Assembly Standing Committee on Utilities and Energy

Good afternoon. I would like to call to order this hearing of the Assembly Committee on Utilities and Energy. We're here for an informational hearing to discuss state planning and coordination for the energy sector, particularly as we work to deliver on California's climate goals and build our clean energy future. Before we begin, I have a couple of housekeeping items to go over first. Some of our panelists will be participating remotely today. Please note that there will no longer be phone testimony at today's hearing.

Public comment will be either in person or submitted via email on the Committee's website. Additionally, 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.

I'd like to take this moment to welcome all of our returning Members of the Committee and also to welcome our newest Members, Assemblymember Friedman, Assemblymember Joe Patterson, Dr. Wood, and Assemblymember Zbur. Welcome, everyone. I'd also like to take a moment to welcome our new CCST Science Fellow, Dr. Kathleen Chen, to the Committee. Welcome, Kathleen. And before we jump into our witnesses, I will note that this is our first hearing of 2024.

It's my first hearing as the chair of the Committee on Utilities and Energy, and I just want to take a minute to set today's discussion in context. So I think we all recognize that this is a pivotal moment for California. We have some very ambitious climate goals before us, and there's a monumental challenge on our hands to deliver on those goals and to build California's clean energy future.

We need to be mindful that as we're working to build that future, we need to balance sustainability, affordability, and reliability. And that all starts with a plan. So that's why planning is the topic of our first hearing of 2024. And while the topic may seem dense by virtue of the number of planning programs and administrative entities coordinating them, but nothing could be more real than the critical infrastructure that we are talking about today.

The way that California plans for this infrastructure for the electricity grid that is the backbone of many of our broader climate policies is absolutely vital. And while there is certainly more than one way to deliver on California's goals, meeting them as affordably and reliably as possible absolutely requires efficient and effective planning. So with that, are there any other? Would anyone like to make comments before we begin? Yes, please.

Thank you, Madam Chair. As the Vice Chair, I echo the comments here this is important, but I also want to underscore the absolute necessity of reliability and affordability. And I am concerned that I've been here 11 years, this is my twelveth, I've been Vice Chair of this Committee. And from the very beginning I have been concerned about two things. Our grid is becoming increasingly unreliable and the cost of electricity to our folks is increasingly more and more expensive.

And so I think that aspiration is one thing, but reality is another. And I think we have to remember that the science of how electrons are created and sent to people, I think we've got to be careful that we don't war with the basics of how electrons are created, how much they cost and how they get to people, because without that we will continue this arc.

And if you look at the reliability issues with this grid, when I first showed up, we were not having the unreliable issues that we have today. And if you look at the rates that we are charging to people today, they are substantially up. I represent an area that is almost entirely PG & E, and we have reliability issues, we have connection issues, we have electrification issues, and we have cost issues.

So ambition is one thing, but if that ambition creates a set of circumstances in which people's electricity is less reliable and more expensive, I don't think we have achieved much for the public. And so I don't think we need- we've got to get past this idea that we can war with and pass laws, that frankly you've got to have enough supply, you've got to have enough for the demand, it's got to be ready and available, it's got to be affordable.

And when you go to the wall and you turn on the plug, it's got to be there. And yet we have gone through, in the 11 years I've been Vice Chair here, I was always told we've got offroads, right? Because we're always saying, well, it's important to have reliability and it's important for us to have cost. And when we have those issues, we've got offroads on all of this mandated supply. Well, where are those offroads? When have we used them?

If you take a look at the grid today and its cost, it is substantially higher than 11 years ago. And I come from an area where hundreds of homes were going to be falling out of escrow because connections couldn't be made by PG and E. We had a major campus of our community college in west Fresno, which is a game changer for that community, and it was delayed over a year because we couldn't get electricity to the project.

We have an airport that is one of California's busiest. We are coming back stronger than ever. Two million passengers after Covid. We've internationalized it. That international terminal is growing. And our concern is, as we construct it, will PG & E be able to connect? And the issue there, quite frankly, is how doggone long it takes to get transmission lines up and going. Let's be realistic in this hearing. If we don't have transmission, it doesn't matter where the electricity comes from.

And I've talked about this in the past. Unfortunately, this legislative body has decided that there are moral electrons and immoral electrons. We're going to make sure that those immoral electrons aren't in that mix. Do you know something? It's the immoral electrons that keep the lights on. When we have these brownouts and blackouts, we go to the Spot market and we get natural gas and we get other forms of electricity other than wind and solar, et cetera. This is the reality of what we're facing.

And all of the aspiration and happy talk about this isn't going to solve the problem, because if we step into this uncertain and without a comprehensive and reliable plan, we'll be here in years to come and wonder why the grid is even more unreliable and why it's even much more expensive. And so I am here to listen, but I'm also here to caution.

Thank you, Vice Chair Patterson, and I certainly appreciate your focus on cost and affordability. As the Members of the Committee know, we will be having a hearing on March 5 to do a deep dive into cost and affordability as well, which is certainly top of mind for me and other Committee Members. Other Members. All right. Wonderful. Let's go ahead and call up our first panel, which includes the three energy planning entities with the greatest number of responsibilities in this sector.

We'll be hearing from the California Energy Commission, the California Public Utilities Commission, and the California Independent System Operator. I'd ask all of our panelists to provide their opening statements, and then we will turn to Members of the Committee for questions. Welcome, everyone. We're going to go ahead and begin with Commissioner Siva Gunda, the Vice Chair of the California Energy Commission. Mr. Vice Chair, you may begin.

Thank you so much, Chair, for having us today, and congratulations on your role. And thank you for having us for the first hearing of the Committee this year and also respects the Vice Chair and the Members of the Committee. So, for the record, I'm Siva Gunda, Vice Chair of the Energy Commission. I will be setting the stage overall for the energy planning in the state.

But I am joined by my colleagues Leuwam Tesfai and Neil Miller, who will be specifically talking to the CPOC's role around the integrated resource planning and some of the results there and the transmission planning that CALISO does. So with that, I would like to move to the next slide, please. Think just at a 30,000 foot level. Just starting off with a high level presentation on where we are on our clean energy journey. In 2013, we're about 41% zero carbon.

In 2020, we were almost 60%, and that changes up and down, based on the amount of hydro we have on the system, we have seen as high as 62%, and then it kind of goes down depending on the hydro. And we are on our journey to 100% zero carbon resources supporting the electric grid by 2045. Next slide, please. Just to start off with our roles at a very high level. So just want to appreciate CALISO and CPUC joining us today.

Other Members on the team include DWR and CARB, who also have important roles in supporting the overall planning, but just at a very high level. The Energy Commission is the state's planning and policy agency, which primarily does a few things. We produce what is called an IEPR Integrated Energy Policy Report every year. Every two years, we update our demand forecast, which is a huge part of that.

We also work with POU's, Publicly Owned Utility, on their portfolio, renewable portfolio standards and their IRPs, and also their reliability planning. CPUC focuses on approximately 75% of the state, which is the investor owned utilities, CCA's and some of the direct customers, and really looks at the energy planning and procurement at kind of boots on the ground level for that 75% of the state. And CALISO works-

We all kind of have different footprints, overall state, CPUC footprint, and the CALISO footprint, which covers all of CPUC, but also has some of the POU's under them, which is about 80% of the overall California State. And then they are primarily responsible for the transmission, planning and interconnection processes, which Neil is going to touch on today. At a very high level, if we go to the next slide, just setting the table on some base level, we are looking at a humongous amount of build out.

And this is from the SB 100 results, the 2021 report. And this is looking at a statewide. And what you'll hear from Leuwam today will be specific to the CPUC jurisdictional entities. So for the state as a whole, we needed to add approximately 183,000 megawatts in total to meet our zero carbon goals. And we are approximately 35,000 already there, but we are talking about adding another 150,000 megawatts over the next 22 years.

As you will see there, one of the core results that came out of the planning is the importance of technology diversity, but also the geographic diversity of where those resources are located, both to ensure local reliability, but the best performance of those resources. And in that you will see that the large amount of future build still relies on solar and wind, but there is a large amount of storage, battery storage that really has to be added to support the evening ramps.

In line of about 50,000 megawatts. Next slide, please. We have a little bit of a-the animation is gone, I think here. Maybe it's the PDF. I'll just kind of walk through layers of this. I apologize. I'll kind of start from the top layer. So at the very high level, you're seeing the climate goals planning. So this is an integrated planning that we all work together on. So in the 20 to 25 year time frame, we do the SB 100.

And in this analysis, much of the results are directional in nature. It gives you the magnitude, rough magnitudes of how much we need to plan for. We do a good reliability level planning in that, and it's based on what we call demand scenarios. It's not demand forecast. The difference being forecast is what we define as something reasonable to occur in the near term. Demand scenarios are different pathways that could happen depending on state policies.

So we look at the demand scenarios and plan for the overall amount of resource Bill that we have to do. And again, the tools that we use here are not robust. They're largely giving you direction on where we are going as a state. And with each of that planning regime, it becomes more and more rigorous.

The next level is the 10 year time frame where we substitute the demand scenarios with more of a demand forecast, which we think is most reasonable to occur in the next 10 years. Given that we have clarity on the policy-policies that the state is pursuing here, we really work on what is called the loss of load expectation reliability analysis. It's a deep dive.

We look at hourly forecast, but we also look at annual forecast to get the main details on what an hourly peak could be, what a monthly peak could be, and what system peak could be on an annual basis. And that's something that we do in what we call the 10 year planning regime. And then we kind of like go into the next level, which is the resource adequacy time frame. This is basically looking at the next year, next summer.

So if we are looking today, our forecast just got adopted. CEC's forecast that triggers a bunch of processes. And the resource adequacy for next summer, for the following summer will be set sometime in October. So we're looking at 2024. We just adopted a forecast in February for 2026-2025, resource adequacy will start planning. And then the next level that you look at is what is called the operational time frame. This is where CALISO comes in. CALISO really is looking at operating the grid in real time.

And when we talk about reliability issues coming up suddenly, whether it's because of a supply shortfall or it's because of a line going out, like what happened on July 19, 2021 when the bootleg fire happened and we lost 4,000megawatts of transmission coming into California, that is something that CALISO has to deal with. And that's where we are thinking about how do we prepare for those emergencies starting 2020.

So I just wanted to give you a layered approach on how we plan and just to amplify the assumptions become better and better as we get closer. So it's like more and more rigorous. So the analysis is more rigorous, the inputs are better, and we have a better idea going into the summer rather than going into five years from now. Next slide, please. Apologize again if the animation is not here. Really apologize. I'll just kind of focus this at the very high level on three bubbles.

First, the CARB Scoping Plan. And next, below it in green, is the CEC's Integrated Energy Policy Report and the SB 100. That's the first contour. So what the CARB Scoping Plan does is gives us an economy wide blueprint. They're doing this every five years, they say, starting from here. If we have to hit carbon neutrality in 2045, here's your best pathway forward.

And I think over the last couple of scoping plans, we have come to a pretty good consensus as a California in a community that electrification combined with clean electric grid is the best pathway moving forward, most cost effective in reaching the carbon neutrality and the most expedient. So when we think about that CARB then within their context develops what is called GHG emission levels for each of the sectors.

So the electric sector gets, this is the level at which the electric sector has to be in order to meet these goals. So the next level, the demand forecast, the CARB scoping plan and SB 100, all of them go into the IRP process at CPUC. And they're all kind of providing different constraints. So the demand forecast tells what the demand is going to look like. CARB sets the GHG constraints on the system SB 100 gives the directional approach on land use and other issues.

So we look at all of them, and CPUC then does an optimization of the plan which Leuwam will go into to figure out what's the most cost effective, given these policy constraints that we have, and that results from PUC will go into the transmission planning at CALISO. So this is a very interactive work. We have number of forums for coordination, both that are well known and well established and that are really in their infancy.

For example, on the demand forecast, we call something called the Joint Agency Steering Committee, that has been in place for almost 10 years now that coordinates staff level engagement and principals level engagement on a weekly basis. So they talk about how the technical analysis on the demand forecast affects the policy implications. Next slide, please. Here's what you're looking at in terms of the forecast the next 10 years.

So, given that our goals are really hinged on 2045, the CEC is trying its best to have the forecast longer than 10 years. So it's almost to 2040 now, and in the next couple of iterations, we'll hit the 2045 forecast. But I also want to caution that beyond 10 to 12 years, it's very speculative in terms of what the electrification levels could be. So if you see the historical line, you will see kind of a flatness to it.

