California's Energy Future & Wildfire Risk: Edison International CEO Pedro Pizarro
VX News here features a conversation between Nat Bullard, co-founder of Halcyon and host of the Nameplate podcast, and Pedro Pizarro, president and CEO of Edison International, recorded for Nameplate's debut episode. Pizarro, who marked a decade as Edison International's chief executive on October 1, traces the company's 140-year arc from the Big Creek hydroelectric project to today's wires-focused Southern California Edison. Find the interview here.
Edison International's 140-year arc
Nat Bullard: My guest today is Pedro Pizarro of Edison International. Pedro, give us the expansive version of the story of Edison International and the companies within it.
Pedro Pizarro: Thanks so much for having me, Nat. It's timely to ask about our story, because it started 140 years ago as of July 4, when one of the original constituent companies lit up the town of Visalia for the Fourth of July. The history continued through a number of acquisitions. One of those companies was Pacific Light and Power, and I highlight that one because it had a couple of key figures. One was Henry Huntington. If you've spent time in Southern California, you may have been to the Huntington Library, a beautiful estate. Huntington was a railroad magnate, a developer and a great art collector. The other was John Eastwood, an amazing hydraulic engineer. Together they developed the Big Creek hydroelectric project, which our team likes to call "the hardest-working water in the world." It's still operating, and the system has something like 1,000 megawatts. That really laid the foundation for Southern California's growth, and as the region has grown, so have we. I like going to Big Creek now and then. It feels like you're staring at the DNA of the company.
Nat Bullard: I'm always fascinated when utility executives tell me that not only is their oldest asset older than me, and older than a hundred years, it actually goes back into the prior century, and it's still operating. Where exactly is Big Creek in your territory?
Pedro Pizarro: It's toward the northern part of our territory, in the Sierra. Open invitation if you want to visit; it's beautiful. For me it's also reflective of who the company is today. It was an engineering marvel at the time. The high-voltage transmission lines that connected it to Southern California were developed in part in collaboration with Caltech, where I got my PhD and where my wife is a research professor, so there's a personal connection there too. This was before helicopters could drop equipment in and before there were roads, so a lot of equipment was taken up by mules on makeshift roads. Beyond the engineering marvel of using the water multiple times as it comes down from the Sierra, there was the physical achievement of doing that work under tough conditions. It's a testament to the DNA of the company. Fast forward to today, and I'm really proud that our team is on the leading edge of applying a number of technologies to our space, including how we're using AI and how we're helping to digitalize the grid. It's important to do hard things. Hard things are what advance you, and I'm proud that's been the history of the company, then and now.
Nat Bullard: I will come back to the Caltech bit. We can talk about trapped-ion magnetic resonance.
Pedro Pizarro: You looked at my dissertation? That's scary, and you're going to get me nerding out.
Nat Bullard: We'll come to that in good time. Your story about mules bringing equipment up to your hydro asset reminds me of my first trip to Sequoia and Kings Canyon, when I asked one of the old-timers how any of the infrastructure got there. He said, "Lately it's been helicopters, but formerly it was mules." Tell me more about the growth of the company. There was a time when you had an independent power producer, Edison Mission Energy, as part of the franchise. I'd also be interested to know how the company navigated the deregulation era of the 1980s, '90s and early 2000s.
Pedro Pizarro: Those stories are actually intertwined, and they're a bit before my time. I joined the company in 1999, though I first started poking around as a McKinsey consultant around 1993 or '94. A couple of things came together. First, you had the shocks of the 1970s energy crisis and the reliance on oil. At a strategy offsite with our executive team, our head of strategy pulled out some newspaper clippings about high prices, rates and consumer concerns, and quizzed us: Is this from today or from sometime in the past? They were from the '70s. As California turned to alternative resources, the company saw an opportunity to build a new business around those alternatives, and, to make a long story short, that spawned Edison Mission Energy. EME grew from its California roots into a global company. It had assets throughout the United States, including coal, natural gas and a large wind business; at one point it was the seventh-largest wind developer in the country. It also had international assets throughout Europe and Asia.
Then we hit the California energy crisis at the end of the '90s and into the 2000s. To manage the company's finances under that stress, a tough decision was made to sell the international assets, and Edison Mission Energy became a U.S. independent power producer under the Edison International umbrella. Fast forward some more, and I ended up being the last head of Edison Mission Energy under Edison ownership. It was a really neat business, but it had coal plants, and those plants became subject to new environmental requirements in the 2000s, which created financial stress. By the time I went to EME, on January 1, 2011, Edison International had told Wall Street that it was a stressed business and that a restructuring, potentially even a bankruptcy, was possible. We worked hard to improve finances and operations, and a great team there delivered a lot of operational improvement. But in the meantime, shale gas came into the equation, and natural gas prices plunged by 25 percent through 2011 and part of 2012. EME was a merchant generator dependent on market prices, and given that stress, it filed for bankruptcy protection at the end of 2012 and emerged with a sale to NRG in the spring of 2014.
I spent a little while on that because it's an interesting story. It showed a lot of innovation in developing that business. It was responsive to California policy and grew into a much broader play. Then factors changed, life happened, there was stress, and we ended up with what I think of as a successful bankruptcy: an orderly process and a sale, and some of those assets still operate today. But it did end Edison International's presence in merchant generation. Today, Southern California Edison is our main operating business, and it is essentially a wires business. SCE has a little generation, including the hydro assets we talked about, one natural gas–fired combined-cycle plant and five peakers, but by and large it's a wires-focused, electric-only business, which I think aligns well with California policy.
