Lynn Good - President and CEO, Duke Energy
Ted Craver - Chairman, President, and CEO, Edison International
Brian Chin - Bank of America Merrill Lynch
Duke Energy Corporation (DUK) Bank of America/Merrill Lynch State of the U.S. Utilities Industry Conference Call September 24, 2013 8:00 AM ET
Good morning everybody. Thank you all very much for coming. I appreciate it. For those of you who don’t know me, my name is Brian Chin. I am the new Bank of America Merrill Lynch electric utilities analyst, and I want to welcome all of you for coming to the conference today.
Today, I’ll be hosting the conference along with my colleague Gab Moreen, who covers natural gas and MLP -related entities. And today, we’ve got a great lineup of speakers. I think this will be a fantastic day.
Just in terms of housekeeping and format here, I’ve asked each of the companies that are on the panel to give about 5 to 10 minutes of prepared commentary on the industry topic at hand. After that, I’ve got a few Q&A questions I’d like to ask each of the speakers, but I do want to throw it out to the audience for general questions and answers on the industry topic, or on what’s going on with each of their companies.
I have asked each of the companies also that slides are optional, so some companies do have slides. Many companies -- most, do not, but this is intended to be a free-flowing fireside chat style format.
Lastly, I do want to give an introduction to my first panel here. I’ve got with me first, on my farthest right, this is Ted Craver, chairman and president and chief executive officer of Edison International, which is the parent company of Southern California Edison, one of the nation’s largest electric utilities.
Ted was elected chairman and chief executive officer in August 2008, and president in April of 2008. Before joining Edison in 1996, Ted served as executive vice president and corporate treasurer of First Interstate Bancorp. He also, before joining First Interstate, spent four years with Banker’s Trust Company of New York, and seven years with Security Pacific National Bank. Mr. Craver earned an MBA and a bachelor’s degree in economics and international relations from the University of Southern California.
And to my immediate right, we have Chief Executive Officer Lynn Good from Duke Energy. She has served as Duke Energy’s CEO, having been recently appointed earlier this year and has served as the Duke Energy CFO since July 2009. Before the merger of Duke Energy and Cinergy in April of 2006, Lynn served as executive vice president and chief financial officer for Cinergy. Lynn earned a bachelor of science degree and systems analysis and accounting from Miami University in Oxford, Ohio.
Thank you very much for coming. It’s a pleasure to have you both here. In order to kick things off with introductory comments, Ted, if I could ask you to go ahead and kick things off. The topic of the panel is “The State of the Broad U.S. Utilities Industry.” Ted, why don’t you go ahead and take it away from here?
Okay. Well, thanks, Brian, and great to be with you. What I want to do first thing is just give you a little bit of a sense for Edison International, and what we’re focused on, and I’ll conclude my brief remarks by touching on one of the issues that I think is going to be fairly important for utilities for some time over the next few years, and that’s kind of the confluence of distributed generation, some of the new technologies, and some of the responses that incumbent utilities will have with distributed generation.
But first, just to set the stage, at Edison International, really the primary growth vehicle for the company is Southern California Edison. As the name suggests, it’s a 50,000 square mile territory in Southern California. We have about 14 million population that we serve through that utility.
And really the big story there has been a shift over the last five, six, seven years, but particularly the last three to five years, to focus fundamentally on the so-called wires business, the distribution and transmission business.
There’s been a huge buildout in California, as probably most of you know, in renewable energy, and a lot of that has been in the form of central plant as opposed to distributed generation that’s located in remote areas and that power needs to be brought into the load areas, which has spurred a significant amount of transmission buildout.
Our choice - it’s really part of our strategy - has been to stay away from developing the central plant renewable resources and focus instead on the transmission side and the distribution upgrades that are required to integrate the renewable generation, and that has caused a substantial amount of growth in capex and rate base.
2013 to 2017, we see that continuing, basically at a pace of around $4 billion or more in some of those years, over the course of each year in that period for a total of around $17 billion to $20 billion we’ll call it for the five-year period. And 90% - in fact in a few years, even more than 90% - of that $4 billion plus a year is going to transmission and distribution, and even within that, the preponderance is in the distribution side. So that’s a hallmark of our company, and really of our strategy.
