Assembly Standing Committee on Utilities and Energy

Okay. Good morning. Take two. Good morning, everyone. I am calling to order today's hearing of the Assembly Committee on Utilities and Energy. We are here today for a double header. First, we will have an update from California's statewide energy organizations.

And second, we will also be conducting an oversight hearing via the newly initiated Assembly Outcomes review process of AB 2316. And we'll be welcoming Assemblymember Ward for that portion of our hearing. So before we begin, I have some brief housekeeping announcements. Public comment is welcome here in person. Otherwise, it should be submitted online via the Committee website.

And second, as is customary, we will not accept disruptive behavior and will apply Assembly rules if in order to maintain order and run a fair hearing. So with that, today's hearing fulfills a statutory obligation. State law requires the leadership of California's energy entities to appear before the Legislature and report on their activities.

But this hearing is much more than a compliance exercise. We are at a consequential moment for energy policy in the state of California. The Newsom Administration is in its final year. Federal energy policy is, to put it mildly, in flux. Utility bills remain stubbornly high, and wildfires continue to threaten lives and infrastructure all across the state.

California is making long term decisions about resource procurement, grid expansion and decarbonization that will shape California's energy future for decades to come. Today, we will welcome the principals of California's five institutions that collectively are responsible for shaping that future.

The California Public Utilities Commission, the Public Advocates Office, the California Independent System Operator, the Office of Energy Infrastructure Safety, and the California Energy Commission.

We have a lot of ground to cover this morning, and we have a hard stop at 1pm So I want to also note before we get started for Members on the dais, that the Committee does have dedicated oversight hearings in the coming months planned on customer energy efficiency programs, on the petroleum market, on grid reliability, and wildfire funding.

So we will be doing a deep dive on all of those issues in the coming months. And I want to thank each of the principals for appearing today and for the work that you do on behalf of California and California families. So with that, we'll go ahead and begin.

And I'd love to welcome all of our panelists to join us at the dais. We are being joined by CPUC President Alice Reynolds, by CEC Chair David Hochschild, by the President of the California Independent System Operator, Elliot Mainzer. Who else? Let's see, okay.

By Joe Ito, who is the board chair of CalISO, and by Caroline Thomas Jacobs, the Director of the Office of Infrastructure Safety, as well as by Linda Serizawa, the Director of the Public Advocates Office. So thank you all for joining us this morning.

And before we begin, I do want to take a moment of privilege as chair just to acknowledge that this is CPUC President Alice Reynolds, final week serving at the cpuc.

After five years of leading this very, very complicated and important agency, I want to just take a moment to President Reynolds to thank you for your years of service to California.

You have led the CPUC through a period of considerable challenge and change and we're grateful for your service and just want to wish you all the best in your next chapter as you assume a role on the KISO board. So with that I think we are ready to get started and I think we'll start President Reynolds with you.

All right, Good morning. Good morning Chair Petrie-Norris and Committee Members. And thank you Chair very much for your comments. I really appreciate the recognition and pleased to be here before the Committee prior to my departure from the PC. Alice, I'm Alice Reynolds, President of the California Public Utilities Commission. Really appreciate the opportunity to appear here today.

I've done this at least annually since I was appointed in December 2021. And as the Chair noted, I'm here today to provide an update on CPUC's work one last time as the CPUC President. Today's update comes at a time when we know that many Californians are struggling with the high cost of utility bills.

And with that context I am going to briefly cover efforts to minimize costs that are borne by ratepayers while meeting legislative directives and allowing for investments that enable development of new clean energy supply, advanced cost effective demand flexibility measures, maintain system reliability and focus on measures that help make rates more equitable for all users of the shared electric grid.

It's always helpful to start with just a little bit of CPUC background for context. The CPUC is the economic regulator of the investor owned utilities that operate within California. These utilities provide essential services to residents including electricity and gas, water, telecommunications, transportation and rail services. In the electricity sector.

Our jurisdiction covers about 75% of the load in California. Electricity supply is provided to customers not just by the investor owned utilities, but also by community choice aggregators and direct access providers. So Overall we have 38 of these retail providers. We call them load serving entities or LSEs.

These entities are responsible for entering into long term contracts to serve the electricity demand for their customers reliably into the future as well as providing resource adequacy to make sure the supply shows up when we need it even in the most constrained conditions.

So even though rates for PG&E and Edison customers have stabilized somewhat over the last two years, we know that people are struggling with rising utility rates. We also know that two of the biggest drivers of electricity electric utility rate increases are investments made to future-proof the grid against wildfire risk and subsidies created by rooftop solar tariffs.

At the cpuc, our proceedings are where we work to scrutinize utility investments and costs to reduce them as much as possible while supporting the utilities mandate to provide safe, reliable, clean energy to all customers. In the last few years, the Commission has taken several actions to mitigate against costs borne by customers.

The Commission approved revenues lower than requested by all electric IOUS in their last rate cases totaling reductions of billions of dollars. The Commission also reduced the return on Equity or ROE, for all IOUS by 30 basis points through a cost of capital proceeding which lowered the overall rate of return.

We also adopted a base services charge on electricity bills to more fairly recover the fixed costs of the electric grid and incentivize electrification by lowering the rate charged for each unit of electricity.

And we started the work of addressing the unsustainable structure of the net energy metering program by creating a new net billing tariff that reduces this cross subsidy somewhat, but still provides a very generous subsidy that contributes to increased rates.

So there's still more to be done, but we're expecting rates of bundled customers in PG&E and SCE service territory to decline this year with rates effective as of January 2026 following several other rate reductions in the past two years.

So a little bit of progress and stabilization, but we know that has followed significant rate increases across the board for all three electric utilities on wildfire costs. We know that these costs are significant and the Commission continues to scrutinize and where justified, reduce and disallow requests for recovery.

At the same time, California is facing worsening wildfire conditions and inverse condemnation creates unique financial exposure for utility caused wildfire damages. So I do have two slides and I'm not sure if we could. zero great. So let's go to the first slide after next slide.

So while we are addressing the current measures that have contributed to previous rate increases, we're also focused on cost effectively and reliably meeting our state's 2045 climate goals. This slide shows the trajectory of ghg reductions from 2020 to 2025 and the future plan for reductions down to an 8 million metric tons target in 2045.

It shows that development of clean energy resources has enabled significant reduction in the carbon intensity of the electric sector. And in fact carbon emissions from the electricity sector are down by over 45% since 2020. I'm sorry, 2000. So in the last 25 years, 45% reduction, but we're still working.

We continue to plan for an electric sector GHG target needed to meet state decarbonization goals as set forth in the CARB scoping plan. That's what we track. That's where the 8 million metric tons number comes from by 2045 as noted on this chart. All right, the next slide may look familiar.

Last year I showed this slide with news about clean energy supply that has come online. And I reported on 2024 as being a record year for build in California with almost 7,000 megawatts of clean energy supply provided. This year, I'm happy to again share continued progress on clean energy development.

Since 2020, the state has developed over 27,000 megawatts of new clean supply to serve caiso load. That includes storage solar, paired solar plus storage, geothermal resources. And what you can see from this chart, if you remember from last year, that vertical line has moved to the right. So this chart shows the built resources and the contracted resources.

And so what we want to see is that those contracts start bringing the new resources online over time. And so you can see that it's working. The vertical line has moved to the right showing that projects are getting built and what has been planned and is under contract is successfully coming online to serve customers.

And this year, the past year, in 2025, we almost repeated that record build from 2024 with the second highest build year at approximately 6,800 megawatts. So those retail providers, the LSEs, have plans to bring online an additional 22,000 megawatts of new clean capacity by 2030. And that's what's shown on the right side of the line.

And we expect that number to continue to grow as they're in active solicitations to competitively procure the most cost effective resources they need to serve their load. All right, that's great. So just a couple of additional points.

I've been talking about the contracts that LSEs have to supply their load, which they bring online to meatload, plus a planning reserve margin. So a little bit of a buffer.

We also have in recent years refined our resource adequacy program by adopting what we call the slice of day framework, where we look at each day in the month for which load is expected to peak and which allows for granularity in the program to ensure that all hours of the day are covered for need when we need it most.

Also want to briefly mention demand Demand Resources Demand side resources so the load serving entities have been working on demand side resources for years and we're continuing to explore new programs. It's an effective tool to reduce demand at critical times. Demand response includes time of use rates which are the default rate for all IOUS.

These rates have successfully shifted demand patterns and we're now exploring dynamic flexible rates through pilot programs offered by PG&E and Southern California Edison. These pilots will use dynamic rates to vary prices, allowing customers to shift their consumption to times when prices are lowest.

Rate design is also paired with other programs that are focused on emergency conditions such as critical peak pricing and reliability demand response resource programs, what we call rdrr. Additionally, utilities are piloting and launching a number of actions to reduce or flex load at the time of energization.

This can be anything from load limiters which avoid panel upgrades, to advanced metering that dynamically responds to grid conditions. Some of these programs have been used for a number of years and others are developing quickly to take advantage of potential growing loads and new technologies.

So as a state, we know we're on track to decarbonize the economy by 2045 and we have a road map to do that cost effectively and reliably.

But decarbonizing our economy will take continued actions by electricity providers to hold solicitations to procure the most cost effective resources that have the attributes we know we need to get gas off the system. Broadly, our work requires that we collectively pursue policies that best and most equitably serve all electric rate payers.

So the state has the work cut out, its work cut out for it. And the CPUC looks forward to continue partnership with the Legislature, with our sister agencies and all of our parties to proceedings to reduce costs and improve services for all Californians. So a lot more work to be done. And with that, I want to thank you for your time and I'll turn to the next speaker. Thank you.

Thank you President Reynolds and Members. We're going to hear from all of our panelists and then open it up for questions. We'll now hear from Director Serizawa from Public Advocate's Office. Welcome.

Good morning Chair Petrie-Norris, Vice Chair Patterson, and Members of the Committee. My name is Linda Serizawa, and I'm the Director of the Public Advocates Office. Our office was established by statute to advocate on behalf of ratepayers for safe, affordable and reliable service across communications, water and energy.

And while we're A part of the California Public Utilities Commission, we are established to be independent in some important ways. We set our own priorities. We develop our own policy positions. We manage our own resources and budget. And unlike the other organizations represented here today, we are not decision makers.

Like other stakeholders, we participate in PUC proceedings and must follow the same rules that they do, including how and when we communicate with PUC decision makers.

So rather than focus on the work that we performed in 2025, which is highlighted in our annual report, I instead would like to focus on the most pressing issue facing ratepayers today, ongoing affordability challenges.

I'd also like to focus on future costs that lie ahead, as well as offer a framework for how to assess any proposals that are intended to address affordability. And I should say that while affordability runs across communications and water as well as natural gas, I'm going to focus specifically on electricity today.

So, sure, I can work the clicker. Okay, if you're looking at a hard copy of the slide deck, I am on slide number three. So, over the past decade, electricity rates across California have increased between 75 to over 100%, depending on the utility.

At the beginning of this year, we have seen modest decreases in the rates of two of the three large electric utilities. Now, I truly hope that these rate decreases are sustained over the long haul, but they may very well be rate fluctuations, not a downward trend.

A change in rates does not necessarily reflect a downward trend in terms of underlying costs. So allow me to be more specific. When we look beyond today's rates and we examine the costs that the utilities have already incurred, the picture becomes clearer.

So as an example, I'm going to focus on one of the primary cost drivers, wildfire related spend. And I'm going to break down the wildfire related costs into three buckets across the major utilities. Billions of dollars have already been spent and they're reflected in customers rates and bills. This is the first bucket.

The second bucket represents costs that the utilities have requested for recovery and are pending before the PUC. This is the second bucket, and the third bucket consists of costs that the utilities have incurred, but they have not yet brought before the PUC for recovery at the beginning of this year.

There's over $2 billion sitting in this third bucket. Buckets two and three represent future upward pressure on rates. I want to emphasize that this is just wildfire related spending.

So we need to keep track of all the buckets across all the major cost drivers to really be able to answer, Are the recent rate decreases sustained over a long Period. What actually determines rate and Bill trends is whether the underlying costs of the system, including utility investments, are rising or falling.

Concrete durable solutions that bend the cost curve down over the long term will determine sustained rate and Bill relief. This is why. This is why a line of inquiry or an initial set of questions should be raised and considered when a proposal is offered to address affordability concerns.

The first question is what's being addressed or solved by the proposal? Does it reduce rates on a sustained basis for all ratepayers? Does it require ratepayer funding that's commensurate with the benefits that are estimated to be provided? And if so, when do those benefits show up? Do they show up in the near term or are they backloaded?

And finally, how are risks addressed? This is why our focus. Let me back up and just say that the initial set of questions. This is the initial set of questions. And they become very important as ideas gain traction, such as overhauling the utility structure or establishing new programs.

These ideas may have promise, but they may take over a decade to implement. That's why our office is focused on a set of four policy levers. And all of these policy levers need to be pushed. Not one, but all. And that's because together they provide a mix of near term and long term relief.

