Assembly Standing Committee on Utilities and Energy

Okay. Good afternoon, everyone. We're going to get started with the regular meeting of the Utilities and Energy Committee. We do have two bills on consent, and so we shouldn't have to be here too long. As usual. There's the typical housekeeping rules. If. If you're out of order, we're going to have the sergeants take you to the dungeon. If Members on the Committee also are not behaving, we might do that as well.

We do have just two items on consent that will be taken on, and so we'll take first a roll call and then we'll take a motion to approve the consent calendar.

Garcia, Here. Patterson, Here. Bauer-Kahan, Here. Calderon, Here. Carrillo. Chen, Here. Connolly, Here. Holden. Mathis, Here. Muratsuchi. Reyes, Here. Santiago. Schiavo. Ting. Wallace.

Okay, we have a quorum Members. Thank you. We have a motion, three Members, and we will take up a vote on those two items.

Item number 1, SB 305. The motion is do pass to appropriations recommended consent. Item number 2, SB 746 The motion is do pass is amended to appropriations recommended consent. Garcia, aye. Patterson, aye. Bauer-Kahan, aye. Calderon, aye. Carrillo. Chen, aye. Connolly, aye. Holden. Mathis, aye. Muratsuchi. Reyes, aye. Santiago. Schiavo. Ting. Wallace. That's 8. Keep it open.

Thank you. We're going to keep the roll open for other Members to add on to the consent calendar, but we will go into recess for the regular hearing of utilities and energy, and we'll transition to what is today's hearing as a follow up to last year's discussion in the need to build transmission capacity to meet our ambitious climate goals.

Fortunately, a lot of attention was put forward last year on transmission, and a suite of initiatives were adopted by this body and by the Legislature as a whole, including permitting, reforms and regulatory initiatives like the MOU signed between the agencies that have responsibilities in this space. Our focus today will be to hear an update on implementing these efforts, as well as understanding additional work that remains.

We also welcome the perspective from our federal partners as efforts to revamp the transmission development process and its impacts with FERC and the Department of Energy. We're all aware of the unprecedented scale and pace at which the development of new, clean resources in the state must go hand in hand with the expansion of transmission systems. Such expansion is marked by a unique set of challenges and introduces opportunities for potential delays that could hamper the ability to meet our climate goals.

Overcoming these unique challenges requires us to all go back to the drawing board and reexamine our transmission development process to find unique solutions. We have invited this panel to discuss the current reforms that entail better coordination amongst the energy entities to synchronize transmission planning and notably, permitting process to ensure new resources can be delivered timely and affordably. With that, I turn to my colleagues to see if there are any opening remarks before we ask the panelists to come forward. Please.

Thank you, Mr. Chair. I want to thank you. And especially I want to thank your staff for writing an excellent and thorough analysis on California's transmission infrastructure. I've been on this Energy Committee since I got here for many years now, and I'm always amazed at the complexities on energy policy. Over the past two years in this Committee, we have debated the issues with interconnection, energization, grid reliability, resource adequacy, and of course, the need to build out clean and renewable energy generation.

There are so many things to consider, which is why it's so hard to come up with a solution or one solution, because there really is no silver bullet to our energy problems. Every time we try to address one part, we need to be cognizant on that effect on the rest of the energy chain, so to speak. The analysis said it best. Each step of the process presents its unique set of challenges and introduces opportunities for potential delays.

It's going to take, as you said, Mr. Chairman, it's going to take a suite of solutions rather than a global solution to make sure we have enough clean energy that we can be connected to the grid and enough transmission to get that power distributed to our customers. So I look forward to hearing from the panelists today.

Thank you. Thank you. Member any other comments before we get started, I'll ask the panelists to come forward. I know the first two will be providing their comments remotely, but if the other Members will please come forward, we will staying from questions until all panelists are complete with their remarks. And so I just wanted to set that tone. Please come forward, take your seat, and we'll start in the order that the agenda has set forward. Today's speakers.

Okay, so we're going to start with the CalISO as the folks get ready remotely to provide their testimony. So when you're ready. We're ready. Welcome again.

