Alliant Energy Corp (LNT) — Q4 2015 Earnings Call Transcript

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 yearend and fourth quarter 2015 earnings, affirmed 2015 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 our 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 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.

Thank you, Sue. Good morning and thank you for joining us for our yearend earnings call. I'll begin with an overview of 2015 performance and then provide an update on our forecasted capital expenditures and rate base. I'll also share the progress made in transforming our generation fleet, modernizing our electric system and expanding our natural gas system. I'll 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 am 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 of late 2015 did impact our actual yearend results. For the first ten months of 2015, our financial results were basically temperature neutral, but the one winter we experienced, especially in December, resulted in a negative $0.08 per share variance in 2015 earnings. This was quite the opposite for 2014 where 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 through 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 through 2019 capital expenditure plan is driven primarily by accelerated investments from our electric and gas distribution systems. The 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 base 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've been executing on a plan for the orderly transition of our generation fleet in an economical manner to serve our customers. We 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, retiring all the 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 for about one third of our 2009 coal-linked plate capacity. These retirements have been replaced with highly efficient gas-fired generation, which produces approximately half of the carbon emissions when compared to coal-fired generation. Though 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 doubled its prior five-year average. Our Emery combined cycle facility also experienced significant increases in operating hours during 2015. With lower gas prices, the additional gas generation in 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 is now approximately 75% complete. The forecasted capital expenditure for this project is 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 Unified. This project is approximately 90% complete and is on time and below budget. The capital expenditure forecast for this project is approximately $270 million and it is expected to be in service later this year. Driven upgrades and pulverizing replacement work continue at Columbia, and these performance improvements projects are expected to be complete next year. This spring construction of a Columbia unit to SCR will begin. 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 therefore more than 50 years of dependable operation. Nelson Dewey and Edgewater Unit 3 were retired in December. The retirement of these units puts several other retirements through 2019, but will result in a reduction of WPL capacities for approximately 700 megawatts. As a result, WPL proposed to construct the 700-megawatt highly efficient natural gas generating facility referred to as a Riverside Energy Center expansion. We anticipate the Public Service Commission will issue its decision on the Riverside expansion in the second quarter. Earlier this month, we announced that we have negotiated options with neighboring utilities and electric cooperatives for partial Riverside ownership of up to 55 megawatts during the construction facility and up to an additional 250 megawatts during the first five years that the facility is operating. With this agreement, the cooperatives have extended their wholesale electric contracts at WP&L by four years through 2026. We're pleased that our neighbor utilities realize the benefits of our proposed facility and want to be involved in this exciting and innovative project. While we now expect the other 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 date has changed from early 2019 to early 2020, therefore the timing of the capital expenditures has 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-megawatt purchase option during construction. In addition to the Riverside joint ownership option, hub service and MG&E will have the option to limit their capital expenditures at Columbia to paying 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 electric co-ops exercise their purchase option for 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 planned for our future generation needs, we aim to minimize emissions while providing safe, reliable and affordable energy to our customers. We believe that with the transition of our generation fleet and the availability of lower natural gas prices, our carbon emissions will continue to decrease. We're 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 purchasing 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 customer's energy needs in 2015. Also, there are several solar projects under development from which we anticipate gathering valuable experience on how best to integrate solar cost-effectively into our electric system. At our Madison headquarters, 1300 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. In Iowa, we will be owning and operating 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 a sense of excitement as we work to transform the company to meet our customer's evolving expectations. A major improvement to our customer experience just happened as we went live with our new customer care and billing system. The $110 million investment replaced the interim systems from the 1980s. Our new billing system will make communication with our customers more convenient and timely and will allow us to provide innovative service options. This project was another well-executed major initiative. 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 we work hard to also deliver 2016's financial and operating objectives. We anticipate no material change for the rate base 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. The central execution on our major construction projects includes completing projects on time and at or below budget 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. We will continue to manage the company to strike a balance between capital investment, operational and financial discipline, and cost-effective customer service.