Nat Bullard: For context, I believe you have about 50,000 square miles of service territory. How many customers are within that?
Pedro Pizarro: There are over 5 million customer accounts and around 15 million residents, so it's roughly 40 percent of California. The geographic diversity is fascinating: everything from the beaches, to the very arid desert past Palm Springs, to the snowy mountains of the hydro system. We have it all, Nat.
California at the policy frontier
Nat Bullard: You certainly do. California is a unique place in the U.S. energy system. Let me start with a broad question and then we'll drill down. The audience here will be others in the sector, investors, and technologists looking to sell into the world of electricity. What do they need to know about California in general, and about Southern California Edison and its territory specifically?
Pedro Pizarro: I'll start at a high level. I love the state; I've spent more time here than anywhere else in my life. I came here for graduate school and raised our kids here, and I love the diversity of the state in every sense, geographic and demographic. It also has challenges. It's an expensive place; maybe you get what you pay for. On the energy side, California tends to be at the forefront of policy. Sometimes that's leading edge, and sometimes it may feel a little bit like bleeding edge. But the state also recognizes its responsibility, as one of the world's largest economies, to find ways to do new things and set an example, and I appreciate that.
As for Southern California Edison, we're part of this economy. Electric utilities might be a few percent of GDP, maybe 5 percent, but the other 95 percent relies on us. So there's a sense of mission and responsibility, and alignment with state policy. At the same time, we view part of our role as being candid, outspoken, analytical and down the middle of the fairway. Over my decade as CEO, we've published something like seven or eight white papers, all centered on how California meets its net-zero ambitions in a real way: What's the most economic way to get there? This is not about dogma. Take natural gas. Some of our environmentalist friends, who I think are very well-intentioned, have been less pleased with us when we've affirmed that, even though we're an electric-only company, natural gas will have a role in the state's economy for quite some time, even as we shift more and more use toward carbon-free clean firm generation. That can't happen instantaneously. We've been outspoken about doing the math, basing decisions on the math and doing the right thing, so that SCE both supports state policy and helps shape it, and speaks up when something hasn't been fully thought out. Wildfire is one example where we've tried to bring analytical rigor to a tough, complex problem.
Nat Bullard: We'll certainly get into that. But first, a bit of biography. In my research on the utility CEOs I'm talking to, pretty much everyone has confounded my expectation that they started as an engineer, did a field job, worked in operations and moved up. That's certainly not your case. Give me the quick version of how you got from undergraduate chemistry to a Caltech PhD to consulting to the company. I think it's helpful for understanding your view on strategy.
Pedro Pizarro: My story is pretty simple, if a little different. I always liked science. I grew up in a lower-middle-class family in Puerto Rico, with great parents, and we moved to Florida when I was in high school. I thought science for me meant becoming an MD, so I was premed in my mind through the first part of college. I got a scholarship to Harvard, and as I went along I realized that I really liked the more quantitative side of science. Or, alternatively, I was a little bit lazy: biology required a lot of memorization, while in physical chemistry you could learn a few equations and derive the rest. So I ended up on the chemical physics side, with a lot of quantum mechanics, and decided to go to graduate school, thinking I'd be an academic someday. I stayed in Boston for my PhD at MIT. My wife, who is Californian, was a year behind me at Harvard, and when she was graduating she wanted to come back and be an earthquake scientist, doing her PhD at Caltech. So I transferred and chased her across the country. It sounds cringey, but we've been married 37 years now, so that worked out.
I completed my PhD and got a fellowship for a postdoc back at MIT, but I thought I'd look around before I committed, and I ended up getting an offer from McKinsey. This was early in their recruiting from non-MBA programs. They were growing at something like a 14 percent annual rate and hiring a full third of the Harvard Business School class, and they thought it would be good to look to other fields for talent. After a lot of hemming and hawing, I went, thinking I'd check it out for a couple of years, and I ended up spending about five and a half years at the firm. Edison was a client, so I got to know the company. When the travel was getting to me and we had just had our first daughter, I accepted an offer to come work at Edison, again thinking I'd be here for a couple of years, until I figured out what I wanted to do when I grew up. Those two years have turned into nearly 27.
I was attracted to Edison by a sense of mission, which back then was safe, reliable, affordable power. I remember seeing the lights as you land in the region, thinking about how much of that was Edison and how neat it would be to be part of that. As the years went on, that mission expanded beyond safe, reliable and affordable to include clean as a big part of it. That's why a big theme during my tenure has been how our business is a key enabler of the clean energy transition, and frankly of doing something about climate change. It is happening, and sadly we've been on the leading edge of feeling those impacts, through wildfires and more. So that's the medium-sized version of the story: premed, then scientist, then consultant, then two years at Edison that turned into a career. I'll have been CEO at the corporate level for 10 years on October 1, 2026.
