Senate Standing Committee on Energy, Utilities and Communications

Let me first say good morning and welcome. Today's oversight hearing is intended to provide Members of the Committee, as well as the public, with an update from the state's energy agencies and the state's principal electrical grid operator on the efforts to address electricity reliability associated with managing supply and demand, particularly given extreme weather events and as the state transitions to zero carbon energy future.

This is a follow up to last year's similar focused oversight hearing, as well as oversight hearing previously held in recent years, including in 2021 in response to the August 2020 unexpected electricity rotating outages ordered by the state's main electrical grid operator, the California Independent Systems Operator, CAISO, and a hearing in 2022 regarding the proposed extension of the operations of Diablo Canyon Nuclear Power Plant, in large part to support our electricity supply reliability, which we've proven to be very critical and needed at this time.

Since 2020, we have experienced challenges to ensuring reliability during some extreme heat events, particularly in the evening hours in the late summer months when residents rely on air conditioning to keep cool. Last year, the ISO issued emergency alerts earlier in the summer. So far this summer, there have not been any emergency alerts issued by the Cal ISO.

However, last month, the ISO issued several days of notices for transmission emergencies and restricted maintenance operations. Though seemingly managed, these notices serve as a reminder of the importance of the need to remain vigilant and on reliability of the electric grid we know that electricity outages, depending on their scale, duration, and frequency, can be life threatening.

Electricity outages can be caused by many issues, including distribution equipment failure or as a safety measure, such as public safety power shutoffs when wildfire risks are high. Today's hearing is focused on the supply and demand challenges of balancing the electric grid.

The challenges to ensuring reliability are several as transition to zero carbon future, including a new mix of generation resources supplying electricity to the electric grid, including a significant portion that are variable, such as wind and solar, which are not available at all times, including during peak hours.

Deployment of distributed energy resources can help reduce the demands on electrogrid, but can also contribute to the peak demand as the injury from distributed energy resources may no longer be generating and these customers must rely on the electric grid. For example, rooftop solar without battery backup.

Local and state policies to mitigate climate emissions are driving increasing electricity demand, quite literally, as the transportation and building sectors are increasingly required to shift away from fossil fuels to cleaner carbon sources, especially electricity. The growing development of artificial intelligence is further increasing electricity demands needed to operate computing systems.

State policies that authorize local governments who elect, and in more limited cases, private companies, the ability to procure electricity resources known as community choice aggregators or CCAs and electric service providers respectfully resulting in a fragmented procurement landscape that adds complications towards a seamless transition to meeting the state's renewable energy and zero carbon energy resources goal while ensuring electricity reliability.

Additionally, the current tightening of resources adequacy or resource adequacy market with requirements for planning reserve margins increasing, the state procurement resources to serve as insurance and limited imports, particularly the limited out of state hydropower resources due to drought conditions in the north west and Canada, seem to be further increasing prices for all customers. As I've said before, we're flying an airplane while redesigning it, adding passengers, and changing the fuel mix mid air as weather forecasts constantly shift, requiring adjustment to the flight paths.

In recent years, we have appropriated billions of dollars of state budget toward electricity reliability, authorized extension of Diablo Canyon Nuclear Power Plant, and just last year authorized the Department of Water Resources to serve as a central procurement entity should the PUC identify a need for a specified long time resources. When we are in our efforts to ensure...

I mean, where are we in our efforts to ensure reliability? What's our game plan to ensure that reliability remains at the forefront of our efforts, even as we transition to zero energy and work toward ensuring affordability? Additionally, I've asked the Administration to provide a brief summary update of the West-Wide Pathways Initiative, an effort to expand energy markets across the west currently within the limits of existing law.

The intent is to provide Members with an awareness and understanding of the effort, though additional discussions and briefings may be needed. With all that being said, now let's hear from our energy agencies, the California Energy Commission, the California Public Utilities Commission, as well as Department of Water Resources and the California Independent System Operator. I want to say welcome, and we will begin with our California Energy Vice Chair, Mr. Gunda, and we ask that you come forward. And when you're ready, you may begin your presentation.

Mr. Chair.

Yes sir.

Are these the pilots of that airplane?

Good morning, Chair Bradford and Members of the Committee. I'm pleased to be here with you today to discuss electricity system reliability with my colleagues from the Energy Commission, the California Independent System Operator, and the Department of Water Resources.

I'm going to start us off and then we will all be sharing the explanation of a PowerPoint presentation that we have for you today. We're here to talk about summer reliability readiness, but I want to start with the big picture to provide some background to describe the background in which we're working.

The electric sector plays a critical role in California's climate change strategy. We're both electrifying the economy and decarbonizing the sources of generation to supply electricity for the new types of fuel switching and that we're doing throughout our economy, including transportation, electrification, and building electrification.

Much progress has been made in the electric sector, and in 2022, 61% of the state's electricity was generated by renewable and zero emission resources. We also achieved new records just this year. We had 146 days where clean energy exceeded CAISO consumer demand at some point in the day.

We had an all time record in solar production peak with 19,368 megawatts on June 20. And the CAISO footprint is approaching 10 gigawatts of grid scale battery capacity. So with this momentum, we're working towards the goals set by the Legislature, 90% clean electricity sales by 2035, 95% by 2040, and 100% by 2045. At the same time, we're, of course, fighting against the impacts of climate change. Climate change is causing unprecedented stress on our grid.

Extreme heat, drought, flood, and wildfires are increasing in frequency and intensity and threatened reliability. The future, what we're all working towards, is one that is clean, safe, affordable, and reliable, and with clear statutory directives and relatively low cost options for clean energy supply, it's not a question of if but how we transition to our clean energy future. I'll now turn to Vice Chair Gunda.

Thank you, President Reynolds. Good morning, Chair, and good morning, Members of the Committee. I'm going to go through the next several slides on just providing a quick update on both how we do the reliability planning, but some of the numbers we have today. So this slide is typically animated. But I know you probably have just as a copy, but, but let me kind of situate you in the layered approach on how we do the planning.

So we have about four time horizons that we are planning for reliability and resources overall. So it starts with our overarching climate goals, which is in the 10 to 25 year timeframe. So we're looking all the way to 2045 through the SB 100 process. So here we get the demand assumptions that we put in are generally have a lot of uncertainty. There are more scenarios, not forecasts.

They include a variety of scenarios on the electrification potential, demand flexibility, and such. And so once we do that, we have a kind of a directional insight into the resource build at this point. It's really not looking at a procurement level analysis, but it's giving us a high level view into what we might have to build in the 20 year horizon. Then it follows with the IRP studies. That's the second time frame, which is the 10 year timeframe. Here the demand scenarios are replaced more with demand forecasts.

We have a little bit better idea on where we are going in the next 10 years, and we enhance the reliability studies using more the state, the industry standards, such as the loss of load expectation. This is where you are beginning to kind of have a much better sense, and this really drives the procurement.

And then within the year to three years ahead, this is where we have the most certainty on the forecasts. Again, those forecasts could be wrong based on the last couple of ups and downs, but this is the best kind of demand idea we have in terms of forecast and resource adequacy Is the process where you're saying, I have this much procurement that I've already authorized.

How much of that should I make sure shows up in the marketplace in any given day? And that's really done through the PUC. And this process is generally followed by every LRA, including some of the POUs, large POUs. And then finally we're in the operation timeframe, and this is where we really differ. To CAISO. We planned what we could plan. We know how much the forecast might be.

We have ensured through RA that we have the resources, and now we are really trying to manage that in the real time. Going to the next slide. So what we'll show you then for top lines for 2024, kind of a continued growth in our resource additions to the overarching system.

So, as you all might note, over the last four years, we have added about 20,000 resources, which we'll talk in a little bit, but given that we have added more resources and the demand has not grown at that level, we don't anticipate any shortfalls under standard planning conditions. This is looking at the 17% planning reserve margin paradigm. We don't see any shortfalls under that. Even if there is a 2020 or a 2022 equivalent event, we still don't see any shortfalls. That doesn't mean that we are not going to have a lot of planning, active planning, whether triggering contingencies or such.

We have the resources that we think we have as matters to the steel in the ground, but we still have to go through the process of making sure we rely on them. So, again, setting the stage while we have the resources based on the demand, a long lasting westwide heat wave or a huge, huge fire that's coincidental could still stress our grid a lot. And I think that's something that we are actively preparing for.

Another element that gives us some confidence is really having the strategic reserve. Again, thanks to the Legislature for the tools that were provided to the state agencies to develop the strategic reserve. We currently have about 4300 megawatts in totality of what we call contingency resources. These are beyond the RA resources, resource adequacy resources.