Well, thank you very much. I'll just jump right in then. My name is Neil Miller, VP of Infrastructure and Operations planning at the California Independent System operator. Thank you very much for the opportunity to speak to you today. We did prepare a few slides to help walk through some material that could be helpful just to set the context for some of the transmission planning activities. I don't know if those are being pulled up or how.

If you'll allow me just to pause for a second. Reopen the regular utilities and energy meeting for Members to add on to a vote, and then we will proceed accordingly.

Please, ma'am, this is a consent file. Carrillo. Holden, aye. Muratsuchi, aye. Santiago. Schiavo. Ting, Aye. Wallace.

Okay, we will recess. We'll leave the roll open for other Members. Right on. We will recess the regular meeting and we'll proceed with the informational hearing.

Please. Well, thank you very much. So, yes, if I could just move to the next slide, please. The first thing I was just going to touch on before I got into the State of the current transmission planning activities was just to touch on a few things that have changed since last summer. Actually, last summer, as we were going into our summer 2022 preparedness, there was a heightened level of concern regarding our supply adequacy going into the summer.

Conditions this year have improved, both due to the addition of new capital resources, new installed capacity on the grid, as well as the improved hydro conditions.

So those two factors combined have put us in a better position by the time we reach September, which is becoming our critical peak load month, and particular risk as we're facing more extreme events occurring in that time frame, we are looking at about having an additional 3000 grid connected storage on the grid compared to last year, as well as additional solar resources that are helpful in providing the charging energy for that storage.

So while we're always concerned going into summer months because of the effect of climate change, we are in a better position than we were last year. Now, the progress we've made on installing new capacity as part of a broader framework. If I could move to the next slide, please. This year we did. In May of this year, our Board of Governors approved this year's annual transmission plan.

And I did want to draw some particular attention to the 20222023 transmission Plan because there really were two fundamental changes this year.

One, we've really sharpened and highlighted a more zonal approach to transmission planning to better articulate for the resource development community and load serving entities the areas of the state that are being targeted, where transmission is being developed, based on coordinated planning with the Public Utilities Commission and the California Energy Commission on where Resources are best located, where the transmission is being proactively planned for.

The other change was that as we continue to pivot to the higher volume of resources that need to be added to the grid year over year. This is also the largest transmission plan we've produced to this point.

The other thing that this really highlighted is that in the linkages between our processes, the Public Utilities Commission and Energy Commission, we really see that while many of the core processes themselves were solid, we really need to tighten the linkage between resource planning, transmission planning, interconnection, and actual resource procurement. We need the load serving entities to be actively shopping for projects in the areas where the transmission is being developed. Next slide, please.

So this year's transmission plan was really reflected by the picture on the right, which highlights the areas and the key transmission corridors that we're reinforcing in this year's plan. And in many of those areas, we also did sensitivity work that we were able to size many of the upgrades to what we saw being the emerging needs that would be coming at us next year.

Because by the time we were finalizing this year's transmission plan, we already had the benefit of knowing the renewable portfolios the Public Utilities Commission was providing us for next year's transmission plan. So this year's plan was keyed off of accommodating at least 40,000 installed capacity over the next decade. But in many areas, the solutions were sized to go beyond that, towards the 70,000 MW that are the target for next year's transmission plan.

The transmission plan was also based off of and able to correlate with a longer term 20 year outlook we had prepared last year that was not a binding or decision making document, but that long term planning really helped provide more comfort to ourselves and our stakeholders that this year's transmission plan was part of a longer term plan and direction to achieve state goals. Next slide, please.

The plan itself, when I mentioned it, was the largest plan we've produced to this point, it included 24 reliability projects coming in at a price tag of $1.8 billion, as well as 21 projects that were focused primarily on accessing renewable resources and delivering that power to load.

Now, these are the bulk transmission system requirements, of course, within each area, local requirements, which are becoming an issue at times, but local requirements also exist depending on which specific projects in each area actually get contracts and move through the interconnection process to get connected. At the same time, we're also working with Idaho Power and with LADWP on several projects that might be brought back in as an extension of this year's plan or considered further in next year's, depending on how that work goes.

