Ameren Corporation (AEE) Q2 2013 Earnings Report, Transcript and Summary

Greetings and welcome to the Ameren Corporation Second 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 Fischer, Senior Director of Investor Relations for Ameren Corporation. On the call with me today are Tom Voss, our Chairman, President and Chief Executive Officer; Marty Lyons, our Executive Vice President and Chief Financial Officer; and other members of the Ameren management team. Before we begin, let me cover a few administrative details. This call is being broadcast live on the Internet, and the webcast will be available for 1 year on our website at ameren.com. Further, this call contains time-sensitive data that is accurate only as of the date of today's live broadcast. Redistribution of this broadcast is prohibited. To assist with our call this morning, we have posted a presentation on our website that will be referenced by our speakers. To access this presentation, please look in the Investors section of our website under Webcasts and Presentations and follow the appropriate link. Turning to Page 2 of the presentation. I need to inform you that comments made during this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those about future expectations, beliefs, plans, strategies, objectives, 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 section in our filings with the SEC. Tom will now begin this call with an overview of second quarter 2013 results and our updated 2013 earnings guidance, followed by an update as well on recent business developments. Marty will follow with a more detailed discussion of second quarter 2013 financial results, other financial matters and pending rate cases. 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 second quarter 2013 net income from continuing operations of $0.44 per share compared to second quarter 2012 net income from continuing operations of $0.66 per share. This reduction in earnings was a result of a planned nuclear refueling outage and an unfavorable court decision related to the Missouri fuel adjustment clause, or FAC, both in 2013, an impact of a favorable regulatory decision in 2012. In addition, our earnings were reduced because of milder weather. The 2013 court action was a May Missouri Court of Appeals decision related to FAC treatment of certain prior-period wholesale sales. The second quarter earnings comparison was favorably impacted by new rates for Missouri Electric and Illinois Transmission Service, both effective in January 2013. Second quarter earnings from continuing operations were in line with our expectations, excluding the charge related to the Missouri Court of Appeals' FAC decision. Reflecting our agreement to divest our merchant generation business to an affiliate of Dynegy, merchant generation results are classified as discontinued operations in our financial statements. Marty will provide more details on our earning in a few minutes. Moving now to Page 4. Today, we also updated earnings guidance. We now expect 2013 earnings from continuing operations to be in the range of $2 to $2.15 per share compared to the prior range of $2 to $2.20 per share. This new guidance range incorporates the second quarter 2013 charge of $0.06 per share resulting from the FAC decision just discussed, as well as cost-containment within our Missouri operations. Guidance continues to incorporate approximately $0.20 per share of parent company and other cost, including certain costs that were previously allocated to the merchant generation business. Turning to Page 5. We remain committed to closing a transaction to divest our merchant generation business to an affiliate of Dynegy. Once this business is divested, Ameren will be a purely rate regulated electric, natural gas and transmission company focused on growing our investments in energy infrastructure, benefiting our customers, communities and investors. We're working diligently with Dynegy to complete the transaction and continue to anticipate our fourth quarter 2013 closing. Request for regulatory approvals are pending at the Illinois Pollution Control Board and the Federal Energy Regulatory Commission, or FERC. Last month, Dynegy's Illinois Power Holdings Units, or IPH, and our merchant generation subsidiaries requested that the Illinois Pollution Control Board grant IPH the same variance from the Illinois multipollution standard that was granted to Ameren Energy Resources in 2012. We expect the variance to be granted, and the board has until late November of this year to issue a decision. Regarding the FERC filing for divestiture approval, last Friday, FERC requested copies of Ameren Energy Marketing's long-term wholesale contracts with 2 entities, both of which have intervened at FERC. Ameren Energy Marketing entered into these contracts under its market-based rate authority. Therefore, we now believe the contract should impede FERC's approval of the divestiture. In addition, FERC requested that an input into Ameren's market power study be revised. Ameren and Dynegy must respond to these information requests by August 9. In addition, our efforts to sell the 3 gas-fired energy centers we retained with the exercise of the Genco put option are progressing. We have shortlisted multiple interested potential buyers based on their initial proposals and we continue to expect to sell these plants by year end subject to separate approval by the FERC. Moving to Page 6. We remain focused on improving the regulatory frameworks for investing in our utilities and states for the benefit of customers, communities and investors. And I'm pleased to report important recent successes on this front in the State of 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. However, the Illinois Commerce Commission, or ICC, misapplied the act in our 2012 electric delivery formula rates. This is our view. To correct these misapplications, the Illinois General Assembly overwrote Governor Quinn's veto and enacted Senate Bill 9. The stature ensures that the originally intended provisions of the 2011 Act are applied by requiring that year end, not average rate base and capital structure be used for ratemaking. Further, the new stature requires the use of weighted average cost of capital, not a short-term interest rate for computation of annual revenue requirement true-up