阿莫林 (AEE) 2014 Q4 法說會逐字稿

Greetings and welcome to the Ameren Corporation fourth-quarter 2014 earnings call. At this time, all of the participants are in a listen-only mode. A question-and-answer session will follow the formal presentation.

(Operator Instructions)

As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Mr. Doug Fischer, Senior Director of Investor Relations for the Ameren Corporation. Thank you, Mr. Fischer. You may begin.

Thank you and good morning. I'm Doug Fischer, Senior Director of Investor Relations for Ameren Corporation. On the call with me today are Warner Baxter, our Chairman, President, and Chief Executive Officer; and Marty Lyons, our Executive Vice President and Chief Financial Officer, as well as other members of the Ameren management team.

Before we begin, let me cover a few administrative details. This call is being broadcast live on the internet, and the webcast will be available for one year on our website at ameren.com. Further, this call contains time-sensitive data that is accurate only as of the date of today's live broadcast, and redistribution of this broadcast is prohibited.

To assist with our call this morning, we have posted on our website a presentation that will be referenced by our speakers, who will use terms or acronyms -- who may use terms or acronyms that are defined in the presentation. To access this presentation, please look in the investor section of our website under webcasts and presentations and follow the appropriate link.

Turning to page 2 of the presentation, I need to inform you that comments made during this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those about future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance.

We caution you that various factors could cause actual results to differ materially from those anticipated. For additional information concerning these factors, please read the forward-looking statements section in the news release we issued today and the forward-looking statements and risk factors sections in our filings with the SEC.

Warner will begin this call with an overview of 2014 results and our outlook for 2015 and beyond. Marty will follow with a more detailed financial and regulatory update. We will then open the call for questions.

Before Warner begins, I would like to mention that all per share amounts discussed during today's presentation, including earnings guidance, are presented on a continuing operations and diluted share basis, unless otherwise noted. Now here is Warner who will begin on page 4 of the presentation.

Thanks, Doug. Good morning, everyone, and thank you for joining us. Today, we announced 2014 earnings of $2.40 per share, within the upper end of our 2014 guidance range. This represents a 14% increase over 2013 results.

This strong earnings growth reflected increased Illinois Electric delivery and FERC-regulated transmission earnings under formula rate-making, which were driven by infrastructure investments made to better serve our customers. The earnings comparison also benefited from increased rates for Illinois natural gas delivery, decreased interest charges, the substantial elimination of parent Company costs previously allocated to the divested merchant generation business, and the absence of the Missouri fuel adjustment clause-related charge taken in 2013. Marty will discuss these and other 2014 earnings drivers in a few minutes.

Turning to page 5. Last year at this time, we discussed how excited we were about our strategy for investing in and growing our rate-regulated electric and gas utilities in order to provide superior value to our shareholders and customers. Today, I am pleased to report on our successful execution of this strategy in 2014.

The first element of our strategy is to invest in and operate our utilities in a manner consistent with existing regulatory frameworks. Towards this end, in 2014, we allocated significant amounts of discretionary capital to those businesses where investment is supported by regulatory frameworks that provide fair, predictable, and timely cost recovery.

Our customers are seeing tangible results from these investment activities. In particular, we invested more than $1 billion in our FERC-regulated transmission and Illinois electric and natural gas delivery infrastructure to better serve our customers.

Ameren Transmission Company of Illinois, or ATXI, began construction of the Illinois Rivers project and achieved all planned 2014 milestones. Land rights were obtained for approximately half of the properties along the project's route, construction was begun on 6 of the 10 substations, and nearly all of the foundations on an initial line segment were completed.

In addition, Ameren Illinois installed almost 47,000 new electric and 26,000 upgraded gas meters, exceeding the first-year goal of its advanced metering infrastructure project.

Further, Ameren Missouri placed into service several key infrastructure projects by year end, including the new reactor vessel head at the Callaway Energy Center, additional environmental controls at the Labadie Energy Center, a major substation in St. Louis, and the largest investor-owned solar generation facility in the State. These projects are already serving customers, improving reliability, and providing energy from cleaner generation sources, and they are eligible for inclusion in new rates expected to be effective by early June of this year.

We also achieved notable regulatory successes last year, including a constructive outcome in our Illinois electric delivery rate case. In this case, the Illinois Commerce Commission authorized a rate increase of $204 million, an amount that was within $1 million of our updated request, demonstrated that the formula ratemaking framework is working as intended.

Even with this rate increase, rates are still expected to remain below 2011 levels for most customers. Finally, we remain relentlessly focused on operational improvement and disciplined cost management, as reflected in the significant reduction in parent Company costs.

The second element of our strategy is to enhance regulatory frameworks and advocate for responsible energy policies. On this front, the Illinois General Assembly overwhelmingly passed legislation extending the constructive formula-based electric delivery rate framework by two years through the end of 2019. This legislation has now been submitted to Governor Rauner.

Further, we aggressively advocated for responsible energy policies, notably in the environmental area. In particular, we raised concerns regarding the impact on customers' rates and electric liability of the Environmental Protection Agency's proposed Clean Power Plan.

