Filed pursuant to Rule 425 under the
Securities Act of 1933, as amended, and
deemed filed under Rule 14a-12 under the
Securities Exchange Act of 1934, as amended
Filer: Wisconsin Energy Corporation
Filer’s Commission File No.: 001-09057
Subject Company: Integrys Energy Group, Inc.
Commission File No.: 1-11337
Date: August 12, 2014
The following is a transcript of a panel discussion in which J. Patrick Keyes, Executive Vice President and Chief Financial Officer of Wisconsin Energy Corporation, participated on August 12, 2014.
Cautionary Statements Regarding Forward-Looking Information
This communication contains certain forward-looking statements with respect to the financial condition, results of operations and business of Wisconsin Energy and Integrys and the combined businesses of Integrys and Wisconsin Energy and certain plans and objectives of Wisconsin Energy and Integrys with respect thereto, including the expected benefits of the proposed merger. These forward-looking statements can be identified by the fact that they do not relate only to historical or current facts. Forward-looking statements often use words such as “anticipate”, “target”, “expect”, “estimate”, “intend”, “plan”, “goal”, “believe”, “hope”, “aim”, “continue”, “will”, “may”, “would”, “could” or “should” or other words of similar meaning or the negative thereof. There are several factors which could cause actual plans and results to differ materially from those expressed or implied in forward-looking statements. Such factors include, but are not limited to, the expected closing date of the proposed merger; the possibility that the expected synergies and value creation from the proposed merger will not be realized, or will not be realized within the expected time period; the risk that the businesses of Wisconsin Energy and Integrys will not be integrated successfully; disruption from the proposed merger making it more difficult to maintain business and operational relationships; the risk that unexpected costs will be incurred; changes in economic conditions, political conditions, trade protection measures, licensing requirements and tax matters; the possibility that the proposed merger does not close, including, but not limited to, due to the failure to satisfy the closing conditions; the risk that financing for the proposed merger may not be available on favorable terms; and the risk that Integrys may not complete the sale of Integrys Energy Services. These forward-looking statements are based on numerous assumptions and assessments made by Wisconsin Energy and/or Integrys in light of their experience and perception of historical trends, current conditions, business strategies, operating environment, future developments and other factors that each party believes appropriate. By their nature, forward-looking statements involve known and unknown risks and uncertainties because they relate to events and depend on circumstances that will occur in the future. The factors described in the context of such forward-looking statements in this communication could cause actual results, performance or achievements, industry results and developments to differ materially from those expressed in or implied by such forward-looking statements. Although it is believed that the expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove to have been correct and persons reading this communication are therefore cautioned not to place undue reliance on these forward-looking statements which speak only as of the date of this communication. Neither Wisconsin Energy nor Integrys assumes any obligation to update the information contained in this communication (whether as a result of new information, future events or otherwise), except as required by applicable law. A further list and description of risks and uncertainties at Wisconsin Energy can be found in Wisconsin Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013 and in its reports filed on Form 10-Q and Form 8-K. A further list and description of risks and uncertainties at Integrys can be found in Integrys’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013 and in its reports filed on Form 10-Q and Form 8-K.
Additional Information and Where to Find It
The proposed merger involving Wisconsin Energy and Integrys will be submitted to the respective shareholders of Wisconsin Energy and Integrys for their consideration. In connection with the proposed merger, Wisconsin Energy
will prepare a registration statement on Form S-4 that will include a joint proxy statement/prospectus for the shareholders of Wisconsin Energy and Integrys to be filed with the Securities and Exchange Commission (the “SEC”), and each of Wisconsin Energy and Integrys will mail the joint proxy statement/prospectus to their respective shareholders and file other documents regarding the proposed merger with the SEC. Wisconsin Energy and Integrys urge investors and shareholders to read the joint proxy statement/prospectus when it becomes available, as well as other documents filed with the SEC, because they will contain important information. Investors and security holders will be able to receive the registration statement containing the joint proxy statement/prospectus and other documents free of charge at the SEC’s web site, http://www.sec.gov, from Wisconsin Energy at Wisconsin Energy Corporation, Corporate Secretary, 231 W. Michigan St., P.O. Box 1331, Milwaukee, WI 53201, or from Integrys at Integrys Energy Group, Inc., Investor Relations, 200 East Randolph Street, 23rd Floor, Chicago, IL 60601.
Participants in Solicitation
This communication is not a solicitation of a proxy from any investor or shareholder. Wisconsin Energy, Integrys and their respective directors and executive officers and other members of management and employees may be deemed to be participants in the solicitation of proxies from the respective shareholders of Wisconsin Energy and Integrys in favor of the proposed merger. Information regarding the persons who may, under the rules of the SEC, be deemed participants in the solicitation of the respective shareholders of Wisconsin Energy and Integrys in connection with the proposed merger will be set forth in the joint proxy statement/prospectus when it is filed with the SEC. You can find information about Wisconsin Energy’s executive officers and directors in its definitive proxy statement for its 2014 Annual Meeting of Stockholders, which was filed with the SEC on March 21, 2014. You can find more information about Integrys’s executive officers and directors in its definitive proxy statement for its 2014 Annual Meeting of Shareholders, which was filed with the SEC on March 27, 2014. You can obtain free copies of these documents from Wisconsin Energy and Integrys using the contact information above.
Non-solicitation
This communication shall not constitute an offer to sell or the solicitation of an offer to sell or the solicitation of an offer to buy any securities, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.