deferrals. Application of SB 9's provisions is expected to have little net impact on 2013 earnings. However, we do expect these provisions to be meaningful as our infrastructure modernization investments grow in the coming years. Further, Governor Quinn signed the Natural Gas Consumer, Safety & Reliability Act in July 2013. This new law establishes a regulatory framework for accelerating gas infrastructure investment, improving customer service and creating jobs. Utilities that elect to participate may implement rate surcharges for infrastructure investments made between rate cases. Eligible gas delivery plant additions include replacement of mains and older pipe, relocation of meters, and the installation of advanced meters, among other things. These surcharges may be updated monthly. The law retains ICC oversight of utility rates and provides consumer protections, including an average annual cap on surcharges of 4% of utility rate base revenues. Ameren Illinois expects to participate in this ratemaking program beginning in 2014 or 2015. Further, it plans to make an incremental $330 million of capital investment above a baseline of $770 million over 10 years and to create 150 new jobs at the program's peak. Turning now to Page 7 in Missouri. We also remained committed to enhancing Missouri regulatory framework to better support investment in that state's energy infrastructure. We're focused on enhancements that would support electric utility investments that are already in place and serving customers between rate cases. We were encouraged by the substantial majorities in both the Missouri House and the Senate, that supported the Infrastructure Strengthening and Regulatory Streamlining Act, commonly referred to as electric ISRS in the 2013 session. However, the legislation was blocked late in the session by a few filibustering senators. We are evaluating options for legislation in 2014, and we'll continue to work diligently on this important matter. As detailed on this page, Missouri electric utility regulation has improved in recent years. However, the lack of a modern framework that better supports capital investments made between rate cases limits the level of discretionary investment we can reasonably make in our energy infrastructure in this jurisdiction. An improved framework would be positive for job creation, the quality of service we can provide to our customers and the return opportunity we provide to our investors. Before I conclude my comments on our Missouri utility, I want to mention a recent operational development. Last Friday, the Callaway Energy Center experienced a fault in its electrical equipment that transfers power from its generator to its main transformers, which provide power to the grid and to the plant. The fault tripped the plant and it also caused a small fire in the turbine building, which is located in a nonnuclear part of the facility. The fire was quickly extinguished. At no time did the situation threaten the public, and no one was injured. The plant is currently out of service and we are still in the process of assessing whether there was any major equipment damage as a result of this event. Our preliminary test to date do not indicate that we incurred any significant damage to our major equipment. However, we still have a series of tests that we need to conduct through the weekend. Until all of our testing is completed, we are unable to provide an exact date as to when Callaway will return to service or an exact estimate of any related financial impacts of this outage. If our complete testing confirms that no damage was sustained beyond that which has been identified to date, we estimate that the energy center will return to service in 15 to 20 days, and that the earnings impact will be less than $0.01 per share. Moving to Page 8 of our presentation. I will conclude my business update by discussing electric transmission. Our plans to invest approximately $2.2 billion in FERC regulated electric transmission projects over the 5-year period ending in 2017 are a key part of Ameren's business strategy. These projects will benefit customers by providing more reliable and efficient electric system and it will also create jobs. Constructive forward-looking formula ratemaking that is in place for these projects provides an opportunity for us to earn fair returns on our investments, recover our costs on a timely basis. Our single largest planned transmission investment is Ameren Transmission Companies of Illinois, Illinois Rivers project. This approximate $1.1 billion MISO approved regional multivalue project involves the construction of a new high-voltage transmission line across the state of Illinois. Our request for a certificate of public convenience and necessity for the approximate 400-mile transmission line is pending at the ICC. In early July, the ICC Administrative Law Judges hearing the case issued their recommendations. We are pleased that the ALJ has agreed the project is necessary and the best approach to addressing transmission and reliability needs and the development of the competitive electricity market. Further, we are encouraged that the ALJ has recommended that a majority of the Illinois River project, 7 of 9 segments, be granted the requested certificate. We comprehensively responded to the questions raised by the ALJs regarding the location of 2 of the 9 line segments and certain substations in our briefs on exceptions filed on July 18. Therefore, we expect a constructive decision from the ICC by August 20, and we expect this decision to allow ATXI to maintain our previously disclosed capital investment plans for the project. 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. Closing my prepared remarks, we remained focused on delivering strong returns to our shareholders by investing in and operating our businesses in a manner consistent with our existing regulatory frameworks. This means, we will exercise disciplined capital allocation, concentrating our discretionary investments in those jurisdictions that provide modern, constructive regulatory frameworks like those at FERC and in Illinois. Finally, we are committed to growing our earnings, earning fair returns on our investments and meeting our customers' energy needs and expectations. I will now turn the call over to Marty.