That doesn't mean that the energy consumption in California has stayed flat. It just means that the consumption has been compensated by behind the meter solar. So what you're seeing there is, even though the consumption is going, the behind the meter solar has been cutting down the peak. So you have about three spikes in there. About 2016, there was a coastal heat wave that happened that really spiked 2016. In 2020, as we all know, we had the blackouts on August 14 and 15th.

That's another bump that you see. And in 2022, on September 6, we had almost 53,000 megawatts in the system because of the 10 day heat wave across the west. And that really gives you another spike. So the struggle that we have as we plan for this is, one planning what is a reasonable level of peak to anticipate?

At the same time, how do we cover those extremes? As the Vice Chair mentioned, in terms of creating the necessary tools in our pocket to make sure we get through those peaks, system peaks. So, largely, our goal is in meeting the peak that we're planning for, we can meet it with clean energy resources, and hopefully we can meet the entirety of that with clean energy resources.

But in the near term, we might need to be supported with some of the fossil and other generation that we might not want to run in the long term. So with that, I'll pass it to Leuwam to kind of go through the IRP process.

Great. Good afternoon, Chair Petrie-Norris and Vice Chair Patterson and honorable Members of the Committee. My name is Leuwam Tesfai, and I serve as the deputy executive director for Energy and Climate Policy at the California Public Utilities Commission. Thank you for the opportunity to appear before you today. My presentation this afternoon provides an overview of the Public Utilities Commission's role in energy resource planning. So on this slide, we're looking at integrated resources planning and looking back at Senate Bill 350.

It directed the Public Utilities Commission to ensure that California's electric sector meets its greenhouse gas reduction goals while maintaining reliability at the lowest possible costs, all themes that were echoed by the Chair and Vice Chair as we started today's hearing. The CPUC's Integrated Resource Planning process targets electric sector decarbonization to support statewide greenhouse gas reduction efforts while maintaining system reliability.

We use a State of the art electric system modeling tool and a robust stakeholder process to help guide the CPUC's decision making on meeting greenhouse gas emission reductions and reliability goals for the electric sector for our jurisdictional load serving entities. Integrated resources planning is a multi step process. The first step of the IRP cycle builds on the findings of the previous cycle and is designed to provide analysis and guidance for those who provide power to the grid.

So these are our load serving entities, which include Southern California Edison, Clean Power Alliance, the CCAs, the IOUS, and the ESPs. They use this information to plan for meeting their greenhouse gas reduction goals, reliability and cost objectives. The second step on this slide considers the load serving entity's preferences and actions that each of them proposed to the PUC for meeting these goals and requirements, which the CPUC looks at overall in order to develop a preferred system plan portfolio for all of the load serving entities.

So all of these entities that I just mentioned, they come forward with what their plans are, but then we look at them together in order to make sure that the electric sector under our jurisdiction are meeting the greenhouse gas reduction requirements and reliability objectives. The Commission decision on the latest PSP was actually adopted last week and is under number three on that slide.

This IRP process lays the analytical foundation for the Commission to consider procurement actions to ensure the state remains on the path towards a carbon free electricity grid by 2045. The preferred system plan also guides the transmission planning work conducted by the CALISO to ensure there is sufficient transmission for the new clean resources being added to the system in California and that the transmission system is keeping pace with that resource development. Next slide, please.

So, as I said last Thursday, February 15, the CPUC adopted the most recent portfolio of expected resources, which are shown on this slide, that will reduce the statewide yearly greenhouse gas emissions from the electric sector to 25 million metric tons by 2035. The portfolio reflects the resource preferences of the CPUC jurisdictional load serving entities and includes an expectation that over 55 gigawatts of new clean energy resources will be built to serve California load by 2035, including 4.5 gigawatts of offshore wind.

This is a 25 MMT portfolio which corresponds to the low end of the 2030 target range set by the California Air Resources Board in its scoping plan, which it adopted at the end of 2022. These resource development plans are guiding significant additions of clean energy resources to the system. Since January of 2020, 17 gigawatts of new generation and storage resources have come online on the CALISO system.

This includes a record breaking 5.7 gigawatts of new clean energy capacity in 2023, more than any year in California's history. These adopted requirements for new resource procurement in 2024 are even higher, which will lead to another record breaking year. Next slide, please. So the preferred system plan portfolio adopted by the Commission will result in significant greenhouse gas reductions. And that's what you're seeing on this slide.

It reduces emissions by 25 mmt in 2035 compared to the 2020 electric sector emissions in this CALISO area, translating to a 58% reduction. It reduces emissions by 85% and achieves a level of 113% clean energy based on the Senate Bill 100, 100% goal for 2045, the PSP portfolio achieves clean energy production well beyond the Senate Bill 100 interim targets used for PSP modeling. Everything in the IRP is key to achieving the Senate Bill 100 plan.

The CPUC's energy resource portfolio represents a 70% reduction in natural gas plant utilization within the CALISO area by 2035 and further reductions of approximately 90% over the full 15 year planning horizon. So with that, I'll turn it over to my colleague, Neil Miller.

Thank you. Yes, my name is Neil Millar. I'm Vice President of Infrastructure and Operations Planning at the California ISO. Really pleased to be able to have the opportunity to speak to you today about what we've been up to. So, as you've already heard, the ISO's transmission planning process is already heavily coordinated with the activities at the Energy Commission and the Public Utilities Commission. That coordination-

Tightening a few key areas. First, it looked at tightening the linkages between the transmission planning, resource planning, generation, interconnection, and actual procurement. Shall we just. Okay, I'll just wait.

And also reaffirming all of our interest in moving forward on a single forecast set instead of everyone developing their own forecasts in isolation. Next slide, please. If I could move to the next slide, please. So the ISO's transmission planning effort really focuses on two primary vehicles to move forward with our activities. The first is our annual 10 year transmission plan, although we are looking out a bit more than 10 years now.

But this formal approval document is the basis for all of the expansion driven transmission planning in our footprint. Over about a 10 year period. It was averaging about $650,000,000 a year in identified new transmission upgrades. Recently that started to ramp up with an over $3 billion plan in the 21-22 time frame and 7.3 billion in transmission identified needed in our 22-23 plan that was completed in March of last year. That requirement was responding to the accelerating load growth and escalating renewable generation demands.

In our transmission planning process, we do focus on finding the most efficient and cost effective long term solutions to meeting the identified needs based on the forecast inputs. Also, we explore opportunities such as grid enhancing technologies and nonwire solutions to look for the overall lowest cost solution to move forward that also meets those reliability needs. That transmission plan also kicks off the competitive solicitation process for a major transmission that are eligible for a competitive procurement instead of being assigned to the incumbent utility.

The 20 year outlook document, the second document, as I wanted to refer to, is a longer term outlook that assesses the longer term needs and helps set a blueprint in which the nearer term planning activities can be conducted. Our first 20 year outlook was prepared in 2022. We are updating that, and we'll be releasing an updated version later this spring that will reach out to 2045. It establishes this longer term direction and also, more importantly, provides the long term context for nearer term planning decisions.

If I could move to the next page, please. Thank you. Sorry about that. Let's see. In addition to the annual transmission planning processes, we also have moved forward with a few other major initiatives as an extension to last year's plan and conducted after we continued with the work to move forward with a joint project with Idaho Power on participating in what's called the SWIP North Transmission line, which is a project from northern Nevada into southern Idaho that would provide access to over a thousand megawatts of renewable generation to come south through to meet up with the California system in the El Dorado Harry Island area.

As well, we've developed a subscriber transmission owner model which would allow transmission developers developing merchant projects to bring power to the California border to be able to join our grid, but at the same time have the cost of that transmission recovered through the power purchase agreements for the generation that is actually subscribing to the transmission line and seeking access to the California market. Another effort we've been working on is to finalize this year's transmission plan, which is identifying 19 to 20 transmission projects.

We're still finalizing this, ranging from $1.2 to $2.0 billion. And in addition, a major policy focus in this year's transmission plan is to start the first wave of steps looking to access North Coast offshore wind. Next slide, please. In terms of progress to date, there is transmission capacity available on the grid, and more is being developed each year. Just a few data points on that. Over the last four years, over 17,000 capacity has been added to the grid.

You've already heard the most recent numbers for success in 2023. We're also tracking over 200 transmission projects that have been initiated in past transmission plans or through generator interconnection agreements and looking at the capacity those projects will make available to the grid as they come online. Based on those projects, we've already awarded over 45,000 megawatts of deliverability status to generators that are in our interconnection queue that then need to achieve a power purchase agreement with an off-taker and move forward on their interconnection.

And there will be more allocations made later this summer as we move on the next tranche of interconnection applications and the transmission plan that was approved in March. Next slide, please. In addition to the transmission planning efforts, we've also been undertaking this year and started last year, major reform to our generator interconnection process.

The transformational changes we're looking for, how we go about studying and moving generators through our interconnection process was largely driven by the oversupply of new applications we received over the last number of years, where the number of applications spiked very dramatically and risked not being able to provide meaningful results with that volume of new applications.

The process is tightly coupled to the transmission planning process, focusing our energies on the areas where transmission is being developed on a zonal basis to encourage generators and generation developers to focus in those areas. We're also looking at developing scoring criteria and a backstop auction mechanism so that we're studying reasonable volumes. We can provide meaningful results and move forward on the projects that have the highest likelihood of succeeding and moving forward.

Those efforts are also being conditioned on the background of the FERC Order 2023 that was released last year. That really reestablished a new baseline for resource interconnection across all nationally regulated entities. But our upgrades are going beyond that to address our particular needs. So with that, I will now pass it back over to Vice Chair Gunda.

Thank you, Neil. Just to close off, I just want to touch reliability, which is important, shared to you and the Members. Next slide, please. Again, sorry for lack of animation on this one, but just pointing to how to interpret this picture. The bottom dark blue represents the total amount of capacity we would need in any given year to keep the lights on. So going into 2021, of the things we realized was we have not been procuring enough to meet the strict reliability standards.

But today we are happy to report that the procurement that IRP has done significantly passes the reliability needs, the planning standards that we have to meet today. So what you see at the bottom is the authorized procurement, the dark blue. But top of the dark blue is just shaded area, which is potentially some of those projects, even though they were procured and authorized, have delay in actually developed.

So I just want to make sure that you're seeing that. On the top of that is the green, where we are talking about circumstances of needing additional resources because we are so far past the planning standards today. For example, September 6, 2022. September 6, 2022, the peak was almost 53,000 mw, which was 8000 megawatt departure from our standard planning. And a year after, on September 6, 2023, we were at 33,000. So it's a massive swing in terms of the megawatts that we need.

So just kind of pointing that when we plan, we are planning for what is reasonable levels of procurement, optimizing between the greenhouse gas emissions, but also optimizing for affordability. So you're looking at that resource graph in green. That is extraordinary extreme heat beyond the planning standards. And finally, catastrophic fire. When we look at catastrophic fire going back to July 19, 2021, the bootleg fire, we lost 4000 megawatts of capacity in an instant. And as you all know, California is near 30% import state on energy basis.

So when we talk about losing 4000 mw coming into California, we suddenly have to make that up. So that shaded box, then the dotted line around those three top buckets, is what we need contingencies for. We're planning, we're procuring to the extent that there are developmental delays, extreme weather and fire, how do we have contingencies in our pocket to make sure we tackle some of that.

And just want to note that our gratitude to the Legislature for giving a number of tools to the state agencies to be able to get through those contingencies. We don't have resources to get through all of the worst case scenarios, but we can significantly plan for them today. Next slide, please. Just to give you a quick flavor, there are broadly three buckets of contingency resources we have today to get through an extreme event. Top of that is the strategic reserve.

That's basically the 205 authorization by the Legislature to give us those additional tools to provide incentives for demand dropping, but also to the money that was used to procure some of the once through cooling units that were supposed to retire last year and have them in the strategic reserve for the next three years. Second, we have ratepayer programs that are paid through the CPUC, ratepayers like the ELRP program, which is really, again, paying incentives to drop load.

And finally, there's our non programmatic voluntary load reduction opportunities and increased generation. So this is where we work with state water project to see if they could reduce the demand on the pumping load, which could be significant for the state for a few hours. It could be the balancing areas, meaning LADWP, SMUD and CAISO, transferring energy between each other to support each other during those extreme events and such. Next slide, please. So after 2020, we have enhanced our coordination and communication even further.