Wisconsin Energy Corporation
8/12/2014 - 9:30 AM ET
Speaker ID
Wisconsin Energy Corporation
August 12, 2014
9:30 a.m. ET
Michael Lapides: I want to thank everybody for participating in this second panel. I think this is an interesting panel because it’s the age-old decision that all corporations across all industries face, which is kind of the balance between organic growth and M&A and trying to think about both of those as value creation opportunities.
I want to thank our participants, Ian from Algonquin, Chuck from FirstEnergy, Pat from PNM, and Pat as well from — who, two Pats, I should have separated you all, this is going to get confusing — and Pat as well from Wisconsin Energy.
Each of your companies have been pretty, over — not different time horizons, have been active within M&A within the power and utility space, so for the last four or five years. What’s the main driver? And Ian, I’ll kind of start with you. When you think about the opportunities of organic growth versus using acquisitions to drive growth, what drives the opportunity set?
Ian Robertson: Well from our perspective, from Algonquin Power & Utilities Corp’s perspective, it’s important to separate the two businesses we’re in because I think M&A versus organic growth play very different roles on the regulated versus the non-regulated side.
M&A has been, from our perspective, a much more prevalent component of growth on the regulated side of our business. On the non-reg side, we’re an independent power producer on that side of the business, it really has been about developing projects, and I’ll call that organic growth rather than being in purchasing operating facilities, which I guess would be classically M&A on the IPP side.
So we — if you look at that from the regulated side, we saw and continue to see M&A as a way to expand economies of scale, expand customer base, really create opportunities for organic growth on the regulated side. So if you want to think of it as a starting point for growth for us anyway.
Michael Lapides: Pat, your company’s announced that in the last couple of months mainly doing — at the beginning stages of the approval process for what’s a pretty sizable merger or acquisition transaction. How much does the cost of capital environment influence the decision-making that went around making a transaction like that? Or is it strictly kind of driven off the synergy opportunity set or the balance between the two companies, or even the organic growth potential of Wisconsin Energy as a standalone versus a consolidated entity?
Pat Keyes: That’s a good question, Michael. I think for us at Wisconsin Energy, I don’t think we are — have been known historically as acquisitive, so this is kind of a once in a decade kind of thing for us.
We’ve always talked about, if you’ve heard Gale Klappa talk, he always refers to three criteria we have before we would look at any M&A activity. And that would be in the first full calendar year after acquisition that it would be accretive to earnings, that it would be largely credit neutral, and that the long-term growth prospects of the combined entity had to be at least as strong as our standalone. So for us looking at this particular transaction with Integrys, we felt that this met or exceeded all three criteria.
To get specifically to your questions, so did the cost of capital play into it? Sure I think, but it was more of a question for us of allocation of capital, meaning we had our own organic growth plan, we were fine with it, and we were positive free cash flow on top of our own investment in our infrastructure. We look at 4% to 6% taking that free cash flow to do share repurchases, and we looked at the combined entity and said boy, we can get to 5% to 7%. So in other words, instead of taking our free cash and putting it into share repurchases at twice book, we can do a rate-based investment at book. That’s a better use of the capital, and therefore that would be a better — create more shareholder value than the path we were on. And that was part of the rationale we use.
Michael Lapides: What about the use of leverage? How does — when you think about utilities and kind of the cycle for M&A, and Pat Keyes, I’ll stick with you but then I’m going to hop around to others as well. How does the use of leverage impact the decision-making process for M&A, especially the use of kind of back leverage holding company level?
Pat Keyes: Well for us, our deal is primarily stacked 74/26, and that’s — for a company of our size and given our premium, we thought that was a better way to structure it.
The leverage itself, I’m going to harken back to our second criteria. It has to be substantial — largely credit neutral, which means we were going to take — we would be willing to take a downgrade at the holding company one notch, but nothing at the utilities if we had to.
And I think, Michael, to your question, that kind of drove the nature of the leverage. We think we’re going to take on $1.5 billion of acquisition debt and we felt that we could handle that type of debt in tranches, shorter term to long term, and still meet that second criteria. And that kind of — and we use that kind of to say where would we — how much debt could we take on and not meet that criteria, and that’s kind of how we drove it.
Michael Lapides: I want to change tack a little bit actually. Chuck, when you look across the regulated businesses within FirstEnergy, how do you think about where the growth opportunities, and the growth opportunities exist today clearly on the transmission side, but longer term, how you think those growth opportunities will evolve? And what’s the right amount of scale necessary to maximize that potential growth?
Charles Jones: Well obviously today, as you said, we’re looking at transmission primarily, but I try to look at it a little differently than that. I think we, on the regulated side, are in the business of serving 6 million customers. And so we’re looking at how do we deploy capital in a way that balances the customer interest along with the growth story. And for the foreseeable future, I think that’s transmission.
We have an aging transmission system, 24,000 line miles that we have today. Much of the equipment’s 40, 50, 60, even 70 years old, and we’re seeing reliability forces happen within PJM where last fall we had to interrupt some customers in order to keep the grid stable. So deploying capital to benefit customers, and at the same time generate growth, is the way we try to look at it.
Now we’ve obviously filed obviously for some distribution rate cases in all four of our utilities in Pennsylvania. I think that positions us going forward to look at the same types of strategies because the distribution system is aging also.
But if I think if you keep it kind of customer centric in the decisions that your making, I have no problem looking at any one of my customers and explaining why I’m spending $1.3 billion on transmission this year and how it’s going to benefit them.