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 of $3.38 per share. The non-GAAP to GAAP differences are due to a $0.07 per share charge resulting from the sale of IPOs Minnesota electric and gas distribution assets and a $0.04 per share charge resulting from 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 IPO 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 investment, 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 IPO and WP&L excluding the impacts of the Minnesota sale. Also, the earnings guidance is based upon the impacts of IPOs and WP&Ls previously announced retail electric base rate settlements. The IPO settlement reflected rate-based growth primarily from placing the Lansing scrubber in service in 2015. In 2016, IPO expects to credit customer bills by approximately $10 million. By comparison, the billing credits in 2015 were $24 million. During 2016, IPO also expects to provide 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 affect full year results. The WPL 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 base additions was completely offset by lower energy efficiency, cost recovery amortizations. Also included in WP&L's rate settlement was an increase in transmission cost, primarily related to the anticipated allocation of SSR cost. As a result of a third-quarter issue after the settlement, the amount of the transmission cost 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 IPO, WP&L, and AEC for 2016 and provides you the actual effective tax rates for 2015. Turning to our financing plans, our current financing forecast incorporates the extension of bonus depreciation deductions for certain capital expenditures for property through 2019. As a result of the five-year extension to 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 carry-forward positions as well as future amounts of bonus depreciation expected to be taken under 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 targeted liquidity and capitalization ratios as well as high-quality credit ratings. Our 2016 financing plan assumes we'll be issuing approximately $25 million of new common equity through our shareholder direct plan. The 2016 financing plan also anticipates issuing long-term debt up to $300 million at IPO 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 deemed 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 of 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 of note 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 rate case for 2017 and 2018 rates. For IPL, we'll be filing our five-year emission plan and budget in the first quarter and expect a decision regarding the permanent application for the approximately $60 million Clinton Natural Gas pipeline in the second quarter. The next Iowa retail electric and gas 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.

Hi. Good morning.

Good morning, Brian.

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

Brian, as we 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'll be sharing specifics as we issue guidance in later years, but what’s important is that targeted incremental equity is included in our forward-looking guidance. So the dilution is reflected in our 5% to 7% targeted growth rate.

Okay. Great and it looks like '15 over '14 and '16 over '15 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?

Yes, what really is, Brian, is that our sales forecast has come down a little bit. Originally we were about 2% at Wisconsin and 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 is 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 the second quarter was Minnesota's charge, and then the third quarter was the charge associated with the voluntary separation package. So second, third quarter. Sorry, Brian.

Okay. Great. Thank you.

Thanks. Good morning, everyone.

Good morning, Andrew.

First question on the CapEx update. Help me understand, is the $260 million net increase over the years pulling forward from the existing 10-year CapEx plan or would that be incremental to the $10.6 billion that you've forecast through 2020 for?

Yes, this is additional to what we previously showed you in the 10-year plan.

Okay, great. Next question I have is on a lot of the announcements you made on Riverside; I believe if I heard you correct, you said that the cash associated with incremental Columbia CapEx would be roughly offset by Muniz 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 as they both have been. We're not revising the CapEx until we know exactly what’s going to happen with the gracious 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. 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. Lastly, I might be reading the wording a little too closely, but in the press release, you mentioned striving to achieve the projected earnings growth rate. Regarding the lower sales growth you just discussed, is there any reason to think that next year might lean towards the low end of that range, or do you still feel comfortable with the midpoint throughout the construction? I'd also appreciate your thoughts on how the outlook looks over the next several years.

Yeah, no, we're very confident and keep in mind the reason we're gravitating towards the lower end right now is that when rate freezes and the sales forecast change from the timing that you agree to rate freezes, but we're still very confident with our plan going forward especially as we enter rate cases about jurisdictions.

Great, thank you very much. I appreciate the detail.

Hi, good morning.

Good morning.

Couple questions just to 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 both the impact of what they decide and when they likely decide on whether they're going to take more Riverside and share some of Columbia.

The change at Columbia will occur during the construction of Riverside, which is taking place from now until 2019. The purchase option comes into play in 2020 and later, but this is not included in our capital expenditures plans. This is something we will need to keep an eye on and we will collaborate with other utilities as they create their resource plans. However, at this moment, we cannot estimate the likelihood of this happening.

So that would be after the plant fully done and operating basically.

