Alliant Energy Corp (LNT) 2015 Q4 法說會逐字稿

Ladies and gentlemen, welcome to the Alliant Energy year-end and fourth-quarter 2015 earnings conference call.

(Operator Instructions)

Today's conference is being recorded. I would now like to turn the call over to your host Susan Gille, Manager of Investor Relations at Alliant Energy.

Good morning. I would like to thank all of you on the call and on the webcast for joining us today. We appreciate your participation. With me here today are Pat Kampling, Chairman, President and Chief Executive Officer; Tom Hanson, Senior Vice President and CFO; and Robert Durian, Vice President, Chief Accounting Officer and Controller; as well as other members of the senior management team. Following prepared remarks by Pat and Tom, we will have time to take questions from the investment community.

We issued a news release last night announcing Alliant Energy's year-end and fourth-quarter 2015 earnings, a firm 2016 earnings guidance, and provided updated 2016 through 2019 capital expenditure guidance. This release as well as supplemental slides that will be referenced during today's call are available on the investor page of the website at AlliantEnergy.com.

Before we begin, I need to remind you the remarks we make on this call and our answers to your questions include forward-looking statements. These forward-looking statements are subject to risks that could cause actual results to be materially different. Those risks can include, among others, matters discussed in Alliant Energy's press release issued last night and in our filings with the Securities and Exchange Commission. We disclaim any obligation to update these forward-looking statements.

In addition, this presentation contains non-GAAP financial measures. The reconciliation between non-GAAP and GAAP measures are provided in the earnings release which are available on our website at AlliantEnergy.com.

At this point, I will turn the call over to Pat.

Thank you, Sue. Good morning, and thank you for joining us for our year-end earnings call.

I will begin with an overview of 2015 performance and then provide an update on our forecast capital expenditures and rate base. I'll also share the progress date on transforming our generation fleet, modernizing our electric system, and expanding our natural gas system. I will then turn the call over to Tom to provide details on our 2015 results and 2016 guidance as well as review our regulatory calendar.

I'm pleased to report we've had another solid year achieving a $3.57 midpoint of our November 2015 guidance range when adding back the negative temperature impact of $0.08 per share to the non-GAAP earnings of $3.49 per share. Our 2015 non-GAAP temperature normalized earnings reflect an increase of over 5% from comparable 2014 earnings as shown on slide 2. The temperatures in late 2015 did impact our actual year-end results. For the first 10 months of 2015, our financial results were basically temperature neutral, but the warm winter we experienced especially in December resulted in a negative $0.08 share variance of 2015 earnings. This was quite the opposite from 2014 when we experienced a $0.09 per share positive variance to earnings. Therefore, temperature swings did lead to a significant year-over-year variance of $0.17 per share.

We also issued an updated capital expenditure plan for 2016 to 2019 totaling $5 billion as shown on slide 3. In addition, we have provided a walk from the previous 2016 to 2019 capital expenditure plan to our current plan on slide 4. As you can see, the $260 million increase in our forecasted 2016 to 2019 capital expenditure plan is driven primarily from accelerated investments in our electric and gas distribution systems. A December 2015 extension of bonus depreciation for certain investments through 2019 has given us the opportunity to bring forward some infrastructure projects that will benefit our customers for years to come. I do want to point out that with this revised capital plan, we expect no material change to the rate-based forecast that we provided last November for IPL and WPL through 2018. We anticipate the increase in forecasted capital expenditures will offset the impact resulting from the extension of bonus depreciation.

During the past few years, we have been executing on a plan for the orderly transition of our generation fleet in an economical manner to serve our customers. We've made significant progress in building a generation portfolio that has lower emissions, greater fuel diversity, and is more cost efficient. The transition included installing emission controls and performance upgrades at our largest coal-fired facilities, return older less efficient coal units, and increasing levels of natural gas-fired and renewable energy generation. Since 2010, Alliant Energy has retired or repowered over 1,150 megawatts of coal-fired generation or about one-third of our 2009 coal nameplate capacity. These retirements are being replaced with highly efficient gas-fired generation which produces approximately half of the carbon emissions when compared to coal-fired generation.