But we did more than just raise concerns; we offered pragmatic solutions to address these important concerns in our comments to the EPA's proposed rules in December. The EPA is expected to finalize its rules later this year.

Regarding the third element of our strategy, creating and capitalizing on opportunities for investments for the benefit of our customers and shareholders, I will highlight three areas of activity. In October, we filed an updated integrated resource plan with the Missouri Public Service Commission, outlining our ongoing transition to a cleaner and more fuel-diverse generation portfolio in a responsible fashion for the next 20 years.

This plan maximizes the use of our current coal-fired generation fleet for the benefit of our customers, while leveraging energy efficiency and investments in renewables, environmental controls and gas-fired generation to meet future needs in an environmentally balanced manner. And the plan also includes extending the useful life of our Callaway Nuclear Energy Center from 40 to 60 years.

Our preferred plan is also projected to achieve the ultimate carbon emission reductions proposed by the EPA in its Clean Power Plan by 2035, rather than the EPA's final target date of 2030, or its aggressive interim target dates beginning in 2020. Importantly, our plan will significantly reduce reliability issues and economic costs of the Clean Power Plan for our customers, while still achieving significant carbon emission reductions.

Next, our transmission team continues to identify reliability projects that are important for customers here in our service territory, while pursuing additional competitive investment opportunities, both here and beyond, as we work to leverage our success as an experienced transmission developer and operator. Finally, we will continue to move forward in executing our Illinois monetization action plan, or MAP, for upgrading our electric and natural gas delivery systems.

Turning now to page 6. In summary, the successful execution of our strategy last year delivered positive results for both our customers and shareholders. On the operating front, it was another year of solid safety performance, as well as strong electric distribution system reliability and base load energy center performance. In addition, our electric rates remained well below regional and national averages, and customer satisfaction improved.

Moving to financial performance, we delivered strong earnings growth in 2014, as I previously mentioned. Ameren as a whole also earned a higher return on equity. Further, the Board of Directors expressed confidence in our long-term outlook, by increasing our quarterly dividend while we maintain financial strength and flexibility. I am pleased with the progress we made last year and we are continuing the momentum into this year.

Turning now to page 7, we anticipate that 2015 will be another year of solid earnings growth, with results expected to be in a range of $2.45 to $2.65 per share. The primary growth drivers are noted on this page, and Marty will discuss them in more detail in a few minutes.

Turning to page 8, here we note key areas of focus for this year as we continue to execute our strategic plan. Our FERC-regulated transmission businesses will advance the regional multi-value and local reliability projects included in our 2015 through 2019 capital investment plan.

Further, our transmission team continues to pursue projects that enhance the reliability, safety, and efficiency of the grid in our service territory, in MISO and in neighboring regional transmission organizations, including competitive opportunities under FERC Order 1000. In addition, we are working to obtain constructive outcomes in the complaint cases pending at the FERC that seek to reduce the base allowed return on equity for transmission owners in the MISO region, including Ameren Illinois and ATXI.

On the matter of allowed returns, I am pleased to note that effective January 6th of this year, the FERC approved our request for an ROE incentive adder of up to 50 basis points for both Ameren Illinois and ATXI to reflect our participation in a regional transmission organization.

Moving to Illinois electric and natural gas delivery, Ameren Illinois will carry on investing in infrastructure improvements under its modernization action plan, which is designed to extend through 2021. This plan includes the installation of approximately 780,000 advanced electric meters and the upgrading of approximately 470,000 gas meters by the end of 2019, including approximately 140,000 electric and 73,000 gas meters this year.

To support the execution of our modernization plan, we are working to ensure that legislation extending electric formula rate making through 2019, which I already discussed, becomes law.

Regarding our Illinois natural gas delivery service, last month we filed a request with the Illinois Commerce Commission for an increase in rates to be effective at the beginning of 2016. In Illinois, we were able to use a forward test year to establish rates in our gas business in order to mitigate regulatory lag. Successfully advancing this request through the regulatory process will be a key area of focus this year.

In addition, we began using the Illinois gas infrastructure rider last month. This rider facilitates needed projects to upgrade aging infrastructure, which will improve reliability and safety for our customers while providing timely recovery of and returns on our investments.

Moving now to our Missouri business, we are working diligently to achieve a constructive outcome in our pending electric rate case. As we reported in our Form 8-K filed last Friday, we learned of an inadvertent disclosure of settlement offer exchanges among Ameren Missouri, Missouri Public Service Commission staff, and intervenors in the pending electric rate case.

The disclosure arose as a result of the distribution of an incorrect e-mail list that included individuals not authorized to receive confidential settlement proposals. The e-mail list was corrected immediately upon discovery of the error, and appropriate actions were promptly taken under Regulation FD. Any further settlement negotiations have been and will continue to be private among the appropriate parties.

As you know, the hearings in the case commenced on Monday of this week. Marty will provide you with some more information on this case in a moment.