These are resources that are either through strategic reserve, which Delphine from DWR will talk about today, but also other tools like the demand side grid support program, DSGS, and other programs where we can lean on to provide some support to the grid. So overall additional contingencies will likely be needed for the strategic reserve to replace OTC generations as we move forward in time.

So just kind of then situating ourselves in the past four years. Real quick reminder, as we think about the changing grid conditions, we were here in front of you right after the 2020 heat wave and the rolling blackouts that we had to face. So as you know that, as we were thinking through that year, I want to just situate you on this visual. On the top is the planning that what we were planning for going into the year, what were the events that we've seen, and then how were we modifying.

So in terms of planning, in 2020, we were always looking at historic conditions, whether they are temperature, whether they are production and such. And then we would always look for average climate change trends. Those were what used to kind of go into our planning regime.

There was always some level of climate impacts baked in, but not significant enough. But as you know, in 2020, extreme heat wave that we had pushed our overarching demand from a median forecast by about 9%. So we've never seen something that large. It was a huge, significant event.

So going into 2021, we really started incorporating some of those climate uncertainties. And then we started more actively looking at procurement and how do we look at these uncertainties moving forward and beginning to increase the planning reserve margin looking at this climate change impact. But as you know, in 2021, in July, we had the Bootleg Fire.

The Bootleg Fire knocked out about 4000 megawatts transmission coming into California. This happened in Oregon. And suddenly, over several moments, we just lost a large amount of inflow of energy into the state. We also hit extreme drought. We had, the first time we had Oroville kind of bottom out. We had wildfires, And then this was the beginning of the real impact of supply chain on the system.

So as we were looking at those issues, we tried to prepare for that going into 2022. And the reassessment of that was looking at planning in terms of planning reserve margin. And the state agencies really were in front of you requesting the tool of a strategic reserve because the uncertainties were so large, and we really needed to have some cushion to think through as we move forward.

Again in 2022, as you know, September 6 was a really, really hot day in California, but across the west, we hit 53,000 megawatts almost on CAISO system. And that really put us in one of the highest grid loads across the west. But we were able to get through that given a number of tools that we were already using.

In 2023, we had further one statistic I would like to just leave with you. September 6, 2022, we had approximately 53,000 megawatts in CAISO system. Same day, September 6, 2023, we had 33,000. It was a 20,000 megawatt difference on the same day, two years apart. And I think that's the uncertainty we need to plan for as we move forward.

2024, we just went through a heat wave. There are fires going on. Again, I want to just take a moment here to recognize, on behalf of all the state agencies, the incredible work that the firefighters do in putting their lives on line to help not only save lives but also save the grid. So thanks to all the public servants who are working on that front.

So then kind of coming off of that kind of overarching, compounding impacts and how do we deal with this. You know, really the grid reliability is largely, the actions that we've taken largely fall into three pieces, which is improving our grid planning processes and kind of that drives better procurement.

And President Reynolds is going to talk about that in a second. We also looked at how can we scale the supply side and demand side resources. One of the important parts of that was to really track the procurement, and this is through a multi-agency effort that's called the TED Task Force.

We work through tracking every project in development. Also, the Legislature acted on a number of things, interconnection, improving interconnection through the CAISO process, but also some tools that we were given on the permitting side. And finally, we've made it a really important part of the planning, which is called now the Preparing for Extreme Events and how do we plan for that. So with that, I'll pass it to President.

Okay. As you heard, electric system planning requires significant cooperation among agencies, and each of us have a different role in that process. I'm going to talk a little bit about CPUC's piece in the planning process, including our planning oversight over the more than 40 load serving entities. The Chair mentioned this today.

We have a number of retailer sailors within California, within the PUC's jurisdiction, including the investor owned utilities, PG&E, SDG&E, and SCE, as well as community choice aggregators and direct access providers. In total, about 75% of California's load is served by the load serving entities that are part of the PUC planning process.

And these load serving entities, of course, have the responsibility for serving their customers, and they determine which projects will serve these customers through competitive bidding and agreements to purchase power. We recently found it necessary to order procurement of new resources to serve customer load and to reach greenhouse gas emission targets.

And what you'll see on this slide is the various orders that we've issued since 2021. In particular, we issued orders to follow the 2020 heat wave, and beginning, we actually began in 2019. The online dates coming from those orders are shown in this slide.

In total, we reached an unprecedented amount of nearly 19 gigawatts of net qualifying capacity, meaning the value of these resources to the grid, not the maximum capacity of the project, order to be brought online between 2021 and 2028. It's really important to note that these orders are for clean energy only.

The requirements cannot be met with fossil fuel resources, and that means that any incremental load that within the IOU territory. So any of these LSEs will be served by clean energy, and even existing load that is being served by clean energy projects that the LSEs are now bringing online.

I want to note that how the process that we use to arrive at these numbers is based on CARB scoping plans. So we look at the greenhouse gas emission target for the electric sector and take the portion of that. We take the portion of the total greenhouse gas emission number and use the portion that applies to the electric sector and then calculate what's needed over time to reach the ultimate target of climate neutrality by 2045.

Our analysis is always based on the CEC's demand forecast. Each year we update our planning to make sure that we're tracking changing demand over time to reflect load growth, and that we're prepared for those worst days of every month. And our goal is to identify the need for new resources well in advance because we know it takes time to build these projects.

And then we do our part to ensure that the resources are contracted for and brought online according to that schedule. This overview shows that the procurement that is ordered in advance, and I'm going to go to the next slide, which builds on what we've directed in procurement orders.

So this slide shows the megawatts of new nameplate capacity that has come online since 2020. So these are actual projects, on the left side of the line, that have been built according to the procurement orders and the contracts of the LSEs. And it shows that the pace of resource development has nearly doubled over the past past four years, during which time we installed 21 gigawatts of new capacity. And in 2023 alone, a record of over 5700 megawatts came online.

This record pace requires a coordinated effort, and the CPUC, CAISO, CEC, and the Governor's Office of Business and Economic Development meet regularly through a tracking energy development or TED Task Force to assess progress and address bottlenecks. So that's the build that has actually happened, and we expect that pace to continue through the next few years.

So if you look at the right side of the line, that is a depiction of projects that have contracts, so under contracts with load serving entities but not yet built. And you can see that roughly 15 gigawatts of additional resources are under contract to load serving entities and moving forward in that process to come online. Majority of this capacity is from solar and storage, including hybrid resources that generally include both solar and storage components.

But we are also seeing wind, geothermal, and biomass resources come online. So looking for resource diversity that can further improve system reliability. Next slide, please. I did want to briefly mention the central procurement mechanism. We heard from the Chair about this this morning. So separately from these procurement orders, we do have a new tool in our toolbox.

Pursuant to legislation enacted last year, AB 1373, which ordered the CPUC to assess whether there's a need for central procurement to be conducted by the Department of Water Resources, and if so, what types of resources are necessary and in what quantity. This initial need determination must be completed by September 1 of this year.

So pursuant to that direction, we did release a proposed decision in July, which will be on the August 22 Commission voting meeting agenda. The PUC will determine whether the whether to vote on the proposed decision. The proposal includes resources as shown on the this slide up to 1 gigawatt of enhanced geothermal systems with the first solicitation in 2026.

Two types of long duration energy storage are also included. First, up to 1 gigawatt of 12 plus hour duration storage with solicitations beginning in 2026, followed by solicitations in 2027 of up to 1 gigawatt of multi-day storage. Finally, 7.6 gigawatts of offshore wind, with the first solicitation in 2027.

These resources were selected because they are technologies that present opportunities to help California meet its greenhouse gas emission target goals for 2045 and beyond, and they include emerging technologies that need scaling to lower costs. So the next step, and I just want to be clear that the amounts shown on this slide are a maximum.

And so the Department of Water Resources would go out to solicitations and determine whether they're reasonable bids that are cost effective according, and then would go forward, or they may decide to wait and do additional solicitations later. The next step after the decision is six month period for the Commission to make a request for procurement from DWR.

And then DWR, if that request is made, would attempt to centrally procure on behalf of all of the load serving entities within IOU territory. And that means that costs would be spread among all of the customers within IOU territory. And that is it for that slide, so I will now turn to President Mainzer.

Thank you, President Reynolds. Mr. Chairman, Members of the Committee, nice to be with you this morning. I'm just going to briefly touch on transmission. When you hear these significant amounts of new resource development that the PUC has ordered procurement, obviously a key function for us at the CAISO is to make sure that there's sufficient transmission capacity and efficient onboarding of those resources onto the system.