Low natural gas prices in 2015 resulted in significant changes to the capacity factors of our gas units. Riverside had an approximately 50% capacity factor last year, more than double its prior five-year average. Our energy combined cycle facilities also experienced significant increase in operating hours during 2015. With lower gas prices, the additional gas generation on our portfolio resulted in savings for our customers in 2015.

Now let me brief you on our construction activities. 2015 was again a very active construction year with over $1 billion deployed. Our investments included approximately $360 million for electric and gas distribution systems. This was one of the largest annual investments in those systems and will be an area of growing investment. These projects are driven by customer expectations to make our electric system more reliable and resilient and to expand natural gas services, especially to communities that did not have access before. In Iowa, the Marshalltown natural gas-fired generating facility is progressing well, and it is now approximately 75% complete. Forecasted capital expenditures for this project are approximately $700 million excluding AFUDC and transmission.

Marshalltown is on time and on budget and is expected to go in service in the spring of 2017. In Wisconsin, progress continues on the installation of a scrubber and baghouse at Edgewater Unit 5. This project is approximately 90% complete and is on time and below budget. Capital expenditure forecast for this project are approximately $270 million, and it is expected to be in service later this year. [Triven] upgrades on pulverizer replacement works continues at Columbia and these performance improvement projects are expected to be completed next year. This spring, construction of a Columbia Unit 2 SCR will begin. The WPL's capital expenditure for this project is approximately $50 million and it is expected to go in service in 2018.

In 2013, WPL announced that it will retire several older coal facilities and natural gas peaking units. And after more than 50 years of dependable operation, Nelson Dewey and Edgewater Unit 3 were retired in December. The retirement of these units, plus several other retirements through 2019, will result in a reduction of WPL capacities of approximately 700 megawatts. As a result, WPL proposed to construct the 700 megawatt highly efficient natural gas generating facility referred to as the Riverside Energy Center expansion. We anticipate the public service commission will issue its decision on the Riverside expansion in the second quarter.

Early this month, we announced that we had negotiated options with neighboring utilities and electric cooperatives for partial Riverside ownership of up to 55 megawatts during the construction of the facility and up to an additional 250 megawatts during the first five years of the facility is operating. With this agreement, the cooperatives have extended their wholesale electric contract with WPL by four years through 2026. We are pleased that our neighbor utilities realize the benefits of our proposed facilities and want to be involved in this exciting and innovative project.

While we now expect the output from the Riverside units to be close to 700 megawatts, the capital expenditure for Riverside remains at approximately $700 million excluding AFUDC and transmission. The targeted in service dates has changed from early 2019 to early 2020. Therefore, the timing of the capital expenditures have been updated and are reflected on slide 3 based on input from the EPC bidders. The expenditures presented for Riverside do not reflect the possible capital reduction if the cooperatives exercise their 55 megawatts purchase option during construction.

In addition to the Riverside joint ownership option, pub service and MG&E will have the option to limit their capital expenditures at Columbia to pay in for only the SCR during the time that Riverside is being constructed. Our capital expenditure plan does not reflect this option being executed. However, we expect that any increase in our capital expenditures at Columbia would be largely offset if the electrical co-ops exercise their purchase options 55 megawatts of Riverside.

Earlier this month, the United States Supreme Court effectively delayed implementation of the Clean Power Plan until legal challenges to the EPA's rules are resolved. This stay will not change our current resource or capital expenditure plan as they were not based on compliance with the Clean Power Plan.