Modernizing Missouri's regulatory framework also remains a high priority. We are seeking a framework that reduces regulatory lag and supports increased investment to upgrade the state's aging electric infrastructure. Toward that end, we continue to educate key Missouri stakeholders, including several freshman legislators and advocate for legislation that would improve the regulatory framework to support investment.

Legislation has been filed in the Missouri Senate and House of Representatives that is consistent with legislation filed in 2014. It is simply premature at this point to speculate whether this legislation will move forward and be enacted.

As we have stated in the past, the execution of our plan is not contingent on the passage of legislation in Missouri. Having said that, we strongly believe a modernized framework that supports investment to replace aging infrastructure is clearly in the best long-term interest of our customers and the State of Missouri.

Speaking of modern, constructive regulatory frameworks, we have asked the Missouri Public Service Commission to approve a new energy efficiency plan under the Missouri Energy Efficiency Investment Act, or MEEIA. This plan would begin in 2016 and continue through 2018, and would follow on the heels of our successful current energy efficiency plan. We expect to receive a decision on this request later this year.

Earlier, I discussed our advocacy for responsible energy policies related to the proposed EPA carbon emission rules. We do so because we simply believe it is the right thing to do for our customers, our country, the environment, and our shareholders.

And to be clear, should the EPA's final regulations withstand the legal challenges it will certainly face and ultimately require us to reduce our carbon emissions in a manner different from our current plan, we expect that our prudent investments to comply with these regulations will be fairly treated by our regulators, as they have been in the past. Finally, we will continue our ongoing efforts to relentlessly improve operating performance, including disciplined cost management.

Moving on to page 9 and our long-term total return outlook. A year ago, we laid out a comprehensive plan to grow earnings over the five-year period ending in 2018. Today, we are pleased to reaffirm that outlook as we continue to expect earnings per share to grow at a 7% to 10% compound annual rate from 2013 through 2018.

Like last year, this earnings growth outlook accommodates a range of Treasury rates, sales growth, spending levels, and regulatory developments. That said, our earnings growth outlook is primarily driven by strong rate base growth.

Looking to the five-year period 2014 through 2019, we expect rate base to grow at a solid 6% compound annual rate. We have a strong pipeline of investments that will bring superior value to our customers and shareholders over the next five years and beyond. Those investments include strengthening our electric distribution system and installing electric and gas smart meters, consistent with the 10-year Illinois modernization action plan.

In addition, we will make meaningful investments in our Illinois gas business to upgrade its metering equipment, while also replacing and modernizing certain mains, lines, and controls to ensure safety and reliability. We will also execute on an extensive list of local transmission reliability projects, while competing for FERC Order 1000 projects.

And in Missouri, we will make disciplined investments to replace aging transmission and distribution infrastructure, while continuing our transition to a cleaner, more diverse generation portfolio in a responsible fashion. These will include investments necessary to maintain the reliability of and add further environmental controls to our existing coal-fired energy centers. It will also include the addition of renewable resources.

Looking ahead, we will also remain focused on our dividend, as we recognize the importance of our dividend to our shareholders. The action our Board of Directors took to increase the dividend last October was indicative of this, as well as the confidence we have in a long-term outlook of our regulated utility businesses.

We continue to expect our dividend payout ratio to range between 55% and 70% of annual earnings. Of course, future dividend increases will be based on consideration of, among other things, earnings growth, cash flows, and economic and other business conditions. And as I stated a moment ago, we are focused on delivering strong earnings growth as we execute our well-defined strategic plan.

In closing, we are successfully executing our strategy across the board, and I am firmly convinced that continuing to do so will deliver superior value to both our customers and our shareholders. Again, thank you all for joining us on today's call, and I'll now turn the call over to Marty.

Marty?

Thanks, Warner. Turning now to page 11 of our presentation, as Warner already noted, today we reported earnings of $2.40 per share for 2014, compared to $2.10 per share for 2013.

Key drivers of this increase are listed on this page. Factors favorably affecting the earnings comparison included increased Illinois electric delivery and FERC-regulated transmission earnings totaling $0.11 per share. And I will note that this amount is net of a reserve for a potential reduction in the allowed return on equity for our FERC-regulated transmission businesses.

The reserve stems from the pending complaint cases at FERC which have the potential to reduce the current 12.38% base allowed ROE for these services. Our reserve calculation assumed the FERC will use a methodology similar to that used in its 2014 order for ISO New England. Further, this reserve reflected an ROE reduction retroactive to November 2013, when the initial complaint case was filed.

Other factors positively affecting the comparison of 2014 earnings to prior-year results included increased rates for Illinois natural gas delivery service, effective January 2014, as well as decreased interest charges. The latter reflected the May 2014 maturity of high coupon parent Company notes, which was funded with lower cost, short-term debt. Interest charges also declined as a result of a December 2014 Illinois regulatory decision, allowing recovery of the majority of debt redemption costs initially disallowed and charged to earnings in 2013.