So in recent years, in very close collaboration with the state agency, the CAISO has developed what I would characterize as transformative changes to our transmission planning and interconnection queuing to make sure that we can keep the state on track for its clean energy objectives. A couple of things I wanted to point out.

First of all, we've adopted a new approach to transmission planning in which we've effectively identified a set of discrete zones on the transmission grid in California that, based off the state planning, make the most economic and operational sense for new energy resource development. And those zones are going to shape the pattern of procurement and interconnection queuing in the years ahead.

A couple years ago, we also developed a 20 year transmission outlook, so we could sort of take a big picture look at the transmission architecture for the State of California out to 20, and now with the recent update, all the way out to 2045, which will set the stage for subsequent transmission planning efforts and procurement of transmission.

We've also made some very specific and actionable reforms to our interconnection queuing process to bring new energy resources into service as soon as possible. This is really important, sort of trying to take the friction out of the interconnection queuing process. A couple of examples.

We've developed a set of new scoring criteria to prioritize and advance those projects that are most ready to come onto the system and are lined up with those zones in the states planning process. And we've also established more stringent viability criteria for projects in the queue to ensure continued progress towards commercial operation.

And just last week we submitted, I think, a very ambitious package of these reforms after over a year of stakeholder engagement to the Federal Energy Regulatory Commission, hoping to have approval for those by this fall and get them into production. So just wanted to highlight some of the elements of transmission. That's a real commitment we have here at the CAISO to make that process as efficient as possible. Vice Chair Gunda.

Thank you, President Mainzer. So now, given the background of overall planning status and procurement status, we'll go into the 2024 grid outlook. We are in August. So the August and September are typically kind of the tightest grid months. So let's give you a quick update on some of the information that we shared with the Legislature.

So this slide captures what we were expecting to add this year starting in January, and this is the first six months of progress. And then the next slide will go over months seven to 12. So in our Q1-Q2 resource additions, we were hoping at the start of this year to add about 4000 megawatts of new resources, large amount of that was storage and a significant part of solar to complement the charging. So as we look at the Q3 report, we have some actual installed numbers.

So out of the 4100, roughly 4177 to be precise, that we expected to add in the first six months, we were able to add about 3700 megawatts onto the grid in the first six months. It's really important to note that the last row down there, which you'll see 44% delay or 65% and such. So what that is tracking really is looking at based on the expectations versus what actually tracks in reality, how delayed are we?

If we remember, just to remind the Members here, coming out of 2020-2021, given the supply chain challenges, one of the things we shared with you was we were observing a about 40% delay regularly on the system, both because of weather conditions, supply chain delays, and others.

But as you see here, one of the things we are really beginning to observe is much of the delays happen in the first quarter, especially coming out from winter, early rains. You have weather conditions that don't necessarily translate to being able to build quickly. But over the last four years, the development catches up by the middle of the year. And really at the end of the year, you see a surge of capacity additions in the last quarter.

But we want to be, we want to report to you that we are seeing one of the best kind of addition rate this year, which is at the end of six months, we are only at about 11% behind our expectation, about 400 megawatts. Also want to call your attention to the total megawatts that are added.

We almost added 3700 megawatts. And as President Reynolds mentioned, last year was a record year where we added in a close to 6000 megawatts last year under the grid. This year we're already almost to 4000 megawatts in the first four months. Going into the next slide, then how is it looking moving forward.

Based on the CAISO Q, what we see is another 7.5 gigawatts of new resources that could come online over the next six months. That is putting us in the realm of 10,000 megawatts this year. Obviously, there will be delays, and we'll observe that, but it's pretty, we feel confident that we could beat the record last year and have higher resources. And this is exactly what we need in terms of SB 100 being able to build consistently at this rate.

So how does that translate then into the kind of September month for you? I mean we present here the September, but all July, August, and September look the same. What you're seeing here in the very first column is looking at the Q1 report that we submitted earlier this year, and we were saying about we have about 4000 megawatts additional resources in addition to the standard planning resources.

So one thing I want to call your attention to, the resources we consider here are not all under RA, right? This is the steel in the ground, all of California, and the expected imports coming into their system. So we look at two things as we plan for summer reliability.

One, are we planning to the RA and then are there resources showing up? That's one thing. And if we were to go beyond that standard planning event into an extreme event, do we have enough resources in California that we can rely on to get through that?

And that's where, even though there are resources in California, you will see some grid tightness, whether it's an alert, transmission alert, whether it's an emergency watch, because we're trying to mobilize those resources to support the grid. So if it's a 2020 event, again, 2020 was that approximately eight to 9% deviation from a median demand forecast, and 2022 was in the realm of 12%.

So you're looking at very high demands baked into it and also some drought risks, not for this year, but typically we put that in there, and higher outage risks of thermal fleet. So as you're seeing here, we're looking better and better because of the additions we were able to have. So under none of those conditions we see shortfalls at this point. So then kind of going into the strategic reliability reserve real quick.

So now that we just shared with you, as we look at the demand and resources and planning for extreme events, we have enough steel in the ground to potentially carry us through a very extreme event. But then how do you mobilize them and how are you kind of planning for them? That's what I'm going to cover here.

So before we go into the actual contingency amounts we have, we just want to set the stage on two types of events we are now beginning to track. One is the sudden onset. A primary example for that would be a fire knocking out a transmission line. That happens very, very quickly and the number of resources we can rely on is very different versus a slow moving like what we saw in July. So when you have 3, 4, 5 days advance notice, and then a long heat wave coming, you can mobilize a lot more resources.

And so that's kind of what this is trying to capture here. And again, want to really reemphasize this. We are meeting our RA obligations as we see. If it's a standard event, we have enough resources under RA contracts to get us through that. If it's an extreme event, we have enough steel in the ground and contingencies to carry us through that. But that doesn't mean that we will not see some of the emergency alerts to prep and arm those resources.

So again, taking a step back on this slide, we want to just remind you when we asked in a planning for strategic reserve, we first want to meet our loss of load expectation. We want to understand the demand, and we want to plan for resource procurement that at least gets us through the standard reliability planning.

And then you should plan for those 10, 20, 30% of delays, whether it's supply chain, whether it's some other way, there's kind of developmental delays. You have to cover that, and then you have to cover heat, and then finally these extreme events such as the fire risk.

So what we plan for, and you see the stack there is the top four, is what the strategic reserve is trying to cover for. We plan for our standard and then anything incremental to that standard, whether it's coming through procurement delays, hot conditions, fires, or drought, we want to have enough resources to carry us through that.

So this kind of slide, slide 19 just gives you a quick look at the contingencies we have. We have three buckets of contingency resources. The first one is the state funded strategic reliability reserve. This is where a large portion of that today is really done through DWR. And Director Hou will kind of talk through that.

There's a couple of programs that were funded through CEC for the demand side options, whether it's the demand side grid support, our backup assets. We'll talk through that in a bit. We have a bunch of programs that are actually paid through the rate paid still that PUC pays for the Public Interest Rates Commission authorizes them through the ratepayer monies. And so we have the Emergency Load Reduction Program, which I'll give President Reynolds to give a quick overview about the CPUC programs.

Sure. So as mentioned by the Vice Chair, there are several programs that we deploy in emergencies that are paid for by utility ratepayers. So customers pay for these programs through their utility bills. It's important to note though that the programs are designed to be used in emergencies only.

So customers are not paying for this either load reduction or additional supply 365 days of the year. They're only paying for it a few days of the year because we know that's what will be needed. So the idea is that we have additional load reduction and additional supply available on a few days of the year.

The main example of one of these programs is the Emergency Load Reduction Program, or the ELRP, which pays residential and commercial customers to reduce their load during emergencies. So it's a pay for performance program. It's triggered when CAISO calls a flex alert or other emergency alerts. And another example is the Smart Thermostat Programs.

And so this is an automatic adjustment to customers air conditioned settings to reduce electricity load at times of grid stress or high prices. And the investor owned utilities have also signed contracts. So that is the second line on the chart under the CPUC section to bring in additional energy imports.

And these are firm contracts where that energy supply is guaranteed into California when needed. The investor owned utilities have also signed new contracts with several combined heat and power facilities. So these are older contracts that were wrapping up and that supply just got picked up for additional years and can be deployed in emergencies.

Thank you, President Reynolds. And so the last category of that is the non-programmatic. These are more done through work from CAISO. For example, they work with LADWP and others on figuring out how each balancing areas can support each other during emergencies. And also there's a couple of extraordinary events we can do through either an emergency proclamation or waivers through DOE, where we can go beyond permit levels which we have deployed in previous years. So.

Apologies. It keeps kind of bugging up on me. So with that, I'll go into the next slide and just start with the state funded programs.

