Assembly Standing Committee on Utilities and Energy

Okay, we're going to get started. Good afternoon, everyone. Welcome to the California State Assembly Utilities and Energy Committee hearing. Like to call this meeting to order the hearing of the Assembly Committee on Utilities and Energy. We're here for an oversight hearing to hold our annual review of the California energy entities with a specific focus on reliability and readiness for summer 2023. Before we begin, I have some housekeeping to go over. The Committee is welcoming the participation and interests of Dr. Wood today.

So welcome, Doctor, to the Committee hearing. One of our panelists will be participating remotely. However, there will not be public phone testimony, so public comment can be made either in person or submitted via email on our Committee's website. Additionally, I will maintain the quorum during the hearing, as is customary, in order to hear as much from the public. Within the limits of our time, we will not permit conduct that disrupts or otherwise impedes the orderly conduct of the legislative proceedings.

Thank you, panelists, for being here this afternoon to hold this very timely conversation leading into the summer of 2023. As we are all aware, the last three summers have caused their share of challenges to our electricity grid. From the unfortunate rotating outages in August 2020 to the bootleg fire in July 2021 that cut off a large portion of energy imports, to the Labor Day weekend heat event last year that seen some record breaking temperatures throughout the state and the highest demand on CalISO's history.

It's unclear what summer 2023 will bring, and I look forward to the hearing as part of today's discussion, what the energy entities anticipate might happen in the next few months. These extreme moments to our electricity grid have spurred us to action.

And all I want I do want to commend the panel on your work these past few years in keeping the lights on and consistently prioritizing reliability, because certainly when the power goes off, especially during a heat wave, lives are on the line, California's health and safety is impacted. But now we are three years out from the 2020 outages, and we have taken extraordinary action through policy and regulatory changes and extensive funding.

That is why we're reviewing and we're wanting to review the effectiveness of our efforts and to understand how ready these efforts have made us for this summer and the future years to come. Legislature has had to make some difficult decisions to shore up reliability, including the extension of Diablo Canyon and the creation of the Reliability Reserve. And this Committee thanks the extensive work and collaboration with our colleagues in the Budget Committee during the analysis and review of these extraordinary proposals.

I also hope today's discussion can provide an opportunity to reflect on the implementation of these recent budget actions and their effectiveness and the impact in the broader energy market. I also want to note that while today's discussion is focused on reliability, this hearing will serve as an annual report on the Legislature from the CPUC and the Public Advocates Office. So we welcome broader comments and questions about all the aspects of these entities work. With that, I'll turn to my colleagues to see if anyone else has any opening remarks. And I'll look to my right. To my left, please.

Thank you, Mr. Chair. Well, I am excited to hear from the departments and the agencies on the progress of reliability. That's for sure. It's encouraging to hear the good news from the Western Electricity Coordinating Council on Reliability from the Committee. Background paper quotes in quotes all regions in the west show adequate Reserve margin to meet demand under extreme conditions. End quote.

While I'm encouraged to hear that we are trending in a positive direction, California does have an increased risk when compared to other Western states due to our reliance on imports. Clearly, the need to prioritize large and robust procurement orders was a right call by the Legislature. We need to balance the need for reliability with providing clean, carbon free energy. I look forward to hearing what the status of those orders will be from the panelists that we have today. Thank you.

Thank you. Anyone else? Okay, we will ask the panelists to come forward. We welcome them. We'll ask that the panelists provide their opening statements. Then we can turn to the Committee for questions after the last panelist presents. Again, welcome, and in the order that you're outlined in the agenda, you may proceed. Thank you.

Good afternoon, Chair Garcia, Members of the Committee. I'm Alice Reynolds, President of the California Public Utilities Commission. I'm pleased to be here today to discuss summer reliability with my colleagues from the California Energy Commission, the Public Advocates Office, the California Independent System Operator, and the Department of Water Resources. As you're likely aware, the PUC regulates privately owned electric, natural gas, telecommunications, water, railroad, rail, transit and passenger transportation companies.

With respect to electricity reliability, the PUC directs electricity procurement carried out by the retail providers of electricity, what we call load serving entities. These entities are community choice aggregators, electric service providers, and the investor owned utilities. And they're responsible for providing power to customers within the territories of the investor owned utilities, which is about 75% of the state's energy load. In addition to reliability responsibilities, of course, the retail providers also are responsible for meeting the state's clean energy mandates.

California's progress on the path to 100% clean electricity grid means that we now have a large fleet of renewable energy resources which provide reliable and Low cost power to serve our businesses, industry and residents. We're also interconnected to the westwide grid, and on most days, the electricity system has more available resources than needed to serve load. But we know that climate change is disrupting the status quo and causing severe weather impacts that include extreme heat waves, bringing unprecedented electricity loads to California and throughout the west.

In addition to increasing energy demand, we're also seeing a shift in the timing of peak load moving to later in the evening. You may have heard discussions of peak versus net peak, net peak being the peak energy load that the system has to cover without solar. Essentially the two are merging. We're seeing that the highest peak load tends to occur later in the evening. And we're now focusing on system capacity in the evening hours, with around 08:00 P.m. Being the focus of system reliability planning.

And I'll note that if you happen to check the Kaiso website yesterday, which I do frequently, you'll note that our peak load was around 08:00 P.m. And solar was essentially zero at that time. I'm looking forward to the time we have here today to present an update on the joint agency efforts that are ongoing to meet this challenge. So, to give you an idea of the run of show, we're following the agenda set forth by the Committee, and I'll start with a few slides on background.

And then after Mr. Baker's presentation, Vice Chair Gunda will describe updates to the resource stack analysis and the latest snapshot on summer reliability expectations, followed by presentation by Department of Water Resources and CalISO. Moving to the slides that I have, the first one I see is already up. Thank you.

And I wanted to note on this slide that over the past five or so years that one of the PUC's top priorities has been to ensure the reliability of the electricity grid by ordering load serving entities to quickly bring electricity resources online in near and midterm to meet increasing demand, irregular weather patterns and the peak load. So, as you'll see, between November 2019 and today, we've ordered a total of 8800 come online by 2028, which is the largest requirement for new clean energy in state history.

That means that the load serving entities, the investor owned utilities, community choice aggregators and electric service providers are all responsible for signing contracts to bring their portion of this new amount of procurement online in a timely manner. And for context for this number, yesterday the peak demand was around 29,000 MW. So you'll see that with these decisions we've ordered more than half of what we needed yesterday.

And importantly, also note that the procurement order from 2021 ordered 1000 long duration storage and 1000 long lead time resources such as S Geothermal. We're looking for these specific types of resources because of their stable energy profiles which allow them to provide energy on demand in the evening hours for extended periods of time. Slide two, please.

This table shows a breakdown of what the types of new resources that we expect to come online by 2026 by technology type, based on what load serving entities are providing to us. So these are the contracts that have been entered into and the main takeaway here is that the lion's share of new resources is going to be standalone storage and hybrid solar and storage resources.

Hybrid solar and storage means that storage is being added to existing solar resources or new solar and storage resources are being built in one location. And while all of the resources listed here do contribute to our electric grid needs at different hours of the day, battery storage significantly contributes to our near term reliability needs during the 08:00 P.m. Evening peak when the grid is most stressed. I'll go to slide three now.

Slide three shows the pace of new resource development, and keeping up this pace is critical to making sure all of our procurement orders result in actual steel in the ground. We have an interagency task force called the Tracking Energy Development Task Force, or TED, dedicated to tracking progress project by progress project by progress project. Based on our cumulative tracking, we've seen over 3300 qualifying capacity brought online between October 2021 and September 2022.

For 2023, load serving entities are reporting that an additional 1800 MW or more will be brought online by the peak summer season, with the potential for another 1300 by the end of the year. I do want to make it clear that this unprecedented level of resource development comes with its challenges permitting supply chain disruptions, transmission and interconnection related delays and other factors make developing resources in a timely fashion difficult.

But staff across all agencies are working to collaborate with load serving entities and developers one on one to help overcome any challenges they're facing. Next slide, please. So, brief update on the status of the Diablo Canyon Power plant extension pursuant to SB 846 from last year, the CPUC opened a new rulemaking to consider extending operations of Diablo Canyon power Plant through October 2029 for unit one and October 2030 for unit two.

Phase one of the rulemaking will address funding for the Diablo Canyon Independent Safety Committee and the retirement dates based on statutory criteria as directed by the Legislature. The CPUC is considering information provided by the Independent Safety Committee, the CEC and PUC joint reliability planning assessments, and the CEC's analysis of need to support reliability and cost effectiveness evaluation. Phase two of the proceeding will determine cost recovery and compensation reporting processes.

And the CPUC is also working with the Department of Water Resources on a semiannual true up of PG&E's relicensing and transition costs. With that, I will conclude my remarks by offering my thanks to the Committee, and I look forward to your questions. I do also want to note that I will be stepping out of the hearing room while Mr. Baker makes his remarks in order to avoid any potential issues with ex parte communications, and I will return after his remarks conclude. Thank you very much.

Thank you very much, Mr. Baker.

Chairman Garcia, Vice Chair and Members of the Committee, thank you for the opportunity to present today. My name is Matt Baker, Director of the Public Advocates office. With me here today are Linda Sarazawa, our Deputy for Energy, and Darwin Farrar our Chief Counsel. You should have our 2022 Annual Report and some of the other key slides before you. I hope you've had a chance to review our Annual Report. It highlights our Team's 2022 work to fight for affordability and equity.

The Public Advocates Office is the independent consumer advocate at the California Public Utility Commission. Our top priority is to help ensure safe, affordable and reliable energy, water and communication services. We do this by scrutinizing every utility application, then providing the Commission with our findings and recommendations. This is important because these applications typically request increases in customer rates and impact their utility services. California faced many hurdles in 2022, including rising utility bills, reliability and safety concerns.

I'm pleased to report that we are working hard to address all these hurdles by identifying creative ways to lower utility bills in this high inflation environment, helping to advance the State's reliability goals, and by recommending cost effective solutions to help transition to a clean energy future. A few brief highlights of our achievements in a couple of these areas.

First, the Commission's decisions to update the state's main rooftop solar program adopted our key recommendations on making this program much less costly and fairer for households that do not go solar. The decision will also enhance California's grid reliability by encouraging NEM customers to pair their new systems with storage. Second, the Commission's cost of capital decision for the four largest energy utilities. This proceeding determines, among other things, how much utilities can earn.

Here, the Commission adopted a significant reduction to their requests of 25 basis points, which is consistent with our position and advances the Commission's and our efforts on affordability. Finally, I have a little slide here in the area of our General rate cases. You'll see from this chart how much rates have increased. This is why we are doing all that we possibly can to advocate for ratepayers in these proceedings.

With these rate increases top of mind, we spent most of last year reviewing PG&E, San Diego Gas and Electrics and SoCal Gas's applications and developing recommendations for PUC consideration. All of these will have significant rate and Bill impacts on customers. For each, we have recommended significant and reasonable cost reductions to the utility's requests. We expect a Commission decision on PG&E's GRC later this year and on SDG&E's and SoCal Gas's GRCs early next year.

Again, as you can see from these charts, bills are increasing at an unsustainable rate. We must do all in our power to address increasing utility costs and their impacts on consumers. Since today's hearing is focused on reliability, I want to conclude my remarks with some observations about the costs and ratepayer impacts of meeting our reliability challenges. First, meeting these reliability challenges is increasingly expensive. RA prices have increased substantially between 2017 and 2021. The August system RA prices have increased at 158%.

We expect this trend to continue due to tight market conditions. The condition throughout the west is also very tight. Generally, we can expect higher prices for summer energy imports because of coal plant retirements and a long term trend for higher temperatures in the Pacific Northwest. It is not just existing RA capacity as the President also alluded to many of the new IRP resources acquired to meet the midterm reliability needs are experiencing delays and costly amendments to their contracted price, with increases averaging 30%.