The first policy lever is to reduce the cost of the utility's day to day operations and capital expenditures. This is most effectively done by returning to the primary budgeting forum called the General rate case. This is where the utilities budget is set for a three to four year period. Doing this instills budget discipline.

It also facilitates prioritization of utility spending and it prevents multiple rate changes happening in a year. Since 2019, for wildfire spending alone, there have been 17 separate applications, of which over half have been for a billion dollars each. Outside of the General rate case process.

By now, the utility should know how to plan for these activities and how to forecast the associated cost. The utilities have also filed separate applications for a wide array of other projects and programs related to customer connections and upgrading their metering and billing systems.

The vast majority of utilities operational and capital investments should be considered in the General rate case, with few exceptions for unanticipated costs. I'll go through very quickly on the next policy levers. The second policy lever is to pursue lower-cost financing of capital investments.

This will provide ratepayer relief for a long term. The third lever is to reform or phase out ratepayer funding for programs that cost more than the benefits they provide. This will provide near term relief.

And the fourth leverage is to modernize rate structures so that costs are allocated equitably across customers and also avoids a situation where a small set of rate customers are benefiting unduly at the cost of others. Recently enacted legislation, in particular by this very Committee, has taken meaningful steps forward on these fronts, and these efforts matter.

They definitely contribute to the solution. Ultimately, the challenge is not simply to manage today's rates, but to manage the underlying costs that determine rates or where rates are going to go. This is how our office has been focusing our advocacy and how we will continue to do so. Thank you. I look forward to the discussion.

Thank you, Director. Next up, Elliot Mainzer, the chief operate, the Chief Operating Officer, Chief Executive Officer, California Independent System Operator.

Good morning. Thank you for having us. We're very pleased to join the other energy entities in California speaking to you today about our work.

And maybe just move the mic a little bit more like there.

Very pleased to have the opportunity to be before you today to describe our work and answer your questions. I'm Joe Eddow. I'm the chair of the Board of Governors for the ISO, and I have with me my CEO, Elliot Mainzer.

Since this is our first joint appearance before you, I thought I would start with a little bit of an introduction, just to clarify what it is, who we are at the ISO and what it is we do.

And then I'll turn it to Ellie to talk about the details of the annual report that you've asked us to prepare. So let's get these slides up here.

What do I have? All right, perfect. So to begin, we are a nonprofit state corporation. We are not a state agency. We are a 501c3 organization. That was really. Elliott likes to refer to us as the Department of Physics and Economics.

We are the implementers of many of California's electricity related policies and priorities related to reliability, affordability, and the clean energy goals that we have as a state. So the way we carry out those responsibilities is in three ways. Job number one for us is to keep the lights on.

We do this by operating the vast majority of California's high voltage transmission network. We do this by operating a control center in Folsom runs 24/7 365 days a week. During the pandemic we didn't get to work from home. This is a very serious job that we take very, very seriously.

Job number two, in support of California's clean energy goals, we plan and oversee the interconnection of new generation to California's transmission system.

So all those resources that President Reynolds described as coming online, our responsibility is to ensure that the transmission is there when they get there and to ensure that the interconnection is safe and reliable for those resources to meet those goals. And we have very aggressive goals on a year by year basis to hit.

Finally, in support of energy affordability, we operate a competitive wholesale market that seeks to ensure that the energy commodity portion of consumers' bills is as low as is practically possible. The last 12 years we've been expanding the real time component of this market.

It's called the EIM, to the point where it now encompasses 80% of the load in the western interconnection spending utilities that cover 14 states. This market over, I think as of last December, has yielded $8 billion in benefits to consumers through lower wholesale electricity prices.

This year we're super excited about the launch of EDAM which is going to add a day ahead component to this market. The Energy Commission conducted a study. We expect this new market will yield an additional billion dollars in benefits annually. We'd like to thank Chair Petrie-Norris for her leadership for the AB 825 legislation.

This legislation provides us with a very, very powerful means that all parties agree is going to be essential for us to secure those benefits. Elliot will talk about some of the specific actions and responsibilities that we have under that bill and the annual report that we prepared.

But before I turn to Elliot, I just need to acknowledge how excited we are to know that President Reynolds will be joining our board.

President Reynolds, Vice Chair Gunda from the CEC really initiated the Pathways Initiative by their outreach to their fellow regulators across the west and laid down essentially the principles that allowed the Pathways Initiative to go forward. I'm very eager to work with her. Just get this across the finish line. Thank you. And with that I'm going to turn to Elliot

Chair Petrie-Norris and Members Committee. Thank you. It's a pleasure to be here today and I'd like to echo Board Governors Chair Eto's sentiment on all fronts. So I'm going to speak for just a few minutes about the Pathways Bill.

AB 825 I think as you are familiar, AB 825 does enable the further expansion and use of voluntary wholesale energy markets throughout the West. It actually enables the ISO to partner with an independent regional organization to govern and operate these markets for the benefit of ratepayers.

The bill establishes very specific requirements that must be met that protect California ratepayers, including respect for state authority, transparent processes, and protection of consumer interests before the ISO and California's investor in electric utilities within its market footprint may transition to an arrangement where the voluntary wholesale energy markets are governed by that independent regional organization.

One such requirement, of course, is to provide an annual report detailing our key activities and initiatives for the previous year. That report was submitted on February 1st. It covers five critical areas. I'm just going to speak very briefly to each of them, starting out with changes to federal tariffs.

The CAISO actually submitted more than 40 filings to the Federal Energy Regulatory Commission last year. The vast majority of them accepted and several of them affirmative rulings on key elements of the design of EDAM or our Extended Day Ahead Market.

With respect to policy initiatives and recurring processes, last year, ISO staff actually completed 24 distinct initiatives with special focus on enhancing stakeholder processes to enable greater participation in market design discussions. With respect to the assessment of market activity, the ISO's independent Department of Market Monitoring develops quarterly and annual market performance reports, and those reports are covered in the report.

I do note, one of their findings was that the WEIM electricity prices decreased last year compared to 2024, primarily as a result of lower demand and the absence of extreme grid conditions like we had seen in July of 2024.

With respect to actions taken by the ISO board, the board approved 25 items last year that helped shape key policies, grid planning and market design, including the approval of the 2024-2025 transmission planning.

And of course, with respect to actions generally taken within the transmission planning process, the ISO continues our sustained efforts to make transmission planning and interconnection queuing more efficient to enable the necessary resources to keep California on track with SB 100. Finally, I just wanted to note, we are all quite excited to report here today that we are actually on track for the May launch of the Extended Day Ahead Market.

This has been a major effort for quite some time. We're excited to actually have the market up and running for the summer of 2025 and to have a chance to demonstrate the enhanced reliability and economic savings from that market, which goes directly back to electricity customers.

So I look forward to questions and as President Reynolds said, and again, congratulations to you. Really appreciate the collaboration across the state apparatus and the support of the Committee. Thank you very much.

Thank you both. Moving on now to Director Jacobs from the Office of Energy Infrastructure Safety.

Good morning. Thank you Chair Petrie-Norris and Vice Chair Patterson, Members of the Committee. As mentioned, my name is Caroline Thomas Jacobs. I'm the Director of the Office of Energy Infrastructure Safety.

Energy Safety was established as a new Department within the Natural Resources Agency in July of 2021 to ensure electrical corporations are taking effective actions to reduce their utility related wildfire risk. Our mission expanded in January of 2022 to include excavation safety with the addition of the Underground Facility Safe Excavation Board, formerly known as the DigSafe board.

The purpose of the new wildfire safety regulatory framework that we were created to implement is different than the traditional punitive regulatory model. We were created to facilitate expedited, proactive investment to improve wildfire safety outcomes through continuous learning.

Within this wildfire safety mission, we are responsible for evaluating electrical corporations wildfire mitigation plans, assessing their performance, implementing those approved plans and issuing notices of non performance and directing corrective action when they don't meet those commitments.

Last year, for example, we completed over 5,600 asset inspections and nearly 30,000 tree inspections along the utility rights of way leading to issuing 89 notices of non performance and over 550 wildfire safety concerns. Year to date, we've already completed 4,000 inspections and issued over 75 notices and wildfire safety concerns to the utilities.

Since our inception, we have inspected over 200,000 wildfire safety activities and and issued corrective action for over 2000 notices and wildfire safety concerns. Examples of these notices of non performance that we find and ensure the utility is correct include missing component installations, incorrectly installed components, as well as vegetation clearance and contact issues.

Examples of wildfire safety concerns that we find and direct utilities to correct include sparking and broken equipment. Examples of what we've directed utilities to do through our plan evaluations through areas of continued improvement. So every year, we review plans and when we approve them, we also talk about how we expect them to improve over time.

We've directed them to create robust quality control programs to ensure the work that they're doing is done well. We've directed them to clear repair backlogs. We've matured their risk modeling to not only look at historical weather, but start to incorporate climate forecasts looking forward.

As well as directing them to conduct one example, a joint effectiveness study for enhanced clearances of vegetation as well as covered conductor and other wildfire mitigations.

Through these Plan Investments, since 2020, utilities have installed over 2,500 weather stations, which is foundational to their ability to understand their wildfire risk and monitor that risk, that weather around their infrastructure. They've installed over tens of thousands of remote sensing devices to identify faults more quickly, often before a spark can happen.

Between 2020 and 2023, we've been able to verify that they conducted over 11 million inspections, finding more than 1.8 million conditions, repairing more than 1.1 million of those conditions, and we're making sure that they have plans to repair the remainder of that. They've developed new grid operating protocols such as fast trip to operate the grid more safely.

Not to mention, of course, the thousands of miles of hardening of the infrastructure. All of this investment is making a difference. While every year can vary significantly based on the weather, the main metric that we monitor is called reportable ignitions. So they're ignitions of significance. And in 2025 there were 90 reportable ignitions.

That's a 51% reduction over the previous eight year average of 183. However, the Eaton and the Palisades fire last year are devastating reminders that it only takes one ignition under the wrong circumstances to cause catastrophic fire. The utilities are not ahead of this wildfire risk yet, more needs to be done.

The investments made so far, however, are making a difference in their ability to understand that risk and target the wildfire mitigations to those areas of risk.

In addition to reviewing the plans, Energy Safety also conducts wildfire or safety culture assessments and extensive audits of the vegetation management activities that they do as part of these plans, verifying hundreds of thousands of veg activities each year.

We also review and issue certifications to electrical corporations that meet specific statutory criteria for utilities request such a certification annually. PG&E Edison, San Diego, and Bear Valley Electric. With the passage of Senate Bill 884 in 2022, we are now also responsible for evaluating large electrical corporations 10 year undergrounding plans.

If they choose to submit, and assessing implementation of those plans. We issued the submission requirements for those plans in February of 2025, so last year, and are awaiting the first plan submissions. We expect to receive plans from PG&E and San Diego later this year.

Within our Excavation Safety mission, the Underground Safety Board leads the state's excavation safety outreach and education efforts, develops safe excavation standards, investigates excavation accidents, and works with partner state agencies to enforce the call Before You Dig law.

In 2025, the Underground Safety Board processed over 2,000 damage and complaint notifications, opened 155 investigations, and issued 56 notices of probable violation to the enforcing authorities. With the passage of Senate Bill 254 last year, thank you to the Chair for your co authorship of that bill and Committee Members for your support.

We are very appreciative of the statutory adjustments that mature and streamline the Wildfire Mitigation Plan process and safety requirements as well as strengthen excavation safety. Specifically, Senate Bill 254 aligns the WNPs with the general rate cases that were mentioned and adds a new cost per avoided ignition metric requirement to those plans.

We have hosted a public workshop in December on that cost per avoided ignition metric to begin discussing how best to define that metric and incorporate that metric into the plan.

And we've also released for public comment and are assessing the public comments right now of a new proposed Wildfire Mitigation Plan submission process to align with the general rate cases going forward. Over the course of 2026 we will be developing the fully updated new Wildfire Mitigation Plan technical guidelines.

Those are all the submission requirements that will incorporate all aspects of the 254 elements by the statutory deadline of January 1st of 2027.

So with that Chair Petrie-Norris, Vice Chair Patterson, Members, I thank you for the opportunity to talk a little bit about what we're working on and of course I'm happy to go into further detail on any one of these topics and answer questions.

Thank you. Last but certainly not least, Chair Hochschild

Good morning Madam Chair, Vice Chair, and Members. I'm David Hochschild, Chair of the California Energy Commission and Madam Chair, I join with you in acknowledging President Reynolds.

I want to just thank you not just for your service most recently at the PUC, but for really a long tenure under Governor Brown as well as Energy Advisor and I wish you well in your next chapter and as you join the CAISO. I did want to just acknowledge Chair Eto and Elliot for the EDAM.

This is a huge, huge feat and we need all the help we can get to apply downward force on rates. So congratulations, looking forward to that launching in a few months. If we could pull up the slides. So I just wanted to begin with a little bit of. It's the 67. Yeah. Okay.