These are three important coordination venues that we have today, incremental to a lot of other coordination that we do today, which is the 2022 MOU that Neil mentioned about already, which really formalizes the coordination between Chrysler, CPUC and CEC on resource planning activities. We have what is called the TED Task Force or Tracking Energy Development Task Force.

That's really a coordination effort to ensure the list of projects we have in the pipeline for the next summer are worked and tracked carefully to make sure any issues with those projects can be dealt with within the state agencies. And finally, this is something that Neil also touched on, which is the transmission development forum that we have to track the transmission projects. Apart from this, there are many other currently formal coordination pathways, including the commissioners at the highest level. Next slide.

So in summary, just wanted to leave this with all of you, which is starting 2020, we have been working really hard to improve our grid planning processes, primarily making sure that the climate change impacts are really well understood and baked into our forecasting and other issues like for example, on the reliability side, we need to understand what the heat rate of a thermal power plant could look like on a summer day when it's hot and really understanding those kind of stuff.

Second, we have to really work on both scaling the supply side solutions, but also the demand side solutions. And the agencies have jointly articulated that in our plan. Just kind of thinking through what we could do for both demand side and supply side. And finally, in the near term, especially as we look through 2030 and maybe beyond, we need to think about how are we going to get through extreme events as we plan for a clean grid.

Because as we added significant amount of resources, as both Leuwam and Neil mentioned, over the last four years, but also the decade, we've also retired almost 10 gigs of resources over the last 10 years. And that's something we are both building to fill the retirement, but also to make sure we can meet the new demand being added. So with that, thank you again, Chair, Vice Chair and the honorable Members for the opportunity to be here. And we're ready to take any questions you may have.

And thank all of you for joining us. Appreciate it. Go ahead and open it up for questions from Committee Members. Assemblymember Wood.

Thank you, Madam Chair. And thank you to the presenters here this afternoon. I, for about a year and a half, been asking some questions about how we're improving efficiency. I understand there's an MOU you're all working together. From what I hear, transmission from the stakeholder side could be seven to 12 years to complete. Maybe that's wrong, maybe it's seven to 10, but the seven number keeps coming up on pretty regular basis.

And so I've been asking pretty continuously every chance I get in a forum like this, as I framed this for the couple of questions I have here. So what are we doing to improve the efficiency? Seven years seems like an awfully long time. 12 is interminable. So I know currently CPUC has General Order 131-D, that's still open, and that's supposed to be ensuring that transmission permitting, is more efficient.

So what's the status of that proceeding and when can we expect that to close?

Thank you, Assemblymember Wood. So we opened a rulemaking for General Order 131-D pursuant to Senate Bill 529. The first decision in that proceeding actually was voted out in December of the very end of last year, our last voting meeting.

And so that's where we were able to accomplish the main requirements of Senate Bill 529 and be able to start shifting some of our transmission permitting from our longer process, which is called a Certificate of Public Convenience and Necessity to a permit to construct process.

So some of that initial work has already been improved, but we also are actually working on another staff proposal that will be coming out in Q1 of this year to undergo even larger updates to the General Order 131-D. We had some parties actually come forward with some ideas, and so we're going to be leveraging some of those ideas and putting out a ruling with a staff proposal to incorporate all of the different ideas that parties have recently come forward with.

Thank you. I've got a couple of follow ups. I'll try to be brief here. So will the CPUC implement a 270 day timeline for the Commission to review some of the environmental impact disputes through these proceedings?

At this time, I don't know if we'll adopt a 270 day timeline. I know that that was something that was adopted as part of the opt in permitting process, that specific timeline. But we will be putting out a staff proposal with a number of different opportunities there. And 270 days is a number that has come up so far among the stakeholders.

It's come up a lot with us too. Okay, so this is a little convoluted, so bear with me. And this goes back to, I just watched earlier today comments you made, Mr. Millar, in June of this last.

So, the CPUC administers the renewable portfolio standard that outlines the energy mix. And I'm going to read this so that I don't screw it up. Okay, I'm a dentist, not an electrician here, but we're trying to obviously meet the state's clean energy goals. The CPUC works with CALISO to come up with the amount, to estimate the amount of the transmission through the TPP. And then my understanding is that CALISO then has to defend that in front of the PUC. Did I misstate that, Mr. Millar?

There are changes now moving towards what's called a rebuttable presumption that came through legislation last year that would shift that for certain types of projects and subject to certain conditions. Historically, the permitting requirements were such that much of the legislation around the permitting process called for the defense of the need for a transmission project in the CPUC's permitting process. So that was still in place when I started my role at the ISO here.

So I would frequently be testifying about the need for the transmission projects in the CPUC permitting process, recognizing that part of the rationale was the resource planning conducted by the CPUC. So with a rebuttable presumption language, shifting that to the extent that a transmission project is being identified by the ISO in response to meeting the needs established through the CPUC's resource planning, that that obligation is shifting.

Now, we haven't had a major application come through since that legislation took effect, but that's our expectation now, is that that burden would be getting relaxed to the extent a project related to the CPUC's resource planning. Now, a plain old reliability requirement that really didn't drive off of that planning might be a different issue. But the policy driven transmission meeting the clean energy goal efforts and coordinated with the resource planning at the PUC, my understanding is that burden is being removed.

In 1373. It was AB 1373 that just did that.

I know that bill actually, pretty well. So it hasn't really happened yet because you don't have any new cases for you. What do you expect that to do? Because what you were telling me was happening here was really duplicative. And we know that duplication is time and money. And so what do we expect things like this to shave off of the process? Roughly?

Yeah, I can share. So when we're going through a CPCN or Certificate of Public Convenience and Necessity, we have the CEQA component of the proceeding. And then there's also a cost and need component. And so that need component is going to be significantly shaved down by being able to leverage this rebuttable presumption.

But don't you all do your own CEQA analyses on these projects as well?

We only do CEQA. CALISO does not do CEQA, so that's not being duplicated.

Okay, Gunda, final question, and I thank you, Madam Chair, for your indulgence. So I've been hearing for a couple of years now that we were going to get to five gigawatts of offshore wind by 2030. And then I heard just somebody say 4.5 gigawatts here today. And now I look at your chart and says 2032. So I'm a little surprised to find that out today. So can somebody- Five gigawatts by 2030 was the number I kept hearing. So what happened?

Obviously, there's no way we could ever get there because we don't have any existing transmission infrastructure. But how did it happen that we find out about that here today and not in some other venue?

Thank you, Assemblymember Wood. I just want to contextualize the five and 25 gigawatt goal. So in articulating the goal and avoiding that decision at the CEC, there was a clear indication that this was a planning goal that would help support our SB 100 goals. But CEC has not done a cost analysis on that. So we always kind of looked at that number as a goal that would provide clear direction for the industry to help coalesce the infrastructure development.

But we looked to CPUC for actual procurement and authorization, and that's something that CEC kind of mentioned it in its 525 report, as it's a planning goal versus a procurement target.

A couple of things here. My slide presentation here has headwinds to deployment are likely to increase, and I did not see you address this. I've looked it over. Also, part of the information on the headwinds has been available land use. And I just want to add Central California perspective on this, because there's a lot of conjecture that fallowed ag land is going to be turned into solar.

I think it's important for us to note that agriculture has been adapting to the problem that they have with water supply. So the state has said, if you pump it out, you got to put it back, but we're not getting the groundwater to put it back. The University of California Water Institute at Berkeley did an analysis. Something like a half a million acres could very well be fallowed. Billions of dollars of lost crop value as a result.

Well, the interesting thing is that there is a large group of some of the most productive and influential agriculturalists in Central California that have decided that they think that turning a lot of that fallowed ground into agave and create a California agave market. I co authored a Bill that passed a couple of years ago. I think that in reading over some of those headwinds, presumptions are fluid. Marketplaces provide options.

I think the good news about adaptation to agave is that we're going to be creating a California agave marketplace for the syrups and all of that. And these agriculturalists are right now testing large numbers of varieties to figure out what the best is. Now, that's going to be a long term project, but a lot of my friends in agriculture would much rather turn it into a California agave crop than another solar farm. They are committed to the ground, to the workers, and all of that.

Now, the interesting thing is we can't call it California tequila, because Mexico has a very firm grasp on that term. And so, a lot of our folks are kind of brainstorming about what to do about it, but it's coming. And one suggestion is that we call our tequila tecali. T-E-Q-C-A-L-I. This is serious. I have traveled extensively outside of Guadalajara to the south of plants and those areas.

Back when I was mayor, we internationalized the airport with our Mexican flights, and I got a tour of the salsa operation, and I noticed a lot of land with a lot of space with a crop on it that was harvested regularly and creating a valuable commodity.

So I think it's important to keep our eye on that, because our agriculturalists are really committed to finding a way not to fallow the ground, but to grow it in a way that doesn't use the kind of water that some of the other crops do. But I'm curious. We're trying to test run takale. You think that works? No.

And as somebody remember, if I understand, I think the larger question is that there are headwinds that are growing stronger, some of which we are well aware of, some of which.

Again, I was hoping we would get a thorough presentation. It's sitting here in my slides I have, and I was anticipating, I looked them over ahead of time. And availability of large scale ground is a problem. And there are competitive factors over long term that will have an impact on where you can build. That's question number one. I would have liked to have seen that and heard that presentation. You've got a lot of planning here.

You've got a lot of matrix, you have a lot of numbers. Have you calculated the expected price tag of all of this additional electricity on the grid? And have you tried to calculate what that is going to do to rates going forward? To me, you're building a lot of new stuff in a marketplace that is increasingly subject to inflation, and it's a moving target, obviously, over time.

But have you looked at the price tag of the acquiring, the necessity to transmit it, what that's going to cost, and then what is that going to look like on a kilowatt hour on my constituents bills?

Thank you, Vice Chair. I'll just start off with the first question and then we'll discuss the second one as well. So the first one on the land use implications, you're absolutely right. I think in the first report on SB 100, which was published in 20211 of the core kind of outputs of that report was a rough estimation of the acreage we need between 2021 and now.

The new report, given the climate change impacts and the higher electrification that we're thinking, we are looking at about 1.5 million acres of land that needs to be developed in California, both land and sea space together. How much more than that will come through in this report? But that's the number we have put out in the previous report. After 1.5 million acres, it's extremely important, as you mentioned, how are we going to get this land?

So there is land use screens modeling that is done through PUC, CEC, CalISO in coordination form. CEC kind of ultimately developed those screens, but we work with a variety of stakeholder groups to develop those. Currently, as you mentioned, depending on how you frame those screens, the amount of land that exists changes. So looking at some of the concerns that you've raised. We are deepening our analysis for the next report and we expect to put them out this summer.

The updated land use screens, specifically from the stakeholders, large solar developers have pointed to exactly what you just mentioned. The idea that land will be available is an issue. That's one. Two, having kind of an average price of that land is also an issue because that could escalate. So what we have been asked to look at in the SB 100 process is different costs and different availability of land.

So we will then have to look at, if we don't develop that much on the bulk grid, where will those resources come from? And it could potentially be on the distribution side. So we are looking at a variety of scenarios and we would love to report.

What do you mean by the distribution side?

So behind the meter solar or behind the meter storage? How does the behind the meter versus the bulk side optimize based on the cost and the ghg constraints that we have as a state?

Given the challenge of land acquisition, is there any thought or consideration whatsoever of using imminent domain?

Those conversations have percolated over the last year. We as agencies have not taken any specific direction on that one, but we are looking to some of the input that's coming from stakeholders and that's consistent. Some of the stakeholders have been pointing to either eminent domain, have talked about large federal lands as an opportunity, talked about potentially using the land that is currently hosting transmission lines and others. How do we optimize between all the land that we have, the brownfield opportunities? So we are looking at that.

You are considering imminent domain?

No, we're not. We have gotten stakeholder input and we are kind of constructing those scenarios right now and we'll bring it back. And the way it happens at the Commission is staff get all the input and staff will then explain to me.

What stakeholders are you talking about landowners presently? Are you talking about agriculture people? Who are you talking to?

Yes, primarily some of the stakeholders that we've gotten. I think the most present stakeholders in our process is really the developer community and the most of the input that we what community? Developer community. So the clean energy developer community. So we get a lot of different ideas in our dockets on these issues and I recall that has been raised in the past.

And Assemblymember Bauer Kahan, thank you.

And I'll just say that I appreciate your comments and I think we should be talking about Agrovoltaic solar, which doesn't replace farms but works with farms to reduce water consumption and produce energy while growing crops. I think it's a great thing that California should be spending more time thinking about. But moving on to the next subject, I was interested in your focus potentially on demand side production.