Some of the factors include increases in the price of battery and solar panels due to supply chain, as well as just increased demand. We're also seeing increases in permitting and soft costs, particularly for battery installations. And second point I want to make about reliability and its costs is while these costs are increasing, not all of them will flow through to the ratepayers. Some battery contracts are structured to allow ratepayers to recoup some of the contract costs when electricity is exported.

In addition, we are hopeful the Inflation Reduction Act's tax credits will help ameliorate some of the cost increases. Our takeaway on this is we should be very concerned about midterm reliability and RA cost increases. However, resource procurement for reliability is only one part of the cost of providing service, and it is not a primary driver of the rate increases that we are seeing.

The ones that I alluded to in the last slide, the primary cost drivers are the transmission buildout, distribution investments and wildfire mitigation, as well as legacy customer program costs. Note I would be remiss if I did not point out the General fund's investments in reliability. The Strategic Reliability Reserve provides a cushion for ratepayers and delivers added reliability benefits. These resources give CalISO additional capacity on top of the CPUC's effective Planning Reserve margin of 20 to 25 22.5%.

Given what climate change is throwing at California as we transition to a clean grid, the added reliability is very important. In conclusion, we at the Public Advocate's Office are committed to working with you, the Governor, the Commission and all others to find effective ways to ensure that utility services are reliable, affordable and safe, especially for those most in need. With this, I'd like to conclude by thanking you again for the opportunity to present today. Please contact me if you have any deeper questions and I'm here to answer any questions you might have.

Thank you.

With that, I will turn it over to the next panelists.

Thank you, Mr. Baker. We'll proceed to the next speaker.

Good afternoon, Chair and Members of the Committee. Thank you so much for this opportunity to be here and provide you with an update on the reliability analysis. I'm Siva Gunda, one of the Commission Members at the Energy Commission. For the record, going to the next slide, please. So, as we continued our discussion on reliability over the last two and a half years, we really kind of coalesced around this particular framing of the reliability challenges we face today in the state. One is the planning processes.

This is where we talk about how do we improve our processes to ensure that the climate change impacts are really being baked into the forecasting. How do we ensure that the processes are in sync in a time fashion, where the integrated resource planning and the other procurement strategies take into account those updated forecast numbers so the procurement is adequate? And also how do we make sure then to interconnect them on a timely basis so that's around the planning side.

In terms of the second big problem, we look at the scaling of resources. Obviously, much of our clean energy transition to date has been around solar, wind and some storage. But moving forward we have ambitious goals. On offshore wind, we have transmission requirements, long lead time resources, including long term storage or long lead storage. So all of those things have to be planned for today to make sure we have them in the ground in a timely fashion.

Along with that, the Committee here raised on several occasions the importance of demand flexibility. That's another important element that we need to figure out how to operationalize and happy to answer that in the question and answers. And finally, how do we continue to augment the resources we have for the purposes of the extreme events. So, apart from the planning standards we have, we have enough cushion to ride through these extreme moments. Next slide, please. So, actions taken to date are collective.

And I just wanted to emphasize here, there has been questions from the Committee and the Legislature on having all the agencies work together better. And this is just to showcase that CEC CPUC, the DWR, CalISO, along with the Governor's office, as well as the Governor's office of the business, the GoBIZ, we are all working very closely together under an umbrella structure.

We work very regularly and some of the key elements that we are focusing on are reliability analysis, resource tracking that President Reynolds mentioned in terms of the TED Task force contingency tracking. What do we do with those extreme weather events, how do we plan for contingencies as well as entity specific planning portions, including Kaiso's operational plan, emergency plan, loading order and real time communication. So we have a number of different teams that we're working collectively together. Next slide, please.

So, this is just a snapshot of what we've provided you in February versus what we are telling you today. The big difference here is twofold. One is the hydro conditions. Since the February update to you, we've gotten the latest data from DWR and hydro. Definitely the overall generation increased, but it also comes at a cost with the increased amount of pumping load required to move the water around. So overall there is a net benefit of about 300 MW.

On the top of that, when we came to you in February, we reduced the amount of import availability by 500 MW compared to last year going through this year. Given the drought conditions. But with the ample amount of water and how we are tracking on imports, we feel like we can get to the 6000 level, which also adds another 500 MW. Overall in the net we are 800 MW better than what we told you in February. Next slide please.

So, on the result summary, I just want to give you a minute here. So again, it's improved hydro and improved import situation. So I want to just walk through the table carefully here. So you have three rows and three columns, the numbers in the last two columns. So the first one, the first row there is what we expected our potential shortfall or surplus could be under standard planning conditions. The first number of 1550 was the surplus we mentioned to you in February under standard planning conditions.

And that has gotten really better to 2350. So in an average conditions, meaning average planning conditions that also take into account climate change. We're not saying it's outside, but once you go into the tail events, this extreme events, that's where you begin to see the need for contingencies. In February, we mentioned to you that if we were to have the same amount of heat as 2020, we will be seeing about 1000 MW shortfall or need for contingencies. That has reduced to 200 now.

And if we had a 2022 equivalent event, which was significant departure from the expected forecast, we will be looking at about 1800 need for contingencies. Now, I wanted to raise a couple of issues for you on this. Please note that these numbers do not include coincidental catastrophic fire to transmission. So, as chair you mentioned, at the top we had the bootleg fire that knocked out about 4000 MW in 2021. And if that were to occur, those numbers will be compounded on the top of this.

And also, just to give you a sense, going into 2022, the numbers were looking between 3000 and 7000 shortfall plus incremental risk. So we're significantly better situated this year given the amount of procurement. And finally catching up, our planning processes are really catching up with where we need to be. Next slide please. I'm going to just put this for record for you guys to just look at. But what we wanted to highlight for you here is the amount of new resources we are expecting to come.

So if you look at the table, a couple of positive signals there. So existing resources went up by 829 MW. That's all hydro. We're also looking an uptick on new battery nameplate, new hybrid resources, everything's looking upward. Resource adequacy imports are also expected to grow and collectively you have about 2000 higher supply side conditions. But on the other side you have about 500 deficit or increased demand due to the pumping load.

So overall, when you take these numbers and do an hourly analysis, we end up with the numbers we showed you on the previous slide. Next slide, please. So the question then is, can we get through those extreme events? And that's where the contingencies come in place. I want to take a moment to really thank the Legislature for giving us the tools last year with the Strategic Reserve, the DSGs program, which is the Demand side grid support program, as well as the Distributed Energy Assets Program.

All of these are really helping us to develop resources and have them in our pocket for contingencies. So we listed a few of them here. The strategic Reserve is a big one. That DWR Delphine is going to talk about that in a minute. CPUC programs. They also have emergency load reduction program flex alert and so on. The third one there says DWR State Water Project.

I just want to note that now that we elevated the amount of pumping load, some of that pumping load could be reduced under extreme conditions. So we right now left it as a zero in our contingencies. But if we look at 2020, we were able to get about 700 relief. 2021, not much because of drought conditions. 2022, we were in the 500 range. So there is a pretty big opportunity, but we wouldn't know that until days or week ahead of time.

And finally, we have non program resources. These are CalISO efforts on ensuring LADWP and CalISO, SMUD Bank and so on are working together to allow for some additional balance transfers. Finally, under an extreme situation, we will have to lean on a Governor's Emergency Proclamation where we go into relieving some of the permit limits, and that's where the additional resources come from. Overall, we have a General of 2800 to 2600 contingencies in our pocket today.

We'll continue to evaluate them, and in every quarterly report you will get those numbers. So given the overall conditions of the shortfall as well as the contingencies we have, we are definitely feeling cautiously optimistic going into this summer, much better than last year. And finally, next slide, just on the additional reliability updates, as you know, we have AB 205, 209 and 846 all kind of coming together on reliability efforts. We have a workshop tomorrow where much of this information will be put out in detail.

Our 2023 Hyper, our Integrated Energy Policy Report that CEC develops, is fundamentally focused on interconnection issues, and we're doing that collaboratively with CPUC and CalISO so we can have one state approach to that. And finally, on the Strategic Reserve updates, DWR will speak to the OTC contracts and then we'll continue to answer questions on this. Thank you.

Thank you very much. We'll move on to the next presenter.

Thank you very much. My name is Delphine Ho. I'm the Deputy Director for statewide water and energy at the Department of Water Resources. Thank you so much for having me here today. I'm going to go PowerPoint free today. So let me start by going back a little bit to review what occurred in 2022. So in 2022, DWR was able to secure over 3500 capacity to address summer reliability. The vast majority of that capacity was approximately 3350 firm energy import contracts.

Focusing on summer 2023, the situation is slightly different, so I'll outline the resources we have prepared for this summer. Thus far, DWR has secured 291 generation in preparation for extreme events. Of that amount, 147.5 MW is already online and another 143.5 is expected to be online by September. This last tranche of resources is comprised of new Low emission generating resources based on the same proprietary technology from a different generator model that has already met the California Air Resources Board certification for distributed generation.

This technology's emissions profile has been proven to be Low enough to be exempt from the permit requirements of air pollution control or air quality management districts. The reduction in capacity, though, overall, is because DWR no longer has the authorization to consider imports, but that has been requested through the revised budget for summer 2023. Furthermore, DWR has voluntarily declined to seek any more diesel generation, even though that is still possible under the Water Code through July 31, 2023.

Moving ahead to 24 as Vice Chair Gunda mentioned, DWR expects to have resources significantly increase to 3150. This large increase reflects the recently contracted once through cooling resources that amounts to 2860 MW. Those resources are actually set to retire at the end of this year, and that's been the most significant change in the last couple of months for DWR and increases our total commitments as of April 30, $2023 to $2.1 billion for the Fund for the three OTC resources, the ones through cooling resources.

DWR entered into these contracts at the recommendation of the statewide Advisory Committee on Cooling, Water Intake Structures, or Saquis. Saquis includes representatives from CPUC CEC as well as the Caliso, so I'm in good company right here. And in the September 30, 2022 report, Saquis recommended to the State Water Resources Control Board to extend the compliance date of three of the ones through cooling resources from December 31, 2023, through to December 31, 2026, in order to include these in the electricity supply Strategic Reliability Reserve portfolio.

Without such action from the State Water Resources Control Board, this 2860 natural gas fire generation resources would have retired by December 31, 2023 in order to comply with once through cooling policy. As the Saquis explained, enabling DWR to contract with these existing resources will allow the state to address reliability concerns and populate the strategic Reserve more expeditiously and with more certainty.

While it works to secure additional resources, extended operations under DWR would not begin until 2024 or later and are dependent upon the State Water Resources Control Board extension of those once through cooling permits. We do expect the State Water Resources Control Board to take action either later this summer or early fall of 23. And that concludes my remarks as an update and happy to answer questions. Thank you very much.

Thank you. We'll be asking questions after the last presenter, so please proceed.

Thank you very much. I'm Neil Millar with the infrastructure and operations at the California Independent System Operator. I did bring a few slides, so if I could just start the slide deck please. So just a quick recap of 2022 and a lot of my material is going to be basically aligns with the same conclusions you've already heard from President Reynolds and Vice Chair Gunda.

We've been looking at it through slightly different lens, including looking at what particular tools in the toolbox have been improving in terms of meeting the conventional planning requirements, as well as then looking at the reserves and the emergency measures as an add on to address the more extreme events. So when we look at last year, we were looking at moderate conditions overall until we hit the unprecedented heat wave in September as which obviously set new records and stressed the system.

Now, a few different tools that we had in the toolbox at that time the western energy imbalance market was extremely effective at moving power around and ensuring that we were able to get the power from where there were surpluses to the people that were most in need. We also had the benefit of at that time about 3000 installed capacity of batteries that were extremely effective at helping us meet those late day peaks as the solar output has dropped off.