As we plan for our future generation needs, we aim to minimize emissions while providing safe, reliable, and affordable energy to our customers. We believe that the transition of our generation fleet and the availability of lower natural gas prices, our carbon emissions will continue to decrease. We are very fortunate to operate in states that have a long history of support for renewable energy and a strong commitment to environmental stewardship. We have and will continue to invest in and purchase renewable energy. We currently own 568 megawatts of wind generation, and our 10-year capital plan includes additional wind investments to meet customer energy needs.

In addition, we currently purchase approximately 470 megawatts of energy from renewable sources. Wind energy provided approximately 8% of our customers' energy needs in 2015. Also, we have several solar projects under development from which we anticipate gathering valuable experience on how best to integrate solar in a cost-effective manner into our electric system. At our Madison headquarters, over 1,300 solar panels have been installed and they are now generating power for the building. Construction has also started on Wisconsin's largest solar farm on our Rock River landfill which is adjacent to Riverside. And in Iowa, we will be owning and operating the solar panels at the Indian Creek Nature Center in Cedar Rapids and are reviewing responses to the RFP we issued for additional solar in our portfolio.

There is sense of excitement as we work to transform the Company to meet our customers' evolving expectations. A major improvement to our customer experience just happened as we went live with our new customer care and billing system. This $110 million investment replaced mainframe systems from the 1980s. Our new billing system will make communication with our customers more convenient and timely and allow for us to provide innovative service options. This project was another well executed major initiative but I do want to thank everyone that worked so hard for years to transform our customer experience. At Alliant Energy, we've already made great progress transitioning our utilities to a cleaner more modern energy system. This would not have been possible without the hard work and commitment of our employees who keep the customer at the center of everything we do.

Let me summarize the key messages for today. We had a solid 2015 and will work hard to also deliver 2016's financial and operating objectives. We anticipate no material change for the rate-based growth through 2018 as the updated capital expenditure plan will offset any impact from the extension of bonus depreciation. Our plan continues to provide for 5% to 7% earnings growth and a 60% to 70% common dividend payout target. Our targeted 2016 dividend increased by 7% over the 2015 dividend target.

Successful execution on our major construction projects include completing projects on time and at or below budget and in a very safe manner. Working with our regulators, consumer advocates, environmental groups, neighboring utilities, and customers in a collaborative manner. Reshaping our organization to be leaner and faster while keeping the focus on serving our customers and being good partners in our communities. And we will continue to manage the Company to strike a balance between capital investment, operational and financial discipline, and cost impact to customers.

Thank you for your interest in Alliant Energy and I will now turn the call over to Tom.

Good morning, everyone.

We released 2015 earnings last evening with our non-GAAP earnings from continuing operations of $3.49 per share and our GAAP earnings from continuing operations up $3.38 per share. The non-GAAP to GAAP differences are due to a $0.07 per share charge resulting from the sale of IPL's Minnesota Electric and Gas distribution assets and a $0.04 per share charge resulting from the approximately 2% of employees accepting voluntary separation packages as we continue focusing on managing costs for our customers. Comparisons between 2015 and 2014 earnings per share are detailed on slides 5, 6, and 7. Retail electric temperature normalized sales increased approximately 1% or $0.04 per share at IPL and WP&L between 2015 and 2014. This excludes the impacts of the Minnesota sale.

The industrial segment continues to be the largest sales growth driver year over year. The 2015 results include an adjustment to our ATC earnings to reflect an anticipated decision from FERC expected to lower ATC's current authorized ROE of 12.2%. We reserve $0.06 per share for 2015 reflecting an anticipated all in ROE of 10.82%. This is a result of the FERC administrative law judge's initial decision issued in December 2015.

