Assembly Standing Committee on Utilities and Energy

Good afternoon and welcome. I'd like to convene today's hearing of the Assembly Committee on Utilities and Energy. Before we move to the agenda, I have a few housekeeping announcements to make. First, I will maintain decorum during the hearing as is customary in order to hear as much from the public.

Within the limits of our time, we will not permit conduct that disrupts or otherwise impedes the orderly conduct of legislative proceedings. Any individual who is disruptive may be removed from the room for today's hearing. Assembly Members Boerner, Irwin and Zbur have been excused. Today is a little bit of a double header.

We'll begin with our final Bill Bill hearing of this Assembly session and then we will move to our annual oversight hearing on electric reliability. We have four measures on the agenda and three of those are on consent.

As a reminder when we are reviewing our bills, primary witnesses in support must be those accompanying the author or who otherwise have registered as support position with the Committee and the primary witnesses in opposition must have their opposition registered with the Committee. Let's see. We will go ahead.

We don't we do not have a quorum, so we are going to go ahead and begin as a Subcommitee. As I said, we only have one Bill on our hearing, AB 1026 by Assemblymember Wilson. When we get a quorum and or Ms. Wilson, we will proceed.

Hello Ms. Wilson, welcome. All right. We will go ahead and begin with File item number one. AB 1026 by Assemblymember Wilson.

And there we go. Thank you. Madam Chair, Members. I am proud to present AB 1026, a Bill that supports California's ongoing need for housing by addressing a too often overlooked barrier, unpredictable utility connection delays that hold up housing projects even after they've been fully approved.

California is in the middle of an urgent housing crisis, one that only that's only been worsened by natural disasters and economic uncertainty. As we fight to build more homes, we must also fight to eliminate unnecessary delays that slow production and drive up costs.

AB 1026 brings much needed transparency and efficiency to the permitting process for developers by holding investor owned utilities to the same clear standards already followed by cities and counties. It requires electric corporations to publicly share what's needed to approve or deny a post entitlement permit, ensures timely responses and prevents last minute changes to application requirements.

AB 1026 establishes fair and consistent standards for the energization application process and strengthens the review timelines recently put in place by the California Public Utilities Commission. This Bill ensures utility providers act as partners in addressing California's housing crisis by keeping approved projects from getting stuck in unavoidable in avoidable delays.

I would like to thank the Chair and Committee staff for their expert feedback on this Bill and confirming that I will be accepting all the Committee amendments. I would like to now introduce my sponsors from Housing Action Corporation Coalition, Corey Smith - Executive Director, and Alisa Pearman - Advocacy and Policy Manager.

Good afternoon Chair and Committee Members Corey Smith and the Executive Director of the Housing Action Coalition or the HAC for short.

Not my choice on that acronym. We're a statewide organization that advocates for building more infill housing for residents at all income levels and we're a proud sponsor of Assembly Bill 1026 because it continues the Legislature's work to put reasonable standards around the review and issuance of building permits and other related approvals.

Beginning in 2021, the Legislature passed AB 2234 which created a standardized application process for cities and counties to review and issue post entitlement building permits.

In 2023, AB 281 continued that work and applied the same concept to special districts and AB 1026 continues that work to bring parity to investor owned utilities or and for context IOUs review documents and it's often necessary for a project to proceed and that's not always timely.

While this process is commonly referred to as a permit or even approval with the amendments referenced, AB 1026 refers to it as energization application, the full process.

While the IOUs themselves may not refer to it as a permit, regardless of those semantics, it is a necessary piece of the puzzle to move the project forward and that approval sometimes depends on other agencies and and other times other agencies depend on the IOUs.

It is an unfortunate complicated process and so we asked our Members and got an example what their experience is with these types of delays and one instance was shared where in San Francisco project was delayed a year and getting comments back took forever, which meant three low income families had to wait a year longer than necessary for new housing.

We have had other Members alter and change housing projects entirely, in order to avoid delays from IOUs and these delays drive up costs and further exacerbate our housing affordability and displacement crisis.

By setting standardized timelines for the energization application process and reinforcing these review timelines recently established by the CPUC, we're taking another step to create a good government guardrail and creating consistency from start to finish. Thank You

Thank you. And before we hear from your second witness, I'm just going to pause for a moment so that we can establish a quorum. Madam Secretary, if you can please call the roll.

[Roll Call]

All right. Wonderful. We have a quorum. You may continue. Thank you.

Good afternoon, chair and Members of the Committee. My name is Kevin Kitchingham. I'm the housing development Director at Mission Housing in San Francisco. We are a community based, nonprofit, affordable developer of multifamily affordable housing. We have about 440 odd properties and have 3,000 residents that call home Mission Housing. I'm here today in support of AB 1026.

It seeks to streamline and sort of bring these approvals in with the Housing Accountability Act. So I can't think of a better. A better match. You had Corey give you a brief indication of the bill's history. We've run into this on a couple of occasions.

We had one of our oldest properties in San Francisco we did a scattered site tax credit rehabilitation on. I know that sounds a little inside baseball. Nonetheless, we were delayed about a year in trying to get a transformer approval. As a developer, we're looking for predictability in the marketplace. We're a business like any other.

Every dollar that we save is another dollar that goes out on an affordable housing property or project. So we're looking to be cost conscientious. That is incredible risk for a developer to take, not knowing where the final design may end up, whether you have the approvals for the equipment, whether you can order the equipment in time.

We had another property, 131 units of Tod that we couldn't figure out how to get a reconductor event through the Intel. The investor owned utility for two years. So we had 131 units ready to open, delayed indefinitely. We came up with a different design to share power with another city building. But all predictability in the marketplace squandered.

And so we're not able to contain costs in that context. So we're happy to have support today. We're happy to provide this support and respectfully ask for your aye commitment today.

Thank you. All right, we'll go ahead and open it up for testimony of support in the room. If you'd like to testify in support of this measure, you can approach the microphone at this time.

Clifton Wilson, on behalf of the San Luis Obispo County Board of Supervisors in support. Thank you.

Steven Sandler with Brown Scene, on behalf of Housing California, in support. Thank you.

Good afternoon. Raymond Contreras with Lighthouse Public Affairs, on behalf of Abundant Housing Los Angeles, Habitat for Humanity California, San Diego Housing Commission, California YIMBY, Fieldstead, and Circulate San Diego — all in support.

Thank you. Okay, moving to opposition testimony. Do we have witnesses in opposition? You can approach the dais.

Good afternoon chair Members. It's good to be in this Committee room. Brandon Ebeck, Pacific Gas and Electric we are respectfully opposed to this bill. I think that we appreciate the work of the Committee that clearly delineates the roles of a local government and the roles of utility. These are two processes that must work in tandem.

We have applications for perfect permits from the local government. Then you come to a utility for electric gas, same as you go to a water utility for other types of service. So it's important that the bill is being amended to clarify those roles. We appreciate that work. We also recognize that there have been delays in the past.

This Committee in particular has spent a lot of time focusing on legislation that was referenced. We have SB 410, we have AB 50. The Commission has established timelines for the application process, the intake process and then the energization process. And this bill I think will start to align with those processes and timelines, which is helpful.

We have come a long way as PG&E and our ability to connect new customers. We did 70% more jobs last year than we did in 2022. That's we're doing about 14,000 connections per year of large scale type single family homes and up more so so we are making good progress.

I think with regards to the amendments we have a question, I think with the second amendment in there, just because it's something we're trying to get addressed through the Commission, we do not think that the 10 day timeline is reasonable. We think the 45 day, it's complicated.

And lastly, it's worth noting that end to end the average application takes about 330 days. The utility is responsible for about 150 of those days. In communications with the author's office we suggested there are three other areas that we should probably look at that can bring down timelines.

It's certain Caltrans permits, it's obtaining easements and it's also this conflict that was mentioned between our requirements and local government requirements about what the right things we should install are. So for those reasons we oppose what we're looking at the amendments. Thank you you.

Madam Chair Committee Katherine Borg with Southern California Edison and we respectfully oppose AB 1026 by Assembly Member Wilson which would require electrical corporations to follow specific timelines and requirements to review post entitlement phase permits for housing development projects. SE understands the importance of timely review of permits and necessary to energy to energize housing projects.

However, this bill is unnecessary, prioritizes one type of project over another. AB 1026 undermines the critical work taking place in the establishing energization timeline order, instituting rulemaking or energization OIR established by SB 410 that PG and you just referred to phase one of the energization OIR.

Establish a reasonable framework based on an electrical corporation's historical timelines and sets new targets to reduce energization delays. These timelines cover customer intake, engineering design, customer site readiness, in addition to critical work such as distribution line extensions and service line extensions.

Utilities continue to work with the California Public Utilities Commission through phase two of the Energization OIR, which is reviewing the progress of the energization framework and may address further refinement. I'll just finish by saying, you know, SE is committed to meeting the growing electrical demands of our customers.

This includes improving our operations and internal processes that can meet the targets set forth in the Energization OIR. The Energization OIR rulemaking should be allowed to conclude before passing any new legislation that would hinder its progress. And for these reasons, we oppose.

Thank you. All right, turning to additional opposition testimony, if you would like to testify in opposition to this measure, approach the microphone. Seeing and hearing none, we'll bring it back to the Committee. Questions or comments from Committee Members? Assemblymember Calderon.

Thank you, Madam Chair. So I have a question. Given the CPUC decision in September 2024. On energization timelines, what is this bill. Seeking to accomplish that that decision didn't satisfy or address?

I think from. And I'll look to my witnesses to also provide comments. I think where we are in this Committee is aligning with what came out in September 2024. And then there are some additional things on top of that. And so I'll note to my.

Appreciate. Work with committee staff kind of early on, like, let's make sure we're hammering out those details. One of the most important pieces to this is the information that is required on the front end when these applications are actually coming in.

And so what we want to be able to do is try to give as much info to the applicant so they can understand what they need to be providing in order for the application to be deemed approved.

There was work done by an organization called the Streamlining Institute, which is based out of Sacramento here, which found that that can reduce the overall permitting timeline being about 40% simply because you're getting better applications in on the front end of the process. As one of the most substantive examples that we think is really going to.

Going to be an actual needle mover with this and hopefully improve the process because we're going to be getting exponentially more housing units over the next 10 years that are going to need to get energized.

Want to respond?

I think it's a fair question. I will also say that when we met with the sponsors a month ago, we asked the same thing of like what, what, what information can we provide?

We had a meeting with our service planning director on and so we stand by if there are particular items that we can more clearly put on our website or application process, we're definitely willing to do that. It's just we need that information on the front end I think to be transparent of what, what else we can provide.

I think our website has a ton of information on it and we work with part of the phase one process in what the second amendment gets to not the is we are now assigning a signed business representative for the case within 10 days and that manager is supposed to walk through hand like it's a white glove service end to end.

Previously it was a lot more handing off across the different pieces. So I think that will help. So that's a lot of just working to get a complete application within that first 45 days and then once that's done then we go and engineer and design easements, all the actual construction work to get it energized.

But I think that will help a lot.

Thank you.

All right, well, thank you.

I want to thank the author for bringing this measure forward and I do appreciate the work that the IOUS have done leading up to this and the work that I know that you will continue to do, both with the author as well as with developers across the state to provide more certainty around timelines and ensure that we are doing everything that we possibly can to get more housing units built across the state.

So with that, would you like to close?

Thank you to the author and thank you for the question to my colleague. And I will note that you know there does need to be consistency across the state for all of our IOUS. And so one may be providing information but making sure that's consistent front and we know that we are in a housing crisis.

We talk about that regularly. Having the opportunity to serve on another Committee that deals with it directly. But it's more than just building more homes. It's ensuring that we remove all delays that hold up the process.

No process or no system is perfect and so every time that we can look at it and fine tune it and provide additional support to ensure that it's streamlined and it is effective to bring more housing. I. It's a great thing, and in particularly as it relates to streamlining our utility connections.

And so with that, I think the testimony that was provided and their support as sponsors of the bill, and I also thank the IOUS and those that have been opponents of the bill because they have, from the very moment of, well, prior to introduction when I told them that I was doing this, they have been at the table.

And I've appreciated them being at the table and having those conversations with me and being open and direct about their concerns. So with that, I respectfully ask for an aye vote.

Thank you. All right, do we have a motion and a second thank you. Motion from Assemblymember Harabedian. Second from Assemblymember Schiavo. Madam Secretary, please call the roll.

Item number one. AB 1026. The motion is due passed as amended to the floor. Petrie-Norris aye. Petrie-Norris aye. Patterson. Patterson. Aye. Calderon. Calderon. Aye. Chen. Chen aye. Davies. Davies aye. Gonzalez. Gonzalez aye. Harabedian. Harabedian. Aye. Hart. Hart aye. Kalra. Kalra. Aye. Papen, Papen aye. Rogers. Rogers. Aye. Schiavo. Schiavo aye. Schultz. Ta. Ta. aye. Wallace. Wallace aye.

Fourteen/zero. That bill is out, and we'll leave it open for absent members to add on. All right, let's see. We are going to go ahead and dispense with the consent calendar. Motion and a second on the consent calendar. Motion from Assembly Member Schiavo, second from Assembly Member Chen. Madam Secretary, please call the roll.

Item Number Two, AB 1301: the motion is do pass to the floor, Item Number Three, AB 1334: the motion is do pass as amended to the floor, and Item Number Four, AB 1436: the motion is do pass to the floor. [Roll Call].

Fourteen/zero. The consent calendar is dispensed with. We'll leave that roll open for absent members to add on. All right. That does--so that was the only bill that we are hearing. What I'm going to do is recess. Oh, what we are--before I do that, we are going to reopen the roll. No problem. Okay. Madam Secretary, please call the roll.