Thank you, Vice Chair. Good morning. Chair good morning, Members. Thank you very much for inviting me. So I'll talk a little bit about one of the state strategic Reserve programs, and that is DWR's program under the Electricity Supply Strategic Reliability Reserve portfolio.

So created through AB 205 and 209, it acts as an insurance policy and safeguards the statewide electric grid during extreme and combined events, as Vice Chair Gunda was describing, such as heat waves, wildfires, droughts driven by climate change.

So the table before you includes also the state power augmentation program, which was developed through an emergency proclamation by the Governor in 2021, as well as the SRP from its inception in 2022 through today.

As you can see, the portfolio has moved away from, for example, temporary diesel generators, which were deployed in an emergency and used during the September 2022 heat wave. And we've transitioned away from that to much lower emitting natural gas resources.

At the point in time in 22 and 23, we also relied heavily on imports as we were trying to ramp up the program and build out new assets in the states.

The major shift then, as you can see, as we transition away from import, is the entry of the once through cooling resources into our portfolio early this year.

And that was on the recommendation of the state Advisory Committee on Cooling Water Intake Structures, which includes the California ISO, CPUC and CEC, recommending two the State Water Resources Control Board to allow for the extension of ones through cooling resource permitting so that it can be provided into the strategic Reserve.

The big tradeoff and benefit of that is that those resources would be removed from the resource adequacy program.

And as Vice Chair gund has described earlier, those are part of the traditional state level resource planning under the CPUC, and they are expected, once they are with the California ISO, to be available 24 hours a day, seven days a week.

So the big sea change in the operation of the ones through cooling resources and all the resources in the Reserve is that they are default off. They are off and they are not operating unless for testing purposes or ordered by the California ISO or triggered by an emergency required for them to operate.

So that's a big change in operations and a big reduction in the emissions of these resources.

And as we'll discuss a little bit more in the next section with these resources from the ones through cooling resources, as well as additional resources that we have with a combination of Low emitting natural gas resources, the Reserve is available to respond to any needs of the state.

And I'll just give you a little preview of that from the perspective of the Department of Water Resources. I know it was barely a month ago that we went through the Thompson fire. And that first large fire in the state, we saw the City of Oroville evacuated. And in that event, it caused transmission lines to relay.

And what happened there is that we lost power to the Oroville complex. So that was a reduction of 800 mw in the blink of an eye to the grid. So thankfully, Kaiser was able to operate the grid in a safe and reliable manner. CAL FIRE was eventually able to get the fire under control.

Power was restored and in that instance, the Reserve was ready. And part of it was used to help through that event. And again, as Vice Chair Gunda had mentioned, we continue to experience heat events and other fires, such as the park fire, throughout the state.

So again, the Reserve is ready and available with the megawatts shown here in the 2024 column to help the state with that. Let me turn it back to Vice Chair Gunda.

Thank you, Director Ho. So we have one more slide on just kind of expanding on the dsgs and the DeBa programs. I want to just again thank the Legislature for this funding stream, especially because it gives us an opportunity to develop demand side programs without rate payer support.

So want to just really stress on the work that we're doing on providing flexible options to developing the demand side program. So we are looking at about 444 mw as of August 2024 and really kind of moving towards three types of programs within that.

But I want to just highlight option three, which has become really successful with kind of using behind the meter storage to develop VPP.

So we have about 210 mw today enrolled in the program, and we expect that to continue to grow on the Deba, given that it's a different type of resource stream that we are beginning to put out solicitations. We already have a solicitation out and that is going to be adding more resources in the 2026 timeframe.

And the reason for our focus on DSGS was really the ability to quickly bring in magazines under this program. So with that, we'll go into the summer 2024 grid update, especially the July event, and I'll pass it to President Mainzer.

Thank you, Vice Chair. So, yes, I'd like to offer a number of observations about summer 2024 conditions, sort of from the perspective of grid operations. I think the bottom line so far is that things have been going quite well. It has been a challenging summer. We've had some very, very high temperatures throughout California and the broader west.

In fact, the broader western United States set its all time demand record back on July 10. So it has been hot. But fortunately, here inside California, we haven't had truly exceptional sort of statewide conditions. I think if you think back to September 62022 we hit a 52,601 mw peak.

The highest load we've had so far this summer is 45,426 mw. So we've been fortunate so far that the Southern California coastline hasn't really heated up. So we haven't had exceptionally. But we have had some challenges. And I think that all of the planning and procurement, as we'll talk, has paid off well.

One of the things we're watching very carefully are the wildfires. Just as was mentioned previously, right now, the park fire has put some strain on the transmission grid. So we're watching that very carefully. Again, deep appreciation to CAL FIRE and all the firefighters doing an incredible job up there.

But so far, the impacts on the bulk grid have been manageable at this stage. The energy resources that have come online the last couple years have made a real difference. As we've said, we now have over 9000 lithium ion batteries operating on the Caiso grid. That's the largest in North America and anywhere outside of China.

So that battery fleet is really performing quite well. And certainly we're going to be continuing to coordinate very closely with our state partners as summer progresses because we certainly continue to have exposure to extreme conditions in August and September. I want to just put a couple of exclamation points on a couple other things.

I think just some of the key takeaways, the amount of new generation that is coming online in California and the planning and the procurement has been a huge difference maker.

Just to be meeting the one in 10 loss of load standard inside California and to have a much, much more robust resource adequacy stack has just made a tremendous difference for reliability here in the state. The other thing is, I really want to express my appreciation.

The amount of planning and advanced coordination that goes into the summers now, the tabletop exercises that we do at the state agencies governor's office, the utilities, all the load serving entities, that just pays real dividends by doing scenario planning and trying to anticipate the full range of conditions that we might encounter during a summer and having a very well crafted playbook that we can operate off and all be operating on the same page has been a major difference maker.

The other thing, as Delphine was mentioning during the most recent July heat wave. The state programs designed to provide grid support during extreme weather events were mobilized and performed, expected. I think that was very smooth and really appreciate the coordination there.

Across the spectrum, the state strategic Reserve domain response, we're starting to see a little bit of additional demand response participation in the day ahead energy market. That makes a nice difference. We're going to continue to try to grow that capability here in the years ahead.

Load flexibility, I think an essential part of the reliability equation here in California. And then finally the western energy imbalance market, which we'll talk about a little bit more, continued to be an essential tool in helping to balance supply and demand both here in California across the broader west. So just wanted to thank everybody for the work.

Your support in the Legislature has been obviously game changing, and it's great to see the progress, but we'll keep our head down and keep moving forward. Thank you.

So I wanted just to call out one other additional piece of data for you, just to kind of, just to show you one other piece, just sort of speaking to that. If you look at the amount of emergency notifications that we've had to do in the last couple of years, you've seen a real decrease.

Back in September of 2022 and through the, through July in the summer of 2022. We had to call 11 flex alerts the last two years, last year and this year. So far, no flex alerts. Also, you can see back in 2022, we had a total of 19 emergency alerts in the Caiso area.

Last year we were down to three. This year. So far only one, and that was a quick call in response to the breakout of the park fire. So these metrics are also showing indications of progress.

And to speak to what I was indicating earlier, and you can also see that for California, really, particularly this summer and last summer, relative to the broader west, who's been, you know, the tables have sort of turned. Back in 2022 is really the State of California. We were right on the edge. Imports the western energy imbalance market.

We were able to receive a lot of support from adjacent states. The last couple summers, the table has sort of turned. We've been in a position to provide some broader assistance, and that sort of speaks to the broader interdependence of the western grid and the benefits of regional coordination. So thank you very much.

And I'm going to turn it back to Vice Chair Gunda.

Thank you, President Mainzer. So we're going to kind of quickly tee up the 10 year outlook, just a couple of slides on that, and then we're going to go into the regional, we're going to end with the regional coordination.

So on the 10 year outlook, just wanted to make sure we recognize much of the information on this slide is really reiterating some of the pieces that we've already discussed. But the kind of constant that we're observing is unknown, unknowns that we are seeing on the grid.

New types of challenges emerge, but fundamentally there are two pieces that we could begin to bake into our planning, which is high electrification and thinking about how we can plan for high electrification. Chair Bradford mentioned in his opening comments about the increasing AI load.

We just had a workshop specifically on that, thinking about how do we even think about that upcoming AI load. So we're doing what we can in terms of the known variables, high electrification and high variability in the weather patterns.

But I think the challenges continue to come from the unknown unknowns in terms of how they hit our supply side. So some of the specific examples again were noted here. So just giving you slide 28, just giving you a quick projection. Both the frequency and the magnitude of heat is expected to grow over the next 70 years.

