember though, Paul, about Illinois is that we do have the formula rates there, and there is a -- we got a formulaic ROE, but there's also a collar around that, plus or minus 50 basis points, which means that, at the end of the day, sales fluctuations, positive or negative, are bound by that, so at most, I'd say a $0.025 positive or negative from any kind of sales fluctuations, whether they be weather related or load related.

Okay, great. And then just as a follow-up to that. The ambitious rate growth, just how do we think about customer builds? You mentioned energy efficiency, that's going to offset obviously some of the impact. Some of the things you're doing are probably going to increase operational efficiencies. So you can't just look at that as a flat impact. But just in general, how should we think about how customers' bills will be impacted by this rate base growth, given the low sales growth, but of course, factoring in these operational and energy efficiency things that are going to be counteracting rate base growth, rate impacts, if you follow me?

Yes, sure. I'll talk a little bit where -- about our -- where our rate base growth is. As you know, a lot of our rate base growth is really in transmission and we're also investing in the Modernization Action Plan in Illinois, as I discussed. And with respect to transmission, of course, the centerpiece of our investment is really in MISO multi-value projects where the benefit of those projects is region-wide, and therefore, the costs associated with those are spread region-wide and don't necessarily then impact our Illinois customer rates, but more rates and cost regionally, so those get spread. As it relates to the Modernization Action Plan, some of the investments we're making at Illinois, the Illinois -- bills of customers are being impacted at the same time as they are by the rollout of these investments, but also by following power prices that have taken place in MISO and have also been impacting customers' bills. So one of the things we're focused on as it relates to those Illinois bills is really working to keep rates, annual rate increases below, say, a 2.5% level and that's the focus there. And then in Missouri, you're right, energy efficiency is -- we're rolling out meaningful energy efficiency programs. I think it's a well-constructed program for Ameren Missouri and for the state, where certainly we're kept whole, if you will, for the energy efficiency efforts, but customers have the opportunity to benefit from those. And then we're also continuing, as we talked about on the call -- focused on disciplined cost control. And we're focused on lean efforts, really, across our Missouri operations and across the company to try to keep any rate increases minimized.

Our next question today is coming from Michael Lapides from Goldman Sachs.

Just thinking about the Missouri rate case you plan to file, does this imply you're expecting to underearn by a good bit in the Missouri in 2014? Is there a kind of -- how should we quantify the amount of lag that's happening in Missouri right now?

Well, as you know, Michael -- thanks again for joining us, by the way, and then -- and your comments at the outset. As it relates to the Missouri rate case, it's -- the filing of that rate case next year isn't solely a commentary on earned returns, but certainly, it's being driven by the things we talked about, making meaningful investments in the reactor head replacement, as well as in environmental controls for the Labadie plant. And clearly, under Missouri's current framework, which does use historical cost, what we need to do is we think about meaningful investments that will grow the rate base and being able to earn a fair return on those investments. We'll need to make a rate case filing at a timely way to make sure we recover those costs and again, position ourselves to earn fair returns. Those are really the drivers.

And then the bulk of the $320 million to $370 million for Callaway and Labadie, is that cost you'll incur in '14? So when you think about Union Electric kind of CapEx of directionally $500 million to $600 million, that this makes up a large portion of it?

Yes, it is a large portion there. Some of those costs -- you don't start those project necessarily in '14, so we've been certainly spending some, say, towards that reactor head already. But yes, I mean, they'll hit largely in '14 and again, be in service by the end of '14.

Got it. And last question, in the quarter or maybe more importantly, year-to-date for 2013, what was the earnings contribution for the FERC-regulated transmission?

Michael, I'll see if Doug can dig that out. I don't have that here in front of me and don't know it off the top of my head.

Yes. Or kind of think about what's just embedded in 2013 guidance for it.

Yes, I think Doug's going to take a look through it.

[Operator Instructions] Our next question is coming from Paul Zimbardo from UBS.