This amount of capex is resulting in a rate base growth in the 7% to 9% compound annual growth rate area, so substantial growth. And in fact, if we look at rate base, over the past six to seven years, we’ve actually doubled the size of the utility because of the level of capex growth that we’ve had, again primarily oriented towards the wires. For utilities, talking about organic growth is pretty substantial that you could double the size of the company.
I mentioned that we’ve been working particularly on things like distributed generation. This may be a little bit surprising, but we’re actually fairly active in that and fairly supportive of that. It started with a program to do rooftop solar in the utility, primarily for commercial customers. So, big arrays that are 1 megawatts to 2 megawatts on top of big box warehouses and distribution buildings.
And we’ve put in about 100 megawatts -- a little less than 100 megawatts of rooftop solar to kind of kick start that part of the industry. Now, we’ve really purchased most of those installations as opposed to build them out, again consistent with our basic focus on the wire side of the business as opposed to generation side.
But we also are looking outside of the utility at doing distributed generation, primarily aimed at commercial and industrial customers. I’ll admit, some of this is a bit experimental at this point. A lot of these companies really aren’t profitable, so you have to really find a business model that’s going to be effective, and that’s part of what we’re doing with the businesses that we’ve created outside of the utility aimed again at some of the alternative energy forms.
The final set of comments I’ll make before turning it back to Brian, one of the biggest issues that utilities have been facing is how do you deal with the concept of distributed generation? What type of impact is that going to have on the incumbent utility? I think it will have a much bigger impact on an incumbent utility that largely self-supplies. It will have a much lesser impact on utilities that don’t primarily self-supply.
Again, by design, we’ve been scaling back the amount of generation that we have for supplying electricity to our customers, and in fact today about seven-eighths of the electricity that we provide customers we purchase from the market and from third parties as opposed to have that in our own rate base. Again, that’s by design.
But even still, what are you going to do with distributed generation? What kind of impacts does this have on the company? Most of that is in the form of subsidies, and a lot of those subsidies are not just taxpayer subsidies, but they’re cross-class customer subsidies, or said differently, there’s a cost shift that’s involved from one group of customers to another.
And as part of this, in California we’ve had quite a, I think, healthy debate about what are the impacts of that. There are some social fairness, social justice issues involved in that, primarily in the form that customers with means - I don’t want to say rich, but just customers with means - have an easier time either paying the up-front cost for the installation of distributed generation or have the credit ratings that allow them to qualify for the leasing structures.
So, they put on distributed generation. Let’s say it’s rooftop solar. They buy less from the grid, because the charges for electricity are almost always volumetric based. That means they contribute less to the overall, or if you will, the social cost of the total system. And this is really becoming more and more of an issue.
In California, it got to such a point where some members of legislature wanted to address that, and we just had Assembly Bill 327 that was passed in California, expected to be signed by the governor, which will do a number of things to counteract some of those cost shifting issues. A fixed charge, up to $10, will be authorized.
Today we have four tiers in California. Those will be skinnied down to two tiers, and condense the differential and the pricing amongst those tiers. Both of those actions together will have the effect of reducing the highest tiers, which have been over $0.30 a kilowatt hour, and a stimulus to a lot of the customers pulling away and self-generating.
The other components embedded in there are also important, but really the key ones are a fixed charge, and reducing the pricing for the tiers. So I think you’ll see more of these types of things - at least that’s my prediction - across the industry as a means of trying to deal with some of the social issues, political issues, of cross-subsidization amongst customer classes.
So, Brian, maybe with that I’ll stop and turn it back to you.
Great, fantastic. Thanks, Ted. Lynn? Also your comments on the state of the industry?
[unintelligible] You’ve got the opportunity here on the West Coast, in California, that’s leading the way on many of the issues that are grabbing the attention of the media at this point. And I’d like to share maybe a little bit of a broader perspective from the Duke business, located primarily in the Southeast and in the Midwest.