I feel like the policies that California has been moving has been moving away from economics that support demand side, rooftop solar battery, et cetera, in part because we don't like the way that's been funded, which I think is a fair criticism. But I am concerned that we are moving away from a potentially important source of energy when transmission is such a huge issue. And yet here you are saying that demand side may be something we really have to focus on. So I just wanted to revisit that because it was a surprising thing to hear you say.

Yeah, thank you SMB Member. I want to just make sure I uplift the coordination that happens between CEC CPUC CARB in developing the SB 100 plan along with the POUs. So what the SB 100 is trying to do is one explore a variety of scenarios under different constraints and sensitivities to figure out how can we meet our SB 100 goals.

In exploring that specifically from the POUs that have local constraints on transmission, we have heard it very clear that for some of them it might be almost impossible to bring in new transmission to develop their local reliability. And so currently we know some of the POUs are planning their SB 100 goals through irps that largely are behind the meter resources. While we do that in some areas, that might not be the same for other areas.

So what we are trying to do in our SB 100 analysis, as we discussed in a recent workshop, is look at, okay, so we need this many resources, 150,000 or 200,000 resources, depending on the updated analysis. And those resources require x amount of land. And let's assume part of that land could not be manifested. So what do we do? So the first thing we always do is look at the least cost option.

And once the least cost option is done, then we study the sensitivities on what if there is a land use constraint? What if there is a transmission constraint? How does that look? And so we would expect some of those scenarios that have land use constraints to pick up behind the meter resources.

But to your point, I think one of the struggles we have is the factual information on the wholesale market versus the cost of a community solar project versus the cost of behind the meter solar project. And those have different costs. And depending on how we study the constraints and how the public policy evolves in California, we might see different futures. And I think the least cost will always be the bulk side.

But when we think about the bulk side to Vice Chair's point, the land use constraints show up and others show up. And so the behind the meter might be picked up. And the other side, I think in kind of thinking through the demand side is demand flexibility that would have a humongous benefit. The agencies jointly adopted a 7000 megawatt goal by 2030.

And I think if we are able to reduce the demand at the time we need these ramping resources, and at times when there's grid stress, I think we could significantly impact the build out. So those will be studied as well.

Got it. I mean, I think it's important that when we think about the cost, we also think about who's bearing the brunt of that cost. Right? So it's not pure cost. It's when you have private investment in addition to public investment, there's a benefit to the taxpayers, to the ratepayers.

And so when we think of, I think some of these projects, it's really important to think about private public partnerships and how that defrays costs from the places that all of us want to defray them from, specifically the ratepayers. And then I do want to touch on while I'm on cost, because I think it is what all of our constituents are thinking about right now is the soaring rates they face.

And this is not separate from that conversation, as the Vice Chair mentioned, because when we build this infrastructure and cost money, it's going into our bills right now. And so I think it is really critical that we talk about how we are going to afford this transmission that I don't think at the end of the day we can afford, period, especially if it's going to put more burden on to ratepayers.

And so as we look at these goals, which are know, I represent the Tri Valley, which has been a hub for many wind and solar projects, the constraint. My community was always worried all of our open space would become clean energy projects. That's not possible because there isn't transmission in all of those spaces. So we have seen firsthand the constraints of building out projects based on where there is availability of interconnection and transmission, and it's real. Right.

And so I think that we need to be realistic about all of these great projects. And this was touched on by my colleague and how we are going to build that and how we're going to bear the brunt of the cost. And I don't think I see a path forward that doesn't result in even higher bills and so I guess I'm at a loss as it relates to that. If somebody wants to touch on that.

I can start, and then I know my colleagues will have things to add. So, to your point about affordability through the integrated resources planning process, we are looking for those least cost resources that are needed in order to meet the reliability requirements, as well as reducing our greenhouse gas reduction goals. Through the MOU and our interagency coordination, that work has been occurring all the way down to the bus bar level mapping level.

So looking at where are the substations on the system, where are the locations where resources are available in addition to where the load is. And so we are getting down to that granular level to understand what opportunities there are on the grid and how do we make the most of those opportunities. So we are getting down to that granular level with these resources that are the least cost. Anything else that you want to add?

Yeah, I think the hypothesis that we all have, and I think it's rooted in modeling, is if we are able to maximize the utilization of the resources we have, so all the electrons that are being generated in California could meet the load at that time, we will have a rate, downward pressure on the rates. Right now, I think we are in this path of both trying to shape the demand to the best demand shape it could have.

So, like, through rates and such, we're thinking through when should the evs charge? Broadly, some of them might charge at other times, but broadly, when do they charge? What's a good rate structure for charging and dispatching behind the meter storage and so on. So I think we are one thinking through the programs to shape the demand, we are also building resources, and different resources are coming at different paces. So, for example, solar.

Right now we have plenty of solar in the middle of the day that is not completely being used. It's either exported or some of it is curtailed. So the idea is, over time, as the clean energy resources become cheaper, which is something we've observed in both storage and solar, and to the extent that we in the future get to a place where we're maximizing the utilization of those electrons, there should be a downward pressure, and that's what we are working towards.

Well, I think we would all support downward pressure on rates on this Committee. That's a bipartisan agreement, I would assume. But I think it is really critical that I have always been a huge fan of distributed resources. I know it isn't the ultimate solution, but I think we have to have all the above solution. And I think transmission is a real limitation to our system. And so I think it has to be an important piece of this and we need to continue to think about it.

But I will say in closing, and then I'll turn it back to the chair, that where the PUC has been charged with picking the least costly alternative, I have not seen that to pan out. I think we can all see the undergrounding as an example of that, where more undergrounding was authorized and seems appropriate when there are cheaper alternatives to wildfire mitigation.

So I would just continue to urge that we think about the cost benefits and ensure that we are driving costs down, because I think we're at a breaking point.

Yes, and thank you for those comments. I would agree. And as I mentioned to our Vice Chair, I appreciate the emphasis on cost. And we do have a hearing scheduled March 5 to do no to do it. I think that is certainly the number one topic on our constituents minds and the number one issue on our minds. So we'll be doing a deep dive into all of those opportunities. Just a couple of questions before we welcome our next panel.

So I think for me, and I've shared this directly with some of you, for me, what's really missing is what I would call a clean energy deployment plan for particularly our short term goals and objectives. So, Vice Chair Gunda, as you said, long term planning and short term planning are slightly different things. When you're talking about long term planning, it's very much kind of is this theoretically possible? Could we believe that we could do x amount of this, x amount of that?

But when we're talking about the next five to 10 year horizon, particularly in a world where, as Assembly Member Wood pointed out, it's taken us seven years to get stuff connected. If we don't have a list of projects right now that are actually happening, then that's not going to be part of delivering on our 2030 goals. So that's what's really missing for me. And I guess, does that exist? And if not, can we make that exist?

Sure, I can start. So we do have that list of projects, and then in addition to that, on the year ahead basis, the transmission or the TED task force Tracking Energy Development Task Force has those projects broken up by each quarter of the year and is tracking each of those projects to come online.

So both for that end of year goal, but as well as the summer goal, some things that we've observed due to storms, weather, et cetera, projects get delayed, but eventually they do come online. By the end of last year, in the last quarter, we had 36 projects that came online, and I want to contrast that with the first quarter where none of the projects came online that were supposed to, but they eventually did.

And our teams are working directly with those developers to make sure that they come online. But we do have a list of those projects.

Okay. And what's the horizon for kind of planning at that granular level?

So for the projects that we are like handholding and helping to get online, it's a one year horizon, but we do have a broader horizon. The whole list of projects that are there. The CalISO is also studying projects by cluster. Neil can talk about that with more detail. So we do have a lot of information on these projects.

And have we identified, we've got our goals up to 2035 there. Have we identified the projects and initiatives that are actually going to deliver on those goals and those targets through 2035?

So I can start. So the load serving entities have provided proposed plans for the projects that they would like to be able to bring online. In the decision that we adopted last week, we looked at all of those proposals and came up with, these are the projects that are going to actually have to come online. So we do allow the load serving entities to have some autonomy over what projects they would like to be bringing online, what kinds of resources.

But then in the end, to make sure that we're working towards our goals, we look at the whole system and then make a final decision on that.

Yeah, I think, Chad, thank you again, I think, for drilling down on that specific question. I think we have in some locations really good data. In some locations and areas we might benefit from having better visibility. But I think on the top line that you're talking about, which is from now through 2045, do we have an implementation strategy? Right after the first SB 100 report, the joint agencies put together some high level barriers, which kind of now have been worked on through the Legislature after 2021.

In the 2025 report, the SB 100 report, there are three sections that broadly will be covered. One is our progress and identification of both best practices and barriers. Second section will talk about high level alternate strategies and scenarios on how we can reach our SB 100 goals. And the third one would be around implementation strategies.

And I think, as we think through 2045, given the long term, the detail at which we are able to show in SB 100 will then be supplemented with more detail, as Lua mentioned, in the year ahead. But we're also looking at how do we uplift all this information into a single location, and we'll continue to work on that and hopefully we can bring that back to you.

And then one related question. Who is the lead entity on what I'll call clean energy deployment?

I think the real answer would be all of us do it together. And I think I would just humbly submit that given how complicated and the different roles that we have that are overlapping, the best kind of strategy that is working for us right now is more of a matrix organization. We pull together important areas of coordination, and those important areas of coordination have a formal structure for us to track through.

So I think as a team, for example, under liability, CEC has been working as a core kind of lead on transmission planning. It'll be CalISO on kind of more the TED task force and IRP, it'll be CPUC. And so we have these lead agencies designated within those matrix roles that we have understood.

And just, I guess a couple of comments. I don't have a solution to that, but that makes me nervous. So, as I've shared with you, I've been an Assembly Member now for five years, but I come from the private sector. And in the private sector, if you're trying to do something big and hard, there's somebody in charge, right?

You need somebody who wakes up every single morning thinking like, zero my God, how are we going to get through the next year, the next month, the next day? And when things are matrixed, it's more complicated. It's no one's number one mission.

And so it feels a little bit, and even as digging into some of the ways that your agencies are coordinating and working really hard to coordinate, it feels a little bit like we are taking certain institutional constraints as a given and then trying to do a very, very hard and new thing for which your agencies actually were not created.

Rather than perhaps taking a step back and thinking through are there opportunities and a need for us to kind of restructure responsibilities to ensure clearer accountability and perhaps more certainty of delivery? So that would be one, I think, yes, suggestion or takeaway, and we can dive more into that moving forward. And I know Assembly Member Zbur has a question, and then Assembly Member Connelly, so thank you.

And I know that Assembly Member Wood has probably asked some of this. So to the extent that I'm repeating apologies, I'm actually looking at this sheet and I see offshore wind has been moved a couple of years back. And I understand you've answered that already, I guess, in terms of the planning for that, though. And I think this is sort of apropos of the Chairwoman's questions. How much have you in even setting those targets estimates, how much have you sort of gone in and looked at?

Sort of all the pieces that have to happen in order to even make that a reality in 2032? Meaning have you actually factored in the fact that we've got to actually do upgrades to our port, we've got to entitle the port infrastructure, we've got to have transmission at that point. And so I was just wondering how much of these assumptions have a sort of a detailed strategy behind them or how much of this is sort of the best we can do at this point, I guess.

Yeah. Thank you, ...just kind of, I think the 525 strategic plan has been adopted by the CEC earlier this year, and that does lay very clearly the aspects that you mentioned, which is the port development that is required, the General dollar amounts that we think is required. So I think that would be the base case for our work. And it's similarly through the shot center, but also, as Neil mentioned, through CalISO, we are studying the transmission issues as well.

So I think overall there is a strategy laid out from here to how we can make it manifest, including I think, the central procurement function that the Legislature has authorized to DWR.

And by the way, I have a lot of respect for the CEC and the other agencies here. I know that you all are very committed to sort of meeting our clean energy and what we need to do to meet the scoping plan requirements. But I share the Chairwoman's concern about someone driving a strategy and the fact that you've got sort of multiple agencies that have shared and overlapping responsibilities and about actually driving to a conclusion.

I'm really nervous about whether or not we can meet these numbers for almost all of this. And so just want to say that I share the concern there. I have one other question. I don't want to sort of, and there was the other sheet that had the. Let's see where.

I keep hearing from various folks that we need more than two to three times the amount of electricity we're producing today. Is that an accurate statement? Is that accurate with the battery storage? And sort of what is the overall electricity we're producing that includes a non-renewable. And how does that compare to the 183 megawatt figure?