Michael Lapides: New Mexico. Are growth opportunities limited when the utility holding company is in only one or fewer — one or two jurisdictions, I guess it can’t be fewer — one or two jurisdictions versus when it’s a portfolio of companies and the holding company can allocate based on individual state or region growth opportunities? How do utilities that serve only one or two areas ensure that there’s a consistent flow of growth opportunities?
Patricia Collawn: I think it’s very specific to the states that you’re in. And so for example we’re in two states; we’re in New Mexico and Texas. Texas is growing like wildflowers. We always say we don’t know what they’re doing there, but they’re doing a great job of it. So there are plenty of opportunities there for growth in both distribution and transmission.
In New Mexico we’re in a wonderful situation because — we’re one of the few people that probably says we’re in a great situation because of the federal regulations on Regional Haze and 111(d). So there’s a lot of opportunity there for fleet modernization and turning our fleet into a lower carbon fleet. So when we look out for the next five years, we have a robust capital program in terms of changing our fleet.
We’re also very lucky — we like to say that we’re the Saudi Arabia of sun. We’re the number two state for solar potential. So — and it’s a lot nicer place to come to New Mexico than to Saudi Arabia, so if you want to take a vacation, come see us. But there’s a lot of opportunities there for us in renewables and then working with transmission, export renewables.
So while you could say that opportunities are limited when you’re only in one and two states, I think if you’re in the right part of the country with the right fleet, there’s opportunities out there.
Michael Lapides: I’ve been involved in this sector since late 1997, 16 or 17 years. And since my first involvement in the sector I had heard different people say this sector will eventually consolidate and will do it rapidly. Pat, does that hold? Are we seeing — I’m going to actually ask both Pats that question. I’ll start with you, Pat. Does that statement — is that statement finally coming true today where we’re seeing an uptick in M&A, an uptick in consolidation? If so, why? If not, why not?
Patricia Collawn: You know, I’ve been doing this a little bit longer than you have, but I’ve heard that since I’ve started. Is it starting to come true now? Yes, but I think a lot of it is driven by cheap capital and sometimes cheap capital makes people do crazy things and very specific circumstances. You guys had a lot of free cash flow and you needed some place to put it, and as you said, you did the numbers and it made sense. There’s — a lot of academic sweat and blood has been shed over what’s the value of scale, and there’s research on both sides. Sometimes scale can be harmful in terms of a big company.
Do I think there’ll still be smaller utilities? Yes. I think some states are going to be fairly parochial about wanting to keep their utility, their headquarters there. Some companies have been very good at managing through that. But I think there’s going to be bigger utilities and smaller utilities, and I think there’s room for all of us in the world.
Michael Lapides: Pat?
Pat Keyes: So I don’t have the wealth of experience of either of you two distinguished panelists, but based on my consulting days, I too have heard the rumors of the rapidly consolidating industry. And I think the person who was my peer that led the M&A practice didn’t last very long because it didn’t happen as fast as we thought originally.
I would say this. I think if you look at this industry it tends to go in cycles. There’s a wave and then a lull, and a wave and a lull, and I think — my personal opinion is if there’s any one thing that
it’s correlated to, at least in the regulated utility industry, it’s around CEO retirement more than anything. That tends to set the trend. So if you have a kind of metric model to predict that, then maybe you could lay out when the next big wave is going to be.
From our sake, obviously, we are focused on getting the one that we just announced through.
Michael Lapides: Ian, cross border, how much synergy is there in the combination of creating more multi-regional North American, not necessarily just U.S. or Canadian, utility holding companies? What are the opportunities there that others may not be seeing? What are some of the potential pitfalls?
Ian Robertson: Well, and my first comment about synergies, you have to be very careful about synergies from a shareholder perspective or from a ratepayer perspective. From the shareholder perspective, we always think of synergies as really being rented to us if you will. We don’t own them; we only have them until they’re ultimately given back to ratepayers. And so we don’t think of the synergies so much as being sustainable value creation.
I think the differences between Canada and the U.S., I mean the Canadian utility landscape is dramatically different than the U.S. one, and I think arguably if you look at our organization, we are focused solely on the U.S. for the regulated business, so that probably speaks to the level of opportunities.
So having said that, the capital markets are different. I think the taxation environments are different. All of those lead to opportunities from our perspective to lever our competitive advantage. You mentioned earlier about cost of capital, and I’m not sure that we don’t enjoy a number of benefits that because of the fact that we happen to be a Canadian-based organization playing in the U.S. marketplace.
So I think there are opportunities, but they’re not necessarily generated by scale of synergy. That’s not what we see as sustainable if you want to think of it that way.
Michael Lapides: Can you talk a little bit more — you touched on the cost of capital advantage. And there’s going to be a lot of people in this room who know Canadian utilities well, but there are going to be others who don’t know them at all. Can you talk a little bit, for those who may fall in that latter camp, about what that advantage really is and kind of how it shows itself in the market today?
Ian Robertson: Well interestingly, and I think if you look at one of the most recent evolutions in the U.S. capital markets is this yieldco, emergence of yieldco. It’s really investor seeking yield, but that’s been a phenomena which has existed in the Canadian capital markets for a long time. And so dividend-paying organizations enjoyed great receptivity in the Canadian capital markets which lowered the cost of capital.
The other thing is frankly a different taxation environment, and at the end of the day we’re an earnings-driven company and having sort of an overall corporate tax rate in the mid 20s compared to high 30s depending on state taxes, definitely can be brought to bear if you want to think of it that way in terms of leveraging earnings, which in some respects is part of the driver behind M&A.
