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CMS Energy Corporation (NYSE: CMS ) Q2 2015 Earnings Conference Call July 23, 2015 8:30 AM ET Executives D.V. Rao – VP, Treasurer, Financial Planning & IR Tom Webb – EVP & CFO Analysts Julien Dumoulin-Smith – UBS Dan Eggers – Credit Suisse Jonathan Arnold – Deutsche Bank Paul Patterson – Glenrock Associates Operator Good morning, everyone, and welcome to the CMS Energy 2015 Second Quarter Results and Outlook Call. This call is being recorded. After the presentation, we will conduct a question-and-answer session. Instructions will be provided at that time. [Operator Instructions] Just a reminder, there will be a rebroadcast of this conference call today beginning at 12 P.M. Eastern Time running through July 30. Presentation is also being webcast and is available on CMS Energy’s website in the Investor Relations section. At this time, I would like to turn the call over to Mr. D.V. Rao, Vice President and Treasurer, Financial Planning and Investor Relations. Please go ahead. D.V. Rao Good morning and thank you for joining us today. Our earnings news release issued earlier today and the presentation used in this webcast are available on our website. This presentation contains forward-looking statements which are subject to risks and uncertainties. These statements should be considered in the context of the risks and other factors detailed in our SEC filings. These factors could cause CMS Energy’s and Consumers’ results to differ materially. This presentation also includes non-GAAP measures. A reconciliation of each of these measures to the most directly comparable GAAP measures is included in the appendix, and posted in the Investor section of our website. Now, let me turn the call over to Tom Webb, Executive Vice President and Chief Financial Officer. Tom Webb Thank you, D.V., and good morning everyone. Thanks for joining our call. As always, we deeply appreciate your interest in our company and for spending time with us today. And John sends his regrets that he can’t join us today. He is recovering from a medical procedure and we look forward to his return in a few weeks. I know he’ll miss fielding your questions today. So we’ll begin the call with an overview of the quarter and provide an update on the legislative process, before turning to more detail on the gas business, the fast half and our growth model, and then we’ll close with Q&A. For the first half of the year, adjusted earnings per share were $0.98, down $0.07 from last year but up $0.03 on a weather-adjusted basis, were $0.13 ahead of plan. Today, we’re reaffirming our full-year adjusted earnings per share guidance of $1.86 to $1.89, and as you know, this reflects real growth of 5% to 7% of last year’s actual results. We filed our gas rate case last week for $85 million. Like our previous cases, it’s small and primarily driven by capital investment. Even with this rate case, we expect total customer bills to decrease in 2016 due to lower gas commodity prices. Last month, we self-implemented our electric rate case at $110 million, and we expect an order for this case in December, which would mark 2.5 years since the last order. Our predictable growth has continued over that time and we have self-initiated many cost reductions to keep prices low for our customers. Here you can see the impact of our actions along with constructive regulatory environment. Our industrial rates are at a competitive level that’s attracting new business to the state. Rates could be improved further with changes to ROA policy, creating a competitive advantage for Michigan’s business in the Midwest and in the country. As we’ve improved industrial rates, residential bills have remained low at about $3 a day. Recently we committed do more in Michigan and help grow businesses. Our spending on in state goods and services will be $1 billion per year over the next five years. By helping to make Michigan a competitive state in which to do business, we are seeing growth. In Grand Rapids, the largest city in our service territory, housing, GDP, population growth and unemployment are all better today than Michigan as a whole and the U.S. Overall, Michigan is moving towards becoming a top 10 state and Grand Rapids is leading the way. Michigan’s energy law update can help to drive this growth. Bills are now in committees with the house and senate. Recently Senate Committee Chairman Mike Nofs introduced a comprehensive bill after considerable research and debate. The Senator’s bill proposes to keep the ROA cap. However, the bill stipulates stringent requirements for both, ROA suppliers and customers. In order to protect all customers from reliability and price volatility, the supplier would be required to procure a minimum of three years of capacity. And ROA customers who decide to stay with alternative suppliers would be required to provide a three-year notice prior to returning to bundled utility service. Once the customer returns from ROA, they are no longer eligible to switch back. These policy leaders are broadly in agreement with the integrated resources plan process which would give the state the flexibility it needs among many things, to enable investment in needed new generation and comply with state and federal environmental regulations. The IRP would replace the existing certificate of necessity process with a more comprehensive longer term decision making process. The IRP would provide us with the assurance of recovery and allow us to plan capacity resources for a