We are interested in these collaborative opportunities as well to see how we can achieve our state goal requirements and at the lowest cost and do it most effectively. Next slide, please. The other thing I wanted to mention, and there's been a fair bit of attention made about the ISO's generation interconnection queue. And just to be clear on this, generators and resources apply to connect to the transmission system. And today that's a precursor activity in order to compete for load serving entity procurement.

So we know that a large number of the projects that apply will not ultimately be successful, even with our very large requirements for resource interconnection. We currently have 180,000 resources in our interconnection queue. And in April of this year we ran an open window, which we do generally annually, and we received another 541 projects that totaled 354,000 capacity. Our peak load, of course, was 52,000 heat wave of last year.

So we definitely need to take steps and we have launched a major stakeholder process to do further refinement to our interconnection process to better couple our interconnection study activities with resource procurement being conducted by load serving entities. We think the coordination with the state agencies on the planning side is fairly tight, but we clearly need to get better linkages to the actual procurement activities to get these numbers down to realistic and manageable numbers earlier in the game.

But like I said, these volumes are just staggering when you consider the size of our system. So we'll be working through the course of this year to develop additional refinements to our interconnection process to better streamline. Now, I'll stop there and I'll be looking forward to questions, and I know particularly about transmission development as well, of course.

Thank you very much. We're going to hold off on the questions, but we're going to go back to the top of the agenda with our presenters that will be addressing us remotely. And I believe the first presenter, Jeffrey Dennis from the Department of Energy, may already be in the queue. And so we'll start when they're ready.

Can you hear me okay?

Yes, we can hear you.

Thank you very much and good afternoon. Thanks for the opportunity to spend a couple of minutes talking about the Department of Energy's work on transmission Development. My name is Jeff Dennis. I'm the Deputy Director for transmission in the Department of Energy's Grid Deployment Office. The bipartisan infrastructure law made the largest long term investment in our nation's infrastructure in nearly a century.

The Inflation Reduction act followed up with the largest investment in the deployment of clean technologies ever setting a path to lower energy costs and to meeting the goals of making the power sector 100% clean by 2035. Now, those historic investments from the bipartisan Infrastructure law led the Department to realign itself to include a new deployment of mission of infrastructure deployment to its long standing core mission of research and development.

And that realignment led to the creation of several new offices in the realignment of existing offices, including the creation of a new grid deployment office, again to focus solely on deployment of electric grid infrastructure needed to ensure that we can bring Low cost electricity to everyone everywhere while meeting climate goals and improving reliability and resilience.

The Grid Deployment Office has three divisions, and an entire division of that office is devoted to transmission because it is a central pillar of the administration's and of DOE's overall infrastructure deployment mission and its mission to bring down energy costs and improve reliability and resilience while delivering Low carbon and carbon free electricity to customers. The transmission system is really a linchpin in all of this, and that's why so much of our efforts are focused on transmission.

By independent estimates have found that we'll need to expand transmission systems by 60% by 2030 and may need to triple our existing systems by 2050 nationally to meet our growing clean electricity demands. Looked at another way, if we maintain our current pace of transmission expansion, which has been about 1% per year of capacity expansions per year for the last decade or so, we could lose as much as 80% of the Greenhouse gas emission reduction promise projected to come from the Inflation Reduction Act.

To capture those benefits, as well as the economic benefits of that law, we'll need to increase that pace to well over 2% per year of capacity additions. So the Department of Energy and the Grid Deployment Office are embarked on a three pronged strategy for advancing deployment of transmission infrastructure. And I'll try to touch on a little bit of that and then answer more specific questions.

But that three pronged strategy is aimed at three of the biggest impediments to expanding transmission capacity at the pace needed to capture those opportunities I talked about and address those challenges I talked about we have a breadth of programs, studies and grants totaling more than $25 billion focusing on three key issues, siding and permitting of transmission, enhanced transmission planning and commercial facilitation of transmission projects to fill market gaps that may prevent transmission we know we need tomorrow from being financed today.

So I'm actually going to start a little bit out of order and talk just for a minute about our work on planning. So we're focused on planning so that to help understand where current and future congested areas on the grid are in an effort to effectively deploy all of these tools to meeting those needs. And we're doing that through a few different efforts.