Yeah, absolutely. So I think just on the demand electric demand to just starting there between 2021 and 2045, we expect it to at least double in terms of just energy consumption. In terms of the peak demand that we are going to meet, it's probably also going to be between two to three times. And we are updating the analysis right now. Currently, our clean energy, the zero carbon resources, are about 60% of the grid for today's demand. Right?

So that's like about a quarter for what we need in the future. So on our journey there, we do recognize the importance of storage of about 53,000, number that we had last time. And just on a success story, we went from 200 megawatts in 2019 to near 10,000 megawatts right now in totality. So we have about 8000 bulk storage already. So we expect that to continue to grow.

And I also want to just offer that by 2030, we could potentially have about 60 gigs of storage on the wheels. And how do we use the 60 gigs on the storage to better shape the demand is another thing that we are working on. But I hope that answers the high-level question.

I had one more question. Of this component, 183 megawatts, how much of that is assuming that clean hydrogen is part of the mix, either for peaker support or for something else?

Yes. So this particular chart. So, first on the hydrogen production side, does not include any energy for the hydrogen production. Hydrogen production in the previous study, as well as the scoping plan, has been assumed to come from off-grid resources. So that's something that we are baking in right now. I think the ballpark is about 5000, 8000 need has been identified.

We have not studied that in entirety, but this kind of particular work will do in reflecting the SB 100 plans, the first report had what we called generic resources of combustion. So we did not know hydrogen combustion would be a path at the time, in 2021. So if we look at a generic zero-carbon firm resource that we could have on the system that reduces the build-out by 20 to 30,000 megawatts right there because of the shape of it.

So moving forward for 2025 report, we are looking at both, including the demand side for hydrogen production on the power side, power sector, the transportation sector has always been included. And the second part we will be looking at is given that some of the IRPs, especially the POUs, already include the hydrogen combustion, we'll be baking that in and thinking through how to optimize the model.

Great. Thank you very much.

All right. Thank you, Assemblymember Connolly and then Assemblymember Wood. And then we'll go ahead and move on to our second panel.

Thank you, Chair. Good afternoon. Good to see you both again, all three of you. A couple of topics I wanted to start out back with customer-side alternatives and particularly rooftop solar, which is a hot topic right now under the SB 100 joint agency report summary, it identifies 12.5 gigawatts of projected new customer-side solar resources by 2030 and 28.2 gigawatts by 2045 as part of 100% clean electricity mix. How can we be confident that we're on track to deploy that 28.2 gigawatts after the drop in rooftop solar applications and layoffs in the solar industry following the NEM 3.0 decision?

Yeah, thank you. I'll just kind of set it at a very high level and welcome Leuwam, to add anything. So, in SB 100, the 2021 report, and just kind of structuring the conversation on how we go about the modeling. We understand the demand consumption first. And once we understand that, the second step we do what is called a capacity expansion.

And what it means is you have this tool where we say, here are all the candidate resources that you could pick from rooftop solar, behind-the-meter solar, sorry, community-scale solar storage, and all of them. And then we give it cost parameters and overall price reduction and stuff. And once you do that, different resources get picked up to match the least cost. And meeting the GHG emissions, when we did that in 2021 as a candidate resource, behind-the-meter solar was not picked up.

It does not get picked up just on the base of that optimization of cost. But what you see in terms of the 30,000 megawatt rough projection is based on the demand forecast we have. So let me just explain that a little bit. When we develop a demand forecast, we first take into account the overall consumption, what we expect the energy consumption should be, and then we look at how much of that would be met by efficiency load management, how much is by behind the meter solar.

And that behind-meter solar forecast comes from our best estimate based on the rate design that exists that day. So based on 2021 forecast, we had about 30,000 based on that. And for the latest forecast, those numbers have not gone down yet. So the question is two parts, right? So one is, what is the forecast? And if you optimize purely for cost, would it ever be picked up? So the second answer is no. The first answer is based on the forecast, based on the customer preferences, based on the rates that the customers might see. The deployment currently still shows 30,000. And we will be tracking that and updating it based on what we observe in the market.

May I contribute a bit to that response? I just wanted to add that some of the changes that we have made to the incentives for rooftop solar. Most importantly, the pairing with storage is in alignment with where our clean energy resource goals needs to be. We do see at net peak, a large drop off of solar on the system. And by aligning our incentives to support the addition of storage, you're going to be able to take that solar even further.

We all know that these are ratepayer incentives that do. These are incentives that are paid for by ratepayers. And our studies have shown that the cross-subsidy from customers that don't have solar to customers that do totals about $6 billion annually. So we really want to make sure that as we continue incentives like this, that we are making sure that they track with the needs of the system in order to help move our resource planning goals forward.

And Member Connolly, just want to one thing, the latest forecast. Want to just observe that the same level of solar deployment still exists in the forecast, but just want to observe that from the modeling, it has shifted from solar alone to hybrid systems to be cost-effective in the forecast. So we still observe the same levels of solar, but as hybrid systems.

Great. We'll appreciate the ongoing discussion on that final topic, resource adequacy. I apologize if it was covered already, but noticed it in the materials as the very well-written staff report notes on page seven. There have been nine changes in the resource adequacy requirement since 2020. So I guess my question is, is there a unified plan behind all the recent changes to meet California's clean energy goals? How are they being aligned?

Yeah, I can start and also have my colleagues contribute. So these are key changes that were made in response to some of the experiences we had with reliability in 2020. So, for example, historically, we were using a planning Reserve margin of 15% since the inception of the resource adequacy program back in 2005.

This is fairly an industry standard there, but we were able to move towards a new planning reserve margin, moving 16% in 2023 to 17% for 2024 to 2025, in order to be more responsive to some of these challenges that we're having on the system and able to make sure that our load serving entities are procuring enough electricity. So, as I said, as you point out, there have been a number of changes, and those have been in response to some of these reliability challenges that we've had.

Yeah, as you remember, I think just kind of observing that the previous paradigm of planning, before the intermittent resources showed up when the resources were firm and something we could always control, we've translated what is called a one in 10 loss of load expectation modeling with a simple PRM or a planning reserve margin. And we were able to do that because the resources were pretty firm and we can control.

But given the rapid penetration of solar and wind and other resources, that paradigm has to evolve and has been evolving. And I think, to Luam's point, all the steps we have been taking over the last five to six years are building towards making sure that the new planning standard really reflects the one in 10 loss of load expectation.

Assemblymember Wood.

Thank you. I'll be brief. Just kind of a follow-up, full circle. I've been asking for a year and a half. This new process of you all working together, what is that going to lead to as far as efficiency? How much are you going to shrink the process? I've never received an answer. Been asking for, like I said, a year and a half can, at some point, not today, can you come back to us and say, this new process is going to save stakeholders this amount of time?

That's going to save the entire process. And the reason I keep coming back to this is time is money, and that is reflected in the rates that consumers are paying. And right now, consumers are screaming at us about the rates, and they're going to go up. We know that. So the more efficient we can be as government to help this process along, the better it's going to be for our ratepayers.

And I don't know, there are ways we can make this more efficient, which there obviously are. I will go back to the Chair. I would agree that somebody overseeing this might make a difference. One person who everybody reports to that can say, okay, we're moving in this direction and we're going to go. That would potentially be helpful. Thank you.

And thank you, Assemblymember Wood. And I guess building on that, if we can give you one other piece of follow-up, I think in addition to cycling back with the committee regarding Assemblymember Wood's question, in terms of how much more efficient have recent changes made the process, I would really appreciate your recommendations of other opportunities for us to identify other process improvements that can accelerate timelines further. So if we can give you those two homework assignments as part of our follow-up, that would be great.

Absolutely.

Okay. With that, thank you to all three of you for participating in our hearing today. Look forward to continuing this conversation as we move forward. And with that, we'll go ahead and move to our second panel.

Thank you, Chair.

All right. Our second panel includes stakeholder perspectives on state energy planning and coordination. We will be hearing the perspective of publicly owned utilities, electric corporations, outside experts, and clean energy developers. Again, we'll ask all of our panelists to make opening statements, and then at the conclusion, we'll open it up to the committee for questions. Welcome. All right. And our second panel will begin with Randy Howard, the general manager of the Northern California Power Agency.

Good afternoon, Madam Chair and Committee Members. We'll just jump to the next slide. My name is Randy Howard. I'm the general manager at Northern California Power Agency. For those that don't know us, there's a little slide up there that just kind of shows we're really 16 member utilities, municipalities that are throughout Northern California. We serve about 700,000 customers. NCPA is a generator and assists with transmission. We currently schedule about 70 generation projects into the Cal ISO to support the needs of the members, as well.

We support three of the larger community choice aggregators and a number of water districts with their generation. Next slide, please. So looking at the agenda of the hearing, I titled this one finding focus and finding focus for me. Those were the planners and the agencies. I have the responsibility of a utility and keeping the lights on in the communities and building the systems that are necessary. So what is currently, from my perspective, our greatest liability and risk, it really comes down to wildfires and climate disasters.

They are devastating our utilities. They are impacting the affordability to our customers. And I'll touch a little bit more on that and speak to it. And so the other issue is how do we, and we come together as POU's, how do we keep the lights on for our customers in the short term, and that's really in the next couple of years, the transitional period. I think as the chair spoke to that, how are we going to get to that, that 2030?

Is there a true plan in place? And then the longer term, up through 2045, I will touch a little bit more on this, but really in that short term, we have gridlock. With the transmission interconnection we are issuing in the POU community, RFPs. We're not really receiving many proposals out there. So our focus right now is what can we build within our own communities that we control the interconnection. So Assemblymember Wood, we worked on within your water treatment facility, a floating solar.

It's an amazing project. It now serves about 8% of his community's power needs. So we're focused with our municipalities to find where do we have airport property, where do we have libraries, police departments. We now have access through federal direct pay programs to have an equivalent tax benefit, and we can build our own. So our biggest issue right now is breaking down some of those barriers that prevents us from quickly deploying those types of projects.

But that's what we see in the near term and not wait for the transmission interconnection queue at the Cal ISO. In the transition period, though, we need to break through some of that interconnection process. We need to ensure that we have the transmission projects being built to the right locations. But our concern in that transition period timeframe know we just agreed to extend the life of Diablo Canyon for another five years.

That five years is going to be up in that period of time, and we really should be talking today about the additional five years of Diablo Canyon. We're seeing biases in the market today. When we're looking at products to buy beyond the five year window, they're pricing them. Recognizing that Diablo Canyon probably won't be around. We're going to pay more today in order to buy those products.

But if we could come to an agreement and recognize the need to give us more runway, Diablo Canyon needs to be extended an additional five years beyond the five years we've agreed to. Long term, again, we have a lot of ideas in the POU communities. We're hoping to build many of our own projects, but as well, we will procure projects as necessary. The assumptions we make, you heard that from the regulators and the planning entities.

There's a lot of different issues that we have to consider in developing all of our own plans. I'm not going to go into detail, but we could certainly talk through each of those, they make the process very difficult for us. Next slide, please. This slide really just speaks to the California wildfire impacts. We continue to use a lot of our resources. That's financial, that's labor on educating our communities. Wildfire mitigation efforts to harden our facilities, to do a number of things related to prevention there.

We're actively spending money on detection and then response and recovery. It's consuming a lot of resources. We're seeing the benefits of that. But California still is having wildfires. There's been a number of national wildfires. It really reinforces the importance of that work and the effort. But we all really need to look hard at the cost impacts because this is directly impacting the cost to our ratepayers.

And going forward, the liability risk is probably our leading threat to our industry and one of the most significant impacts to those costs. And California and other states around us continue to look at new ways of doing it. But it's not just our homeowners that are unable to insure their homes. Electric utilities and the POUs are unable to insure our electric facilities and our transmission lines. POUs are not part of AB 1054. That's that wildfire liability backstop fund that's available to the investor-owned.

We have nothing equivalent at this stage and we're unable to find insurance or affordable insurance. And that gets to, as we look to invest in new transmission, we're challenged. One, because we're unable to get reasonable loans to build new assets, but we're also unable to insure those assets. So it just adds to our liability risk going forward. So if we really are interested in building a lot more transmission, we need to have something addressed here regarding some of the liability. Next slide, please.

So as the agencies were able to show the integrated resource planning efforts, this is an example of NCPA. We have an interagency. We take all of our Members together, we put together a resource plan of what would be all of their needs based on the growth forecast that we have. What are the types of resources, whether it's a wind, solar, where it should be from, geothermal or in our case, hydrogen.