Thanks, Tom. Turning to Page 9 of the presentation. Today, we reported second quarter 2013 net income, combining results of both continuing and discontinued operations of $0.39 per share compared to second quarter 2012 net income of $0.87 per share. The second quarter 2013 net income included a loss of $0.05 per share from discontinued operations. As Tom previously discussed, Ameren earnings from continuing operations were $0.44 per share for the second quarter of 2013 compared to $0.66 per share for the second quarter of last year. On Page 10, we list the key factors that drove the $0.22 per share decline in second quarter earnings from continuing operations. Several large items impacted the quarterly comparison. These include expenses related to a planned Callaway Energy Center refueling and maintenance outage, which reduced earnings by $0.08 per share. Because Callaway has refueled approximately every 18 months, there was no refueling outage or associated expenses in 2012. In addition, the second quarter 2013 earnings were reduced by $0.06 per share as a result of the Missouri Court of Appeals' decision Tom referenced earlier. This decision related to FAC treatment of certain prior period wholesale sales, which occurred in the 2009 through 2011 period. The earnings decline also reflected the absence in 2013 of a $0.07 per share 2012 benefit from a FERC order related to a disputed Missouri purchase power agreement. Moving to sales. Temperatures negatively impacted the earnings comparison by approximately $0.05 per share. This year's early summer temperatures were cooler than last year's warmer-than-normal temperatures reducing electric sales volumes to our native load customers. Electric and gas sales volumes to native load customers also fell on a weather-normalized basis, reducing second quarter 2013 earnings by approximately $0.02 per share compared to the same period a year ago. This primarily reflected lower weather normalized electric sales volumes in Missouri, offset by increased weather normalized electric sales in Illinois and natural gas sales in Missouri. While on the topic of sales, I want to mention that for the full year of 2013, we expect weather normalized electric sales volumes to native load customers to be roughly flat with those of the prior year. Combined residential and commercial sales volumes are expected to increase about 0.5%, but this is expected to be offset by an expected decline in lower margin industrial sales volumes. Focus now on the last item on Page 10. The second quarter 2013 earnings per share comparison was favorably impacted by new rates from Missouri Electric and Illinois Transmission Service, both effective in January 2013, which combined the increase in earnings by $0.08 per share. Turning now to Page 11. Before concluding my discussion of earnings, I'd like to provide you with some information to assist your thinking about Ameren's third and fourth quarter 2013 earnings outlook. On this page, we've listed select items that are expected to impact third and fourth quarter 2013 earnings from continuing operations as compared to the impact of these items in the third and fourth quarters of 2012. First of these items is weather. In last year's third quarter, warmer-than-normal summer temperatures increased earnings by an estimated $0.14 per share. And in the last year's fourth quarter, warmer-than-normal early winter temperatures reduced earnings by an estimated $0.02 per share. Our 2013 guidance for earnings from continuing operations assumes normal temperatures for the second half of this year. The second item to note is an expected positive impact on the Ameren Illinois electric delivery earnings comparison resulting from variation in the timing and amount of expected full year recoverable cost under formula ratemaking. These earnings are expected to increase by approximately $0.10 per share in the third quarter 2013, and $0.01 per share in the fourth quarter compared to the prior year periods. This is a good place to note that our full year 2013 Illinois electric delivery earnings guidance now incorporates an average 30-year treasury bond yield of approximately 3.4%, and therefore, a formula allowed return on equity of approximately 9.2%. Finally, earnings should benefit from the new Missouri and Illinois transmission rates that went into effect in January of this year. Turning then to Page 12. We move from earnings to a discussion of our updated 2013 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 $450 million, an improvement of $50 million from our May 2013 guidance. The guidance continues to include merchant divesture-related cash outflows of approximately $100 million, including the $25 million of cash that is currently held at Genco. These divesture-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. Moving to Page 13. I would like to update you on Ameren Illinois' 2 pending Illinois energy delivery rate cases. First, in January of this year, we filed a request for an increase in gas delivery rates based on a 2014 future test year. In June, the ICC staff and other intervenors filed their initial testimony in this gas case. The primary differences between our request and the positions of the ICC staff and the Illinois Industrial Energy customers are related to the return on equity level that should be incorporated into rates. In addition, the Illinois Attorney General and Citizens Utility Board recommended that the ICC use a higher forecast of revenues from gas transportation and industrial customers than we had proposed. If adopted, this adjustment would reduce the needed rate increase. A final ICC decision is due by December 19 of this year. Turning to Page 14. In addition to the pending gas rate case, in April of this year, we made the required annual electric delivery rate update filing. Our filing supports a net annual rate decrease consisting of a decrease for the 2012 revenue reconciliation under formula ratemaking, partially offset by an increase, primarily reflecting 2012 recoverable cost and expected 2013 net plant additions as prescribed by the rate formula. In June, the ICC staff filed its initial testimony in the case, recommending a larger net rate decrease than we had requested. The difference between our request and the staff's recommendation is primarily attributable to the same cost of service adjustments made by the ICC in our 2012 rate orders. A final ICC decision is due by December 15 of this year, and the new rates will take effect in January of next year. Moving finally to Page 14 of our presentation, let me summarize. Second quarter 2013 earnings from continuing operations were in line with our expectations, excluding the charge related to the Missouri Court of Appeals' FAC decision. Service to customers has remained highly reliable. We remain committed to a fourth quarter 2013 closing of the transaction to divest our merchant generation business. The divestiture allows to focus exclusively on our rate regulated utilities. In addition, we remained focused on improving our regulatory frameworks and have seen recent progress on that front in Illinois. Further, our utility investment plans provide the foundation for growing our rate regulated earnings. In fact, we project rate base will grow at a compound annual rate of approximately 7% over the 5-year period ending in 2017. Finally, Ameren's $1.60 per share annualized dividend rate is well covered by expected 2013 earnings from continuing operations and provides investors with an attractive current yield of approximately 4.5%. This concludes my prepared remarks. We now invite your questions.