Renewables, net metering and the return of load growth
Nat Bullard: Two years becomes 27. I appreciate that, because it helps set up how you think about running a company in this very particular state. I want to look at a couple of things that are uniquely Californian. The first is the mix of renewables, distributed generation and a very high penetration of renewable energy that is, and I say this in a neutral way, an imposition. It begins as policy, to which you as a utility may have some input but are not the arbiter. It comes from the legislature and then has to express itself through the actions of companies. I first encountered this in my very first piece of research, 19 years ago, on the California Solar Initiative, a program providing financial support for people to install rooftop solar in a distributed fashion. Not being terribly sophisticated at the time, the first thing I was able to determine was that all of that funding was going to the wealthiest zip codes in the wealthiest state in the country. So many things resonate outward from that. What learnings can we take from the beginnings not just of the renewable portfolio standard, but of this particular focus on distributed generation, and how does it bear out today?
Pedro Pizarro: There's a lot there. Let me start here. When the state first enacted its initial renewable portfolio standard, a 10 percent RPS requirement, I was a younger executive at the company, and I was really concerned. Within a couple of years, I ended up being the one signing those contracts as vice president of power procurement, so there are still contracts operating that have my signature on them. I appreciated the state's policy leadership and vision for moving toward renewables, and I supported the move, but I was concerned about the cost implications for customers. That has been a theme all along. What I underestimated at the time was the power, and it's a double-edged sword, of policy actions like that to stimulate a market and bring the cost curve down as volumes increase. We keep pricing terms confidential, but the first central-station solar contracts I signed were probably, in nominal terms back then, 13, 14, 15 cents a kilowatt-hour. Today you read public announcements of solar at 3 or 4 cents a kilowatt-hour, sometimes 4 cents with storage attached. So there was definitely a volume effect that helped push R&D and manufacturing down the cost curve, getting more efficient and bringing costs down for everybody.
Now, you can take that to a fault. Before we started recording, you mentioned Spain. I visited Spain around 2010, when they still had their feed-in tariff, which, if I remember correctly, was something like 35 cents a kilowatt-hour in nominal dollars at the time. That ended up being way too much, Spain pulled the plug on the program, and there was a lot of appeal. So there's a balancing act for policymakers, particularly in a place like California. How do you stimulate markets and lead? How do you make investments that might be a little expensive at first but carry a promise of return, without overdoing it?
When net energy metering started, it provided a very strong incentive to deploy a brand-new and, at that point, quite expensive technology. It was a subsidy choice the state made. The state makes lots of subsidy choices: about 3 percent of an Edison bill today goes to public purpose programs beyond net energy metering, such as low-income subsidies for folks who have a hard time paying their bills. Those are choices, but the rest of the customers pay for them. Here's what happened. Net energy metering worked, because it helped bring more volume. My numbers are a little dated, but I believe the price of solar panels when the program started, compared to the cost now, is something like a factor of seven difference. It's a lot cheaper in real terms to install solar on your home today. The program worked, but until a couple of years ago it had not been reformed, and you had these really large subsidies. The latest number I saw, which might be a year old, is that around $8.5 billion annually is being transferred from non-solar to solar customers in California through net energy metering. And you're right: a large portion of that has historically gone to more affluent customers.
So the program needed reform. The Public Utilities Commission introduced some reforms a couple of years ago, and there was a lot of concern expressed by some members of the solar community. But my view is that California does not have an infinite checkbook, and our customers don't have an infinite checkbook. It is appropriate to have subsidies for emerging technologies. Once a technology has emerged, let's move those subsidy dollars to new technologies that need help emerging. Today, I would rather see a subsidy dollar go toward heat pumps. Our analysis of what it will take to get California to net zero shows that we not only need clean energy resources, but we need to electrify a lot of the economy. By 2045, we need over 90 percent of vehicles to be electric and over 90 percent of buildings to heat their water and heat and cool their air with electric heat pumps rather than natural gas. The heat pump market is still at an emerging stage, so I'd rather apply subsidy dollars there than to a technology that is much more mature and fairly economic today.
Nat Bullard: I think we'll find a lot to talk about there, because I'm always curious about what's on the wish list, and we'll come back to that later. The other thing that strikes me is that these programs are designed to tap into a lowering cost of wholesale power, but you then have an entire system built up that is not, shall we say, deflationary. We encounter this in every state, but particularly acutely in California. How do you think about that, especially in a future of non-wires alternatives and other investments to keep our system stable, operational and resilient, where every bit of extra expense outside generation can be part of an inflationary structure? I'd be curious to get your take from both a policy and a technology perspective.
Pedro Pizarro: I'm glad you raised that. Let me start with this fact: For California to get to net zero, because of the amount of electrification that will be needed, we see statewide load nearly doubling by 2045. Getting there requires a massive amount of investment in generation, whether bulk power or distributed. To do some simple math: today, about 15 percent of our residential rooftops have solar. We've assumed that will go to something like 50 percent by 2045. Australia is probably at 25 percent or so today, maybe a little more.
Nat Bullard: It depends on the state, but it's high.
Pedro Pizarro: It's higher than California, but we're headed there. It would be great to see more, but there are limits in terms of which roofs can take it, whether it's economical and so on. In rough numbers, that 50 percent would contribute something like 30 gigawatts of capacity. Let's say we got it wrong and you could actually go to 100 percent; that would add 60 gigawatts. But we see the state needing a lot more than that developed by 2045. If I recall correctly, it's over 120 gigawatts of capacity. So it's a bit of all of the above. We need to find every clean resource we can get and put it to work, including distributed resources, in order to use those across the economy.