And as I reflected on the topic of “State of the Industry” I thought about an industry that is encountering change. But it’s an industry that’s encountered change for decades. I think about where we sit today, having come through periods of deregulation, having come through periods of diversifying our generation [fleet], whether it’s renewables or it’s gas, having responded to an economic downturn, where we’ve seen a substantial shift in our customer base, and we’ve really been grappling with a more anemic load growth environment.
This is an industry that’s had to adapt and change and continue to find ways to provide this very vital service that’s so important to our customers and communities. So I come to this period in our history with confidence that we’ll figure out a way to work our way through it. And as Ted shared, distributed generation being a key element, the utilities in California and other places are finding ways to adapt and change and adjust their business model.
And so as I think about the broad trends that we see today impacting our business at Duke, it’s a combination of things. And as I share these with you, I’m certain I won’t get all of them right. And as we look back at these remarks 10 years from now, there will be something that I missed, because the industry is so dynamic and impacted by so many things.
But I point first of all to regulation as an issue that will impact our business, whether it’s environmental regulations or ongoing implications impacting the nuclear fleet. We’re the third-largest nuclear fleet in the U.S., and that’s an important part of the generation that we offer, and we’re constantly grappling with changing regulations.
I’d also point to technology. And Ted talked about distributed generation. I think as we look at renewables in general, as we look at perhaps advances in micro-grids, we look at energy efficiency, all types of things that are impacting both supply and demand in our business.
I think one of your competitive banks indicated that there 10 states with subsidies or grid parity for solar and we see that number of jurisdictions increasing every time. And North Carolina is the fourth-largest installation of solar at 200 megawatts, in the U.S. And so we see technology impacting our jurisdictions.
I would also point to changing customer preferences and behaviors as a trend, whether it’s demographic change, whether it’s just a customer base more aware of their energy providers, looking to be communicated with in a different way. I think our approach to customers is going to need to change over time as this trend is developing.
I also think anemic load growth that we began to see from 2008 forward is here. It’s a variety of things contributing to that load growth. As we plan our business and think about the future, we’re thinking about very modest amounts of increases in megawatt hour sales.
And so I think about how is the industry going to respond to this? I think we’re going to have to make economic choices as a result of regulation. I think we’re going to have to focus on cost. I think we’re going to have to focus on customers, and I think we’re going to have to find ways to embrace the technology and make it work within our regulatory footprint.
And Ted talked a little bit about changes in the way California is addressing the technologies and how it impacts their business, whether it’s rate design, whether it’s fixed charges, dealing with net metering. I think it’s going to be jurisdiction by jurisdiction, and I think at the end of the day, we’re going to have to ensure that we’re being paid for the service that we provide, and I think you’ll see those trends across the U.S.
And so where is Duke at this point, as we think about the future of the industry? We are the largest utility in the U.S. We have a very diverse set of jurisdictions, a diverse set of customers, diverse set of assets, diverse businesses, and have spent the last 15 months, after the merger, really focusing on how do we prepare the company for the future? How do we create a foundation, eliminating uncertainty and addressing issues that need to be addressed in the short term to position the company for what lies ahead?
And so we have completed a very substantial modernization program, bringing new generation into the business, about $9 billion. We’ve also been very focused on cost structure and integration of the merger, ensuring we drive efficiencies out, trying to leverage the overhead and cost structure of the company for efficiency.
And we’ve also been working through regulatory proceedings and converting these investments that we’ve been making into cash flow to position the company to operate over the next several years without the need for rate increases or exposing the company to regulatory uncertainty.
And I think that foundation will put us in a very good position to see how the industry develops, what opportunities develop from these trends that we’re talking about, and also look for ways to deploy capital in our jurisdictions consistent with what benefits our customers, the regulatory schemes that exist in these jurisdictions, and the specific needs.
And so as I look around our footprint, I think about T&D investment being important in Indiana. We had a recent senate bill 560, giving us an opportunity to track investment to improve the distribution system and we’ll have an opportunity to deploy capital on that area.