In addition, the absence of the 2014 charge related to Missouri FAC treatment of certain prior-period wholesale sales had a positive impact on the earnings comparison. Finally, temperatures had an estimated $0.01 per share positive effect on earnings compared to 2013, as a colder winter in early 2014 was largely offset by a milder summer.

Factors having a negative effect on the earnings comparison included increased depreciation and amortization expenses and a higher effective income tax rate. In addition, operations and maintenance costs not subject to formulaic ratemaking, riders, or trackers increased year over year. While such operations and maintenance expenses increased at our utilities as a result of our efforts to improve service to our customers, these increases were partially offset by lower parent Company costs, reflecting the substantial elimination of business and administrative costs previously incurred to support the divested merchant generation business.

Before I conclude my discussion of 2014 earnings, I would like to touch on electric sales results for the year. We estimate that weather-normalized kilowatt hour sales to residential and commercial customers increased nearly 1% in Illinois, but declined by nearly 1% in Missouri; however, we calculate that these sales would have increased about 0.05% in Missouri, excluding the effect of our energy efficiency programs.

In Missouri, the earnings impact of reduced electric sales volumes resulting from our energy efficiency programs is mitigated by revenue recovery under the state's Energy Efficiency Investment Act. Kilowatt hour sales to industrial customers in Illinois and Missouri declined a combined 1.5%; however, in Missouri, such sales would have increased if not for a late-year decline in sales to Noranda Aluminum, Ameren Missouri's largest customer. Kilowatt hour sales to Noranda declined because of operational issues at their plant, which they have characterized as temporary.

Turning to page 12, I will now briefly update you on select matters pending before our state and federal regulators. In Missouri, the focus is on our pending request for an increase in electric rates to recover higher net energy costs and to recover and earn a fair return on infrastructure investments made for the benefit of our customers. The request also reflects increased taxes, rebates paid for customer-installed solar generation and other costs.

Our rate increase request has now been updated for true-up items agreed to by parties to the case. Rate base, capital structure, and certain revenue and expense items have been trued up through year-end 2014, and net energy costs and payroll costs have been trued up through January 1, 2015.

In addition, we reached a partial settlement with the staff of the Missouri Public Service Commission and certain interveners on certain revenue requirement issues, and filed it with the Commission on Monday. Reflecting the true-up and this settlement, our updated rate increase request is approximately $190 million annually, comprised of approximately $100 million for increased net energy costs and approximately $90 million for other costs, including our requested return on equity. This updated request incorporates electric service rate base of approximately $7 billion, a reduction from the $7.3 billion contemplated in our initial filing, primarily due to the extension of bonus depreciation through 2014.

Hearings before the Missouri Public Service Commission began on Monday and are scheduled to continue for a few weeks. A decision from the Missouri Public Service Commission is expected by May, with new rates expected to be effective by early June. More details on this case are provided in the appendix to today's presentation.

Moving to regulatory matters pending at the Illinois Commerce Commission, Warner mentioned that we filed a request for an annual increase in natural gas delivery rates of $53 million last month. This case is based on a future test year ending in December 2016, and includes a request for a decoupling mechanism that would permit us to collect our authorized revenue requirement from residential and small non-residential customers independent of sales volume fluctuations.

We expect the Illinois Commerce Commission to issue a decision in this case by December, with new rates effective by January of next year. A summary of this filing is also included in the appendix to today's presentation.

Finally, the previously mentioned complaint cases seeking to reduce the allowed ROE for MISO transmission owners, including Ameren Illinois and ATXI, are pending at the FERC. Last month, the FERC established a schedule for the initial case. This schedule calls for hearings to begin August 17th, with an initial order from an administrative law judge expected by the end of November of this year, and a final order from the FERC expected next year.

I'm pleased to note that the FERC approved, effective January 6th of this year, our request for an ROE incentive adder of up to 50 basis points for both Ameren Illinois and ATXI to reflect their participation in a regional transmission organization. Collection of this adder will be deferred until the ROE complaint cases are resolved.

Moving to page 13 of our presentation, next I would like to discuss our 2015 earnings guidance. As Warner stated, we anticipate that 2015 will be another year of solid earnings growth, with per-share results anticipated to be in a range of $2.45 to $2.65 per share. This expected growth is largely driven by the increases in FERC-regulated transmission and Illinois electric delivery rate base noted on this page.

Like 2014 results, our projected 2015 electric transmission earnings include a reserve for a potential reduction in the current MISO base allowed ROE, but also incorporate the 50 basis point ROE adder effective January 6th. Further, our expected Illinois electric delivery earnings incorporate a formula-based ROE of 8.8% using a forecast of 3% for the 2015 average 30-year Treasury bond yield. Our 2015 Illinois electric delivery guidance also reflects the absence of a $0.03 per share 2014 benefit from a regulatory decision allowing recovery of the majority of previously disallowed debt redemption costs.

Looking now to Ameren Missouri, projected 2015 earnings will benefit from the absence this year of a nuclear refueling and maintenance outage at the Callaway Energy Center. Such outages typically occur every 18 months, and the next one is scheduled for the spring of 2016.

