California’s Next Power Play - Transmission & Renewable Energy Markets

At the Los Angeles Business Council’s Sustainability Summit, former LA Times climate columnist Sammy Roth led a wide-ranging discussion with CAISO CEO Elliot Mainzer, SCE’s Mike Backstrom, and developers from AES, EDF, Southwestern Power Group, and Vineyard Offshore on how California will build the grid a clean economy requires.

Mainzer framed the scale: California must integrate 100–120 GW of new generation over the next 20 years—“more than $50–60 billion” in transmission—on top of $20 billion already approved across the last three CAISO cycles. Optimization—reconductoring, non-wires, grid-enhancing technologies—helps, he said, “but we still need a lot of new lines in the air.” With about 65 GW of current deliverability, Mainzer warned that the buffer “disappears fast” if the state continues to add 7–8 GW per year, making energizing new lines and efficient interconnection management essential. VX News offers an edited excerpt capturing highlights from the Los Angeles Business Council’s Sustainability Summit.

“…[this new governance framework] creates parity among all utilities while maintaining state jurisdiction over key policy and rate-making authorities in California and other states. Equitable, independent governance has been a goal for years.”
— Eliot Mainzer, CEO of CAISO

[...] I want to start with Elliot. As head of the California ISO, he’s got a broad lens on everything. California ISO, as many in this room know, oversees the electric grid and the markets for most of the state. As a frame for this conversation, how much new transmission does California actually need to build to hit our clean energy goals over the next 20 years? [...]

Elliot Mainzer: A couple of years ago, we put together a 20-year outlook for transmission. We tried to step back and think about the big grid in California—inside the state, offshore, and into the Intermountain West. We figured California needs to bring on somewhere between 100,000 and 120,000 megawatts of additional generation over the next 20 years to stay on track with SB 100 goals.

For context, that compares to a peak load we have now of about 55,000 megawatts?

Elliot Mainzer: Our all-time peak in California was about 52,000 megawatts—back in 2000.

We’re talking about doubling that?

Elliot Mainzer: Yes. It’s a significant amount of transmission. You can measure it in dollars—it’s probably more than $50 to $60 billion worth of transmission. Just in the last few years, we’ve approved about $20 billion in projects.

At CAISO, we’re extraordinarily focused on making the best use of our existing grid as well. There’s a lot of emphasis right now on optimizing resources, leveraging the distribution system, using non-wire alternatives, reconductoring, and grid-enhancing technologies. We’re doing all those things, and doing them ambitiously and effectively—but we still need a lot of new lines in the air.

We currently have about 65,000 megawatts of transmission deliverability in our inventory. That gives the utilities a decent buffer for resource adequacy, but we can eat that up quickly. When you add 7,000 or 8,000 megawatts of new generation each year, that inventory disappears fast. So yes, we’ve done a ton of planning and approved about $20 billion of transmission in the last three planning cycles.

The next phase, beyond optimization, is energizing new transmission—getting that infrastructure online so we maintain a healthy inventory of transmission deliverability. If we couple that with efficient interconnection queue management, we can make sure that as utilities procure new clean energy resources—whether inside California, out of state, or offshore—transmission doesn’t become the limiting factor.

I see Mary over there, and she reminds me every time I see her: we have to keep onboarding, keep transmission energized, and maintain that inventory so we don’t bottleneck. That’s a key focus for us at the ISO.

I want to follow up on the practical steps it will take to accomplish those goals…Before we get there, one issue that’s been on everyone’s mind in recent months is the new regional market Governor Newsom pushed hard to pass through the legislature this year. The idea is that this market will help create some of the efficiencies you mentioned, not necessarily through reconductoring, but by getting more electricity flowing over the existing grid throughout the western United States.

The goal is to make it easier to move electrons from where they’re generated to where they’re needed – whether that’s wind in New Mexico, hydropower in the Pacific Northwest, or solar in California. The intent is to move electricity from areas with excess capacity to those with higher demand. How much will this realistically help, assuming the market is established? The bill primarily sets up the political and governance structure to move this forward, but how much could it actually reduce the need for new transmission buildout?