But really kind of, I think my main kind of takeaway here is some of the climate projections we were having in the 20102015 timeframe that were suggesting the impacts that we're seeing today to show up in 2035. So we're really seeing earlier kind of impacts of climate change than we've anticipated.

The length of the events are also increasing. So one of the piece that we will continue to see here is long heat waves at a time, also the magnitude. So an important takeaway as you look at the statistical distribution of this information is the median temperature doesn't really change that much.

The median grows slowly, but these extreme events become more frequent and the tails continue to grow further and further away. And so from a grid planning side, that becomes a real challenge because you're having to plan for thousands of megawatts just for those extreme events, which are there for 10 to 50 hours a year.

So what the 10 year outlook has done at the direction of the Legislature was to look at, okay, given the procurement status where we are, how does that look going into several years forward? And much of the negatives that you see on the system here are also because some of these years don't have procurement debt.

So the CPUC will be putting in procurement, but I think directionally from the agencies. All our analysis suggests that even if you met the one in 10 loss of load expectation, there will be megawatts that you would need beyond that for a very, very short time.

So that kind of puts the question on how do we evolve the strategic Reserve. The funding we currently have is really looking at 2030 timeframe. And here's a quick visual on how we are thinking about that. In 2023, we really were trying to stand up a strategic Reserve as quickly as we could.

So much of that was fossil based. Whatever we had, we took it and we ran with it. But I think as we move forward, we are trying to evolve that to be as clean as possible. But also the funding stops at some point.

And then we need to think about how do we plan for those emergencies in 2030 and beyond. So as you see here, in 2024 to 2026, the OTC power plants, as Director Ho just talked about, really gives us a significant cushion, especially in slow moving events.

And what that also gives us is time to build the clean dsgs and Deba resources. And that's something that we are continuing to build. One of the things even the demand side grid support had to rely on was backup generation at data centers.

So we are hoping to reduce that as we move forward into the years here, because now we are able to build that virtual power plants and then demand flexibility options. But beyond 2030, and as the funding for DWR goes away in 2026, we will have a significant reduction in our strategic Reserve.

And I just wanted to point out that's the reality we are going to be moving. So that kind of provides the overarching reliability discussion. And with that, I would welcome presidents back to beginners on the discussion of pathways.

Okay, our last topic, I wanted to say a few words about the pathways initiative. So, just a description of the status of efforts that are underway to increase west wide market coordination. So this is in parallel with and building on Caisos development of its market.

And when we say pathways, we're referring to a diverse group of stakeholders that have formed to explore further efforts to harness the benefits of a larger western market. And so I am going to start by turning to President Mazer, who will give a reminder of the background of KAISL's various roles.

And then I'll talk a little bit more about the pathways initiative and how it builds on that.

Thank you, President Reynolds. I wanted just to reestablish grounding in sort of the kind of dual role and sort of functions that the California ISO provides.

Of course, first and foremost, we serve as the balancing authority for about 80% of the State of California and have the responsibility but for the design and oversight of those balancing authority rules we operate the transmission grid, as you know, within a Caiso footprint, and, of course, maintain the generation interconnection process within our footprint, and essentially, that real time reliability responsibility within that footprint.

We also, of course, handle compliance with all of the reliability standards that are promulgated by the North American Electric Reliability Corporation. So those are sort of the essential within California functions. We also, of course, provide a set of regional services. More broadly, we administer the oversight of the market rules.

Of course, we have entities from across the western United States who participate in our existing energy markets. We provide physical operation and optimization of a regional dispatch. We are responsible for the settlement of all the different market transactions. And, of course, we also serve as the reliability coordinator for about 80% of the western United States.

This is a function that we took on several years ago. Sort of think of us as kind of the control tower operator for even a bigger footprint outside of California. And these are services that we've operated for a number of years in parallel with our core responsibilities to the State of California.

Turning to the next slide, I wanted to just touch briefly on the western energy imbalance market, which in many ways has been sort of the foundation stone and set off the broader dialogue around regional coordination in recent years.

The western energy imbalance market is effectively a real time, short term energy market that allows participants to buy and sell available energy on a very short term basis. And since 2014, this energy market has generated roughly $5.85 billion in grosse for customers, with a significant fraction of that going here to California electricity ratepayers.

We are now in the process of enabling our EIM participants to buy and sell energy in the day ahead timeframe through what is known as our extended day ahead market, or Edam. And the day ahead market will allow for even further optimization of economics and reliability, and an even greater broader footprint of collaboration.

This market structure, I think many folks would say, is the next logical step in enhancing regional markets and achieving even greater economic and reliability benefits. So I'm going to turn it back to President Reynolds with some additional comments.

Okay, great. So what we wanted to talk about a little bit is exploration of a larger market. So, compared to the efforts that President Mainzer described, that we're already seeing benefits from the EIM and Caiso has developed a tariff for an enhanced a head market.

But there's also an effort underway to examine proposals for an independent regional organization that would govern the market functions, not the other Caiso functions, but the market that would leverage the existing Caiso infrastructure and minimize cost to repair. So, recall the three large grids in the US, the western, the eastern, Texas.

So we're already connected to the west, including Canada. But the markets and the market operations in the west are very fragmented. We have a large number of balancing authorities, and we have the Caiso market, and then we have bilateral trading, and we have.

And so this effort is really thinking about the benefits of a larger market, meaning, think about a market with a footprint that is larger than any one weather event. So we're talking about the resources in California that need to be ready for California for only 10 to 20 days of the year.

And with a shared market, we can optimize those resources for reliability purposes, work with our neighbors. So it's hot in Arizona and those resources can go there. It's hot in California. We can drop from the Pacific Northwest. And as I said, we're connected. But a market would enable us to do that more effectively.

It would provide visibility for operational purposes into a wider range of resources, for reliability purposes, but also for cost benefits. And so the idea would be the shared resources could maximize the cost savings for ratepayers, really, throughout the west. And so we share interests of our western partners in increasing reliability and decreasing costs throughout the west.

And importantly, the changes that are being discussed in the pathways initiative would not involve changes to the Caiso balancing authority. Concepts that are explored really take into account Caiso remaining as Caiso for balancing authority purposes, as well as our own transmission planning that we do for California.

And so that is our joint agency planning exercise that we've been talking about here today. With any of the proposals that the Pathways initiative is talking about, CaiSA would retain those functions.

The Pathways initiative was formed, as I said, by a group of stakeholders, and it's really interested parties throughout the west involving stakeholders from a large group, number of groups, customers, large and small customers, consumer groups, labor, environmental groups, the investor owned utilities, the public power, independent power producers.

So really a broad group of stakeholders who are working on exploring options for additional cooperation. Let me now turn to chair Gunda for Vice Chair Gunda.

Thank you, President Reynolds. So, kind of, I think, chair Bradford, you kind of set that up really well. I think within the Kaiser's boards kind of mandate, they kind of have been taking different steps to enhance the market as they see from eim to now. Edem.

So what the pathways initiative of this independent, Westwide, self organized group of stakeholders, along with the state representatives, is really looking at, what are their suggestions for the Caiso board to consider to continue to enhance those market functions? So with that, it's a good time. They've just set up step one, ask to the Caiso.

They've put some proposals, but the proposal really focuses on continuing to create conditions to capture the broadest footprint under EDAC. So in order to capture the broadest footprint, again, to President Reynolds point, it's both about affordability, but also reliability to ensuring that seamless exchange of energy.

So the proposal in front is to develop further Independence on just the governance of the market functions and then becoming more a market governed by the broader western groups to allow for those conditions necessary to have more people feel confident and comfortable to join the Edam. So that's the step one proposal.

And the Caiso board is currently considering that step one proposal right now. And we'll vote on it soon here, and I'll share that with in the next slide. But, you know, just in the governance framework, in the last bullet point, I just wanted to raise a few things. So, one, currently we have two boards.

We have the Caiso board and then Western Energy Imbalance Market Board. Both operate at Caiso. And the Western Energy Imbalance Board is looking at the market rules, and then theyre helping them develop. And once those market rules are developed, they come to the Caiso board for finally being able to vote on them.

What the proposal asks for is that the market ruled are really decided under the Wiem board primarily. And then, same with what we have today, there will be a dispute resolution if the boards don't agree.

But what you see on the third one, the second one is important, which is if the dispute resolution did not bring the two boards together, there is a jump all filing to FERC, meaning both boards can put that proposal to FERC. And just kind of noting that Caisa today, you know, works under the FERC Public Utility authority.