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

I wanted to ask you about the FERC office of energy market request for additional information. It looked like there was -- I guess, they want some more information at least partly because of market power. And also, I'm just wondering what you thought about any potential schedule impact or just what you could tell us more about the interplay with that in your -- getting these plants sold?

Yes, sure. Paul. So you're right. I mean, last week, the FERC did have a, I'll call it a data request but they did ask for additional information with respect to a couple of things. They asked for contracts that we have with 2 customers and they also then asked for some additional information with respect to the market power effects on competition. We have 14 days to respond. We expect to certainly be able to respond within the 14 days. And we don't expect that the additional information they've asked for with respect to the market power impacts to really have any meaningful effect on the data and certainly, no effect overall on the conclusion. So we're going to provide that data as soon as we can, and we're hopeful that there won't be any impact on the overall schedule. We still expect that once the FERC receives that data, they may certainty invite some opportunity for comment on that, but wouldn't expect that it would slow the FERC process down meaningfully, such that, as you heard on the call, we still expect to be able to get FERC approval and close the transaction by year end.

Okay. Now I know you guys, obviously, are planning on selling the plants but any thoughts about just sort of the RPM auction and the ability going forward next year's auctions with respect to the potential to sell capacity into PJM, just seams issues, what-have-you? Any thought with respect to what we saw in May and what might be there? Obviously, I know you guys are getting rid of the plants but obviously, you're still working with them. So I just was wondering if you have any thought about that.

Paul, no, I wouldn't say I have any specific thought with respect to the auction for next year. As you know, the -- this business segment that we're divesting of was successful in getting the ability to sell additional capacity into PJM in periods beyond really the '14 timeframe looking out to post '16. And generally, those prices still look favorable to the prices that exist in MISO today. And so I think just continuing to execute on selling what capacity can be sold into PJM is what that business segment will continue to focus on.

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

Perhaps first, just going back to kind of the merchant business, if you will, just entertain me for one second. I'd be curious if any of the latest regulations kind of change the landscape at all. One hour SO2. Recently, Illinois draft coal ash rules recently released. Does that change anything as far as you're concerned?

No, it doesn't. Certainly, we're monitoring developments there. But as you know, the decision to exit the merchant business is a strategic decision for us. Really provides us the opportunity to focus exclusively on our rate regulated operations. And so, no, Julien, while we're certainly monitoring conditions and frankly, that business segment that we're selling continues to operate well and perform well, but it's obviously a strategic decision to exit the business.

And then going back to the Missouri legislation this year. Just kind of a little bit rehashing and thinking about next year, others have alluded to potentially going back for it, perhaps in a little bit more of a diluted approach. Have you put any thoughts to that next year?

This is Warner Baxter. And so the simple answer is, of course, we're looking at all kinds of options as we look forward to legislation for next year. I mean, certainly, there was a bill that was presented on the senate floor late in the session, which we thought was a good bill. That's certainly an option. We also look at several amendments that were prepared to be discussed and never really got discussed in the floor. Those are potential options. And there are certainly options for even the skinnier version. So what we're going to do and what we've been doing and we'll continue to do is have discussions with key stakeholders to get their input to see what we can do to move constructive legislation forward that will support investment in the state of Missouri. So that's what we'll do. And we'll continue to work with our key allies in Missouri, including all the electric energy providers, to try and craft an appropriate approach forward.

Great. And then a last little detail. Just going back to what you were talking about a second ago in the prepared remarks and I apologize if I missed this, but with regards to the outage here at Callaway, any kind of sense of how significant this would be from a timeline perspective and impact the 3Q results, just initially at least?

So Julien, this is Warner again. I think Tom said that basically, we still have some more tests that we have to complete. And that will take us through the weekend. But preliminary tests indicate that we haven't incurred any significant damage. And so, if everything we have seen so far, indeed, carries through once we complete our tests, it means that Callaway would -- we would expect that beyond another 15 to 20 days from today to get it back into service. But the tests aren't done and we will get those done through the weekend and we'll have a better assessment, certainty, some time next week.

[Operator Instructions] Our next question comes from the line of Andy Bischof with Morningstar.

What would you expect for a ruling after you supply the additional information by August 9?

Yes, this is Marty again, Andy. It's hard to know exactly when they would respond. There's no specific timeline. Once -- you got about 180 days, frankly, to respond and can extend for another 180. But obviously, this request for information indicates to us that they are actively looking at our filing and we would expect FERC based on past practice to move more quickly than the 180 days that are allowed. So no specific deadline, but again, based on past experience, we certainly expect again to get the FERC approval and be able to close by year end. Of course, there's another filing that have been made at the Pollution Control Board and there, the timeline is about 120 days. So in both cases, we expect to get the Pollution Control Board approval for the air variance transfer, as well as the FERC approval for the sale in time still to be able to accomplish a closing before year end.