Item Number One, AB 1026. [Roll Call]. That's fifteen/zero.

Fifteen/zero. That bill is out.

This is the consent file. [Roll Call].

Fifteen/zero. That consent calendar is out, and that does conclude, I guess, the first part of today's double header, so that concludes our bill hearing. That is adjourned. We are now going to gavel in for the second part of today's hearing, which is our Annual Oversight Hearing on Electric Reliability.

If I can go ahead and welcome our panelists to the dais at this time, you can go ahead and come on up. I'll make a couple of brief opening remarks as we welcome our guests. So as I said, this is our Annual Oversight Hearing on Electric Reliability.

California, as we know, is the fourth largest economy in the world. It goes without saying that a robust electric reliability is absolutely foundational. I think it's something that many of us take for granted, but this hearing is something that is more of just--than just of theoretical concern.

As we all know, in 2020, many of us looked on in horror as California experienced rolling blackouts, and as California navigates our clean energy transition, reliability challenges will continue to intensify. So the goal of today's annual hearing is really threefold.

Number one: to review the progress that California has made in recent years, number two: to get an update from our witnesses on the reliability outlook for summer of 2025, and number three: to really start to understand the challenges that we will need to navigate in the mid to long-term as well as to understand the action that this committee and the Legislature as a whole can take to ensure that we are positioning California to, as I said, keep the lights on as we move forward.

So with that, we're going to go ahead and welcome our first panelists. We've got two panels today. The first is an update on electric reliability and the second is going to be our provider perspectives on headwinds to electric reliability. I believe our panelists are speaking to us.

I think it's like a three-parter, so the continued response to 2020 outages and lessons learned, number two, as I said, the Summer 2025 outlook, and number three: mid and long-term outlook. With that, we'll go ahead and welcome our first presenter. Are we starting with President Alice Reynolds from the Public Utilities Commission? Thank you, President Reynolds, for being here.

Thank you, and good afternoon, Madam Chair, Mr. Vice Chair, and members of the committee. For efficiency for the committee, I'm going to introduce the folks who are here on the panel and just give a brief outline of what--each agency's role.

So I'm here today with my colleague, Siva Gunda, Vice Chair of the California Energy Commission, Elliot Mainzer, President and CEO of the California Independent System Operator, and Delphine Hou, Deputy Director for Statewide Energy at the California Department of Water Resources. And then just for a brief orientation of the various agencies, we can go to--I think it's slide--if you could advance two slides? One more.

All right. So for the overview, we have every--all of the agencies listed on the slide are represented here today except for California Air Resources Board. CARB is the agency responsible for setting the requirements for economy-wide greenhouse gas emission reduction and that includes targets for the electricity sector.

CEC, primary responsibility with respect to reliability is load forecasting so that we're ready for variations in load and they also oversee the Renewables Portfolio Standard. The CPUC conducts electricity supply and reliability planning so that we're ready for future conditions and so we can cost-effectively supply California with clean energy, and the CPUC also has a role in RPS oversight.

CAISO is our transmission operator. They also run the wholesale electricity market and conduct transmission planning. DWR has electricity supply backstop responsibilities including the Electricity Strategic Reliability Reserve Program and they manage the Diablo Canyon Extension Fund. These agencies have other roles, but those are the primary roles with respect to reliability. All right, I'll turn to the Vice Chair.

Thank you, President Reynolds. Good afternoon Chair, Vice Chair, and the members of the committee. Thank you for the opportunity to be here. Next slide please. Just wanted to orient. There's a couple of charts on this. Sorry for the small print. There's two charts.

I would like to, you know, take your attention to the top right and what you're seeing there is the grid conditions on August 14th and 15th of 2020. What you see there are two lines, and I want to detail them. So the blue one right there at the top is what we call the gross peak.

So that's the peak, that's the system peak that CAISO manages minute to minute, second by second to balance the grid. And what you see there, secondly, the orange line, the orange bold line, that's what we call the net peak or the net load curve, and that's basically means take the blue and subtract all the renewables, solar and wind on the grid.

So you're taking solar and wind and say, how much more do I have to meet with other resources other than solar and wind? So what you observe there is two days when we had the outages, they were focused on the net peak. That was when the solar just came down, the load did not go down, and the wind hadn't fully arrived yet. So that's the net demand load. That was seen as a problematic thing to deal with as we move forward.

One of the pieces that happened right after the 2020 was Governor sent a letter to the agencies asking what the root causes of the rotating outages were and we collectively identified three pieces.

One: climate change was happening faster than we anticipated and the impacts of that on the grid were being felt much faster than we expected, two: our resource planning, given we have more and more intermittent resources on the grid, haven't caught up with the needs of the grid.

So we looked at how to improve climate change impacts into the grid planning and such. And the third recognized widely as just communication, improved communication between the agencies and how best can we work together. So that kind of brings us to 2022. Again, 2022, September 1st to 10th was an extremely difficult period to balance the grid, and we hit our all-time peak of over 53,000 megawatts on the CAISO grid.

And as you see there, you have a couple of pieces. Again, you have the gross peak, but also the net peak lines, but you also have a red part on the line which basically shows where the Amber Alert was sent out.

That helped with reducing about 2,000 megawatts. We were very close on the grid conditions that day, and if not for the demand response that happened, we would have had much tougher situation to balance the grid. Next slide. So just a summary.

As we look at 2020 and 2022 and different years, we had to catch up a lot on lessons learned and incorporating them into our planning criteria and creating best practices. So what you see there is the top line year by year what we were planning for and what kind of events we were actually experiencing.

So going into 2020, one of the things we primarily understood was we were--based on most of our projections were based on historical information. We didn't really have a way to incorporate climate change impacts and such into our planning regime.

So we understood that and then given the heat wave conditions, we really tried to rectify that moving into 2021. But as you know, some of you might remember 2021; apart from the heat, we also had drought and wildfires. In June of 2021, we had the Bootleg Fire that knocked out a transmission line.

We also had a heat dome over Oregon and the West. All that tested the conditions and we had to incorporate further analysis into it. That really got us into 2022 with the need for not only improved processes, but what we call the Strategic Reserve, and the idea was to have, when we move beyond these planning conditions that are so extraordinary, what are the megawatts we could lean on to support the grid?

So in 2022, we had one additional thing to deal with and that was the tariffs and that really created supply chain issues and how fast we could build. So today as we think about it, thinking about how do we improve our processes--we can go to the next slide.

Just kind of making sure to summarize the three main lessons for us was how do you improve our processes to make them current to ensure all the climate change impacts are well-understood and planned for, we looked at how PUC can look at large amount of procurement, and there was an extraordinary amount of procurement that President Reynolds is going to talk about and also looking at resource adequacy and how do we improve that.

Second bucket of work we did was really--okay, now that we've authorized the procurement, can we build fast enough? And that was around tracking the progress and solving for in real time how to keep moving forward with the build-out.

And the third, even if we planned for and if we built the necessary resources, you know, we still will have these extraordinary events and what do we do with that? And that was the creation of the Strategic Reserve. Those were the three priorities that the agencies have been working on. Next slide.

To just kind of then summarize the progress we made as a team, I want to just direct your attention to the last two rows of this table. You're looking at how many emergency alerts we in CAISO had since 2020 all the way to 2024, and the very last row is how the rest of the West is doing, indicated by the RC West alerts. And as you see there, we had a number of emergency alerts in 2020, 21-22, and since 23 and 24, we had remarkable performance on the grid compared to the rest of the West and thanks to building out historic amount of volume over the last two years.

With that, I'll pass it to President Mainzer. Sorry, President Mainzer. It's still me. I was hoping to pass it to you quickly in interest of time, so yeah. So we'll go to--so the next few slides; I have three more slides to just now move from what we've learned historically, what we tried to improve on our processes, and how is 2025 looking?

So just the top lines on 2025, based on the demand we see for this summer, based on the resources we have gotten the last couple years, and the expected resources over the next several months, we see no supply shortfalls under traditional planning conditions and we also don't see numerically any shortfalls based on 2020 or 2022 conditions.

Having said that, we have an internal motto to not jinx ourselves so we can always say we are cautiously optimistic because there still could be extraordinary events happen with heat and fire together, happening together. So that's something that we are carefully watching.

We do expect about 4,000 megawatts of contingencies in our back pocket if an extraordinary event were to show up. And hopefully we are prepared really well to get through those extraordinary events. Next slide. Then kind of giving you a little bit of how we have been improving over the last several years, again, in this particular table, I'm going to focus on the columns.

So if you look at Summer 2022, you have demand, total resource stack we've had, and then looking into how well-prepared we were. As you see there in 2022, under 2022 conditions, we were 7,000 megawatts short going into that summer and that's what we had to make up in real time because of the extraordinary heat event we had.

But as you move forward into 2025, even if a 2022 event of that 52,000 megawatt heat happens, we feel pretty good with the resources we have. We still have 1,300 megawatts of cushion. Having said that, the reason why you see the red 2,700 megawatts in bold is if we have a west-wide heat event coinciding with the wildfire, we will still be exposed. And so that's the 2,700 megawatts potentially that we have to deal with. Going to next slide.

I'll wrap here quickly, just kind of giving you--these are all the resources that the Legislature has provided the agencies with. A number of these would not happen without the Legislature giving us the tools of the Strategic Reserve, and this is just the list of contingencies we have.

Again, I want to acknowledge my colleague, Director Hou from DWR who manage nearly 3,000 megawatts of those resources through the Strategic Reserve that they manage. And we have a number of other programs, demand side grid support that we lean on, and also PUC has a number of ratepayer programs.

So overall, again, to just summarize from the state's perspective, we go into this well-prepared compared to the last several years. We are still cautiously optimistic given the severity that we are seeing, and, you know, extraordinary conditions could still happen. With that, now I'll pass it to President Mainzer for his remarks.

Thank you, Vice Chair. Madam Chair, Vice Chair, members of the committee, it's nice to see you. I'm going to keep my comments quite brief. I just want to corroborate some of the points that Vice Chair Gunda--obviously from the Independent System Operator's perspective, we also conduct our own reliability analysis going to each summer and we are definitely seeing progress in strengthening resource adequacy in the state.

Our own probabilistic analysis, which looks at the probability of trying to meet a one in ten--one year, one event in ten-year loss of load standard, shows that we are going to have a surplus of capacity going to the summer of about 1,450 megawatts, so that's looking good.

We've also conducted our own stack analysis, a deterministic analysis which also verifies that we do have a surplus going into the summer. Of course, as we've heard, wildfires and the potential for widespread heat and other disruptions do continue to pose risks for the system and we are closely monitoring them.

Just briefly on the weather forecast, turning to the next slide, it does look like we're headed for another hot summer in 2025 and it does look like we've got a reasonable probability of fairly widespread heat across a pretty good portion of the West.

It looks like the heat's likely to come in most intense in the early part of the summer, maybe tapering off a little bit towards the tail end, and possibly, a slightly lower probability of above-normal temperatures in the coastline of California, which gives us a little bit of diversity, but it is likely to be a warm summer, so being prepared is always critical.

And in the next slide, just a couple last things to point out. As you know, one of the key resources that has been added to the grid here in recent years is over 11,000 megawatts of four-hour batteries.

Those batteries which absorb excess energy during the heart of the day, particularly solar, are able to re-inject that power back into the system in the evening as the sun is setting and the demand is still high, and they've just been a major game changer in terms of reliability for our system operators.

And so that's been a tremendous resource addition. We also do a tremendous amount of coordination. We conduct tabletop exercises both here within the state with the state agencies and the utilities, and then just earlier today, we conducted a west-wide planning exercise with all the other utilities across the West just to be as prepared as possible and have that visibility.

And then finally, of course--and we'll touch on this a little bit later--our Western Energy Imbalance Market, which extends across a significant fraction of the Western United States, as well as our Reliability Coordinator function are able to move power around most effectively when it's needed, making a major contribution to summer reliability, particularly during stress grid events. So definitely moving in the right direction and ever ready for the summer. Thank you.

Thank you, President Mainzer. So we're going to move into the third segment of just, into the overall picture on what the process improvements have been and what to look towards the rest of the decade. So looking--go to the next slide, please.

So one of the primary functions of the Energy Commission is to develop the demand forecast, which then becomes a standard product that is used across all agencies. So the CEC's demand forecast is developed in collaboration and coordination with agencies, stakeholders. And what I show here is just the peak demand growth.

There are a number of different forecast products that come out of the CEC, but let me situate you all on this chart. So the first thing to take away from this is, based on where we are over the next 15 years, we expect 21 gigawatts of new load coming on the system. So it's a pretty massive number.

That's what you see in the waterfall chart in the green. So now, building up to the waterfall chart, what is added and what is reduced, as you look towards that--so obviously there's consumption that will just add based on basic economic demographic variables in a population and GDP. And the next step there is climate change.

We have taken a number of steps together as agencies to figure out how best to incorporate climate change impacts into the forecast. So that's what you're seeing about a gig of climate change impacts coming in.

One thing to point out here, the reason why this is important is we're not only seeing a higher temperature growth in the maximum temperature in a day that is going up, but also the minimum temperature that we fall to is not falling as much. So you have that heat buildup, and that's one of the things that we need to take into account as we think about the climate change projections.

The next is data centers. This is a pretty big variability right now. We show that about three and a half gigs of data centers, much of that coming from PG&E territory, but want to flag to the Legislature here, to this committee, that that's a pretty big variable. We see a lot of applications coming in and we do not want to overbake the data centers that cost affordability, but at the same time, we don't want to underbake it.