As you already heard from President Reynolds, that is now our new critical time of day. Next slide please. Some key observations though when we look at the summer of 2023, as I mentioned, our conclusions do also support those you heard from Vice Chair Gunda. We are seeing materially improved conditions in 2023 based largely on the improved hydro conditions overall, as well as the addition of new resources to the grid.

When we look at those and do the assessment against the conventional probabilistic planning targets, we do see that using the resources that are currently in our pipeline to be connected to the grid now or by June 1, that we have a slight surplus of meeting the long term planning targets. And when we look at the resources that are still grinding towards targeting a September 1 in service date, those actually give us a much more comfortable margin up over 2000.

Put in perspective, these same metrics were showing a shortfall last year of 1700 MW as we were going into the summer. And I should mention these contingencies, these events look at us not saying that we would be shedding load, but that we would be calling on emergency measures to mitigate the impact if we hit those. Next slide please. Some other key observations though.

This planning analysis looking at long term planning targets, of course does not take into account and we remain vulnerable to widespread heat wave events that could drive up to high load levels at the same time as threatening imports and as we mentioned before, hours of vulnerability. Do focus on the late evening post solar window hours. The strategic reserves that you've heard about already are something we're working hard to mobilize with the state agencies to ensure that we can call on them when needed. Next slide, please.

On this slide, we've just shown what's giving us the reason for the additional comfort this year. The increased resources, primarily in batteries as well as solar, for charging that storage have been a huge help in our analysis. We're also looking at a roughly 240% of average hydro conditions on April 6 when we took a snapshot to inform our analysis. That more than offsets on the next slide, please. The somewhat modest increase in load when we look across the energy commissions projections. If I could move to the next slide, please.

We're working with our Reliability Coordinator neighbors to ensure that our processes for accessing surpluses if we're in a shortfall situation are fully tuned up and vice versa. We've also been working to improve coordination across the industry to ensure that the roles are crystal clear. And we've also been fine tuning some of our own coordination tools internally for our own operations group. That latter has been focusing primarily on broadening our wildfire visibility and awareness. If I could turn to my last slide.

The other key focus, of course, is on communication. So we've also been doing whatever we can to firm up our communications plan and be ready for this summer, looking at summer system condition bulletins, tuning up Flex Alert communications, and also relying on a very robust social media platform framework for reaching out in times of need. So thank you for the opportunity and I'll look forward to the questions.

Thank you very much. We're going to open it up to. My colleagues looking to the right. Let's start with our guest.

Careful what you wish for, but we're ready. Thank you. So I'm a little bit of a novice here, but I'm going to do my best to not screw something up here. But I have questions and I'm going to address it to each of the panelists. Ms. Reynolds, you mentioned a phrase there bringing procurement online in a timely manner. And so looking at the new resources section there, we're obviously producing power. How are we improving our transmission and interconnection permitting to get it online faster?

As I recall, one of the big reasons for extending Diablo is that we're struggling to get green power resources online efficiently. And I'll add to that after we had the hearing on Diablo here, and after we left, I started hearing about significant challenges of interconnection and transmission in my district to a point where we started asking a lot of questions. And now I'm running a Bill on that because it's a serious problem.

In addition, during that hearing, there was a gentleman who sat right there from Trinidad who talked about one of the biggest challenges we have with our green energy portfolio and our growing green energy resources is the ability to get interconnection and transmission. And so I asked at the time, Ms. Montesantos, about that and she said, we're aware of that. So as we look at reliability going forward, to me that also means we need to have better transmission and interconnection to ensure reliability.

And maybe I'm just a novice because I don't really know. I just plug things in and turn them on and hope the hell they work. So what are we doing? Because we heard from our utility, PG and E in part of the district that it will take seven to 10 years to get the go ahead to do a transmission line. That's an awfully long time considering that things like Diablo have been permitted for additional five years to help with this problem.

So help me with that basic question. I know it was long, but had lot to throw in there.

Sure, absolutely. And you have identified a few areas that are really critical to the clean energy transition and areas that all of the agencies have been spending a lot of time working on. And you're right, this is a significant problem. I'm going to separate out a couple of things that you covered in the question and that really kind of identified some of the key challenges that we're facing. So one is generation interconnection.

And I talked a little bit about the Ted task force where agency staff look at all aspects of the project and try to make sure, from soup to nuts, that we're doing everything we can to facilitate. One of the stages that we work on is interconnection, and I will defer to my colleague from Kaiso to talk about the generation interconnection process.

All of the agencies are participating in a process at Kaiso that is looking at ways to facilitate and make sure that we're managing the interconnection queues in the best way possible. You also raised distribution interconnection and energization, and in particular, I think, energization of new projects, which is becoming a significant growing issue throughout the state. This is an issue that is arising because of significant changes in the distribution system. New load coming online, our expected increase in load.

So California has had a pretty stable load for almost 40 years. So we haven't developed processes to plan for significant amounts of new load, which we actually welcome now because we want to see increase in transportation electrification and building electrification. So we're in a transition period in the distribution system where we're realizing that there are capacity constraints if we're looking at adding concentrated new load in different areas. All of the utilities do have mapping and portal information on their interconnection capacity.

So they have their system mapped and they have interconnection capacity through portals and websites. What we're working on doing with the utilities and managing their work is planning for new loads. So we know that there are existing capacity constraints. Some places on the system have existing capacity, some don't. The places that have capacity are not necessarily the ones where the new projects are coming in.

And so we're trying to look for ways to increase the coordination between local governments, between developers, other stakeholders and the utilities so that they can actually plan ahead and make sure that the system is ready for increases in capacity. That's of course difficult because sometimes the planning doesn't necessarily is you have to get the timing right. When is the project at the right stage? I think, unfortunately we've seen a lot of instances where projects have been ready and the distribution system is not ready.

And so that's not where we want to be. We want to get ahead of the capacity needs and make sure that the distribution system is ready to go. There's a significant volume of work that needs to be done. So I won't say that we have all the answers. We do have existing proceedings at the PUC to work on this issue and we also have almost like an informal strategic task force within the PUC where staff is available to mobilize with developers when we hear of problems.

And so we have been responding to instances where development is ready or we know development is imminent and the system is not where it should be to work on. Have we done an analysis of the load shape of the new development so that we know what is necessary for the system to match it? Are there alternatives, are there even temporary alternatives so we can get those projects online when they need to and get the system ready so that the projects can move forward?

I think that becomes critically important when we're talking about an acute shortage of housing in this state and housing that's going all electric and having housing projects ready to be energized and not energized. We're sending the wrong messages there on that and it's causing a lot of frustration. That's why there's a large volume of bills in this area this year to try to get our arms around that. I do have a bunch. Is it okay if I ask all my questions? I'm sorry.

You guys want to get coffee? It's not that bad. But I noted in the it's also Chair Reynolds as well. I noted in your total September net Qualifying Capacity contract page you had there, 2025 and 2026, you're contracting zero for biomass, biogas. Why zero? You're just not contracting or are you just not everything else is being contracted, but not that.

So these are contracts that the load serving entities report to us. And so everything that has responded to an RFO or RFP that the load serving entities have sent out and then has resulted in a contract. So come in, lease cost, best fit is reflected on the chart. We do have statutory mandates for biomass and biogas and so we have seen some contracts in that area pursuant to mandates. But I expect that it's just and the contracts could be coming.

So the future years don't reflect what we will ultimately see. So I think for the near term you're probably seeing what is the full range of what's going to happen on the chart. But for the out years, we're going to see more contracts come into place.

Okay. Yeah, it just jumped out at me that everybody else was contracted, but there were zeros, so okay. Question for Mr. Baker. Mr. Baker, you had a chart that showed prices for SDG E significantly higher than SoCal, Edison and PG E, which were kind of lumped together. So is that staggered because of rate case decisions or something mean? Why is one so much higher?

San Diego Gas and Electric is particularly high for a couple of reasons. One, it has less industrial load than the other two utilities. And so if you can spread more of the costs out over more industrial load, you can ameliorate some of the fixed costs. I think another major driver of the disparity between San Diego Gas and Electric and the rest of the system is they have a very, very high penetration of NEM rooftop solar.

And in some cases, by our estimate, almost 20% of the rate in the San Diego Gas and Electric territory is due to legacy net energy metered systems.

You also mentioned, and I was trying to type this as I was listening to you said something about just in General interconnection and transmission costs are increasing fairly quickly. So why the increase? What's driving that?

Well, I think President Reynolds touched upon a couple of points, but one is I would just say the distribution system is starting to get old and it's needing a significant amount of reinvestment. We're also wanting to modernize distribution system and we're wanting to, where possible, Harden it for wildfire considerations. So between those three factors, we're putting considerable amount of resources into the distribution system. And as you know, Kaiso is projecting through their TPP another $30 billion of investments in the bulk transmission system.

And I should say that's just for, those costs are financed. So those costs actually are probably about twice as much, just including finance costs and not including any cost overruns.

Thank you.

And if I could say one thing on your last question, just really quickly. I do think that and this gets to the price issue as well one of the potential bright spots in terms of the increasing rates that we're seeing is if we can electrify transportation and eventually heating and cooling relatively quickly in as cost effective way as possible.

Because that's really one of the few areas where we have the potential to put some downward pressure on rates again because we can spread those fixed costs over more electrons and more uses. So at the Public Advocates office, we think it's very important to try to energize those communities as quickly as possible. It really is part of the regulatory compact. The utility has an obligation to serve there's, load there. We'd like to see it move as quickly as possible.

It's more complicated than that, as President Reynolds alluded to, but it is a very important issue for us.

Thank you. Mr. Gunda, you also referenced interconnection and transmission processes, I believe. Maybe, and this is kind of a General question for everyone. Is there any possibility that things don't take seven to 10 years before they can actually begin to do some of these, or is that going to be the time frame? And the reason I'm saying this and frame this for you we're looking at potential offshore wind development. We're talking about gigawatts of power, certainly in Northern California.

No capacity for transmission there at or actually, when do people start planning for that? Because I don't know. How awful would it be to have an amazing net green resource there and be mired down in a process where we can't move that power?

Thank you, Assembly Member Wood. Absolutely. I think just kind of elevate your concerns on the interconnection and transmission issues, I think they're absolutely important to tackle and I think absolutely real. So I'll kind of comment on a couple of things and I'll pass to my colleague Neil here. So, two elements. So the Energy Commission has an opportunity to work with CAISO and CPUC through the IEPER process to really elevate this issue.

So because of that, for the 2023 IEPER, we are really focusing on laying out the problem statement of where the interconnection issues are coming from, really kind of provide transparency. This is one of the questions that the Legislature asked us in our earlier hearings. Do you guys have a Gantt chart on what's happening?

So that's one of the products we are hoping to develop this year is to provide you a full timeline and flowchart of the interconnection process, both on the transmission side as well as the distribution side. Two: we would like to elevate the barriers and then three: we would like to showcase some of the solution metrics that the stakeholders are proposing.

So, on the problem statements, some of the things that were elevated in the last two workshops we had comes down to resources just fundamentally both on the transmission side as well as the distribution side from the IOUs. What we've heard is this two to three fold increase in the interconnection requests on both sides is really jamming the resources.

We are just not equipped in terms of resources to be able to do all of that work rapidly. That's one. Second, we heard about potentially the issues around transparency, how, for example, in the distribution side, we've heard within the utilities, not all departments work together. So they themselves do not have transparency on the totality of the issue. So that's something as a problem statement that was raised.

And third, just the sheer volume of deploying this with the necessary workforce. What we've heard over and over is it's not a construction issue. It's definitely like the construction resources are available both on the bulk side and the distribution side, but it comes down to the planning and early execution side. So I will have Neil comment on that. As a part of the solutions, just to elevate a couple of pieces, there are midterm and long-term solutions being deployed in terms of enhancing our planning, right?