decade or more. This transparent process could include new gas capacity, renewables and efficiency programs. Now on the regulatory front, I’m please to highlight the Governor’s announcement yesterday of the appointment of Norm Saari as a new Public Service Commissioner. He has a long track record of public and private service in the utility sector and public policy space. We look forward to working with him. We continue to look at and evaluate new investment opportunities that could increase the capital spending in our 10-year plan. When we look at these opportunities, we evaluate each one by asking, does it add customer value; does it reduce O&M cost; does it help balance our fuel sources and/or is it mandated by state or federal regulations, and none of our investments in the plan or those identified as opportunities are big bets. Our gas business is one of the larger distribution systems in the country. This scale provides many investment opportunities for additional growth. We’ve been upgrading our compressor stations, installing new transmission lines and replacing aging infrastructure. We could do more and we could accelerate the pace. Our plan calls for doubling gas investment over the next 10 years. This brings our investment mix to over one-third gas. Our customers benefit from the safety, reliability and cost effectiveness of the gas plant. If fuel costs remain low, additional headroom will allow us to make these investments without impairing price. On average, our gas customers spend about $2 a day. That’s equal to their bill in 2004. Now here’s a little more detail on our results. For the second quarter, our earnings were $0.25 a share on both, a reported and an adjusted basis. This is a nickel below last year or a penny on a weather-normalized basis. Weather in June was the mildest in 15 years. Cooling days where 50% lower than last year. Economic sales also were flat as one substantial low-margin customer came through a temporary supply interruption. For the first half of the year, our results were $0.98 or $0.86 on whether-normalized basis. That’s $0.03 better than 2014. And at the mid-year checkpoint, we are $0.13 a share or 15% better than our plan. We have lots of room to move. As you can see here with first half weather-normalized earnings up $0.03, we’re positioned well. Even with a nickel of cost in the second half associated with new mortality tables and lower discount rates, our cost reductions of $0.12 more than offset this. For the full-year, costs are down about 3% and new rates already have been implemented. At mid-year, our earnings per share is $0.13 ahead of plan, and like last year and many of the years and the decade prior to that, we added substantial customer reliability work and still plan to hit our 5% to 7% guidance. O&M reinvestment of $18 million is underway, including more forestry work at the utility and accelerating a planned major outrage at DIG from 2016 into this year. The DIG pull ahead accomplishes a double benefit of accelerating the DIG outage cost into 2015 when we had ample room to absorb it and bringing up capacity in what will be a very tight market in 2016. In addition, we’ll be increasing DIG’s capacity by 38 megawatts and these reinvestments could add $20 million to profitability next year. From time to time, some of you ask us, how we accomplish consistent earnings growth year-end and year-out and how we do it without raising customer rates above inflation. As you know, we have a robust capital investment program and a substantial opportunity to increase it. However, we build our investment plan starting with customer rates growing no faster than inflation. And here is how we do that. Our O&M cost reductions worth about 2% a year; conservatively forecast sales growth of about 0.5 point a year; avoidance of block equity dilution worth about a point and other self-funds five points of investment. This permits earnings to grow 5% to 7% and customer rate impacts stay below inflation. Here is our capital investment program for the next 10 years. Investment in our gas business grows substantially. Investment in our electric business continues to grow too but at a slower pace. And please remember that our earnings growth is not predicated on sales growth or cost reductions. Upsides from these are directed to our customers. Even without any upsides, our capital investment program over the next 10 years will be 45% larger than the last 10 years. As a percent of market cap, CMS investment was 10% over the last 10 years. It’s 16% over the next 10. This exceeds peers. The opportunity to increase that investment by as much as $5 billion to over $20 billion continues to be practical, particularly when many of the investment opportunities do not increase customer bills. A lot of the capital investment we put in place enables us to reduce O&M cost. These are down 10% since 2006, and we’ll reduce these costs another 7% by 2018. There is no magic to this cost reduction program. It’s simple. Natural changes in our business like coal to gas generation and Pole Top Hardening make the difference. Here is more detail around cost reduction actions, down 6% in two years as we switch from coal plants, which requires substantial number of people to operate, to gas generation and wind firms, which require about 10% of the workforce needed to run coal, we’ll be able to reduce our O&M by $35 million. By continuing our program to harden our Pole Tops, we reduce future storm-related damage and we capitalize rather than expense