阿莫林 (AEE) 2013 Q2 法說會逐字稿

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

(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 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 factor sections in our filings with the SEC.

Tom will 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 is Tom, who will start on page 3 of the presentation.

Thanks, Doug. Good morning, and thank you for joining us. Today we announce 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 the 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, 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 of 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 earnings 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 costs, including certain costs that were previously allocated to the merchant generation business.

Turning to page 5, we remain committed to closing the 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 are working diligently with Dynegy to complete the transaction and continue to anticipate a fourth-quarter 2013 closing. Requests 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 unit, or IPH, and our merchant generation subsidiaries requested that the Illinois Pollution Control Board grant IPH the same variance in the Illinois multi-pollution standard that was granted to Ameren Energy Resources in 2012. We expect the variance to be granted, and the Board has until late November this year to issue a decision. Regarding the FERC filing for divestor approval, last Friday FERC requested copies of Ameren Energy Marketing's long-term wholesale contracts with two entities, both of which have intervened at FERC. Ameren Energy Marketing entered into these contracts under its market-based rate authority, therefore we do not 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 three gas-fired energy centers we retained with the exercise of the Genco put option are progressing. We have short-listed 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 am 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 missed applications, the Illinois General Assembly overwrote Governor Quinn's veto and enacted Senate Bill 9.

This statute 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 statute requires the use of weighted average cost of capital -- not a short-term interest rate -- for computation of annual revenue requirement referrals. 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, and investments grow in the coming years. Further, Governor Quinn signed the Natural Gas Consumer Safety and Reliability Act in July of 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 advance 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-based revenues. Ameren Illinois expects to participate in this rate-making 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 and Missouri, we also remain committed to enhancing Missouri regulatory framework to better support investment and that state's energy infrastructure. We are 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, who 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 will 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, for quality of service we can provide to our customers, and the return opportunities we can provide to our investors.

Before I conclude my comments on our Missouri utility, I want to mention a recent operational development. Last Friday, with -- 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 also caused a small fire in the turbine building, which is located in a non-nuclear 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 tests 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 a five-year period ending in 2017, are a key part of Ameren's business strategy. These projects will benefit customers by providing a more reliable and efficient electric system and 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 and recover our costs on a timely basis.

Our single largest plan transmission investment is Ameren Transmission Companies of Illinois, Illinois River Project. This approximate $1.1-billion MISO-approved regional multi-value project, involves the construction of a new high-voltage transmission line across the state of Illinois. Our request for a certificate of public convenience, a 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 ALJs 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 ALJs recommended that a majority of the Illinois River Project, seven of nine segments, be granted the requested certificate. We comprehensively responded to the questions raised by the ALJ's regarding the location of two of the nine 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 remain 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, instructive, 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. This 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 included expenses related to a planned Callaway Energy Center refueling and maintenance outage, which reduced earnings by $0.08 per share. Because Callaway is refueled approximately every 18 months, there was no refueling outage or associated expenses in 2012. In addition, our 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%. 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 of 2013, which combined increased 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 have 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. The 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 of 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 costs 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, the 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 divestiture-related cash outflows of approximately $100 million, including the $25 million of cash that is currently held at Genco. These divestiture-related cash outflows are more than offset by expected transaction-related cash tax benefits of approximately $180 million in present value to be substantially realized in 2015.

Moving to page 13, I would like to update you on Ameren Illinois' two 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 interveners 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 (sic - see slide 15) 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. Divestiture allows us to focus exclusively on our rate-regulated utilities.

In addition, we remain 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 five-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.

We will now be conducting a question and answer session.

(Operator Instructions)

We ask that you please limit your time to one question and one follow up as necessary.

(Operator Instructions)

Paul Patterson with Glenrock associates.

I wanted to ask you about the FERC Office of Energy Market request for additional information. It looked like, I guess they want some more information -- at least partly -- because of market power and also, I was just wondering what you thought about any potential schedule impact or just what you could tell us more about the interplay with that and getting these plants sold.

Yes, sure, Paul. So you're right. Last week, the FERC did have a call data request but they did ask for additional information with respect to a couple things. They asked for contracts that we have with two 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 do not expect that the additional information they have 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 you know 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 certainly 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 get FERC approval and close the transaction by year-end.

Okay. I know you guys are obviously planning on selling plants, but any thoughts just about, sort of, the RPM auction and the ability going forward -- next year's auctions -- with respect to the potential of sell capacity into PJM just seen some issues what have you, any follow-up 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 are still working for them. I was just wondering if you had any thought about that.