Now, let's review our 2016 guidance. In November, we issued our consolidated 2016 earnings guidance range of $3.60 to $3.90. The key drivers for the 5% growth in earnings relate to infrastructure investments, such as the Edgewater 5 and Lansing emission control equipment and higher AFUDC related to the construction of the Marshalltown generating station. The 2016 guidance range assumes normal weather and modest retail electric sales increases of approximately 1% for IPL and WP&L excluding the impacts the Minnesota sale. Also the earnings guidance is based upon the impacts of IPL's and WP&L's previously announced retail electric base rate settlements. The IPL settlement reflected rate base growth primarily from plants seeing the Lansing scrubber in service in 2015. In 2016, IPL expects to credit customer bills by approximately $10 million. By comparison, the billing credits in 2015 were $24 million.

During 2016, IPL also expects to provide a tax benefit rider billing credits to electric and gas customers of approximately $62 million compared to $72 million in 2015. As in prior years, the tax benefit riders may have a quarterly timing impact but are not anticipated to impact full-year results. The WP&L settlement reflected electric rate base growth for the Edgewater 5 scrubber and baghouse projected to be placed in service in 2016. The increase in revenue requirements in 2016 for this and other rate based additions was completely offset by lower energy efficiency, cost recovery amortizations. Also included in WP&L's rate settlement was an increase in transmission costs primarily related to the anticipated allocation of SSR costs.

As a result of a FERC order issued after the settlement, the amount of the transmission costs billed to WP&L in 2016 will be lower than what was reflected in the settlement. Since the PSCW approved escrow accounting treatment for transmission costs, the difference between the actual transmission costs billed to WP&L and those reflected in the settlement has been accumulated in a regulatory liability. We estimate that this regulatory liability will have a balance of approximately $35 million by the end of 2016. This regulatory liability is another mechanism we can use to minimize future rate increases for our Wisconsin retail electric customers.

Slide 8 has been provided to assist you in modeling the effective tax rates for IPL, WP&L, and AEC for 2016 and provide you the actual effective tax rates for 2015.

Turning to our financing plans. Our current financing forecast incorporates the extension bonus depreciation deductions for certain capital expenditures for property through 2019. As a result of the five-year extension bonus depreciation, Alliant Energy currently does not expect to make any significant federal income tax payments through 2021. This forecast is based upon the current federal net operating losses and the credit carryforward positions as well as future amounts of bonus depreciation expected to be taken on the federal income tax returns over the next five years.

Cash flows from operations are expected to be strong given the earnings generated by the business. We believe that with our strong cash flows and financing plan, we will maintain our target liquidity, capitalization ratios, as well as high quality credit ratings. Our 2016 financing plan assumes we will be issuing approximately $25 million of new common equity through our shareowner direct plan. The 2016 financing plan also anticipates issuing long-term debt up to $300 million at IPL and approximately $400 million at the parent and Alliant Energy Resources. $310 million of the proceeds at the parent and Alliant Energy Resources are expected to be used to refinance the maturity of term loans. We may adjust our financing plans as being prudent if market conditions warrant and as our debt and equity needs continue to be reassessed.

As we look beyond 2016, our equity needs will be driven by the proposed Riverside expansion project. Our forecast assumes that capital expenditures for 2017 and 2018 would be financed primarily by a combination of debt and new common equity. Before the five-year extension bonus depreciation, we were not expected to make any material federal income tax payments through 2017. Thus, the extension of bonus depreciation is not expected to change our financing needs for the next two years. We have several current and planned regulatory dockets [unmet] for 2016 and 2017 which we have summarized on slide 9. During the second quarter of 2016, we anticipate a decision from the PSCW on the Riverside expansion proposal, and we anticipate filing a WP&L retail electric and gas base case for 2017 and 2018 rates.

For IPL, we will be filing our five-year emission plan and budget in the first quarter and expect a decision regarding the permanent allocation for the approximately $60 million flint and natural gas pipeline in the second quarter. The next Iowa retail electric and gas base rate cases are expected to be filed in the first quarter of 2017. We very much appreciate your continued support of our Company and look forward to meeting with you throughout the coming year.

At this time, I will turn the call back over to the operator to facilitate the question-and-answer session.

(Operator Instructions)

We will take our first question from Brian Russo with Ladenburg Thalmann.