And you want them interconnected. The Electric Power Research Institute did an analysis, maybe seven or eight years ago, of what it would take for an average Southern California home to be fully off-grid using solar panels and batteries. California is a fairly sunny place, but we do have rain now and then, and cloud cover, especially on the coast. The study concluded that to have reliable power service on a standalone basis, you would need batteries for at least three days' worth of power use. The value of the grid is that it's the original sharing economy, before Uber, before Airbnb. You're connecting supply and demand across a wire system, so that home doesn't need three days' worth of batteries. It might have a day's worth, rely on the grid and put power into the grid, assisted by a fairly low-cost component, which is the wire system.
When you call it an inflationary system, I think you mean, and tell me if I misread you, that there is constant investment needed. It is a negative-cash-flow business; you're having to deploy capital. But there's a governor on that: ultimately, the Public Utilities Commission has to determine and approve that the capital we're investing is efficient capital. We face the risk of disallowance if we invest capital without their approval and they disagree with where we put it. We don't have carte blanche, and that's appropriate. We're a regulated entity, and it's appropriate that the regulator be regulating and making sure there's public convenience and necessity in making these investments.
One more thing I'd add, going beyond California: we're now in a period in the history of the electric grid where we've gone back to load growth we haven't seen in decades. If you and I had been talking four years ago, I would have told you that, based on our analysis, we still saw load increasing by 2045 in order to get to net zero, but by something like 60 percent, and we still expected our load to stay fairly flat through about 2030. That's because for the past decade-plus we'd been seeing customer additions and load growth offset by energy efficiency, which is really valuable, and by distributed generation. Fast forward to now, and this has all happened much more quickly. We're now seeing 1 to 3 percent annual growth. We expect 30 to 40 percent load growth by 2035 and, as I said, nearly doubling by 2045. That story is actually accentuated across the rest of the country, though the components are different. For us, it's really being driven by electrification. We're seeing some data center growth, and we already have a lot of data center presence, but we're not seeing the big training centers show up here; it's an expensive place. For my colleagues in other states, there are two other components: data centers and the reshoring of manufacturing. Those three things, data centers, manufacturing and electrification, are driving a big change, and that requires capital investment.
The last point I'll make, particularly when you think about data centers and all the controversy around them and who pays: our view, based on our analysis, is that done correctly, with the right regulatory structure, we want to see those data centers and other large loads show up in our territory. That's more steady use that goes into the denominator and amortizes the costs you have in the numerator, and that can actually help lower rate pressure.
Nat Bullard: I'm glad you brought up the components of load growth. My first year working at New Energy Finance was 2007, which was basically the top tick of nationwide annual electricity demand for about a decade. It's a bitter lesson to unlearn, so to speak, to have to get back to thinking about growth. I always thought of flat demand as a convenient umbrella under which to do a whole bunch of other things that seemed costless, coupled with a very low cost of capital. Tell me about the specifics of Southern California Edison's load growth. I've talked to some utilities that have 250 percent of their current peak demand in potential data center demand that could be built. I don't think that's quite the case for you. What does electrification mean in this context? I think it needs parsing out depending on where you are.
Pedro Pizarro: Let me bring it together. Again, this is driven by where we see the state's economy going over the next 20 years, because of the state's net-zero target and its policy choices around things like vehicle electrification. Our components of growth start with normal customer growth. You've read a lot about whether California's population is growing or declining; we're still seeing some modest population growth, but more importantly, there's a housing crunch, so we continue to see housing development. We're currently setting something like 40,000 new meters a year, on a base of more than 5 million. That's steady growth.
Then there's electrification. In electric vehicles, California has had a much larger share of electric new-vehicle sales than the rest of the country. Until the removal of the federal tax credits, in round numbers, something like 10 percent of U.S. new-vehicle sales were electric, versus something like 25 percent in California. That dropped immediately after the removal of the federal tax credits, and we're seeing it start to normalize again. I don't have the numbers in front of me, but I believe the latest I saw had us at maybe 20 percent, give or take, maybe a little lower: still substantial, and still more than the rest of the country was even before the removal of the tax credits. And now California is bringing back its own replacement for some of those tax credits, in addition to manufacturers bringing more and more vehicles to market and focusing more on lower-cost vehicles.
It's like the Mark Twain line, which I'm going to mangle, that the news of my demise has been exaggerated. Take Ford as an example. They were pretty bold with the Lightning, the electric truck. It's a great vehicle, and we have a number of them in our fleet. The market just didn't buy them as much; they were expensive. Ford hasn't abandoned EVs, but it is focusing more on small sedans, and I believe it will be bringing out a small pickup soon. I just read an interview with Mary Barra at GM, who acknowledges that the pace has slowed down but still sees the end point as EVs. Maybe more importantly, go anywhere outside the U.S., go to Europe, and you see the market flooded with Chinese vehicles. From a U.S. competitiveness perspective, I sure hope we get back to supporting our auto industry on EVs, because otherwise we're going to get frozen out of the global market.
So electric vehicles are a big component of the load growth we see coming. There are other forms of electrification, and importantly there's building electrification, which is off to a slower start. We're seeing some pickup, but we believe it needs more focused attention, whether through incentives or otherwise, to really help stimulate the market. I believe we'll see what happened with solar: as the market grows, costs come down, and that makes it more affordable for everybody.