And so they'll be filed there and then they'll be, you know, both of the western stakeholders feel that's a fair thing for FERC to hear their concerns. But Caesar board retains sole FERC filings. It'll continue to retain that and also have retention on the exigent circumstances. And finally, public interest was added.

And thanks to President Reynolds and many of the regulators in the west, the Wiem Board, the Western Energy Imbalance Market Board doesn't currently have within their statute, a public interest component. And that was added in the proposal that that has to be honored given that this enhanced role.

And finally, this proposal will not trigger unless there is a 70% of Caiso current EIM load joining the Edam. So those are several trigger points. So that's the ask right now in front of the Caiso board and going into the next steps. On June 5, the launch Committee submitted this proposal to the Caiso board.

We anticipate the Caiso board to be voting on this soon, in August at a joint board meeting, both the WIm board and the Caiso board. And from July through August, the pathways initiative.

They're holding a number of public workshops to continue to think about what more can be done on the market front so we can push the markets even further in the west and evolve them.

So between September and December, what we anticipate is that the pathways launch Committee will prepare and draft and draft and issue a final proposal on the next steps of evolving this. So we have step one proposal, and they'll come up with further step two or next steps on how to evolve these markets as a proposal.

So right now, again, in closing, this is a self organized stakeholder group that has continued to think through the problem statement of how do we have the broadest footprint of energy markets so it could benefit the west. And based on those discussions, an initial proposal has come through, which is in front of the Caiso.

And Caiso is right now deciding on that. So that's all we have in prepared slides. And so with that, we'll quickly stop and take your questions. Thank you.

Thank you for that presentation. Much appreciated. And I'll just turn it to my Committee Members. Are there any questions that Committee Members have? A few things. Okay, hold it.

First.

If you want to go, go ahead. If you're ready.

Sure. Yeah. Thanks. Thank you, Mister Chair and thank you to our presidents and Vice Chair. I think this kind of joint reliability planning is exactly what we had in mind when we initiated all this.

And this kind of quarterly update is very helpful and encouraging to see all the coordination across jurisdictions here.

I know we've been operating in I wouldn't say completely lucky circumstances, but a relatively wet year or wet years; relatively low fire seasons, it's all held up under these circumstances, but we haven't had the kind of 2022 conditions, as you all noted. So still cautious, as I appreciate you all are as well.

My questions were really about sort of the look forward in that post 26 or 26 and beyond timeframe and how to make sure we're getting the most bang for our buck in this kind of strategic reserve contracting that we've been undertaking.

My understanding from the interactions with the budget subcommittee chair and our staff on the current contract for the OTCs is that of the $1.2 billion, which is all general funded. Right? At 1.2, that only a certain amount has actually been spent down, but that the bulk of it remains sort of unspent.

Can you distinguish for us just how much has been invested from that $1.2 billion contract in the upgrades and retrofits and sort of sunk costs like physical asset upgrades versus that sort of insurance policy or the capacity that we've purchased, in other words.

Thank you very much for the question, Senator. Yes, I'd be happy to talk about that. So, one thing I do want to differentiate is exactly how you described. There's a couple different categories that we were contemplating when we signed these contracts, but I think it's important to focus on the overall.

So, as we all know, these once through cooling resources would have retired. But for these contracts, and of course, that was also the agreement that we had with the State Water Resources Control Board in order to extend their permits. So, there's a couple of things at play.

So obviously for the reserve, we do want to maintain the physical capacity of the resources, but what's also very critical is having the staffing and the commitment to be able to operate these facilities and to have them staffed 24/7. So, there's the contracts that you see and the commitment there is the payment is structured as similar as possible to what folks have known and gotten used to in sort of the resource adequacy construct, which is they're structured as month-to-month payments, but overall, the contract is for a total of three years from January 24 through December 31, 2026.

So as the units perform, we pay out month to month that capacity payment. There's also a component where we do provide funding in order for them to go through maintenance, to do upgrades that the DWR would approve, and to make sure that the units are ready and available to respond to California ISO dispatch.

So, it's important to think of the contract as a whole and that the negotiation with the counterparty was contingent on having the all three-year contract and the visibility of all of those aspects combined together as part of that negotiation.

Right. So, I appreciate that. That's why I described my question that way. So, I'm asking how much you've spent on upgrading like Ormond?

How much have you spent on, I understand they were going to take a, a chunk of the money and rip out the powerhouse, build a whole new crane and upgrade that OTC that was scheduled for being taken offline. So how much have we spent to the contracts on upgrading Ormond, for instance?

We can definitely get those numbers for you, but I think in that specific question that you're asking, I'm not aware that that has happened. The funding that DWR has provided is to be able to maintain the resource in its current operation in order to respond to the Cal ISO.

I'm not entirely sure if what you're asking for is maybe a future development for-

My understanding was to make that resource even available to the grid, that major overhauls were going to have to be sunk into it to get it operational. So, I'm just trying to figure out, I get that you're obligated in the capacity payments. I get the structure of the contract.

I'm asking about how much has been spent on the physical asset to get a sense of how much we're on the hook for, for spending to upgrade these units.

And if we should anticipate you all asking for another extension post 26 because say we've spent $300 million of taxpayer's money on upgrading an old gas plant and making it new again, and are we just going to walk away from that asset? Are we going to keep going with it?

So, when you say we've seen the contracts, we haven't seen the contracts. You have the contracts, but we've asked questions about them.

You've given us responses and I get the defense of the structure and all that, even just to see the terms of the contract or understand these and really to include that in the JARPA or at least an update on 205 I think would be really helpful. So, you're saying you don't have that information today, though, how much?

Not today, but happy to provide that, too, sir. We can definitely provide the contracts as well. And just to make clear, our goal is to maintain the facilities, not to make them like new. So, I think we're on the same page there.

I guess, just to finish up that line of questioning, and thanks, Mister Chair. My understanding is that we cannot - there's no reversion clause and that we can't actually, if we say we've only spent $300 million out of the $1.2 billion contract, we can't go take the outstanding 900 million and divert that, say, to think to assets that we're actually going to utilize.

That's my understanding of the terms of the contract, is that it can't be altered for the sort of the unspent funds. Is that right?

So, I want to maybe make a slight modification to that. So, the amounts that we have committed are maximum commitment amounts, and it's to cover contingencies that we see and conditions that we see pursuant to the contract. But to the extent those funds are not spent, for example, because there are provisions, for example, if the, not every contract, but some of the contracts, for example, have both penalty and performance provisions. So, if they perform well, they can earn some additional funds. If they don't, they can get penalized. So, depending on how that.

Understood, but they don't perform at all, which is currently what they're doing. Right. We have not utilized any of the OTCs to meet any of these events, is that correct? We've used-

But again, do you want to be careful?

I get that they're on capacity. I get that they're on reserve. We've paid for the reserve, but we have not actually run those OTCs under these contracts to meet any of the grid reliability events that ISO was referring to. Right. The number was zero, at least in the chart, of how much they've actually been utilized.

Like turned on. Have they been turned on at all?

They've been on standby in case of an emergency.

I got standby. I get. I'm saying, have they been run?

Not its maximum. Not to its maximum capacity. That's correct.

Okay, so those are sort of sitting on layaway. We've put over $1.0 billion into them. We don't - we're going to find out how much we've actually spent on that. Meanwhile, the assets that have kept the grid solid, what I've heard is huge increase in storage, great performance out of what we've got out of DSGs so far.

Further looking at the DSGs and that kind of demand side work from ISO, but we've only spent, I think my math is here, about 18% of the funds that have been appropriated on DEBA and DSGs thus far. If you combine both, I think it's about 540 million and we've only spent a combined...whatever, you get the numbers.

I know this year in the budget we moved that from general fund to the GGRF. I'm really happy that we're at least keeping the money moving, but I'm frustrated with the pace of things, and I see your chart anticipates growth and increase.

The concern is at the same time you're anticipating this growth and things coming online and us hitting higher numbers in 25-26. Meanwhile, Edison's plan on VPPs and demand side work was rejected at the PUC in part, DWP has pulled back.

So, I'm just trying to wrestle with, and I get that that's a ratepayer funded application versus a GGRF non-rate based funded. But should, what kind of takeaways should we be deriving from that?

Sort of the underutilization I guess of the appropriated dollars and are we going to see a ramp here soon and a sort of engagement with utilities on this front or is there still a, I guess a discordance, like, "Okay, yes, we'll spend GGRF on it, but no, we're not really going to encourage the utilities to keep going with it." Maybe between CEC and PUC you could comment. I know there's sort of two different sources of funds, so two different sets of sensitivities too.