A little bit of what's happening on the grid today. So we're actually getting two thirds. More than 2/3 of our power today in California is coming from clean sources like solar and wind and geothermal. It takes us, there's a long lag time in the collection of this data because we have 43 publicly owned utilities.

So the actual staff estimate is about 70%. So we're the most decarbonized major economy in the world. And this is a huge feat to be getting to this point.

And we're absolutely on track to hit the target that you have set together for us with Governor Newsom to get to 90% clean energy by 2035 and 100% by 2045. We are adding, as Alice mentioned. Can you click forward once? Thank you. One more. Thank you. One more. We're adding a colossal amount of power.

And I wanted to just provide a little bit of context. Electricity came to the state of California in 1850 in San Francisco after the gold rush. So, 176 years ago. In that entire time, our states added 105 gigs of utility scale capacity. So we've added 30 of that since 2019.

Last seven years, this is the biggest build out in state history by far. And the, you know, significantly, this is allowing us, we've added all this energy storage. You can see about half of that is energy storage. And that's allowing us to do something really remarkable and totally unprecedented.

So last year in the state of California, we hit 100% clean energy on the CAISO system for 279 days for a period of the day. So like last July, we were running, you know, it's six and a half hours at 100% clean. It's never happened before.

And that's really a combination of energy storage and renewables that's making that possible. We're also rapidly expanding electrification. We have now two and a half million electric vehicles on the road in California. We're adding about 1200 EVs a day.

That is a downward force on rates because the vast majority of your bill are actually constituted by fixed costs. So even if generation were free, the majority of what you pay monthly is for these fixed costs. And when you have more electricity being sold, you're spreading those fixed costs among more kilowatt hours. Right?

I also want to highlight we now have more EV charge plugs in the state of California than we have gasoline nozzles. So about 120,000 gasoline nozzles in California, 201,000 public and shared EV chargers, and about 800,000 privately owned. And I wanted to acknowledge especially Assembly Member Irwin's focus on charger reliability and accessibility. It's really paid off.

Happy to report we're finally making real progress on charger reliability. We're 96% uptime for level two and a lot more is coming in. The new stuff that's going in is very, very fast. We just dedicated a. I own a charger system in San Francisco. 400 kilowatts charges a car in 15 minutes. Right. So some good progress there.

And sorry, it's being a little bit sticky. So I did want to highlight, when you look at load growth, there is sort of electrification of everything that's underway. And of course a lot of talk about data centers. We still project, however, that electric vehicle load is going to constitute but double the data center load growth.

But there's a bunch of other things driving electric demand up. And so that's why it's really important we keep up the pace on storage and renewables. And also on efficiency. We do rank number one in the United States on energy efficiency. We do that through codes and standards.

So things like lighting and we did television standards and so forth. And as steep a challenge as the affordability crisis is now, it would be a lot worse if we didn't have robust energy efficiency requirements. And let me just close with this is a little picture of some of that.

So just to explain, on the bottom at the right, that dark blue is just one example of our standard. That's the lighting standard. Okay. So that what's moved us from incandescents to high color rendition LEDs, that one standard saves $6.7 billion a year. We did a television standard, cuts the energy use of TVs in half.

About $2 billion of savings a year, and battery chargers and so forth. So it's really important we continue to be ambitious on this. That saves us money on the build out. We'd have to build less capacity as a consequence of that. And with that, I. Oh, I think I have one. One more slide just on.

Sorry, the last slide here on gasoline. Sorry, this thing's been a little. Yeah, there we go. Just on gasoline price spikes to highlight that that has been an issue. As you all know, the last two years it's been a really intensive focus at the Energy Commission led by my very capable Vice Chair Siva Gunda, on this effort.

And you can see in the purple and blue bands, the gasoline price has really been largely contained. We don't see the kind of spikes that we had in 22 and 23.

And we're really aided by your support on some of the new data gathering we've been able to do with the authority granted to us to closely monitor and plan to get ahead of that.

And that remains a challenge and a very, very big focus for us because this is not a threat that is over by any means. We're really locked on doing everything we can to stay ahead of that. And with that close, I'm happy to take questions.

Thank you, Chair. And thank you again to all of our panelists. We'll open it up for questions from Committee Members. Assembly Member Irwin

Yes, thank you very much for the presentation. It's great to get these updates. One of the topics we're talking a lot about is DSGS, and it seems that there's not quite the funding decisions that have been made yet. As you know, it was a top priority for the Assembly during the cap and trade discussions.

And it's basically utilizing resources that are already there, dispatching them to the grid at the right time, which should lead to big savings. So I was wondering if we could get an update from Mr. Hochschild on DSGS and why it's important to have steady funding over the next three years.

My understanding is if we don't get the funding, then the previous funding that we have already allocated is sort of wasted.

Yeah. So first of all, with respect to the budget that is ongoing with DOF and, you know, we will implement the programs that the Governor and the Legislature send to us. That was a direction that was given us three years ago. We stood up the program. It's now the largest virtual power plant in the world.

And CAISO did a test in the late summer and we got really good results on that. I think one of the things to keep in mind, the state of California is adding about 2,000 behind the meter battery systems a week.

And so the concept of a virtual power plant is to make use of those so they can be dispatched. They function like a central station power plant. You can aggregate all that, all that generation. So we feel really good about the potential for that. And I do want to compliment the PUC has been working hard as well on this.

And I think we're going to need all the tools that we have available as we face more severe weather. We got lucky. I think we all know that last summer with the weather we did not have the kind of extended heat domes that I think we know are coming. But yeah. Thank you

Assembly Member Rogers.

Thank you, Madam Chair. I have a couple of questions kind of across the board. But first, I think as many of you know when I talk about my district, we have pretty substantial geothermal resources. We also have proposed offshore wind projects.

For us, it really appears as one of the economic development opportunities for communities that have felt left behind. And so my first question really is sort of for the CPUC.

Your proposed decision that comes up tomorrow outsources offshore onshore wind, reducing our goals in California while allowing additional energy to come in from other states, states that don't have the same job training requirements that we have.

How are you integrating our other broader goals like our economic goals or go business goals, particularly when we look region by region at what we're trying to accomplish that's not just energy related but also economic related.

Yeah. Thank you for the question. And I guess what I'll say is so the IRP decision as you said is a live proceeding.

And so I don't want to get too much in the details, but I certainly can speak to the decision that is out there and also put it in the broader context of so our IRP or Integrated Resource Plan process is that it's planning and so it uses modeling to do generation capacity expansion modeling.

So as we add generation resources, looking at the system as a whole and of course we're connected, resource generation is used throughout the west on the interconnected system. We're not Texas where which is a state that has a separate grid. But for California we do planning for resources to serve our load here in California.

The IRP portfolio that is put forward to CAISO through the proposed decision is the largest showing of new generation needed from a planning perspective in state and out of state. So it's the total amount is larger. So if this plan is implemented it will result in a lot of build in California.

A lot of projects in California, potentially some outside of California, but it's a plan. And so implementation of that plan depends on decisions made by those 38 load serving entities.

A lot of that work is being done by community choice aggregators, local governments, affiliated with local governments making decisions about what they want to procure to serve their customers. And so their decisions will go forward through solicitations where contracts will be entered into for specific projects. That then build process involves a lot of factors too. Right?

So the projects that bid can get, be a least cost successful bidder if they receive support from permit streamlining or other actions that I know have been in discussion from a broader perspective. So wind projects can benefit in state with permit streamline and other actions.

So there are many other factors that kind of then will go into the mix as implementation takes place. The other point is that our integrated resource plan process is iterative. And so the most important timeline in this current decision is the 10 year timeline.

And so focusing on the 2036 numbers are the ones that will result in triggered transmission upgrades. Transmission upgrades could be a substation anywhere in California, it could be on the border, but it's within the CAISO system. Those upgrades which then trigger transmission work inside California which will bring economic development jobs inside California as well.

And so that 2036 number is the most important one for current purposes. 2041 is done. Again planning purposes. We want to be smart about the build and so planning helps. We think about the 20, the 15 year timeline as a more, more of a guidance.

And then in our next IRP process next year we'll be looking again we'll be looking at developer interests, we'll be evaluating the system, we'll be seeing what has come online in the past year and we'll do another 10 year and 15 year that will go over to CAISO. So there are a lot of factors that are at play.

And I want to punctuate the point that I think that I just heard and confirm for me if I heard it right or if I'm wrong. But the IRP helps to inform where we put resources for transmission and for build out.

That's right.

So by taking some of the wind like as I mentioned that my district is particularly interested in for, for jobs out of the state from an area that currently doesn't have the transmission resources to, to bring online almost any renewable resources north of the Delta is the analysis that we've seen.

How are you then helping these communities that need to make a transition and could benefit from that level of investment by having projects located there?

Because what I heard from your answer is good luck getting in the next IRP and then maybe we'll build out the transmission that we need to be able to turn on these projects or attract that investment in an area that quite frankly hasn't had a lot of economic development or a lot of interest from Sacramento in a long time.

And there's still wind in the portfolio in state and so those projects, you know, wind is a very valuable resource.

But I'm asking very specifically about the, the equity aspect of this for communities that have been left behind and then the process seems to continue to leave them behind. So I'm not asking about could you still have wind in the state? I'm not asking about could you still have more creation in areas while you allow more outside.

This is one of the golden tickets for the north coast. And it's being left behind in the IRP process and this proposed planning that the CPUC will see tomorrow. So how are you integrating other goals like equity and economic development? Because it really matters.

We look at ratepayer savings. So we look at what is a plan that can be put together with the least burden on ratepayers. And that involves building the projects that we need according to legislative direction on climate policy and reliability. And so that can support economic development. And there is wind in the portfolio.

And if those projects are built, then they will go into the portfolio as cost effective and potentially over the years grow. And so if those projects are successful and we see the possibility and so we're essentially identifying possibilities, but we don't set economic policy for the state.

We don't pick between different counties to provide incentives for various counties. We look at what's the best for the ratepayers.

All right, thank you. For the Public Advocate's Office, one of the charts that you had showed the amount of spending projects that have been built that have not yet come forward in a GRC that could be, I think it was a little over 2 billion, was the number that you had.

What guardrails are there on the utilities for the amount of public infrastructure that they are or the infrastructure that they are building that then they can come back in the future and ask for a rate increase based on that work that's already been completed?

So those, the utilities have a choice in terms of how they seek cost recovery for wildfire related costs. Well, for actually most costs. They can put those requests in their general rate case, as I mentioned, or they can file separate applications. And that's the 17 that I mentioned earlier.

So attached to all of those requests is a PUC process, the formal process. There's assigned commissioner, assigned ALJ and intervenors who scrutinize like the Public Advocate's Office. And we scrutinize those requests to make sure that the requests are reasonable, that they deliver the benefits that they were supposed to deliver.

I will say that it has been very challenging for our office and I would say for other interveners as well to participate in so many proceedings.

But that is a guardrail, is the fact that we are intervening and we are looking at what the utility is bringing forward and we are trying to whittle down as much as possible what the utilities are requesting to recover in rates and bills. But it's been very challenging to do across so many proceedings.

And do you know when the last time that process was denied where projects were brought in, proposed that were outside of the GRC, but then it was denied.

There are, I would say typically again because of rate per advocacy and not just from our office, from other rate payer advocates. There has been reductions that have been approved by the commission of the utility's original requests. So it's proceeding by proceeding where we're seeing cost savings.

I will say that the Legislature last year enacted important legislation in SB 254. It was a one word change that makes all the difference and it changed a shall to a may.

It returned important discretion back to the PUC to determine whether the utility should continue to request separately outside of the GRC to seek recovery of wildfire related costs. So I do see a right sizing here and it's very heartening.

I appreciate that. Thank you. Two more quick questions, Chair. I think that this is for the Energy Commission. We are starting to see in some locations like Sonoma County, a gradual move, if not a fast move towards winter peaks.

So the duck curve and all of our preparation for the hottest days, 4 o'clock in summer actually won't be as relevant to some other jurisdictions that have either shifted their time of use from electric vehicles charging or other types of infrastructure. How are you planning for that?

Because I think rapidly we'll be in a situation where multiple counties will be seeing winter peaks instead.

Yeah, it's a great point. And I think this highlights the benefits of energy storage that provides us a huge cushion. And one thing I'd observe about energy storage that's really positive is we've been able to deploy it really quickly.

So the build out time in the United States if you want to build a new combined cycle gas plant today is seven years. These storage projects are coming online, you know, 12 to 18 months. We're starting construction next week on the largest battery storage project in the world, the Darden project, $5.5 billion in West Fresno County.

That's typically four hour lithium dispatch but we're also now doing about $220 million for long duration storage, something that Alice and I have been working on for quite some time. There are chemistries out there like form energy is 100 hour dispatch and EOS is 20 hours.

And so there's different types of storage that are going to help, but that's I think really highlights the benefits of energy storage because you're absolutely right, the load shape is changing with time.

Thank you. Then my final question is for CAISO. There are other states that do connect and manage for renewable resources rather than having to have all of their ducks in a row before they can start construction on the project. Have you looked into what that might look like in the state of California?