This is Paul from Julien's team here. I wanted to ask about your thoughts on the impacts of the closing of the Paducah processing plant. How do you see this impacting the outlook for Joppa, as well as our prices and demand in the region and also the -- if you could mention the impacts to your financials.

Yes. Paul, this is Marty. As it relates to the Paducah facility and impact on Joppa, obviously, the Joppa facility is one that -- is part of the portfolio that we're looking to sell to Dynegy. In terms of the impacts of the Paducah facility closing on our earnings, I don't really have anything to report there. Overall, that -- the merchant business, this quarter versus last, performed well. Availability was solid. Capacity factors were solid at the plants. I think, as we all know, power prices were down a little bit, down some this year versus last. But we came into the year pretty well hedged. So overall, the unit continues to perform well. I can't really comment on how that facility closing would impact future years and certainly expect that, that plant to be part of the Dynegy IPH portfolio going forward.

Okay, great. And then a quick follow-up. I believe you said you were assuming a 3.44% average for the treasury yields. Could you quantify what the impact was for the third quarter and roughly the amount that was implied in that fourth quarter guidance?

Well, the amount that's implied in the fourth quarter guidance, Paul, really is within that 9.24%. So when we talk about the 9.24%, it's really what we're expecting to be the average over the course of -- over 2013. And as then we look at the blue chip consensus for next year, we see that going up to maybe 3.95% for the 30-year treasuries, which would put you at about 9.75%. In terms of the impact on the ROE, you can kind of do the math. What we've talked about is about 50 basis points is roughly $0.025, so depending upon what's your expectation, as you can kind of take a look at what the impact is.

Our next question today is coming from Rajeev Lalwani from Morgan Stanley.

You -- in your prepared remarks, you had talked about just growing the dividend. I was hoping you can walk us through the policy and your expectations going forward there, and then a follow-up.

Yes, sure. So there -- as we've discussed in the past, what the board looks at is a number of factors. But first of all, getting this deal closed with the sale of the merchant business, which, as we've talked about, we expect the benefit of that to be more stability and certainty in terms of earnings and cash flows going forward. So that's an important step. And then, looking at growth in the earnings and cash flows of the regulated businesses going forward, we've talked about a payout range target to be in the range of 55% to 70% of our regulated earnings. And today, we're at the upper end of that range with our $1.60 earnings. But as we do grow the earnings from the regulated business, and we believe we have a good plan to do so, and as we grow those earnings and cash flows, aspire to be able to then grow the dividend, and as that payout comes down into that range of 55% to 70% that I discussed.

Are you expecting not to raise the dividend until you get to around the midpoint?

No, that was not my statement at all.

Okay. And then the follow-up question. I think you noted that earnings for this year at the Illinois utilities don't reflect the SB 9 impact. Is that accurate?

Well, what the earnings reflect -- I guess, I'm trying -- not following in terms of what you mean by it doesn't reflect.

Well, I guess there are some benefits around the changes with the legislation earlier this year, and trying to figure out if that's incorporated in your earnings for this year of if that's more of a next year event, just given timing.

No, I think that the -- to the extent that the legislature clarified its views on the way the Illinois formula [indiscernible] we've actually formulated that into our 2013 earnings expectations. So it's our expectation that the Illinois Commerce Commission, as they rule on 2013 reconciliation, will, I guess, rule in line with the legislature's intent and financing this last piece of legislation. So that is reflected in our 2013 earnings. We haven't done anything in terms of going back in time and picking up any kind of benefit for prior years that may come through appeals of the commission's rulings for prior years. But we did impact -- we did update 2013 earnings for -- to reflect the provisions of that legislation.

Okay. And then in terms of just regulatory lag in Illinois, can you just talk about where you expect that to be going forward or if there shouldn't be any lag with the changes made?