But yeah, I'll start with the ratepayer aspect. And I think maybe the most important thing to think about is that we have a range of these types of VPPs and demand response programs. We're doing pilots. We have existing programs that have been in effect for quite some time.

We have regular RA programs, programs, demand response programs that qualify for RA, and we have emergency programs. And so, what we're looking at is really kind of bringing forward lots of types of creativity, but also being very careful as a steward of ratepayer funds. These funds all show up on electricity bills.

And then given the uncertainties that we have moving forward, we're kind of designing to address those uncertainties, but making sure that the programs continue to fit what we see and anticipate and get the most bang for our buck from ratepayers.

And so, as we, and I think the utilities are, and the CCAs in particular are being very responsive and creative. But when we compare across a whole portfolio of programs, we're going to want to focus on the most cost-effective ones and keep kind of driving towards those.

And so that doesn't mean that we allow ratepayers money to be spent on everything everybody wants to do, no matter the cost. And so, we really are seeing a great uptake. We're learning a lot about VGI. We're learning a lot about VPPs, and then we're also, of course, doing the larger kind of megawatt programs as we go.

Senator Stern, I think just thank you for that question. Just want to add kind of a little bit of color to what President Reynolds just mentioned. As you know, like one of the things that you asked the CEC to do was the load flex goal.

So as a part of the goal, we've set a 7000-megawatt goal statewide by the end of 2030. And we really categorized them into three buckets. The first bucket was around the load modifying. So how do you make sure that the rate design really enhances our ability to flex demand?

There's a number of steps that are being taken there through PUC's CALFUSE use proceeding, CEC's work on the load management standards. And there's an opportunity to really think about how do you extend that wedge? That's the first part. The second part, I think is kind of the regular resource adequacy, which we call the proxy DR planning today.

How do you see that wedge moving forward, especially given the number of things that are happening through more and more gadgets we have today? So, like, is it a gadget backed or is it behavior program and how do they evolve? And the third bucket is the emergency programs.

So, what the, you know, the funding through the DSGs and DEBA has given us is an opportunity to test new concepts of program design.

And I think one of the things we are doing, and we're working very closely with PUC on, to the extent that these programs are viable in terms of cost effective, they can kind of migrate into the middle wedge, which is kind of more on the RA side.

But right now, based on the legislatures ask, we really are focusing on that VPP bucket, which is market aware. It's not dispatched by CAISO, but in the day ahead timeframe, if the prices meet dollar 200, they begin to dispatch and support. And that's what happened in July. The prices were 200.

And the DSGs in option three started to become a part of that so I think we are kind of thinking through that in that lens, but really welcome your push and challenge on continuing to expand those programs.

Thank you. My last question, if you'll indulge me, Mister Chair, just to follow through the thought. I hope we can leverage as much federal funds on this front as possible. We know there's money out on demand side support as well as on the transmission side too.

And so, the more we can get outside the rate base and find other source of money, time's taken here. We got a short window, we got a couple big deals through the pipeline, but I'd love to see more action on the energy front to leverage all that.

But just turning to ISO just for your sort of rounded out take on meeting these reliability challenges, what I didn't see in the report on the Pathway's Initiative, which is just sense of what you all anticipate or have modeled retrospective numbers on the 5.85 billion in gross benefits for participants since 2014 in the IM.

But do you have numbers on sort of under this new hypothetical model that's before the board, what we could see both from a California ratepayer savings perspective, as well as a sort of, of this reliability, how much of this could actually meet so we don't have to be turning on the OTCs or relying on them?

How much of that could come from this new enhanced e-dam or whatever?

Thanks very much, Senator. There's been a range of different studies. Obviously, like everything, it's assumption driven. It depends on how broad the footprint is. But just this last quarter, the energy imbalance market itself produced about $365 million of savings for consumers.

We could see at least that, probably close to a doubling of that on just the economic side. I think the key thing though, that I'd like to emphasize, and we've been finding more and more, is that really the ability of the broader footprint market to support the system during extreme events. The reliability element is becoming increasingly important.

I think as you see the reduction in the number of energy emergency alerts, that's our goal. We want to keep the system calm. We want to have that wide area of visibility.

We want to understand not only what's happening in California, but what's happening in the broader west, so that on a day ahead basis will have the ability to move power to where it's most needed given the capabilities of the transmission system.

So, I think both a significant improvement in the economics, but probably even more importantly, I think the reliability benefits are going to be where the value proposition really is going to lie.

I really appreciate that, and I just, I hope you take the next step. I think you've put a really good proposal on the table. I appreciate the public interest edition, and I hope we keep, you know, going forward deliberately.

Thank you. Senator Seyarto.

I thank you very much and thank you for all the information today and keeping us up to date on our efforts to have reliable energy to our citizens. A couple questions regarding the Pathway's Initiative. I'm looking at your next steps and the July-August public meetings. How many meetings have we had so far?

So, the Pathway's group has done multiple stakeholder meetings. I believe two was just based on the workshops. There's a third one in process, but as a matter of their process, they have been doing, I think, one every month, a public kind of discussion on the progress. It's the Pathway's committee doing that.

And in terms of CAISO, I'll differ to CAISO in terms of when they got the step one and what workshops were done there.

Yeah, usually I get to know more than the public when we're having these, and this is the first time I've even seen this.

So, I don't know what our outreach is to the public and when those meetings are, but this is something important for people to understand so they understand why we're doing it or why it needs to be done. And if it's something that is just kind of part of a box to check off.

Oh, yeah, we did public meetings. We did this, and now we're doing this. You're going to have a lot of pushbacks from the public because anything that they think is or it might raise their rates right now, they're hypersensitive to it.

So, on one of your slides, you had the issue about what, you know, some of the issues going on with transmission reliability and stuff. You had 19 incidents of transmission issues. That's more than all of the years combined before here. What is going on with our transmission issues?

Yeah, I'll speak to that, Senator, thanks for asking the question.

We have a special category of alert known as a transmission emergency, which is, honestly, it sounds a little bit more extreme than what it really is.

It actually typically refers to a very discreet set of events in a particular portion of the grid where due to fire, which has been the case this summer, there is stress on the local transmission system that requires a change in generation patterns.

And typically, it allows the ability of the utility that's affected in the area to have its power side and its transmission side coordinate in extraordinary fashion. So, by the declaration of the transmission emergency, it opens up access to some additional resources. It allows for enhanced communication, and then we're able to bring that to resolution.

We have been operating that in particular up in Northern California for quite a number of days this summer. We've been able to prevent any broader disturbances. But it certainly is a very different category of event than an energy emergency alert, which refers to a broader reliability issue for the broader grid.

Right. Just this last month, at the end of June, beginning of July, El Dorado Hills: two days in a row, thousands of people without power, 5 hours, it's 105 degrees. And so, I think those are the things that the public worries about.

And so, when we're talking about transmission and you're talking about wildfires and transmission lines, you know, that's one of our concerns also. I look at this whole process, this whole effort, the whole effort to address climate change and go 100% renewable energy and all of that as trying to get from point A to point B.

That's all right. And the fastest way on the road to get from point A to point B is to jump in your Tesla model S and get on a straight road that has no bumps and no curves and go 120 miles an hour. And sometimes I feel like we're trying to do that.

But the problem is we're on a curvy road with a bunch of bumps. We have a curvy road with a bunch of potholes in it. And those potholes are and the curves are stuff that we don't control: weather. Whether or not we meet our goal in 2045 or whatever it is, the weather is still going to be an issue. It's not going to change. Even when we hit our goals, it is not going to change. 1% is not going to change the world's weather. The natural disasters, because that's not just weather related.

Those are also earthquakes. We are earthquake prone out here. That can set us back our infrastructure development problems. That's another curve that makes us slow down. And those supply chains and things like that, a big one.

It's really big right now is the cost borne by consumers to try to do all this, going 120 miles an hour, trying to get from point A to point B before it's actually practical for us to get there.

The problem with that is as consumers become more and more unable to keep up with the costs, they start leaving our state. And we're heading into some economic issues now that are starting to reflect that. And the last part of one of the other curves is our budget.

Obviously, our budget is not what we wished it could be to be able to address all these problems so we could go 100 miles an hour down that straight road.

And so, you know, I think in terms of being able to accomplish all of these, set goals, we're struggling with that, and I think we're going to continue to struggle, and that's what we need to be able to plan for. We need, number one, to be reliable, to keep our public safe.

And part of that means going at a pace that allows us to bury transmission lines where they need to be buried and not make excuses for why they should be okay over a brush area. They're not. We have the opportunity to understand that that makes a difference.