And when do we need it, which year do we need it and how are we going to get there? So we've been working through this process with all of our members and you can see there again, because of the lack of interconnection queuing available, we're focused at the moment on ones that we can manage ourselves within our own service territories. But all of it does require a lot of new transmission. And the other thing that wasn't discussed, distribution upgrades.

So within our member communities, we have hundreds of millions of dollars that have to be spent on upgrading the wires to individual homes, to the businesses in our communities to accommodate all the growth that we're seeing in both the load from electrifying transportation, but electrifying the building envelopes as well. So that's competing against the same resources and dollars on the external build of transmission and renewables. Next slide.

I just wanted to take a minute and touch on hydrogen because it really wasn't discussed much on the previous panel. So NCPA owns and operates the Lodi Energy Center along the Interstate Five corridor within the City of Lodi. There's currently the upper part of that picture there shows the existing plant with the reclamation ponds, wastewater ponds for the City of Lodi. We're proposing to build out. We're part of the arches process of hydrogen hub.

So we're proposing to build out this field of electrolyzers where we'll take our excess renewables, we'll produce green hydrogen. We'll store that on the property. Next slide, please. We're fortunate at that project because we have excess water from the wastewater to utilize. We're not using potable water. We have a very active IBW workforce, and we currently have installed the turbine capable of a 45% blend with hydrogen. The project's transmission connected, and this is where we need to.

As we look at the planning cycle, we need to look at where do we have existing power plants, existing resources, and how do we repurpose those facilities because the transmission is already there. We're near the load centers. Instead of building all new facilities, how can we use that to help meet our future needs? And this project is going to be one of those projects that's going to be able to demonstrate how do we get to zero emission.

But we're going to take it from a large, large power plant and be able to use the excess curtailed renewables and produce that hydrogen. This picture also shows that across the freeway from us, we're working jointly with Pacific Gas and Electric company. They're going to build an R-D facility to look at how their system could handle hydrogen into the future. We'll provide them hydrogen. They'll be blending it. They'll be testing out various pipes and sizes. We think that will add a lot of value to.

As we know, we're going to need to use the natural gas infrastructure for some time to come. How much hydrogen can we inject within it and do that? Safely. Next slide. Just another pictorial close-up. The project is also geared to support transportation industry. We believe we'll be able to make excess hydrogen, green hydrogen, make it available for large-scale trucking along the I-5 and I-99 corridors to reduce some of the emission footprint from the heavy-duty trucking.

And then one of our members is the port of Oakland and the airport of Oakland. And we'll be producing hydrogen here to support some of the port activities down in Oakland. And last slide, please. Last slide that I just wanted to touch on. It's another effort that wasn't shared much previously, but I am part of the West-Wide Pathways Initiative. I'm on the launch committee for that, and it's an effort to see is there a way we can get to this 4egional transmission planning and sharing.

The State of California has made a number of efforts with other states around us over the last number of years. I've been part of those efforts and they've not led us forward yet. But the Cal ISO does a wonderful job in the real-time market. They're working hard on the day ahead market. But how do we get the states working together around us? Because we know that's going to lower our cost. It's going to make our process quite a lot more efficient.

So what you see before you is eight of our evaluation criteria that we're using as we look at the options to get there. But I just want to let this Committee know the effort we have is how do we keep Cal ISO as the balancing authority for California and allow it to be independent for California, but give it an opportunity to join another larger regional organization that they could become part of and do more active trading throughout the West.

They might even be the entity that would be contracted to do that work. But California would retain its control over the Cal ISO. So that's been fundamental for the group. But as you can see, we're really trying to recognize here that we need to respect the state authority for all the states that might want to participate, all the utilities that might want to participate. And I've been very impressed with the launch committee team members as we continue to work through this. And hopefully we'll be coming back to this body in the future with potentially legislation that might be needed or might not be needed, depending on the outcome of our efforts. And with that, I will close.

Thank you, Mr. Howard. Next, we'll hear from Shinjini Menon, who is the vice president of asset management and wildfire safety for Southern California Edison. Welcome.

Thank you. Hello. Chair and members of the committee, as you said. My name is Shinjini Menon. I have a slightly expanded role right now. I'm the VP of asset strategy and planning for Southern California Edison, and to put it bluntly, we think it's time to reimagine the electric system planning in California. We have had a planning process in this state that has served us well in the past, but it needs to be bolstered to meet the challenges ahead.

We must take a more integrated view, integrated across domains including generation, transmission, distribution, and local resources, and also integrated across objectives including affordability, reliability, load growth, and climate adaptation. As these are interrelated at the transmission level. California has begun to enhance its system planning, as the panel before was talking about through increased collaboration around zonal planning among Cal ISO, CPUC, and CEC.

State agencies and system operators should build on these efforts by instituting Cal ISO interconnection reforms that prioritize generator applications, demonstrating commercial readiness. Neil touched on this, generation interconnection challenges have increased as more large-scale solar, wind, and storage developments via to connect to bulk electric facilities. The volume of interconnection applications has more than tripled in recent years. Having a commercial viability screen upfront reduces unnecessary efforts for already constrained resources and reduces time to interconnect viable projects.

State agencies should also expand upon interagency zonal planning efforts to match clean generation development in geographic areas with existing or planned transmission capacity. This will simplify interconnection and transmission upgrade studies and promote timely transmission buildout. As my fellow panelists mentioned, California should look beyond Cal ISO's borders and plan more closely with neighboring states. The creation of a regional transmission organization would give all participating western regions access to an expanded set of clean resources to serve power needs during extreme weather or grid-constrained events.

Regionalization would also create a larger, more efficient market that would unlock additional affordable sources of electricity. I would also like to talk a little bit about the distribution level. Load growth is accelerating faster than it has in decades. The residential and commercial development ongoing in the Inland Empire in Southern California is just one example. Though Senate Bill 410 provides a pathway to supplement CEC's IEPR forecast with known load and undertaking distribution upgrades, by the time load is known, it is often too late.

For example, housing developments have tentative plans ready 18 months ahead of wanting to energize. That is not sufficient time for utilities to run load analysis, develop solutions, design, permit, and build infrastructure, and often certain areas are so congested they are triggering high voltage upgrades, which we all know has much longer lead times. We need to broaden the definition of what constitutes known load and build proactively so that the infrastructure is ready by the time final requests come from customers.

We are all trying to balance building too much too early and too little too late. But if we agree on the endpoint 5, 10, or 20 years out, we know that capacity is not going to go to waste. In fact, it'll spur necessary electrification and economic growth. Instead of being a potential barrier, we also need to deploy new technologies and utilize distributed energy resources in different ways that will increase the utilization of existing infrastructure, manage load by reducing and shifting usage, and upgrade the grid in ways that helps us build faster and cheaper. Grid-enhancing technologies are just one example. In the transmission domain, there are many more for distribution facilities. Some of these technologies are not mature yet, and innovative partnerships are necessary to accelerate technology development and deployment.

So what are we doing? I'll speak for Southern California Edison. Here we are diligently refining load forecasts that align with carp's policies and the state's goals, and we regularly collaborate with the CEC on this. We are actively working with customer groups such as the Building Industry Association, fleet owners, and charging facility developers to compile better long-term forecasts on when, where, and how much load is expected.

We are developing a roadmap for re-architecting the grid with new configurations and technologies so that we can deploy innovative, integrated solutions that mitigate capacity, reliability, and resilience risk. And the objective is to move faster and reduce overall costs. We are also looking at creative bridge solutions that can help us tide over the immediate needs, even if partially till the long-term solutions can be put in place. In addressing our common adversary, namely the climate crisis, time is of the essence, as is affordability.

We collectively have a lot of work to do and if we stay on the current path, even if we had infinite labor, resources, and money, which we do not, we will not be able to deploy all the necessary updates in time. I will return to the theme I started with. A holistic, system-wide view of planning across domains and objectives is needed to optimize investments and improve efficiency. I want to end on affordability.

Solutions for achieving a net zero economy in California will be durable only if they are affordable, and no Californian is left behind in realizing the benefits of decarbonization and electrification. It is critical that we are clear-eyed on what is needed. Transformational investments in electrical infrastructure upgrades are necessary to meet the state's clean energy goals that are the law of the land now. However, with proactive integrated planning we can reduce the costs of necessary buildout.

We can also ensure that these investments create significant economic development in our communities in addition to reducing air pollution and addressing climate risks. While additional electricity usage will increase electric bills, savings from reduced or eliminated fossil fuel expenses will more than offset that increase for households that adopt electrified technologies. Relative to what an SCE household pays today, combined energy expenses decreases by about 40% by 2045, and an average household is expected to see more than 10% savings by early 2030s. So I'll end with with holistic and careful planning, we can design an electric system that meets the legislative goals of carbon neutrality, and with careful planning, we can also do it affordably. And I look forward to your questions. Thank you.

Thank you so much, Ms. Menon. And next, we are turning to our screen. We'll hear from Michael Colvin, who's the director of the California Energy Program for the Environmental Defense Fund and one of the authors of the joint 2022 report by EDF and the Clean Air Task Force called Growing the Grid, a plan to accelerate California's clean energy transition. Welcome.

Thank you so much for having me. And first off, just wanted to thank you for allowing me to participate remotely. This was an unavoidable delay. I would much rather be in the room. So very glad to be able to do this remotely. Thank you for you and your team for letting that happen. I have a few slides that I wanted to share, and I also wanted to to address some of the comments that were made on the first panel and on some of the others as well. So if you'll indulge me, I will share some slides and then at the end of my presentation, just do one or two editorial comments as well. So with that, I'm going to do my best to share my screen remotely. Thank.

Hopefully, you all are seeing this.

Yes, we are. Success.

Great. Fantastic. Thank you so much. As Vice Chair Gunda alluded to, so I'm not going to go over these numbers in too much detail. But our clean energy agenda does require unprecedented action. While I think the first panel spoke really well about the goals, the report that the Chair mentioned that we did in partnership with Clean Air Task Force was really about implementation.

And when we talk about the need to try and grow the grid in three to four times in the next 20 years, we are talking about a certain amount that has to be built every single year. And the adage that I think the Chair was referring to is you can't manage what you don't measure, and we're not measuring in a very systematic way right now.

And so when we say that transmission capacity needs to triple, I think one of the things to take home from all of this is we can do this affordably, and we can do this reliably, and we can do it fast. But in order to do something fast, and affordable, and reliably, we need to coordinate, and we need to coordinate better than what we're doing right now.

And so there are some headwinds that are out there that we need to be aware of as we're trying to figure out how to do this management better. As with any type of deployment, you try and do the easy things first. And so right now, we are at this inflection point of we have done some real successes of we've had the access to good project sites, we've been able to take advantage of falling hardware costs. We have had some easy access to transmission and some public support.

But over time, that's going to change where there's going to be increasing and competing demands for land, agave notwithstanding, there's going to be lots of different needs for land out there. We have to figure out what is appropriate for transmission, what is appropriate for land development, what's appropriate for lots of other things that are out there. And we're going to have less access to transmission. We're going to have less access to landowners who say, yes, I'm willing to do this.

And we're already seeing increasing local ordinances out there saying, well, I don't want solar or I don't want wind or I don't want this. I have a preferred solution as well. Things are just going to become more complicated. In addition, Ms. Tesfai from the PUC started talking about the transmission development timeline and the TED task force that's out there. She sort of alluded to, there's a lot of handholding that's required. But even with the handholding, transmission development just takes longer than we anticipate.

And this is a slide that we put together to say the online dates of when we think something is going to come online and when it actually comes online takes longer than you think, and those timelines tend to slip. And so you really do need, not a plan for a plan sake, but a deployment plan to be able to point to, to say, if you take three more months, what are the secondary effects that are going to happen?

And this is a chart that really kind of keeps me up at night because I want to think through how do we make certain that the trains are running on time. The last thing in terms of problems, then I want to talk about solutions. But the last things in terms of problems standing on the shoulder of some of the work that the Nature Conservancy has done as well. Not all suitable land is actually going to be able to be developed.

There's going to be lots of competing interests that are out there. So we have some land that has been identified for certain reasons. And then when you actually kind of go into it and realize, okay, can we actually do this? It gets a lot harder.

One of the things that I'd like to commend from the ISO's 20 year outlook is that it's really trying to say, no, this is what we think it's going to take, now how do we integrate the land use that's going to be required and really start doing, not picking winners in terms of actual individual projects, but saying, we are going to need something in this area for this resource. Now let's go ahead and develop.