No, really shouldn't be any lag. When you think about the formulaic rates going forward, there really shouldn't be any lag. The legislation, we believe, is pretty prescriptive in terms of the costs that are picked up. Earlier this year, we did lay out certain costs that were outside of the formulaic ratemaking that would continue to be a drag, but for continuing efforts to reduce those costs, and we laid some of those costs out and we also identified those ones which we expected to go away over time. And then as it relates to the gas portion of the Illinois business, we have filed a rate case as we discussed on the call with the 2014 forward test year. And that forward test year is intended to minimize lag and some underearnings that we're experiencing this year in the gas business. But with the updated rates reflecting the 2014 cost and investments, that will minimize the lag next year. And then we also have the ability, now with the legislation in the gas portion of the business, to update rates monthly for incremental investments in our infrastructure that are beyond those reflected in the forward test year. So that also will help going forward as we deploy capital in the gas portion of the business to make sure we have an opportunity to earn a fair return there. Then the other portion of the Illinois business is -- continues to be transmission, where we still have transmission, that's FERC-regulated transmission in the Ameren Illinois business and of course, we have formula rates there. And again, don't experience lag as it relates to the transmission business. So all in all, I would say, in Illinois, very little in terms of ongoing regulatory lag.

Our next question today is coming from Ashar Khan from Visium.

If I can just go over these factors that you pointed out, Marty. So if I take the midpoint of the guidance for this year, which is I guess now $2.05, you kind of mentioned there is like $0.07 that doesn't come in because of the [indiscernible] more normal, so a more normalized number would be like $2.15, if I add those $0.10 back. And then you were saying that the parent and other should go from a negative $0.20 to somewhere between $0.10 and $0.15. So say, now you pick up on the $0.07 midpoint of that, so you're starting like at $2.22 normalized. And on top of that, we should add rate base growth for the distribution and transmission business. Am I doing my math right?

Yes, all of your math is correct. So those are pieces of information provided. So then the midpoint is, as you pointed out, is $2.05, and our range is $2 to $2.10. I'd say, as we sit here today, we feel good about being maybe even a couple of cents into the top half of that range. So your $2.05 is a good starting point and you're right, we've had $0.07 of negative impact this year, one time from the FAC. And weather, one number -- you mentioned $0.03 weather. I think, year-to-date, it's probably $0.02 of negative weather, so it's -- you're probably talking about $0.09 there to add back, which you did appropriately. And you're absolutely right, we expect to reduce those parent company, other costs, which we estimate to be about $0.20 for this year, down to that range of $0.10 to $0.15 next year. So the things you're adding back are correct.

Our next question is coming from Paul Patterson from Glenrock Associates.

Operator, I think Paul was already on and off.

No, I'm here. I'm sorry. Just -- there was this an independent market monitor report from MISO that companies have been talking about in terms of potential impact on reliability and the reserve margin decrease. And rather -- I guess, under certain circumstances, rather sort of dramatic decrease, perhaps in reserve margin that has been discussed. And I was just thinking how you guys see that. I'm sure you guys have reviewed it. Obviously, for Illinois, the impact is a little bit different since you don't have generation. But just sort of how you see that in terms of Missouri and just any thoughts you have on that, and how that may or may not be in your rate base growth forecast right now, if you follow me, in terms of potential resolution of that or if you -- I don't know. Any comments you have on that I would be interested in.

Yes, Paul, I think as it relates to the issue you're referring to, we've had a long-standing position. We do believe that within MISO, we do need to get beyond this sort of annual capacity construct that really more of -- multi-year, longer-term price signals are appropriate to incentivize investment and make sure that we do have good reserve margins within MISO. It really comes down to being important, we believe, from a reliability standpoint. So our positions on those factors haven't changed over time. In terms of our Missouri operations, we obviously operate a good strong portfolio of assets that are performing well. And as we think -- longer term, as you've seen in our 5-year investment plans right now, I don't have anything in there in terms of meaningful change in our generation mix. But as we think longer term, we certainly do have an aging fleet of generating units, and we'll monitor all conditions, capacity price conditions, and as well as the IRP process in Missouri, which as we have discussed before, I think it's late next year. We will file another IRP with the Missouri Public Service Commission and at that time, I think we'll lay out our thinking about the options we have around our portfolio long term.