In Florida, we have a generation rate adjustment mechanism that will give us an opportunity to stay out of rates but include generation investments, those combined cycles and [peakers] over the next four or five years.
And in the Carolinas, I think it will be a combination of generation, that we’ll be deploying capital. It could be renewables, it could be combined cycles, at the end of the decade. We’re also looking at a very small, 5% to 10% interest in the V.C. Summer nuclear plant that’s being built in South Carolina. I think distribution investment will be important there as well.
So I see an industry positioned to address these issues. Duke is certainly positioned to address these issues, and believe that the scale and diversity that we offer as a company will give us a sound foundation to address developments in the industry.
Great. Thanks to you both for your comments. One topic that you both touched on was distributed generation. Obviously, there’s been a lot of media reports on this, in The Wall Street Journal, EDI has commissioned a report from Peter [Kind] talking about this.
Ted, you had mentioned in your comments that utilities that self-supply should have a much larger impact from distributed generation than utilities that have less self-supply. Can you go into that in a little bit more detail? Why do you believe that that’s the case?
Of course a lot of that will depend on just what the scale ultimately is, and just the level set. So within Southern California Edison, we have about 600 megawatts of distributed generation on the residential side. So, we’re not talking about enormous numbers here at the moment, but I think it would be unwise - maybe I’ll put it that way to kind of dismiss distributed generation as something that will always be a fringe kind of issue.
I think we see it particularly in California, where most of the wind and geothermal and solar is really located remotely, if you’re talking about central plant. And the ability to run transmission from remote areas in the Mojave Desert or the Tehachapi mountains, and what have you, into the load pockets, is becoming increasingly difficult to do, and expensive.
Compare that with the distributed world, particularly where you can co-locate on already disturbed land. In some cases, that’s parking lots or on tops of buildings, whatever. That can be a really attractive alternative.
I think like most things, we’ve learned in this industry - Lynn really referred to a lot of these - it’s never all one thing. It’s always a mix of things. It’s just, in my view, distributed generation is going to be an important part of the mix. And so, at least from our perspective, as we see those costs go down, I think that will certainly put pressure on traditional forms of generation, particularly when you dial in the customer preference part.
And I think I see this both at the commercial industrial level and at the residential level. It’s not just a matter of straight up price comparison. Obviously that’s going to be important, because these are big, expensive installations, even at the residential level.
But there are other things at play. There’s a customer attitude, customer behavior, which as much as anything else is around independence, wanting to be independent not having to only go to one place. So I think that’s an important behavioral and attitudinal element here, and the other is a little more economic, hedging the cost.
That will tie into, I’m sure, one of the other questions you want to ask eventually, which is what do you see in the way of kilowatt hour sale growth? And the flatter that is, the more pressure there’s going to be on rates to increase overall, and so being able to hedge against that potential steady increase in pricing, which has really not typically been part - not on a real basis – has not been part of our industry up until the last decade or so. And we’ve been able to provide more and more electric infrastructure at pretty much a flat price on a real basis.
So, that’s been changing, so I think for those two reasons that are more behavioral, I believe it’s a trend that is here to stay.
Interesting. I want to ask one more question on this distributed generation and load growth change before I turn it over to the audience. What is each of your estimate of how much the load growth outlook has been affected by growth in distributed generation? Are we talking 0.5% of reduction versus what it otherwise would normally be, 1%? Are we still talking 0.1%? Is there just a rough range of how you’re looking at it in your service territories?
I can start, Ted. We don’t have the level of penetration that Ted has experienced, and so I think on a percentage basis, it would be very inconsequential today. But we look at a variety of areas around load growth, in particular whether it’s energy efficiency, whether it’s economic, whether it’s capacity being added to the system in the form of distributed generation. We’re expecting very modest growth, and run sensitivities that would say what if it’s flat? What if it’s slightly negative? And what are the implications to cost structure and capacity and so on?