And could that help decrease the amount of time and the amount of cost to get renewable projects built?

Thank you for the question. We have looked extensively at that model quite directly with ERCOT in Texas. What we've generally found is that while there are some advantages to that model, it tends to be a little bit more reactive. And we're even finding in Texas that they're seeing that they need to do more long term planning.

So what we've done here in California is we've really synchronized the long term load forecasting and integrated resource planning with the transmission plan, got ahead of the curve with the transmission planning and then reformed the queuing process to make sure that folks coming into the queue are lining up with where we're going on the long dated transmission and are providing these cost projects.

And we've just last year put our new reform processes into place, significantly reduced the number of requests in the queue, made a dramatic reduction in the time it's taking to process those requests. So I think we're on the right track here in California. Thank you.

Great, thank you so much.

Assembly Member Zbur.

Thank you for being here.

I had a number of questions that I think follow on my colleague from Humboldt related to the CPUC's Resource Planning and the integrated resource plan. And you know, focusing on the issue that there was a significant share of California's future energy needs being planned for resources outside of the state of California, wind resources in Wyoming, other states, other resources in Arizona and was nervous about that because in reading about some of that it seems that many of these resources are speculative.

We're planning on achieving significant amounts of our power from out of state at a time when we've had wind projects in the state of California that have been turned down. And so I guess I'm wondering and I'd like to sort of understand sort of what are the factors?

I think you partially answered it which is that some of these factors just aren't considered.

But you know, how does the PUC factor in sort of cost of labor and right to work states and you know, how does that align with in these right to work states with California values and sort of protecting our workers in the state of California?

Does the PUC assign additional costs to development in California related to cheaper land out of state as a benefit to those out of state resources in the planning? does the PUC consider benefits of the increased tax base for local governments and the thousands of jobs that are created when projects are developed in state?

I'm just, from an equity standpoint, are these things being considered in your resource planning or are we just sort of blindly looking at where is power going to come from and not looking at other goals that we have as a state which is maintaining high wage, high skilled jobs in the state, making sure that when ratepayers are paying for ultimately paying for this power, that actually we are getting all of the benefits that the people of the state of California deserve?

Yeah, it's a great question and I think it's something that, you know, that we would have a piece of. We don't have all of it. Right? And so we work with our sister agencies, we work with the direction that you give. There are PPA, Power Purchase Agreement provisions that include labor protections and labor requirements.

And so there's, there's kind of a larger framework to work on the issues that you're talking about. There's been a change in the tax contribution of renewables to local governments where there was an exemption before. And in the new year there will be payments to local governments.

And so there have been some changes that surround the PUC's work.

What we do is we look at available resources and developer interest and the system as it exists today and again do that capacity expansion modeling with the idea that our major focus is on ratepayers, which again affects the economy, which affects the cost of living in California.

And so from our planning perspective, we're putting out here's a blueprint for lease costs. When you think about what it says. First of all, most of the build is in California. And in the decision that we have before us for a vote, we have moved, for instance, solar in the Fresno area.

We doubled the amount in that 10 year planning horizon, which will mean that for near term compared to last year's. So the 2041 number was a little lower. But what was important, as I said, is that the trigger of the transmission upgrades was moved forward.

So doubling the amount of solar in the Fresno area, which is more important the 10 year than the 15 year for current purposes. And so things like that will lead to build in California. And then being connected to the rest of the west means that other states use our resources.

And so that we're doing build in California that at certain times of the day we'll be serving other states. When you think about renewable resources, wind and solar, we benefit from having geographic diversity. And so you know, and I understand and our plan again does emphasize California projects.

Our load serving entities for the most part are contracting with California resources. And we have a connection to the CAISO system, which is largely in California. And that's where all these projects are. It's really connected to the CAISO system. But we also can benefit from Wyoming wind.

It blows at a time that is very favorable to our system. We don't want that to happen at the expense of Californians. But we can have it all if the projects are done right and in a way that is cost effective, but also protects workers and labor and pays the wages that are, you know, that are fair.

And so it's more of a way of like here's a possibility, here are the low costs. And then we also need to make sure the contracts are done fairly when the projects are actually built. So I hope that's helpful.

It's kind of, this is a plan, it's not the actual implementation, but it's a low cost plan and it happens within the larger context of protections that the state and priorities that the state puts in place.

So I think that response makes me very nervous because obviously what it conveys is the fact that we've got a complicated system in terms of our resource planning. And you've got a lot of actors making decisions in a sort of desegregated way. And there's some. What I heard is there's some natural.

The benefits of locating in California, and basically in the end, much of the generation will be located here, so, you know, we'll get the labor benefits and other benefits that come about because we actually oversee the development of resources in California in a way that's different from other states.

But what-- I'm worried about the fact that such a large amount is planned for out of the state, because, one, I'm hearing that a lot of the those projects are really speculative at this point, and if that is driving transmission into the State of California that is actually out of the state, California ratepayers are potentially paying for transmission for speculative projects that may never occur.

I'm also nervous of the fact that if our neighboring states lean into more gas generation and coal, how does this really impact our ability to decarbonize here in the State of California? And so, I don't know if you want to respond to that set of concerns.

Well, the near-term planning is more certain, and so that's why we do the every year cycle. And so we iterate based on-- farther-out planning, yes, there's uncertainty about what's actually going to come online, but we look at the contracts that are actually entered into and those are incorporated into--as well as projects that are being built--and those are incorporated into the planning process, and so it gets more certain with each year.

And the transmission that is planned-- that is actually triggered is meant to be least regrets. And so, what happens is that the transmission planning process-- we have a plan that could include-- and the upgrades can serve a number of projects, so it doesn't have to be one particular project, but it provides increased capacity on the system as a whole so that there's a range of projects.

Land-use planning is largely controlled by the local government, as you know, and there are some local governments who are working collectively to increase projects in their areas. Kern County, Fresno County, of course, they have facilitated renewables development, and that is something that plays into the IRP process in terms of the projects that are actually built in the commercial interest, and that gets taken into account.

And so, we're putting lots of inputs, and every year, we use additional inputs. And we are seeing projects being built, and so, I don't-- you know, and then we look at least regrets, because that is a big fear, right? You build transmission and the projects don't show up. And so there are protections against that. And I don't think we've ever seen a transmission to nowhere project.

Yeah, I mean, maybe Elliot could add in, because I understand. I get anxious about that too. We do not want to spend ratepayer money and have it go to stranded assets.

I think the only things I would add is, you know, we certainly, in our transmission planning process, which is directly reflective of the state's integrated resource planning, and certainly the vast majority of the projects that are being developed, both transmission and generation are being developed in the state, and I think we all have a heightened sensitivity the importance of the jobs and the economic development in California.

At the same time, as President Reynolds said, there have been a number of projects that have showed up in the integrated-- resources that have showed up in the integrated resource planning process that demonstrate that some of the renewables from other parts of the West--New Mexico, Wyoming, up into the eastern side of the Columbia River Gorge--are areas where we can get electrical and resource diversification at lower cost.

And so, we are in the process of working with several of those big interregional transmission lines. The key thing I wanted to point out, however, is to your point about stranded investment and ratepayer costs, two of the most important segments that are under development--the SunZia project got into New Mexico and the TransWest Express project got into Wyoming--are being developed under a very unique cost allocation methodology known as the Subscriber Participating Transmission Owner Model, where the developers of those transmission lines are actually putting up all of the capital in advance for the projects.

They're then subscribing the transmission capacity with resource development and then offering, to load serving entities in California and other states, the opportunities to purchase bundled and delivered energy and transmission. So it's a very unique, I think, express methodology to manage some of that risk and ensure that Californians aren't exposed to stranded cost and investment.

So, very sensitive to that issue, but also I would just say that from a reliability perspective, it's also very helpful to us to have some electrical diversification across the region.

So those offsetting patterns of generation between New Mexico and California, Wyoming, Idaho, they help our system manage the variability of the resources more efficiently and that also helps lower costs for energy dispatch. So very sensitive to the point, take your major issue--I think we're all acutely sensitive to that--but some level of geographical diversification and risk management, I think, is part of the equation as well.

This is my last question and then I'll turn it back to our chair and our colleagues. You know, obviously I think-- you see there's a number of us that actually have concerns about, you know, about sort of the outcome of the IRP process in this cycle and how much is actually anticipated out of state, both from the stranded assets, both from the fact that, you know, we have less comfort that's going to be renewable energy that's developed in some of these other states, from the fact that we have potential exporting of jobs that are paid by California ratepayers.

What kind of additional guardrails do we need to put in place in California, if any, to make sure that, you know, as we are moving forward in this sort of disaggregated diffuse resource planning system that we have here in California, that we're actually, in addition to achieving lower rates, that we're actually maintaining, achieving the other benefits that we want to achieve here in California, which is making sure that we have high-wage, high-skilled jobs here in the state and that we actually are not building transmission to nowhere in other states?

Yeah, I mean, you're right to point out that it's very disaggregated, and remember that 25% of load is served by utilities that aren't part of this process. Forty-eight public utilities? Forty-three public utilities serve 25% of the load and they do their own planning processes.

There's a lot of hydroelectric generation that happens outside of the state that serves public utility customers, and it's low cost. And so, what we're doing too is trying to bring some of the-- trying to make sure that ratepayers are protected so we get to our goals in the lowest-cost ways and protect that impact on bills.

California has one of the best planning processes from the IRP to the CAISO's work in the nation. I mean, we are called out by FERC, we're called out by-- at national conferences as a model, and it's not to say we don't have more, but-- and we need to look at each iteration and make sure that everybody is coming together to support the projects, which we also do.

We haven't talked about that, but we have a really robust interagency working group to support California projects, including GO-Biz and everybody here, where we make sure that the projects that are contracted can come online. We break through barriers so that those barriers don't create additional costs for the developer, which could fall on ratepayers, and so, all of that is done in a coordinated way.

You know, we'll continue to think of ideas to improve, and we're doing that all the time, but we do have a process in place. So it's balancing a lot of interests, but also fundamentally trying to protect ratepayers.

Thank you all. I appreciate it, Madam Chair.

Before we move off this topic, I just have a couple of follow-up questions. I think, you know, as you've already heard from other members on the dais, I think a number of us were very concerned by the proposed IRP.

I think in particular, when you look at the 2040 to 2041 window, in-state wind decreases by 3 gigawatts and out-of-state wind increases by 6. So that's a place where that balance, I think, is concerning for all of the reasons articulated by Assembly Member Zbur.

But I want to, I guess, take a little bit of a step back and I think better understand when the IRP goes from sort of a plan that doesn't matter to something that's actually driving real procurement decisions and real transmission planning decisions.

So, President Reynolds, if I understood your earlier comments, you've said that it's kind of the 10-year horizon that matters. I feel like that's really different than what we're hearing from our in-state clean energy developers who-- I think they are making investment decisions based on that 15-year horizon.

And so I would just flag that as, I think, a potential point of important disconnect. And then second, Mr. Mainzer, if you can help us understand the TPP time horizons a little bit better so we can understand, should we be concerned about building transmission to nowhere or is that a different time horizon?

I'll just quickly note, you know, it's a little bit of a chicken and egg issue, right? I mean Assembly Member Zbur noted that we don't want to base our planning on speculative projects. The developers want certainty before they get to the kind of certainty of their own projects. They want to make sure the transmission there, and so we're having to balance that chicken and egg problem, but I'll turn to Elliot.

Yes, we generally conduct transition planning on two horizons. We have a long-term sort of outlook which is sort of a 20 to 25-year look at the broad architecture of the system, but our transmission plans, which we update every year, primarily between a 10 and 15-year look, so that's really the horizon more actionable. And we'll be coming out with another one, the 2025-2026 plan later this year.

To your point about-- so I would say we are acutely sensitive to the issue about building transmission lines to nowhere, and certainly the projects that we have at play right now, those three segments that I mentioned, have been directly indexed to identified needs from the state's planning process.

And as I mentioned, we also-- because we are very sensitive about the cost allocation methods, we've really innovated on the cost allocation mechanism where the developers of those projects and resource developers are really bearing the risk of those projects not coming to completion or not delivering on time or on schedule.

The one exception to that is the project that we're developing in cooperation with the States of Nevada and Idaho, the SWIP-North line. That's been a shared process of subscription through California load-serving entities and the State of Idaho, kind of a nice partnership that's actually going to help strengthen the extended day-ahead market dispatch. But fundamentally, you know, the 10 to 15-year time horizon is really the most actionable and the one that we're focusing on right now.

All right. I think we'll-- pause there, but I feel like the central point of importance is whether it's the 10-year window or the 15-year window. So if it's one-- if it's both of those, that is a little confusing, I think, for all of us.

I said 10 to 15 because we've been transitioning from 10 to 15 over the last cycle. It's historically been been a 10-year. We're now moving into more of a 15-year look just to give us a little bit longer dated perspective on resource development.