Moving to low trends, I guess, during the quarter, we've seen some weakness in competitor low trends. Can you just provide a little more clarity on the trends you're seeing across your customer base?

Sure, I'll be happy to comment on that. This year, we've seen a bit of variation, very much like we saw last year. The weather normalized sales started out pretty strong in Q1, but again, like last year, we had some quarterly volatility and we had a bit of contraction in the second quarter. Year-to-date, however, I would say, our residential and commercial sales are up about 0.5%. We said at the end of each of the last 2 quarters that in terms of our 2013 guidance that we expected little in the way of growth. And so, like I said, residential and commercial sales across our utilities are up about 0.5%, and that's we're looking for, for the full year, about 0.5% of growth in residential and commercial sales. With respect to industrial, between Missouri and Illinois, they've been down a little bit this year, primarily in Illinois. Missouri is actually flat to up a little bit. The Illinois trend is a reversal from the past couple of years where we saw really solid increases in industrial sales. But this year, they've turned south a little bit. For the full year, we expect similar kind of patterns for Missouri to be up a little bit in terms of industrial and for Illinois to be down. So those are some of the trends we're seeing. I think -- when I think about the economy and what's going on, what may drive the sales, frankly, in Missouri, the growth in our sales is kind of underscored by some of the things we're seeing in terms of positive movement, job growth, good producing and services jobs, housing starts have been on the rise a little bit, and our customer counts are up. Year-over-year, both residential and commercial residential, up about 0.4%; commericial, about 0.7%. So we're seeing some good trends that give us confidence that 0.5% of growth will be there for the year in residential and commercial and happy to see Missouri industrial sales up a hair this year. So that's generally, I guess, what we're seeing.

Our next question comes from the line of Ian Jenkins with the Wisconsin Investment Board.

This is Dan Jenkins. I wonder if you could give me a little more background on this Appellate Court decision on the FAC and Missouri. And then just what the basis was for the decision? And then if it will have any impact on how your FAC operates going forward?

Sure, Dan. Maybe Warner will -- who's president of our Missouri operations will take that one again.

So remember, when you go back to this issue, it really relates to some margins that we realized from certain wholesale contracts. Actually, back several years ago that the Missouri Public Service Commission felt those margins should have been provided back to our fuel adjustment clause like many of our other office system sales are under the existing rules. And these wholesale contracts really stem from some excess power that we had available for sale due to the loss of load from Noranda Aluminum, which is our largest customer, resulting from a severe ice storm in 2009. And so you go back in 2011, the commission issued the order that we had to refund approximately $80 million of margins earned for the period, March '09 to September '09. And we, indeed, recorded that charge back in 2011. That's a pretax charge. That was -- that did not take those contracts through their full duration. Those contracts went further. And so, in 2012, the staff, Missouri Public Commission staff, recommended additional refund of about $26 million related to the same wholesale contracts. And that's from the period from October 2009 to May 2011, whereas the first one was for March 2009-September 2009, that was the period under review. In 2012, just to give you the history so you know, we actually ended up winning our appeal of the commission's order before the Coal County Circuit Court, but later in 2013, which is the Appellate Court decision that Marty referenced, we -- the Missouri Court of Appeals upheld the Missouri Public Service Commission's position. So as a result of all those things, the commission yesterday issued an order requiring that refund of $26 million. And that's about $0.06 per share, as Marty talked about. And so, we, obviously, will comply with that. And while we were disappointed with the commission's decision, we certainty weren't surprised given the recent Appellate Court decision. So really, as we go forward, we will continue to operate under the provisions of the Missouri fuel adjustment clause. We will -- to the extent that we will follow, we really don't have an issue because we don't have similar types of wholesale contracts going forward. We'll just continue to have -- do the off-system sales as we do today and we'll provide 95% of those margins back to the fuel adjustment clause. The one thing that you should know, during all of this period of time, that we actually did file another or initiated another proceeding in the state of Missouri. And this goes back to July 2011, where we filed with the -- a request with the commission for an accounting authority order that allow Ameren Missouri to defer as a regulatory asset. Really, the fixed cost totaling about $36 million that were not recovered from Noranda as a result of that loss of the load back in 2009. So now that all of these other decisions have been put behind us, the commission now still has before it another docket to potentially provide us an accounting authority order for those losses that we incurred as a result of that loss of load. So a bit of a long story, but that gave you sort of the history of what's going on with the fuel adjustment clause and where things stand today. And so there is no set timetable for the commission to make a decision on this accounting authority order request, but we think the decks are now clear for them to take that up in the relative near future.

Okay. And you don't intend to appeal that under the Supreme Court, the appellate ...?