So I think there are a couple of factorial and structural issues which I think provide us as a Canadian competitor an advantage. I mean those things can obviously reverse, but right now they seem to be in our favor and are continuing to be so.
Michael Lapides: Chuck, I want to come back to the organic side of growth a little bit, but I want to stay on the distribution side. If demand growth remains below kind of the long-run historical averages,
meaning half a percent, maybe up to three-quarters, up to 1%, is the distribution — can the distribution business be a growth business in that type of environment?
Charles Jones: Well the first thing I’d say, I don’t think there’s an if. My first job with the Company was working in the capacity and transmission planning area, and at that time we projected low to grow at 7% per year because it’d done it basically since the inception of the industry. And then things changed and it didn’t happen, and it dropped to 3.5%.
And I think what we’re seeing today is real because there’s energy efficiency mandates that are driving it, there are federal manufacturing standards that are driving it, there’s fuel switching from electric to natural gas that’s driving it. So I don’t think that the question of if is the right question. It’s going to happen.
So then I think going forward you have to ask yourself how do you deploy capital in a way that’s good for customers, good for shareholders, and recognizes that that environment’s changed. And I think that’s all to the regulatory construct and whether or not decoupling might make sense in some cases or not, whether or not riders that allow more efficient recovery of that capital in real time. We’ve done that in Ohio and it’s worked very well.
I think you just have to think about the whole business a little bit differently with again, and I know I’m repeating myself, with an eye towards thinking about the customer here. Because at the end of the day, they pay the bills.
Michael Lapides: When you — when Tony Alexander, when Jim, when the Board looks at the suite of businesses within the FirstEnergy umbrella, you’ve got one business, the transmission business, that’s a very high-growth enterprise and will be for at least four to five years, potentially longer depending how Order 1000 plays out, depending on coal retirements and renewables driving the need for incremental transmission. You’ve got distribution which is in a rate case cycle now but faces, as you just commented, kind of lackluster normalized — a new and lower normal demand growth.
How do you all think and how does the Board think about kind of the sum of the parts, that would a series of smaller companies be worth more than a larger company that has a high-growth enterprise in transmission and a lower-growth distribution business attached to each other? And are they separable?
Charles Jones: That’s a good question, and we’ve talked about that a little bit recently. Back right after the Ohio Edison and Centerior merger, we formed ATSI. We formed ATSI with the idea of splitting it and selling it and got it all ready and all bundled up, and then thought you know, this might not be the right thing to do. And we held on to it, and it is now the growth engine. I mean we’re spending out of $1.3 billion of CapEx this year, about $900 million of that’s going to spent in ATSI.
So I think you go through cycles. I think for the long term, I’m not sure that that does make sense to kind of separate it, and I don’t think that they’re mutually exclusive anyway because as I said, I’m spending a lot of money to improve service for the distribution customer, because at the end of the day they’re all hung on that bulk electric system in some fashion or another. In Ohio, the 69-kV and the 138-kV transmission systems are where all the customer substations are hung off of, and that’s all within ATSI.
So I don’t — we don’t think about it as separate, and I do think that for the foreseeable future, we’ve talked about the next four years, but I think it’s a 15- to 20-year initiative to really modernize that part of the system. You mentioned Order 1000. I don’t even worry about it because the types of investments we’re making, no one else is going to come in and do. So it’s steady, it’s benefiting customers, and it will go on.
Michael Lapides: Pat, you talked about having to retrofit the fleet and that that’s one of your drivers when you think about rate-based growth, organic rate-based growth within the New Mexico utility. What happens when that’s done? And I’m actually thinking about Pat sitting next to you whose company went through a very similar thing. Not a retrofit, but a new build, and then when it was done, the growth level looked very different. How do you think about planning for that future because today, four or five years from now looks really far — the world can change five times in five years? I can’t predict a lot of things; that’s one thing I can predict.
I guess my question to you would be how and when do you start thinking about the what do I do when it’s done?
Patricia Collawn: Actually we’ve started thinking about that already because the time in our industry goes by a lot quicker than we think. So we look out and we look at grid modernization. We do not, for example, have smart meters in New Mexico. Our average monthly bill is $75 so it’s hard to justify a smart meter. Our average monthly bill will be higher by then because fleet modernization will cost money.
So we look at smart meters. We look at the ability to integrate more renewables because I think that is a trend that’s not going to go away, distributed solar. And so we say our distribution — or our distribution system is 50 years old, and while that doesn’t seem really old when you’re over 50, it’s old from an electrical sense. So we need to start modernizing our grid. We don’t want to do that while we’re asking for a lot of money for fleet modernization.
So when we look out there, there’s lots of growth opportunities for us in our own service territory. And obviously when the time comes you do the math exactly like how you all did it in terms of do we pay it back to our shareholders in dividends? Do we buy back shares? Do you buy another company?
But as far as we can see in our planning cycles, and we do go out past that four or five years, there’s growth opportunity out there.
Michael Lapides: Ian, when you look at U.S. regulated company opportunity sets, and given what you’ve described as your cost of capital or tax advantage, or the combination thereof, where are the greatest opportunities? Electric? And when I say electric, [PND], gas, other?
Ian Robertson: Well as a diversified modality utility in the water, gas, electric, and arguably I guess wastewater space, we’ve actually seen the pendulum swing around. To be frank, we are battling sort of I want to say stagnant demand growth in some of our service territories on the electric side, but seeing phenomenal opportunities on the gas side. I think the economic advantages enjoyed by natural gas are just creating a wealth of spinoff opportunities. There’s just a compelling economic reason to extend gas service to communities and businesses that don’t have it right now, which create investment opportunities.