You've said it three times in this hearing that transmission lines and fires don't work, and yet we continue to go down that same path. Why? Because it's better to do it faster than it is to do it right. And that's what I want, to make sure that we're doing it right.

And so, some of these efforts are in the right direction. You guys are doing a phenomenal job ensuring that you're working with the tools that you have to ensure that we're as safe as we can be and we're as reliable as we can be.

But the faster we go through those curves, the more chances we are going to get that we will run off the road. And any one of these things can be the trigger for that happening. And so those are my concerns.

And like I said, I appreciate what you do every day to keep us powered up, and so do the constitutions out there. Thank you.

Thank you. Senator Dodd.

Yeah. First of all, appreciate you being here today. I'm sorry I wasn't able to be in the room the entire time, but I was watching a little of my office in between meetings.

Obviously, we have reliability issues, transmission issues, we got rate relief issues, and we're trying to do this all in the context of a zero-carbon future. I don't need to give platitudes to any of you, let alone all four of you, in terms of the job that you've done.

I'm leaving here in three or four months, and I just do have to tell you, and I think that Senator Seyarto is right. We have a lot of struggles. There's a lot of issues.

And to use the analogy that our good chairman used earlier about flying this plane while we're re-engineering it and doing all the work. I can tell you as I'm leaving the legislature, I am confident in the quality of the people that are sitting in front of me and the job that you're trying to do every single day in making this work, not only not for the legislature, for the people that we all serve.

And while it's not perfect, just know that there are people that are noticing the really great work that's coming out of this state because of the four of you and the people that you work with every single day. Thank you very much.

Thank you. I have some comments, but I was going to see if your schedule allows you to first hear oral communications. We want to hear from the public first. So, if there are members here in this room who have comments, we ask you to form a line, and we'll give you 1 minute each.

I think Mister Wetch is the first one up.

Thank you. Mister Chairman and members: Scott Wetch, on behalf of the California Coalition of Utility Employees and the State Association of Electrical Workers, are focused on the Pathway's process. As you all know, we've been the proverbial fly in the ointment and opposed all three of the prior legislative attempts at regionalization.

Those proposals would have transformed the CAISO itself into an RTO. In contrast, the Pathway's Initiative would preserve the CAISO and its balancing authority and other functions, except for control over the energy markets. The IBW is a member of the Pathway's Launch Committee. We are pleased with the progress that the launch Committee has made in the past year.

We remain optimistic that the launch committee will be able to make a recommendation to create a new regional organization and transfer oversight of the energy markets from the CAISO to the new regional organization. This step will enable many more utilities around the west to join the day ahead market.

I want to emphasize that we foresee that the proposal would not affect California, California's or any other state's ability to protect its policies, such as renewable furlough standards, transmission planning, cost allocation, or ghg reduction. It could even enhance our ability to decarbonize at lower costs by allowing us to use solar, wind and hydro resources more efficiently.

I also just want to emphasize that the pathways proposal being developed would preserve California jobs, unlike previous regionalization proposals. We look forward to working with the legislature next year to enact that legislation that would allow California Utilities to participate in a day ahead market with a wider footprint.

Thank you for the hearing today and for all the participants.

Thank you. Any other comments?

Thank you very much, Mister Chairman. My name is Dan Jacobson, today advocating on behalf of the Clean Energy Buyers Association.

I just want to thank the panel very much for their hard work and particularly focus on resource adequacy, which we think is a critical piece to both being able to help keep the rates down, but also be able to move us toward more clean energy, the loss of load and the one in 10 expectation we think is critical.

This committee has moved out bills that would help us move toward that, and we would encourage us to continue to move in that direction. So, thank you all very much.

Thank you.

Thank you, Mister chair and members: Meghan Loper, on behalf of Western Freedom, which is a coalition representing large energy users across the west who are interested in clean, affordable and reliable energy, and would like to thank the panelists and the committee for the continued focus on reliability and affordability and how we reach our goals.

Kathleen Stacks, who's the Executive Director of Western Freedom, has been honored to serve as one of the Pathway's co-chairs and has felt that it has provided a great opportunity for collaboration and really good discussion, not only with many of our California based stakeholders, but other partners across the west.

And we do look forward, as you heard from Mister Wetch to those continued discussions and hope that this process will allow us to come back to the legislature better informed and with more consensus about what policy proposals the legislature should continue to consider in the future to help us reach our affordability, reliability and clean energy goals.

So, with that, thank you for the continued focus on these issues, and we appreciate the work of the panelists and your committee staff and all of you. Thank you.

Thank you. Mister Cook, come on up.

Mister Chair, members: Greg Cook, representing Northern California Power Agency. I would like to pursue the questioning that Senator Stern raised with Department of Water Resources, specifically the use of existing funds, available funds for the retrofit of existing facilities to make them more efficient and provide greater resources as we go into the future.

Specifically, the Northern California Power Agency operates the Lodi Energy Center. The largest investor in the Lodi Energy Center is the Department of Water Resources. They own 38% of the facility. NCPA has a proposal to improve the efficiency of that operation by 25%.

The Energy Commission has seen the value of that and so they have contributed $7 million to the cost of that improvement. The Department of Water Resources has sent signals that they are not going to participate in funding and expanding that facility's resource they utilize.

They, as I understand it, they use the passage of Senate Bill 1020 a couple years ago as the rationale for why they cannot participate in this extraordinarily important expansion of an existing asset to increase the efficiency of that facility by 25%. I don't understand the reason why, and I would like the committee to pursue that.

Thank you very much.

Thank you.

Mister Chairman and members: John White with the Clean Power Campaign. Thank you for this excellent hearing and for the testimony. For us to keep track of all these moving targets, I want to return to the pending central procurement proposal at the PUC.

One of the things that's missing from that proposal that was originally intended by the legislature with the passage of AB 1373, is Imperial Valley geothermal being procured. Even though the midterm reliability procurement directed the utilities to buy geothermal, the load serving entities haven't signed power purchase agreements.

So, the geothermal we're trying to develop down in Imperial for the ability also to develop the lithium industry is going to be delayed. So, we really hope the commission will take a closer look at the value of the conventional geothermal and include that in the procurement by DWR. Thank you.

Thank you. Any additional participants here in the room who want to add comment? Testimony? All right, seeing none. I too want to thank our panelists. You've done a yeoman's job with what you have to work with, and I'm just going to be honest, you're doing it with your arms tied behind your back.

And much of the reason why is because of some of the aspirational policies that we have passed as a legislature. And I'm just going to be real about that.

As someone who is in my 14th year in the legislature and have chaired energy on both the Assembly, I have no doubt that much of what we pass has good intentions. But as the old folks used to tell me, "The road to hell is paved with good intentions."

And we find ourselves here today with these challenges because our legislation has been more aspirational than practical. And when I look at the title of this hearing of electric reliability towards zero emissions, we're focusing on intermittent resources instead of dispatchable resources, baseload resources.

And when we talk about zero emission, we're focusing on not the two cleanest sources of zero emission energy, and that's nuclear and hydro. So, at some point we need to start having real adult conversations about what our goals and objectives are. If it's about zero emissions, then we need to talk about the cleanest source.

You talk to any electrical engineer in the world, and they'll tell you, as you guys will attest to, hydro and nuclear are the cleanest sources we have. So, we talk about reliability. Baseload dispatchable resources is where we have reliability, not on batteries, wind, and solar. And we need to expand upon that. We need to have those conversations.

And that's where I think we lose the public and again, and then, as we say, we drive up costs. As my colleague stated, if we're really talking about consumers, consumers are feeling this.

And we need to be more practical in what we're trying to do, legislation that we can implement that really achieves the goals of a cleaner environment, but more importantly, a reliability, and we wouldn't have made our climate goes two years ago, our world climate goes if it wasn't for natural gas. But nobody wants to have that conversation.

And so that's my desire as I leave the legislature, that we have policy more rooted in. I want to see reality and implementation, and we need to hear from the agencies, and we need to hear more pushback if we're moving in a direction that makes it harder for you to do your job.

So that's where I am on that. So, I don't know if any more comments by my colleagues. All right. Well, again, I want to thank you for your testimony. I thank you for the work that you're doing on a daily basis. It's truly needed. And as our colleague stated, we're creating some of those potholes.

And I want to be able to help you guys implement this and make it work for all Californians and for the environment as a whole. So, for any individual that didn't get a chance to address the committee, we ask that you submit your questions or comments in writing.

We'd be more than happy to look at them in consideration. And I want to thank the staff and individuals who called. I want to thank everyone for your patience and your cooperation today and participating in this hearing. We've concluded our agenda, and the Senate Committee on Energy, Utilities and Communications is now adjourned. Thank you.