So the transmission queue process, the reform process. Similarly, on the distribution side, we have some processes in place and there was an absolute ask for Bid Solutions. So one particular example to elevate, we have this in LA area, we have a particular client who has a lot of electric trucks ready to be deployed, but not necessarily have the energy to plug them into.

And one of the creative solutions that they are doing right now is deploying sub transmission and distribution level resources that can just be used for plugging the load. So those were elevated as potential solutions over the next year or two as the rest of the processes catch up. So I'll pass there and pass it to Neil Millar.

Before you do, could I follow up on that? Because I've heard the same thing. I've heard that it's not the construction end of it. There's a workforce, they're ready to go, they're there to do the work, but it is in the planning piece of it. And you just said yourself that you've got a lot of requests coming in, so the bottleneck is there. What are you doing to expedite that?

Yeah. So that's where we--we who see do not work directly in that space. So I would love for Vice President Miller to kind of answer that question.

Okay. Sure. Yes. Thank you, Vice Chair Gunda. Let me jump in and provide. I'd like to provide maybe a bit of a snapshot of where we're at and that we definitely see the need for major process change that we're working on actually this year. So just in terms of where we're at, we do hear the concern about new resources coming online, new transmission being added, and new resources getting connected.

Just to remind people, we have been--over the last two years, we've been averaging about 4,000 megawatts of installed capacity being added to the grid each year. And this year, we think we'll probably be breaking the 8,000 megawatt of new installed capacity. Now that's, I'd say, good progress, but the challenge is to sustain that.

With the concern about the availability of additional transmission that's needed to bring more resources on on a sustained basis year over year, we did try to pilot about a year and a half ago and took the unprecedented step of actually publishing the list of all the projects in our interconnection queue that could get connected, either with no new transmission upgrades necessary--they just needed to get connected--or that relied on transmission that was already approved and moving forward through the construction process. And that totaled at the time about 20,000 megawatts of new capacity.

So that shows that there's a good start on moving on these projects. But as we move from an average of needing to add several thousand a year to 7,000 megawatts of new installed capacity year over year, those processes were not going to be sustainable. That's where we saw that we do need to do much more to tighten the linkage between the resource planning, transmission planning, the interconnection process, and actual resource procurement because one of our challenges is keeping so many projects alive so that they can be choosed from in the procurement stage.

And just to hit some numbers on that, we currently have 180,000 megawatts of capacity in our interconnection queue that is lobbying for a PPA so that they could move forward. Also this April, we ran another open window for new applications and received 541 applications totaling 354,000 megawatts of capacity that is competing to be the lucky ones who get a Power Purchase Agreement and move forward.

So we need to tighten our processes to winnow down that excessive level of competition, sort out who's going to actually be successful, and get the transmission and interconnections moving for those particular projects because otherwise having this excessive volume clamoring to get connected, as you might have guessed, they're all saying there is no transmission for us, but many of them are coming in at the end of a very long line.

So this is where we do need to tighten the linkage across the spectrum. The resource planning side and the transmission coordination, I feel, is moving fairly well at identifying the key areas where the transmission system is being reinforced to allow generation to connect. And that's something that we've been working very well with the Public Utilities Commission and the Energy Commission on. And in this year's transmission plan, we really took extra efforts to call out those zones where the transmission system is being reinforced because those are areas that as a matter of state policy, those are the areas where the resources should be getting developed.

Those are the good areas, they've got the right attributes, the land use, and that we're focusing the transmission. But at the same time, we do need to get our arms around this hyper level of competition for being the ones that actually get connected because adding 354,000 megawatts on top of 180,000 that's already in process, that's just not a good use of in planning and engineering resources, and to be blunt, it's a distraction.

So this is something we're working on inside, looking at our processes right now, how we can tighten the linkages in collaboration with the Energy Commission and the Public Utilities Commission to put sharper focus both with the Resource Development Community as well as with the people actually signing Power Purchase Agreements to be buying the resources out of those areas, to be signing those contracts earlier so that we can focus on the projects that are moving forward and actually get the transmission built that they specifically need.

I think we're making very good progress on identifying and moving forward on the big, longer lead time projects, but the local area projects that depend on which specific projects are going to get a contract, that's where we also need to really sharpen up. Now, you also mentioned offshore wind, and I really wanted to make a point of that circling back to that because in the transmission plan that we're bringing to our Board of Governors for approval in two days, we did focus primarily on the transmission required for a lot of the Southern California requirements, including some imports from out-of-state as well as the resource development areas in Southern California.

We also studied sensitivity cases for what it would look like to address the North Coast requirements. And the Public Utilities Commission has already provided us renewable generation portfolios to be the basis of next year's transmission plan that will drive us. A year from now, we will be asking our Board of Governors to approve the first wave of major transmission reaching to the North Coast to address offshore wind requirements.

So we've studied different alternatives, we have the year, we have the information we need, and next year by this time, we will be moving forward with recommendations on a first wave of transmission to address those North Coast offshore wind requirements. Now, when we look at that, we do have to consider the different alternatives and permitting.

None of these alternatives will be easy. We do recognize that permitting challenges will be severe, and we will be looking for whatever help we can get in helping manage those permitting requirements to get that transmission permitted and approved and online as quickly as possible.

Thank you. I have just two other things, and then I'll be done, I promise you. Thank you. Mr. Gunda, you said in your handout here you have 2023 IEPR theme accelerating Clean Energy Connection. Is that a report? Is that just your theme for the year? I mean, help me understand what that is.

Yeah. So the Integrated Energy Policy Report is a report that the Energy Commission by statute is required to produce every year. So as a part of the IEPR, a number of the bills that we have right now provide specific requests to be included in the IEPR, which includes forecasting some of the hydrogen issues or natural gas, but also every year, collectively getting stakeholder input as well as input and consultation from PUC, CARB, and CAISO. We develop key theme to investigate, and this year we all agreed that interconnection issues is the most important thing to dive into.

Great. And then my final question, and it's probably not answerable but that's okay, I'm going to ask it anyway. Based on everything I'm hearing here, these are really long-term challenges for us. So fast forwarding four years from now, if we haven't gotten made enough progress, are we going to make enough progress for us to be able to retire Diablo? Or are we potentially going to be kind of moving along and still struggling to get our green energy transmitted and interconnected as we thought we were going to or we hope we were going to?

So maybe you don't have the answer for that, but I'm hearing a long time. I'm hearing a lot of processes longer term, and that's not consistent with what I thought we were doing with the extension of Diablo. So hard question. Maybe you don't have an answer. And that's just my instinct. So my instincts can be wrong sometimes, but not wrong all the time.

I'm happy to just take a stab at at least making a comment on that and say that it's a challenge, but we are planning the system to be reliable, cost-effective without Diablo. So in our planning processes, we're taking into account what can we do without that resource so that then we can be in a position to let it go.

But of course, and I don't mean this as an excuse--I mean it as placing importance on this issue and looking forward to the partnership with the Legislature and sorting through the issues as they come up--is that we are working on transitioning our entire electrical system at the same time that the impacts of climate change are hitting us. And so, I really appreciate the attention that you're placing on these issues, and you should know that we're also taking them very seriously. Thank you.

I'll just end with this. I think we do want to be partners, and so, when I think of partnerships, I think of people bringing us ideas or challenges that we could collectively solve together and that it's a two-way street. We put things out there because we're trying to solve problems, but we would welcome your agencies bringing us potential solutions that we as a Legislature can debate and move forward through the process and fund, hopefully, through the budget to expedite some of these things. So thank you very much. Thank you very much, Mr. Chair and to Members of the Committee that I don't sit on.

No. Just wanted to highlight that in the 846 bill that the Legislature requested us to look at alternatives to Diablo and that report is going to come in September. Just wanted to highlight that. That's on our boards. Thank you.

Thank you, Dr. Wood. And you're always welcome to sit in with us on these important matters. Assembly Member Eloise Reyes?

Yes. Thank you, Dr. Wood. I think it is important, and I appreciated that the questions were very methodical, they were very detailed, and they showed the problem that we have, and that's how long this is all going to take. We do want the reliability, but there is something to be said about getting there sooner rather than later because there were representations when we kept Diablo Canyon open.

And based on those representations, many of us voted because it was going to be a short fix just to tide us over, but I'm hearing the same thing as the questions are asked and very detailed. And I appreciate that about how long this is really going to take and the problems that some of us may not have to deal with, but the next cohort of legislators will have to deal with it, and we're starting all over again without the institutional knowledge.

But I did have a question for President Reynolds. I'm hoping that you can speak a bit about the CPUC's resource adequacy methodology. I'm concerned that it may tip the scale in favor of fossil fuel resources over clean energy, and I'm hoping that's not accurate, but it kind of seems like it is. And if it is accurate, what potential improvements can be put into place to ensure our resources for our reliability mix are clean?

Sure, I'm happy to answer. So our intent at the PUC is to use the resource adequacy process to facilitate clean energy. So really it's not meant to encourage fossil fuels. Just what we're trying to do is get away from fossil fuels. And we have the most stringent greenhouse gas reduction goals in our integrated resource plan process, which is where the resource adequacy program tease off of that we've ever had.

So we're moving to reduce greenhouse gas emissions throughout the system. The resource adequacy requirements are being revised. We have proposals to update the requirements. We're looking at a slice of day model where the load serving entities need to think about load and think about adequate resources for every hour of the day, given the fluctuation of demand and intermittency of generation resources.

We're taking climate change into account in our metrics as well by changing the values of resource adequacy products so that they reflect the actual value to the system during that hour. So we're making updates to more accurately reflect the resource adequacy tools that the load serving entities bring into the mix to make sure that they're actually working.

You may be referring to a bridge resource decision that we recently made that allows load serving entities, if they need to have a reliability bridge, to take them to a clean energy product that they are allowed for a short period of time to contract for--I believe it's for exports that may be fossil fuel exports. So they can use--sorry--an import. Excuse me. So they can use an import into California while a clean energy project is coming online. And that's because we realize that reliability is absolutely critical for our clean energy future.

I'm just hoping that--absolutely--we need the reliability, but we have time to plan to make sure that as we're looking at this reliability mix, that we don't allow the dirty fossil fuel to come in, that that be limited as much as possible so that we really are going green. I recognize we're looking at lots of planning, but if we aren't intentional about it, I'm concerned that it will not be as green as it should be. Thank you.

And if I may, Mr. Chair, for Mr. Gunda, I wanted to quote the background paper in reference to the recent procurement orders the legislatures mandated. And I quote, 'these procurement orders also suggest that the historic planning efforts of the energy agencies may be inadequate to meet our current needs and must also urgently evolve to ensure reliability, at least costs, while transitioning the electricity sector to meet our clean energy goals.' How are both commissions adapting to meet these evolving needs?

As a follow-up, I know we've done historic and major procurement recently, but if our planning process through the Integrated Resource Plans and the Integrated Energy Policy Reports are not planning for our current needs, does there need to be additional changes to how we forecast energy demand?

Absolutely, Assembly Member. So just kind of want to answer that question by elevating just to a higher level. So as you noted, the Energy Commission develops the forecast which then flows into the IRP, the Integrated Resource Planning for them to consider what resources to be procured. Historically, we had a few challenges which we are rapidly fixing. So first is, are we actually having enough climate change impacts baked into the energy forecast?

So over the last two to three years, since 2020, we have done a lot of work to incorporate climate change and we are going to continue to do so with more and more geographic disaggregation and temporal disaggregation. So I think that we are doing a good job on. Two: we had an issue where the forecast that's provided to the CPUC might be stale by the time they start a proceeding and end a proceeding in two years. So as a preemptive solution, the CPUC requested that CEC begins to bake in more of a scenario-based forecast, especially on electrification goals.