So I’d actually argue right now that the natural gas utilities probably, at least from our perspective, have the greatest organic growth opportunities kind of baked into them.
As we have seen housing start to return, as Pat I’m sure knows, in the Southwest, you’re starting to see Arizona return to growth and the water business is obviously doing very well for us down there.
And I think — you had spoke earlier about diversification across states. I’d actually argue, I think we’re enjoying the benefit of diversification across modalities because these things do move
around and there are opportunities that change over time. And it’s nice to have a place to put money and redeploy that capital without being faced with that uncomfortable decision, do I give it back to shareholders. If you can do something better with it, than clearly that’s hopefully what they’re paying you to do.
So I don’t know if that’s responsive to the question, but we definitely see right now natural gas as the greatest opportunity for organic growth.
Michael Lapides: How do you think about the mix of businesses? We talked about this on the last panel a little bit, and you’ve got this, and Chuck, FirstEnergy does as well. Think about the mix of business in terms of your independent power business on one aspect, your regulated businesses here in the U.S. on the other. What are the synergies? Maybe what are the dis-synergies between the two when you think about them from an operating standpoint and then when you think about them from a value and value creation standpoint?
Ian Robertson: Well I guess right now we are totally comfortable with about the 50/50 split if you want to think of it that way between our non-regulated IPP business and our regulated businesses. They have very different characteristics. I’d argue that the non-regulated IPP business is very growthy in terms of the opportunity to create investment potential through your own efforts in terms of finding development projects.
On the other hand the regulated business is extremely credit supportive. I often joke that S&P have a soft spot in their calculably small hearts for the regulated business and it is — hopefully no one from S&P is here — but to have a significant portion of your earnings coming from the stability and predictability of the regulated utility business, it’s a great complement from our perspective to the opportunities on the IPP space.
So I’d say we’re totally happy with the 50/50, though I think everybody acknowledges M&A can cause that to — the lumpiness of it can cause that to swing around. But if I was king of the world, that’s how I’d have things stay.
Michael Lapides: Chuck, when people think about FirstEnergy and M&A, they kind of think back to the Allegheny transaction, but they focus a lot on what happened on the non-regulated side. I’d actually like to ask some questions on the regulated side. When you think about the combined companies post-integration on the regulated side, where were the greatest realized synergies? Where were the greatest opportunities that emerged as you combined the companies and said okay, from the regulated businesses, there’s greater opportunity than we may have thought when we first looked at this?
Charles Jones: Well I think the first clear place to look for those synergies is in the corporate support areas. We have one IT department that supports now three new utilities and it wasn’t substantially changed after that integration. Same with payroll, et cetera, et cetera. So the support services is one area.
I think one of the skillsets that we got in that acquisition, because Allegheny had just completed the construction of the TrAIL line, was the skillsets that are helping drive that kind of growth strategy on the transmission side today. And through that we got a lot of good people.
Beyond that, when you think about the utilities, I think you have to think about them as independent utilities. There are some benefits to customers that come from being the size that we are. We’re situated in an area where I can put lineman on the road and they can drive from any utility to the other utility in a seven-hour timeframe. And we have unfortunately had four very significant weather events. I quit telling our Board hundred-year events after the third one, but they were obviously significant. So I think that’s a synergy that came along with it.
But when you think about the individual utility, the investment decisions you make within that utility are based on the growth that’s occurring within that utility. In Maryland I see lots of growth. In New Jersey I see lots of growth. In Pennsylvania and Ohio right now, not so much, although I think that the whole Utica/Marcellus shale industry is going to be a long-term growth engine for us in Western PA, Northern West Virginia, and Eastern Ohio, but it’s just starting. But I think you make those independent decisions within those utilities based on different circumstances for each one.
Michael Lapides: I have an M&A-related question for you, Chuck. One of the interesting things we’ve seen when just looking back at transactions is among regulated companies, we’ve seen a whole mergers and acquisitions take place, Company A buys Company B, or Company A and Company B do a merger of equals. What we haven’t seen much of over the years, especially recently, is Company A selling Utility Subsidiary XYX to Company B without kind of whole lock, stock, and barrel transactions. Why is that? Is it because the opportunity isn’t there? Is it because there’s a dis-synergy somewhere in there for the buyer or seller?
And I think of companies like yours where you have big regulated subsidiaries in really big states where there are other big regulated subsidiaries as well, and even some smaller ones. But it’s been a while since we’ve seen Company A — I mean you see a little bit of it, but most of the M&A within the regulated space is full-on total company mergers or acquisitions versus spin or sale of this subsidiary.
Charles Jones: Well to me you had asked the question earlier about the rapid consolidation of the industry. And I don’t know what the definition of rapid is, but I can tell you growing from 1 million to 6 million customers in an 11-year or 12-year period felt pretty rapid as we were going through it. There’s a lot of work that has to happen.
I think if you think about it though, when you have to have FERC approvals and state regulatory commission approvals, et cetera, that process to do any kind of a deal is a complex process. So I’m not sure it’s really worth going through for something that’s not going to be a step change in the way you do business. Spinning off one part of one utility or one utility, I’m not sure that it ever makes — or that it will ever make sense given what you have to go through to make something like that happen.
Michael Lapides: In Wisconsin and, Pat, when you look at Illinois as well and the other jurisdictions, somebody touched on the opportunities. Ian, you touched on the opportunities on natural gas versus electric. When you think about that 5% to 7% kind of multi-year earnings growth rate target, does it differ much on the electric side versus gas? Have you broken that down and said you know, we expect the gas business could be above that and the electric business could be below that and it kind of averages out? How do you think about the differences in the earnings growth trajectories for the various subsidiaries underneath the broader umbrella and the various fuels?