The appeal of the Supreme court, no, we don't tend to do that. There are certain provisions of the commission's order which we may look to appeal, not the entire $26 million, but another smaller component of that, about $3 million that we think may have been addressed in the prior rate case settlement, that's still under review. But beyond that, no, we do not plan to take this up to the Supreme Court.

Okay. And then just what's your regulatory schedule, I guess, in Missouri? You don't currently have it filed as -- but you have talked in the past about being a more regular rate case scheduled. Should they expect something coming up in the next few months?

Dan, we haven't made any final decisions as to when we'll file our next rate case. But just as we've done in the past, we'll seek to time the filing of our next case to mitigate regulatory lag. And that's regulatory lag resulting from meaningful capital additions, as well as to mitigate regulatory lag for operating costs. And so, when we look at those things, obviously, we just completed a rate case at the end of last year, we'll be mindful of those types of things, as well as capital additions that we have coming before us in a variety of different areas, not just in '13 but in '14. So a final decision hasn't been made, but we keep a very close eye on all these things in terms of when we'll file our next rate case.

Okay. And then the last thing I has is you had a slide show on the cash flow and the fact it will be negative, I just wondered if you could update us what your financing plans are coming up.

Sure, Dan. this is Marty again. So in terms of financing plans, as you probably know from looking at our balance sheet, really nothing in terms of short-term debt at this point have good liquidity. So we'll be looking at this year as some of the maturities that, I believe, we talked to you about last quarter, that we have coming up, both in Missouri and Illinois. And then we've got -- the negative cash flow is really being driven by the capital expenditure plans we have overall. So we'll be taking a look again at those maturities, plus the cash flows driven by the rate base growth and then refinancing those when they get to levels that we think are appropriate to take to the financial market. As we look right now, some of that financing may be done in the second half of this year, some of it may slip to the first quarter of next year. So -- but those are the plans. And then, of course, next year, we've got the debt up at the holding company that you're aware of that we'll be looking at refinancing options. Those come up in May of next year, May '14. And certainly, we've got the opportunity there, as we talked about before, to significantly lower the interest rate of that -- the parent company debt. And, Dan, while I've got you, one thing I want to tack on to Warner's thing, it's just important, is that the charge we took relative to the FAC that when we had the similar one in a prior period, but those are fully behind us, those sales that were in question happened during the finite period of time, the FAC was later modified to address those kinds of things. So it's not an issue that will be recurring going forward. So that $0.06 item was a bit of a onetime item this year and in terms of it not happening again in the future. And we did include it in our core, if you will, earnings from operating activities. But that is not something that would repeat in future periods.

Our next question comes from the line of Steven Fleishman with Wolf Research.

So listen, on the Illinois Rivers, just -- do you agree that the ALJ recommendation was adopted largely as it is? I mean, how much of an impact might it have on the CapEx for that project? I mean, obviously, there were some segments here.

Steve, we have with us here today the president of that subsidiary in segment, Maureen Borkowski. I think I'll let her address your question.

I think the question is if the ALJ order was approved as is, how would it affect our CapEx? Realistically, what would happen is it would probably trigger another proceeding if the order was approved as is. We would have 7 of the 9 line segments approved for routing, as well as several of the substations, we would be moving out on those. And then we would need additional clarity on the remaining 2 segments and the substations. The issue is not really whether or not those things are needed and whether or not they're going to be built, it's just a matter of what the route is. With regard to the 2 line segments that the ALJ didn't recommend approval of, the route was somewhat in question because there was a question about where the locations that were the terminating points of those line segments should be. With regard to the substations that they didn't recommend approval of, the issue was really with regard to the use of the facilities and sites of some existing Ameren Illinois company substations that were nearby. And whether or not we needed new sites adjacent to those facilities or if those existing facilities could be utilized. So it's really just a matter of getting clarity around those issues. So the bottom line is, if the ALJ order was adopted as is, we still wouldn't expect it to significantly affect our capital investment. We'll probably have another proceeding that was a follow-on to clarify the remaining issues. We're hopeful, though, that the response that we provided to some of the issues the ALJs had raised will be clarified in a commission order that's due on August 20. Did that answer your question?

Okay. Yes, that's very helpful. And I think on Dynegy's call this morning, they talked about continued and worsening congestion issues in the region and potential transmission needs for that. Can you talk about whether you're seeing more opportunities in your transition business to address that issue?

We certainly are always looking forward to new transmission investment opportunities. But as you know, the regional transmission plan is really designed by MISO. So we continue to work with the Midwest ISO and with Dynegy and other entities, about addressing some of the congestion issues. But MISO has to work that through their lengthy stakeholder transmission planning process, and any needed improvements have to be determined within the course of the parameters that their transmission plan sets up. Most of the time, I would think these kinds of projects would have to be either reliability or market efficiency projects. We're certainty continuing to propose projects that would address some of these issues, but they have to work their way through the planning process.

Okay. One last question, I guess, for Tom. I think on the last call, you mentioned that there's going to be kind of a board retreat in June, might have been a response to a question on dividend strategy and dividend growth. Anything come out of that on -- in terms of the kind of thinking on dividend strategy and even just how the company looks once this generation transaction is completed?