So as of last year, we transitioned the higher electrification, which we used to call it a sensitivity into more of a planning scenario. So both on the electrification side as well as the climate change side, we've made significant progress in the last couple of years to just give you the magnitude. If we look at the IEPR forecast for 2023, three, four years ago and the four advantages ago, it was a couple of thousand megawatts below and now we feel like we caught up with some of that. And given that we are cushioning more and more, both on the climate side and the electrification side, we believe at least we are standing with a better planning situation.

So then that goes into the IRP process, for them to kind of evaluate two elements. One is you have the forecast, but how is the distribution of forecast going to look like given this extreme weather events? And so that's where we are making the next progress is, let's take the overall forecast, but we now understand that the tail events are becoming longer and longer. So how far down that tail event do we want to be able to cover through standard planning processes?

And that's something that CPUC is working really hard on, both baking that into the analysis but also evaluating resources like solar, wind, more appropriately in the IRP process. So with that, we feel like we're in a good footing, but as you noted, we have to continue to make those developments. Thank you.

Thank you. Thank you, Mr. Chair.

Thank you. Questions? Please.

He has the answers, so I was going to let him go first. Thank you, Mr. Chair for convening us as always, and thank you all for being here to share your expertise with us. I think, you know, just continuing on what the Majority Leader was talking about, reliability is so critically important, as you all, I'm sure, aware. My district was one of the hardest hits by the PSPS a few years ago and we saw what it was like to live without electrification for more than a week in some areas, and people died, right?

I mean, seniors had falls that were unanticipated because of the lack of electricity, not to mention the folks who need electrical devices to survive. So reliability is critically important and I think that that being our foremost thing that we're paying attention to makes sense, but I think that what the Majority Leader was touching on about our green energy future is really, really important and we need to make sure that we're not moving towards decarbonization and electrification and then just electrifying those devices with dirty energy because that doesn't get us to where our climate goals want us to get to.

You know, I represent the Tri-Valley where we do a fair amount of wind and solar, large scale solar, and I see how hard it is to get those projects built, to get them online. Everyone thinks the whole valley is going to turn into clean energy. It's not possible because you can't connect into the grid in all parts of the valley. You have to do it in very specific places. And so we have these laudable goals and we need to make sure we're moving towards them while also balancing that with our environmental goals.

And so, I really wanted to touch on a little bit of what the briefing papers talked about regarding--and I know we had a whole hearing or a hearing where we discussed the proposal for DWR to be doing central procurement, which I know is something that is really a focus of our reliability, but I was struck by how much of that energy, if not all--because we don't really clarify what we're importing--but my understanding is a lot of our imported energy is not clean energy--if we even know what we're importing.

And then the rest was all diesel and natural gas generators, peaker plants, et cetera. So that was striking to me. I mean, it was laid out here that the DWR central procurement process to date, which again is only a short period of time, wasn't moving us anywhere near our clean energy goals. And we're being asked to make that a more permanent solution.

And I think that we had a really robust conversation in Committee about that and talking about how there is a role for that but maybe it is long-term resources that need that kind of procurement but get us to our clean energy goals, the offshore wind that we heard my colleague talking about and et cetera, rather than importing dirty energy. So I just wanted to touch on that. And then we talk a lot about demand side, right? Demand reduction. We talk about these distributed backup assets.

You know, I had a bill a few years ago focused on those behind the grid resources because we knew in 2020 when the lights were going out, that we actually had enough energy on the grid in those distributed resources to keep the lights on, but were not accessing them.

And so I really wanted to touch on that piece of it because I do think the distributed resources and those assets and ensuring that we are offloading those assets in times of need is really critical and I know it's been something that's been slow in the making at the PUC, but it's really important. So I don't know if President Reynolds, you want to touch on that distributed energy backup resource project that is I think, ongoing at the PUC.

Sure. And I'll also turn to my colleague, Vice Chair Gunda, because I think the backup resources that you're talking about is something that he can address. And we have been working on distributed energy resources in proceedings at the PUC in order to incentivize and value them. There's a lot of interest by certain providers in getting resource adequacy value and so we're trying to figure out ways to do that.

We have some pilots for virtual power plants that we're pursuing and trying to make sure that they work the way that they're supposed to work with the grid so that they provide the value that we're looking for. So that work is ongoing and we're also doing collaborative work with the CEC and looking for ways to really maximize all of those Demand Response options.

And then, I'll just note, and you're absolutely right that we need to avoid dirty resources that come in from out-of-state as well as relying on the fossil fuel resources for reliability; we need to move forward with clean energy. But a lot of the imports that we get are hydro from the Northwest. And so just keep that in mind as you think about imports, that some of it is hydro.

Thank you, President. Thank you, Assembly Member. Just on a couple of points that you raised, we'll start off with the demand flexibility and improving the demand-side resources. The 846 bill that passed last year requires the CEC to develop a goal, a load flexibility goal regularly and then we're going to start doing so by June 1st this year.

So we are doing that in collaboration with CPUC, very close coordination. So the first, I think, thing to figure out there, as President Reynolds just mentioned, is much of these demand-side resources, we don't have clarity on the performance. So what problem happens is, if we rely on them to show up at a specific level, sometimes they go past it, and sometimes they underperform, given the day and the temperature conditions.

So what we're beginning to think through is if we were to say, double the demand-side resources that we have today through improving our rate design, time-of-use rate design, or through incentives for emergencies or RA products, so the hope would be to move a little bit more towards a performance-based incentive mechanism and also figure out a pathway for emergency products, especially on the demand side, that might not sustain a long period of time.

So let me explain that a little bit more. When you look at resource adequacy demand-side products today, they have to typically perform about five hours continuously, and what happens is they perform well for a couple of hours and then they drop. So what we're trying to collectively figure out is a paradigm where we actually take whatever they give us two hours, three hours, and really match them with the emergency.

So just wanted to flag that we are working hard on that to operationalize that, and you should get a report middle of June from us on that issue. Second, you're absolutely right. It's a really sobering reality last year when we had to rely on a lot of diesel backup generators to keep the lights on. And what we are trying to do through the Distributed Energy Assets Program is to really clean the backup generation and also provide controls to operationalize more of virtual power plants. So those are the things we are trying to do.

And I think, I mean, the virtual power plant, I think, is really exciting because those resources are on our grid today and the technology is such that we can make it more predictable, right? We can hold back certain energy and those resources, especially a certain time of year. And when you look at I mean, we talk a lot about rate and the cost of electricity in this Committee because it's really something Californians, it's hurting Californians, everyday Californians, how much they're having to pay.

And for those peak times when the whole west is getting really, really hot and we're competing for energy and those costs are so, so high, drives up rates all year, right, to make up for those peak costs. And if we can drive those down by using distributed assets that are already on our grid, I think it's something we should absolutely do and be doing more of because they're there and more and more people are investing in those backup batteries.

And I think allowing that to be exported to the grid and incentivized is a critical resource. The other thing I wanted to ask about was for the demand-side, right, so demand reduction, right? Some of that is the text message that saved us all, right? So the individuals who turned their lights off or unplugged their cars or whatever the case may be, but a lot of that is the larger stakeholders that you are calling on to reduce capacity at the time of an emergency, whether it's large consumers, et cetera.

And I wanted to understand a little bit more about how that communication is working and what the plan is in those moments of emergency to communicate effectively with folks we need to drive down energy consumption from and make sure that that's seamless and not something that we're just doing in a disorganized fashion.

Sure, I'll start. This is something that we have been working on a lot in terms of--we have developed emergency programs so that anybody can sign up to be compensated for reducing load in an emergency. And we're trying to do as much forward planning on that as possible. At the CPUC, we have a program called the Emergency Load Reduction Program.

We automatically enrolled all of our care customers so that if they drop load during an emergency, even if they don't know they're doing it, they'll be paid, and it is to incentivize everybody. So sign up. If you drop load during a Flex Alert, you get paid--compensated for it. We also have industrial customers, commercial customers who can sign up through the utilities.

The CEC has a companion program for the public utilities and we're working collaboratively with the CEC to make sure that as many people get signed up as possible. So all of that load reduction potential is prewired to be compensated so we have the incentives in place.

And that's the case, so if you have a home battery, the idea would be you make sure that even when, if your solar panel is no longer producing, you've got your battery pulling the load from your house and you're getting compensated because you dropped your load. So we're looking at performance there and evaluating the results of the performance and then looking for ways to improve that going forward. We've also through budget authorization, ramped up our Flex Alert messaging and we're doing some paid media.

We have kind of getting the word--hopefully your neighbors now know about Flex Alert, but really trying to make sure that everyone understands that certain times of the year, this is when we all come together and reduce your energy uses a little bit, but always looking for ways to improve.

I understand all that. I guess what I'm wondering is, and I'm trying to recollect exactly the circumstances, but a few years ago, when we had one of the rolling blackouts and we had one of these hearings, it came to light for us that one of the IOUs--and I don't remember exactly, so I'm not going to name names--had dialed up instead of dialed down, right? That there was a miscommunication in the energy sector that led to the rolling blackouts, right? It was a big mistake, right?

And so I guess what I'm trying to come back to is, okay, how are we communicating in those moments to our--whether it's our giant energy users, whether its the IOUs that are dialing up, dialing down, the LSEs, whoever, to know exactly what we should be doing at that moment so it's seamless?

There is a lot of real-time communication and the CAISO organizes a lot of it, so I could turn to Neil.

Yes, thank you for that. Yeah. As I mentioned in my earlier slide deck, one of the things we're really needing to also put additional focus on is getting the sequence of events of how we're responding when the system is tight, down as crisp as possible. We call them playbooks on exactly the sequence of events, who's communicating with who, and making sure that those communication channels are established and tested before we're actually in these stress conditions.

It wasn't that many years ago where a fair bit of this was still just being done a little too ad hoc based on previous working relationships, but there's been a lot of work over the last two or three years to make sure that those communication paths are documented and tested, that people know who should be calling them and what they should be saying, so that we're crystal clear on the messaging.

So that has been a very important issue for us to make sure that we don't have those kinds of communication snafus and that the messaging is clear, precise, and gets the desired outcome.

Thank you. Yeah. Mr. Gunda.

Yeah, just to add to Neil's points there, I think a couple of other elements, I think, if I heard you right, how are we also doing it on the load reduction side? So on the load reduction side, we now have essentially a group, an administrative group through CAISO where all the IOUs and key providers come together to again have a playbook.

And the other element that you mentioned, we had a bunch of ad hoc resources in 2020 where we reached out to and were able to get a bunch of demand reduction. Since then, to President Reynolds point, we are really trying to operationalize them and move them into existing programs. So what the existing programs will give us is visibility of the type of resource and then we can have a dispatch order to be able to dispatch the cleanest first.

So I think overall, since 2020, we have been able to better collate the resources that exist and move them into more operationalized, organized, standardized process.

We like organized and operationalized. So thank you all.

Thank you very much. I apologize, Mr. Chair and the presenters, for missing much of the meeting. And so I ask for your forgiveness if I might touch upon something that was discussed. First of all, I appreciate that the focus of the hearing is on grid reliability and to be prepared for this upcoming summer.

But as I was watching on my TV screen, as I was taking another meeting, I recognized Mr. Wood talking about an issue, a concern that we've been sharing that I think is very much related to the grid reliability, which is the transmission grid and the interconnection issues. And it's an issue that I'm very much concerned about because I've been hearing both from our utilities as well as from our CCAs that we're doing pretty good in terms of building clean energy generation capacity.

Our biggest challenge to meet our climate goals is our grid. I've dropped a couple of bills this year to try to promote that. I I think it all got swallowed up in this discussion on the regional grid, and so, you know, I appreciate that that, you know, is very much a big picture, you know, priority that we need to continue to flush out.