Pat Keyes: Good question. I mean certainly we’ve got growth plans in all subsidiaries and service types that we think will benefit customers, but if you want me to go relative where we think a point of emphasis would be, I’ll echo Ian’s comment on the gas side.
I think we’ve got several phenomena at work across the two states. In Wisconsin, as an example, we are the fifth largest propane user, and that’s because of basically outside of the cities, everybody’s got propane tanks in their yard. And this winter, being as long and as cold as it was, people were running out of propane and what they could find was three times as expensive. So we have been asked and have been trying to accommodate our customer demand to accelerate our gas network into those rural areas, so that’s part of it.
New Mexico may be the Saudi Arabia of sun. Wisconsin has been called the Saudi Arabia of sand. And that’s because a lot of the fracking sand comes from the western part of the state. And why does that matter as a utility you may ask? Well, I’ll give you my Sand 101. Basically when you mine the sand, it comes out wet. And you put it in — it’s shipped by rail car. You pay by weight. So you’re better off drying the sand before you put it in the rail car. And the preferred method of drying sand is big industrial gas dryers.
So as a result of that, in the part of our state which is very rural, hasn’t traditionally had a lot of demand, we’ve had to extend gas laterals at the demand of the customers again to help provide that gas for those frack sand miners. So that’s another piece of it. That’s the Wisconsin side.
And in Illinois, gas demand is also strong, and that comes from the city of Chicago needing to replace 100-plus-year-old pipes in what Integrys calls the AMRP, Accelerated Main Replacement Program. That is a legislative rider that basically calls for a level of pipe replacement each year for the next 20 years. Combine the three and we’ve got quite a bit of gas demand. And that’s — so therefore —
I guess like, Michael, last year on the panel we also talked about is there a — I think your question was along the lines of do you see a change in the gas usage pattern for your existing customers? In other words, has the use per customer changed?
And if you look back to say 1970 with furnace replacement, each — these 60s, 70s, even 80s vintage furnaces were very inefficient, so as people replaced, their use per customer went down simply because their furnace didn’t burn as much gas to heat the house.
What we have also found, particularly with the lower gas prices, that in the — it’s not as expensive for people to turn their furnaces up another couple of degrees in the winter when it’s very cold. And as a result, that use per customer which is on a downward trend is now leveled out perhaps. It’s hard to tell. In the last three years, getting back to Chuck’s comment on the hundred-year weather, we’ve had a record warm winter and a record cold winter in two of the last three years. So when you normalize the demand out, it’s hard to tell if that use per customer is a long-term trend or short-term, but clearly something is changing.
So I think I’ll add that as a fourth reason then for the gas being a point of emphasis.
Michael Lapides: Is the — circling back a little bit, is the earnings growth trajectory for the gas businesses dramatically different than the electric, or are we talking kind of on the margin?
Pat Keyes: I think the short answer to that is on the margin. I don’t know if there’s — I could look at it and parse it out and say you’re going to see one like this and one like that. Others may have different experiences, but I give you mine.
Michael Lapides: Ian, I want to come back a little bit on the independent power business that your company owns and talk about what you think the optimal size and scale of that type of business would be and how you compare or think about what — how that differs from what you think the optimal scale would be for your regulated businesses?
Ian Robertson: Sure. The IPP business, not surprisingly, is a lumpy business where one is building multi-hundred-million-dollar projects at a time and there is definitely an economy of scale in terms of building 150 megawatt. Has about the same effort as a 25-megawatt project from a permitting and construction management perspective, and so you might as well enjoy the economies of scales of
making that project larger. And therefore there is a benefit from the size of the organization in terms of managing the financing.
Let’s say it’s a cost of capital in the IPP business is probably the most critical success factor given the relatively high operating margins or low operating costs associated with the IPP business. So for sure in the IPP business from our perspective, size does matter. And given that a typical 150- or 200-megawatt win project might cost $300 million, multi-billion-dollar organizations will definitely do better, if you will, than a smaller organization.
As the industry has matured, the risks that one needs to take in order to be successful in the IP business has got bigger. The requests from utilities, and I guess we’re a little bit schizophrenic on this because we’re on both sides of the equation there, but the requests from utilities for posting security for the PPA that they’re prepared to get into are not immaterial. You know $15 million and $20 million are not unreasonable sizes of security that needs to be posted.
So I would say that size definitely matters on the IPP side of the business. And if you want to be successful I’d say if you’re less than a couple of billion dollars in enterprise value, you’re going to have a hard time just competing against other organizations.
On the regulated utilities side of the business, I guess I’m a little less convinced, maybe a little bit more agnostic, on the issue of economies of scale. I said earlier that it’s my belief that synergies largely belong to the ratepayer, and in some respects so they should. And so perhaps those economies of scale are a little bit less important because really, let’s face it, the utility [compact] is about getting a return on — return of your invested capital together with your reimbursement of operating costs.
And while we’re in ten jurisdictions across the U.S., at no time has a regulator said to us I appreciate that those are prudently incurred costs, but you’re not as competitive as X, Y, or Z utility and so therefore we’re going to deny recovery. We’ve generally always got recovery of all of our costs, arguably being a smaller competitor and therefore potentially not having the same economies of scale.
So I guess I’d offer up that size doesn’t matter as much from our perspective on the regulated utilities side as it does on the IPP side. I don’t know if that’s what — where you were trying to get to?