that work. These are just a couple of examples of how we’ve reduced our cost 3% last year and are in the middle of a program to do another 3% this year. Since 2006 through 2014, ours is the only utility to reduce its cost, down almost 3% a year. We forecast reductions perhaps conservatively at 2% a year between 2014 and 2018. The outlook for the economy in our utility service territory continues to be bright. As you can see here, many companies from a variety of sectors have announced new factories and businesses. This will add new growth of almost 3%. Despite this, we continue to plan conservatively, including overall sales growth at about 1.5% over the next five years and industrial growth of about 2%. While this is another opportunity in our model to minimize customer rate growth, there may be a little upset. One more element of the self-funding model that promotes robust rate base and earnings growth without allowing customer rates to grow faster than inflation is the benefit from a large stockpile of NOLs. Typically a utility would lose about 1% of its earnings growth through dilution associated with new equity to fund growth. In our case, we’re fortunate to be able to invest our cash in utility growth rather than taxes avoiding full points of dilution. So the model is simple and perhaps it’s a little unique. We start our planning by keeping nominal customer rate growth below inflation, or in other words, we provide real rate reductions. With cost reductions, modest sales growth, no block equity dilution and shrinking surcharges, we’re able to grow rate base by 5% to 7% and with substantial opportunity to do more. Many of our capital investment opportunities not yet in our plan can be accomplished without any increase to customer bills. This includes replacing PPAs as they expire and the potential that customers on ROA may return to bundled service, creating more headroom to pull ahead incremental capital investment. So here’s the PPA example of growth not included in our plan. We have more PPAs than our peers, and as they are replaced, we’re able to build new gas generation at a cost that’s lower than the existing PPAs. What a nice way to grow our business and provide reliability for our customers without increasing their bills. And here is the opportunity should ROA customers choose to return to bundled service. As they return, which may be a better economic choice for them, all our customers can experience rate reductions of about 4%. This provides headroom for more investment to meet customer needs. Think of it by replacing expiring PPAs and building for returning ROA customers, we’d add 3,000 megawatts of new generation that’s not yet in our plan. And this is without increasing customer bills at all, a clear win for our customers and a clear win for our investors. You can see the need for new generation in MISO’s most recent report. MISO updated their 2016 capacity forecast showing MISO will be short 1.5 gigawatts in Zone 7 by spring. With our newly purchased Jackson gas plant, we can provide sufficient capacity for our bundled customers. We can’t however be sure if AES suppliers can do the same for those ROA customers. And by the way, our mix of coal field capacity has been reduced from over 40% to a third today, and as you can see in the appendix slide with coal plant closures next year, the mix will be below 25%. With our business model, we’ve been able to deliver consistent earnings growth of more than 7% each year for over a decade, through recessions, through adverse weather, through changing policy leadership and through anything else that came our way. As we do, we hope you to see this as a sustainable model for our customers and our investors for a decade ahead. As you can imagine, with this consistent investment growth, our operating cash flow as a percent of market cap has gone from less than our peers five years ago to greater than our peers today, with prospects that additional growth will provide an even larger cash flow. This is a nice place to be providing resources for the future, resources to invest more for our customers, more rate base growth and/or improve capital structure. So here is our sensitivity chart that we provide you each quarter to assist you with assessing our prospects. In this time of rising and volatile interest rates, it’s comforting to know that our model is not very sensitive to changes in interest rates. At the utility, higher borrowing costs related to higher interest rates is largely offset by the impact of higher discount rates on our benefits and retiree programs and perhaps a higher return on equity in the future. At the parent, our practice includes pre-funding parent debt two years in advance and maintaining a smooth maturity schedule. This insulates us from substantial risk to change in interest rates. If for example interest rates rise from our plan by 100 basis points, the annual earnings impact would be less than a penny a share, and we already include high interest rates in our 10-year plan. Here is our report card for 2015. We’re in a good position and at the midway point with substantial benefit from the Arctic blast earlier in the year and better-than-planned cost reductions so far this year. We’re putting the surplus to good use with reliability improvements for our utility customers and we’re accelerating outages to enhance the outlook for 2016. Continuing our mindset that focuses on customers and investors permits us to perform well. We hope you agree. We’ve achieved substantial