Okay. So then you are going to be making transmission planning decisions based off of these 2041 numbers?

Yes.

And that's going to drive real procurement decision-making?

I mean-- Alice, you can certainly clar-- but certainly, the plan and the procurement decisions that are coming out of the state and the load forecasts are direct inputs into our transmission plans. And they are based-- they're not based off actual-- every single specific project.

There is flexibility for procurement, but they are generally signaling the resource development areas and the zones within the state and the resource categories that the state is intending to procure from to meet SB 100 goals.

Right. In terms of planning processes, my understanding is that moving solar into the 10-year horizon from the 15 horizon will trigger a CAISO solicitation for three specific upgrades. And so that decision is important because of the 10-year versus 15-year.

All right. Okay. Assembly Member Hart.

I have a different series of questions. Looking at the charts that you shared about the development of battery storage--it's very impressive, going from almost nothing to 15 gigawatts--it occurs to me that these projects have a finite life. I have no idea what that is.

And will there be a problem at that point in time when all of this storage is no longer functional? Are the developers responsible for maintaining their facilities and upgrading them and keeping them operating? I imagine this power is on a contract term. What thought is being given to the future when these issues become pregnant and important down the road? What will we be doing? Will efficiency eclipse these projects and be replaced with newer technologies? What's the long-term plan for maintaining this storage capacity as part of the portfolio in the years ahead?

I'll take a stab at that. So the storage projects are generally constructed with the benefit of a long-term contract from a load-serving entity. So it could be 10, 15-year contract pays over time for the developer to do the work to install the project, and after the expiration of that contract, if the facility is still operational and efficient, the contract could be extended.

Or if it has reached the end of its life cycle, a new contract could be entered into with a new developer, either at the same site or to replace it so that the ratepayers would be on the hook for that period of time under the contract and then a new contract could either support-- upgrade a new project or extension. And-- yeah.

And approximately how far-- what are these contracts for? Approximately 10, 15 years?

I think they're 10 to 15 years. Some for certain resources are longer than that.

Yeah, just add, so, you know, every single energy technology has an end date, and what you see is a gradual degradation. Like in solar, for example, it's typical to have a 25-year warranty and you're guaranteeing 80% of the nameplate capacity at the end of that 25-year period.

For storage, you know, what will happen is there will be a degradation over time, but it'll still function, and so, in the case of, if you have an EV, for example, that-- if you lose, you know, 15, 20% of your range, you will probably want to get a new battery.

For stationary applications for storage, there's not quite that same incentive because of just the energy density of the facility, and so, we don't know yet exactly how long these facilities will last because this is the first time really that utility scale storage has been scaled up at this rate.

I will say there's also-- what we're putting in there right now has just been predominantly lithium. Right now it's LFP lithium, but there are these other chemistries coming, iron-air and then sodium, which may last even longer, and then the flow batteries, like vanadium and iron chromium, have, you know, much, much longer life. They don't degrade much at all.

Thank you.

Vice Chair Patterson.

Great, thank you. Been taking some notes up here, and I just wanted to say that through the course of this conversation-- and I think there's always-- I don't think it's intentional, but there's this, I think, you know, misdirection where everything starts off with affordability, affordability being, you know, the most important thing, and then it's immediately followed by a bunch of ways we can make energy more expensive.

You know, in this conversation, you know, I've heard about, you know, moving away from gas, for example, is something that was brought up. And, you know, I'm not really sure on the legislative authority about that. In fact, there have been efforts here in the Legislature to do just that, and, you know, they haven't moved forward.

And I don't think anybody-- I think if that measure were to be put into the Legislature, it would fail resoundingly, but we use other legislation, and in an ambiguous way, I think, to be able to move forward with those sorts of mandates, and I don't think it's a good idea.

But, you know, even when I look at the CPUC's mission statement, it says safe, clean, and affordable, as affordable's the number three. The governor's press release announcing the new chair, the headline says affordability, but the first, like, three paragraphs are all about the transition to clean energy and I think there's some conflict on that.

I think the number one source of emails that I get in my office--and I do have actually an affordable utility, publicly-owned utility in my district, that we get emails there too, you know--but, you know, the number one source of emails is about affordability.

I think the number of emails I get on, you know, transition to, you know, 2045 or whatnot, it's like zero. I don't even know if I've ever-- I'm sure I've gotten some, but this is the number one issue facing people. The speaker has convened a committee and talked about it being his top priority as well. The governor says it's their top priority, but, like, the actions that follow don't actually prioritize that. We say it, but we're not doing it.

And so, I have a lot of concerns about that and I could go over more of those, but I'm just curious, if you wouldn't mind, President Reynolds, and maybe you'll be happy this is the last time that you have to come up here, but--and congratulations on going maybe to greener pastures, I don't know--but in terms of the gas and transition from natural gas, how has the PUC looked at how that impacts affordability?

Yeah, I appreciate the question, and, you know, I think you're right. We do need to continue to think about affordability as a foundation for everything that we're doing. Of course, then what happens is we'll wait. There are these other important priorities that we want to further, and aren't you taking those into account, but they all have costs.

And so, what we do is pay very close attention to legislative direction and implement that in the least-cost way to ratepayers. And there is a cost. Ironically, a lot of the costs going on the system now are climate change-induced costs.

Because of the conditions we're facing in the state, we're at the front line of climate change impacts with the catastrophic wildfires we've been seeing. We have a system, especially the large IOUs that runs into very rural areas, wildfire prone areas. A large percentage of IOU territory is in high wildfire threat risk areas, but the utilities have to serve the customers there.

And when a storm comes, even the past storms that we recently had in the Sierras, the utility infrastructure is impacted and needs to be rebuilt. We also have to do-- the utilities need to do, as Director Thomas Jacobs mentioned, risk reduction from wildfires, and there is a huge cost to that.

There's a lot of pressure now to underground, which can be an effective way to avoid wildfire ignitions. It's also very, very expensive, especially in rural remote areas. And so there is a balance that we do.

We have fantastic input from the ratepayer advocates and other-- ratepayer advocate's office and other ratepayer groups that we take into account in our proceedings and work to make sure that everything we do reduces costs as much as possible, but there are costs going into the future and those are borne by ratepayers.

Well, thank you for that. You know, I will concede that a lot of the regulatory decisions that you have to make are a result of legislation that has passed out of this building.

And you know, I think that that's an important thing and why I've supported legislation that one of my colleagues on the other side of the aisle has pushed forward to say, hey, when we consider policies in this committee in particular, that it should come with sort of like a CHBRP like we do in the Health Committee, you know, about how much that's going to cost the ratepayers.

Because how am I supposed to vote on something on the transition to clean energy, or building more transmission, or this type of transmission or that type of transmission, you know, when it's going to have a certain impact on ratepayers? And, you know, we've had some discussion about the location of offshore wind and things like that, and you know, it's a good discussion to have, but, you know, it's quite possible that building offshore wind in one location might be more expensive than the other, you know?

And so, you know, to even say, hey, we should prioritize maybe local wind, which I sort of agree with the philosophy behind that, but it might be more expensive than actually other options if that is out of state, include transmission this direction. So I think it's really important we look into those.

But I did want to ask one more question to you, President Reynolds, about the renewable energy, and I think there's an order out there, or maybe proposed order about 6 gigawatts of renewable energy, and I'm just curious what that does. You know, how does that help with affordability having an order like that? How does that impact the markets? And is the goal there to reach those 2045 goals or how will the PUC consider affordability with that proposed order?

Yeah, the proposed order is meant to be a step in the iterative process that leads towards the 2045 goals, and it's an instruction for all of the load-serving entities to go out with solicitations to get the lowest cost resources to meet what we see as the need for the growing load and reliability, including looking forward to winter peaks and the CEC's load forecast.

So to the extent that we're seeing load growth too, there's also a need to meet that with resources. The order does include a specific allocation for procurement of certain attributes that we know we're going to need in the future, and those are long lead-time resources, including geothermal.

So clean, firm resources, geothermal projects would qualify in long-duration energy storage to try to make sure that our system is being developed in a way that will have the attributes we need as we see less and less gas use.

The gas plants are still providing service to the system, especially in constrained times when we need them for reliability, but they're running less, and in order to meet the goals of the state, we expect them to continue to run less and less as we get a reliable portfolio of resources brought online.

Thank you. And I'd like to say that the 2045 goals is a legislative-driven mandate, correct?

That's correct.

Okay. So just wanted to say what we do here is pretty important to how that-- to what you're doing and what the costs that show up on utility bills as well. I have so many more questions because I-- you know, the Chair, you know, I know she's given me a hook at some point, but-- so I'm going to just make a couple statements, if you don't mind, and then I have one question for the Public Advocate.

But you had mentioned, sir, about the utilities bills, you know, EVs and things like that. You know, the utilities, there are a lot-- most of the bills fixed costs, I think. Am I paraphrasing you correctly? You know, I'm not disagreeing with what you're saying, although, as we, you know, bring more data centers online, more electric vehicles, obviously we need to put in those fixed costs to build more infrastructure, right?

So maybe-- so I sort of get what you're saying, but if we have to build infrastructure to get those, you know, fixed costs in the first place, those are obviously going to be, you know, borne by the ratepayers. And if you want to add anything to my rant, feel free, but was I crazy to suggest that there-- it's not expense-free when people-- you know, you get the electric vehicles and then you're obviously-- the data centers, and whatever we need to meet our needs here in California.

Yeah, it depends on the load. So for EVs, they looked at that pretty extensively and that is, you know, widely considered to be a downward force on rates. I think we've gotten something like 8 or 9 billion dollars of EV, people buying electricity for their electric vehicle that's coming into the electric system, and there are some distribution system upgrades in some cases, but on balance, it's still a net downward force.

I did want to just-- if I could, add one additional comment to your earlier point. You know, the way, I think, we can think about renewables, in part, it's actually insulating us from the volatility in fossil fuel priceback. So if the country, for example, goes-- we begin exporting a lot of LNG, right, that will affect domestic gas prices.

And I think one of the big advantages we have with resources like geothermal and wind and solar, there's no fuel cost. The cost, as you point out, is all upfront, but once you've built that, you're not then subject to the volatility that we see. So I do see it as a kind of insurance policy in that sense.

One question for the Public Advocate, if you wouldn't mind, and thank you for that. I have about 30 questions here, but I'll just limit it to one, one really long 30-part question. You know, I appreciate the work the office does, obviously, trying to keep rates low, and, you know, I could go on about that for a long time, but, you know, some of the significant things that, you know, we do, we can-- a lot of these decisions are driven by the Legislature in terms of the rates, for example.

We could do things right here, whether it's expedite transmission, you know, cutting some red tape around that, and so some of the costs, you know, are decisions that we make here, as I've kind of already talked about.

But you had-- I just have this one question, and that is, we have a lot of-- you mentioned inefficient programs that could maybe be eliminated or programs that aren't really used, you know, public purpose programs and things that could be eliminated from rates. Is that correct or--

Let me clarify.

It was on your slide.

Yes.

Yes.

It's policy lever three, thank you. But I want to clarify that there are public purpose programs that provide great social value. We are not here to say they should be eliminated, but what we are here to say is that perhaps there should be different sources of funding, that electric ratepayers shouldn't be funding these programs or they should be reformed so that they are cost-effective and providing value to electric ratepayers. But I want to be clear, we're not advocating for elimination of programs. It's the funding that we're focused on.

Well, if you have suggestions on maybe inefficient programs that should be eliminated, I don't think that's a bad thing, you know, to mention. But that is an important point because we are putting a lot of bill-- a lot of important programs, whether it's wildfire, which is important--you know, I could name probably a million other programs that we put into the electric bill some way, not quite a million, but we're getting there--and there should be maybe discussion.

I think there has been, but more discussion about whether that should be a General Fund obligation rather than a bill that's put on to ratepayers, because it is a public resource or whatnot. And I'll ask you offline sometime about, you mentioned reverse subsidies or having to-- it was another point on your slide about--

Oh, incentives.

We can talk about that later. I'm very curious about that, but in the interest of time and my chair, who will yell at me later if I don't-- I'll ask you later. But thank you very much for everybody's time.

And actually, I just-- I have a bit of a comment, because as you said, a lot of these goals have been set by the Legislature and the agencies before us are implementing legislative intent, and so I think your question is a very important one.

So in the face of soaring utility bills, in the face of growing concerns about California's cost of living crisis and our full-throated commitment to driving down costs, why are we doing this, right? Why are we continuing to work to build California's clean energy future? Why don't we just throw that all out the window?

And I guess I think it's really, really important to remind all of us that this is not a nice to have. It is not a nice to have. The inconvenient truth is that the climate crisis is real and it's not just dangerous; it's really, really, really expensive.

And so, like we can either continue to spend untold billions of dollars investing in wildfire mitigation, untold billions of dollars rebuilding communities that burn to the ground, or we can make generational investments to build a clean energy future, which I guess the bad news is, that's expensive right now.