So there's a whole process that's going on to ensure that we're baking it well. The next one, a big one, electric vehicles, is another eight gigawatts of new load that's expected to add to the peak. Next is fuel substitution or the word that we use for building electrification. You're substituting natural gas with electrification.

That's another six and a half gigs that'll be added over the next 15 years, and then you look at the behind the meter PV that shaves off about 600 megawatts down and energy efficiency and behind the meter storage further reduce that, but the overall with the pluses and minuses, you're looking at a 21 gigawatt increase over the next 15 years.

Next slide please. And one of the things we really want to make sure that the committee sees this is the growth in the summer peak is that 21 gigs that we just talked about, but as you see the blue line there, that's the winter peak, and we're talking about--right now when we talk about peak--we're talking about September, August, and we now begin to see dual peaks. So you could have as much as a peak in winter in February because of the cooling loads done through heat pumps.

So this is what we're watching for and as soon as you think about the winter peaks going up, the resource mix changes, you don't have the same level of solar output, and the resource mix needed would be different. And all this is flowing into the procurement process, and I'll pass it to President Reynolds.

All right, thank you. So picking up from Vice Chair Gunda's description of the demand forecast, I'm going to talk about how this feeds into the CPUC's reliability, supply needs assessments, and overall procurement planning.

So the demand forecast informs both the longer term Integrated Resource Planning proceeding, which is the proceeding that requires load serving entities, all those retail providers, the IOUs, and the CCAs, direct access providers.

They have to meet reliability and greenhouse gas emission goals going into the future, and then the demand forecast also feeds into our shorter term resource adequacy program that requires those resources to be under contract to show up when they're needed to provide energy to the CAISO region.

So over the past six years, the CPUC has issued several procurement orders within the Integrated Resource Planning proceeding--we call it IRP--to increase the total amount of capacity available. The orders have totaled 8.8 gigawatts--and that's what you see on this slide--of new capacity to be contracted by those load serving entities entities through cost-competitive solicitations.

So the procurement orders are shown on this slide, one in 2019. The second followed the 2020 heat wave and the last was in 2023. The responsibility to sign those lease cost contracts for the 18.8 gigawatts is split up among the roughly 40 load-serving entities under CPUC jurisdiction that operate in the CAISO area. So again, including IOUs, CCAs and electric service providers--and those 40 entities represent about 75% of all electric load in California.

We expect that these resources, when they come online through the processes of the load serving entities, to eventually participate in the Resource Adequacy Program, which means that they'll be under a shorter term contract to be required to bid into the CAISO market to to produce electricity when needed.

And then--so these new resources are meant to expand the total amount of electric capacity that's available to the system--that's the capacity that Vice Chair Gunda described--and this--and just to make it clear, the proceeding and our results and procurement orders come from close coordination with all the state agencies and together with the CAISO as well. And then also note that these procurement orders are all for clean energy and battery storage. Fossil fuels are--

Not permitted to comply with the order. All right, next slide. This slide tracks the progress that we've made in getting new resources online in the CalISO area. The vertical line is where we are now.

This is the current moment with new capacity that came online since 2020 to the left of the gray line and then future new capacity. And this is new capacity that's already under contract. So we know what these resources are. They have contracts with one of those 40 LSEs and that's to the right of the line.

This slide is cumulative resources. So it's showing that since 2020, total number of new resources connected to the electric grid surpassed 25 gigawatts. So that's in just five years. And also important to note that this is total generation capacity of each resource. We call it name plate capacity.

And then to match that with the previous slide, the procurement orders were actually the numbers are a little bit lower because they reflect the net qualifying capacity, which is a measure of the dependable output of each resource. So that's what we really have to focus on for reliability.

The other notable part about this chart is what we did last year. Last year in 2024 was 7 gigawatts coming online in one year. And that's a record for California all time for online resources. And then you'll see that the solar shown in yellow battery storage shown in purple represent the majority of the new capacity.

And we do expect this trend to continue as as President Mainzer mentioned, we now have about 11 gigawatts of battery storage in, in online in the CalISO area. And that's up from just under 1 gigawatt five years ago.

Other resources in the graph include hybrid solar and storage systems, small amounts of natural gas upgrades, as well as geothermal, hydropower, biomass and biogas. And then a little bit on delays we have, we are tracking delays that are residual from the COVID 19 pandemic.

And we're also tracking the extent to which new tariffs may affect build out, but that's currently unclear the impact of that. We're doing this tracking work to make sure that the trend that we're seeing now continues into the future so that those projects under contract actually come online.

We're doing that through a collaborative process known as the Tracking Energy Development or TED Task Force. And that's a process that the state agencies use to really work with the developers, work on any kind of delays that we might see and address project specific, specific bottlenecks over time.

I will note that more resources do mean more costs, but again, these Resources are competitively bid to get to the least cost best fit portfolios.

And then additionally as we bring on those low marginal cost resources like solar and batteries, they do help bring down market clearing prices and so they can lead to reduction in market costs overall. And then the last point is that what we're talking about as our portfolio of resources, we don't think about just supply side.

We also include a new build. We also think about energy efficiency, try to maximize energy efficiency and real time demand response programs that can help to shift and shape load and manage contingencies. I have next slide. Briefly wanted to comment on a couple of issue areas. One is central procurement.

Responding to AB 1373, the Commission in last year in August adopted a decision regarding central procurement. We created a process for a central entity to bring online diverse clean energy resources. We looked at those resources that require long lead times and measured that by over five years to come online.

Geothermal, long duration energy storage and offshore wind were the examples that we looked at. So we've set up this process. This is one tool that we have in our toolkit. It hasn't been used yet, but we've set it up for use.

The decision allows the Department of Water Resources to hold competitive solicitations for each of these types of resources up to a total megawatt cap. And you'll see the caps listed on the slide.

The decision also the PUC decision seeks to contain costs by establishing the broad resource categories to encourage competition and then also allowing for a series of solicitations. And we hope to to leverage declining costs over time.

So this is one of the pathways to help us go where we need to go and really does provide us some flexibility and deal with the variabilities that we're facing domestically and globally and uncertainties in our future. All right, next slide. Wanted to briefly talk about resource adequacy. Resource adequacy program is a reliability based procurement program.

So it assigns capacity requirements to those new resources that come online and we match it to total peak demand in the CAISO system. So the load serving entities, each one of them must show that they have enough capacity under contract to meet their load plus a planning Reserve margin.

So buffer on top on both a yearly and a monthly timeframe. The planning Reserve margin that buffer accounts for unexpected events that could increase demand or reduce supply, such as extreme heat or power plant outages. And so we have generators, imports and demand response programs under contract for resource adequacy.

And each one of those has an obligation to participate. So to Come forward and offer into the CAISO market. We made a recent change to the resource adequacy program. Until recently, we assigned resource adequacy requirements based on one instantaneous peak load each month. We've shifted to a framework that we call the slice of day framework.

And what that does is we take the peak day for each month and then the load serving entities have to cover the load for each hour of that peak day to make sure that throughout the day we have enough supply on hand.

It allows for more granularity and really make sure that we're paying particular attention to those evening hours when the solar drops off. So we'll continue to examine this new framework. It's fairly new, it's being implemented now and to make sure that it's working and make changes as needed.

But so far it seems to it's working well and those resources are showing up in the market. The next slide, the last highlight is on electric transmission infrastructure enhancements. I just wanted to briefly mention updates that we recently made to Our General Order 131E.

Also, in response to legislative direction, we adopted changes to the order to make it easier and faster to approve and build electric transmission projects. And these rules apply to any transmission facilities, including sub transmission lines, substations and switching stations. We're looking forward to accelerating permitting with implementation of these new rules.

And for some examples, it allows applicants to submit their own versions of CEQA documents to to expedite environmental review and minimize duplication of work. And then also implements a need presumption that CAISO establishes.

And so if CAISO makes a determination of the need for the project for a particular project that operates as a presumption in our process so we don't redo that need determination. Geo131e with our changes would also require pre filing consultation.

This allows us to meet with the applicants beforehand to make sure they come in with strong applications so that they don't have to be modified over time causing delays. All right, I think I'm passing to thank you.

Well, as you've heard, we are adding a significant amount of new generating capacity to the grid here in California. And one of the things we need to be able to do in order to accommodate that is to make sure we have enough transmission capacity to do that.

And the CAISO is actually responsible for conducting the transmission planning for our footprint. And we do that again in close coordination and a very synchronized fashion with the CEC and the CPUC. And we've also, because transmission is long dated, it takes a Long time to get it in the ground.

We've really stepped back and first of all tried to provide a 20 year outlook looking forward of what are the key pathways, key sources of transmission capacity both inside the state, offshore and into the Intermountain west that we believe are going to be necessary to meet our goals in SB.

And so our 20 year outlook, first installation of that came out in 22, in 2022, we updated that in 2024. And that outlook serves as sort of a blueprint for our annual transmission plans. And Starting back in 2021, we began significantly scaling up the amount of transmission that we took forward for approval.

I think the previous 10 years the average had been about $650 million a year. Beginning in 2021 we ramped that up to $3 billion worth of transmission in investment. In 2022 to 2023, another 7 billion, and then just last year another 6, $6 billion of investment.

These are significant financial investments, but this is the transmission capacity that the state's going to need to make sure that we can actually deliver all of these resources reliably to the customers. One thing I want to mention, Certainly at the ISO, we are a 501c3 public benefit corporation.

So we are very motivated both to, to achieve this transmission capacity on a reliable basis, but also affordably. Our incentive is to try to bring back to our constituents the least cost transmission plant that provides the best sources of new lines, but also tries to really leverage grid enhancing technologies and non wire solutions as well.

And for the chair, we've certainly appreciated your support on that topic, so thank you. Just on the next slide, I'm not going to spend much time, but this just shows you the sort of the way that we structure up the grid.

We've effectively divided the grid into various different zones and those zones allow us to think about the demand for power and the resource base in those different areas, Both on a 20 year basis and on an annual basis.

And that allows us to really sync up with the state's resource planning and procurement and the needs of the load serving entities. And on the next slide you can see that we've been able to leverage the state's integrated resource planning.

The vast majority of resources are being called for in state in California, but the PUC through its IRP has also looked to other states for some additional resource space.

And we have been working very actively with utilities and independent power producers in other parts of the west to open up some significant new transmission, including a line out into New Mexico to open up as much as 3,000 megawatts of wind energy off into Wyoming through the Transwest Express project and also across into the Upper Columbia River Plateau through the Swift North.

So these projects will help increase access to renewable resources and they're also going to really fortify the western grid and allow for even greater transfer of energy between California and the adjacent states, which will really support reliability and resilience.

One other area I wanted just to mention, and this is another area where we really try at the Caiso to try to take friction out of the system, right? As we onboard all these resources, as you can imagine, many, many developers would like to get onto the grid here in California.

And we've had this problem of a very, very congested queue, right? We have people lining up to get on the system, but the number of resources that have lined up have vastly exceeded both the demand for power and here in California, and effectively the planning capacity of the transmission planners at the Caiso and at the utilities.

So last year we sat down with the region and conducted a very intensive stakeholder process. And we took back to the Federal Energy Regulatory Commission last year a set of reforms that would really transform the way that we conducted this interconnection queuing. Those reforms were approved by FERC in September 2024.

Shortly thereafter, we put them into production, and within a few months we'd already cleared out about 67% the requests going into the study process, which really helps separate out the best projects that line up with the needs of the utilities and are consistent with the state's resource planning.

So we're going to continue to fine tune our interconnection queuing processes to make sure that we can get these resources on board and on the system as efficiently as possible.

The last thing I'll mention before we move to close is, as you know, here in California, not only do we manage the electricity market inside the State of California, but over the last 10 years we, we've extended what's known as our real time energy market to utilities across the west through something that's known as the Western energy imbalance market.

This started back in 2014 and it's effectively a very short term market the next 51015 minutes, which allows utilities across a vast portion of the west, connected by transmission lines all the way up into the Pacific Northwest and in the desert Southwest, to effectively exchange energy with each other on a very short term basis.

And that transmission connect here allows us to move power around on a very large scale.

And this market has actually created almost $7 billion of savings for electricity customers just through those production cost benefits on a real time basis, and has also played an increasingly important role in moving power to where it's most needed during those extreme weather events over the last couple of years.

Building on the platform of the western energy imbalance market, we've now developed an extended day ahead market because you can imagine there's an even greater commitment of electric resources and demand in that day ahead time frame.

And having visibility into the broader system on a day ahead basis gives us much greater sense of what the overall reliability of the system is and an ability to move an even greater amount of power across the grid.

So that our tariff proposal for the extended day ahead market was approved by the Federal Energy Regulatory Commission in December of 2023. We're now right in the middle of implementation with plans of going live with our first market participants next spring and next fall.

And this, of course, is another key tool in both the affordability and reliability playbook for California and a topic that is of interest here in the state through the Pathways initiative. So with that, I'll pass it back to President Reynolds and we'll conclude. Thank you very much.

All right, thank you. Just a couple of points to leave you with. What we've presented here really shows close coordination among the agencies and three agencies in Caiso. And when you think about reliability planning, it's both the short term and then the longer term. And it really involves all of the pieces, right?

We think about generation, we think about the system, transmission, distribution, market, operations, permitting, GHG emissions, cost effectiveness, affordability. And so our goal is to maintain reliability while reducing emissions, at least cost.

We did have an historic build out and you can see plans in place and we're moving towards more historic build out and that has enabled us to get through weather events. But I think, you know, one thing that we all think about is that our work is never done.

And we appreciate the opportunity to present to you and really thank you for this opportunity.

Well, and thank you all for joining us and for providing us that update. I think we're all very grateful to hear that the outlook for the short term is, I think you said, cautiously optimistic.