And it's really trying to address this potentially suitable versus practically developable conundrum. Vice Chair Gunda sort of led to this, and I think he had his part trying to go through it. The Chair sort of identified this need already of who is the lead, who's responsible. And it's a little bit like the Spider Man meme of everybody's pointing to each other. There's a lot of great work happening out there. I really like all of the efforts that are happening.

I have so much respect for each of the individual organizations, but there is no one entity right now that is saying, yes, we are on time or no, we all need to take three more months for this really legitimate reason. And it's sort of done by committee and there's no one entity that is out there. So I briefly wanted to go through a few recommendations to try and address how we could go through and make some of this better.

The first is develop a deployment plan, and that says, here's the quantity, the time, the locations that are out there. We're starting to leap towards this in some of our planning, but I think more can be done. The second, as the Chair sort of recognized in some of her questions during panel one, is there is no one lead agency that is out there that might be appropriate to have happen.

One of the things that we did when we interviewed several dozen different developers was that they said they needed to know where they were in the queue. They needed to know where they were. Is their project part of dispatch or not? The task forces that are out there was alluded to by the PUC I think are helpful, but they are not particularly public. It's really hard to be able to see. Here's what it's going to take to actually track progress.

And last, but certainly not on this slide that I wanted to highlight, was the need to be able to engage the public early and often is extremely important. So that way you don't get through the end of a planning process before you get to a local community. And they say, oh, we're not interested in this, we're really interested in something else instead. And having to kind of go back to the beginning, trying to avoid that tabula rasa is really critical.

That was the end of my prepared slides. I did, if you'll indulge me, wanted to take just one moment to address just a couple of things that have been mentioned already. The first is, as Mr. Howard referenced, there is a regional effort that is happening out there to try and figure out how can we help better connect California and the rest of the western states. That process is ongoing. There is a launch committee that's out there. I'm on that launch committee as well.

So if there are any questions that the panel has today, I'm happy to try and address that. But in order to help contain generation and transmission costs, a regional grid is one very viable option. It's not the only option, but it is something that every study out there that says this is a really important way to help contain cost overall. There was also a question that was just asked on resource adequacy.

The PUC just adopted a new standard for a one in 10 expected loss of load. But that is for integrated resource planning. And the way that we count that does not necessarily translate to how we count same things in resource adequacy. I also note that the same GHG goals that we have really tried to integrate into the IRP don't exist in RA's context. And so I think there's a lot of scenes in between those two topics.

A lot of parties submitted comments and asked for there to be a joint workshop last year, and we're still waiting for a new staff proposal, and that's something that I think that could help. The last comment was asked on transmission permitting, and quite frankly, I think we have been making some progress. There's more to go. 22 different parties submitted a joint settlement agreement at the end of last year. And as Ms. Tesfai sort of said, oh, well, we're working on a staff proposal.

She didn't mention that there was a settlement agreement sort of pending to try to help kickstart some of these things. The Cal Advocates Office also just submitted another proposal last week that was really focusing on just this cohort of projects. I think there's a lot more that can be done to help streamline permitting. There are some ideas that are sitting before the PUC, and I'm hoping that there's going to be some prompt action there. With that, I look forward to the questions that the Members may have at the end of the panel. And thank you so much for letting me address you all today remotely.

Thank you, Mr. Colvin. Really glad to have you join us. And I know there's questions, but we will hear from our last panelist before we jump to those. So our last but certainly not least panelist is Scott Farris, who is joining us from EDP Renewables. Thanks.

Chair Petrie-Norris and other distinguished Members of the Committee, thank you very much for the opportunity to testify today, and thank you for hanging in there to the bitter end. I appreciate it. My name is Scott Farris, and I am the Director of State Government Relations for EDP Renewables, one of the world's largest renewable power developers. We develop on and offshore wind, distributive generation, utility scale solar battery storage, and hydrogen related projects.

In conjunction with our joint venture partner, ENGIE through the joint venture called Ocean Winds, we are one of the leaseholders developing offshore wind off Morro Bay. In addition to our multiple California projects already in operation or under construction, EDPR has plans to develop an additional five gigawatts of large scale solar and storage here in the Golden State over the next two to seven years. So we have a very ambitious aspirations because we believe California is a great place to do business.

I want to make the point that the independent power producers are critical. I was going to say exclusively tasked, but Randy reminded me that we're only primarily responsible, for developing, planning, permitting, and constructing the new clean energy projects going to get California to its clean energy targets. Second, I want to say I think this hearing is a wonderful sign that policymakers now grasp, and I think some have always.

But it's really coming into focus, the enormity of the scale of development that you have endorsed by passing SB 100 back in 2018. When we hear that on a particularly temperate day in April, the state's power needs were met almost exclusively with carbon free generation, it can mislead us into believing that our goal is close at hand. But it is not. Achieving that goal will require bringing on, as you already heard, 150 gigawatts of new power online by 2045, according to the state's SB 100 analysis.

And that is an astonishing amount of development, equivalent to building roughly 70 new Diablo Canyon nuclear plants in terms of energy output. Now, one purpose of this hearing is to ensure our policies are aligned with that buildout, and that it will entail a lot of roll up your sleeves, just plain hard grunt work.

It is said personnel is policy, and we are fortunate that the leadership and staffs of the PUC, CEC and CalISO, in addition to CARB, seem to understand the challenges before us and have demonstrated a high level of collegiality among themselves, which I think is far more important than restructuring flowcharts or reporting lines. We are especially pleased by the creation of the Multiagency Energy Development Task Force.

EDPR is scheduled to meet with the task force on March 5 to outline our ambitious development portfolio and to identify the challenges that could impede the development of that portfolio. Often the development process is stymied when various public entities are not in sync, and to have a place to go that can help untangle these situations should be immensely helpful.

Now, this is not to say there are still no gaps to fill between the agencies, as my first slide addresses, and I think you've already seen this slide, the CEC and PUC, for example, are not in sync in planning for diverse resources like offshore wind. In response to legislative direction from AB 525, the CEC adopted a planning target of up to 25 gigawatts of offshore wind by 2045.

But the PUC's most recent integrated resource planning decision, which is where the rubber meets the road in providing direction to the state's load serving entities and CalISO, is planning for only four and a half gigawatts. As it already been noted, these kind of mixed signals by the state stymy the long term investments required to launch an industry like floating offshore wind, and they raise questions about the value of the state's various planning efforts if they don't equate and translate into positive policy outcomes.

From EDPR's perspective, the two challenges that will determine whether California reaches its goals to us are transmission and siting and permitting. As the second slide notes, while the state has improved its long term transmission planning, as reflected in the snapshot from the CalISO's 1st 20 year outlook on the left, the length of time to plan, permit, and construct a transmission project has grown unconscionably long.

I believe that was a word Assembly Member Wood already used. Nearly a dozen years on average, for projects requiring a certificate of public necessity and convenience, and more than a decade for projects that only require a permit to construct. Worse, for many projects, the completion date is indefinite and even fluid. Now, there are many transmission related issues facing California, from interconnection queue reform to whether California should be part of a regional transmission operator, which has also been discussed and which we would endorse.

But I want to focus and bring light on one of the issue of transmission providers, primarily our IOUs, completing critical network upgrades in a timely manner. Now, I am speaking here of comparatively small projects, not interstate transmission lines, but things like expanding a substation or adding wires to existing transmission rights of way. Now, I want to emphasize that I am not here to cast blame.

Our industry appreciates the many challenges and stressing facing the IOUs, and we understand they have many competing and critical priorities, most notably wildfire risk mitigation. So we want to work with our friends in the IOUs to find a solution to the backlog of projects, some of which received CalISO and PUC approval a decade ago, which would have still not been completed.

A recent example, we have a 200 megawatt solar plus 100 megawatt storage project in the Central Valley that we had hoped to have operational in 2026 or 2027, because that is when we were told a local substation upgrade necessary to the project would be completed. The utility contacted us in December to say the substation upgrade would now not be completed until 2029 or perhaps 2030. Now, regularly when these delays occur, we are not given a reason why, nor do we have any avenue to appeal.

But in this instance, the transmission provider did note that the financial and personnel constraints were a factor, as was the fact that a circuit breaker necessary for the upgrade had been ordered but would not be delivered for 50 months, four years, two months.

This example may spur a variety of ideas in your head already, such as whether utilities need access to alternative financing, whether third parties should be allowed to do these upgrades, and whether the state can leverage its buying power to mitigate supply chain challenges like the one I mentioned.

But the first step I would urge this Committee to take is to hold additional information and oversight hearings on this very topic so that there is a better sense of the root causes and scope of this problem because this is an issue that demands more transparency and accountability. Regarding siting and permitting, we are fortunate that most Californians see the benefits of allowing renewable energy projects to be sited in their communities.

But I can say this with certitude, there are no more easy places, and I put that in quotation marks, to develop. Given the scope of development required, renewable power development will increasingly bump up against other land use priorities. This brings me to my third and final slide, which underscores the dilemma. Now the proposed Chumash National Marine Sanctuary and Chuckwalla National Monument are both worthy ideas, and proponents of both have said they wish to accommodate renewable power development.

However, the enthusiasm to advance these ideas led state and other officials to endorse early conceptions of each so that we are now scrambling, in the case of Chumash, to secure a rule change that would allow a quarter for the cables that are necessary to bring the power generated by following offshore turbines to shore. And in the case of Chuckwalla, state officials embraced the proposal without first consulting the clean energy industry to see if the proposed boundaries would accommodate planned solar development and associated transmission.

Such conflicts and land use priorities are why I am regularly asked whether we can achieve California's 100% goals with just rooftop solar, including covering every parking lot in the state with solar panels, too. The answer, sadly, is no. Distributive generation, which EDPR does, and so which we advocate, will play a critical role in achieving the clean energy goals, but can probably ultimately account for only about one third of the solution. I can go into details about that later if you'd like.

The rest will come from repowered wind farms already in California, offshore wind, utility scale storage and solar that we're trying to do now, and renewable power traded for California can be both an energy exporter as well as importer, with other western states, blue and red alike, who have also aggressively embraced clean energy development. We want to develop projects where we are wanted.

The groundwater crisis has led farmers to take tens of thousands of acres out of production in California, which the Vice Chair noted before he left. These farmers would probably love a drought resistant crop like solar panels. Our industry could use help identifying these lands. While changes in the Williamson Act, for example, could make such a switch in land use more desirable.

The industry also needs to do more to increase the appeal of our projects with community investment and more imaginative habitat restoration, including agrivoltaics, which was mentioned earlier, and ag friendly wildlife development like pollinators. Since transmission is key, we must also plan to get transmission to where the public wants development, which could also reduce congestion at current access points. This all brings me to my final point.

County planning offices are already seeing an unprecedented number of permit applications from solar developers, as well as housing developers and infrastructure of all types. Those that aren't already overwhelmed by this new deluge will soon be. Timeline certainty is a top priority for any business, including us. We cannot afford extended project delays as a company, and the fight against climate change cannot afford delay either.

AB 205 recognized the problem by offering a state permitting option through the CEC, but we, candidly, we would prefer to permit through the counties because that helps provide the social license necessary to successfully operate in any community. I encourage this Committee also to devote some additional attention to how the state and developers like ourselves can ensure counties have the resources to ensure an efficient permitting process that will eliminate delays as much as possible. And with that, I just want to thank you for the opportunity to speak to you today, and thank you again for staying to the bitter end, and I look forward to your questions.

Well, thank you, Mr. Farris. And to all of our panelists, you have given us a ton to think about and digest. I'll first open it up to questions from Committee Members. Go for it.

Thank you. And I apologize that I had to step out and miss part of a presentation, but I'm curious your perspective. Obviously, there's a huge amount of time. The chart you showed there isn't a surprise about how long it takes to actually permit and then build out. And you may not be able to answer this, and you may not be the right people to answer this, but adding capacity to existing transmission, how long does that take and what does that process look like?

I've heard that it's just as onerous as new transmission and takes just as much time because of all the permitting you've got to go through and CEQA analysis on top of when you're already using existing infrastructure. Can anybody answer that? Or maybe I'm barking at the wrong people.

Certainly, I can take a stab at it. From my experience, it takes a little less time, but not a lot less time, and it depends on where the rights of way go through and some of the issues. But it's not as simple as just putting a bigger size conductor. In many cases, you might have to redesign the towers and a lot of the infrastructure associated with it. You might need a CEQA. Well, you're going to need a CEQA, but you might need a NEPA as well if you're going through federal lands.