Paul, I wouldn't say I have any specific thought with respect to the auction for next year. As you know, this business segment that we are divesting of was successful in getting the ability to sell additional capacity into PJM and periods beyond really the '14 timeframe looking out to post-'16. 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.

Okay. Good work. Thanks a lot, guys.

Thank you.

Julien Dumoulin-Smith with UBS.

Hi. Good morning. Can you hear me?

Yes. Good morning.

Excellent. Perhaps, first just going back to kind of the merchant business if you will, entertain me for one second, I would be curious if any of the latest regulations kind of change the landscape at all? [1-hour SO2] recently, Illinois [draft cohosh rules] were recently released. Does that change anything as far as you're concerned?

No it doesn't. You know 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 you know Julien, while we're certainly monitoring conditions and frankly that business segment that we're selling continues to operate well and perform well, but you know it's obviously a strategic decision to exit the business.

Excellent. 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 to, perhaps a more of a diluted approach. Have you put any thought to that next year?

Julien, this is Warner Baxter. The simple answer is, of course, we are looking at all kinds of options as we look forward to legislation for next year. Certainly there is 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 on the floor. Those are potential options. There are certainly options for even a skinnier version.

What we are going do and what we have been doing and will continue 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. That's what we'll do. We'll continue to work with our key allies in Missouri, including all the other electric energy providers, to try and craft an appropriate approach forward.

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

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

Great. Best of luck.

Sure. Thank you.

(Operator Instructions)

Next question comes from Andy Bischoff with Morningstar.

Good morning. Just a real quick question. When would you expect for a ruling after you supplied additional information by August 9?

This is Marty again, Andy. It's hard to know exactly when they would respond. There is no specific time line. Once we got about 180 days, frankly to respond and then 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 would certainly expect again to get the FERC approval and be able to close by year-end.

You know, of course there is another filing that's been made at the Pollution Control Board and there the timeline's about 120 days. So in both cases, we expect to get the Pollution Control Board approval for the air variance transfer as well as FERC approval for the sale in time still to be able to accomplish a closing before year-end.

Thank you. Moving to low trends, I guess during the quarter we have seen weakness in competitor low trends. Can you just provide a little more color on the trends you are seeing across your customer base?

Yes, sure, I will be happy to comment on that. You know, this year we've seen a bit of variation, very much like we saw last year. You know the weather-normalized sales started out pretty strong in Q1 but again, like last year, had 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%. You know we said at the end of each of the last two quarters that -- in terms of our 2013 guidance, we expected little in the way of growth. Like I said, residential and commercial sales across our utilities are up about 0.5%. That's what we are 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 a -- 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 are 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 and job growth, both in goods producing and services jobs. Housing starts have been on the rise a little bit. Our customer counts are up, year-over-year in both residential and commercial residential, up about 0.4%, commercial about 0.7%. We're seeing some good trends, that give us confidence of the 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.

Thanks for the clarity.

Sure.

Ian Jenkins with Wisconsin Investment Board.

Hi. This is Dan Jenkins. I wonder if you can give me a little more background on this appellate court decision on the FAC in Missouri, and then just what the basis was for the decision and then if that will have any impact on how your FAC operates going forward?

Sure, Dan, maybe Warner, President of Missouri operations, will take that one again.

Hi Dan. How are you doing?

Good.

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 be provided back through our fuel adjustment clause like many other off-system sales are under the existing rules. 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.

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 of '09 to September of '09. We indeed recorded that back in 2011. That's pretax charge. That did not take those contracts to their full duration. Those contracts went further. So in 2012, the staff - Missouri Public Service Commission staff -- recommended additional refund of about $26 million related to the same wholesale contracts. That was from the period from October 2009 to May 2011, whereas the first one was for March 2009 to September 2009. That was the period under review.

In 2012, just to give you history so you know, we actually ended up winning our appeal of the Commission's order before the Cole County Circuit Court, but later in 2013 -- which is the appellate court decision that Marty referenced -- Missouri Court of Appeals upheld Missouri Public Service Commission's position. 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. While we're disappointed with the Commission's decision we certainly weren't surprised given recent appellate court decision.

So really, as we go forward, we will continue to operate under the provisions of the Missouri Adjustment Clause. We will, to the extent that we go forward, we do not have an issue because we do not have similar types of wholesale contracts going forward. We'll just continue do the off-system sales, as we do today, and we'll provide 95% of those margins back through the Field Adjustment Clause. The one thing that you should know, during all this period of time, that we actually did file another or initiate another proceeding in the state of Missouri. This goes back to July of 2011 but we filed a request with the commission for an Accounting Authority Order that will allow Ameren Missouri to defer as a regulatory asset, really the fixed cost of 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 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 lost load. A bit of a long story, but that gives you the history of what's going on with the Field Adjustment Clause and where things stand today. 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 do not intend to appeal that under the Supreme Court, their appellate?