Wildfire liability and the limits of reform
Nat Bullard: I want to turn next to a very big topic. It's both timely and, no pun intended, evergreen: what some people call the Pyrocene, and what it means for California in particular. When you spoke to the Los Angeles radio show AirTalk on August 5, you said that you operate lines across 50,000 square miles and that 27 percent of that territory is high fire risk. Many people listening will know about the Eaton fire, but I'd like to hear about it from you. Where does it stand within what is, to my mind, an unbelievably complicated set of policy, regulation, finance and capital markets? Where are we on recovery, how do we think about the policy landscape, and then let's go further into the future and the technology interventions we can make.
Pedro Pizarro: That's a lot, so stop me if I'm going too long. Honestly, Nat, this topic has dominated my tenure as CEO. I'll start with this piece of context. As a regulated utility, SCE has an obligation to serve. If we were a normal commercial business, we would probably be making risk-based choices not to serve every bit of that 27 percent of our 50,000 square miles. It's just too high-risk. We don't have that choice. That's point one.
Point two: when you think about these heartbreaking, catastrophic fires the state has been living through, there are multiple factors that contribute to the catastrophe. In the case of the Eaton fire, even before an investigation report came out recently, we said all along that it's likely Edison's equipment was associated with the ignition. Frankly, that's a heartbreaking thing to say. We can get into what seems to be the root cause, but more importantly, to your question, think about the scale of that event. It may have started with an ignition caused by induction on an idle line, but the scale of the event was due to a number of other things. We had 100 mph winds that night, which means embers moving more than a mile, a mile and a half, a minute. It also meant firefighting helicopters had to stay grounded for major portions of the event. It appears there was unfortunately insufficient water in places. This is not the residents' fault, but the reality is that, through the arc of state policy, we as a state had not moved to harden those homes, even though they're in high-fire-risk areas. Then you had the urban configuration, where the fire spread very quickly into an urban area nestled in a high-fire-risk area. And the gas company's gas kept flowing for several days, apparently, so that may have contributed as well.
With all of these factors, we need to be accountable and held accountable as electric utilities. But at the same time, we cannot be the insurers of last resort for all of those other societal factors, including the impact of climate change and its exacerbating conditions. By the way, by the time you release this, we will have issued a white paper, in conjunction with Climate Week NYC, that looks at climate adaptation. One of the things we look at is how we expect to see a lot more wildfire risk from all causes in the state by 2050, because of exacerbating climate conditions.
So that's the context: an obligation to serve, not a choice to disconnect or not serve. And the state is unique relative to just about every other state in having a doctrine that was established not in law, but by the courts.
Nat Bullard: I know where we're going with this one: inverse condemnation.
Pedro Pizarro: Inverse condemnation. The short version is that if a fire started with electrical equipment, however it started, the utility is responsible for all property damage. It could have been a drunk driver hitting a pole and the wires falling on the ground; that's electrical. The doctrine is rooted in a theory about governmental entities. Take a governmental water system: a pipe breaks, and three blocks' worth of homes get flooded. The water agency has essentially taken, or condemned, property; hence inverse condemnation. Because it's providing a public good, the expectation is that it can then recover those costs from the public it's serving. When the courts established that theory in California, their underlying assumption was that an investor-owned utility, because it serves the public good, would be able to turn around and collect those costs from its customer base.
There was an understanding that, of course, the utility needs to be held accountable. We need to be prudent; we can't neglect safety. But if we've acted prudently, there would be the ability to recover those costs, and the ultimate arbiter is the Public Utilities Commission. Unfortunately, there was a case completed in 2017 over a 2007 fire experienced by San Diego Gas & Electric, in which the commission, in our view incorrectly, determined that SDG&E had been fully imprudent and allowed no cost recovery. That happened at about the same time as the first of the catastrophic fires of this era, the Wine Country fires in PG&E territory. Nat, I remember a distinct moment standing in one of our hallways, talking with our then head of the utility and the then general counsel of the holding company. The Wine Country fires had started, this decision had come out for San Diego, and the three of us looked at each other and realized we were living in a new era. We were going to have to rethink how we manage wildfire risk, and that's what we've done.
There were two prongs to that. One was to seek legislative and regulatory changes that would create a framework where utilities can be held accountable yet still have a fair opportunity for cost recovery, given our obligation to serve. Separately, we undertook some dramatic changes in how we build, maintain and operate our physical infrastructure, and today that's been codified in wildfire mitigation plans. It's everything from hardening, where by now we've replaced over 70 percent of our distribution lines in high-fire-risk areas, swapping the typical bare wire for covered, insulated conductor. We have yet to see an ignition from one of the root causes that covered conductor is meant to mitigate; it's been very effective. We've added other equipment, like fast-acting fuses, weather monitoring stations and high-definition cameras. We've implemented public safety power shutoffs as a tool of last resort when they're needed, and we try to narrow their scope. All of these measures reduce the risk of our operations, yet that risk will never be zero. You could not spend enough money to make it zero.
Because there's always some risk, as materialized with the Eaton fire, the state needed reform. Again, that ignition cause was something unexpected and unprecedented, a really unique set of circumstances that coincided with really tough weather conditions and all the other factors I mentioned. Let me pause there, but I'm happy to cover the reforms we've obtained and those we're still seeking.