Elliot Mainzer: First and foremost, it’s going to help a lot. Over the last ten or eleven years, we’ve been operating the Western Energy Imbalance Market—a short-term, real-time market with a large footprint across the West. It connects about eleven states and twenty-two entities. It’s that grid that’s bigger than the weather, and it’s made a real difference, particularly in recent years, improving both reliability and affordability.

This is what, hour-ahead trading?

Elliot Mainzer: Closer to the next fifteen minutes. Think of it as a short-term swap meet where you’re trading heat rates and optimizing the system. The bigger value, though, is in a day-ahead market, which represents a much larger commitment. Many utilities that have been participating in the EIM are now considering a deeper engagement in this broader energy market with more extensive optimization.

They’ve raised legitimate concerns about governance and want to ensure that market rules operate under an independent governance framework. We have a fabulous Board of Governors here in California—they’ll continue to carry major responsibilities for transmission planning, interconnection queueing, and resource adequacy. Still, there’s a shared understanding that if we’re going to unify across the West, we need a different kind of governance model.

Governor Newsom, along with an incredible coalition—we saw Assemblymember Cottie Petrie-Norris here today, showing tremendous leadership—made that happen. We now have the physics and economics in place for a truly valuable, wide-area energy market, and the ability to expand it into the day-ahead timeframe under independent governance through a new entity that will provide oversight.

I’ll add—this is the first time all California utilities are participating in our energy markets, along with key partners across the region. The coming months will determine how this takes shape, but this new governance framework creates parity among all utilities while maintaining state jurisdiction over key policy and rate-making authorities in California and other states. Equitable, independent governance has been a goal for years. Governor Newsom said it best at the signing ceremony: “We’ve been working on this for years and years, and this coalition came together and made it happen.”

We’re excited to support it, and we believe it will open tremendous opportunities for California.

This would be, in theory, a good time to bring you into the conversation, Mike, as a utility that Elliot just referenced as being part of these markets and working on these new structures. We’ll come back to you…Because I want to follow up with one question first. There’s been some division within the environmental community over this new regional market. Many supported it, while others expressed concern. This has been a debate that’s raged for a long time, until Governor Newsom and members of the legislature pushed it across the finish line this year.

The question has always been whether a regional market could require California to give up political control of the ISO to the point that other states could force us to accept coal power. There have also been concerns about transparency and whether reduced oversight could lead to higher costs for Californians. You run the ISO alongside the Board of Governors—do you have any concern about those possible issues?

Elliot Mainzer: First of all, those are always legitimate issues to raise. California is rightfully proud of its clean energy leadership, and all of us here are honored to be part of that effort. The concern about maintaining control over state jurisdictional issues around energy policy is strong. Not just in California, but across the West. The new legislation includes specific safeguards to preserve state-level policy autonomy. Those protections apply not only to California but to every participating state.

It’s important to remember that we’ve been operating the Western Energy Imbalance Market since 2014. That spans California, Arizona, New Mexico, Utah, Wyoming, Idaho, Oregon, and Washington.

That started as a partnership between CalISO and PacifiCorp—Warren Buffett’s company—which operates a lot of coal plants in Wyoming and Utah, right?

Elliot Mainzer: That’s true, and it’s a great point. Over the last eleven or twelve years of operating that market, California’s clean energy commitment has only strengthened. We haven’t been overtaken by Utah’s energy policy. Instead, we’ve leveraged wide-area physics to save money for customers and, frankly, to keep the lights on under some very difficult conditions, like the extreme September 2022 heatwave. The structure has allowed states, particularly California, to maintain policy autonomy while benefiting from regional efficiency. It enhances reliability and affordability without compromising environmental standards.

The timing of this reform was ideal—reliability and affordability have never been higher on everyone’s agenda. For CAISO, this process lets us stay focused on operating the market—running the Energy Imbalance Market effectively, advancing the Extended Day-Ahead Market, and ensuring a seamless western energy network. Stakeholders across the board came together to make this possible. Labor unions got comfortable with the framework. Utilities stepped up. Environmental advocates joined in.