And I think that this presentation did a really excellent job outlining, I think, both the scope and scale of what we have already achieved, as well as what we are trying to achieve over the next 20 years as we collectively build our clean energy future.

So happy now, I think, to open it up for questions or comments from Committee Members, very pleased to be joined by our colleague, Assemblymember Steve Bennett. Who chairs our Budget sub four Committee. Thank you so much for being here. Did you have a question or.

No. Okay.

Okay. All right. All right. Excellent. Well, I do have. I've got a couple of questions I want to Assemblymember Hart. You go ahead.

Well, I just want to start off by saying thank you so much. This is just a powerful presentation. And I love this first sentence in the staff report that talks about the North American electric grid is the world's largest connected machine, linking everyone's lights through a continuous monumental network of wires carrying electricity at the speed of light.

I think that describes the challenge that you have that you're managing really incredibly, thinking about the progress that you made in five years and the way you've described, you know, look it ahead. But a couple of things popped out in your presentation that I wanted to ask a little bit more about.

You know, one is the demand from data centers, which is, I think, very difficult to estimate. And I think Mr. Gunda mentioned that that is something that's a variable that's a little hard to define. How. How big of a variable is that?

Is it the kind of thing that we don't know what companies are going to use, how they're going to use this technology? Are consumers a big part of that equation? How are you getting a handle on that potential increase in demand?

Yeah. Thank you. As a Member. So the. I think I'll just kind of place it into data collection and then incorporation of that data into the planning regime.

So from a data collection perspective, and I just want to extend, thanks to the PUC, we've had opportunity to directly talk to the IOUS in understanding what is called the known loads. So they have applications that are ready to go, and those are some of the most clear indications of the load that we'll see.

And then the second version from there would be what is expected to come online based on, as you mentioned, both the technological needs of the system, but also what the companies might do and whether the companies will build them in California or elsewhere. So basically, where we are right now is when we collect the data first.

We feel like we have good data now, thanks to PUC again and then the IOUS and the Silicon Valley for providing that information to us.

But as you bake it in into the forecasting, the first thing to look at is when you ask for an application of, say, 100 megawatts, is that 100 megawatts going to show up immediately or is it going to be staged so that we have historical information over the last several years?

Especially thanks to Silicon Valley, they were able to provide us how fast that ramp up of the build happens. So we use that as a way to kind of bake in the ramping.

And now the next question comes in, which is do we want to have the grid ready to absorb the load or do we want to have the load meaningfully show up to absorb, to build out?

So in that sense, I think we've heard as high numbers as 8 gigawatts of data center load in this 15 year time period.

Based on the current analysis and based on the leadership and thought leadership from all the agencies, we thought that three and a half is enough to bake in, while the existing system in those load pockets could absorb the rest. As we go forward year by year, we could continue to increase that based on what we see.

And thank you, Madam Chair. Could I just follow up? I just didn't hear one thing that he said. You said you could either have the grid ready to meet the load or. And I missed the ore.

So basically, as I remember, it's like, do we want to make a lot of investment to have the grid platinum coated ready to see if the load shows up? Are we at some level follow the grid enhancements with the load? Right.

So how far do we want to build and how much cushion do we want at a time?

Which is really the question of the day, which is cost and reliability. Those things are intention. We don't want to over build. We want to have exactly what we need with the cushion that you have demonstrated here in the presentation today, that's really effective. But something occurs to me that the standard is enormously high.

One event in 10 years is extremely reliable power. And you have really meant that over the last 20 years, with the exception of, and I guess that would really count within the 10 years, 21 and a half events in 25 years or so. But that is expensive to maintain that standard.

And it occurs to me that, you know, voluntary load reduction should be part of this equation as well. You know, what can we ask consumers to do?

There are obviously differences between a commercial operation that has to continue to make the products that they're doing and then all of us deciding, okay, we don't need to do the dishwasher today. How does that fit into this in terms of being part of the plan and how effective is it?

Yeah, I think we all three of us might have input here. So I'll just start off. I think the point you raise is extremely important, which is how far do we plan for?

So whether we talked about the 1 in 10 standard, but I think as with any crisis coming out of 2020, even though it was a 1 in 10 event, it's not acceptable by the broader public in those periods. But having that conversation is really important.

So the way we've structured ourselves today is to say in order to balance the rates and reliability, the rate payers will get us to the planning standard of 1 in 10.

And beyond that 1 in 10, if we need incremental, which we are seeing more and more severity and frequency, you know, have that as a part of the strategic Reserve. And your question goes to the next point of how far can we lean in on voluntary action?

The answer is, you know, seeing the 2022 September 6th curve, that was an extraordinary drop. But it also meant that we leaned in fully on California. And just even looking at that event, it was a 10 day event and how often can you call for voluntary action?

And some of the analysis that we collectively did indicates that the voluntary action, even with the flex alert just drops precipitously day after day. So I think it's kind of thinking about how long these events are going to be and can we show that purely on a voluntary basis? And I'll pass it.

I'll just add in quickly. I think it's a great question. It's what we think about a lot in terms of how do we, what's the ratepayer share. And there are federal reliability standards that we need to meet. And so we recognize that the load serving entities are responsible for meeting.

You have to serve your customers to a reliability standard. It has to meet, meet the federal standards. And then we're also facing climate change. And in California that has meant more, more people are getting air conditioning, we're having more extreme heat events.

And so even if you're thinking, well we can just meet 1 in 10, that means every 10 years the power we may have load shed, these are really hot days where there are also health concerns.

And so adding those, it can be flex alert, voluntary measures, strategic Reserve that are just ready for emergencies beyond, so that we make sure that we get through the system, through the extreme events in a reliable way and take care of everybody.

I would just add that with respect to your question about the data centers, because they're representing such a significant potential amount of load on the system.

I know there's a lot of dialogue within the data center community about how they can effectively be good grid citizens and essentially bring some flexibility themselves to the table, such that under extreme events they may be able to back off some of their actual load on the system or make their backup generators available to the broader grid.

And I think that that's going to be a conversation we're going to. I've been encouraged by the level of engagement from folks in the hyperscaling community because I think that's going to be a key part of the solution.

Well, thank you. It's very helpful. Appreciate it.

Assemblymember Calderon. Yes, thank you, Madam Chair. And thank you all for being here today. I really enjoy your presentation. So given that we're facing unprecedented load growth, do, and this is, I guess, for anybody, do you foresee the need or is there a consideration for Diablo to be, you know, go beyond 2030.

Let me start and then anyone can add in. So again, good question. And we're constantly monitoring and as we've talked about, there's a lot of uncertainty with data centers, there's still uncertainty with the weather. So that kind of load growth trajectory is something we've got to continue to track.

When the extension of Diablo was done, it was done in a way that directed the PUC to do planning. So the integrated resource planning that I was talking about for the load serving and needs to plan as if that resource wasn't there.

And so the idea is you go ahead and you build what you need to build, assuming the resource is going to go off. Because we don't want to wait till the date that Diablo goes off and then we don't have. Then we were like, zero, well, it's going to take four or five years to build the replacement.

And so we're trying to build the replacement now. So I think it really is a matter of continuing to track that progress and to constantly be looking at where we are.

One more question, quick question, and this is for anybody. Do you believe we should move forward with, you know, the regional Western. Regionalization. Western.

Yeah. And thank you. Thanks for that question.

I think if we are talking about just the expansion of the regional markets, you know, both our agencies, both PUC and Cec, have been a part of working with the Pathways Initiative and we see a lot of benefits in both reliability, you know, in terms of reduction in GHG emissions and over overall cost.

So I think, you know, as a framework, I think expanded markets could absolutely help with the, with overall grid planning in the future.

Assembly Member Patterson.

Great, thank you. You know, a lot of this stuff's way above my pay grades, so I just leave it to the experts to make a lot of the decisions. But just was intrigued by the, you know, in terms of planning and capacity and not wanting to overbuild because, you know, ratepayers pay for that.

And I mean it is the number one source of emails that I get to my office. But that said, you know, just how much goes in, you know, the cost of capital, you know, exceeds the rate of, you know, just time. Right. I mean the cost of capital goes up, time is money.

I mean, you know, just the old adage of that. And so how much are you looking, you know, if you make an investment, you know, you're going to need some kind of capacity making investment now might be cheaper after inflation and even after that suggested 10 years from now or something like that.

So I'm just wondering how that goes into calculations.

Thank you as a Member. So just kind of at a 30,000 foot level. I think from a planning point of view, before we think about the cost of it, we are trying to do two things.

As mentioned in the slides, one of the things we really caught off guard with the renewable resource deployment, which is especially the intermittency of the resources, is were we actually planning to the level that we need to plan for.

So first kind of looking at if we got the demand right and then we can build a resource stack that actually gets you the reliability that is expected on the grid.

So that 1 in 10 grid, the next thing that we are thinking about before it kind of goes to the procurement and this is where we work towards together is what is the lead time of different types of resources. Some resources could come online quicker than the others or there is a pipeline of them.

So those are the parameters we are thinking about from a planning perspective is how much do we need? Are we kind of procuring to the right levels and what lead time do you need in terms of premium and the cost effectiveness? I'll pass the President Reynolds on how we think about it.

Yeah, it's a really interesting question. I'm trying to think about how to get the right information to you. I think you're getting to how, how do we maximize the investment, right? How do we get the most for our money?

And sometimes that might drive us towards, well, you're going to invest now because you'll have it later and it pays off. And so when you think about the procurement that we're doing, most of it is not being done as utility owned procurement.

So investments by utilities, private developers are making financial decisions and then contracting with our retail sellers. And so what we're seeing in rates is that contract price and getting the price at the right place to drive the investment and make sure the developers are there to do the build.

But also minimizing the cost to the ratepayers is a struggle. And so how do we get those the best investments, the best projects built and the cheapest ones for ratepayers, but also financially viable for the private capital that's coming in to make those investments.

Assembly Member Shavo.

Thank you. You know, on the I, I know President Reynolds, you said something that I wonder if you could expand upon a little bit more where you said new resources means more cost, but it also, but soon after that you also said that it could also can bring costs down.

And so could you talk about how it brings more costs and how it can bring costs down?

Sure. And I may pass to President Mainzer because it really has to do with market operations.

And so when you just in General, kind of my oversimplified way of saying it is that if you have the market settles at one price and so you have bids into the market and wherever that the last reason the marginal resource is, that's what sets the price of the market.

So if you have cheap solar coming on and we have enough that can set the price of the entire market versus needing all of those more expensive. So at times of the day we don't need the more expensive resources. They don't get selected in the market. And those aren't the ones that drive up the price.

So it's about keeping market prices low. I don't know if President Mainzer, you want to add in.

I think that was great. I would just add to the previous question from Member Kelleran the ability to exchange electricity across a wide footprint and to take advantage of that resource diversity.

So we may be in a situation where we're operating at a very high level of demand and having to operate our more expensive resources, but if we're able to import from another part of the region that has surplus, that just helps dampen prices here and supports affordability and reliability. Yeah, thanks.

And do President Reynolds, I mean obviously affordability is a huge, huge focus of the chair of the Committee of the Public of yours and there seems to be. I always get caught in a discussion around affordability when it comes to our energy resources is that the system is dependent on.

The system is set up in a way in which the IOUS make more money by building more infrastructure. Right. And so there's an incentive by them to continue to build and grow and grow and build.

And how, how do you, can you talk a little bit about the work that you all do to make sure that you're finding this balance of what is needed? Because obviously we do need some of that. Right.

But making sure that it is what's needed, that it's not excessive, that it's not over overly expensive, because that comes back to ratepayers in the end.

Yeah, exactly. And that's really the core of what we do in our proceedings. And it's difficult, but that's really what we focus on. Exactly what you're talking about.

Getting to the place where the utilities are making those investments that are the cheapest way, minimal cost to get to reliability, to get to safety and to follow legal requirements like the renewable portfolio standard, the GHG reductions that are, that we need to meet or any other legal requirements.

And so I mean I'm sure you're aware we do that through a litigated process where parties bring in evidence and we cross examine that evidence. We have rape hair advocates who come in and say no, wait, that forecast of what they say they need to spend is too high.

And so we weigh that and evaluate and really look at what is the least cost way of doing the necessary work that they need to do. Some of it is trying to come up with a risk reduction factor.

So when you think about safety investments, how much safety, what safety investments are gold plating, what safety investments are needed for the system. And so we try to get to that right size of what they need.

I'm just going to add to that briefly in the realm of transmission, just to reiterate, you know, when we're looking at the transmission system, first and foremost we want to try to make sure that we're utilizing those assets to the maximum extent possible before rebuilding.

So the use of grid enhancing technologies, the use of non wire solutions, the usage of voltage control devices, all of those things are designed to take the existing system as far as we possibly can.

And then when we have to build new lines, we're really trying to look at a wide range of scenarios to make sure identifying the most cost effective extensions as possible. So that's really an essential part of the CAISO's transmission planning ethic and the work that we do in cooperation with the state.

Thank you, Assembly Member Bennett.

Thank you very much. I have four questions. I'm going to try to move as quick as I can on them. Last week we had two. Last week we had two economists that specialized in cap and trade California, what we're doing, effects on electricity rates, et cetera.

One of them stated that it was his belief that rate electric rates in California are too high, certainly relative to where they should be to create the proper incentives for us to convert over to electrifying most of our systems. My question is, do you agree with that?

And I'm going to ask the second half of my question so you can do both. His response when we said what could we do about it? His response was the safety requirements that the utilities are having to engage in to stop wildfires.

The wildfire prevention activities are so expensive that they are the number one thing that we should try to knock down in terms of that. Could you opine on those two things?