In addition, new higher Missouri Electric delivery rates are expected to become effective in early June. Until these new rates are effective, Missouri earnings will be negatively affected by regulatory lag, reflecting the absence of a return of and on investments in projects completed since our last rate case, including the major projects that entered service late last year.

Before I leave the discussion of 2015 expectations for our Illinois and Missouri utilities, I would like to mention our sales outlook and temperature effects. Off to the right on page 13, you see that a return to normal temperatures in 2015 would reduce Ameren's earnings by an estimated $0.03 per share compared to 2014.

Further, we expect weather-normalized kilowatt hour sales to residential and commercial customers to decrease by approximately 0.05% compared to last year, with higher sales to commercial customers more than offset by lower sales to residential customers as a result of our energy efficiency programs. Net of the effects of Missouri's energy efficiency programs, we expect Ameren-wide kilowatt hour sales to residential and commercial customers to be roughly flat.

Turning to industrial customers, kilowatt hour sales to this group are expected to increase approximately 2.5% compared to last year, with the larger part of that growth expected to come in Illinois. As I previously mentioned, the earnings effect of reduced Missouri electric sales volumes due to our energy efficiency programs is mitigated under our MEEIA plan. Further, the earnings impact of kilowatt hour sales fluctuations in Illinois is limited by the 50-basis-point collar around the allowed ROE for our delivery service business.

Before moving to page 14, I do want to highlight that we recognize that investors are interested understanding the sensitivity of our earnings outlook to changes in our allowed ROEs, given our formulaic rate making and pending rate cases. Therefore on this page, we have provided estimates of 2015 earnings per share sensitivity associated with hypothetical changes in allowed ROEs.

Moving then to page 14, parent and other costs are expected to decline as a result of a full year of interest cost savings related to the previously mentioned May 2014 maturity of high-cost parent Company debt. We also forecast our 2015 effective income tax rate will be about 38%, a decrease of approximately 1 percentage point from the 2014 effective rate. Finally, this earnings guidance incorporates average basic common shares outstanding of 242.6 million, unchanged from the prior-year level.

Continuing on page 15, for 2015, we anticipate negative free cash flow of approximately $500 million. On the right side of this page, we provide a breakdown of our $1.96 billion of planned 2015 capital expenditures. We plan to fund this year's negative free cash flow and debt maturities with a mix of long- and short-term borrowings, including expected long-term debt issuances of $500 million.

Turning to Page 16 of this presentation, here we provide an overview of our $8.9 billion of planned, regulated capital expenditures for the 2015 through 2019 period. The expected funding sources for these infrastructure investments are listed on this page. In particular, we expect to benefit from approximately $1.1 billion to $1.2 billion of income tax deferrals and tax assets over this period.

The expected changes in deferred taxes are driven primarily by our planned capital expenditures. The tax assets include approximately $715 million of federal and state net operating loss carry forwards, federal and state income tax credit carry forwards, and expected income tax refunds and tax overpayments at year-end 2014.

Approximately $440 million of these tax assets are at the parent Company and are not currently earning a return. These tax assets are expected to be realized into 2017.

As I previously mentioned, we do not expect to issue any additional common shares in 2015. Further, we do not plan to issue additional common shares via public offering through 2019. Should we decide to issue additional equity at some point over this five-year period, we would expect to do so by issuing new shares through our dividend reinvestment in 401(k) plans.

We remain committed to funding our capital expenditures in a manner that maintains solid credit metrics, and this is reflected in our capitalization target of around 50% equity.

Moving to page 17, we plan to invest a substantial $2.3 billion in FERC-regulated projects over the five years ending in 2019, with $1.3 billion of this at ATXI and the remaining $1 billion at Ameren Illinois. Here we provide an updated cost estimate for the Illinois Rivers Project, incorporating the final route approved by the Illinois Commerce Commission. The updated cost estimate for ATXI's investment in the project is $1.3 billion, compared to our prior estimate of $1.1 billion.

In addition, Ameren Illinois is building parts of the project that connect its transmission system to ATXI's portion of Illinois Rivers at multiple points. These expenditures, as well as local reliability and expansion investments, for which there continues to be a need, are included in Ameren Illinois' five-year spending plan. The entire Illinois Rivers Project represents an estimated investment of $1.4 billion.

I'm pleased to report that the project is progressing as planned, and we continue to expect the first section to be completed in 2016, with the last section slated for completion in 2019.

Now turning to page 18, I will summarize. We delivered strong 14% earnings per share growth in 2014 and are successfully executing our strategy. As a result, we expect to again deliver solid earnings growth in 2015 compared to 2014. We also reaffirm that earnings per share are expected to grow at a strong 7% to 10% compound annual rate from 2013 through 2018.

Of course, long-term earnings growth is driven by investment in utility infrastructure for the benefit of our customers. We expect 6% compound annual rate base growth over the five-year period of 2014 through 2019 based on a transparent mix of needed transmission, distribution, and generation investments across multiple regulatory jurisdictions. We believe this highly visible growth is outstanding as compared to our peers.