We're embarking on a national transmission needs study, which is a robust analysis of both current and future congestion and capacity constraints conducted in accordance with congressional direction in the Federal Power Act. This needs study helps identify areas of high priority for transmission development to inform national efforts both at DOE and in the states.

We're also embarking on a more ambitious long term national transmission planning study that looks not just at needs, but at national scale long term, both needs and opportunities to identify a portfolio of solutions to those needs. That national long term transmission planning study conducts a lot of new analysis along a longer time frame to identify both those needs and those solutions. And we're also convening stakeholders to look at transmission needed to deploy offshore wind at scale.

And we recently kicked off work on the West coast to convene decision makers and stakeholders and to study the transmission that may be needed to capitalize on offshore wind on the Pacific Coast. Turning to siding and permitting we know that to build transmission at the rapid pace required, the current permitting structure needs to improve. Inciting and permitting are a major focus of the current Administration, from the White House through to the federal agencies responsible for permitting.

Given the need for additional transmission infrastructure I talked about earlier and the recognition that permitting processes are often the long pole in the tent when it comes to the long development timeline for transmission. Currently, federal permitting for transmission lines can take as much as 10 years or longer, and we know that transmission sighting and permitting is a multifaceted challenge. We have those federal permitting challenges.

State and local authorities are still the primary driver of transmission sighting in many areas, and local communities can face unique impacts from new transmission infrastructure. We're working to use a number of tools at the Department of Energy, some existing and some new, from the Bipartisan Infrastructure Law and the Inflation Reduction act, to address challenges at each of these levels.

This includes a new effort to coordinate federal permitting for transmission among nine key federal agencies who are often involved in transmission permitting to reduce duplication and delays by setting binding schedules that require final decisions on permit applications within two years and that require the production of a single environmental review document as the basis for all federal decisions. We're also working to designate corridors where transmission congestion and constraints are harming consumers, to allow the deployment of new financial and sighting tools to address those constraints.

And finally, we're implementing a grant program that would support and provide grant support and financial support to state and local sighting authorities to help them improve and speed up their work on transmission sighting and permitting activities, and to provide economic development opportunities to communities that are impacted by transmission development.

Finally, on the financing and commercial facilitation side, as I mentioned earlier, we know that many projects we will need in the future suffer commercial challenges that prevent them from obtaining sufficient financing and customer commitments early enough in the process to match with that long development timeline we know transmission takes. Congress has provided us with a number of tools to combat this problem. One key tool is the transmission Facilitation program.

This is a two and a half $1.0 billion borrowing authority that allows the Department of Energy to enter into capacity contracts with proposed transmission projects or public private partnerships or loan guarantees to ensure that projects that would otherwise not be constructed or would be constructed with less capacity than is optimal, are built and can progress to construction. We also have additional authority to enter into loan guarantees for facilities that are meeting those national imperatives to reduce capacity, congestion, and constraints I talked about earlier.

And all of these tools together can help complete the financial picture and reduce the total cost of transmission development. I'd be happy to discuss all of these initiatives and tools and what we see as the view on transmission development nationally in response to your questions. Thanks very you very much. I know we have a number of questions. Once all the.

Presenters put their presentations before us. We're going to pause the informational hearing for one second and reconvene the Utilities and Energy regularly scheduled meeting for Members to add on to the two consent items.

This is a consent file. [Roll call].

Okay, 13-0. I think at this point we can adjourn the meeting on the Utilities and Energy with no further interruptions. We'll continue the informational hearing, please. The next speaker will be Christina Hayes.

Afternoon. I appreciate the chance to speak with you about Order 1000. I believe I have some slides. I don't know if those are able to be seen by the folks in the. Oh, terrific. So I'm Executive Director of Americans for a Clean Energy Grid. We are a diverse coalition that advocates for high-capacity transmission around the country, mostly on the federal level. Prior to this, I worked for FERC for a number of years, including for Chairman Wellinghoff during Order 1000.

So I'm pleased to talk with you today about things that are happening at FERC around transmission policy. Go and go to the next slide. FERC has jurisdiction over transmission planning. This is found in Federal Power Act Section 201 in terms of the practices that relate to rates.