At the end of the day, that coalition presented Governor Newsom with one of the broadest alliances around a single issue he’d ever seen—and I think he even noted that himself. Getting this legislation passed was foundational. Now we turn to implementation, and everyone along this line is going to play a role in making it a success.

[...] Talk about the practical lessons Southwestern Power Group learned that might apply to California right now. What were some of the key challenges you faced in developing SunZia in New Mexico and Arizona, and how might those lessons inform California’s approach as we launch new transmission projects? What steps should policymakers be considering to overcome those same barriers?

Ravi Sankaran: Yeah, it’s a great question. I’m not sure my answers will be especially problem-solving for you. For background, our company, Southwestern Power Group, started the SunZia project in 2006. I got involved in 2008. It began as a five-party joint venture. We recognized a huge wind energy region in New Mexico with no transmission within 100 miles, it is some of the best wind resources in the country. We decided to build a 500-mile extension cord, essentially, to deliver that power to the load centers, to people in Los Angeles and across California.

[...] With SunZia, this group of five parties said, okay, we could probably permit this in three years, build it in two, and be online by 2013. We had a permitting budget of $12 million – $12 million to get to shovel-ready. That $12 million became over $200 million. The three years to permit became fifteen. The five-party venture dissolved, and it ended up being one party carrying the project through fifteen years of permitting. A few observations and lessons from that. It’s a poster child for why we need federal permitting reform. We can’t let a single agency hold a project hostage. In this case, there were multiple agencies creating roadblocks. That’s a clear takeaway.

If you’re going to pursue projects like this, you need patient capital. You need an effective boots-on-the-ground strategy and strong external engagement. You need bipartisan engagement and support—transmission is not a left or right, red or blue issue. From a planning standpoint, Elliot, you mentioned the 20-year outlook…they were doing that even before it became a requirement under FERC Order 1920. Long-term planning and diversification are essential.

SunZia is a moonshot, the same way TransWest Express to Wyoming or SWIP North to Idaho are moonshots. Even offshore wind kind of falls into that category too. We also need the singles and doubles—the more actionable, near-term projects. The 20-year outlook and the Transmission Planning Process are really important steps. Ten years ago, those plans weren’t as robust, and now we’re seeing the benefit of taking bold, forward-looking actions. Those are exactly the kinds of steps we need to expand going forward.

You mentioned the need for permitting reform and said it’s not a red or blue issue at the federal level. I have to push back on that as the Trump administration just moved to block the Grain Belt Express…because it was a transmission line for wind power. 

It raises the question: is this still a bipartisan issue? Can we really depend on both sides to come together on permitting reform?

Ravi Sankaran: I guess what I meant is that it should be a bipartisan issue. Permitting reform is tricky. There actually is some appetite for it within the current administration. It really comes down to strategy. You have to look at who’s calling the shots in any given administration. SunZia survived four different presidential administrations, and each one has its own priorities. You have to adapt, at least to some degree, to the people in charge at that particular time and place.

[...]

…A social license to operate with the question of battery fires right now is front of mind for basically every community there where batteries are being developed, right?

Dan Patry: Certainly. When we look back to January of this year with the Moss Landing incident, where we started there.

That's the big battery fire. Folks are mostly familiar here, but up along the central coast. Was that the biggest battery fire there's been anywhere? Well, compared to other battery fires. Was it big compared to the explosion at the Chevron refinery in El Segundo last week? No.

Dan Patry: Mercifully, no one was injured in the Moss Landing incident, which is the most important point. From an industry standpoint, I sit on the board of the California Energy Storage Alliance, and our focus since then has been on proactive engagement with local agencies, fire authorities, and others. We conduct tabletop exercises to explain how the technology operates on site, where muster points are located, and how emergency procedures work. This transparency helps build confidence within the communities where we operate. There’s no such thing as zero-risk energy – it doesn’t exist – but our goal is to demonstrate that we have a plan, and that we follow it.

Talk about the bill that Governor Newsom just signed yesterday, SB 283, which creates a kind of process for community input or safety plans. Describe what that will do, because I think you were beyond excited about that.