But as I've been chewing on these issues, I saw this recent New York Times editorial just from about two weeks ago, May 4th, titled, 'We Desperately Need a New Power Grid. Here's How to Make It Happen.' I don't know if any of you saw this editorial in The New York Times, but it's focusing on the national need. But the issues seem to be very similar to what we've been talking about here in California.

I won't read the whole op-ed, but it talks about how the United States needs to double the pace of power line construction. I've heard that California, in order to meet our SB 100 goals, we need to triple our grid expansion. The editorial goes on to say that building is the easy part. What makes the target virtually impossible to hit is the byzantine approval process that typically includes separate reviews by every municipality and state through which a power line will pass.

Of course, this is written from a national perspective, but what I'm hearing is the byzantine approval process of the state as well as our cities, combined with the ability for any California citizen to file or threaten to file a CEQA lawsuit. And so I wanted to not only emphasize the urgency of the grid--I see one of the slides that Commissioner Gunda presented.

It appears that your 2023 IEPR theme is accelerating clean energy interconnection, and so I'm sorry I missed that discussion. But I guess, number one, are we on track in terms of our grid expansion as well as our interconnection needs to meet our SB 100 goals at this time?

I think we all have something to say, so maybe all of us will take a shot at it. And we are in the process now of doing an update to the SB 100 report. We have been bringing projects online according to planning to get to that goal, but we have a lot of work to do.

The transmission planning process has ramped up in the past few cycles, so the CPUC is sending larger amounts of new generation to the CAISO to study for transmission projects than ever before. So that's both in a base case and a sensitivity case, looking forward to the future with offshore wind in mine, with other projects that we need to get to our clean energy goals.

We've typically done 10 year planning, and Neil can tell you about the 20 year cycle that we're doing now with exactly this in mind that we need to think ahead for these long lead time resources projects. Recognizing that it does take time to get transmission approved, whether that's an upgrade to an existing line or a new line. So let me stop there and go to Neil.

Thank you for that. And yes, what we did a year and a half ago was launch this Outlook process of building off of input from the state agencies, developed a long term blueprint for what we saw the transmission system would need to look like 20 years from now to provide context for the transmission projects that we're looking for approvals for. And pushing through the pipeline today to show, to demonstrate that those transmission projects aren't a one and done, that they're part of a longer term strategy.

And that does establish a trajectory to actually meeting goals by 2040 and 2045. So that first version of the 20 year outlook came out in May of 2022, and we are looking at developing this year a second version of that outlook to update the inputs and also reflect some of the projects that we've moved to approve since then. And we will be putting that out in 2024, about May of 2024.

Now, when it comes to the transmission projects themselves, this transmission plan itself is the largest that we'll be bringing to our board in two days for approval, is the largest transmission plan we've ever advanced. We're looking at 7.3 billion in transmission, that covering. And it's not only addressing the base case scenarios you heard about, but also have us well positioned to get on track for the longer term projection that is the established trajectory to get to our 2045 goals.

So there will be additional transmission coming in next year as well. And it will also be shifting a focus to pick up the first layer of needs for offshore wind development. So that transmission, the planning is happening, projects are being initiated, the permitting process itself is daunting. We do recognize that the state agencies are obliged to follow the letter of the law regarding the permitting processes they're managing.

And that does at times take us into time frames that we wish we quite frankly didn't have to deal with. We're also looking at the possibility of having to approve projects not only within the 10 years, but also looking out beyond the 10 year window because of the complexities of the permitting processes.

So if there are steps that can be taken to streamline those processes and shorten those timelines, that's obviously something we're very interested in seeing happen because we do need to move on new transmission to meet those targets. And like I said, we are moving on the new transmission projects, but getting them permitted and approved and actually built. There's a lot of work ahead on those projects.

So along those lines, going back to this editorial here, it says that the most important change necessary to overhaul the permitting process is to put a single agency in charge of major transmission projects. Is this a plan that you're preparing to release? Does it contemplate anything like a central state agency in charge of major transmission projects?

Well, we hold the role through the state legislation to conduct and federal tariff to conduct the actual transmission planning in terms of getting it permitted. There are multiple responsibilities within the state that have to be addressed and we are not in a role to take on the environmental permitting challenge ourselves.

So does the State of California- Should the State of California have a single state agency in charge of transmission permitting? I imagine it would be a very complicated topic. But what I'm hearing is that that's not part of the current plan that is being-

I'm not aware of any discussion on that path right now. I think the different layers of concerns that are addressed, California does have to its benefit has among the strictest environmental requirements that impact a number of different domains of what it takes to get a transmission line permitted. How that would come together, I'm afraid I'm not in a position to comment on.

I'll add that the PUC does do approval of transmission projects. So we have a process that does CEQA review and evaluates alternatives, evaluates costs, because of course cost is very important here and that's part of the reason we do all this advanced planning to put together the least cost portfolio to meet our targets. And so that process lies at the PUC. We have approved projects in the past.

We follow the lead time that we take into account with our planning to get the projects online according to the target goals. So, in California, that's how we carry out the process, which obviously has an important cost impact on it.

And if I can just quickly follow up on that, President Reynolds, I think currently the PUC takes like what, 9-10 years to approve transmission grid expansions.

If that's the average that you've seen, I won't question that. I think it has been less, but it's probably been more too, in the past. I will also say that pursuant to legislation, we have a new rulemaking that we're just opening to evaluate the rules regarding the level of review for transmission processes. And so we'll be evaluating whether a full permitting process is appropriate for certain types of upgrades. So the Legislature has directed and we're carrying out a streamlining process.

We're also using that to evaluate storage projects and other projects that the IOUs are proposing in order to make sure that we're streamlining as much as possible.

Thank you, Assembly Member. The only thing I would add to what my colleagues already mentioned is a huge part of the permitting delays obviously comes to the land use implications. We have collectively started the process of updating the land use screens in a much more comprehensive and collaborative fashion to make sure that we consider those earlier in the process to reduce the downstream impacts on time. So just wanted to elevate that. That's another element that we are working on.

Mr. Millar talked about any efforts to speed up the timelines. I believe this Committee passed a Bill, a similar approach to what we've taken with stadiums I think, of having a 270 day time limit for courts to handle CEQA litigation in courts. Would that be one example of something that would have a significant impact in terms of speeding up the process of transmission, project permitting?

I think litigation is always a factor for project approvals, so yes.

I also said on the Natural Resources Committee, I know we're talking about categorical CEQA exemptions for housing given the recognition that housing is a crisis. Given that we have a climate crisis, I mean, is there any consideration about CEQA exemptions for transmission grid expansions?

At CEC, we, in collaboration with PUC and CAISO, have work that's around transmission corridor planning and such. One of the things that has been raised with the Energy Commission is to reconsider potentially programmatic EIRS that allow for more programmatic approval of transmission. But that's in a very early stage of discussion that we'll be bringing into a public sphere for conversation.

What does that mean, a programmatic EIR?

So rather than project by project, it'd be more of a regional.

Okay, I just wanted to add, Mr. Chair, this particular editorial concludes by saying the balkanization of the electric grid keeps costs unnecessarily high and makes it harder for utilities to beat surges in demand. So I thought you might appreciate that comment.

Thank you very much.

Thank you.

Good line of questions. We'll move on to another colleague, Schiavo.

Hi, thank you so much for your presentation. I want to just chime in on my colleagues'concerns around interconnection. It's something that I've been hearing a lot in the meetings I've been taking in my office from anywhere from solar battery energy that's trying to get connected up to the grid to housing developments that haven't been able to get connected. And so it's not only impacting our ability to have the energy that we need, but it's also impacting our housing needs.

It has so many ripple effects that we're seeing. And so I wonder if you have insights also into what else is a part of this. I hear what you're saying around the planning and glad that there are some ideas marinating about how we can impact that and maybe improve upon that. I've been trying to have conversations about what is the problem, what is actually the problem that is going on right now? Is it a workforce issue?

I've heard that more of like the engineer level, that there's a lot of retiring engineers and need to be able to fill those gaps and those holes around being able to go out to sites and really line up how that work is going to happen. But I'm trying to figure out what else is going on that we need to address.

Do we need to have monthly meetings where the different energy providers come on in and tell us how many they've been requested to connect up and where they are in the process to move things along? What needs to happen to help generate the kind of urgency and importance on this issue that doesn't seem to be there in some ways right now that we all know, I think here that is really urgent for us to be able to make our goals.

Sure, it's Neil here with you, so I'll take the first shot at that. So first off, I want to be very clear, the urgency is what we're dealing with day in, day out. This is one of the most important issues that we're dealing with is managing how to get the largest number of projects through from concept into actually getting built as quickly as possible.

As I mentioned earlier though, one of the challenges we have is a tremendous amount of competition for the amount of actual development that's actually going to move forward. So we see that we really have to do. On one hand, we have to keep moving through the projects that have applied. We have to keep working on focusing on getting them through the process and built. We also have to address this overheated competition for the projects that want contracts don't have them yet.

They want power purchase agreements, they want to sell their output and then they want to get connected and they're applying for interconnection so that they can bring that interconnection proposal to the companies that are actually buying power and saying, see, 'I've made it to this part of the process. I'm real I'm ready to move forward'. But we have to come up with a better way of managing just letting anyone apply anywhere they want to apply and managing that huge volume of, like I said, overheated competition.

Even if we had the engineering resources, it wouldn't be a good use of state resources to be developing interconnection proposals for everyone who's asking in case they might get a power purchase agreement. There's just too much competition out there for them to get meaningful results in the first place and it would just overwhelm the system. So we really need to tighten up how we're doing those studies, who's getting through and actually does get an interconnection proposal developed and moves forward into the procurement and into construction.

So clearing out what's becoming a bit of a roadblock at the beginning is really important. That's something we're wanting to explore this year. Working with the state agencies and with our stakeholders because they're also seeing that same problem. They know that it's not meaningful to get interconnection results. Studying adding literally seven times the system's peak load in one interconnection cycle, how would you connect up 350,000 resources?

So that's what we're looking at is what we can do to streamline up front so that we can focus our planning and engineering resources on a more reasonable number of projects that will actually get through and get built, so that that's where people can put their time and energy. Now saying that's easy, getting it done is going to be more difficult. The process design work, there is something we'll also have to get our federal regulator on board with.

But we have a lot of confidence that there's the need for change is clear as we've moved from processes that did work, if you were adding 1000 megawatts a year but simply cannot pick up the pace to accommodate adding 7000-8000 megawatts installed capacity year over year. So that's one of our big focuses is what we can do to tighten that up and direct those resources where they're really needed. Now getting past that, the amount of actual design and construction work is also a real challenge.

So once we get past that, we know that just managing the volume of development that's required will still be significant. It will still strain the entire chain, including the permitting process to manage getting that through. So we need to be looking not only at the one issue, but the entire chain of events. What does it take to actually get these projects online? But as I said earlier, we have been successful at getting a large number of projects through.

We are expecting this year that we'll be reaching, we should be breaking the 8000 mark for installed capacity in a single year, which is a very good start. But now we have to be on track to sustain that year over year. I don't know if there are other comments.

I think part of what you're hearing from Neil is that it's important to focus on the right projects. The projects that are the right stage in the process and so that's one thing we've been trying to do from all sides.

So from CAISO, from the PUC is focused on encouraging the utilities to look at, know what projects are ready, when they're going to be coming up and focus on those projects and at the same time try to get to a manageable place for the future as we go forward.

Thank you, Assembly Member. So, just to reiterate some of the points we made earlier. So the IPER, the Integrated Energy Policy Report this year is focusing on the interconnection issue and we're all collectively working on that report and we will be able to provide some of the basic questions that you're asking, which is how does the flowchart look like, what are the main issues here and how do we solve them? So that's going to be coming out later this year.