improvements in customer value and customer satisfaction. We have the best cost reduction track record in the nation. We are in our 13th year of premium earnings and dividend growth, and we plan to continue this performance for some time. So thanks for your interest and your support. We appreciate your calling in, and we’d be delighted to take your questions. So operator, would you please open up the line? Question-and-Answer Session Operator Certainly, and thank you very much Mr. Webb. The question-and-answer session will be conducted electronically. [Operator Instructions] We’ll pause for just a second. Our first question comes from Michael Weinstein with UBS. Your line is open. Julien Dumoulin-Smith Good morning, it’s Julien here. Tom Webb Good morning. Nice to hear your voice. Julien Dumoulin-Smith Likewise. So I suppose first quick question if you don’t mind, just with regards to legislative developments. Just to be very clear about expectations. As far as the latest proposals from Nof moving through this summer, is that still in line with what you’re expecting in terms of return to ROA and return to customers? Tom Webb The bottom line is yes it is, and I would just comment, keep in mind that we’re not planning on any return in our financial plans that you see. That’s kind of all of an upside. We suspect as the policymakers work through this during the summer months and do something before the end of this year that from an ROA standpoint, there may be an economic opportunity that comes out of the law where customers will decide it’s probably better to be with bundled service, because they are likely to have to secure not only energy but capacity as they go forward. And to do that, they may find bundled service a better place to do, and that’s exactly what we like. We like seeing them make the right economic decisions. So the answer again to your question is yes. Julien Dumoulin-Smith Great, excellent. Perhaps coming back to the cost-cutting efforts. Just to be clear, how are you setting up in the next or I suppose the pull forward isn’t quite happening to the same extent. What are you thinking year-over-year? Just I know you have a broader confidence in your 5% to 7% growth rate, but how do you think year-over-year in terms of cost-cutting effectiveness? I know it’s a little early but just kind of curious. Tom Webb Well, we feel very good about what we’re doing. As you recall, I mentioned that we’re ahead of plan already. You can see that on the reinvestment slide when you have a chance to peek at that. You’ll see our cost savings are better than what we anticipated to the extent of about four or five pennies. So that’s pretty good. That’s a big number. So the plans for this year are good. The reinvestment will continue. Now if I told you how much we’d reinvest at the end of the first quarter call, it would be a lot more. And what I tell you at this call because of the cool weather that we had in June. But when you look at that reinvestment slide, you still see we’ve got lots of room to move and lots of decisions to head, to tailor into what are the right places to put our money and still deliver for you on the profits. Julien Dumoulin-Smith Great. And a last little detail. As you’re assuming we get some developments on the legislation in forthcoming periods, how swiftly thereafter would you anticipate making a filing or talking about new generation construction just in terms of a timeline since we’re coming up against here potentially seeing this legislation going forward? Tom Webb Yes, a little premature to say exactly what we do because we need to see what the final shape of the plan is, but think of it in two fashions. There will be – likely be this new IRP process. So that will have work done by the state to start planning where we need to be to meet PPA requirements, to do our own state requirements on environmental, all of that. That will be followed by the official IRP process. So that will take a little while. So I suspect what you’ll see in the law are some bridging actions. Now I’m just speculating, but take something like energy efficiency to ensure that we continue to do the good work we’re doing today, there may be a little bridge that says you continue on the program you have today for a period of time before you go into new things. Is that sort of thinking that wants me to hesitate a little bit on how soon we say we’ll announce new capacity, part of it will depend on how the ROA plan goes, returns to customers, part of it will depend on the needs of what may come out of the EPA in August and September, maybe more renewables. So we’ll put all that together, be talking to the regulators and policymakers and then probably have something if you made me guess early next year to give you a sense of where we think we’re going and what our proposals are. Julien Dumoulin-Smith Thank you very much. Good luck. Tom Webb Julien, thank you. Operator The next question is from Dan Eggers of Credit Suisse. Your line is open. Dan Eggers Hi. Good morning, guys. Just extending on Julien’s question about the IRP process. Can you maybe walk through how you see it working as best you can tell right now, working with the commission to kind of layout the parameters for renewables, for efficiency, for conventional generation? And then with the shortfall in ‘16 in Michigan, even with the MISO updates, how you go about trying to resolve that in the context of a bigger policy goal? Tom Webb I’d be glad to do that. First of all, think about what we’ll do. We’ll make