Nat Bullard: I would like to get briefly into the reforms. If I step back a couple of removes, the fundamental question is whether this enormous amount of hardening investment, preparation, policy and planning comes down to being paid by taxpayers or by ratepayers.
Pedro Pizarro: They're the same people, by the way.
Nat Bullard: They're the same people, but with a different distributional element, I think we could say. I know there was hope in the legislature that you would get the reforms that were needed, and from my chair it does not seem that everything came through as desired. Tell me about the last legislative session and how we think about it going forward, in particular what guidance it can give for the next event and the one after that, but also for other states. One of my postcards from the future here is that just as this is acute, even existential, for California now, it will be acute for neighboring states soon and relevant for everybody eventually.
Pedro Pizarro: By that measure, we're already living in the future: it's already acute in a number of states. You've seen issues in Oregon, Washington, Colorado and Texas. You've seen unexpected fires in areas like Louisiana, New York, New Jersey and the Carolinas. I'll tell you, from an investor perspective, right after Lahaina, a major European investor that is a top holder across many U.S. investor-owned utilities sent out essentially a data request to a number of utilities. Not us, because they already knew we had a wildfire mitigation program, but they sent it to some of our peers in southern states and on the East Coast, asking what they were doing about wildfire mitigation and whether they had a public safety power shutoff program. So this is certainly broader than California or even the West. To my peers' credit, the Edison Electric Institute, the trade association for investor-owned utilities, which I chaired a few years ago, has had a CEO task force focused on wildfire for some time now. Steve Powell, the CEO of Southern California Edison, is one of its co-chairs. And it's not just folks from California sitting at the table, because this is viewed as a broader issue that may be coming to a theater near you, and it has already come to theaters in some of the states I mentioned.
So, the reforms. Let me quickly say what has been done already, because I need to give the state a lot of credit. Laws were passed in 2018, and the largest one in 2019, which I would summarize as setting up a framework for defining what prudent behavior looks like and what the expectations are for utilities. Investor-owned utilities are required to have wildfire mitigation plans, updated annually, that define all the measures we're taking, and those are reviewed by the Office of Energy Infrastructure Safety and by the Public Utilities Commission. The law also set up a wildfire fund, funded half by shareholders and half by customers of the three utilities. It was around a $21 billion fund, and it was meant to be the first stop. If a fire happens for one of the three investor-owned utilities, the first $1 billion in damages is meant to be covered by the utility's own insurance. That could be commercial insurance or, in our case, customer-funded self-insurance, which we've transitioned to. But beyond the $1 billion mark, there's liquidity, because you go straight to the fund, as long as you have a safety certification and have been deemed qualified under the wildfire program. I won't take you through all the details, but that's the gist of it.
The law also set a liability cap. It recognized that utilities have to be prudent, but that even if they end up being imprudent, there are a number of other contributing factors when you have a catastrophic fire, and so the utilities alone cannot be the insurers of last resort. It set up a liability cap of 20 percent of the utility's T&D equity rate base.
Nat Bullard: Transmission and distribution, for those listening.
Pedro Pizarro: Thank you. We have so many TLAs, three-letter acronyms. Let's take the Eaton fire. Since we've said it's likely associated with our infrastructure, the first $1 billion in damages is coming from our customer-funded self-insurance. Beyond that, we will be drawing funds from the wildfire fund, which is administered by the California Earthquake Authority. By the way, we should talk about the wildfire claims program we've also set up independently, which allows our customers who were impacted to get recoveries much more quickly than through standard litigation. Time is of the essence here, and this is one way we've taken accountability. However we get there, once we have completed the litigation, settlement and claims-paying process, we go to the Public Utilities Commission. The law says that as long as we have a safety certification, we're presumed to have been prudent, unless somebody creates a serious doubt about that prudency, in which case the PUC will go through a process and ultimately adjudicate our conduct. If it determines we were indeed fully prudent, there is no repayment to the wildfire fund of the amounts we withdrew. If we're found to have been imprudent, the PUC can determine that we were partially or wholly imprudent and require our shareholders to repay amounts to the wildfire fund, but with that liability cap in place. We will pay no more than 20 percent of our T&D equity rate base for any and all events over a three-year period.
The reason for that was to strike a balance, recognizing that a single event can be so catastrophic that it sends a utility into bankruptcy. Bankruptcy is not good for maintaining the financial health of investor-owned utilities, which are critical to the state's economy. The legislature and the governor found this balance: 20 percent is a big number. For Eaton, it would be about $4.3 billion of penalty exposure if we're deemed imprudent. By the way, we've said we are confident SCE will be able to make a good-faith showing that it was prudent. But in any case, $4.3 billion would be a very difficult day for our shareholders, but it would not send us into bankruptcy. That was the balancing act.
Now, what's going on now? We don't know how large Eaton will end up being. We have not been able to develop an estimate of the losses. We know losses are probable, but not estimable today. There are a number of third-party estimates floating out there, and to be honest with you, they're all over the place, but some of them might even exceed the capacity of the fund, just over $21 billion today. So the potential that Eaton could consume all or much of the existing wildfire fund became a big concern not only for Edison, but for the other two investor-owned utilities. You saw PG&E's shares decline significantly after Eaton, as did Edison's.