Sure, I'll start. And I. We are seeing large increases because of wildfire safety mitigation actions. And that does flow into rates and especially those vegetation management. The operation and maintenance costs are collected in real time. So they're not even spread out over time. They're collected right away.

And we've seen them impacting rates significantly in the last few years. I agree with the idea of looking for ways to reduce those costs. So are there ways that we can have that work done again, to the safety.

Getting to your safety metric that we need to get to because the system needs to be safe, but reduce some of those costs.

And so we have been working closely with the Office of Energy Infrastructure Safety, the new office that was created for welfare Safety, in trying to align our processes more closely so that we can have a cost effectiveness review done of some of those activities in a way that feeds into our General rate case.

Thank you very much. It's something to explore more interestingly. I would just offer for the Members here that his response was hardening of homes was the best way to decrease the liability because that's where the liability cost of the utilities is so high. My second question is data centers.

The question was raised by my colleague, but I've had data centers contacting me and saying, can we build our own power and can we do our own connections? And the other half of that question is how important is it for us to be accommodating of data centers if we want California to keep its technological leadership globally?

Okay, I'll start. So.

And I'm not sure exactly what the proposal is from the data centers, but I'll just say, you know, it's kind of somehow we think about it, one aspect of this is data centers, when they come to California, do business in California, join the system, share in the costs, they can have downward pressure on rates.

And so if we can find areas where data centers can locate, especially areas where grid capacity is already there, so if they go to the right place, we don't have to do upgrades, they start sharing system costs. Bringing on large amount megawatts, large amounts of load can help put downward pressure.

So everybody else, so we get to the point of lowering rates for all of the things that we want to do. And so that's kind of the General framework. And really it's about doing this as cheaply as possible. We're also exploring ways to. And Vice Chair Gundit touched on this look at flexible service connections.

Do you need the load right away? And so there are ways, I think that from when we see applications come in, we're looking for ways to reduce costs.

So are we concerned that if they build their own, then they don't participate in helping us lower cost?

Well, in some ways I'm not sure what their proposal is because I haven't heard of a data center not wanting to connect at all. So it depends on what the proposal is. But we would be looking at it as like, is this the cheapest way possible and does it help other ratepayers and not burden other ratepayers?

We don't want them to come in in a way that burdens our existing California residents. Commissioner Gunda.

Yeah, thank you. I think just on the question around keeping the tech sector in California, I think it's really important. So from a, from a perspective of data center, they're kind of like two, you know, broad needs for them, which is those, those functions that have very low latency mean very close.

They have to be very close to the actual tech workers. And there are things like in a long term training data sets that you could theoretically have it much further down somewhere else that can train those. So we are looking at both of them.

So we're looking at what kind of load we need to accommodate that has that latency issue and what could be elsewhere.

Thank you. Cost of electricity, trying to get it to be appropriate in the long run. My question is this. I mean, as I look at California, water is going to get more expensive in California. It seems like electricity is going to get more expensive in California because we need more of it.

And we have to make significant capital investments as we make this transition over. In the short run, we're trying to keep electricity rates down. And then I have this Curve that came in from this economist who says a electricity rates are too high for a conversion standpoint.

My question is, in the long run, is it your analysis that electricity will cost more but overall energy costs for all of us should go down as we're not paying for gasoline for cars, etc.

But will electricity keep generally be going up or are we going to find some time where we're economies of scale are going to be such that we're actually going to be able to lower the cost? Could you help us with that?

Yeah, sure. And there's so many variables in that. And so I, you know, but you're. Going to give us a guaranteed. I'm going to get right. I'll tell you what will happen 20 years from now, what the rate will be. But that's certainly the goal.

And there's a path there, right as we start using more electricity and their system gets hardened enough to withstand climate events and then we have more megawatts being used. Your car is electric, your home is electric. So everybody is sharing the cost of the infrastructure. The rates would, would go down or at least stabilize if, if that.

With that vision in mind, that is possible. Yeah. The uncertainty is what, what's going to add to rates and.

Yeah, thank you. And my fourth question, trying to be efficient here and that is, would the ideal for California be residents all having solar with a backup battery?

Would that be the ideal for us so that, you know, we, we have at least that short term reliability of there's the backup battery, as long as that lasts to get you through those temporary events and also decrease the amount of capital investment we'd have to make?

I think it depends on the cost. And you know, you heard electricity travels at the speed of light. Solar, Solar. You want to put it in the best place, cheapest place.

Thank you very much.

Thank you. And if I may, I would say I think the vision, I think the vision that we're all working towards is I think twofold, number one, that energy costs as a share of wallet do go down when you look at your entire expenditure.

But number two, and I think this is the promise that we have to make to Californians is that we are looking to bend the curve on electricity rates.

And I think that we need to do a better job of painting that vision for Californians as well as delivering on interim milestones so that they believe that that is going to be true.

And I think that's incredibly important if we're going to keep the public on side as we work to achieve our climate goals and build California's clean energy future. Assemblymember Haribanian thank you, Madam Chair.

Just quickly as a follow up, Assembly Member Calderon and Assembly Member Bennett had some good questions that I think touch upon.

11 item that we really haven't delved into, but I think when it comes to data Centers, Diablo Canyon SMRs and the future of potentially bringing that technology back, especially when it comes to data centers and I think to the chair's point about not knowing what the plan is, I think if you talk to a lot of tech companies that are trying to build out data centers, I think their plan is let's try to bring this technology back.

So I think that it's a fascinating conversation with a lot of intricacies and I think it is a potentially elegant solution. Where are you guys all collectively and individually on potentially doing that? And Mr. Gunda, we've talked about this briefly so I'll put you on the spot. First.

I was hoping to pass. No, thank you. No, I think, I think I want to two things. We have a moratorium on nuclear. But if I'm just putting my mechanical engineering hat and system planning hat, any firm clean Electron is really helpful for the grid.

So I think whether we talk about any sort of resource, if I can firmly shape it and control it, that would be really helpful.

Having said that, I think as we go through a lot of this planning process, it's about what Californians are open to and based on the openness and your leadership will faithfully discharge whatever that option is.

All right. Assembly Member Schiavo.

I just had one further question. And I appreciate the work that's being done because I know for folks in our community and throughout the state affordability really is critical. Back to President Mainzer. I wanted to just follow up on one of the things that you mentioned also around clearing the queue. This was one of the biggest issues really that I heard in my office for the first couple of years that I was here. Now going on year three, I haven't been hearing about it as much or really not really at all that I can think of as a huge issue.

And so I hope that that is a reflection of success here, and clearing it 60 something percent seems like a huge success. Can you talk about what that clearing means? Is that clearing out things that were superfluous and not needed, or was it actually moving things forward and getting them, you know, online and approved?

Yeah, the fundamental problem historically with the queuing is that you'll have hundreds of thousands of megawatts of resources lining up for the opportunity to get on the grid when the actual demand for power is typically a small fraction of that. Right.

And so all the study engineers are faced with this huge number of requests to get studied and it clogs up the whole processing of, and just takes... You're ending up producing studies that aren't really meaningful because they bear no relationship to the actual demand for electricity.

So what we've done with the Energy Commission and the PUC and the other local regulatory authorities is we've really said, look, what is the demand for power in these different parts of the grid in the next 5, 10, 15 years. And we've looked at the individual projects that come in to the queue. And the projects that actually line up with the resource planning needs of the state, the ones that are located in areas where we either have existing capacity or we're planning to build transmission lines.

And the projects that have experienced some level of interest from our load serving entities, they get scored. And the ones that score the highest go forward into the study process and the other ones are basically given the opportunity to leave the queue and come back at a future date.

And so by right sizing the queue and focusing on those projects that are really aligned with the state's, this actual demand for power and the state's resource proclivities and where we're building transmission in the future, it's just allowed us to clear that out and take the friction out of the system. Now we're going to continue to fine tune this process.

You know, we're going to learn every study will learn a little bit more. But that's our responsibility as the ISO, is to try to take that friction out of the system. And we're going to continue looking for other ways to speed up the residual study process. We're to going artificial intelligence, new forms of data analysis. But I'm glad to hear you're not hearing that much about it because, certainly, and I thank all the stakeholders that participated because we really did reach out to the region for the solutions.

That's great. Well, congratulations. Thank you.

All right. Well, thank you, Members. I do have a couple of questions, and I want to start with a couple of questions related to some of our existing resources. I'd say two charts really jumped out at me in your presentation. The first is this, you know, the forecast that shows the precipitous growth, particularly in winter demand, winter peak demand. And then the second is our expected resource growth of new clean energy resources, which, again, that's a very, very steep slope. So with that in mind.

And I think, Mr. Gunda, you just said that any firm clean electron is helpful. I want to follow up on the question from Assembly Member Calderon related to Diablo Canyon. President Reynolds, I think you, you said the plan has always been that we are, we're planning around that as a resource.

I guess my question is when do we need to make that call? It's 2025. Those resources are supposed to come offline 2029 or 2030. At what point do we need to have kind of a come to Jesus and ask ourselves if it's time to reauthorize that and extend it beyond 2020, 2030? She's looking to you.

Yeah, I don't know. I mean, I guess I would say the sooner the better in terms of planning and making decisions about investments. That said, what's, you know, maybe the question is, is something going to, but when is something going to break? I think, you know, the longer the wait, the more uncertainty we have, probably the more costs would go up because we're making decisions that we might not be happy with if we decide to leave it on or decide to take it off. So I'd say the sooner the better. I can't tell you when, you know, when that breaking point is, where we get to a point where the system isn't reliable. Do you have an opinion on that?

I'm going to just minutes of kind of the question. And I think I want to just maybe reflect on the conversation we had in 2022. And when we're talking about the need for Diablo extension, as we showed in the chart, there was under extreme events, there was that 7,000 megawatt hole.

And the immediate question was, as you are moving into 2025 timeframe, here you go. We are letting go 6,000 megawatts, right. And economic, economically retiring, the OTC power plants, about 3,000 megawatts and 2,000 of Diablo, so roughly 5,000. And is it prudent for us to hold on to that given how much hole we are in?

So from that premise, you know, if we are looking at the long run forecasting and the long run planning, it seems to appear that, you know, we are on track to continue to procure and continue to add resources at pace. And we'll be doing this analysis every year.

And I think maybe the broader question, and I would, this is probably about my break rate on this one, is to just think about what kind of resources are acceptable on the grid planning in California. And I think that gives us the options to think about what resources we do our policy planning around.

Maybe I'll just add another thing to think about. It goes to President Mainzer's point. And then also I'll add that we have interest by more resource developers and resources than we need. And so you get to a point where choices are made. This is very doable. The chart with these contracts.

We know there's also interest in doing more solar development. What's going to happen with offshore wind, you know, so there are options so that we can get to a place where we don't need Diablo Canyon. But over time, we'll get more certainty on the viability of all those projects.

Okay, I do think it has to happen. We certainly cannot have a repeat of what happened in 2022, when it's like, oh shoot, we can't keep the lights on if we don't reauthorize this and take a vote on it next week. But beyond that, I think we had this hearing last year where one of the witnesses actually said that the cost of long term resource procurement is higher than it should be because of this sort of weird uncertainty around Diablo.

So I do think we need to probably like in the next, you know, by the end of this year really be ironclad in our belief that we don't need that as a resource and can start moving to wind that down rather than this kind of maybe we do, maybe we don't. I'm not sure that that's a good signal for the market.

So I think, Chair, I just want to absolutely agree with you on the market certainty and what we want to do. And I think just kind of making sure we add to the point that there are a number of resources that we currently consider for our long term planning like SB 100 and IRP.

We try not to have resources in that that are speculative. And there are some that are speculative, but try to kind of reduce that. I think from a planning perspective, it's all about which resources we think are viable for California. And I would say going back to the previous answer, anytime you have firm dispatchable resources, it's really helpful on the grid, but it's really about what kind of resources are viable in California.

And the cost. Right. Yeah. And to be really clear, I think all of us would be absolutely thrilled to hear, yep, we are 100% on track to deliver and have these procurement targets realized for 2029 and 2030, so we don't need to have that conversation. As long as we are on the topic of controversial energy resources. I want to ask about the Strategic Reliability Reserve. So that is like 3,000 megawatts of kind of our contingency resource for this summer. That is coming offline in summer of 2026. Is it the right time for us to be taking those resources offline?

Thank you, Chair. Answer the first part. So of the 3,000 megawatts or so of the reserve, I think the ones that you're referring to that are going to expire at the end of 2026 are the larger ones through cooling resources. So that's a little over 2,800 megawatts. So the vast majority of the reserve, the contract extension time is time for the OTC extension that was granted by the State Water Resources Control Board, which is in turn based on the reliability assessment that the CEC, PUC, and the CAISO has done.

So that's the contracting period that DWR tried to match for those resources. And again, they were going to retire much older resources, but obviously brought into the reserve as the backstop and then balanced with having them default off so that we're not... So there isn't as much emission output as it would be in the market.

Just on that one, just making sure I think the construct of the, of kind of the 2022 strategic reserve was what do we have that are immediate? And we looked at OTCs as something that we could immediately fill behind. But again, on the broader question, while we improve our planning, what do we do about these extreme events and what kind of resources could we build in I think is a continuing discussion we should have. And I the idea was, as the OTCs come down, we have enough strategic reserve that's demand response and that's clean and we are fastly building that part.

And actually that is a good segue to a question I did have. President Reynolds, in your comments you talked about the role of energy efficiency and demand response. Can you tell us a little bit about what's happening right now on that front and what we can expect and how we can, I guess, grow the role of those programs over time?