sure our bundled customers are covered. So from a capacity standpoint, we’ve got a lot of optionality, even though the state is going to be sure probably at the least the Lower Peninsula [ph] and the spring of next year, we will have tools to take care of our folks. What we’re uncertain about and part of what the law is about is who is going to take care of the ROA customers. Is that something that the AESs are willing to do economically with those ROA customers or it’s something where we really do need to step in for long-term planning basis. So here are the steps. First, the public service commission will put some parameters together for the IRP filings. So it will take a little time to do that. Second, within a couple of years of the enactment, there has to be IRPs filed. So you see there is a little flexibility in there, but that’s the next step, and that will include a long-term outlook. And then before we file an IRP, if you follow the bills the way they are structured today, we would do bid an RFP to make sure we understand what’s out there in the market that we would factor into our plans. Now you might think of that as, what does that mean? You’re not going to able to build thing. I wouldn’t think of that at all. I’d think of that as the common sense that we use. Remember, we were about to build a new gas generation plant in [indiscernible], and instead we twice went out on our own to check the market. And in the second check, which was last December, we found, my goodness there is a far better deal for our customers. So we were thrilled to put that in place and did that, change our capital investment totals at all? No, because we backfilled with things that we can’t fit in today with things that needed to be fit in it and so that worked just perfect. So then when you get into the RFP process, there is they call it a shot clock, interesting a little basketball hooper is in here. There will be a 270 day process for that to go through. So you see that’s a little bit of a long process, and therefore there will be some bridging in between on several issues which could include energy efficiencies, it could include a bridging around generation plants where the existing con might be used as a quick process to cover needs in the future and not have to wait for a year or two or so to make those decisions. That’s all up in the air. That’s all the kind of discussion that’s happening this summer, and everybody seems to have their heads screwed on very right to make sure that the state and our customers are taken care of. That makes sense? Dan Eggers It does. Now let me ask the simple question which is when we sit from the outside looking at next year, what should we look from you guys as far as how you address the shortfall in Michigan for ‘16 and ‘17? Tom Webb Well, two points. First point, remember, we are inside of those numbers you see. We’re covered. We have adequate plans in place to take care of all of our bundled customers. If for some reason there was an emergency and I’ll do a theoretical thing, all ROA customers chose to come back to bundled service right away, we would find short-term measures to cover that and think purchases on the market, think use of short-term PPAs, think DIG, think all the list of options like that, there are many. So short-term, we could be in very good shape. Longer term, we want to plan for more certainties. So what we would work on is how to put more permanent capacity in place in Zone 7, so our customers will essentially own their generation as opposed to renting it. Dan Eggers Okay, got it. I guess one last question, Tom. If you could just – what do you see as the kind of the big bridge drivers if we look at the second half of ‘15 versus ‘14? I think you probably need to make $0.15, $0.17 more in this second half than you did last year. Just what are kind of the chunky pieces you see helping to get to that number? Tom Webb Yes, that’s a good question. If you can, if you’ll refer to slide 12, you will happen to see sort of the best roadmap, but I think it’s in the slides first half, second half. When you look at the second half, we already have programmed in actions that give us lower O&M, and that’s in the $0.12 that you see, that’s largely what that is. And those are all underway, so there is no like new cost reductions that desperately need to be found. And then you’ve got the mortality tables that are the full-year effect. You remember it was $45 million, so just the portion that impacts in the second half is about a nickel of bad news. Then you got rate release and everything else. Remember, just about all of our rate release that we’re talking about is really second half. So think of the electric rate case as an example. On the electric rate case, we just self-implemented. So we’re actually collecting that. We get all that upside as we go through the second half of the year, something we didn’t have in the first half of the year. So I would tell you there is a lot of natural things like that, that don’t require a lot of wishing and praying or worrying of any kind. And then have you think about slide 13 that shows the reinvestment plan. We’re actually still in the mode of looking where we deploy our resources in steps throughout the course of the year to go from $0.13 better than planned to what would leave you with a good 5% to 7% earnings growth. So we are in, I’d say great shape. This is actually a fun place to be. It’s little tougher when it’s the other way like it was about three years ago when we had a