Michael Lapides: No. And that’s actually a good path to take this. And Pat, when we think about your company with operations in both New Mexico and Texas, and you’ve made dramatic improvements over the last couple of years to the regulatory paradigm in New Mexico, I mean, very significant. May be understated how significant those changes are. How do you and the Board think about what your true cost of capital is? I mean how do you think — cost of capital is not a static point in time. It’s something that moves around every day, every hour. But how do you think what your true cost of capital is at this point in the cycle and how that kind of — how you expect that to evolve over time? And time meaning the short term, next one, two, two to three years?
Patricia Collawn: Well our cost of capital has obviously gotten a lot better as we have gotten financially healthy. And we were in the unregulated businesses for a while.
When we think about our cost to capital we think about sticking to our knitting, keeping our credit ratings where they are. We go through and do the math and say you know if we got upgraded to an A does that make a lot of difference in the cost of capital? In today’s world the answer is probably not.
And so we keep an eye on it. We make sure that our regulators understand that their actions have an impact on our cost of capital, directly related to that cost of capital, and that the lower cost of capital is better for our customers.
And then we don’t worry that much about it because we know as long as we’re doing the right things, to Ian’s point, and we’re prudent, if the cost of capital happens to go up we’ll be able to recover that.
We’re also very fortunate in New Mexico, we have a forward-looking test year now so when we file our next rate case this year, we’ll be able to incorporate forward-looking cost of capital. So that’s very helpful when we think about where we should be on that cost of capital curve.
Michael Lapides: Pat, having just announced the Integrys transaction the last couple of months, where do you find when you talk to investors the biggest misunderstanding is by investors about what the M&A opportunities are and maybe are not in this space?
Pat Keyes: I think, and Chuck alluded to it, I think the biggest misunderstanding is the length and nature of the approval process in the regulatory — in the regulated industry. We had a bet on when we were going to get the first question on when’s your next one, and it was like on our road show right after we announced. People are like well that’s good, but almost set it aside and what else is out there? We’re in the new world. You’ve got to keep —
It takes a lot of time to work through that, to work through the various jurisdictions and peoples’ concerns and get the employees comfortable, et cetera, which is slightly different, but still. So I think what’s behind the curtain is something that’s perhaps a little better understood when you’ve lived it than when you’re sort of looking on the outside.
Michael Lapides: Ian, and I’ll bring this to you first, one of the folks who’s emailed in a question, and I’m going to remind everybody, after this one we’ll open it up for Q&A. We can do this old school. People can raise their hand and someone with a microphone will come around to you, or you can please feel free to email them in to our live current system so it’s just livecurrent@gs.com and then just hashtag pump. I think the address is on the screen behind me.
Ian, when you look at the opportunity set on your non-regulated side, how are you looking at — where do you think we are in terms of the valuation of different types of assets for independent power assets as well as just broader corporate valuations in the market for independent power companies?
Ian Robertson: Well when you mean different types of assets I presume you’re meaning different modalities, wind versus solar versus natural gas. I might offer up the observation that wind, this last decade has kind of belonged to wind in terms of maturation, evolution, reductions in the [low-life] cost of energy due to improvements in size and cost competition.
But I’d offer up that I think it’s our belief that the next decade will actually belong to solar. And so we’re a little bit on that crossover point right now. I think if you look at the U.S. today, wind and natural gas clearly from our perspective are the right modalities in terms of the economics and in terms of the characteristics. And so we think we’re at a good place, at least in the wind, at least on a dollar per kilowatt-hour basis. And you might argue well that kilowatt hour only comes when the wind blows. I get it, but on a dollar per kilowatt-hour basis all in, you can build a wind project for like under $0.05. And I think that’s an interesting observation to say I can get 25 years of energy which is non-fossil-fuel exposed for under $0.05. And so I think we’re believing that wind is at an optimal point from a value perspective going forward.
I think if your question is from an asset or a corporate perspective, I’m not sure that at the end of the day a corporation adds a lot of value to that asset. There really is very little opportunity to optimize the operation. The operating costs of renewable generation is relatively small and so I’m not sure I see a real value difference between an asset being owned by one company versus another company.
Cost of capital is clearly at the end of the day the biggest driver from our perspective in terms of creating value in the IPP space. If your money is cheaper, that project is definitely worth more to you than it’s worth to the next guy.
Michael Lapides: Chuck, I’d like you to kind of touch on that piece. And I know, less the valuation piece and more the what is having a larger multi-fuel but definitely more size and scale of a fleet mean for opportunities to manage the fleet in a more efficient way versus kind of some of the comments that Ian just made about the impact of having it under — it’s really just how much does scale move the needle on the non-regulated side?
Charles Jones: Well since I don’t run the non-regulated side, it’s a challenge. But I will tell you as you think about the size of the fleet and the fact that we do have diversity in the fuel makeup of our fleet, we don’t have a lot of renewable, but we’ve got 450 megawatts of wind inside that portfolio. And I think the scale gives you an opportunity to deploy capital by looking at the fleet as a whole and to move it around within different timeframes.
We just announced that we’ve made some decisions to delay a steam generator replacement at Beaver Valley II. We have the ability to do that and use that capital elsewhere, potentially maybe for the dewatering facility at the Bruce Mansfield Plant, et cetera, et cetera.
I think it gives you flexibility to look longer term and make decisions on a broader scale that are fleet-type decisions.