Yeah, we have a number of programs, and to highlight a few, some important programs from a reliability perspective are the ones that we use for emergencies. So we have several that actually count for resource adequacy. They are proven and certain enough that we can give resource adequacy value.

There are things like our Base Interruptible Program, which is a discounted rate that industrial customers have for agreeing to reduce load, subject to penalties, when needed, when called upon for emergencies. We're also developing demand response that's tied to rate signals. aAd so making sure we're taking advantage of dynamic rates that can have enough of a signal to get that demand response when we, the times we need it to match the grid needs. And then we have... So we have a lot of programs that deal with the demand side too that get baked into the demand forecast rather than counting in our stack of resources.

Thank you. All right, I do have a couple more questions. Sorry. I think we're still doing pretty good on time. So I want to come back, again, I think Assembly Member Calderon had asked a question about the role of regional markets. And President Mainzer, you did a good job in your deck talking about the role of those.

But I know when we were talking earlier I asked you to help me understand how does that create $7 billion of value, which is effectively $7 billion in savings. I think you said that something like two and a half billion of that would have flown through to California.

I think particularly given that the conversation around regionalization and regional markets is going to be coming to the Assembly very soon, I think would be really helpful for all of us to better understand the role that regional markets play both in long term sustainability and long term reliability, as well as long term affordability.

Thank you. At its most, at its most rudimentary level, just starting here in California, when we established the energy market, you know, back 25 years ago, the purpose was to provide information to the Independent System Operator about the cost of all the different resources in the system.

So that as we operated the grid, we could identify every 5, 10, 15 minutes the lowest cost power plant that could be available to serve that next increment of load. And that's the basic principle of the market and that we've operated that here in California for a number of years.

And then back in 2014, as other regions of the west started experiencing more volatility on their system, more renewable energy growth, California said, hey, we built our energy market here in California. It allows us to dispatch the system on the least cost basis and to find the lowest cost power plant at any particular time to meet demand.

We can extend that outside to those of you outside of California. And over the course of the last 10 years, about 80% of the utilities in the west have joined that western energy imbalance market. And we're very fortunate in the west to have big transmission lines in extending from California all the way up into the Pacific Northwest and out into the desert Southwest and out into the intermountain West. And that's allowed a lot of different resources to participate in that energy market.

So it's, as you have with just about any market, more liquidity tends to mean more opportunities for savings. And so as the market has become bigger and deeper and more liquid, the savings have continued to escalate to the point that we've now been able to to save roughly $7 billion in production cost savings over the last 10 years.

What we've also seen though, and I think this is typically undervalued in the conversation, is that connectivity that we have across the west and that ability to access diverse resources. You know, when it's really, really hot on a day in California, 124 in Burbank, it might be a lot cooler up in the Northwest or out in Idaho.

And our ability to import electricity under those conditions allows us to stay away from really, really distressed conditions. It allows us not to have to declare flex alerts, we don't have to declare energy emergencies. We don't have to go into stage two or stage three.

We don't have to take on the disruptions of the economy and that very destabilizing stress in the system. And as you know, when things get tight, the price of power goes through the roof, right? So it provides both economic savings, but probably more importantly, it's become really important tool in reliability.

And I think the reason we're now looking at the day ahead market is within the, within the WEIM, we're optimizing on a very short term time basis, 5, 10, 15 minutes. By now moving into the day ahead market all of the utilities that will be participating provide us with energy 24 hours in advance.

Information 24 hours in advance. So we can see with some confidence that there is the ability to move power across the transmission system to meet everybody's demand. And that means, once again, we can calm the system down and reduce the likelihood of reliability events, which reduces disruption, builds confidence in investment, and ultimately I think provides much more stability for our grid operations.

Thank you. And that's very helpful. Appreciate that. So my last questions are related to resource adequacy. So you implemented some new reforms and are now utilizing the slice of day resource adequacy model. How are you evaluating the success or the efficacy of this new approach?

Well, the reforms that we made also go hand in hand with some increases in the PRM. And so as we were increasing that buffer, realizing that we need to get a little higher given what we're seeing with the load forecast, we were also implementing slice of day.

So we're monitoring both at the same time and increasing the PRM had impact on the availability of RA and cost. And at the same time, we're escalating the new projects that come online. So like all those things are related. You need the projects to be built to provide the RA, and, as we're increasing the PRM, you need more, and then you have to do every hour. And so we're not, I don't, I think that our tracking and our monitoring have to do with all of those different things.

So we ask for year ahead showings, and we ask for then month ahead showings as well, that, so that we know how we're doing as coming into the summer. What we're seeing is that the load serving entities are doing very well on a total basis. There are some LSEs that are doing better than others, and we're monitoring that and we do have enforcement ability for resource adequacy. But I mean, overall, so far I'd say it's going very well. And there's compliance, there's a high level of compliance.

Okay, because. And then you've, you said, I think it was fairly recently started to utilize an effective margin, a planning reserve margin on top of the regular planning reserve margin. Is that something you expect to continue beyond 2025 or do we just need to set a new planning reserve margin?

So we are now considering that. And yeah, so it was done after the reliability events of how can we have, how can we get through this time where we still need the build, prices are high, what's the most efficient way to do it to preserve that reliability that we need to see?

Because it does seem, it seems very complex, as I was looking at it, trying to understand the way that we are now looking at resource adequacy. So I do wonder if that complexity is serving us or if there's a more simplified way to get to the same result, which is ultimately ensuring that we are prepared for extreme events.

Yeah. I mean, I think one way to think about it is if as we move to the future and we get more stability and we have our transition to electrification done and that there may be ways to simplify, but now we're using all of the tools that we have and using work. They work together in different ways. But sure, I mean, I am always a fan of simplification. I do try to do that. So I think it's a really good question that we need to continue to ask ourselves.

All right. Well, with that, I'll just close by saying thank you to all of you for being here. Thank you for the tremendous work that you're all doing. I think you began by saying that the presentation, the conversation was illustrative of just the close collaboration across agencies. And I think that that's really clear. And we really do appreciate your partnership and look forward to continue to work with you as we make progress on sustainability, reliability, and affordability in this sector.

Thank you, Chair. Thank you so much for the opportunity.

All right, so we will now transition to our second panel. We'll go ahead and introduce our panelists as we do a swap. We are going to be joined by Gillian, Gillian Clegg from Pacific Gas and Electric, Ryan Tracey from Sonoma Clean Power, Rebecca Lee from NRG Energy, Glenn Barry from the Los Angeles Department of Water and Power, and Tony Zimmer from the Northern California Power Agency.

And this, the focus of this panel is power provider perspectives regarding headwinds to electric reliability. What I'd love to do is ask each of our panelists to keep their opening remarks to five minutes at a maximum so that we can ensure that we can have robust conversation and discussion with Committee Members. Thank you. With that, are we starting with Gillian, or Ms. Clegg? Thank you.

Good afternoon, Madam Chair and Committee Members. My name is Gillian Clegg, and I'm the Vice President of Energy Policy and Procurement at Pacific Gas and Electric Company. In my role, I'm responsible for PG&E's planning, procurement, portfolio management, settlement of all natural gas and electric supply contracts.

Thank you for inviting me here today to talk about this important and timely topic. I did have a couple of comments to share on the upcoming summer. We have a large portfolio of supply resources that is ready and prepared to produce this summer, starting with our jewel in the crown, our 3,900 megawatts of hydroelectric facilities.

We had a good precipitation year, and it's ready to generate all the way through September, most dicey month, as we know. You heard on the prior panel, battery storage is a big critical, become a critical portfolio. We have almost 2,400 megawatts of operational battery storage that's already operating today in the California ISO market.

How about Diablo Canyon Unit 1? This is the first summer in its extended operations which started November 2024 last year, and Unit 2 will go into extended operations in August 2025, just in time for September. And so actions taken by the Legislature under SB 846 to extend Diablo Canyon will be contributing to system reliability this summer.

When I look out to the mid and long term or say the 2 to 10 year time frame, I see both opportunities and challenges. We heard a little bit in the last panel about load growth that's coming, both electrification as well as data centers. A lot of questions on data centers.

Happy to chat about that a little bit. We are projecting 3 million electric vehicles on the road in our service territory alone by 2030, and we have applications for 8.7 gigawatts of demand centers that have come in through the door so far. This load growth offers an opportunity to reduce rates for all customers if we can bring it on in a way that spreads out fixed costs over a larger load base, brings in more revenue, and then thus putting downward pressure on rates for all customers.

You heard the California ISO footprint has added over 20 gigawatts of resources since 2020. That's quite remarkable. And 7 gigawatts in the last year. You're going to need to see this pace continue to serve the growing load. Some of our projections internally show that we'll need probably an 80 gigawatt build out of resources by 2035. So a lot of growth to come. As I mentioned though, some challenges with interconnecting new load. First challenge is cost, short term commodity costs, both resource adequacy and RPS energy.

We've seen those be at historic highs recently in the last year due to shortages of both relative to their individual increasing requirements, the PRM, but also the increasing renewable portfolio standard percentages. The second challenge is it may be difficult to obtain the optimal type of new build resource in the late 2000s like base load resources.

For example, maybe you want a baseload resource for a baseload data center. Something like geothermal has a long lead time for development. And the alternative is to keep building solar and storage, which we will do and we need to do. But we estimate for every 1 megawatt of flat load, you need to build 5 to 7 megawatts of battery plus storage combination. 5 to 7x. That's you know, in contrast to a base load resource where that would be roughly one to one.

The third challenge is project delays in this mid to long term due to uncertainty in import tariffs, tax credits, supply chain, permitting. You know, several counterparties that we are currently negotiating with have indicated that they're either unable to offer fixed prices right now because of the the uncertainty in tariffs and tax credits.

And that's typically how we like to procure is under fixed prices. Or they need a reopener clause in their contracts due to the tremendous uncertainty that seems like it's day to day right now. Even counterparties that have existing agreements have begun to indicate they may not be able to perform under their contractual timelines or pricing.

On permitting, counterparties who require BLM action have indicated there's diminished workforce at the BLM. Things are taking longer there. Good news though is next. We heard about regionalization, west wide market. We are a supporter of a larger market footprint.

We think that SB 540 is the next step and the necessary step to move us along that journey to a west wide market. We also would like to see policymakers with support and all of the above kind of approach. So load management for EVs. Right now we still see that. We project that still 500 megawatts of EVs will be charging over the peak in 2030.

Let's not have them charge over the peak when we already have a peak problem in California. We can do something about that with load management. We would encourage the Commission to include carbon capture as a candidate resource in the IRP.

Lastly, permitting at any stage, local or state, would be helpful. Any reforms there to speed up review to get projects on sooner. And to conclude, you know, it's a challenging and exciting time. It basically has been in the 25 years I've been working on this. So lucky us. And we appreciate the Committee's attention to this matter of summer and mid and long term reliability with that.

I conclude my remarks. Thank you, Ms. Clegg. Oh, perfectly timed that was. All right, Mr. Tracey.

Good afternoon, Madam Chair and Assembly Members. I'm here as the Director of Planning Analytics for Sonoma Clean Power. My name is Ryan Tracey. Sonoma Clean Power is the CCA serving Sonoma and Mendocino Counties.

I'm here to share our perspective as a power provider seeking to provide a portfolio of resources that can enable the retirement of natural gas and providing comments on reliability as such. SCP is the canary in the coal mine for an issue that the state will have to contend with.

And looking at that chart that Vice Chair Gunda just shared, SCP is actually expecting our winter peak to meet our summer peak by the end of the decade. We're already seeing when we're looking at our resource adequacy requirements, we're seeing them higher in January and December than they are in the summer.

That's very difficult to do with a clean resource mix, given the lack of solar and the ability to charge battery storage and move it around during the winter months. Winter reliability is also not just tomorrow's problem.

In December 2022, we had an issue where we had fuel constraints that led to extreme vulnerability, led to power prices in California that increased five fold over the previous year. Prices on the wholesale market average $250 per megawatt hour. That event has changed the structure of the forward price curve for California.

And in January 2024, the Pacific Northwest actually declared 12 energy emergencies in January. The winter reliability issue is also beginning to bear out in state planning. So we look at that chart that Vice Chair Gunda shared. 2040 seems a long way out, but it's actually tomorrow when you think about the pace for transmission planning and portfolio planning.

The PUC actually started looking at the reliability implications of the winter load peak in just the portfolio that they put together earlier this year before they made any adjustments. By looking at just the portfolio output that came out of the resolve model, they are seeing 1.56 days per year of loss of load events.

So if you recall, that's 15 times greater than the 1 in 10 load standard. That realization required them to post hoc add 41/2 gigawatts of resources into Northern California before they ship that to the CAISO. But it exposed an issue that we really have. A winter reliability issue we're going to have to worry about.

Because the resource mix you're going to need to be able to provide reliability, winter is going to be a lot different.

An important thing to keep in mind too is that all that planning is based on a single deterministic portfolio that was put together with a set of assumptions that we assume is correct and there's a lot of uncertainties. It assumes that we'd be able to rely on four and a half gigawatts of offshore wind.

It assumes that we're able to rely on 10.7 gigawatts of out of state wind, much of which is impacted by the federal moratoriums that are happening right now. And still we're seeing those loss of load issues and to the consternation of a climate forward CCA.

It also assumes that we make no progress at all on retiring our natural gas fleet. Delaying action on clean energy solutions for winter is not just a reliability issue, but also an affordability one. Without clean firm resources, we're headed towards a future with two grids, a renewable one and a natural gas backup.

Now, natural gas OPEX and CAPEX are going to continue to go up as facilities age and they're going to run less often. It's going to push up total costs and concentrate the cost that we're going to need to recover through resource adequacy, given that they're not able to recover revenues in the market.