The good news is that we are making investments that are actually driving down costs in addition to cleaning our grid. But I think, the point I'll really agree with you on, and I know conversations we've had in this committee, I think we need to be really honest about the challenges and I think we need to be clear-eyed about the trade-offs because we're not in a world where we can set ambitious goals and wave a magic wand and deliver on that.

And so, I think it's a super important conversation and we need to make sure that we're continuing to make progress, but doing so in a way that is building an energy future for California that is sustainable, reliable, and absolutely continues to be affordable. So more to come. Okay, let's see. Assembly Member Zbur.

Thank you for your grace. I have just one additional question. A question came into my office that I neglected to ask before and it relates to the decarbonization zone pilots. One of the questions that's coming in is whether or not those tracks, the pilot zones, are going to be purely residential or commercial.

I'm reading the discussion and it looks to me like they are census tract zones that would include both residential and commercial entities in those. I think the concerns that are coming into the office are, you know, when you look at electrification of single-family homes and residences, you know, all the technology's there.

It's a question of sort of how you sort of pay for conversions, all of that kind of thing. With respect to commercial entities, it's more complicated, and of course, you know, people are afraid of the fact that if you're in a zone that at some point the gas is going to be shut, service will be shut off.

So there's concerns out there. So I just wanted to see if you could sort of talk a little bit about how you're dealing with this. And you know, this is coming from someone who is a big proponent of electrification. I think we have to-- it should be a priority.

You know, I think the bill is a good bill, but that set of concerns is out there with respect to sort of commercial entities. I was just wondering if you can talk a little bit about sort of how you're thinking about that in terms of making those decisions in the pilot program about, you know, eliminating service.

Yeah, I'll say that we have been focusing a lot on residential just, you know, how to make this work for residential customers. These are their homes, we need to make sure they transition, and of course, the benefit of avoiding an upgrade and using the costs in that way.

I'm going to have to get back to you on how we're dealing with the commercial side, and I'm not surprised that the zones include commercial, but I'm not sure the pilot would actually include commercial, and so let me get back to you on that.

Really appreciate it. Thank you, Madam Chair.

Assembly Member Papan.

Just very briefly to follow up on my colleague from Santa Rosa and the concern about whether wind brings a good economic impact, I thank you very much to our chair from the CEC for this diagram that is color coded, but when I see geothermal--and it has a certain color to it--I don't see anything in the chart that reflects since 2019 we've done anything to increase the geothermal, which as we know, comes from Santa Rosa.

So if we're looking at ways in which we're going to advance our renewables, and wind may come from that area, geothermal comes as well, and I just don't see enough progress here. So I'm just making a pitch. It's really not a question.

But when we've got two forms of renewable that could come from a particular geographic location, I'd love to see it increase. I think it's a win-win economically and I think it's a win-win from our renewable goals. So I'm making my geothermal pitch because it seems to overlap with where wind is come from as well.

If I just speak really briefly to that, so you know, what's been happening, as you know, is solar and storage have been winning on price--

Wait, did I get the color coding right, though?

Yeah-- no, you're right. Very little geothermal, but part of-- you know, it's been-- to President Reynolds point of trying to contain costs, but the one thing to note is that geothermal, unlike the other renewables, did not lose its tax credit. So that continues and that will probably help the economics.

There were three projects that we had in the permit pipeline at the Energy Commission down in Salton Sea from Berkshire Hathaway. Those got put on suspense. We're working with them and we'll see if those can get restarted, but I think the tax credit continuing is a good thing.

All right. I have a handful of questions, and just being mindful of the time, I'm going to try to do rapid fire questions and then hopefully rapid fire answers. We can begin public comment in about 10 or 15 minutes.

All right. So the SB 100 report, that was due a year ago, so I believe you hosted a joint agency workshop last week on that. When can we expect it, what's been the delay, and-- yeah, help us understand what's happening.

We'd like to apologize for that. This is the first SB 100 report we've been laid on and I want to own this is a very complex interagency process. In this cycle, there were some especially complex dynamics with data centers, and we felt, you know, more important to get it right than to get it done quickly.

Having said that, the draft is now out. We're taking public comment on that and that's available, but I do want to apologize. That's, you know, really not what we aim for. We've been pushing hard, so I want to own that.

Okay. So we will, I guess, look forward to that once it's finalized. I have a question for Director Serizawa. So we talked about-- you talked a bit about the proliferation of balancing accounts that we've seen in recent years, and I know that that has been a big area of focus for the PAO with, I think, somewhat mixed record of success. What more would you like to see in terms of the actions needed to rationalize balancing accounts and what actions do you need from the Legislature in order to make that happen?

Yes, thank you. Thank you for that question. And actually, it's-- I would clarify, it's balancing accounts and memo accounts. And actually, I'm going to focus specifically on memo accounts because memo accounts, to us, they shift risk away from the utilities onto--this is how we look at it--they shift risk away from the utilities onto ratepayers.

And that's because they're usually employed for costs that are incurred outside of the general rate case process. And they traditionally--I've been around so long I can say this--there haven't-- traditionally there hasn't-- historically, there hasn't been that many memorandum accounts until the last 10 plus years.

The purpose of a memorandum account is to allow the utility that incurs a cost for unanticipated events, extraordinary events like catastrophes, like wildfires, mudslides, and they have to restore service, and may entail rebuilding infrastructure. Those are costs that cannot be forecast in utility GRC.

Those are reasonable in terms of establishing a memo account and allowing the utility to come forward to the commission and say, we incurred these costs, we should get reimbursed for them. Totally reasonable. We do litigate those issues and look at those costs as well.

But there has been-- and I'm going to dial back a little bit and say, primarily because of things like catastrophic wildfires, which, you know, if you go back to 2019, they were unanticipated. You could argue they should have been, but they were not anticipated, especially the scope and the scale.

And so, the Legislature saw that and said, okay, we're going to establish a mechanism that allows the utilities to recover those costs outside the GRC. Well, it's been several years now. That was 2019 when that statute was passed and it's time now to recognize that the utilities should be able to plan and forecast those costs.

And I think, like I said before, the Legislature has taken a huge step forward in allowing the PUC discretion. And I think that's the kind of model we need to see is the off-ramps, the recognition that, okay, we have to respond to a crisis, something that's an immediate challenge.

We're going to put in a regulatory mechanism like a memo account or a balancing account, but make sure there are off-ramps, that it's not perpetual, indefinite, et cetera. And reassess, reassess those memo accounts.

And I think the Legislature, particularly this committee, has authored bills that requires the commission to take a look periodically at certain accounts to see, are they necessary. Again, that's an important off-ramp. I hope I answered your question.

You did, yes. Thank you. All right. So, we've been recently--and I think I've mentioned this to some of you--I've heard from a number of load-serving entities about their sort of confusion and consternation regarding what is going to count as clean in a post-RPS world.

So, I think post-2030, we have a definition, or we have a goal by 2035 that LSEs are supposed to procure 95% or 90% clean resources. But those haven't actually been defined, and that is, from their perspective, creating some confusion and ambiguity and perhaps actually leading them to create-- to enter into suboptimal contracts focusing on just a really small, limited set of resources.

So from your perspective, what needs to happen to--and I'm curious to get everybody's view, or CEC and PUC view--what needs to happen in order to define what qualifies as clean? Should there be ambiguity?

I think the term is zero carbon. Right. And so we've been. Yeah. So just kind of to me that adds a little bit more clarity of, you know, resource that doesn't produce carbon emissions.

Clearly gas plants would not count and we have a, for IRP have the portfolio of resources that is based on what will get picked up at the modeling. So for instance, carbon capture and storage is not an input. It's not an eligible resource in IRP modeling. But that's largely because it has not shown up as cost effective.

And so we haven't done the work to start to analyze it and think about how we would consider it to be eligible for the process. We are going to be looking at that and we say that in our, the proposed decision to look at, you know, should we consider it? How would we consider it?

And so that process could be used to further define and provide clarity. So there are many options. We also have a proposal out on a renewable clean resources plan that would kind of provide an umbrella over our resource adequacy and IRP and marry that with rps that would provide more certainty to the load serving entities.

So we'll be continuing to ask about that and develop it and see if that could be a useful tool.

Yeah, I would just say for some reasons like nuclear large hydro, I think it's not so complicated. I think there were issues we had, if you remember, like the Ivanpah project, the solar thermal, they had to pre fire that boiler with gas to get it up to temperature. So for a renewable facility there.

So do you count that? Those are the kinds of questions that had to be to be worked through. But I think you hit the main points.

All right. I'll also say, you know, maybe the more helpful framing is that GHG target which is geared towards the CARB scoping plan and you know, that could provide a framework of like look lses you have to meet that target which would deal with these issues where there's potentially a small amount of gas involved in a resource.

Okay, so, and just so I make sure I understood so what you said about the IRP process. So just because some things a resource isn't showing up in the IRP doesn't mean it does not qualify as a zero carbon resource.

In many cases you would never have emergent technologies showing up in that because they've yet to be demonstrated as cost effective. So. All right, thank you. I think there's more conversation needed on that this year, but we can follow up as the year unfolds. Okay. With that seeing no further questions from Committee Members.

I'll once again thank all of our panelists for joining us today for all of the work that you do for California and look forward to continuing to partner with you to build California's clean energy future. With that, thank you so much. And I think we'll move to public comment at this point.

So for anyone who would like to make public comment, please approach the microphone and we'll go ahead and allow everyone one minute. And that should give us sufficient time to dive into the second part of our doubleheader.

Madam Chair, Member Scott Wetch on behalf of the California Coalition of Utility Employees, the State Association of Electrical Workers, California State Pipe Trades Council and the Western States Council of Sheet Metal Workers. I'm sorry, I do not believe a clear picture was presented to you today.

It was made to appear that all of the out of state generation in the IRP is somehow this long term plan. In the 15 year window they have planned for 33,000 megawatts. 33 gigs of out of state Nevada, Arizona, Wyoming, New Mexico power. 17,000 megawatts is phantom power.

I would urge the Committee and the Members to demand from the PUC that they document where they believe this 17,000 megawatts exists because everybody in the industry is scratching their head. It's illusionary. Second of all, last year we supported your Bill.

Madam Chair co sponsored it to create pathways because we were told that we absolutely had to have control of our reliability in instances where we have constraint in the West. All that 33,000 megawatts in the next 15 years is outside of pathways.

There is no guarantee that when we need that power in California we're going to get it. It flies in the face of the intent of your Bill. Thank you. We'll be circulating some additional information and we really hope that the Members focus in on this issue. It's critical. Thank you. Thank you

Madam Chair and Members. Jim Wood representing Golden State Clean Energy. I do want to note two years ago when I sat on that dais, I asked CAESO a question about how stranded assets and overbuilt. When was the last time that happened? The answer was 1920. So I don't know what's changed, if anything's changed.

But keep that in mind as you start looking at transmission. Very concerned about a third of our power procurement coming from out of state when we have projects in California that could get going. This Legislature passed a Bill AB 2661 signed by the Governor to promote solar power in Fresno. And the IRP doesn't reflect that.

And CAISO reacts to the IRP. So we have a problem here. Part of the. In addition to the phantom wind that my colleague was talking about, we have wind projects in California that have been not. Not been approved yet. We're going to acquire wind from out of state. I have a problem with that. Thank you. I'll just.

One second. Transmission build out takes 12 to 14 years. Anything you can do to shorten that time reduces costs. And I don't believe that's being considered in the CPUC IRP process. Thank you, Madam Chair.

Thank you.

Good day, Madam Chair and Members. Hunter Stern with IBEW Local 1245. We have a number of our Members here who are also going to address you. Just as the previous two speakers said, we do have great concern about what you were told around the IRP and its future. We appreciate the questions that you all asked.

I'm not sure that you got good or full or accurate answers. That Bill 2661 has been approved both by the Legislature by the Governor and now Westland's water district has an approved project. We need CAISO to approve it so that we can build it and provide 10 gigawatts of electricity to California from California.

And it is, as it was said, it's not in the RP, but we need that approval. So there are things that are that we can do much better both in the near term, the midterm and the long term. And we hope you keep asking these questions of these agencies. Thank you.

Thank you.

Good morning, Assembly Members. My name is Al Fortier. I'm a journeyman lineman by trade and a Member of IBEW 1245.

And I'd like to speak in opposition to the IRP largely due to the loss of hundreds of thousands of jobs, potentially for high-paying skilled workers in California, and based on the speculative nature of the reliance on out-of-state power procurements. Thank you.

Good morning. Liz McInnis. I'm also an electrical worker with Local Union 1245. And I also strongly urge you guys to oppose IRP. We need to keep those jobs in California. Thank you. Thank you.

Good morning. My name is Mayra. I'm from IBEW 1245 and I if you can please oppose CPUC's IRP. It will take 400,000 jobs from California. Thank you.

Thank you.

Good morning. Rosa Montano with IBEW 1245 and I just. We ask that you oppose the CPUC's IRP to maintain as many jobs as we can here in California.

Thank you.

Hello, Assembly. I'm Tito Ayala. I'm also with IBEW 1245. I'm more on the line clearance sector for IBEW.