Dan Patry: SB 283 from Senator Laird, who represents the district where Moss Landing is located. What the bill intends to do was essentially bring forward the latest and greatest National Fire Protection Agency codes and standards and best practices on battery storage, forward into the California Fire Code, because the cycles were offset. You would be in a situation where you wouldn't be bringing in the latest and greatest fire suppression techniques, balance of plant, all these different pieces of the puzzle. 

Now with this bill, it essentially pulls that all into one place. It requires you to, on the front end, meet and confer with the local fire authorities before you apply for approval. Then, after the fact, kind of at the developer's expense, you ask the fire officials to please come in and inspect us and give us the all clear before we operate. So a really good outcome in doing what most parties are already doing, but in a more transparent way.

You used the term ‘social license to operate,’ which I think is on everyone’s mind involved in developing or facilitating renewable energy. Compared to fossil fuels, these technologies are far less harmful and lower impact. 

Still, as you were just saying Dan, without a level of social license to operate, you inevitably face community opposition. Even if projects overcome that opposition, the process can take too long, and communities may end up relying on less sustainable options simply because they’re familiar. I’m curious if you could expand on that…

Dan Patry: I would say we're an all-technology provider. We have about 850 megawatts of operating battery storage in California, some paired with our solar assets and some standalone. We’re taking an all-of-the-above approach and bringing lessons learned from other technologies into the battery storage space.  We also have a fantastic Stakeholder Relations team, many of whom are here today, that engages with counties, cities, and communities to explain the technology and outline our processes in the event of an emergency. For example, we operate a large facility in Alamitos near Leisure World, a retirement community close by. We have regular touchpoints with residents there where they can ask questions and better understand what they’re hearing or seeing at the site. Those efforts aren’t necessarily about enabling further development on-site, but about being a responsible and trusted partner in the communities where we operate.

Rick Umoff: I could quickly add to that. We’re working in a community with a long history of extractive industries, and we’re very mindful of that legacy. We’re also fortunate to have a supportive community, and we don’t take that for granted. We have a tribal liaison on staff who is a member of the Hoopa Valley Tribe, as well as a fisheries liaison. Our project is still several years away, but we already have an office in the community. We’re investing early to come to the community and understand their needs and interests.

Ravi Sankaran: I also want to point out that the technology being installed today—lithium iron phosphate systems and the shift toward containerized designs—is far safer than what was installed five years ago. Many of the incidents we’ve seen in the past, like Moss Landing, likely wouldn’t have occurred with today’s technology and safety standards.

Ravi, there are still stories and perhaps even ongoing lawsuits around SunZia. Pattern is now building it, but throughout its development there were numerous challenges: lawsuits, objections related to quality of life, local environmental concerns, and tribal issues. I imagine that’s a reality every transmission developer faces today.

Ravi Sankaran: The whole stakeholder engagement process is critical. Power plants are one thing, and they’re localized, but a 500-mile corridor introduces a completely different scale of complexity. You encounter a wide range of issues: cultural and archaeological concerns, biological impacts, multiple agencies, and layers of jurisdiction. 

There were countless challenges, and we could spend all day talking about them. It really comes back to external engagement and having boots on the ground. We’ve hired many of our people from the counties, people who know the local supervisors and community leaders. You have to engage effectively. There will always be opposition, and there still are people protesting SunZia, but the key is to engage and address issues the best you can.

[...]

Ryan, I’d like to bring you into this discussion…what does the federal permitting landscape look like at the moment? Many are aware of the obstacles that have emerged on federal lands for renewable energy projects. I’m curious what that experience has been like for your team, whether you’re focusing more on private, state, or public lands, and what you’re finding to be the most significant permitting challenges right now.

Ryan Pfaff: Happy to weigh in there. Power Solutions is one of the oldest clean energy developers in the U.S., with about 40 years of experience. We’ve worked across a wide range of technologies, historically focused on wind, and we’re now advancing a major offshore wind project on the East Coast that I’ll touch on in a moment. At this point, most of our work centers on solar and storage projects, both paired and standalone. We’re primarily focused on projects in the U.S. and Canada. In Canada, most of our work centers on wind, while in the U.S., our portfolio is largely solar and storage. There are still a few companies, like Pattern and others, continuing to advance new wind projects.