There are court cases that have said that, for instance, FERC cannot specify how board Members of an RTO or ISO are selected, that that is too far removed from a practice impacting rates that was specific to what happens in California. But here the courts have found that FERC's jurisdiction over transmission planning is directly connected to the impact on rates, and so that has been upheld several times. So the framework for planning is established at FERC, and then it's implemented through Kaiso. Next slide.

So these are the planning regions around the country. As you can see, California is mostly covered by the California Independent System operator. There are little bits also covered by WestConnect, which is primarily in nonmarket areas in Arizona, New Mexico, and Colorado. Northern grid covers the Pacific Northwest and part of the Mountain West as well. And then you see the RTOs and the planning regions are coincident throughout the country, and then Texas is not a planning region. Terrific, thanks. Order 1000.

Order 1000, moved from Order 890, had been focused on providing opportunities for planning, but not requiring it for regional planning. Order 1000 required regional planning and offered opportunities and guidance around interregional planning, but did not mandate that next step. So it required regional planning that satisfied principles around transparency and cost allocation to require a regional plan required planning to address economic congestion, reliability, as well as public policy requirements.

It also included elimination of a federal right of first refusal and federal tariffs, but left the door open for states to incorporate their own right of first refusal, which led to competitive bidding for projects in some Order 1000 planning regions, and also provided that opportunity to coordinate with neighboring regions for interregional transmission, where it was found to be efficient or cost-effective. For cost allocation, it prohibited participant funding.

You could not merely say, kind of throw it open to developers to have to fund their own projects, but instead, provide opportunities for regionally planned transmission. Regionally identified challenges where solutions would be solicited from a wide number of participants and then the best ones selected to serve customers in the region. Next slide. So these are the current FERC commissioners.

This is relevant because currently there is a rulemaking pending at FERC to consider revisiting some of the reforms in Order 1000 to make some changes here and there. However, that proposal has been pending for more than a year. There have been comments that have been taken and we have not yet seen a final rule. The Chairman that proposed those revisions and those reforms has since rolled off of FERC. And so we now have a FERC with two Democrats and two Republicans.

Chairman Danly, I'm sorry, Commissioner Danly, you can see he's on the right. That's simply to indicate that his term ends here at the end of the month, but he is eligible to hold on through the end of December. Commissioner Clements is a Democrat and her term ends next year. And so you can see that there is an opening at FERC and there will be another one soon.

This is just to show some of the turnover at FERC and how it could potentially impact reforms to Order 1000. Next slide. So the proposed reforms consider some changes in terms, especially being more specific about what it would take to plan ahead for long-term, potentially 20 year was the proposal needs for new load, new electrified buildings, electrified vehicles, a number of other drivers on the system, as well as potential new generation.

The proposal also suggested looking at multiple long term scenarios to incorporate a minimum set of factors. There were something like 17 factors proposed and there was consideration of whether or not they should all be mandated or if there should be some more variability in consideration.

Also, the idea was to look at each line in terms of the many benefits that each line provides, whereas the same line can provide both economic benefits as well as reliability as well as address some of the public policy choices being made by utilities, customers, and jurisdictions, governments around changes in the resource mix, and the focus is to establish criteria to maximize benefits over time. Next slide. In addition to changing planning, how that's conducted there was also consideration to how cost allocation might be changed.

One idea was to focus on the ability of state entities to agree within a planning region on cost allocation, to establish a cost allocation method for facilities using an ex-ante analysis, and also to establish a cost allocation for those looking at long-term regional planning complying with Order 1000. So this is the fundamental concept of beneficiaries should pay focused on the benefits that they receive, focused on reduced outages, reduced impacts from reliability events, and also reduced economic congestion. Also provides economic benefits.

So next slide. FERC is also considering a large number of other proposals related to transmission. The one that we keep hearing is going to come up sooner than the others would be interconnection queue reform. So this is to expedite the current process to allow more for cluster studies rather than serial studies of integration of new resources onto the grid.

Backstop sighting was a reinvigoration of the statute from EPAC 2005 in IIJA that passed Congress in November 2021 gave FERC renewed authority to sight lines in case of a state declining to act on a certificate or rejecting that certificate within a year on lines that are proposed to be within a corridor that's designated by the Department of Energy, and then the last piece that is being considered as a minimum transfer capability requirement.