So I think we’re watching closely the trends that are developing in California, I think Hawaii, Arizona. And the percentage increases of distribution generation are quite substantial. But the overall penetration, as Ted indicated, hasn’t yet reached the level that’s impacting [load] in a consequential way.
I don’t actually think it’s distributed generation that’s causing the flattish load growth. I think it actually has more to do with kind of a maturation of the system. For decades, we’ve been building the system. I think it’s largely built now, so it’s just a matter of population growth that really would provide some level of increase. And that’s being more than offset by energy efficiency. From what I see, to be quite blunt, I think we’re just scratching the surface on energy efficiency, and particularly, as it works its way into commercial industrial. That’s really the big load.
And, again, our company has one example that may be on the cutting or bleeding edge, but we used to be pretty close to a third, a third, a third in our load between industrial, commercial, residential. Now about 10% of our load is industrial, and of course there might be a potential to say, yeah, that’s California, and they’re anything but hospitable to major industrial users. If you actually look at the data, there has not been a decline in load from industrial customers. What’s happened is it’s shifted away from using the utility as its supplier. So it’s gone to more and more self-generation.
As technology improves, I think you’ll see more and more of that. So it will be kind of co-generation using other industrial processes to both produce electricity and oftentimes it’s steam or heat for industrial process.
So I think we will see this extend more and more into the commercial industrial side, and those are the trends that I think are really driving the flattish growth. I don’t think it’s distributed generation. Maybe in a more broad sense, of saying self-generation is part of it, but some of it too is just coming up with more efficient ways of producing and using electricity.
So I think that will be part of the landscape that we need to plan on get used to. I think that’s one of the reasons - I completely agree with Lynn’s comment - there will need to be a renewed effort on the part of utilities to really examine their costs and really think hard about well, what do we actually do, and what do we really get paid for? What do we really earn on? And focus on those things and not get distracted with other things that are basically pass-throughs or just add to the cost.
Right. Any questions from the audience? We’ve touched on a number of different themes in the prepared comments and in Q&A so far. I’d like to turn it open. [No questions.]
Fair enough. I do want to touch base on another topic that regards generation and diversity of supply. Lynn, you had touched on this. Duke is a very diverse entity. I think one common thread among both of your experiences as CEOs, is it’s a difficult position to shut down a nuclear plant. As I talk to investors, one of the questions we get is is there nuclear plant risk at other utilities in a similar vein as what we saw at Crystal River, what Dominion had to go with Kewaunee, and Vermont Yankee.
If you were standing in investors’ shoes, given your experiences with your respective plants, what are some of the points that you would consider about, well, wait a second, this utility has this nuclear asset that has these kind of characteristics, there’s a little bit of a risk factor I need to think about when looking at them? Any thoughts?
It’s a very good question. I think you should look at each of these instances, Crystal River, SONGS, Kewaunee, and Vermont Yankee. I think every one of them has some unique aspects that ought to be considered. And in the case of Crystal River, it was a major repair, steam generator replacement, that developed complications, and whether or not we could replace the steam generators and repair the plant in a cost-effective way when it was nearing the end of its [40-year] life and life extension was uncertain.
And so I think there’s certainly a theme of aging infrastructure, difficult repairs, costly repairs, with a short life and perhaps uncertain life. And the economics of that are just something we have to grapple with, making the decision that’s in the best interests of the customers, and best interests of the company.
I would contrast that to a Kewaunee, that I think was dealing with very tough commercial pricing and commercial market that made the economics of continuing to run the plant effective. And I would almost analogize that to the tough commercial environment that’s impacting coal plants and other things that have cost structure, O&M, to keep things going.
But I do think, as we deal with aging infrastructure, ongoing regulations of the nuclear fleet, we’re going to have to make decisions around the economics of continuing to invest in these plants, and whether these economics make sense for the companies and for customers.
I think Lynn’s hit the nail on the head. Probably our two plants had some unique technical issues. In our case, in fact we just had a release yesterday, a press release, an 8-K release, on the Nuclear Regulatory Commission findings. It was pretty clear it was a design problem. We hired Mitsubishi Heavy Industries to design and build the replacement steam generators. There was a flaw in the computer code, according to the NRC, and that resulted in a faulty design and faulty steam generators. So that’s kind of a unique thing.