Nat Bullard: Yes.
Pedro Pizarro: The fear was that if there were another catastrophic fire, in spite of utilities' best efforts, there might not be funds left in the wildfire fund to support victims. And importantly, the liability cap I mentioned is extinguished when the wildfire fund is extinguished.
So in 2025, the legislature and the governor went to work. They passed a stopgap measure, SB 254, which did a couple of things. It created a continuation fund that would apply to future fires, not to Eaton. That fund would have $18 billion in nominal contributions over time; some rating agencies have estimated that at about $10.5 billion in NPV terms.
Nat Bullard: Sure.
Pedro Pizarro: So that's a start, but you could certainly imagine fires that exceed the capacity of that continuation fund. Recognizing that, the legislature said, "Look, we know we need to do more, and we know we need larger structural reforms," and it tasked the California Earthquake Authority with a comprehensive analysis of what else the state needs to do about wildfire mitigation writ large, not just about utilities. The CEA produced its report in April 2026. It was really well done. They consulted lots of stakeholders, got all that input, did a lot of math and had consultants, and the report came out with broad options for the state to consider. It covered everything from upstream mitigation of wildfire risk, where it acknowledged that utilities have done a lot and there's probably a lot more that needs to be done in other sectors of the economy, to the insurance market. Having accessible, affordable insurance is critical, and that's been a challenge.
The report also acknowledged that there may need to be a role here for the state in providing a backstop, and the way I think about that is as a way to make the commercial insurance markets workable. I've talked privately with CEO peers at insurance companies, and a couple of them have described it this way: they have pretty good models. If you think of a probability distribution of events, large and medium, they can size those and figure out the pricing. The problem is that California has had these extreme tail events. What used to be 100-year events are happening more often now, and that gets really hard to price in the commercial markets. That's a place where a state backstop might be quite beneficial. In fact, you've seen models for that at the national level, with Price-Anderson protections for nuclear facilities. You've seen Florida step in to shore up the markets for hurricane insurance. France has an all-hazards model that's really interesting, which the CEA cited too.
We then went into the 2026 legislative session, and there were a number of hearings. I'll spare you all the details, but we were hoping for a package that included real structural reforms: from our perspective, further work in mitigating wildfires across the economy, but importantly, from a utility perspective, the security of the liability cap, so there's clarity about what the worst case is. That's needed to attract capital into the state at a time when, as we talked about earlier, we have massive capital needs to keep up with and serve the load growth we expect. We also needed structural reforms to provide clear liquidity for future fires, a source of funds to make sure victims can rebuild their lives.
Unfortunately, the package that made its way through the legislature had none of those things. It had some small improvements, such as a potential fast-pay claims process that would look a lot like what we're doing for the Eaton fire, and some measures on utility accountability, but it didn't solve the big structural problem. Frankly, I give a lot of credit to the Assembly speaker, who said he recognized there was a lot of work on this, but it just didn't go far enough, and did not have the Assembly vote on it. Now there's potential for a special session of the legislature; we'll see whether the governor calls one. A couple of Assembly leaders have already said they'll be holding hearings through the fall of 2026. Given the conclusions of the Earthquake Authority's report, our hope is that there's a deep sense of urgency, because the cost of inaction for the state's economy is huge. We're hopeful we'll see reforms in a special session in 2026, and we're certainly advocating for that. If not, this topic will need to be at the top of the agenda as we head into a new legislative session with a new governor in 2027. Again, I hope it gets solved in 2026; the state needs it.
Nat Bullard: Let me come back with a look ahead for other states. What is the lesson for other service territories, utilities and states, as yet another postcard from the future? How can the deliberations you've gone through, the choices made and the research by the Earthquake Authority guide others as these one-in-100-year events start happening once every five years and come our way too?
Pedro Pizarro: That goes to the work we're doing at EEI, bringing together investor-owned utilities from across the country to think about this at a national level, and it's a number of things. First, we've been sharing best practices across utilities in the country, and that's really important: how you think about hardening the system, the responsible use of public safety power shutoffs and so on. Second, we need good collaboration with government. Some of the discussion at the national level is whether refinements to federal law are needed to better support collaboration with federal agencies, in order to reduce wildfire risk before a wildfire happens, including ways to streamline the process of working with agencies like the Forest Service or the Bureau of Land Management. A lot of utility lines go through a lot of government land. I appreciate that our government partners have been trying to help with that, but more is needed, and new legislation may be needed.
We also need to think about the liability standard, which really varies by state. California's inverse condemnation doctrine is pretty unique, but quite frankly, even in most other states without inverse condemnation, as some of these cases have gone to jury trial, you've seen some very large awards. Let me back up: it's absolutely important that when somebody's impacted by fire, they are able to get fair compensation for their physical damage and economic damages. But you've seen non-economic damages in some states that have been staggering, and ultimately that creates a cost for everybody else on the system. Even if you say that's coming from shareholders for a given fire, it's going to have an impact on the utility's balance sheet and financial health. That in turn will affect credit ratings, which in turn affect the cost of debt, which is passed through to customers. So ultimately customers and citizens, whether as taxpayers or as utility customers, end up feeling the cost of excessive damage awards, and that's what you've seen in a number of states without inverse condemnation. This really is a national issue. Is there a possibility of defining a liability standard at the national level, or at least having sensible liability standards apply at the state level? You've seen some states move on that; for example, I believe Utah set some limits on the amount of non-economic damages that can be awarded, in order to have a fair outcome. Another concept that could apply broadly is some sort of wildfire fund, some way to socialize this cost so that there's support for impacted individuals, in a way that's not only fair but allocates costs to minimize the total cost to the economy.