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

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

Yes, it does. Yes, the CapEx period Steve, that's right.

So it's 2019?

Yes.

Okay. I have a question regarding the recent acquisition announcement of ITC and its involvement in transmission. I'm curious if you will be involved in that transaction or face any issues or interventions related to it.

Steve, we wish we're analyzing the transaction as you can imagine. We're a very large customer of ITC, so this is of quite interest to us as you can imagine. So we've had open dialogue with the folks at ITC and we just plan on having the open dialogue and we'll figure out exactly what our position is in their dockets. They 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're still looking at what the different options are at this point, Steve.

Thank you. Just a quick question, on the rate base that you commented on earlier, is the deferred tax portion of rate base going up while the entire rate base total phase constant versus your prior guidance. Is that the best way to think about it?

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

The earnings base stays constant?

Yes.

Yeah, I would say the net rate base remains constant.

Net rate base, okay, and then 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 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 your planning period?

Sure. We're using 1% now to book utilities. But I would say the growth is about 1%. It's higher in the industrial sector and lower in the residential sector.

Okay. Thank you very much.

Sure. You're welcome.

Hey good morning, Pat and good morning, Tom. Question just to follow-up on Raza's question. So the rate base with the change in bonus depreciation and CapEx is the expectation are flat. So the earnings growth will 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 increase modest as you just said Tom, increase in financing needs. Do I have it right?

In the near term, yeah, because when we had our previous forecast assuming no depreciation or potential bonus depreciation, we were looking at making modest tax payments beginning in '17 and '18 and now with the extension, we won't have that, but that delta in terms of cash is not that significant certainly in the '17 and '18 timeframe.

Right. Okay, great. And then earned ROEs at the utilities subs what were those in '15 on sort of a non-weather adjusted basis understanding that weather is going to.

Yes, we definitely earned our authorized return which was about 10.4 and then in Iowa is around 10% again excluding the Minnesota sale though.

Got it. Those figures are weather adjusted, so that would correspond to the $0.08 adjustment or possibly more like a $3.57 number. I realize it's not entirely fair to discuss this 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 trended, 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 you look forward through '16 and beyond just volume trends you're seeing.

Trend it's actually going through our strategic planning process. Right now looking at other opportunities and where they can expand their current footprint. So I'm very optimistic about some possibilities that they're looking at right now, but they've been very proactive knowing the reduction in their business these are really basically cold transportation. They're looking forward at some other opportunities for them right now, some more to come on that.

Got it. If we're considering 2016 and it's likely within a broad range of guidance, we certainly couldn't return to the 2014 level of earnings from Krandex, but we might see some improvement with the strategic initiatives we are currently reviewing. Is that fair?

I would say it might be beyond '16. It would be hard to execute on projects for '16, but definitely going into '17.

Good morning, guys.

Good morning, Paul.

Just what was the 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 forecast is now 1% what was it previously? I apologize.

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

Okay. Regarding the incremental capital expenditures, this is new investment, not a reallocation from previous projects. What exactly is included in this, and what factors are contributing to this increase?

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. And I guess so I'm wondering though if this is incremental over a 10-year forecast that would indicate that something is driving those. I saw the slide, I guess what I'm wondering is what's driving this? Is it something forward that would indicate that you guys see some new need and I am just wondering what that is or if there is one, what I am missing?

Yeah, 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 where we evaluate after this five-year program because actually for the next five years if we want to accelerate even more in the second five-year time frame; and again, our customer's expectations are reliability and resilience; you're just keep increasing.

Okay.

This is our first stage of looking at that and putting good dollars to work for our customers.

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

Yes, at a high level, yes the safest comment is 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 their own circumstances into the plan. So we're 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.

Thank you, sir.

Yes, hi. 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. You would want it, our non-GAAP temperature adjusted so similar to what we did in '14. So you would want to rebase that now that we reported our actuals for 2015. So the base for purposes that calculation would be $3.57.

Okay. Thanks a lot.

With no more questions, this concludes our call. A replay will be available through March 01, 2016, at 888-203-1112 for U.S. 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 Investor section of the company's website later today. We thank you for your continued support of Alliant Energy and feel free to contact me with any follow-up questions.