Finally, Ameren's $1.64 per share annualized dividend rate provides investors with a current yield of approximately 3.8%. In our view, this expected earnings and rate base growth coupled with our dividend yield add up to a very attractive total return proposition for investors.

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

Thank you. (Operator Instructions)

Our first question today comes from the line of Julien Dumoulin-Smith with UBS. Go ahead with your question, please?

Hi good morning, can you hear me?

Yes, Julian, this is Marty. You're a bit weak. Please do speak up.

All right, indeed. Excellent. So perhaps the first quick question on the CAGR, if you will, just why not roll forward and have a consistent rate base EPS CAGR? Anything in particular, particularly as you think about earnings in 2019 or was this just a fluke?

Well I would not call it a fluke. No look, we felt it would be good to continue to provide updates to the guidance that we provided last year. We put a stake in the ground that we expected to grow earnings 7% to 10% from 2013 to 2018, and I think it's certainly important that we continue to let you know where we track against that.

So I said on the call longer term, we really believe that growth in this business is driven by a rate-base growth, and longer term certainly plan to provide the rate base growth outlook that we've provided. So we think that's a good basis going forward to continue to provide longer-term outlook.

Okay fair enough. Moving on to some of the details here. As you think about gas, and specifically the new rider, is there a full-year contribution here in 2015, or should we think about it as somewhat lagged into 2016 as the benefits fully accrue?

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

Yes.

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

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

What really triggered that is, as we looked at, we certainly study the orders that FERC's given out, not only in ISO New England but with other companies that come before them. There was a December order that FERC issued relative to another company, which we believe gave better clarification as to how the FERC's going to think about computing the ROEs for the various refund periods that exist with respect to these complaint filings.

So using the ISO New England as well as the guidance provided in that other FERC order, we felt that we could reasonably estimate a reserve to book. Thought it was prudent to do so, prudent to get that reserve booked and behind us, and so therefore we've done that.

You didn't ask specifically about the amount, but I can tell you that the reserve we recorded gets you to an ROE about at the same place that the FERC landed in the ISO New England order.

Got you. Excellent. Well I'll get back in the queue, thank you.

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

Good morning.

Good morning, Steven.

Wanted to just talk about the resource plan and EPA regulation. Assuming that later this year we do receive a plan that looks a lot like the draft plan that we received, could you talk a little bit about how you think and your constituents think about the timing for actually executing the plan?

There's always litigation around big plans such as this from the EPA, but curious in the face of that, do you see a need and a desire to try to at least start to move forward with your plan, to move towards compliance? Or would there be a delay before moving forward, given the litigation? How do you think about that?

Stephen, this is Warner. Of course, if the EPA issues a Clean Power Plan, which is very identical to what the rules are as they've been proposed today, of course, we will move forward to be in compliance with that plan, recognizing, as you rightfully point out, there will be litigation we believe surrounding this plan for several years. Which as you probably know, one of the issues that not just we but many in the industry have raised. But we will do our best to operate under that.

But as we've raised to others, we have concerns with not just the economic impacts, but I think what you're starting to see in these hearings at the Federal Energy Regulatory Commission are conducting there are real concerns about reliability risks, significant concerns.

So we're hopeful that the EPA is listening very carefully to concerns that we're raising, those concerns that are being raised the industry, but also by those that are experts in the industry to ensure reliability, and frankly those outside of the industry. So we're hopeful that the EPA, in listening to that, will make modifications to that rule to make it acceptable, if that rule ultimately withstands the legal challenges.

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

As we pointed out during the call, this is Warner again, we think that the opportunities are really two-fold. Number one, while we've talked a lot about the FERC 1000 projects, we sit there and we sit among the seams of SPP. Certainly we have opportunities within MISO, especially with the addition of Entergy, and of course within the seams of PJM.

And because of all of those things, we believe that there continue to be robust opportunities for us to make proposals. And combine that with our operating experience and our knowledge of the system, we believe we have a very good opportunity to enhance our transmission spend and investment because of those.

And I wouldn't stop there; we've taken a hard look and continue to do so in terms of local reliability projects, to continue to improve the system for our customers here within both Missouri and Illinois, as well as in opportunities that would enhance just within MISO. So Steven, I see that putting those two things combined, we see meaningful investment opportunities in the transmission business, and especially that's fruitful when you have a frame work which is supportive of investment in transmission.

Great. Thanks so much.

Sure.

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

Yes, hi good morning guys.

Hi, Steve.

I had a couple specific questions related to your ROE and interest rate assumptions. So first on the Illinois business, it looks like in 2015 you're using a 3%, 30-year. So if you assumed it stayed flat through 2018, I assume your core base is off like the forward curves for the 30-year or something? Is that how you --

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

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

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

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

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

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

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

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

I think, Steve, over time, we'll have to assess that. You'll want to see how these cases come out and then assess through time how we'll go about updating FERC ROEs through time. So I don't want to get into exactly what we've got embedded in our 7% to 10% growth and our own plan going forward for FERC.