Sure. We did have a, what I would view as a successful strategy update session with our board in June. They bought into the management's plan about growing -- how we anticipate to grow the business by making investments. We're totally supportive of that approach and they're very much in favor of us as we grow earnings, as we grow the rate base and grow earnings, that we would also grow the dividend over a period of time.

Our next question comes from the line of Kevin Fallon with SIR Capital Management.

I just wanted to see if I could get a little bit more color in terms of the regulatory lag issue in Missouri. And in particular, how fast are you incurring lag, and what's a reasonable amount of lag to accept before you file?

This is Warner Baxter. When you look at regulatory lag in Missouri, it's driven by a couple of things. Number one, it's driven by the fact that they use historical tests here, principally, to set rates. Another big driver is that when capital investments are placed into service between rate cases, there's now an ability to update rates for those major adjustments. And so, what we have been doing as a company is that we've been working very hard and had success in better aligning our spend across our enterprise, both capital and O&M to be more consistent with the regulatory framework that we have in front of us in the state of Missouri. And so we've been able to manage that and we continue to do that going forward. But of course, there will be some point where we're going to have to file rate cases. And what we've been very focused on is narrowing that gap between the allowed return on equity provided by the commission and what our actual earned return on equity has been and we've been able to do that over the last several years pretty successfully. So I wouldn't say there's a magical number or a magical timeframe, we just know that we're going to manage our operations and manage consistent with that and keep a fairly narrow gap and that's what our plan has been and will continue to be.

Is it too precise to say that you guys are hopeful that you can stay out until you have another shot at the legislation? Or is that too fine a point?

Kevin, I would say that's too fine a point. We'll do what we think is right for the business, what we think is right for shareholders. And that's when we'll file rate cases, as well as, frankly, we think legislation isn't just about how we earn better returns. We think it's in the best interest, frankly, of the state of Missouri and its customers. And so, bottom line, we're trying to create a win-win for everybody.

Okay. And in terms of financing plans, as we look over the next couple of years, you guys obviously have a big CapEx buildout. Could you give us some color in terms of the need for equity or target capital ratios for the consolidated firm?

Sure, this is Marty again. We've provided these over time. I think we look to keep the equity content and the cap structure over time, around that 50-50 kind of level where we are today. So we think that's a target that we'd have going forward. We haven't given any specific guidance on any need for equity. Obviously, we've got a strong, we believe, rate base growth plan, capital expenditure plan, expect to be able to grow rate base 7% annually out through 2017, as we mentioned earlier. Largely, we believe that will be funded by the reinvestment of retained earnings as our -- from the earnings we got in the business and the growth in the earnings going forward coupled with that financing. To the extent that we needed some supplemental equity, which we're not issuing any currently, but would have the ability to turn on our DRIP or 401(k) or utilize those programs to generate additional equity. But again, we're not doing that currently and we would make that decision on a year-by-year basis going forward.

Okay. And just last a last question. I just want to confirm that if the ALJ position is upheld on the Illinois Rivers project, that even if you have to seek a second proceeding to get the full amount of the substations and lines completed, the construction on the project as a whole will move forward as scheduled and it's kind of an add-on to that incremental process that you would need to go through? In others, it wouldn't delay the spending of the CapEx.

This is Maureen. Yes, that's is correct. I mean, the encouraging news about the ALJ order is that they completely endorse the need for the project and said that Illinois River is the best approach. So really, this issue with regard to the substations and the remaining 2 line segments is about where they should be, not whether or not they're needed. So yes, we would move out on the segments and the stations that have been approved and then would work through the issues with regard to the routing of the remaining segments and stations. It would not impact the CapEx plan.

Our next question comes from the line of Stephen Byrd with Morgan Stanley.

It's actually Rajeev Lalwani on Stephen's team. I just have a question on a comment you made in Missouri, the cost referral that you're seeking relating to Noranda, is that kind of a one-time thing or will that carry forward?

Rajeev, this is Warner Baxter. This would be really kind of a one-time thing. The event was the loss fixed cost resulting from the ice storm and so it would be a one-time event. And so the commission is in the county authority order and then if we'd be granted that county authority ordered, then we would seek to put the commission's decision into rates during our next rate case.

Okay. And the other question was on Illinois. As we see the 30-year treasury go up, why is that not impacting your expected earnings for the business? Or is it too small to have much of an impact?