And we strongly oppose this Bill that's going to affect our members, lose jobs for our membership and it could be over 400,000 jobs that we could lose that California we did here in California, not exporting it out from other states. Let's keep it California and strong. Thank you.

Good morning Assembly. Marina De La Torre, IBEW. Please publicly oppose the CPU is IRP that will export 400 of our California jobs. Thank you for your time.

Thank you.

Hi. Karina Duran, Member of IBEW 1245. Please publicly oppose CPUs IRP that will export 400 California jobs. 400,000. Thank you.

Thank you.

Jesse Green, Journeyman Lineman, IBEW Local 1245. We oppose the Bill and we want to be an exporter of power, not importer and keep our jobs here. Thank you.

Albert Jimenez, also IBEW 1245. We ask that you guys publicly oppose the CPUC's RP plan and keep those 400,000 jobs here in our home California. Thank you.

Thank you.

Good morning. I'm John Sandoval with IBEW 1245 and I just ask that you guys publicly oppose the CPUC's IRP that will export 400,000 jobs outside of California. Thank you.

Thank you.

Good morning Assembly Members. Unfortunately Mr. Rogers isn't here. I want to express my appreciation for his concern for jobs in his district. I too, Steve Lange from IBEW Local 1245 ask you to publicly oppose the CPU IRP at the risk of exporting hundreds of thousands of jobs. Thank you.

Thank you.

Good morning. Todd Kadota, also a journeyman lineman with IBEW 1245 and I wish you would oppose the CPUC's IRP to keep the jobs local in California and the energy production here also. Thank you for much.

Thank you.

Good morning. Charlotte Stevens, a proud 15 year Member of IBEW 1245. We do oppose the CPUC's IRP. We will need the CPUC IRP to reflect a strong commitment to California produced energy that supports jobs here at home and in state economic growth. Thank you.

Thank you.

Good morning Assembly. Ethan Stonecipher with IBEW Local 1245, Journeyman Lineman by trade, currently here to ask you to oppose the CPUC IRP in its current state. Thank you.

Thank you.

Good morning Assembly Members. My name is Rey Mendoza. I'm also a Member of IBEW Local 1245. I'm here just to express my opposition to the CPUC'S IRP due to the expected the huge expected job losses. Thank you.

Thank you.

Good morning. My name is Rick Thompson. I'm with IBEW Local 1245. I'm here to urge you to oppose the IRP for for the concerns raised by Assembly Members Zbur and Rogers. Thank you.

Thank you.

Morning. Francisco Ferreira, IBEW 1245, Journeyman, Arborist by trade strongly oppose the IRP. This is definitely going to affect the hundreds of thousands of Members.

Good morning, Chair Members. Vince Wirratmadja with MCE, California's first CCA. We appreciate the focus today on the biggest cost drivers of rates, but we did hear some comments about EE and PPP that we just wanted to provide some context for ahead of the program's hearing.

We would argue that these programs have a very strong nexus with respect to utility rates. According to the July 2025 PUC report on demand side programs, the programs, number one, make a tiny percentage of the Bill, less than 5% for EE and electric side and gas side of the Bill.

And then two, the CPC specifically said that the low impact of these rates provides low cost to equitably achieve cost savings for customers and reduce total energy consumption and peak demand, which in turn reduces retail rates through lower energy prices and avoided capacity, transmission and distribution costs.

In short, the EE programs and the PPP funding for them drive down retail rates and do need a reliable and steady funding mechanism. Looking forward to the conversation during the dedicated hearing. Thank you.

Thank you.

Good morning, Madam Chair. Mike Monagan, on behalf of State Building Trades, we have a long history of supporting renewable projects, including offshore wind, and a recent project up in the north that was onshore and was not approved by the CEC. Second of all, there's a long history of legislative policies that pair climate goals and California jobs.

And we think that the IRP, the proposed IRP, is a departure from that legislative policy. Thank you.

Thank you. Well, thank you everyone again for participating in today's hearing. That concludes the first hearing of the day. We are going to take a five minute break and then we will regroup at 11:45 to commence our oversight hearing. So stay tuned.

Welcome back. We are now Transitioning to our second topic for the day, an outcomes review of AB 2316 authored in 2022 by Assembly member Ward.

The outcomes review is a recently initiated process from the Assembly Speaker's Office and an important opportunity for us to provide legislative oversight and ensure that bills are being implemented in a manner which is consistent with both the letter and the spirit of the law.

So to begin today's hearing, I am pleased to welcome the author of the Bill, Assembly member Ward, who will provide us some brief remarks to remind everyone of the goals of AB 2316 and what the Bill was intended to do. So welcome, Assembly member Ward.

Well, thank you Madam Chair and Committee Members. I really appreciate being here and I appreciate, I appreciate the speaker for flagging AB 2316 which I authored in, as you said, in the year 2022 with a number of important policy outcomes that we wanted to be able to achieve, but also in line with California's direction.

We wanted to make sure that the California Public Utilities Commission would help us create a community renewable energy program which would prioritize some access for community solar for renters and other low income households.

The Bill was intended to create a mid scale community solar program so that all Californians, especially those unable to host a rooftop system, could realize the benefits of a distributed energy system through a cost effective program which would provide benefits to all ratepayers.

So when Bill passed and then In September of 2023, I partnered with 20 of our legislative colleagues in the State Legislature to pen a letter to the PUC outlining our support for the net value billing tariff put forth by the Coalition for Community Solar Access and supported by a wide group of parties.

In the letter we made it very clear that the net value billing tariff proposal most closely aligns with the intentions of AB 2316 and we felt that this proposal one, was the most cost effective.

Proposal two, expanded access to California's most vulnerable residents by mandating that at least 51% of each project for low income would go towards low income customers. Three, minimize rate impacts to non participating subscribers and four, quickly deployed solar powered battery projects which would provide power when our grid needed it the most.

Now unfortunately, the decision that was adopted by the Commission is wholly inconsistent with AB 2316's outcomes and it rejected the community solar model in favor for another proposal. This decision represented a dismissal of California's need for clean, reliable and affordable energy and after agreeing with nearly all stakeholders that the state's existing community renewables programs were not workable.

The proposed decision opted to repeat some of the past mistakes by creating an outdated commercially unworkable program that would result in no new renewable projects or energy storage to date. That leaves us without the untapped potential of 5,000 megawatts of carbon free energy. The projects aren't there, the Bill credits aren't there, the prevailing wage jobs aren't there.

And I must also reiterate the immense potential of community solar to provide a lower cost options for California housing developers who are trying to meet Title 24 compliance and a rapidly increasing need for housing production.

The California Building Industry association estimates that 250 to 400 megawatts of community solar would be needed each year to meet builders needs under the regulations. And this number will only rise as higher requirements are expanding.

And they further estimate that one year of new home construction using net value billing tariff projects could save between 102 and $419 million. So as a Member of the Assembly's Budget Sub committee 5, these are the kinds of common sense cost saving measures that would help alleviate the deficit while preserving funding for vitally needed programs.

And I think we'd all agree as a state we must rapidly accelerate housing production in order to address the growing housing and homelessness crisis. And without a viable cost effective option for Title 24 compliance, housing costs will only continue to rise.

So I'd assert that the solution that was adopted in 2023 was fatally flawed, resulted in no new projects being built, and therefore is inconsistent with some of the Title 24 mandates.

California is a leader in solar adoption and we have to get this right as community solar has incredible potential to reduce rates across the board, reduce net peak demands, avoid long transmission investments, displace expensive gas generations and be built quickly.

So I'm looking forward to the presentations here today to dig into some of the decisions that surrounded the decision which was made and provide us some, through oversight, a little bit of direction about how the Legislature might be able to respond and try to put this back on the right track. Thank you Madam Chair.

Thank you, Assemblymember. At this point we'd like to welcome Kerry Fleisher who will be providing us with an update on the implementation of AB 2316. Ms. Fleisher is the Director of Distributed Energy Resources at the California Public Utilities Commission. Welcome.

Thank you. Chair Petrie Norris, Assembly Member Ward and Members of the Committee. My name is Kerry Fleisher and I am Director for Distributed energy Resources, natural gas and retail rates at the California Public Utilities Commission. I am pleased to present today on the implementation of Assembly Bill 2316.

Before I start, I'll highlight that the CPUC's Community Solar Proceeding is an open proceeding. It is currently in the deliberative phase on the remaining issues in scope, with a proposed decision anticipated in the next several months. I cannot share information about what may be in that proposed decision, which is protected by privilege.

To begin, I would like to provide some of the key context around solar development in California. As you're all aware, California is number one among states in terms of solar capacity on our electric grid.

There are solar generation projects of all sizes connecting to our electric grid and we expect thousands more solar projects to be built in California over the coming decades at all scales to meet our clean electricity targets.

Since 2020, the state has brought online over 9 gigawatts of new solar nameplate capacity in the CAISO balancing authority plus an additional 2 gigawatts of hybrid solar plus storage resources.

Between now and 2029, our retail electric providers are reporting that they will bring online an additional 5 gigawatts of solar and over 4 gigawatts of paired solar plus storage resources and we expect that number to rise as they continue to execute contracts to reliably serve their loads and meet procurement requirements.

Costs for these projects are kept as low as possible since load serving entities which include investor owned utilities and community choice aggregators typically issue competitive solicitations for these projects and receive bids from developers who locate projects where the economics make the most sense, which is usually on the transmission bulk grid.

This type of competition is economically efficient, results in low cost power purchase agreements and makes electricity bills more affordable for ratepayers since it's ratepayers who pay for this electricity on their bills. Every month

There are cost effective small scale solar and storage projects being built throughout California and brought online to serve homes and businesses through this competitive framework. Community solar is a concept that has evolved over time to mean different things depending on the context. As presented by stakeholders in the record of the CPC

Community solar proceeding that implements AB 2316 community solar typically refers to a solar array interconnected at the utility distribution level and that primarily exports power to the electric grid without supplying electricity on site.

This type of physical solar project is not new in California and in fact there are many projects in California that have these attributes and compete in our markets. What's different here is that in the community renewable energy program called the CRE program, solar developers can receive a guaranteed administratively paid price for these systems regardless of location.

As we implemented AB 2316 we have drawn on CPUC's long history of experience in this space to improve our existing community solar programs for low income customers and to establish this new CRE program consistent with statute. As you are aware, AB 2316 require the CPC to carry out three mandates.

First, evaluate existing renewable energy customer subscription programs and determine if they efficiently serve distinct customer groups, minimize duplicative offerings and promote robust participation by low income customers.

Second, either terminate or modify any existing programs that do not meet those criteria and third, determine whether it is beneficial to ratepayers to establish a new community renewable energy program consistent with requirements in the Bill including minimizing costs to ratepayers who do not participate in this program.

I want to note here that these statutory provisions are to a significant extent similar and consistent with the broader objectives and principles that guide the CPUC's work.

They require the CPC to closely monitor the Bill impacts of our programs on both participants and non participants and make sure that we use ratepayer funding as efficiently and effectively as possible.

In response to AB 2316, the CPC adopted a decision that preserved and expanded our existing disadvantages Communities Green tariff program called DACGT, which is a community solar program administered by three investor owned utilities, PG&E, SE and SDG&E, as well as 11 community choice aggregators such as Peninsula Clean Energy and Marin Clean Energy.

This program allows low income customers living in disadvantaged communities to subscribe to community solar projects and receive a guaranteed 20% discount on their monthly electricity Bill. The decision also maintained our green tariff shared renewables community solar Program with modifications to improve its design.

This is a program that allows any customer, regardless of income as well as commercial entities to subscribe to a pool of community solar projects and the decision also adopted a framework for a new community renewable energy program, the CRE program that allows low income customers, moderate income customers, renters and commercial customers to directly subscribe to an individual community solar project while creating a mechanism to capture external funding.

The specific implementation details for the CRE program are underway as directed by AB 2316. The design of the CRE program will not result in Bill increases for non participants. This was a key prudency provision in the Bill. Accordingly, the CPC set the amount of compensation for solar power exports to the grid at cost avoided by each project.

Consistent with AB 2316. The program design also ensures that low income customers receive at least 51% of each project's capacity and we designed this program so that these participant customer Bill credits can utilize non ratepayer funding to avoid putting Additional upward pressure on electric rates and customer bills.

As you are all aware, the CPUC, in conjunction with other state agencies, pursued a Solar for All Federal grant administered by the EPA and we were successful. California was awarded $249 million right around the time our Community Solar decision was adopted.

Like most federal grants, this one had specific requirements for how funds could and could not be utilized, guidance that the EPA was still finalizing and updating after we received the award.

Since all grantees still needed a second round of approvals from the EPA before programmatic funding was made available to ensure compliance with the EPA's evolving requirements, the CPUC issued two rulings to develop the procedural record with stakeholder input on how we could best comply with EPA's guidance, such as their methodology for how to calculate 20% household savings and their five year spend down requirement.