As I mentioned, if you took the current ROEs embedded in our 2015 guidance and held them constant through 2018 without any change, you'd stay within that 7% to 10%. You would have to believe -- I guess what I would agree with you on is that over time, if we see cost of capital rising, if we believe it's prudent to adjust the ROEs upward, we'd certainly take action and pursue that with the FERC.

Okay, great. Just thank you, I appreciate, just wanted to make sure I understood those aspects, so I appreciate going through all of it.

Absolutely.

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

Hi. Just wanted to touch base with you on just to clarify exactly what was settled on Monday in Missouri and what was left out. So you guys are asking for $190 million. You broke out the components of that pretty well. I'm just trying to get a sense as to what was settled and what wasn't settled in the case. If you could just elaborate a little further on that on Monday, the non-unanimous settlement that you guys filed.

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

What I was wondering is what's not settled, if you follow what I'm saying? What's still contested that you guys just left open? Do you follow me?

Yes, so the large issues that are open are obviously return on equity. We have some tax issues that are open today. Obviously, the trackers, the FAC, the Office of Public Council is proposing to remove that tracker or change the sharing percentage. Staff is proposing to remove the storm tracker. There's some meaningful depreciation issues that are still open today, and there are a few amortization issues that are at risk as well.

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

No, Paul, we don't have really, I can't say a good point estimate for where the staff is today. We did put a stake in the ground in terms of our own position, which is obviously we know our own position, which is in the back, you'll see $190 million; $100 million of that is net energy costs and about $90 million of it is other costs.

I can tell you that in terms of from the original case that we filed to the case that we have today, our non-fuel ask is down about $45 million. That's probably $25 million to $30 million due to lower rate base, primarily bonus depreciation, and the other $15 million to $20 million is due to updates of pension, post-retirement medical, and active medical. So a lot of those costs are actually going through riders and trackers. But it gives you a little bit of a sense for how our position moved from the original position to where we are today.

Michael provided you some of the color on some of the positions that the other parties have taken. We've provided an overview or summary of that in our materials, as well in the appendix. But can't give you as I sit here today an exact bid ask spread.

Okay, and then you mentioned the seams opportunity that you guys have, which makes a lot of sense. But as you know, there's also a proceeding or a couple -- well I guess a generalized, generic proceeding with respect to MISO PJM on capacity transfer and day ahead and a whole variety of other things.

And although it's been moving slowly, in some respects, it's moving. It appears to be at least. And FERC has recently put out an order and stuff on it, and I'm just wondering do you think -- do you have any perspective on that? And could that impact your transmission opportunities, depending on how that unfolds? Or are those transmission opportunities there, pretty much regardless of what happens with this generic PJM MISO seams proceeding?

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

No, no.

I appreciate that. Maureen Borkowski, who is the President of our Transmission Organization, she can probably touch on some more of the details throughout those current proceedings. So Maureen?

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

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

Again, Paul, this is Michael Moehn. As Warner said, it is similar legislation. The Senate Bill 310, House Bill 925 it was very similar to last year. I think we're early in the session, so it's difficult to speculate the outcome. We're spending a lot of time with various stakeholders, again explaining there's a lot of freshman legislators there, explaining to them the importance of this legislation and the need to modernize the regulatory framework to get working on the aging infrastructure issue.

We're certainly mindful that all of the utilities in Missouri are in for rate cases, and so that's just a factor that we have to be aware of. But as we said in the past, we're going to continue to pursue this and be relentless about trying to get it across the finish line. But I think it's probably a bit premature to speculate the outcome.

Anything specifically different than the last couple years politically that we should be thinking about?

I'm sorry?

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

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

One other thing, Paul, which I think is helpful is we certainly, in the conversations that we have in Missouri, we point to the success that we continue to have with constructive legislation in Illinois, not how it's only improving the reliability, not only how Richard and the Illinois team continue to hit their metrics, but also how they're creating jobs. So all those things are right across the river, and those are important conversations that we continue to point out. Because we see that as really the opportunity for Missouri to do something in the future. So with a little bit more history behind that, we think it is another important aspect of our conversation today.

Excellent. Thanks a lot guys.

Sure.

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

Hi, good morning.

Good morning.

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

Sure, 25 basis points is probably $0.01 to $0.015. We actually did provide a sensitivity, if you take a look at slide 13, some small print, I recognize. But in the Ameren Illinois electric delivery section, we note that a 50-basis-point move in EPS or in ROE would change the EPS about $0.025. So obviously, 25 basis points would be about half of that.

Okay, got it.

That's pretty small in the grand scheme of the earnings guidance for this year.

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

Oh, you're talking about -- what year do you want it measured off of, 2014 looking out to 2018?

Correct.

So last year, somebody had asked, hey, what's the growth rate off of 2014? And we had replied 6% to 9.5%, and at that time, when you looked at our 2014 guidance, the midpoint was 2.35. If you look at our weather-normalized results for 2014, they are $2.37 so that 6% to 9.5% number still holds. It's basically 6% to 9.5% off of 2014; out through 2018 is the CAGR is equivalent to the 7% to 10% off of 2013.