We're finding just the challenges of wildfire hardening on our rights of way through federal lands right now can take years. We want to go in and say we're going to put in metal poles instead of wood poles to make it more resilient. We're going to put covered conductor. It's not as simple as you would think it would be to do even those types of measures because you could go in and be disturbing a particular area, and they're going to have you go through all the similar studies as if you're building new.

I'll just add that there are technologies out there of advanced conductors, and so Edison in the last decade or so have deployed about 500 miles of that. So they're called high temperature, low sag conductors. So they are not heavier than the current conductor. So you can actually reconductor without having to reengineer the structures that are holding them up. And the capacity is much higher. They don't sag as much. So you can stay with the current heights. So those are things that are being worked on as we speak to speed up deployment without having to go through the entire permitting process again.

And I just wanted to add, and this can get so confusing because there's so many layers to the transmission issue. So everything my colleagues said is true, but also my point I was raising, there are some projects that have actually already been approved and have been largely permitted that are still not getting built because the utilities have other issues that are straining their resources. They are heavily stressed. And so again, we don't want to lose sight of that issue as well.

I apologies for stepping on. I think there is, from a logical perspective here, new lines that are an expansion, an extension, an upgrade or modification do not need the same level of CEQA review and permitting review that a brand new line does. And the Legislature actually gave guidance to that effect last year, and we're trying to implement that now.

I also want to just note that certain new technologies on the distribution side and on some stuff on transmission, grid enhancing technologies, actually can be implemented relatively quickly and actually don't need the level of CEQA and permitting review that some folks would normally think. And so there's a lot of ways of doing stuff in terms of those enhancements that could really help. I think we just need to approach it on a situation by situation basis.

The one observation that I would make is we need to do two things at the same time. Really expand our existing system to the fullest extent that we can, and at the same time do new development. And one is not the same process as the other. And so, as long as we acknowledge what world we're in, we should be able to do both.

Thank you.

Assembly Member Connolly.

Thanks. Question for SoCal Edison and Ms. Menon. As you're hearing throughout this hearing, one of the big issues we're frankly hearing about every day now is the high rates that our constituents are facing from the utilities. And one of the stated reasons is wildfire mitigation. So I guess my question is, do certain methods for wildfire mitigation involve a financial rate of return for the utility, while other methods don't? For example, undergrounding, which appears to be very costly. If so, how does this influence decision making when designing a wildfire mitigation strategy?

So I'll say a couple of things. One is we operate under what is authorized rate of return by what the PUC authorizes for us. And I am not an expert in the financial rate of return aspects. However, I can speak more on the engineering side. For Edison, the cost aspect is very important. That's one of the big reasons why, for wildfire mitigation, our approach, which makes sense for our service area, has been more of deploying covered conductor instead of undergrounding.

Undergrounding is necessary in some severe risk areas. But though covered conductor does not reduce risk at the same level as undergrounding does, it's significantly cheaper and can be deployed faster. And we put in other mitigations in place to supplement the covered conductor so that we get the same level of risk reduction. So I can speak from that level how what we are doing to directly address affordability.

Yeah, and perhaps, let me ask it more directly, because I think you're responding. Is anything being done to ensure that best fit, cost effective approaches are being used, rather than methods to maximize shareholder return for the utilities?

Well, again, I can speak from my perspective and the work that my department does, we are not looking at shareholder return. That's not part of the equation. We are looking at how much risk can we buy down at what cost and what's that efficient frontier. So that's what we look at, and that's what our leadership looks at, is how do we reduce the risk to our communities at the least possible cost.

Thanks.

Okay, so I want to. Mr. Howard, pick up on something that you said, which concerns me. I think you said that there is such gridlock right now with the interconnection queue, that essentially you're figuring out ways to not have to even engage with that. Our previous panelist, Mr. Millar, spoke about some of the reforms that have been undertaken. Obviously, that's not adequate. And I know, Ms. Menon, you had made a suggestion about a viability screen. What are some other, I guess, recommendations that are top of mind for you or, Mr. Colvin, for you, to help break that gridlock?

I'll jump in first. The CalISO is walking through a number of processes to try to break that gridlock and to address it going forward. We're very active in those proceedings. What I was really saying is, in this interim period, while we're unable to move forward, while they're working through that with the stakeholder groups, we're just moving to a focus of what can we control, where can we do new projects, expansions, and interconnect within our communities without requiring CalISO interconnection approval or authority.

And so that's just the focus of POU communities at this point, trying to take advantage of federal tax incentives while they're available, with the concern that we might potentially lose those in a few years. So, wanting to optimize that value. But we do believe the reforms that are occurring will get us to a better place. It's just a process to walk through.

Understood. And you had suggested viability screen. Any other recommendations or suggestions?

I think I'll go back to those two. One is basically, if a project is they get in the queue, and then they're not commercially viable towards the end. That's what we're talking about. And the other part is, I think where you were talking about, Mr. Howard, is just the development. If we can plan in such a way together so that the generation development is coming where we already have transmission capacity, or where transmission capacity can be built faster, that just speeds up.

And we have done this in the past. Edison had a large project several years ago, building the lines for Tehachapi. Once we build the lines, it just boosts the growth of generators, and the connection is so much faster. And we're just asking that taking those examples from the past and replicating them or speeding them up is where we really need to go as far as the generation interconnections are concerned.

Understood. Thank you. All right. And one other question. So again, Mr. Howard, you, in your opening comments, said that we should be talking about another Diablo Canyon extension now. You also made the point that one of the reasons that we need to talk about it now, rather than in five years time, is that you're now buying energy at a premium because the market is counting on the fact that that energy is not going to be available and that prices are going to go up? I guess, can you say a little bit more about that? And I would be interested in reactions from other panelists on that particular point.

One of the procurement requirements that we have in order to qualify within our renewables is we have to buy products that are 10 years or longer in many cases. And that's a piece of legislation that we're obligated to put into our plan. And so when you look at right now buying some 10 year products, we have five years where Diablo is on and five years where Diablo potentially is shut down.

And we're seeing the curves, the futures on those curves reflective of the uncertainty as to whether that will be a resource available to the state at that time. And are we doing enough to replace that? And will there be sufficient supplies? So we're going to pay a premium today in that first five years with a recognition that there's unknown in the last five. So having the certainty for our market right now would impact, I believe, the rates that our rate payers are paying today with that recognition.

Would anyone else like to comment? All right, seeing and hearing none. As I said, I want to thank all of you. And Mr. Colvin, thank you so much for joining us and for reviewing these recommendations. Thank you for all of you for joining us and for your recommendations. I sort of wish we'd done this panel in parallel with our agencies so that we could hear their real time reactions to some of these recommendations.

But as follow up, what we'll be doing is following up with our agencies and understanding their reactions to these recommendations and whether or not there are changes that we need to and can make. So appreciate you for surfacing these. And Mr. Wood.

I'm sorry.

No problem.

I guess going back to a year and a half ago when we had discussions about Diablo Canyon and extending the life of Diablo Canyon, the premise was that we're going to have this huge challenge with getting our green energy online quickly enough because of all the things we've been talking about here today...

Kind of a loaded question, what confidence do you have that we're on the right track? How much, in five years, are we going to be making the kind of progress that's going to allow us? We must not necessarily be if you're already talking about the idea that we should have extended Diablo maybe 10 years. So, realistically, where do you see us now? Actually, in three, we're a year and a half shorter than we've had that discussion.

I'll give you my perspective. My perspective is if everything was static, I think we're doing enormous strides in achieving additional renewable growth, in storage, and all these efforts. But it's not static. We're chasing after a growing load and it's growing very fast for us. So we're seeing, in some of our territories, 8% per year growth. So we have to meet that growth in addition to transitioning our existing fleet of resources to a renewable resource. So we're doing multiple things at the same time.

That's why if we did not need to worry right now about the replacement of Diablo in this next five year period and can focus on our growth efforts, I think we temper some of the cost affordability issues that we're seeing hitting us right now. That's from my perspective.

I would just add, I mean, we heard earlier from the CalISO, almost eight gigawatts was brought online last year. Seven or eight, whatever it was, which is unprecedented. I mean, typically, California has only historically done one or two gigawatts of clean power per year. The supply chain issue in the wake of the pandemic and international relations and all that thing set the industry back a bit.

But as I mentioned, EDPR is just one of a dozen to 20 developers, and we have five gigawatts of clean power we'd love to have online by 2030, in addition to what the gigawatt or so we're constructing right now. So the projects are out there. There are these impediments, transmission, permitting, procurement, which I think is going pretty well, but we still need people to buy the power. So right now, at this moment, you would say the line doesn't get us quite to the goal by 2030.

But I think there's some reason for optimism, if we can address some of these questions pretty quickly. But I do think there needs to be a real sense of urgency, or we are sort of maybe looking at some things we just assume not do.

Thank you. And I'm going to just pick up on that as kind of my closing comment. So I would absolutely agree that there needs to be a real sense of urgency. And I think, as I opened with, this is a pivotal moment. We need to make decisions, we need to address these challenges now, or we're just not going to get there.

And so I appreciate all of you being part of today's hearing, and more importantly, I think being part of our ongoing effort to address these challenges and ensure that we actually do deliver a clean energy future for California, that is, as I said, sustainable, reliable, and affordable. We'll definitely be, as I said, picking up on a number of these themes in subsequent hearings. It's not March 5.

March 6 is our hearing on affordability, and then we'll also be having a hearing to dig into opportunities around permitting reform. So, again, thank you for joining us. And before we wrap up, we now will go ahead and open it up for public comment. Let's see. So thank you to everyone who stuck around and made it, as someone said, to the bitter end. Line up at the direction of the Assembly Sergeants and state your name and organization.

Good afternoon. Not quite the evening, Madam Chair. Alex Jackson with the American Clean Power Association. We're a trade group representing utility scale developers. I want to commend this hearing and the focus on really moving from our important planning efforts, which we have made a lot of progress, to a focus on deployment. I think you hit it exactly right, Madam Chair.

And I just want to plus one 3 areas where we still see a bit of a gap between what we're planning for long term and what we're actually achieving. So transmission is critical. It is the number one roadblock to utility scale development across technologies. We need to both streamline new approvals, and I encourage this Committee to keep an eye on the 131 D proceeding as phase two kicks up and address the backlog to already approved network upgrades.

We need a better sense of why these projects are getting delayed, more accountability, and some better tools for the utilities to execute on them. Second, on resource planning and planning for the diverse portfolio the state needs to meet reliability. I think we saw that there's still a disconnect between some of the policy signal coming from the Legislature and the CEC and how that's actually translating into the IRP, where decisions really matter. And I think we're concerned.

There's a sense that California is kind of a passive observer for how offshore wind is going to develop on the Pacific Coast. It's really the decisions California makes that can influence those timelines. And then just last on land use considerations. Our 30 by 30 goals are not incompatible with SB 100, but they do need to be considered holistically. It's very difficult when they're done in silos. Thank you.

Well, thank you.

Thank you, Chair. Members, appreciate it. I'm Derek Chernow with the Coalition for Community Solar Access, and I just wanted to mention that mid and long term utility scale planning is absolutely critical. However, it is also important to highlight how community solar, colocated with energy storage, plays a pivotal role in complementing these large scale projects to enhance midterm reliability. By storing excess energy during peak production periods, these systems ensure a stable and reliable supply of electricity.

Furthermore, colocated storage and community solar projects enables a more efficient use of our energy infrastructure, bringing clean energy production close to where it is consumed, minimizing losses, and enhancing the overall efficiency to our electricity system. As a recent NREL study found, California has a technical potential for over 60 gigawatts of community solar, which supports household savings on utility bills, expands low income access, increase more equitable workforce development.

By fostering local energy reliability and providing communities with direct access to the benefits of renewable energy, community solar will encourage broader public support for our clean energy transition. It's a strategy that not only complements utility scale projects, but also aligns with our goals for energy affordability, especially for renters and low income households. We are hopeful the CPUC will adopt a proposal before them, supported by a wide range of stakeholders, to establish a viable and scalable program. Thank you.

And thank you. All right, so with that, we have reached the end of today's agenda. As I said, we will be reconvening. We're reconvening tomorrow for a hearing on electric vehicle infrastructure in partnership with the Select Committee on Electric Vehicles. And then on March 6, we will be digging into cost and affordability. So thank you again to all of our panelists for your participation and to Committee Members. With that, we are adjourned. I almost closed without...