The cost impacts are under predicted by system modeling that continues to say we need to retain our current fleet, which looks at overall system costs and not necessarily the price set by the marginal unit and paid by ratepayers.

If we're retaining natural gas in the state's electricity portfolio, we're we are also by definition not building the infrastructure needed for clean firm alternatives. So what can we do today? I have a couple things that I want to ask Assembly Members to consider.

So firstly I'd like to see us progress initiatives to promote the supply of clean firm resources that provide winter reliability, much as we do through the geothermal legislative package that's being championed by Assemblymembers Papan and Rogers this year.

The midterm reliability order and CPE have been transformational in driving investment into geothermal energy as one of the clean firm options. It's in a huge demand signal, but to manage cost and attract local investment, we need to look at supplied side incentives and not just look at doing things on the demand side.

The geothermal legislation this year does this by addressing key regulatory bottlenecks that the industry has asked for to be able to make investment in geothermal more viable. We also need to look at more early deployment funding.

We need to look at clean firm designations in the GGRF, look at future bonding that can benefit clean firm and look at the opportunities for the IBank to provide funding. One of the key things we've been looking at too is we need to revisit the current system's focus on summer deliverability.

Right now any resource that wants to connect to the grid has to get deliverability if they want to get resource adequacy. That deliverability designation is based on summer peak conditions. In essence, that means we're trying to build a geothermal project to be able to provide benefits that could help the help the grid in the late 2030s.

We need to make sure that it can deliver electrons to LA. That's a huge barrier for deployment today because deliverability is used as the intake for interconnection now it's used to trigger transmission upgrades. It's used to determine what's eligible for RA and procurement orders.

A first step could be allowing for procurement orders resources that don't necessarily have deliverability to count. We could also look long term at creating deliverability measurements outside the winter and also look at a non summer deliverability system.

Last thing I want to recommend is that given the level of uncertainty, we need to start planning a transmission system for a system that's robust across a wide range of futures. Let's not accept a transmission plan that only works if we retain every single natural gas unit.

Let's approve transmission projects that add flexibility for the state and to succeed in decarbonization and futures that differ from just a single base case. And also let's equip our state resource agencies with the best in class tools. This is a very complex problem and getting it right has huge return on investment for cash California ratepayers.

In conclusion, winter reliability will be one of the key challenges to reach SB 100 targets affordably. Let's give it the attention it deserves today. Thank you.

Thank you. Moving to Ms. Lee, welcome.

Thank you. Chair Members of the Committee, thank you for the opportunity here to speak. Rebecca Lee on behalf of NRG Energy.

And first, thank you for the oversight and I would like to, and we would like to, affirm what you had just heard from the last panel. That we have indeed seen the price curve bending somewhat, especially on resource adequacy. That as more resources coming online we're seeing the price recede and that is a good thing and as cautiously optimistic as well, ensuring their optimism. And specifically we want to thank take this opportunity too to thank CAISO, CPUC, CEC staff and our regulatory team, our commercial team work with these staff very closely and the the reform that you heard earlier today took tremendous amount of very, very committed staff work.

So we want to give them credit for where credit is due. Who are we? We are direct access providers and we are competitive retail providers in serving the commercial and industrial customers in California. And in this role we compete against the utility, we compete against the CCA and we compete against each other.

So affordability is really our bread and butter. And so in that lens we think this, our role has an important role to play in this ongoing conversation regarding addressing affordability while keeping the grid reliable. And in fact we cannot recruit new customers if we have a resource adequacy violation.

So we have no room for error in terms of achieving our compliance. And so today you've already heard from many experts and we will keep this short by providing some recommendation, just three top line recommendations that we think are modest and concrete, but would have very positive impact on the ongoing discourse.

First, aligning the planning processes across the agencies. And this is where we have seen the agencies have done tremendous collaboration work and they are improving.

And in the spirit of continuous improvement, what we can do is look at some of these finer metrics are used for reliability assessment of the different resource type in both RA, resource adequacy under slice of day, as well in the ARP process to make sure that the longer term portfolio that we are building collectively can meet that short term reliability need in a future year.

And we also, we understand the California Independent System Operator also understand that as the resource adequacy is transitioning and now in the first year of the slice of date framework, that they too ought to be can be looking at adjustments to make sure that as we achieve the the compliance target at the PUC that RA supply plan can also meet the CAISO's grid operational need.

So that's first and second, improve information access. The state has many important policy goals and this comes at us at an alphabet soup of important programs. We have the IRP, the RPS, the RA, the PCO and many ad hoc data request to help the staff, the planning staff do their job.

And we think this aligning, merging, looking at a way to streamline the reporting across these programs would really help not just us, but really the agency themselves. Policymakers, like you better identify information price trends in better to do that sort of calibration for course adjustment as needed and really position the agency themselves for success.

Lastly, we would be remiss if we didn't mention the importance of demand flexibility. As weather becomes more volatile. As we look to accommodate more weather dependent resources, enabling greater demand flexibility, we think is highly critical. And currently as a retail provider because we are able to do essentially a B2B rate arrangement with our customers.

Through that arrangement we offer dynamic rates that are indexed to the day ahead market price that are cleared at the California Independent System Operator. And about half of our customers actually opt to take service under a dynamic rate option. And we understand all major direct access providers have such options.

And this is a great tool to help customers save money on their bill but also help us reduce our procurement cost, as customers are responding to these price signals and reduce and make adjustments and often use that price signal to help optimize their on site generation if they have any.

That is helping us avoid that extra slice of RA or wreck or whatnot that we do not need to procure and that becomes a cost saving that we then get back to the customer.

So in, in closing, as the state is looking at affordability and potential of bringing on new load, new either new load through energization initiatives for electrification or data centers whatnot.

And if the concern is to contain cost but accommodating these larger unconventional load, we think one obvious solution is to consider adding more eligible customers to the existing direct access market to allow, to allow more options and more competition to help address the cost pressures. And with that, thank you for.

Thank you. All right, we're going to turn it. I think we'll turn it to Mr. Zimmer and then our final panelist is remote. Mr. Barry, we'll hear from you in a minute. Mr. Zimmer from the Northern California Power Agency. Welcome.

Great, thank you for the opportunity to speak. Say good afternoon Madam Chair and Assembly. Really the goal of our comments day is focused on reliability. The purpose of this discussion and NCPA is a joint powers agency. We work on behalf of 16 municipal utilities located through northern and Central California.

And be honest, our number one priority is ensuring cost effective reliable service to our customers. And it was really interesting listening to the panel earlier today because I did touch on a number of key areas that I think will be important. Really focusing on that mid to long term planning horizon for the purpose of reliability.

So in the interest of time, because I know five minutes I'll touch on what we think are some of the key areas where we should be focusing our policy objectives.

One is really on that issue of transmission development as discussed in the prior panel, we're on a growth trajectory to build a lot of new capacity and interconnect to the system. One of the real challenges today is ensuring that there's enough transmission capacity to interconnect to.

And in some of the more really interesting information that the California ISO shared, they have a cool tool called the heat map Interconnection Heat map, which actually depicts where there's current capacity available for interconnecting new resources.

And today most of that capacity tends to be in very urban areas like the LA Basin or in the Greater Bay Area. But that may not necessarily be where we're going to build all of our new resources to meet some of our climate objectives.

So some going to be really important to ensure that the transmission planning process that was discussed as well as the interconnection study process is further enhanced. There's a lot of efforts undergoing in that space to ensure that there's coordinated planning across the agency.

One note that we want to compliment the California ISO and their recent work in enhancing the interconnection process. There was a huge backlog of generation that was trying to connect to the grid. And from a commercial standpoint, I'm in the business of acquiring output from those facilities.

So I really want to ensure that those facilities that have the greatest commercial viability have an opportunity to connect to the grid.

Also from a load growth perspective, for example, one of NCPA's Members, the City of Santa Clara, is expecting fairly dramatic load growth over the next five to 10 years as a function of either extensions of their data center customer demand or adding new data centers.

As well as another example, one of my members, the City of Palo Alto, is also expecting see quite a bit of demand as a function of electrification with additional EV penetration in their system.

And so in addition to building transmission to enable new capacity, we also have to plan appropriately to ensure that we can serve the load growth that we're expecting. And there's a lot of challenges that go on that. But we think transmission development as an area focus could should continue to be an area of focus.

Another area is electric utility finance stability. And so as we talk about building all this new infrastructure that's very expensive, so the utilities are going to have to borrow a lot of money and ensure that they can build the system out to maintain reliability in the system.

And ensuring that our electric utilities have both strong financial and stable financial outlooks will be critically important because in many cases we'll be having to borrow significant amount of capital to build that to build all that new infrastructure.

And one of the key things we just continue to highlight as a potential risk in that area is the utilities ongoing exposure to wildfire, both from the standpoint of exposure to impacting infrastructure directly, but to some degree from a financial standpoint, exposure to impacting the utilities credit ratings.

Because I talk to the credit rating agencies quite often and the first question they asked me when they walk in the door is what are you doing about wildfire risk?

And so it's really, I think that's a key area and also ensure that we're mindful of setting policies that enable the utilities to be successful and be able to borrow the funds at a cost that ensures affordability long term. Third item I'll talk about today is really the concept of regionalization and resource diversity.

We think that will be a critical component to support long term reliability. When you're trying to meet demand on a 7 by 24 hour basis, you have to have many tools in your toolbox. You have to have different types of resources that can provide various operating characteristics.

For example, the hydroelectric facilities in the north part of the, northwest part of the country, wind across Idaho, New Mexico and a lot of the solar resources now there in California. It's really going to take a combination of utilizing all that to serve reliability in an effective manner. I know there's an active discussion regarding a regional market.

We generally support the concepts behind that.

We think the benefits of a regional market one, support affordability because I think as discussed by Elliot Mainzer earlier, it enables a more optimal dispatch of the fleet and also supports reliability and increasing access to a more diverse set of resources that can be used to serve load and also would ultimately lower emissions.

Because one of our goals is to continue to build more renewable resources. And practically speaking, today we're already running into challenges where we're having to curtail some of those renewable resources. So perhaps by establishing a regional footprint, there's an opportunity to deliver that power across the broader west.

And in some respects, one thing we wanted to note is to the extent that we're not successful in and moving to regional market, that could in itself actually pose a risk to long term reliability.

Because to the extent that California can't harness or access all of those attributes that I spoke recently and in effect have to go alone, that in itself poses some challenges to ensure that our grid can be robust in the context of extreme weather.

And most importantly, we can ensure that we can continue to provide services at a cost effective manner for our ratepayers. So in the interest of time, I'll stop there and I'm happy to entertain questions.

Thank you. All right, for our final panelists, we are going to turn to the screen. We're welcoming Mr. Glenn Barry from LADWP.

Hi, can you hear me?

We can hear you.

Okay. I had sent some slides. If we have them, it'll be helpful to put up. If not, I'll go into it without them and you'll just have to imagine the numbers. Do we have the slides? zero, we did. There we go.

We've got them.

Okay, perfect. Okay, perfect. Are you ready? Then I will start. Okay. Good afternoon. As was stated, I'm Glenn Barry, the Assistant Director of Power Supply Operations for the Los Angeles Department of Water and Power. Let's give a quick look at our reliability for this summer.

We are a municipally owned utility with an all time peak load of 6,502 and that occurred on August 31, 2017. As a municipal municipality serving the ratepayers of Los Angeles, we're not CPUC jurisdictional, but we are extremely conservative when it comes to planning to cover our load.

You'll kind of see that on the screen in the first column. You kind of see month by month for this summer our total generation resources. And that's based on all planned or known outages already taken out of there. The second column is the target load that we plan to cover.

You'll notice that even though our peak of 6 502 occurred the last day of August in 2017, we actually used that number for July, August and September. We're more conservative. We use a higher number even though in months July and even in September we haven't seen anything that high.

But again, the last day of August it can happen at any time. So we use the higher number to make sure we're conservative and can cover our load. The next column, the green one there is the forecasted 1 and 2 year a lot lower. You'll see, but we don't use that for planning purposes.

LA has several ties with other utilities both inside and outside of California, but we typically don't rely on any imports when serving our, when planning. We do it all on our own to make sure we can cover it and we're usually able to do that. We usually export, if anything.

A day ahead and real time plants may utilize imports when they're economically desirable. And we are a member of the energy imbalance market, so that does come into play in real time. The next column over kind of just has a net value of our contractual imports that are captured in the planning horizon. They're counted there, but they're not much.

Again, it's 177 July, August and September. And those are mostly lost paybacks and things of that nature. The next three columns, kind of where we do most of the work here. And those are. The first one is our N-1 that all balancing authorities are required by NERC to carry for us.

It's our single largest unit at 575 for the summer. The next one, then we go a little further and we actually plan to carry replacement reserves of N-1-1. That would be our next largest unit, about 562 in July, August and September.

We also then carry up to 400 megawatts of reserves for our variable energy resources. They're not firm dispatchable units. We know they can all go away, wverybody knows that. We, we plan to carry that we actually do 50% of whatever's online up to a maximum of 400.

So you can take caps out at 400 in the summer because we're much higher than 800. I think we have usually around 1400 megawatts of renewables on the system.

With all that said, you can kind of see in the, in the last column, the green one there on the right, if we encounter our typical 1 and 2 year, we can comfortably cover the forecasted load, including all the reserves, both what's required and what's not.

In the second to last column, the blue one there you can see if we counter our all time peak loads, again being conservative going with that high 6,502 most of the time we become much tighter. You actually see some negative numbers there. But again we're trying to cover over 900 megawatts of reserves that aren't necessarily required.