That said, I think it is ultimately economics that come into play on all these things. So you could try to fix them, you could try to replace them. That starts getting into, well, what’s the remaining useful life? What’s the remaining license period? Lynn mentioned that relative to Crystal River as well.
So I think in a way they all ultimately tie back to economics. Is it cost-effective for rate payers, customers, for you to put the requisite capital into the plant, given what you see as either the license period or the useful life of the asset? And the older assets get, the more complicated that calculus becomes.
More broadly, I think one of the big public policy issues that the country is going to have to grapple with, and other countries are as well, if you’re serious about carbon, and you’re serious about trying to produce a vibrant economy that is low carbon focused, it’s hard for me to imagine how that works without nuclear being a significant part of that.
So there’s some important tradeoffs. And right now, and maybe for some period of time, it will be difficult for new nuclear to make sense when you’re comparing it against other resources. But I don’t know how you get, ultimately, to your goals on carbon without nuclear being part of it. So that’s going to be a big public policy point that may not be entirely a matter of plant-by-plant microeconomics.
Right. Once again, I’ll see if there are any questions out there in the audience.
Unidentified Audience Member
Great question, and I’ll admit I’m not sure we have a perfect answer. But I definitely come down on the side that it’s an opportunity as opposed to a threat. Again, some of that maybe is based on some decisions we’ve made along the way, but we’ve focused our utility business in California on the wire side.
So as I mentioned, we only produce about 1/8 of the electricity that we provide to our customers. So we’re not exposed on the generation side. All of this distributed generation, particularly at the residential level - might be a different issue for the commercial industrial - it does not work without a really vibrant distribution system.
There’s a tremendous amount that we need to do on the distribution side to really enable things like distributed generation, or storage, particularly if you think in terms of electric vehicles. Again, California is probably leading the way in the electric vehicle technology and adoption. Those are basically mobile storage devices.
The more you think in terms of these new technologies interacting with the distribution system, the more that distribution system needs to be capable of two-way flows. Certainly distributed generation, you’re injecting electricity into the distribution system, not just taking it out. So, in the old model it’s a radial system, from central plant transmission/distribution, out to individual homes and businesses.
Now, you have electricity coming in, out of the capillaries. That requires a system capable of two-way flows of electricity. That’s the type of thing that we’re really aiming our infrastructure replacement at, is being able to enable those types of new technologies to be interacting with the grid.
Same thing if you think in terms of storage devices, if you think in terms of smart meters and some of the things that customers can do in terms of managing their own electric usage. All of that requires a much more flexible, dynamic distribution system, and that’s where we’ve been really focusing our investment. So I see it as an opportunity, not as a threat.
On the commercial industrial, I think that’s going to be a more mixed type of deal, and that’s one of the reasons we’re doing things outside of the utility, as well as some of the things I mentioned inside the utility. So really, we want to be able to address all customer classes in a way that really meets their needs.
Unidentified Audience Member
I think like really across the country, that’s, in my mind, kind of broadly part of the energy efficiency part. So the more that you think in terms of distributed generation, the more you think in terms of potential storage devices, the more you’re going to end up also having a lot of impact on where the peaks occur.
And within California, just given the level of renewables that we have, be they distributed or central, plant form, you’re starting to see a shift in actually where the peak exists, at least from a utility or a grid perspective.
And in some extreme cases, you could imagine your peak, if you have a lot of solar, for the utility is not going to be actually in the afternoon, because you’re going to have so much distributed resource or solar renewable resource, contributing electricity into the grid.
So I think those are all kind of part of this overall mix of energy efficiency, different forms of generation, storage in due course - right now it’s a little more of a fringe issue - all of those things are going to have an impact on demand, and so demand response I think is going to have to find its way through there. It may not be the traditional place or use or demand response as we’ve had.
Excellent. I think we’ve just about run out of time here on this panel. Ted, Lynn, thank you very much for your comments on the industry.