really mild winter and we had a fine $0.13, which we did, and as you know, the actuals speak for themselves we’re in great shape. So not a lot of pressure for us, but you can see our normal cost reductions coming in place. We’re now getting rate release in the second half. We didn’t have in the first half. And so the comps, I guess, are a little busy easier if you look at it that way. Dan Eggers Great. Thanks for time and best recovery wishes for John, please. Tom Webb Thank you for that. Thanks Dan. Operator The next question is from Jon Arnold with Deutsche Bank. Your line is open. Jonathan Arnold Hi, good morning. Tom Webb Good morning, Jonathan. Jonathan Arnold Just quick question on the slide where you show the 6% to 8% opportunity versus 5% to 7% in the plan. Tom you mentioned – you have sort of short-term and long-term labels there. Can you just – it seems like you’re going a step further towards raising the growth rate without actually doing that. How do you think about short-term, and are you meaning to imply that in the next year or so we could be there? Tom Webb I think that’s fair enough. There is a mix of things, some of which are short-term and some of which are a little bit longer term. So when you think about the generation side of things, those are a little bit longer term adds into our plan, but there is plenty of short-term things to do as well. And I’m actually going to take you to slide that you prefer not to be taken to I think, instead of the one you’re talking to, and that’s slide 13 which shows the reinvestment curve again. Here is the best way I can encourage everybody to think about this. There are some very important things we don’t have to do but we sure would like to do for our customers. Tree trimming is one of the simplest explanations I have. Our tree trimming cycle is closer to 10 years and it should be closer to five or six years. So the commission is kind enough to give us a little bit more with each rate case and then they know every time we can find an opportunity to do a little bit more when we have good news from cost reductions or weather or whatever it is, we also do a little bit more. What I would caution everybody is, yes, underneath we could probably be growing a lot faster than 5% to 7%, but inside as long as we have that opportunity to do these important things for our customers, we’re going to do those, and I think there will be things like that to do certainly this year, and I think certainly next year, and then we’ll talk about the future after that and that’s not a hint up or down, we’ll just talk about that a little bit later. The other thing it does for us is by doing this work like the DIG pull ahead and like more tree trimming and whatever, it actually makes it easier for us to deliver the next year because our customers are better off, we pull cost ahead that would have happened in the next year or the year after, but it makes it easier for us to deliver the good results that you need to see. So no move from the 5% to 7%, certainly not today. Jonathan Arnold So the – you do at some point run out of things that you can accelerate like will you catch up on tree trimming and is that part of the motivation for putting this opportunity number out there? Tom Webb Well, we get asked the question enough that we wanted to show with the investment profile how easy the model works. So if we had more investment, we can do that without putting stress on our customers and still give them average rate increases that are less than inflation. That’s the point. The point is less so to say, look for 6% to 8% earnings growth in the near-term, just know that the capacity is there, but our desire to use that capacity this year, next year and who knows beyond that is important and it’s paying off. It’s paying off for our customers, and then indirectly it’s paying off big time for all of our investors by allowing us to have that happy customer group as well as to be able to deliver that 5% to 7% every year. Jonathan Arnold Okay. So can I just – one follow-up on that, Tom, the NOLs. Can you remind us how much runway you still have on NOLs and how – when those end out of that sort of – how does that fold into the longer term growth outlook? Tom Webb Yes, we’re good on NOLs for several years to go. The gross NOLs are near $1 billion still, and remember, then you got to net that for the tax effect. And I believe in your appendix you do have our operating cash flow slide, and it will show you in the bottom bright yellow bar when anybody gets a chance to look at that, that NOLs and credits are still positive and available all the way through 2020, and the NOLs are used up a little earlier than that depending on bonus depreciation and depending on other tax things. But at this point, we’re still pretty comfortable telling you, we can go five years without any block equity because of that tax opportunity. I’m a little embarrassed because every time I – once a year I have to explain to you it has to go out another year. Probably five years ago, I think we were telling you that we had five years to go and today our time is up, but fortunately we have another five years to go. Jonathan Arnold Great. Thank you, Tom. Tom Webb Thank you, Jonathan. Operator The next question is from Paul Patterson with Glenrock Associates. Your line is open. Paul Patterson Good morning. Tom Webb Good morning. Paul Patterson Just wanted to touch base a little bit on the sales growth. Could you give us a little bit more of a flavor as to when we look at