Hi, good morning.

Good morning, Brian.

Would you guys be able to possibly quantify the amount of equity you might need to help finance the Riverside expansion?

Brian, as we have said our objective is to continue to maintain the targeted equity levels at both IPL and WP&L so you can assume that with the largest project here at WP&L that we will have incremental equity needs. We will be sharing specifics as we issue guidance in later years but what's important our targeted incremental equity is included in our forward looking guidance so the dilution is reflected in our 5% to 7% targeted growth rate.

Great. It looks like 2015 over 2014 and 2016 over 2015, you got to kind of gravitating towards the lower end of the 5% to 7% EPS CAGR. Is there something structural there that as rate base grows it's harder to get in the middle or the higher end or is it just a function of lumpiness of the CapEx?

What it really is, Brian, is that our sales forecast has come down a little bit. Originally we were about 2% at Wisconsin, 1% in Iowa. Now we see it as overall 1% and that's what's really brought us down to more to the midpoint of the range, not to the higher end of the range.

Okay. And just to clarify, fourth quarter weather versus normal was negative $0.08?

That's correct.

Okay, and what quarters did those two charges occur? Were they in the fourth quarter or earlier?

The third quarter we recorded the Minnesota charge and I believe --.

Second quarter.

Second quarter was Minnesota charge and then the third quarter was the charge associated with voluntary separation package. So second and third quarter. Sorry, Brian.

Okay. Okay. Great. Thank you.

We'll take our next question from Andrew Weisel with Macquarie Capital.

Thanks. Good morning, everyone. First a question on the CapEx update. Help me understand, is the $260 million net increase over the years, is that pulling forward from the existing 10-year CapEx plan or would that be incremental to the $10.6 billion that you've forecast through 2024.

Yes, so this is incremental to what we've had shown you on the 10-year plan.

Okay. Great. Next question I have is on a lot of the announcements you made around Riverside, I believe if I heard you correct. You said that the cash associated with incremental Columbia CapEx would be roughly offset by munis exercising the option for 55 megawatts.

Is that right? And is there a scenario where you have one but not the other?

Andrew, that is correct that they should offset each other if they both happen. We are not revising the CapEx until we know exactly what is going to happen with the purchase options at this point. But the additional capital for Columbia would be offset by the co-ops purchasing Riverside.

But it is possible that one of the options could occur without the other.

Right.

They're very independent of each other.

Okay, could that be big enough to move the needle on equity needs?

I don't think so. We're talking capital of under $100 million here.

Okay. Great. Then lastly, I might be reading the subtleties of the wording a little too closely but in the press release, you added -- you used the expression striving to achieve the projected earnings growth rate and in the last question, you just talked about the lower sales growth. Any reason to think that the next few years might be toward the low end of that range or do you still feel comfortable with the midpoint through the construction, maybe just commentary on how that [travvy] outlook looks over the next several years?

No, we're very confident and keep in mind the reason we are gravitating toward the lower end right now is that we are in rate freezes and the sales forecasts change from the time we agree to the rate freezes. But we're still very confident with our plan going forward especially as we enter rate cases in both jurisdictions.

Great. Thank you very much. Appreciate the detail.

Sure.

We will take our next question from Steve Fleishman with Wolfe Research.

Hi, good morning. Couple questions.

Just a follow-up on the one with you mentioned on Riverside and Columbia and the co-ops. How about also with Wisconsin Energy and MGE, just how do we think about kind of both the impact of what they decide and when they likely decide on whether they are going to take more of Riverside and share some of Columbia?

Yes, so the Columbia, that change is happening during the Riverside construction. That's between now and 2019. The purchase option is 2020 and beyond.

That's really not in our CapEx plans but that's something we're going to need to monitor. We'll be working with the other utilities as they develop their resource plans as well, but that's not something that we can actually estimate the probability of right now.

So that would be after the plant's fully done and operating basically?