Maybe I'll close this by saying that when I think about the Lahaina fire, that was again an unprecedented set of conditions for our colleagues in Hawaii. But I suspect that if they had gone to the regulators before the fire and said, "We've been looking at what California is doing, and we want public safety power shutoffs to be something we do," I don't know what the reception would have been.
Nat Bullard: I think that's the right question, and I'm with you on that. We observe these things in the breach. Unfortunately, the way we come to policy on these may be that only after these events have arrived are we receptive to even making these kinds of plans, because otherwise they're outside of experience, and they're hard to account for, literally and metaphorically.
Pedro Pizarro: I appreciate that. But this is where the fact that it's not just happening in California matters: it's happened in places where it wasn't expected. And you have climate change making conditions more volatile over the next couple of decades. It is sadly coming to a theater near you, so prepare the theater. And this goes beyond wildfire, to other climate-related natural impacts. The paper we'll have released by the time you post this talks about sea-level rise. In California, we've seen something like eight inches of sea-level rise over the last century, and we expect another foot by 2050. Think about it: it took a century to get eight inches of rise, yet we're going to see 12 inches in the next 24 years. How do we prepare not only our electric infrastructure, but partner with communities so they can prepare themselves too? Southern California Edison cannot unilaterally make the choice of whether one of our coastal towns will defend in place or move more of the community inland, away from the likely storm-surge area. In some sense, we can't make our decision until they make theirs. That's why partnership and proactive action, not just by utilities but by communities and other sectors of the economy, is so critical. This part of the climate change curve is here, and it's not going to get bent back down. There's so much focus on climate change mitigation, appropriately, to keep the curve from getting worse, but we need to accept that there's a piece of the curve we're going to have to live with, so we have to prepare for it now.
Nat Bullard: That's right. And it's not just sea-level rise; it's also extreme precipitation and the extreme lack of precipitation. All these things will have to be incorporated into planning and thinking.
Pedro Pizarro: Floods and droughts: we're going to get both, and more of them. And extreme heat: we expect the top 1 percent of heat events to become seven times more prevalent, and hotter. That's a lot of impacts. On the power resource side alone, our team estimates that by 2050, the added heat will create an extra power requirement equivalent to what would power something like half a million homes today.
Nat Bullard: It's a vicious cycle to combat, in a sense. The hotter it is, the more power we're going to need, and unless that power is zero-emission, it will itself have some quantum of warming impact.
The technology wish list
Nat Bullard: Let's close it out briefly. We've touched on the technologies you deploy in the system, but what's on the wish list? Think five or 10 years out. What would you love to have available and economical? What are you looking for?
Pedro Pizarro: A lot of things, and the good news is that we're working on them now. We see technology transforming how we do business across the board. There are some obvious ones, like making our back office smarter and using AI to help streamline operations, and frankly to make jobs more meaningful too. A lot of jobs have a rote component that can be replaced through robotic automation or AI. On the grid side, we already have something called AWARE. Think of it like your smartwatch, sensing your temperature and your heartbeat and, hopefully it never tells you this, telling you if you're about to have a heart attack. AWARE fuses data from multiple sensors across our distribution system, both to help our teams predict when a fault might be about to occur and, when one occurs that we didn't predict, to help us locate it more quickly. That technology won the Edison Electric Institute's Edison Award in 2025, EEI's top award for technology innovation.
We're also looking at how to make the grid more autonomous and more adaptive. We're in the early stages of this now, and on the wish list is seeing it really come to fruition, so that we have more self-healing components of the grid, using sensors to keep track of components and signal when they may need maintenance, so we can avoid an unexpected outage. One of our pillars is workforce intelligence and smart execution: things like intelligent capacity planning, to keep looking at what generation and what wires we need to serve new load; smarter scoping and design; and strategic asset management, using AI to forecast where we're going to have issues, so we have risk-informed insights on our assets and can do the maintenance in time. Then there are the control rooms. If you've ever been in an electric control room, or if you haven't, come on down and we'll give you the tour. We're seeing more and more support there for our teams, but I think there's even more we can do, using AI to support them with switching programs when we're doing work out on the grid, being able to sample the entire space of potential outcomes, and increasing both the safety margin and efficiency.
So I'm excited about this. You hear a lot about people's concerns around AI, and those are appropriate. Governments globally will need to think about the right guardrails. We're seeing AI act autonomously outside its parameters, so there are certainly concerns there. On the other hand, this feels to me like just about every other technology innovation humanity has experienced. There's a learning curve, and there are displacements, but ultimately these tools help us as a society go to a next level. I think there's a really exciting next level coming in how we can use these tools to operate our system more safely, better and more cost-effectively, and frankly to deliver a better customer experience.
Nat Bullard: As somebody who uses these tools every day and is building a business with them, I hardly disagree. That's a perfect place for us to call it. Pedro Pizarro of Edison International, thank you very much for joining us on Nameplate.
Pedro Pizarro: Thank you, Nat.