And also just wanted to reiterate, so I think you mentioned the resources. Resources has definitely been something that was raised in the workshops, but there are other issues as well, especially in terms of visibility within the utility on how they are doing different parts of the interconnection process. So we are working on improving transparency, which should potentially yield a lot of efficiency on the distribution side.

Thank you, I appreciate that and I am excited about this report. So back to your point around the kind of streamlining the pipeline. I feel like on that, part of the problem is that because of the delays, everybody's like as soon as they got something that looks like it could happen, they want to sign up because it's a four year delay before they can get connected to the grid or whatever it is, right?

That kind of the delay situation is actually creating this scramble and overloading the pipeline in a way because people are concerned that they're not going to be able to get connected up when they need to be. So they want to get in line as quickly as possible. So who is that?

I'm sorry, I'm the new kid on the block and I'm learning a lot right now about all of this process. But are you in charge of the pipeline? Who's in charge of the pipeline? Who can do the streamlining? How does that happen?

We're responsible at the ISO for running the generation interconnection process, for catching all the new requests for connections to the transmission grid and working with the transmission owners to develop the required interconnection proposals for them, also identifying the network upgrades that would be needed to allow them to come on and to actually serve load. So getting them connected is one thing, getting the other network upgrades necessary to get their power to load is another. And that's the process that we lead.

But then the transmission projects that are identified still need to be permitted and built. And we do have a lot of transmission in various stages of development that's been approved over the past number of years. And there have been times where some of that transmission has been delayed for a number of reasons, whether it was supply related issues from utilities or staffing or there were times where other priorities, some of the wildfire mitigation requirements definitely pulled staffing from other priority areas.

That's the other thing I've heard.

So that's something that's been a concern. We've been working with the transmission owners to work to try to mitigate the transmission delays that are impacting the largest number of projects at any time. One of the other steps we took in conjunction with the Public Utilities Commission was to provide the transparency around what's happening with these transmission projects.

And we now have a process called the Transmission Development Forum that's run quarterly, where all of the major transmission utilities come in and once a quarter go through the projects that affect generation. We don't go through the interconnections themselves, but all of the network upgrades that are required by generators. The transmission owners go through the status of those projects and report on if they have experienced any delays and what's caused the delays. So that's providing the clear transparency to everyone about which projects have been impacted.

And then what can we do to try to mitigate the impact of that delay if a project has been delayed. And we think that transparency has been very helpful and allowed us to focus on, I'll say, the real problems, as opposed to sometimes we hear stories about projects being impacted, but this provides the clear transparency, which projects have been delayed? By how much? What's the impact? And what can we do to get those projects back on track?

And I appreciate, when I was talking earlier about the urgency, I appreciate you all understand the urgency. When you're hearing about four year delays to get connected up, then it feels like someone's not understanding the urgency. But, in this process, that you are in a leadership role on, at what point when do I go- If I have solar and battery energy, I want to get connected up to the grid, I go to you?

And at what point do I talk to PG&E or how does that all work?

Well, if someone's looking to apply to connect to the transmission system, utilities are responsible for leading any distribution connections. But if one is looking to connect to the high voltage transmission system, they apply through our interconnection process. We normally run an open season once a year for new applications, and we study them all and move them all sequentially through a two year study process. At the end of the first year, you get your preliminary results that establish cost responsibility.

You put up some additional money, some additional posting funds, and then move forward into detailed proposals that would then get a contract in place if you were able to get a power purchase agreement and can actually move forward. And that's the challenge, is that we have a lot of projects applying that aren't getting contracts and that are then waiting for the opportunity to get a contract with a load serving entity for their output and aren't really ready to move forward.

We also have a case where there's just so much competition that that can become almost a denial of service attack when you have that many projects applying at the same time. So that's a real issue we're having to manage. And that's why we're trying to do what we can to tighten the linkage between our interconnection process and the actual procurement so that we can focus more of the engineering talent on the projects that are actually getting contracts and moving forward.

Yeah, I mean, I come out of working a lot in healthcare issues and it sounds a little bit like there needs to be a triage process with some of these folks with like, are you really ready? And then you can prioritize the ones who actually are ready to go and they can move more quickly. I'm glad you're looking at that. Thank you for answering my question.

A very good analogy. Thank you. Great questions.

Any other questions to my right? Doctor, please.

Thanks. I thought it was going to be the last question earlier, but I just want to can't help myself. After listening to some of the discussions here, how often do you all get together and brainstorm on how we solve some of these problems? Let's take Lithium Valley, for example. He's going to have some major projects down there that are going to be geothermal and production of lithium.

Maybe that's not a good example because they're not power projects, but maybe it is. And I've got potentially offshore wind. So are you all getting together and talking about what the challenges are going to be, how we're going to look at the transmission, how we're going to look at the procurement, how are we going to look at and who's going to be in charge of that whole massive entity moving forward?

Because I will say, as you start moving in these projects, as I've talked to the companies who have been in my office, they kind of want to know who's the go to person on these things. And they don't know. They absolutely don't know. Is there somebody who can make, in a position of authority to make decisions, that can be helpful to moving from moving some of these things forward and not just this issue, but other issues? And the reason I say it's like it's simplistic, right.

We had a one stop shop in our city for building projects. Police came together, fire, the electric utility. Yes, we had our own electric utility in the town. Water and sewer planning department all come together. Project proponents come in, they sit down, they work it out, and they leave with one bite out of the apple. And so as we talk about all the things that are happening here, it just feels like the challenge is that the proponents, the companies, go from one silo to another.

And I don't know how interconnected it is because it doesn't feel very interconnected to me.

Sure. So we do coordinate a lot. I mean, both at kind of our level. The four of us know each other very well, but also our staff. So we all have staff, interagency working groups with designated members who work closely together through the various work streams. And so Lithium Valley, for instance. There was a Lithium Valley Commission. I sat on the Commission, it was staffed by the CEC. We came up with a report.

We also worked with the Governor's office on transmission issues down in Lithium Valley because of the need for geothermal projects to support lithium extraction there's. Now, IBank is involved with a loan program, and so we worked together to put all the pieces together on that. For instance, for distribution system issues of the type that we've been talking about, we have ongoing coordination through the integrated through the IPER process. But we also have, as I mentioned, the real time strike force through the PUC.

So I would say if someone comes to you and says, I want to get interconnected, that would be CPUC. For generators, we also have the transmission forum that Neil talked about. So we have a number of interagency collaborative working groups. There's one for SB 100 as well.

How is that translating to increased efficiency, increasing ability to get these things going? Because I'm not there, I don't know. But like I said, we're still at this point where we feel like we're really struggling and kind of just crawling along here, struggling with some of the- I mean, we're a year removed almost from some of the comments we made a year ago sitting here. And so we're still looking at reports.

I mentioned the TED Task Force as well. That's another interagency group. We have increased our battery storage generation capacity by over 200% in the past three years. And part of that is the generators coming in, the load serving entities contracting, but also the state agencies being there to facilitate. We did this through COVID. We did this at a time when our ports were overloaded. So we are seeing results and projects come online.

It's not to say we don't have challenges and we work at it every day, but so absolutely understand. We're always trying to do better.

To kind of elevate your question. So, for example, on the reliability, for example, we meet weekly on Monday. So we have a standing meeting every week where we all collectively go through the updates for the summer, longtime issues, and for example, on the demand side issues, the staff meet bi-weekly and then we elevate to the principals level to like a monthly meeting. So we have various venues that are chartered out within the energy agencies.

But I think to your point, if you're looking for an elevated transparency of the ecosystem of work that's being done and how and who is on point, we can absolutely share the different forums that kind of handle these things and the points of contact in each one of them. I think absolutely happy to provide that. Two points of consideration is, as President Reynolds just mentioned, when we got hit in 2020, in the middle of COVID, the COVID impacts were real, right?

The COVID impacts were real for the agency staff, it was real for construction, supply chain. And I think we are coming out of that and you will see more and more how we are able to improve the efficiencies, and communication is absolutely vital. The second element, just for your consideration is, as you know, we have the Bagley-Keene process and no two commissioners who are working on a specific issue can sit in a room to discuss the broader impacts.

And a lot of work is cross cutting work that one Commissioner might be doing on transportation cuts with reliability. But we can't sit together in a room because of the Bagley-Keene limitations. So that does rely a lot on the staff to help create the forums of cross pollination. And I think they are in place and sorry that it's not as elevated to you to your level on how we are doing behind the scenes and we'll make sure we convey that to you publicly.

Yeah, because I asked that question with all honesty. I didn't know. I don't know. I've heard that there is some collaboration. So I'm happy to hear that. So final, I said this before, final question for now anyway. What do I tell my constituents? What do I tell my constituents that are struggling to connect projects, to wait for power? What do I tell them? Because it's a problem. So what would you do if you were in my shoes? What do I tell my constituents?

So I think first step is, again, send them to the PUC. And we do have a mechanism to triage those requests and are working project by project to see if there are alternatives, if there are temporary solutions, if there's something that the utility could be doing differently to find solutions to various projects. And, as well as assist with, have you looked at your load shape in the right way? Are the upgrades necessary? So working through the issues on a case by case process, basis.

I think it's also though, that there are processes in the works to get ahead of this, to move forward in the future so that we won't be in a triage situation. So that we'll have better planning process, better interconnect, better communication between local governments and utilities with respect to what's coming. And so those connections and processes are growing, and we hope to see them play out in the future. But in the meantime, we're looking at projects that come and are facing delays and are ready and look for solutions to those.

I appreciate that. Thank you.

Mr. Ting.

Thank you, Mr. Chair. I appreciate President Reynolds talking about battery storage, and I think it's been amazing progress. I was just going to ask Deputy Director Hou whether battery storage is part of that strategic reserve or has any plan in that strategic reserve.

Thank you for the question. We have released two separate RFIs because, as you noted before and in prior conversations, right now the portfolio is very much natural gas heavy. And so one of the efforts that we've taken is to release two different requests for information. The first one actually is focused on storage, but we want to also have a broader view of storage.

We are cognizant that, per the water code, we don't want to compete with load-serving entities who are out there trying to procure for their resource adequacy requirements. And as we understand it in conversations is that lithium-ion is still the preferred resource technology of choice. So in releasing our request for information, we are looking, which could include lithium-ion.

But we are defining storage fairly broadly to see what other resources are available out there that may hopefully not be in competition with what load-serving entities and publicly owned utilities are trying to procure for their own needs. So that's the first one for storage. The second one focuses largely on, I think, what we called non-fossil fuel usage. So we're looking at different technologies. We're hoping to get a robust response for us to evaluate and then move forward onto an actual request for a proposal.

So we are still at the information stage, and we're expecting responses to come back to us after a short Q and A period for that. So that's all to look at the future of the reserve, to hopefully transition beyond natural gas. And as we're cleaning the portfolio, we do want to reach those other targets of having either non-emitting resources, renewable resources, as well in the portfolio.

And maybe this is kind of a silly question, so forgive me if it kind of comes off sounding odd, but to me it's a little puzzling that you would issue an RFI. You have two experts sitting to your right and their agencies to give you fairly up to date information on what's out there, I guess. What do you hope to get from an RFI? And does that mean that you won't be purchasing storage going into this summer?

I think for this summer there isn't sufficient time to be able to do those purchases for summer 2023. But in terms of interagency coordination, we do collaborate very closely with our colleagues at both the PUC and the CEC. Some of the issues that we've found somewhat challenging is that we are looking for resources, potentially, that may only run during extreme event. So we want to balance some of those resources requirements, but also just a general desire to participate more in the market, for example.

So we've had various conversations, but the other thing we also want to do is to make sure that we are coordinated. So we've taken individual conversations. We've also coordinated with PUC CEC staff, but we were hoping that with the RFI it would be a much more organized and uniform process to get as much information as possible to as broad of an audience as possible.