Except for the 55 megawatts for the co-ops. That's during construction.

Okay. And just the growth rate and the rate -- the growth rate of 5% to 7%, is that through 2018 or 2019 to follow the CapEx period?

It's the CapEx period, Steve. That's right.

So that's 2019?

Yes.

Okay. And then a question on the -- as I'm sure you are aware, we had a recent acquisition announcement of ITC and you have the transmission involvement there. I'm just curious if you are likely to get involved and have any, you know, kind of issues with that transaction or intervention.

Yes, Steve, we're still analyzing the transaction as you can imagine. We are a very large customer of ITC so this of quite interest to us as you can imagine. We have had open dialogue with the folks at ITC and we just on plan on having the open dialogue and we will figure out exactly what our position is in their dockets, or they'll have several dockets over the next several months.

Is your intention just to file at FERC or do you think Iowa has a role at all?

We are still looking at what the different options are at this point, Steve.

Okay. Thank you.

Our next question comes from Reza Hatefi with LNZ Capital.

Thank you. Just a quick question.

On the rate base that you have commented on earlier, is the deferred tax portion of rate base going up while the entire rate base total stays constant versus your prior guidance? Is that the best way to think about it?

I would characterize it that NOLs along with the additional CapEx are offsetting the effect of the bonus depreciation.

The earnings base stays constant?

Yes.

I would say the net rate base remains constant.

Net rate base. Okay.

And then the -- I think you commented on it a little bit earlier but this incremental CapEx that you added, how does that affect financing plans over this period? Does it potentially lead to a little more equity or not, or how should we think about that?

The modest amounts that we're adding will not significantly change our equity needs. As Pat made reference, some of this is due to the timing of Riverside. Some of that cost is being pushed out and then we do have the opportunity to backfill, as Pat mentioned, with some of the electric and gas distribution. So it's not going to be materially changing any of our financing needs.

And then the load growth you talked about, I'm sorry if I missed this earlier but what is the forecasted load growth for the -- you're planning period?

Sure. We're using 1% now at both utilities but it's -- I would say the growth is at 1% higher in the industrial sector and lower in the residential sector.

Okay. Thank you very much.

Sure. You are welcome.

We will take our next question from Jay Dobson with Wunderlich.

Hello. Good morning, Pat. Good morning, Tom.

Question just to follow up on Reza's question. So the rate base with the change in bonus depreciation and CapEx is the expectations are flat. So then the earnings growth would be flat but it doesn't really change your tax position.

So cash flow, we would anticipate would in fact be negatively impacted by the rise in CapEx which facilitates the increased -- modest as you just said, Tom, increase in financing these. Do I have that right?

In the near term, yes, because when we had our previous forecast assuming no depreciation -- or extension bonus depreciation, we were looking at making modest tax payments beginning in 2017 and 2018 and now with the extension, we won't have that but that delta in terms of cash is not that significant, certainly in the 2017 and 2018 timeframe.

Right. Right, right. Okay. Great.

And then earned ROEs, at the utility subs, what were those in 2015 -- on a non-weather adjusted basis? Understanding that weather is going to --.

Yes, we definitely earned our authorized return in Wisconsin which was [yield at] up to 10.4% and then in Iowa it was around 10% again, excluding the Minnesota sale, though.

Got you. And those are weather adjusted or so that would reflect that $0.08 adjustment so maybe more like a $3.57 number? I know it's not fair to say that on a jurisdictional basis, but --.

Right, I would say it's all in, including the weather.

Got you. Okay. Fine. And then last one on CRANDIC, the transportation segment, just what you see going forward there. Obviously a tough year in 2015 for that segment, though it developed throughout the year so not a great surprise but as you look forward through 2016 and beyond, just volume trends you are seeing.

Yes, CRANDIC is actually going through their own strategic planning process now looking at other opportunities and where they can expand their current footprint. So I'm very optimistic about some possibilities that they are looking at right now.