…Obviously there's offshore and onshore available, but not as much new onshore wind.

Ryan Pfaff: The permitting question is an interesting one. I have an answer for the onshore piece, and I have concerns based on the offshore experience. We’ve been in a joint venture on a large offshore project for about seven years. It received its federal permit before the change in administration, and like many other projects on the East Coast, it followed every step of the permitting process. There are established requirements, and developers spend tens or even hundreds of millions of dollars over many years conducting studies, meeting standards, and following the rules. After all that effort, when an approval can suddenly be reversed or delayed by a new administration, that becomes a serious problem.

This isn’t just an offshore wind issue – it’s a broader concern. If the policy pendulum swings back toward gas, the same uncertainty applies. What happens to those projects if every change in the White House brings a different approach? The project we’ve been developing requires continuity across roughly three presidential terms to be completed. It makes me think of the SunZia project – these are 12- to 16-year efforts. California’s offshore projects have even longer timelines. For East Coast projects underway right now, even if there’s renewed support, success depends on stability across multiple administrations.

If there’s always a fifty-fifty chance that policies will flip, and that a permit today might not be valid tomorrow, it becomes extremely difficult to invest in long-term infrastructure in the U.S. That applies to fossil projects as well. If they fall out of favor and later there’s a push to bring them back, it will take real conviction for investors to commit, knowing that political changes could undermine their projects. The real concern, as we’ve seen with offshore wind, is that when a company plays by the rules and secures a permit through the proper process, it must be able to rely on consistency and stability in government decision-making. Without that, we risk scaring away the very investors needed to build critical energy infrastructure.

…How much stability or certainty can that create in the face of such significant uncertainty around government policy?

Ryan Pfaff: I’m not answering your question about onshore permitting directly, but one of the most important developments in this industry is that, unlike in the early days when it was backed by RPS’ and clean energy mandates, there’s now an undeniable need for power, period. Every megawatt hour that can be produced is urgently needed to meet priorities for this administration: AI dominance, energy dominance, and outcompeting China. Every project that could come online to support data centers is essential if we don’t want to fall further behind. This is all part of maintaining U.S. competitiveness on the world stage.

Renewables can compete. That doesn’t mean every type of renewable project will succeed – some experimental technologies may not – but mainstream renewables are competitive and compelling for customers. There’s strong demand for them, and there’s also demand for gas. It’s not one or the other; there’s room in the market for both, including hybrid systems that pair gas with renewables.

To your question, I do worry about how government opposition can still slow things down, even when demand is there. The reality is that much of the West is on federal land. Even with lower-cost technologies like PVS, the permitting and land-use challenges can still be significant.

Rick, I want to hear your thoughts, but hold that for just one moment while I follow up. If solar can compete, that’s great. However, if the federal government is blocking new solar projects or canceling previously approved ones it's going to slow it down. What has your experience been?

Ryan Pfaff: The experience has been that the offshore precedent is concerning, though there seems to be a particular focus on offshore wind that hasn’t extended to other technologies. At this point, there’s no bad news – there’s just no news. When the executive orders were issued directing the Department of the Interior and the Department of Treasury to evaluate various actions, that process is still in progress. As a result, many teams within the Department of the Interior remain uncertain about what they can authorize, and everything has effectively come to a standstill.

It’s not that projects aren’t approved; they simply aren’t advancing. That means it’s important to pitch projects based on their merits: meeting the need for power, creating jobs in the area, and recognizing that alternatives are limited. Gas projects take time to ramp up, and GE and others report they no longer have the same manufacturing capacity they had 25 years ago. Rebuilding will take time, creating a shortfall if projects are canceled or delayed. These are the messages we are communicating to the government.

If I may editorialize briefly, you used the phrase ‘energy dominance’ earlier. I wrote a column on this a few weeks ago. If energy dominance were a real priority, there wouldn’t be delays in the valuation period. Solar and storage projects on federal land would be moving forward immediately, with nothing left to evaluate. 

These projects deliver electrons that are cheap and ready to go. That isn’t the priority, though that is a separate conversation. Rick, you wanted to weigh in?