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

Well you raise a good point. When you look at our CapEx for this past year, we really came in right where we said we would. We had forecasted to be at about $1.850 billion, and we finished the year nearly $1.8 billion, so pretty much on top of where we had expected.

We are expecting a little bit of an uptick in 2015 in terms of capital expenditures, up about another $175 million as we reported on the call, to about $1.960 billion. And that level is a little bit of an uptick, mainly due to the timing of our projects.

But if also you'll take a look at the slide 16 that we provided where we layout our expected capital expenditures over the five-year period, we're projecting $8.9 billion of regulated infrastructure investment over this period. And that's actually up over the prior-year five-year period.

So we -- back in last year, we had said 2014 through 2018 was going to be about $8.3 billion; now we've moved up to about $8.9. So we've added about $600 million of overall capital expenditures to this five-year plan, as compared to the old one. So we've added expenditures, we've added expenditures that will translate into rate base growth, an amount that is roughly double what we see as the negative impact of bonus depreciation. So we've more than offset the impact of bonus depreciation with identified additional projects to invest in for the benefit of our customers.

When you look on slide 9, that's where we actually show then our expected rate base growth, and basically, we're expecting to grow rate base 6% from 2014 to 2019. That's a very is similar rate to what we had before for 2013 to 2018. But you can see because of that added capital expenditures, over the five-year period, that the ending rate base of projected rate base of $15.5 billion is about 9% more than what we had last year projected at the end of 2018.

And so one should not assume either that the CapEx that we added is back-end loaded. It's really been added throughout the period. But ultimately, leads to a rate base number at the end of 2019, which is about 9% higher than what we had been projecting for 2018.

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

When you get the 10-K, I think you can calculate it -- you may be able to calculate it on the stats page. We earned pretty close but slightly below the allowed ROE in Missouri.

What we're really talking about, about lag on the call though was more about 2015. We put a number of projects into service at the end of 2014. Those began to be depreciated and were no longer capitalizing return on those. So as we roll into early 2015, we do experience some lag until we can get the rates reset to reflect recovery of those costs and rates that reflect an appropriate return on those investments. So that's the lag I think we were really pointing to on the call.

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

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

Thank you very much.

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

Okay, thank you.

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

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

Yes, sure Michael, good morning by the way. This is Marty. Good questions. So last year, we had guided that in 2013, we'd had about $0.18 or so of parent and other costs. We had projected to drive those down in 2014, which we were successful at doing. We said to $0.10 or below, which is where we ended up, including, I would say, the effects of dilution, we're probably at about $0.09 of drag. And we expect that we'll be able to reduce that further in 2015.

Of course, you know we get the full year benefit of that maturity at the parent Company where we had the high cost debt. So we do expect another $0.04 or so of interest savings. So expect to drive that number down to maybe about $0.05. And depending upon taxes or things like that, maybe a hair lower, but we're expecting $0.05 or a little bit under in terms of parent Company drag in 2015.

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

I don't know, Michael, whether there is anything more transformative. I think when you look at the gas business in Illinois, we've already, I'd say, ramped up some investment there, because we do see that as constructive environment as it exists today.

As you know, we have the ability to use forward-looking test years for our gas rates. And the rate case that we have pending today, as we mentioned on the call, looks out to 2016, we uses 2016 projected cost and rate base. We think that's constructive.

And then we've begun to be able to use basically a rider for our qualifying infrastructure projects, so that we can actually adjust rates monthly between rate cases to reflect the return of and return on those qualifying projects. So we believe there's been enhancement made to the framework, which is actually allowing us to step up investments. And we are replacing meter modules and gas business alongside the meter replacement program that we've got going on the electric portion of the business. And its allowing us also to make some necessary investments in that business to ensure the safety, as well as reliability of the gas business.

I think moreover, Michael, what we may see that may reflect or spur investment over time, we think the framework is good, but it will be whether we see some additional safety rules that come out at the national level that may drive actually investment in spending. And but we do believe we have the framework in place that if we are required to make those investments that we'll be treated absolutely fairly in terms of the regulatory processes.

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

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

Michael, I don't have it at my finger tips but we did give you some websites at the back of the presentation that show our Attachment O filings for 2015. The total is about $1.4 billion average rate base for 2015, but the breakout is public and it's in there. I apologize that I don't have that right in front of me.

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

Thank you, Michael. Thanks for your questions.

Thank you, guys.

Our next question comes from the line of Andy Levi with Avon Capital Advisors.

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

Thanks, Andy.

If you'll give me --this is Doug. If you'll give me just a second here, I think I may have found that information here. Andrew is going to help me here for a second. It's about $0.5 billion for ATXI and about $900 million for Ameren Illinois is the number here I'm getting.

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

Doug?

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

Thank you, Mr. Fischer. This will conclude our teleconference for today. You may disconnect your lines at this time. We thank you for your participation. Have a great day.