They've been very proactive knowing the reduction in their business is the really basically coal transportation. They are looking forward at some other opportunities for them right now so more to come on that.

Got you, but if we are thinking about 2016 and it's probably within a broad range of guidance. Would you -- we certainly couldn't get back to the 2014 level of earnings from CRANDIC but we probably do see some improvement with some of the strategic initiatives there reviewing currently. Is that fair?

I would say it might be beyond 2016. It would be hard to execute on projects for 2016 but definitely going into 2017.

Got you. That's fair. Pat, thanks so much. Tom, thank you.

Sure.

We will take our next question from Paul Patterson with Glenrock Associates.

Good morning, guys.

Good morning, Paul.

Just on -- I'm sorry if I missed this, what was a 2015 weather adjusted sales year over year? What was the growth rate?

It was 1% in both of our two utilities. Again, that's adjusting for the Minnesota sale.

Okay. And then the sales force [cast] is now 1%. What was it previously? I apologize.

Previously, this goes back to a year ago with 2% Wisconsin and 1% in Iowa, and now it's 1% in both jurisdictions.

Okay. And then the incremental CapEx, I'm not exactly sure. This is incremental above.

This isn't bringing is forward from what I understand, this is new stuff. What is that and what's driving that?

We have provided a slide in our supplemental slides that highlight that but I would put it basically in two big buckets. The first is dealing with our electric area in terms of certainly continuing to replace existing distribution lines, so it's really trying to upgrade the distribution system. And we also have then some modest gas expansion as well.

Okay. I guess what I'm wondering though is that if this is incremental over a 10-year forecast, that would indicate that something is driving this.

I mean, I saw the slide. I guess what I'm wondering is what's kind of driving this. I mean, if it's not bringing something forward, it would indicate that you guys see some new need and I'm just wondering what that is or if there is one or what I'm missing.

Yes, I would just say that we're actually just taking the opportunity to expand some of these projects. We've had a replacement program for our overhead and underground system for years and we're just really increasing that. Taking the opportunity now to increase that and we'll re-evaluate after this five-year program exactly with the next five years and if we want to accelerate even more in the second five-year timeframe.

And again, our customers' expectations on reliability and resiliency just keep increasing. This is our first stage at looking at that and putting good dollars to work for our customers.

And just the Clean Power Plan, I believe that the Wisconsin has halted implementation of that. Is there any impact that you guys see of that or how are you guys dealing with that on a high level? Any thoughts we should have on that?

Yes, as a high level, yes, the state has come out and so that they're not going to put any resources to work on any Clean Power Plan implementation. However, the utilities are still working together to try to understand our own circumstances into the plan, so we are working very proactively with the other utilities and we'll just have to see how this plays out in the state.

Okay. My other questions have been answered. Thanks so much.

Sure. You are welcome.

And there are no further questions. I would like to turn the -- we actually have a follow-up question from Brian Russo with Ladenburg Thalmann.

Thanks for the follow-up. Just can you remind us what the base year and adjusted EPS is to formulate the 5% to 7% CAGR?

Brian, we update that every single year. So you would want to -- (technical difficulty) for non-GAAP temperature adjusted, so similar to what we did in 2014 so you would want to re-base that now that we reported our actuals for 2015. So the base for purposes of that calculation would be $3.57.

Okay. Thanks a lot.

And there are no further questions at this time. I would like to turn the conference back over to our presenters for any additional or closing remarks.

With no more questions, this concludes our call. A replay will be available through March 1, 2016, at 888-203-1112 for US and Canada, or 719-457-0820 for international. Callers should reference conference ID 8244179.

In addition, an archive of the conference call and a script of the prepared remarks we made on the call will be available on the investors section of the Company's website later today. We thank you for your continuing support of Alliant Energy and feel free to contact me with any follow-up questions.

And that concludes today's presentation. Thank you for your participation.