Okay. But I mean, I guess, just wanted just a more general comment in terms of this potential -- rather remarkable reserve margin potential that, under certain circumstances, could theoretically show up. Obviously, you guys are -- feel reliability is important. It's not clear to me exactly where -- what service territory would be impacted or who would be deficient. But I'm just sort of wondering if there's any -- if you feel that there's any issue that requires sort of a more rapid response.

Well, we don't. As it relates to Missouri, which, I guess, for your question, we don't see a deficiency in our Missouri resources. I mean, we do have adequate resources in our Missouri business to meet our Missouri load obligations. So we don't see anything there. I think the -- one of the things we said, Paul, honestly, is that, with the reserve margins today, we believe, are high within MISO. At what point we get to sort of critical conditions is uncertain. We've certainly looked at what's been put forward by the market monitor and the committees that have reported out to MISO. And certainly, those are valid concerns that are being raised. And so we do think it's important that MISO take action to -- with regard to its capacity construct and move, as I've said earlier, into having a multi-year capacity construct. But as it relates to Missouri, I certainly don't see any kind of condition of emergency or urgency as it relates to our resources there.

Okay. What about Illinois? I mean, I know that you're not responsible for, but just in general, do you see that as a -- that Zone 4 is being problematic? And I guess, does that maybe lead to maybe additional transmission issues or potential investments or just any thoughts there?

Well, we're obviously -- we're investing a lot in transmission. I don't know if it will lead to incremental transmission in the near term. But our concerns about the capacity market and the -- our continued belief that it's important, from a reliability standpoint, to have a multi-year capacity construct, does get to Illinois and making sure that in Illinois, where it is a deregulated market, that the right price signals are sent over time to incentivize investment in generation so that there are resources available as Illinois goes out to -- and customers in Illinois go out to procure the power and capacity that they need. So again, I'm -- Paul, I'm not, by any means, saying that there's an emergency situation necessarily. But I think the points that are being raised at MISO are the right points to debate and consider as we think about a capacity construct going forward and the need for reliability in Illinois and throughout MISO.

Our next question today is coming from Bill Appicelli from Nexus Asset Management.

Just had a question about the underlying O&M growth that you've seen sort of for this year. I know there are some lumpy items, but what do you guys see sort of going forward at the utilities in terms of maybe O&M growth rate or -- you've got this comment about continued discipline on cost management. So is there a target in mind, or what are your thoughts around that?

Yes. We haven't really -- Bill, thanks for the question. We haven't really communicated, I'd say, a target. Our goal is, as we've said repeatedly, is to, in Missouri, for example, is to keep our earned returns very close, as close as we can, to our allowed returns and to really try to minimize that impacts of regulatory lag. And so as I said earlier, we continue to look for ways to streamline our operations to become more efficient. I mentioned our lean efforts, which, we believe, over time, will produce savings but really haven't communicated, I'd say, any specific targets or expectations. In Illinois, we continue to be focused on running efficient, lean operations there as well. Earlier, the question came up about customer bills, and we are investing and improving the infrastructure in Illinois for the benefit of our customers, it's creating jobs as well. But one of the things we are doing is continuing to work to be efficient in terms of our operations and maintenance spending as we roll out those investments to, again, minimize the overall impact on our customers' bills. So really, across the operations, we're looking to operate in a very disciplined way.

Okay. And then I guess, just at the parent, I know outside of the refinancing of the parent debt next year, that will drive some of the cost savings. What are the other areas that are -- you guys are focused on to reduce the parent drag?