Yes. No, it is embedded in there. So we have seen the 30-year treasuries rise this year, but it is having -- it's up, I guess, about 30 basis points from where we started our guidance at the beginning of the year and 30 basis points for this year is about $0.015. So that is embedded in the overall guidance. If you look at the guidance we've provided, and I think somebody did this last time, took a $2 to $2.15 range and then added back the parent and other of $0.20 to get to a midpoint of a range around our regulated earnings, which gets you to about $2.27 or $2.28, somewhere in that range. We started the year with regulated earnings expectations of $2.25. After the first quarter, we raised it to a midpoint of about $2.30 and again, there's a range around these numbers. We didn't have anything specifically and therefore the $0.06 FAC charge, frankly, as Warner said earlier, could have gone either way, been a $0.06 charge or a $0.04 upside. The fact that we have this $0.06 charge is the reason that we're bringing down the upper end of our range from $2.20 to $2.15. But my point is that we brought down that midpoint only $0.02 or $0.03. Based on that charge, we're seeing a little bit of upside from the -- from those 30-year treasuries, and we're also controlling our cost to help offset some of that. And bottom line, it's steady as she goes in terms of regulated earnings for this year. We've been between that $2.25 and $2.30 midpoint, we're still there even after this FAC charge at about that $2.27 to $2.28 range. So those are some of the things that we're incorporating. We had a Callaway refueling outage in the second quarter. The result of that as we've shared in our talking points, it was $0.08 for the quarter, $0.09 for the year, right in line with the guidance we provided earlier in the year. So all in all, it's -- we're -- things are in line through 6 months.

Just another follow-up question on Illinois. In terms of the new legislation there, it seem like it didn't have much of an impact on your numbers. Can you just talk about why that is? And I was under the impression that it will improve the delta between earned and the lag going forward.

Yes, you're asking about the Illinois Electric in particular?

Yes, sorry.

Yes. So the reason it didn't have a -- really, a big impact on this year is that it will have a positive impact going forward. So Tom went through some of the things that are underscored which is use of the year end rate base, the actual year end cap structure, as well as in weighted average cost to capital returns on deferrals. One of the things in our talking points we did talk about is that coming out of the first year of the use of the legislation, there's actually a deferral that is actually a liability back to the customers. And so, when you look at the weighted average cost of capital return on that, that is actually an incremental obligation which mitigates the positive impact of the other 2 items, the year end rate base and the actual cap structure. So for the year, it was a bit of a neutral. As we go through time, this is what was in our talking points, we go through time and we deploy the capital in order to improve the infrastructure, create the jobs per the Act, we expect those deferrals to be actually regulatory assets and would expect them to -- the weighted average cost of capital returns on those. So this year, it kind of netted out to not really having much of an impact. But going forward, those fixes to the legislation are necessary and will be positive overall.

Our next question comes from the line of Ashar Khan with Visium.

My question has been answered.

Our final question comes from the line of Michael Lapides with Goldman Sachs.

Just coming back to Ameren Illinois real quick. I want to make sure I understand, we've seen this with Commonwealth Edison, what is the amount of -- on the electric side of items of cost that the commission does not include in the formula rate process. Meaning, that creates a little bit of structural earnings -- structural underearning. I don't think it's a huge number, but when you think about kind of going for 2014, 2015 and beyond.

Yes. Michael, I wish I had that in front of me. We went through some of this, actually, coming out of our year end call and perhaps Doug can find the slide. What we did coming at year end, we gave our guidance for this year. So we actually laid out some of the items that actually we expected to cause some under earning this year. Actually Doug wasn't able to pull that out. The things we laid out at that time, Michael, were about $8 million of ICC ratemaking adjustments. Those are things that unless we're able to find some other way to mitigate those or to get recovery, those would be sort of recurring. We laid out, and this was back -- it was in Slide 13 by the way in the year end call, we made about $7 million of electric system rework that we plan to do and are doing this year, and that would not be recoverable. However, while those costs were incurred this year and last year, we don't expect that those costs would be sort of going-forward cost. We believe that, that rework is largely behind us after this year. So we'd not expect that to continue to be a driver of underearning. And then, with the $1 million this -- we have this year, it was greater last year, we had $1 million this year of required donations under the formula rates, and of course, we continue to make those donations going forward and those are nonrecoverable. So I think what we laid out there was about $60 million or so of items impacting us this year, both the expectation that, that would go down to maybe in the $9 million range next year. And so that's sort of the guidance we provided.

Got it. So when investors think longer-term about the Illinois Electric business, should they basically think, look, on the distribution or delivery side, you're likely to -- there's nothing structural that keeps you -- that keeps the rate base math from happening. Meaning kind of taking an end of year rate base multiplying times whatever the equity layer is and then just taking the 30-year treasury plus 580 bps. And then maybe subtracting out those structural items you just -- the nonrecoverable items you just talked.

Yes, Michael, that's right. You should look for it. It should be -- it should work formulaically as -- obviously, when we got started last year with these reviews, there were certainly some debate around some of these historical ICC ratemaking adjustments or how the law would be implemented. Those historical ICC ratemaking adjustments will continue per the law. We believe we've gotten clarity from the legislature in terms of the some of the issues that were debated with the ICC. But generally, you're right, Michael, we should have rate base growth going forward. The ratemaking should work formulaically as designed. And as the 30-year treasury, say, if they do rise, then that will impact the overall return. And I think, next year, I think that blue chip consensus forecast we use right now, it's at 3.95, which would imply for next year if that held through a 9.75 return in the Illinois energy delivery space.

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

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

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