Rick Umoff: I want to pick up on the issue of political risk. We are entering an era where we will need to hedge our bets in multiple ways. Diverse resources are critical for both reliability and cost. Regulatory and political risk at the federal and local levels can pose challenges. Having worked in the solar industry, I’ve seen problems arise when communities aren’t engaged or when there is overbuild in a particular area. This will increasingly challenge grid and energy planners. One way to navigate this is by maintaining a diverse portfolio. California has many irons in the fire and isn’t overly reliant on a single energy resource or scale of resources.

Mike, what do you think? Is that the right way to look at things?

Mike Backstrom: Absolutely. In terms of the broader picture of timeliness, reliability, and affordability, the question is how to bring all those pieces together for our communities and our state. If we get caught up in pursuing only one type of resource or extending projects further geographically, we elongate time frames. Elliot mentioned the congestion in trying to bring resources into some of the project queues today. I don’t think anyone has heard of a project that takes longer and gets cheaper as a result. The reality is that the more time that goes by, the more new cost pressures emerge, and we see that across every facet of the business. 

From our standpoint, a lot of what the panel has touched on hits the right notes regarding holistic planning. Currently, utility operators have separate planning processes for power procurement, distribution, and transmission, with some intersections. We need to move toward a paradigm that holistically plans across all of these areas. This approach creates an energy procurement portfolio that aligns with smart grid development at both the distribution and transmission levels. Communities can then understand what is happening, why projects are sited where they are, and how they fit together. Serializing singular developments makes it difficult for a given community to feel they are being treated fairly. Without presenting a comprehensive picture of how projects interconnect and contribute to the larger system, it’s hard to convince anybody that it’s the right thing to do.

On affordability, a key focus for utilities and the state is matching power delivery with demand. Timely, proactive grid development avoids rushed construction at higher expense and ensures people can connect to the system. Utility costs and power bills are lower when demand aligns with available supply. Looking toward 2045, projections indicate that with coordinated transmission and distribution development, aligned with electrification of end uses, we can achieve a 40% reduction in overall energy costs, including electricity, gas, and natural gas. Achieving that outcome requires careful, integrated planning from the start.

[...]

…Dan and Ryan, you build batteries. How fast could we scale up in California, and even nationally, if there were a concerted policy effort to address rapidly growing electricity needs with batteries instead of gas? What could realistically be achieved?

Dan Patry: I'll offer this perspective. AES Energy Storage and our AES Next organization created an OEM called Fluence, which is now a standalone company and a U.S.-based integrator and manufacturer of containerized solutions used in many of our projects. Manufacturing capacity in the United States is still developing, located in Utah, and we are scaling it up. 

The interesting part of your question is the implications for places like California. The CPUC recently released a draft proposal for an NTR covering new procurement, roughly 1,500 megawatts of net qualifying capacity per year. A key consideration is the availability of electrons to charge these assets. For example, suppose Diablo Canyon goes offline and AES assets in the Alamitos and Huntington Beach areas also go offline. In that case, sufficient charging infrastructure is needed to ensure these batteries function as intended. So does that influence procurement policy down the line? Are we just going to do more energy only projects, that are just renewables, and do that alone? There is a scenario where battery storage procurement could accelerate, but it is not in a vacuum and must be planned alongside these broader impacts.

Ryan Pfaff: I agree with that. You would have to prioritize batteries and allocate resources outside the normal process, allowing them to move ahead in line to achieve deliverability sooner. Some projects have no value until 2034–2035 when certain system upgrades are completed. These projects could be built today if the system were rearranged to allow batteries to produce their full benefits. It takes years, and changes would be required because a long line of projects is waiting for their green attributes. There is no way to accelerate a single project without altering the system.

[...]

Panelists:
Mike Backstrom, Senior Vice President, Regulatory Affairs, Southern California Edison 
Elliot Manzer, President and CEO, California Independent System Operator (CAISO)
Dan Patry, Director, State Government Relations, AES
Ryan Pfaff, Executive Vice President, Grid & Distribution Scale Power, EDF Power Solutions
Ravi Sankaran, Senior Director, Business Development, Southwestern Power Group
Rick Umoff, California Market Lead, Vineyard Offshore