Michael Lapides: Pat, your fleet retrofit decisions for the New Mexico utility, how do you think through the retrofit versus buy decision versus build? I mean you’re in a state where there’s still merchant assets in the state or in the region that can dispatch into your service territory. Some of them, not all. How do you think through the what’s the most optimal — what’s the easiest fix, because a lot of the work you’re doing is to meet environmental standards? So A, what’s the easiest, least complex answer? And B, what’s the most optimal from a cost and from a potential growth answer?
Patricia Collawn: I’m going to answer the second part of your question first. The way we went about thinking about it is what’s the lowest cost for the customer?
And so you can naturally tumble to well, as you said, there’s a lot of merchant assets out there. We have bought some merchant assets in our state that we had PPAs with. We’ve bought them. Our regulators like us to own our own generation. They know we’re going to run it better in many cases, make sure it’s efficiently maintained, and we can bring it in so that there’s no impact to the customer.
Then we start looking at over the long term what kind of regulations are coming down the pipe because any one regulation doesn’t change your decision in a fuel, in a diversity. It’s Regional Haze plus carbon rules plus the next set of [NOx] rules. And we try to think 10 to 15 years ahead on the regulation. And then we say what’s the best out there?
To your point, there’s some merchant assets, but many of them are in Arizona. The transmission in the West is not that easy to get it back across into New Mexico. However, we happen to own
134 megawatts of Palo Verde that’s not — the nuclear plant is not in our rates. So we look at bringing that back into our rate.
So we really looked at it in terms of what’s the cheapest cost for the customer? Where do we think our regulators would be happy? And what’s going to put us in the best stead for the next set of environmental regulations? And for us, fortunately that equation worked out to be filing to bring some merchant assets in our nuclear and buying some of those merchant plants in our state.
Michael Lapides: Okay. Last go around. If there are any questions please, either raise your hand or email them in. I’m going to do one last one and then we’ll wrap up the panel. When you think about the next five to ten years and how M&A opportunity sets differ versus what we’ve seen for the last five or seven years, and crystal balls aren’t perfect. No one has one. If they do, I wish they’d call me. How do you think the M&A opportunity set changes over the next five to seven years? And I guess I’ll ask — I’ll start a little bit with Ian and then I may turn to Pat Keyes because you both have been relatively active in that space over the more recent and over the last couple years and we’ll go from there.
Ian Robertson: Well I think from our perspective the past, even shortened over the past two or three years, the focus on M&A has driven premiums up dramatically. You look at just some of the utilities that got sold. In Pat’s state you watched TECO buy, and in Missouri and Alabama, the prices of those utilities have to cause you to think twice about am I creating value. Because at the end of the day, the question one asks oneself with M&A is are these two businesses somehow better together than they are apart? And given what I have to pay to bring them together, am I going to create that value back.
And I’d say that’s a tough proposition right now. I mean I think I totally get the thesis between WEC and Integrys. I mean I understand that. But as you think about just broad M&A, you mentioned earlier Company A buying Company B, man, you’ve got to have a story beyond just bigger is better from our perspective. And it’s how do I lever those opportunities? Am I creating synergies for investment that exist?
And so I would actually argue for — as I look forward for the next while with the current M&A market, that really the value creation for us is on the organic side, and it’s first prize. On the utility side you get put at dollar for dollar without paying a premium. On the power side, on the IPP side, you’re creating that value to the development cycle.
And so I’ve got to say that as we stare at the M&A environment right now that I think the greatest value creation for us is on the organic side of the business going forward for the next while. I mean it’s a pendulum. Everything changes, and so — but today I think that would be my conclusion.
Michael Lapides: And Pat, since announcing the Integrys deal, I’m going to change the question a little bit, how has that changed, if at all, your outlook on kind of what you think industry-wide M&A may look like over the next five or seven years?
Pat Keyes: Let me start my view of the industry for what it’s worth and then I’ll hone it in to us. I mean I think if you look at the history of this industry with the cycles, I think a wave plays out and then people watch. What concessions were given? So be thinking if this happens, then the next group is going to take what was — the concessions that were there and may add on, so I’ve got to factor that into my math.
If the — with the higher premiums, did the people that made those buys and looking back three, four, five years, was it worth it to them? And if you see accretion, people might view that
differently than if you look back and so no, it put them in the tank. They’re never going to get out of it. And that to me will drive your next five to seven years is kind of the studying and the look-back.
As it pertains to us, I said it earlier, our first order is to get what we’ve announced approved, get it organized, get it ready. And we are very pleased with our own organic growth story, and that’s where we’ll be looking in the short term. But five to seven years, who knows?
Michael Lapides: All right. Real quick, I want to — first of all I want to thank all four panelists. Appreciation willingness to discuss, and a lot of times there are folks in this industry who don’t really want to openly discuss M&A. Very, very helpful. Very insightful.
Real quick, before we wrap up, we’re going to take about a 15-minute break. We’re then going to come back. We’re going to have our one technical session, and this is an interesting topic because the EPA-proposed first draft regulations for greenhouse gases, for carbon dioxide emissions from the power sector. And I think one of the best ways to get insight into this is talk to folks who work for the various trade groups, who work for the various industry economic consulting firms, who’ve done a lot of work on what these type of regulations mean.
So at 10:45 we’ll come back and we’ll have Sam Newell who’s a principal with the Brattle Group, one of the leading economic consulting firms, talk about his firm’s first look, first view of what the GHG emission rules might mean for the U.S.
And with that, I’m going to wrap this panel up. I want to thank our four panelists. We’ll take a 15-minute break, grab a coffee, and we’ll come back in. Thank you folks.