We have worked with the ISO in the last couple years to make any excess generation, including those reserves that aren't required, available in the day ahead or real time time frame on a firm contingent basis. Meaning we can get those back if LA has a contingency and we need to supply our system.

So they've agreed to that and we make those available whenever we possibly can. LA also has about 100 megawatts of demand response. That's worth mentioning, not captured on this screen. If you go to the next slide. Last one, wrap this up. Not much to see here really, but it shows our resource mix kind of separated out.

How we separate it. The pie chart has the averages at the bottom there. Doesn't mean that this will be the actual mix that's on. It's just what's available.

One critical note to mention is that we have 13 megawatts of in-basin thermal units that are once through cooling and scheduled to go away at the end of 2029, you can see the far right column. We're in that 31 to 3300 range of our in basin thermal. This about 1, represents about 1 third of that.

So those units really have to be repowered in the next now four years. They have to be repowered. The in-basin is very critical to us. All our flows come in from the east to the west and we don't have anything to push back other than that generation.

So very critical that we get those units repowered or changed over to air cooled units. And we're in the process of working on that. And with that I'll turn it back over to you. Thank you.

All right, thank you Mr. Barry and thank you to all of our panelists for being here. We'll go ahead and open it up for questions from Committee Members. Assemblymember Rogers.

First of all, good to see you. Mr. Tracey, outside of baby music class. Always good to see you in the professional capacity. So for folks on the Committee who don't know, I was on the board of directors for Sonoma Clean Power for I think five years before being elected to the Assembly. And for some context.

First of all, thank you for plugging the geothermal package that Assemblymember Papan and I are, are helping to carry. Sonoma Clean Powers territory is I believe the only place in the United States that can currently deliver 100% renewable energy 24/7 from a locally produced source.

And that's because of the partnership with the, the geysers and the geothermal plant with Calpine in our district. One thing that was highlighted was the need for increased reliability and transmission and build out. But the role of a CCA is not in that realm. Have there been any discussions?

And at the same time as CCAs in particular have a really big rate base that they can potentially bond against for capital projects, should they be enabled to or should there be an opportunity for them to do so? And has that been part of the discussion about how to meet some of this reliability challenge in CCA territory?

Real quick? Likewise. It's good to see you outside the baby class. But I would like, you know, the idea of financing transmissions a little bit out of my expertise. But I do want to double down and say that as a CCA that is very climate forward. Transmission is setting the speed limit for everything we do.

And I tell people when I first started with Sonoma Clean Power, we did our first IRP when I was on board in 2020. And at the time I kind of viewed it as a compliance exercise. But over the years, I've actually seen it as our tool to advocate for the type of infrastructure we need for our portfolio.

The reason I'm here today, I think a lot of the advocacy I'm pushing here is that we see a big need to put the gas pedal on transmission as an affordability tool as a way to be able to create new opportunities.

When we're a CCA right now going out to try to procure the battery storage or the solar power resources that either meet a mandate or meet our portfolio needs, the developers are able to set their price because there's not enough interconnection space.

And we've lost a lot of the value of having a deregulated market with competition where the best projects win. And I think the value of creating more transmission headroom is really understated. And I think all options should be on the board, including ways to leverage CCA financing.

Yeah. And especially when we were rebuilding infrastructure after the Tubbs fire. I know that there were partnerships between PG&E and Sonoma Clean Power for Micro Grid capabilities in areas where it didn't make sense to rebuild that infrastructure.

And just want to highlight as a City Council Member, we were able to flip the switch and switch over to 100% renewable energy for municipal buildings overnight because we had in place the procurement already for projects that were up and running. And then sort of the chicken and the egg cycle.

Because of that increased demand for the City of Santa Rosa going all electric or green energy. It actually allowed Sonoma Clean Power to invest in what's called the GeoZone initiative, working on different geothermal technologies with private developers to try to provide additional energy. So I appreciate you allowing me to highlight that and answering the question.

It is something that I'm really interested in is how we can create those partnerships to remove those roadblocks or those pinch points. Because it's not just about the creation of clean energy, but actually the delivery of it. Particularly in my area where it's a bit under resourced in terms of transmission. Thank you.

Assemblymember Harabedian.

Thank you, Madam Chair. Thank you to all the witnesses for being here and for such a educational presentation overall. I mean, I do think that the longer that you sit on this Committee, the more you need a glossary.

And I'll tell you that one of the things that Ms. Lee brought up, but I think is really part of the headwinds here is that things are seemingly overly complicated by the amount of entities involved with overseeing and regulating what you do.

So I really want to kind of get everyone's thoughts on particular the headwinds that have to do with the inefficiencies that we as a state put on you.

And I think that when dealing with five different agencies and bodies and trying to get things planned and online and then once that happens, actually operating efficiently seems extremely hard when you are dealing with many different entities doing different things. So. And Ms. Lee touched upon this, but all of you sort of danced around it.

How can we make that process more efficient? I mean, it seems obvious that there needs to be some sort of unification. I don't know exactly how we do that, but there needs to be something done to make your lives easier so that power providers and generators can actually do their jobs easier. So how can we do that?

Sure, I'll take a shot. No, I really, really appreciate the question. That's incredibly important. NCPA's Members are publicly owned electric utilities. We're not technically subject to the CPC jurisdiction, but we do work very closely with the California Energy Commission. In the context of our business.

I'd say one thing that would be very helpful is some level of general consistency and a general sense of stability.

And I think one question came up, not to focus on a singular example, but I think there was a discussion about Diablo Canyon earlier and as to whether it be NCPA has a strong position one way or another as to whether that facility should be retained, I think coming to some resolution as to whether that facility will be retained could have a material impact on how we plan for the future.

Because just as one acute example, that's a 2,000 plus megawatt baseload generating facility. And if our goals as a community and an industry is to maintain reliability, we have to plan accordingly for that. I think a good example is most of my existing development, you know, that I'm planning for today likely won't be online until 2030-2032.

And so most of the investments we make are fairly, fairly capital, extensive long lead time development.

And so, you know, having, you know, some kind of stability in terms of being able to forecast the future really helps us align, you know, our portfolio and make those investments in a, in a way that, you know, speak to the reliability and the cost effective needs of our customers.

But I don't, I'm happy to elaborate on anything.

No, that's great. Feel free to jump in.

Sure. Thank you for the question, Assemblymember. I just want to also follow up that we don't really, we don't attribute the sort of the silo then the very Highly structured, complex system to really this is not the fault of the Agencies because-

I know I do though I attribute it so you don't have to. My question attributes it. So.

These policies were created in different times of the California's energy policy history. And so they were developed. These compliance programs were really developed at different junctures of our journey. And so at this part we understand the agency leaders to be highly aware of the need to coordinate.

And this is the highest level we would say coordination we've ever seen across the agency. But just additional encouragement perhaps staff resources. I think I used an example of their resource adequacy slice of day reform.

That's where we really saw very committed staff that have, that probably was not given, didn't have access to the best tools but they really, really worked very hard through many calibrations to make the tools work. And so that is one example is where the staff probably need more data management tools.

And that's sort of a resource conversation you all can have with the agency leaders and looking at, at some point in time if we have developed a IRP sort of procurement paradigm and we also have a, that's a long term paradigm, we also have a sort of this legacy RPS long term procurement paradigm.

How do we then consolidate the reporting in a way that helps minimize the sort of staff work? And we want to be able to harness the talent of the staff toward creative problem solving and not necessarily wrangling different compliance spreadsheets. So that's some thoughts there.

Yeah, I would add not necessarily differences in agencies or improvements there, but looking at like what we have coming post 2030 we will have still the extension of the renewable portfolio standard. Post 2030 we have GHG free targets kicking in starting first ones 2035, then 2040.

We also have emissions reductions targets that the CPUC may or may not make binding as we build out our portfolios. So post 2030 we'll have three different clean energy programs that we will try trying to comply with at the same time.

And the more kind of constraints you put on, the harder it is to pick the thing that is going to satisfy all things. So I would welcome a conversation on simplifying.

That's the first thing that came to my mind is simplifying from three down to one to make it more efficient, easier to procure one thing that ticks all the boxes.

Super helpful, super helpful. And I think on that point, and Mr. Tracey, you brought it up, I mean I think SB100 2045, how are we going to get there and that's all part of this. But you know, on your winter reliability points, which I thought were really unique and we're kind of focused on summer, you can start.

But on that kind of that deadline focus, especially SB100 and thinking about 2045, how do you think the state, our agencies, CAISO, how are they doing, in your opinion, to set us up to actually get there? Especially considering your winter reliability points, which it really is this new paradigm. Right. That we have to think about.

So we'd love to get your thoughts and any of all three of the other Members and thank you for being here. This is extremely helpful and you're all doing a great job.

Excellent. Yeah, no, I appreciate the question. And you know, to be fair, you know, the challenge that all the agencies are tackling is immense. I frequently, when I talk to the PUC team, I say, you guys have the coolest jobs. You're literally charting the future not just for California, but the world and trying to solve this problem.

But that said, I think there are a lot of opportunities in thinking about 2045. I think a lot of the focus is on near term or very kind of mid term type reliability issues and mixes and the type of grid that's going to deliver. The mix we need in 2045 is going to be very different.

And I think it's really important to consider those trade offs today because you're going to need potentially different infrastructure. Also, there's potentially resources you would build for 2045 today that could provide value through both.

And you're not going to end up with this scenario where you end up building one set of resource mix that you don't necessarily need because you have to build something else in 2045. So with that said, I'm starting to see some progress.

So for example, in the integrated resource plan process, the PUC just unveiled what they're doing for this next upcoming cycle and they've activated enhanced geothermal systems as a potential clean firm technology that was not before activated, it was not available option.

So they're starting to look at the role of some of these more emerging technologies and how they could provide a piece of the puzzle down the road where I don't think that they've kind of before have been placeholders.

So I'm seeing progress, but I think we need to start really thinking about exactly what does this look like, what are the infrastructure requirements, where do we potentially need to have deployment funding or other types of priorities to get to get this off the ground. Thank you.

Yeah, I mean, I would share. I mean really hats off to the California ISO on their reform, their interconnection queue reform. That was everybody's headache for many years.

You know, he talks about like literal humans having to write up, you know, reports that the minute you hit done, it's absolutely useless because there's, you know, hundreds of thousands of megawatts in the queue behind that one and it's all become meaningless. Like major, major reform on that.

Really hats off to them. The, you know, the, the release of the RC triple P. If you don't know that acronym yet, I mean no one knows what it stands for, but just go with RC triple P. It's the new paradigm framework where we're going to sort of make sense of a programmatic approach to the IRP.

Hopefully we can marry up like the way you count with the way resources are given capacity in RA and the IRP. Let's try to make those the same. That'd be great. I'm very optimistic about the RC triple P and look to actively participate in that.

This is where we agree with the importance of aligning the metrics.

And so if we're counting a set of resources a certain way on a longer term basis and we have a different way of counting them for next month or the next year, then how do we know and when developers are looking to transact deals with us, that uncertainty of how their resource embedded RA value, that uncertainty whether or not that RA will count, that just, it's just extra risk and extra risk premium they have to think about when making an offer.

And so, and for us as well. So, so that's something that is a good governance guidance that you all can provide to the agencies to make sure that as they, you say building these programs and paradigms that they're aligning as closely as possible on the metrics that are used.

And reasonable planners can disagree on different metrics to use. But when commercial decisions are made and have to be made based on procurement directive that come out of these finer metrics, then that's where we are getting sort of, we're getting into this commercial risk and then cost and affordability concerns.

And if I may, it's a big problem. I agree with Ryan's comments. I feel for the agencies it's an incredibly complex problem we're trying to find a solution to. But I just wanted to echo my recognition of the recent collaborative planning efforts that has been a focus of the agencies.

You know, I think the agencies are working better today than they have in the past and also wanted to echo my acknowledgment of the effort done by the California ISO to improve the interconnection process, to enable more capacity to move more efficiently quickly through the process, to connect and just to focus on maybe something a little bit more acute because it is such a big problem.

I'd also want to echo, you know, streamlining reporting, that could be a really helpful thing. And because as we, as we continue to dive farther into this complex world, generally there's a strong desire understandably to kind of check the progress along the way.

But generally that creates a ton of additional administrative effort in terms of staffing time that could be committed to other things for that.

So without going into the details of what exactly we could streamline in that context, we're happy to talk to you more about that, but that would just be one minor example of how we could potentially refocus our resources to those things that are more productive, I think.

Any other questions?

And thank you all for those reflections. I really do appreciate this discussion on the need to rationalize some of our regulatory structure. As I think you said, we're not going to whiteboard it here and figure it out.

But I really would like the opportunity, and I'm sure other Members would as well, to dig into the details of some of that a little more and understand what bits of it can we help to shift through legislative action or perhaps removing some of the things that we told people to do 25 years ago that perhaps are no longer relevant.

I do have a follow up question, Ms. Lee. You were talking about kind of, you know, they need to align the IRP with the RA process. And I did ask a question of our other panel. Essentially the way that we are doing resource adequacy seems incredibly complex.

Do you think that complexity is serving us and delivering sufficiently better outcomes than a more simple process would? Happy to hear anyone's reflections on that.

We would say that complication is not serving the agency's own goals and needs. However, those complications arise because of restrictions placed on them. So I think this is something that probably take a much bigger conversation with the Administration and the agency leaders to sort of, they probably might have to whiteboard this among themselves.

So we'll I think, keep that high level. But as a, you know, due to our work and frequent interactions with the agency staff, we do see them being, this is very hard work. We do not envy their roles.

And so we're of the perspective that anything that can help the agencies do their job easier, more effectively, the better and it's good for the public purpose. It's good for our needs. And we think this is the right focus.