Yes. So there were -- I talked earlier in the year about as much as $30 million or so of costs that were G&A costs, if you will, that had been allocated over time to the merchant business. A significant amount of those are really direct costs, costs that we were incurring sort of at a parent level that were directly associated with the merchant businesses. So as we get to closure there, those costs -- those direct support costs will be eliminated. And then to the extent that there were other costs that were being allocated, we've had significant efforts underway over the past several months to identify ways to be able to eliminate those costs as well. And that progress -- that work has been going very smoothly and very well. So those targets that we talked about, getting $0.20 down to $0.10 to $0.15 next year, we feel very good about. And then as we look to '15, what we talked about on this call is getting those costs down even lower as those costs are reduced and rationalized. We get the full year benefit of the refinancing next year. And I've said before that we expect that we might be able to get those -- we'd be able to get those costs, not might -- we'd be able to get those costs down under $0.10 in the 2015 timeframe.

Okay. And then just on the refinancing, do you expect to refinance the full $425 million or would there potentially be a lesser amount that's refinanced or -- in terms of reducing the principal?

That's under consideration. We think that today, if you look at today's market, that you'll be able to refinance that 8.875% debt. Today, maybe at around the 2.5% kind of mark. So favorable conditions as we sit here today and big opportunity for interest savings. What amount of that we would do sort of on a longer-term versus a short-term refinancing is under consideration and we'll let you know when we've got a specific view on that. But we do have -- as you know, we have the full capacity under our credit facilities available to us today. We've got no borrowings under those. So we have the flexibility with respect to that $425 million to do some of that long term and some of that on a short-term basis as well.

Our final question today will be a follow-up from Michael Lapides from Goldman Sachs.

Two items, one on O&M. Can you just walk us through how the Callaway outage schedules impact O&M? I think impacted last year and then will -- this year and then what the impact is in 2014? Does that get capitalized or is that all kind of flowing through and therefore, you see kind of some abnormal trends rather than just steady year-over-year changes in O&M?

Yes, Michael, that's true. I know that the accounting practices vary across the industry. But we do expense the full cost of the operations and maintenance expenses for the Callaway refueling in the period that, that outage occurs. So we had the full Callaway refuel expenses expensed earlier this year. So we did have a refueling in the spring of this year. The next one is, I sort of referred to earlier on the call, is in the fall of 2014. We certainly have significant capital expenditures at that time that I mentioned. We also have the refueling and maintenance outage, O&M costs that we will incur there at the end of 2014. And then 2015, we have no scheduled refueling and maintenance outage. So 2015 wouldn't have any refueling and maintenance outage costs in it.

Got it. So will the -- because it's a bigger or kind of more complex outage that's happening in the fall of 2014, because you're doing the extensive capital work, will the O&M piece of that outage be different than a normal refueling outage? Or will some of it get capitalized, some will be O&M? Like I'm just trying to think about, as you start to give drivers for 2014, how the Callaway refueling schedule will impact things.

Yes. So Michael, I think sitting here today, we're not giving out our 2014 guidance, and I'll give more specificity when we do along those -- along the Callaway outage. However, I don't believe that the 2014 O&M costs are expected to be materially different than the 2013 cost.

Okay. And then those -- when you did the 2013 cost, what was the cost of that outage that happened in the spring?

Well, it'll -- this is Doug. It's in the Q. I don't have it precisely. Maybe we can...

We'll try to dig that one out for you too, Michael. But as Doug said, it's in the -- we did disclose that in the...

When the Q is filed, it will be clearly in there.

Mr. Fischer, there are no further questions at this time. I'd like to turn the floor back over to you for closing comments.

Thank you, all, for participating in this call. Let me -- excuse me, 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 Fisher, or my associate, Matt Thayer. Media should call Joe Mellencamp. Our contact numbers are on the news release we issued today. Again, thank you for your interest in Ameren, and have a good day.

Thank you. That does conclude today's teleconference. You may disconnect your lines at this time, and have a wonderful day. We thank you for your participation today.