No, the appellate with the Supreme Court, no we do not intend 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 a 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 do not currently have anything filed, but you have talked in the past about being more regular rate case schedule. Should we expect something coming up in the next few months?

You know, Dan, we haven't made any final decisions as to when we'll file next rate case. Just as we have done in the past, we will seek to try and find our next case to mitigate regulatory lag. That's regulatory lag resulting from meaningful capital additions as well as mitigating regulatory lag for operating costs. 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 editions that we have coming before us in a variety of different areas -- not just in '13, but in '14. A final decision hasn't been made but we keep a very close eye on all these things in terms of when we'll next file rate case.

Okay. Last thing I had is you had a slide show on the cash flow and the fact that it will be negative. I was just wondering if you can update us on 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, nothing really in terms of short-term debt at this point, we have good liquidity. What we'll be looking at this year is some of the maturities that I believe we talked to you about last quarter, that we have coming up both in Missouri and Illinois. We have negative cash flow 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-based 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 or so of next year. 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 come up in May of next year, May of '14. Certainly we've got the opportunity there, as we have talked about before, to significantly lower the interest rate at the parent company, for the parent company debt.

Dan, while I've got you -- one thing I want to tack onto Warner's thing that is important is the charge we took relative to the FAC when we had a similar one in the prior period, but those are fully behind us, those sales that were in question happened during a finite period of time that 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 one-time 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.

Okay. Thank you.

Steve Fleishman with Wolfe Research.

Hi Tom and Marty. So listen, on Illinois Rivers, just agree that the ALJ recommendation was adopted largely as is. How much of an impact might it have on the CapEx for that project? Obviously there were some segments.

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

Good morning. 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. Then we would need additional clarity on the remaining two 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 is 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. 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 probably have another proceeding that was a follow onto clarify the remaining issues. We are 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 the 20th. Does that answer your question?

Okay. Yes, that's very helpful. I think on Dynergy'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 transmission 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've continued to work with the midwest ISO and with Dynergy 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 perimeters 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 are certainly 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 had mentioned that there was going to be kind of a board retreat in June, response to a question on dividend strategy and dividend growth. Anything come out that in terms of thinking on dividend strategy and even just how the Company looks once this generation transaction's completed?

Sure. We did have what I would view as a very 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 are totally supportive with that approach. They're very much in favor of us, as we grow earnings, as we grow rate base and grow earnings that we would also grow the dividend over a period of time.

Okay. Thank you very much.

Kevin Fallon with SIR Capital Management.

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

Hi Kevin. This is Warner Baxter.

Hi.

You know you look at regulatory lag in Missouri, it's driven by a couple things. Number one, it's driven by the fact that they use historical test-year principally to set rates and another big driver is that when capital investments are placed into service between rate cases, there is not an ability to update rates for those major adjustments. So what we have been doing as a Company, is that we have been working very hard and have had success in better aligning our spend across our enterprise both capital and O&M to be more consistent with the regulatory framework we have in front of us in the state of Missouri. So we have been able to manage that. 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.

What we've been very focused on is narrowing that gap between the allowed return on equity provided by commission and what actual earned return on equity has been. We have been able do that over the last several years pretty successfully. So I wouldn't say there is a magical number or a magical time frame. We just know that we're going to manage our operations in a manner that's consistent with that and keep a fairly narrow gap. 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 is too fine a point. We'll do what we think is right for the business, what we think is right for shareholders. That's when we'll file rate cases as well. 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. Bottom line we're trying to create a win-win for everybody.

Okay. In terms of financing plans, as we look over the next couple years you have a big CapEx build up. Can you give some color in terms of the need for equity or target capital ratios for a consolidated firm?

Sure. This is Marty again. You know we've provided these over time. I think we'd look to keep the equity content and 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. You know 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.

You know, largely, we believe that will be funded by the reinvestment of retained earnings as -- from the earnings we've got in the business and growth of earnings going forward, you know, coupled with debt financing to the extent that we needed some supplemental equity -- which we're not issuing any currently, but we have the ability to turn our drip to 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 a last question. I just want to confirm that if the ALJ position is upheld on Illinois river's project, that even if you have to seek a second proceeding to get the full amount of the substations and lines completed, that 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 other words, it won't delay the spending of the CapEx.

This is Maureen. Yes, that's correct. The encouraging news about the ALJ order is that they completely endorse the need for the project and said that Illinois Rivers is the best approach, so really this issue with regard to the substations and remaining two 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 CapEx plan.

Thank you very much.