the 0.5% growth, how much of that’s focused on industrial versus the other rate losses? Tom Webb Yes, happy to do that. So we – our first half sales growth weather-adjusted weather-normalized for electric was flat. You’ll see that in our addendum, you’ll see that data. Paul Patterson Yes, I did see that. Tom Webb Yes. And you’ll see residential down and commercial up a little bit. That’s nothing to really get too nervous about because we’ve seen that flat to down to up a touch. It’s oscillating. Those two are not making the big recovery. Now typically you would see after recession. So that’s still ahead of us. That hasn’t started happening yet. The point for today is probably more around the industrial side. When you look at the data, our growth was over 1% in the first half and we know that its underlying growth is better than 2%. So you may say what’s happening. Now I have to be careful because I can’t talk about a specific company, but there is an individual company that’s a big customer, a very low margin customer of ours and they have an interruption on the supply side, and it was a stubborn one. And I’m not even sure and it’s not my business to say when they’ll be coming out of that, but obviously they’ve worked their way through that. And when that comes back through, you’ll see the industrial numbers back up to what we think is a more reasonable level. So keep in mind, we expect that to happen for the future and we really haven’t factored in all the 3% of new growth from new businesses locating which will be largely late this year, mostly ‘16 and some ‘17. But the answer to your question was, in the analysis think industrial as of today. Paul Patterson Okay, but when we look at that 0.5% increase, how much, I guess, what I’m really saying is going forward? How much do you guys associate that coming from industrial versus higher margin residential and commercial? Tom Webb Yes, I can help you on that. So when you look at that, think of the long-term growth as flat to positive on residential and commercial. And that may be where we are under calling things a bit, because typically there is a point after recession where the jobs and the employment bring in more residential, which brings in more commercial. The industrial side in our assumptions going forward is the main driver because we have great visibility into that. We know the folks that are expanding. We know the folks that are shrinking, if they were, but mostly net expanding. And we know the folks that are coming into the state that have announced, who’ve shared of that and those that are looking that we can announce because they haven’t yet. So we feel pretty good on that side. Does that help? Paul Patterson That’s very helpful. Just in terms of the sensitivity since you guys always provide, is that – when we look at that 1%, is that basically across the customer groups or is that pretty much with the same trends that you’re seeing in terms of industrial leading that? Do you follow what I’m saying? Tom Webb I do. That sensitivity we do on an average basis. Paul Patterson Okay. Tom Webb So, if you will, think about the sensitivity that would be oriented more to industrial than to residential, that would make the sensitivity a little less so, because residential is key in here. So we do an average. Paul Patterson Okay. And then IRP versus the mandate, which is one of the differences we see inside the legislation I think. Does that make a significant difference in terms of what you think the sales growth outlook would be, or is it just a question of what’s selected in terms of making the – does it have an impact I guess on decision [ph]. Tom Webb Yes, I don’t think that’s going to have a big deal on sales growth and competition where you were going. So when we talk about having or not having a mandate and using the IRP, that mandate would have been around renewables is a simple example. If you don’t have a mandate because the policymakers would rather make sure that the IRP process is more thoughtful around what the important things are doing, and in an IRP process you might come up with 4% renewables as opposed to a mandate might say something else. The policymakers think the IRP process will be more thoughtful. And when we get into all the needs for capacity, for environmental compliance and those sorts of things, I think you’re naturally going to see a mix of renewables, a continuing mix of energy efficiency and we’ll probably need to put some capacity in place. So when you were relating it to sales growth, I know you were thinking more choice. I would tell you, we’ve assumed 10% continues forever in our plans. So if you were to conclude that ROA customers might be coming back in this process that will actually help sales. Paul Patterson Okay. Tom Webb Okay? Paul Patterson That’s great. Really appreciate it. Thanks so much. Tom Webb Pleasure. Thank you for calling in. Operator I’m showing no further questions at this time, I’ll turn the call back over to Mr. Webb. Tom Webb Thank you very much. We appreciate everybody joining us today. We had a strong first half. We look forward to the second half of the year and we expect to see an improved energy law as we’ve been talking about today, and we expect to see an order on our electrical rate case in December, and we expect to deliver predictable financial results. So thanks for your interest and spending time with us today. We’ll see in the near future. Operator This concludes today’s conference. We thank you everyone for your participation.