Then, as you're all aware, in August 2025 the Federal Government abruptly terminated our 249 million Solar for All grant along with other awarded Solar for All grants on the alleged basis that this was required by the One Big Beautiful Bill Act.

We in partnership with the California Attorney General and a multi state coalition, contend the termination was unlawful and we have sued the Federal government to challenge it. That litigation remains ongoing and while we do not currently have access to the $249 million, we do not yet know what will occur.

In spite of this uncertainty, we are proceeding to implement the CRE program and we are finalizing implementation details and anticipate a proposed decision in the next several months.

The proposed decision by the Administrative Law Judge will be based on the record of the proceeding which consists of all the stakeholder comments we have received on how to implement this program consistent with all elements of the statute and EPA guidance. Thank you for the opportunity to talk about AB23 implementation. I look forward to answering your questions.

All right, we'll open it up for questions from the Director, Assembly member Zbur.

So first of all I would like to thank you for being here.

I'd like to thank Assemblymember Ward who was the author of this Bill and as I think he indicated, AB 2316 was written for the millions of Californians who live primarily live in multifamily housing, who cannot put solar on their roof and giving them an opportunity to do that.

That Bill required that at least 51% of the program's capacity serve low income customers. Wanted to ask how many low income customers are currently enrolled in the Community Renewable Energy Program?

Thank you for that question. So as I was mentioning we're finalizing the implementation details of the CRE program and we anticipate a proposed decision in the next several months. And once that all the details are finalized, that would start and initiate the program and the launch of that program.

We adopted a decision that established the framework for that program and then immediately afterwards we put out a ruling to comply and carefully design the program to be in compliance with EPA's guidelines for the Solo for All grant.

So that was an iterative process and that took us many months of back and forth at the EPA because we needed a second round of approvals and we had to make sure the program was designed to comply with all of the different requirements for prevailing wage requirements to how it calculated the Bill savings.

And so we're at a point now where the program, once this proposed decision is enacted, would be able to be fully launched.

So that basically means that there's no one currently enrolled in the program, is that right?

There's no one currently enrolled in the CRE program. However, as I was mentioning, we have a number of existing solar programs and many low income customers are participating in those programs. So we have the DAC GT program, which has been around for many years.

There are 100 megawatts of enrolled capacity customers right now are enrolled in accessing that community solar. We also have a number of other programs for folks who live in multifamily housing that don't have access to rooftop solar. For example, we have our SOMA program. We've had our MASH program, I think for over two decades.

We've had programs that amounted to over a billion dollars to go toward community and low income programs specifically designed for low income customers to receive Bill credits on their Bill.

I had understood that the DAC GT program was under subscribed, that the green tariff program was suspended. So I guess, you know, to try to put this in perspective for, you know, the people we represent, you know, let me ask a question.

From the perspective of the families that AB 2316 was written for a renter in Fresno paying $200 a month for electricity can't install a rooftop solar under the existing NEM program. Part of their Bill goes to subsidize their wealthier neighbors rooftop system. The public advocate's office reports that that cost shift is now $8.5 billion per year.

And AB 2316 was supposed to give that renter a way to subscribe to a community solar project and get savings on their Bill. So what does this renter in Fresno, what do the commission's programs provide for that renter today.

Thank you, I appreciate that question. I just want to take a step back and go back to the overarching framework for how we get electricity for all customers.

So we have an IRP process or integrated resource planning process in which all the load serving entities, the community choice aggregators, the investor and utilities, they seek PPAs and power purchase agreements to procure, at least cost, all of the electricity they need to serve their customers.

And by doing this, we deliver low cost solutions to meet our decarbonization and reliability goals. So I think that's first and foremost the way that we deliver the cheapest electricity we can to everybody. In terms of specific programs that are designed for low income customers, we have a number of programs that do that.

As you're all familiar with the CARE program, large number, I think over a third of customers in the investor and utility territories enrolled in this program and that delivers a 37% Bill discount on their Bill, on the volumetric portion of their Bill. So there are a number of ways to support customers in terms of Bill savings.

And again, as everyone spoke about in the last panel, there are a number of ways that we're scrutinizing all of the General rate cases and all of the costs that come through the commission to put downward pressure on rates. And, and there are many strategies to get there.

So I just want to make sure that big picture is, you know, clear because there are many different pathways to get to that goal.

Yeah, but you know, the CARE program though, you know, I think the intent of this Bill was to provide folks that were not, that are not in single family homes with the same opportunities to get the benefits of rooftop solar, you know, especially in given sort of this cost shift that we're experiencing.

And so, you know, obviously the CARE program is, you know, that's a limited number of folks, it's the lowest income people. You know, I guess, you know, I'll just sort of close and say that. Well, I guess I'll ask one final question.

I mean, when do you anticipate specifically that the, this process will be completed and the, the people that Assemblymember Ward's Bill intended to benefit will get the benefits of AB 2316?

I think that once the program is launched, it is really dependent on the developers coming forward and putting forward good projects that can meet and comply with the program design and then developers subscribing customers to those projects.

So I think once we finalize the implementation details, I would expect, as we've seen, developers have always brought us very low Cost projects and they move quickly. And so as soon as those projects come online and the program is set up, I would expect it to move fairly quickly.

Is that years, is that months? Years? I mean, when is this project going to be? When is it going to be the process going to be completed and then when, how many. What do you anticipate will be the timing in which the benefits of this program will be available to the public?

Again, I think that depends on the state, the, at what stage these projects are in. And I think there may be a lot of projects that are right now ready to go, like shovel ready, and then the end developers are ready to sign up subscribers. So I think it really depends.

It depends on the, the type of projects that we're seeing and the type of participants in the program. But you know, it could be, it could be a year or two. I mean, these programs always take a lot of time. Any program that we've designed to, to enroll subscribers does take some time.

You've got to get the administrative gears in motion and get everything set up. So it could be any, it could be months to year, a year or two.

I'm just going to close by just asking if you could get back to us with a projection, with more specific projections. I mean, this is a, that seemed like a pretty vague answer in terms of when the benefits from this program would be made available to the public.

And I'd like a more precise answer with some, you know, some information behind it when you anticipate the, the, the process will be completed and, and some kind of timeline for achieving the benefits of the Bill. So with that, I appreciate your time today and thank you for being here.

Yeah, happy to follow up with that information. Thank you, Assemblymember Ward.

Thank you, Madam Chair, and thank you, Assembly member Zbur for those questions, maybe tearing off of that and then I want to bring it all the way back in a couple of years. Notice here, the timeline July 1st of 2026. Is that the anticipated timeline for the, the completion of your work?

We expect a proposed decision that finalizes all the details in the next several months.

Okay, so I have been minutes July 1, but next several months would be great ahead of that.

But it seems that we've had some steps along the way that have certainly disappointed me as the author and many of our stakeholders that worked hard on this, the wide array of groups that had been working hard to really prove their point.

I'll get into the decision itself and then sort of also the implementation of that decision as well. And you know, Sort of these extension of timelines that have pushed it forward to the years that have passed since we ultimately the Legislature passed this Bill in the first place.

So walking it back a few years, to the best of your recollection, the Bill required the PUC to consider adopting a community renewable energy program that benefits all ratepayers and to have that established no later than July 1st of 2024. And then you did adopt the program. I remember because I was there.

I went to these proceedings in May of 2024. We know it's been over now 18 months since that deadline. What has occurred since then, that is, you know, continuing to be able to hamstring us from fully rolling this out. Why are we now heading into July 1st of 2026?

Thank you. I appreciate that question. The decision that adopted the framework, the one you were referencing, that you were at our meeting, that was in May 2024.

Immediately thereafter, in June 2024, we put out a ruling with a number of questions because we had just received the Soliferol grant and that external funding was part and parcel with the program design. At that point we were planning to distribute the $249 million.

And so we had a lot of details we had to work out and we really had to carefully design the program because if we weren't compliant with EPA requirements, we couldn't apply that funding. So we received stakeholder comment.

And then as you know, there's an iterative process with these federal grants and we were officially presented access to those funds in March of 2025. And just four months later, the Federal Government, we contend, unlawfully terminated that grant. And we issued another ruling along the way to collect even more details about the EPA program.

So there's been a tremendous amount of uncertainty in terms of the solar for all funding that was intended to supplement this program. And so there's been. That's part of the reason why this has taken longer than normal. This is something where we had a lot of interactions with the Federal Government.

No, thank you. I want to come back to that grant in a second because I'm aware of that. But, but staying on that timeline. So you released the ruling in June of 2024. You were asking very basic questions about how the program would work.

One question asked how Bill credits should be applied for low income and non low income customers. So why were these basic elements unclear when the PUC actually adopted the program? And specifically when was this version of the community renewable energy programs proposed in the proceeding? And who proposed it? I know there was nine Proposals that went forward.

That's right. I think you're speaking to the complexity and how large the procedural record was leading up to that 2024 decision. I believe there were three rounds of testimony, two rounds of briefs, several rulings.

And of course, the statute, as you know, it did more that did more than just say create a new community solo program, was also evaluate these other programs. And so it was a complex undertaking. And so this led to a decision that did several things.

As I mentioned earlier, it streamlined existing programs, it established the framework for these new programs. So I think the administrative law judge, looking at that evidentiary record, was able at that point in time to establish those elements of the program. But there were some elements that needed to be. We needed to build more record on.

And do I recall this correctly, that the original proposals post this adoption that they were due in one area I'd give the PUC credit for is I believe that, you know, they saw this coming and prior to though it wasn't in effect and fully enacted until January 1st of 2023, you got to work certainly when the Governor had signed it and knowing that this was coming and you were asking for proposals by January of 2023, is that correct?

I don't recollect the exact date, but that sounds roughly right.

Okay. And so kind of what you just said, sort of tearing off what you just said earlier, you know, we had the commission adopted a program in November of 2023, which was 11 months after, you know, sorry, the adoption date was in June of 2024. Right.

But that proposal that you received was in November of 2023, which was long after, I think, the initial request for submissions for that proposal. And then there was a ruling that asked specific questions about a completely different proposal. The Net Value Billing Tariff, NVBT.

How much time did other parties really have to be able to respond to the proposal that was ultimately selected? It came really fast in the end.

I can't recollect exact timelines, but I do know that elements of that program. From my understanding, the program that we did ultimately adopt was based on the REMAT tariff and wholesale rates for electricity. And that concept was put onto on the proceeding record earlier in the proceeding. So I'm trying to track.

But it sounds like you're referring to a very specific proposal.

One of the things that frustrated us at that time is that others have been playing by sort of initial rules. And I understand new information comes and just and things change, but based on something that was economically feasible that would meet the intents of the Bill that would serve the Californians that we want to serve.

You had a proposal that was out there and sort of, you know, beyond the 11th hour, you have another proposal that comes forward that gets in there and is now under consideration, fine. But because of that, how much realistically time was there for discovery, for cross examination, for other rebuttals?

Do you really feel like that proposal achieved the proper vetting that it would have been able to achieve relative to other proposals that had been publicly submitted, like, you know, for months prior?

Our administrative law judge in the case, in this case, looked at the entire record before them and wouldn't have moved forward and put out the proposed decision if they didn't feel like they had presented all the opportunities to the party for due process. That's something that obviously we look at when we establish these procedural processes.

So I think the administrative lodges, based on the record that was before them, felt that this was an appropriate landing point for the decision.

I remember that moment. I think we were also asking for more time for the chance to be able to fully and more appropriately analyze some of the later submission proposals, one of which was ultimately adopted as the one to go forward. Back to my preferred proposal, the net value billing tariff.

It, it had broad support and that was on the record turn. Coalition of utility employees, renewable energy industry, environmental, environmental justice organizations, the building industry groups, they all showed that this proposal met the requirements or potentially just needed minor modifications. Why did the PUC determine that?

And maybe if you can reflect on the old judge's ruling that they were wrong.

Thanks for that question. So the proposal, the NVBT proposal is based on a framework whereby the solar projects would be compensated at the avoided cost calculator.

And in the decision that we adopted that created the framework for this program, the decision speaks to the fact that that ACC avoided cost calculator is not the right fit for compensation because it would lead to a cost shift for non participants. And the reasoning is because load it is designed for.

The avoided cost calculator was designed originally to measure cost effectiveness of energy efficiency resources and today it's used for compensation for rooftop solar. And those projects are different and distinct from the ones put forward in the NVBT proposal.

Because load is in proximity to generation and thereby there's a measurable way to say that those projects avoided the investment in transmission and distribution. So there's an avoided cost there. The NVBT proposal that was put forward by parties, the generation was not connected to load. The subscribers could be hundreds of miles away.

And so the decision said that ultimately a wholesale tariff was a more appropriate way to compensate these sort of projects in order to keep electricity bills and rates down for non participants. Because ultimately for these projects they are socialized costs just like any other project we see through the IRP program.

These are costs that end up on all customer bills. So we need to be really mindful at this time when affordability is such a challenge to keep costs as low as possible. And the statute also required, required us to minimize cost to nonparticipants. So we wanted to make sure to comply with statute.