Steven Berg with Morgan Stanley.

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

This is Warner Baxter. This would be really kind of a one-time thing. The event was the lost fixed cost resulting from the ice storm. So it would be a one-time event. So the Commission that's in Accounting Authority Order and then if we would be granted, that order 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 have seen the 30-year treasury go up why is that not impacting your expected earnings from the business or is it too small to have much of an impact?

Yes. It is embedded in there so you know we have seen the 30-year treasuries rise this year, but it is having, it is 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 That is embedded in the overall guidance.

You know, if you look at the guidance we've provided and think somebody did this last time, took our $2.00 to $2.15 range and added back the parent and other of $0.20 to get to a midpoint of a range around our regulated earnings, which gets you it 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. Again there is a range around these numbers. You know we didn't have anything specifically and therefore the $0.06 FAC charge frankly as Warner said earlier could have gone either way. A $0.06 charge or a $0.04 upside. The fact that we had the $0.06 charge is the reason we're bringing down the upper end of our range from $2.20 to $2.15. 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 30-year treasuries and we're also controlling our costs to help offset some of that. Bottom line it's steady as she goes in terms of our regulated earnings this year. We've been between that $2.25 and $2.30 midpoint. We're still there, even after the FAC charge, about that $2.27 or $2.28 range. Those are some of the things incorporating. We had a refueling outage in the second quarter. Result of that as we 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 things are in line through six months.

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

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

Yes, sorry.

The reason it didn't have a really 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 or capital returns on deferral's. One of the things in our talking points we did talk about is that, you know, coming out of the first year of the use of the legislation, there is 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, you know that is actually an incremental obligation which mitigates the positive impact of the other two items, the year-end rate base and the actual cap structure. For the year, it was a bit of a neutral.

As we go through time -- and this was in our talking points -- as we go through time and we deploy the capital in order to improve the infrastructure to create the jobs per the act we expect those deferral's to be actually regulatory assets and would expect them to the weighted average cost to 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 legislature are necessary and will be positive overall.

Great. Thanks. Sorry I missed that in your talking points.

No problem.

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

My question has been answered. Thank you so much.

Thank you.

Michael Lapides with Goldman Sachs.

Coming back to Ameren Illinois real quick, I want to make sure I understand we have seen this with Commonwealth Edison. What is the amount of -- on the electric side of items, costs that the commission does not include in the formula rate process, meaning that creates a little bit of structure earnings, structural under earning. I don't think it's a huge number, but when you think about kind of going forward 2014, 2015 and beyond.

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. Coming out of year-end we gave our guidance for this year we actually laid out some of the items that actually we expected to cause some under earning this year. Actually Doug was able to pull it out. The things we laid out at that time, Michael were about $8 million of ICC rate making adjustments. You know, those are things that unless we are able to find some other way to mitigate those or to get recovery those would be sort of recurring. We laid out -- this was in slide 13 by the way -- in the year-end call, we had about $7 million of electric system rework that we planned 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 costs. We believe that, that rework is largely behind us after this year. So would not expect that to continue to be a driver of under earning. And then the $1 million we had this year it was greater last year. We had $1 million this year of required donations under the formula rates. Of course we continue to make those donations going forward and those are non-recoverable. I think we laid out there was about $60 million or so of items impacting us this year, but with the expectation that, that would go down to maybe in the $9 million range next year. So that's sort of the guidance we have provided.

Got it. When investors think longer-term about Illinois Electric business should they basically think -- look on the distribution or delivery side, you are likely to, there is nothing structure that keeps rate based math from happening meaning taking an end of year rate base multiplying whatever the equity layer is and then just taking 30-year treasury plus 580 BIPS and then maybe subtracting out those non-recoverable items.

Yes, Michael, that's right. You know as you look forward it should work obviously as we got started last year with these reviews, there were certainly some debate around some of these historical ICC rate making adjustments or how the law would be implemented. You know those historical ICC rate making adjustments will continue per the law. We believe we've gotten clarity from the legislature in terms of some of the issues that were debated with the ICC. But generally, you are right Michael. We should have rate based growth going forward. The rate making should work from likely as designed and as a 30-year treasuries, if they do rise, then that will impact the overall return. I think next year, that blue chip consensus forecast we use right now is 3.95 which would apply for next year if that held true, a 9.75 return in the Illinois Energy delivery base.

Got it. Thank you Marty. Much appreciated.

You're welcome.

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. Excuse me. Let me remind you again that this call is available for one year on our website. You may also call the contacts listed on the release, financial analyst inquiries should be directed to me, Doug Fischer, or my associate Matt Thayer. Media should call Joe Mullencamp. 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.