So we had the same discussion a year ago on Budget Committee. So you're telling me that at the time that everybody was ramping up on storage we chose not to? Because last year when we were in Budget Committee, we had the same discussion that hey, everything you're buying is natural gas. The response was fairly inadequate, made it sound like you were responding from the State of Texas, not from the State of California. So what happened in this last year to go cleaner with your strategic reserve? Sounds like there wasn't anything that happened.

For the reserve, when the office was started in summer 2022, I think we were in very much emergency mode. We had to establish the office, we had to populate as much as possible for a reserve for a need that actually occurred as early as the September heat wave last summer. So I think in that time frame that we were given in order to execute for summer, having started in July 2022 and then having assets by September 22.

I understand what happened in 22. Yeah. But since we talked in 2022, which was a year ago till about now, what's been done?

Correct.

Because it sounds like storage is no longer a novelty. It seems like there's a lot of people are buying storage, a lot of entities were buying storage. Why weren't we?

So coming out of the emergency process, we focused first on resources that we could easily procure that didn't compete with the load-serving entities. As we were moving through probably the winter timeframe into spring, we are still checking in with load-serving entities to understand where the market is there, and we are still hearing some pressures around a desire to procure those resources. So again, we don't want to compete directly with them as they are struggling to procure for resource adequacy, as Director Baker had mentioned before in opening statements.

Okay, but when I hear that, then I'm hearing, okay, the only resources, and again, please correct me if I'm wrong, because I hope I am, the resources that the entities don't want are older technology and dirtier technology. So is that what we ended up purchasing? Because to me that's what people don't want, right? That's what's available.

I think from the emergency period when the fund first started, we were unfortunately...

I keep asking, this is starting in the fall. So we got through the fall, we got through the emergency, you got our feedback. So what's happened since the fall?

Correct. Since the fall, we've had additional contracting to close out some of the requirements that we had from over the summer, but also looking forward into the spring. We are focused on trying to get three additional assets online for this summer 2023.

And what are they?

Yes, so those are the three units that I spoke of in my opening comments. Those are the ultra low emissions natural gas fired resources, and again, those of a similar model are certified under the California Air Resources Board Distributed Generation Program. And so those do have fairly low emissions even though they are natural gas fired. So those are committed to come online for this summer, and moving forward simultaneously with a focus on the summer, we also had released the RFIs to understand what other technologies are out there as we're still seeing pressure on the storage side.

Is the hope that by next summer that we'll be able to purchase clean?

We are hopeful for.

Technology.

We are hopeful for that. So we are hoping to see a robust response on the RFIs, and we'll move as expeditiously as we can to add those resources to the reserve if appropriate.

Is there a reason why they couldn't be clean technology, clean energy? Is there any reason to think that they wouldn't be clean energy?

Not at this point. That's why we released the RFIs. We are hoping we do get a robust response for both the storage side as well as resources that are not using fossil fuels.

Got it. Thank you. Just going back, appreciate the highlight of demand response. And I know I had a chance to talk to Commissioner Gunda about this also. Just want to get a sense of how we can really potentially grow the adoption of demand response. I know the technology is still very much in its infancy and still growing, but it seems like this is technology that we could deploy, deploy quickly and still be able to do it cheaply. We don't have to worry about interconnection or we don't have to worry about transmission.

Yeah. Thank you, Assembly Member Ting. Just kind of high level overview. So we are hoping to submit the load flexibility goal for the state required by 846. We are supposed to complete it by June 1. So middle of June hopefully it'll come to the Legislature. So as you pointed out, there is a significant opportunity on the demand side that we could operationalize. So we are looking at it in broadly three buckets.

So one is really improving the demand response on the load modifying side, on the forecasting side through automation and rate design. So that's a collaboration between CPUC and CEC on really kind of looking at the CalFUSE model that CPUCs has come up with and other time of use rates, and merging that with MIDAS which is our online database to really help automate rate design and the data together.

So that's one element we are working on. And I think there it's mostly incentives for automation would be really helpful. And then we have the resource adequacy bucket, which is what we have today. One of the problems we have on the resource adequacy is some of the resources perform overperform some days and underperform some days given the weather and such.

So what we're hoping to do is bifurcate those RA resources that exist today that might not be able to fully perform into more of an emergency load reduction program. And to that end we are thinking through how do we operationalize that. The money that the Legislature provided us in terms of the DSGS and DEBA money. We are going to implement those monies for piloting some of these programs in collaboration with PUC. And our hope is to at least double those demand flexibility resources by the end of the decade.

Great. Is there anything we can do to, I know one of the challenges with demand response is you have individuals that are in charge of their own technologies. So is there a way to create something that's more systemic so that we could actually rely on 50,000 people doing this or 20,000 people doing this when we need that assistance?

Yeah, absolutely. And I think you absolutely kind of nailed the point on there is how do we ensure the performance. So to that end, I think there's a couple of elements that PUC, CEC and Cal ISO agree on which is around standardizing how we evaluate the demand response and then load flexibility and how do you operationalize to the end that we pay based on performance. So we are working on that. In June report you will definitely see some of the recommendations laid out.

Thank you.

Thank you, Mr. Ting. Look to my right. Any other questions? Yes sir.

Thank you. If I may, I just wanted to try to wrap up I won't say last question like Mr. Wood, because I know every good lawyer knows not to ever say that. President Reynolds, I just want to clarify, in terms of going back to the issue of transmission grid permitting, am I correct in understanding that the PUC is the lead agency for overseeing the permitting process for any transmission grid projects? In terms of expanding the transmission lines?

In California, yes.

Okay. And does that process include working with cities? In other words, if transmission lines are crossing the borders of multiple cities, then part of that permitting process is working with each and every one of those cities?

Yes.

Okay. And so, is it fair to say that there is a significant amount of time spent by the PUC to consult with and get the approval of every city in which that transmission project crosses borders?

Yes. I mean, I assume we go through the full CEQA process, and so there would be involvement of responsible agencies along with us as the lead agency. So I assume that takes place for the significant lines.

Okay. So, you know, while I appreciate what all of you have been talking about in terms of the Monday morning meetings to address reliability or the TED Task Force meetings or the IPER meetings. I mean, it seems like a lot of high level meetings to make sure that the silos, or not the silos, the agencies are talking to each other. In terms, going back to what Mr. Wood was talking about. That one stop permitting shop at the city level. The analogy of that, we don't have that at the state level to the extent that the PUC has to consult with each and every one of these cities, is that fair to say?

Well, I think, currently, there aren't multiple. We have one transmission project now that's coming up an active proceeding. And I shouldn't say, there are probably more in the works, but one that's coming close to decision. I think, you know, Neil can talk about the location of some of the projects that he's looking at, that Cal ISO is looking at. Now, some of them are out of state, so I think there are three that are out of state.

And so, while we know work with the local governments, there's not as much activity as there are in some of these other areas. And so we would work closely with local governments and certainly do a lot of work through staff, do a lot of work with counties and cities. And the utilities also work very closely with counties and cities.

And we're always trying to encourage that local connection, as well as, from the state level, making sure that we're reaching out even into communities. And maybe not just local governments, but communities who are impacted by anything that we're doing as well as tribal governments. So there is a lot of collaboration. I think you're right. We just mentioned the state participation here. But through all of our agencies, we also have connections with communities and local governments.

Commissioner Gunda, you talked about a program EIR?

Yes. Assembly Member, it has been discussed in the past as a potential for streamlining permitting where you look at a corridor that could broadly be considered under environmental review and then specific projects could be cited in that. In the last several years, as President Reynolds mentioned, much of our load was very stable.

Now that we're thinking about this huge generation within the statute that CEC has to do, which is the corridor assessment, the staff are hoping to put that out in the public sphere to consider if the parties and the stakeholders broadly encourage that view.

So would it be possible, would it be feasible if there was a transmission project that crossed multiple city municipal borders that you can have a programmatic EIR that would replace each and every one of those cities having to do its own CEQA review?

Yeah, I think much of the CEQA, I just want to elevate this, is done in consultation with the cities, so they're a key stakeholder in the process, and we take their input. So right now, I think it's in rare instances where the city actually have to provide a separate permit. It's more of a consultative role. But to your point, yes, it would create efficiencies.

All right, thank you.

Thank you very much. Like to thank all the panelists for your time today and responses to all the questions that were asked. I appreciate every single member who put forward questions today. Clearly, there is a tremendous amount of interest in this conversation. We probably could spend another hour where we also talk about who's going to pay for all this and how we ensure that it isn't the ratepayers and only the ratepayers when we are talking about the need for a stronger, reliable system.

Because in this Committee, we've consistently talked about reliability coupled with affordability. And one of the major conversations that I think also merits another hour or two of a conversation, perhaps not today, but certainly we're working with our committee team to shape what a potential hearing could look like around that issue as well. So I just wanted to say thank you again.

I'm happy to take any closing comments from each one of the panelists, including Mr. Baker, who's online, and so we'll start with the folks who are here and then wrap up with Mr. Baker.

Thank you, Chair Garcia and the Members. Really appreciate this opportunity to come in front of you and provide an update. We know that there is a lot of moving pieces here and appreciate the opportunity to continually update you through the quarterly reports. Just as it was hinted in the conversations today, I think much of our transition in the energy sector, while we know where point B is and where we are today, I think it comes to some trade offs in the interim.

And we appreciate you giving us the opportunity to lay out those trade offs, whether it might be affordability or reliability or equity. So thank you so much and look forward to continuing to provide you updates. Thanks.

Thank you, Mr. Chair and Members of the Committee. I really appreciate the opportunity to be here today. And thank you also for raising the issue of rate payer affordability. We know that rates are going up in California, and we realize how important it is to think about cost effective solutions to all of the problems we've been talking about and to make sure that our processes are geared to finding those cost effective solutions and making sure that we're controlling costs as much as possible. So thank you very much.

Thank you, Chair and Assembly Members, for having me here today. I know it's a difficult position that DWR is in, in fostering this transition to our clean energy future. And as Assembly Member Ting noted, the portfolio is rather natural gas heavy. But I think in there we do want to ensure that we are there for the state, for extreme events, for reliability, but to also improve that portfolio moving forward. So I really appreciate the questions and your time here today. Thank you.

Yes. And I just also wanted to pass along my thanks as well for the opportunity to participate today. I hope we were able to help provide some clarity on some of the issues we're dealing with. And just want, you know, just wanted to reinforce as well that for us, getting the maximum volume of resources connected as quickly as possible is basically job one and getting the transmission in place to support it. So thank you.

Mr. Baker.

Thank you, Mr. Chair. Thank you for having me here. And I look forward to further discussions on affordability. I think there's a lot of places we can go that both advance our decarbonization agenda and bring more affordability for ratepayers. I do want to close on one note, though. If it wasn't the case that we were essentially being mugged by the climate, this would have been a very celebratory session because what, we are a party in PUC proceedings.

We're not part of the coordination that happens between the agencies. But the amount of resources that our state was able to bring online, I think is truly heroic. And we should be looking to the lessons learned. How did we get those thousands of megawatts of battery power? How are we trying to quarantine, essentially, fossil resources and essentially keep them out of the market so that they run less?

And how can we apply that kind of thinking to the other problems that we have identified with, whether it's transmissions or hookups and of course, affordability. So, again, as an outsider, I think we really made some really important steps towards reliability. And as a ratepayer and a citizen, I congratulate the planning and regulatory agencies that were able to accomplish that. And hopefully we won't be in situations where we were in the last couple of years. Thank you again, Mr. Chair.

Thank you, Mr. Baker. Look to my right. Left. No more questions up here. We'll move on to now what is the public comment section of the agenda. Please state your name and the organization that you're with. We would appreciate that you keep your comments tight to the point, so please. The public comment section of the agenda is now open. Those wishing to address the Committee, please come forward. Seeing no one, we will then conclude with this hearing. Thank you again all for participating. This meeting is adjourned.