This was an area that was gaining bipartisan interest at FERC as an important way of looking at transmission as a way to support reliability. A workshop was held last December. Comments were submitted in mid May and then also due again here at the end of June.

And in the middle of all of this, Congress passed its debt deal that provided for some NEPA reforms, as well as requiring the North American Electric Reliability Corporation, or NERC, to conduct a study examining whether this minimum transfer capability requirement would be helpful. NERC has 18 months to do a study, then turn it over to FERC. FERC has 12 months to put it out for comment and then make recommendations to Congress for changes that should be made in response to NERC's study.

That is the end of my presentation and I'm happy to answer any questions.

Thank you very much. We'll go on to the next presenter with the Public Utilities Commission. Simon.

Good Afternoon. Chair Garcia, Honorable Members of the Committee, my name is Simon Baker and I serve as a Director in the California Public Utility Commission's Energy Division. My presentation this afternoon provides an overview of the PUC's role in the transmission, planning, and permitting process. Given the extent to which California's climate goals rely upon clean, reliable electricity, the PUC is very focused on building out infrastructure across the three main components of the electricity system generation, distribution, and transmission, the focus of today's hearing.

I do have some slides. If you could pull up my second slide, please. On this slide, it depicts all the steps in the transmission planning, permitting, and cost recovery processes. On the far left, there are the planning inputs that come in from the Energy Commission's demand forecast and the PUC's Integrated Resource Plan, or IRP, which feeds into the CAISO's transmission planning process, or TPP, depicted in purple and blue.

Projects are identified either by the CAISO through the TPP process or by the utilities for the low-voltage system. From there, the projects follow different permitting pathways. Either the projects are permit exempt or they go through PUC permitting and seek a review. The green boxes depict the project construction phase, and the orange boxes at the far right reflect the project cost litigation at FERC and ultimate cost recovery.

Finally, the PUC recently adopted a transmission permit review process, which operates in parallel to enhance ratepayer protections by bringing transparency to utility costs that go into transmission owner rate cases at FERC. Importantly, this parallel process does not hold up the permitting process. The PUC's IRP process produces annual forecasts of the portfolios of resources expected on the grid over the next 10 to 15 years, and it's based on the IRP filings of the load-serving entities.

We have about 40 of them, and it's one of the key drivers of the transmission expansion in California. The IRP process also optimizes clean energy resource procurement to achieve the most cost-effective system plan to reach the state's aggressive GHG targets while also ensuring reliability. Further, the annual results of the CAISO's transmission plan feed into the IRP, which in turn develops portfolios that inform the future CAISO transmission plans.

And through this cyclical process, we're continually updating IRP assumptions such as resource costs, the plans and procurement activities of the PUC jurisdictional LLCs, and information about transmission constraints. In addition to providing the CAISO with the most cost-effective resource portfolios needed to meet climate goals, the IRP process conducts what's called bus bar mapping, which envisions the geographical areas where these new resources are most likely to be developed, and therefore the bus bar or the transmission substation locations where they would connect to the grid.

Bus bar mapping is foundational to the CAISO's analysis and helps to optimize development of new transmission projects. The CEC's load forecast developed in the IPER is another key input, and the state's load forecast is increasing because of electrification policies, which triggers the need for more clean energy resources and, in turn, more transmission. Next slide, please.

For example, if we look at this chart, we can see how the PUC portfolios that were conveyed to CAISO in the 2021 TPP cycle included just 12 gigawatts of new capacity, and that resulted in three new transmission projects. Two years later, the 2022-2023 portfolios were modeled using a lower GHG constraint and higher levels of transportation electrification, and this resulted in 40 gigawatts of new capacity. As was mentioned earlier by the previous speaker, this is more than triple the amount of the 2021 cycle.

In turn, the CAISO plan approved a significant increase in the number of projects, 45 specific projects in this year's plan, the vast majority of which will be built in California at an estimated cost of 7 billion. For the current TPP cycle, the base portfolio that the PUC conveyed to CAISO includes 85 gigawatts of new capacity by 2035, which is inclusive of the 40 gigawatts from before, and we expect this will trigger significant amounts of new transmission. Going back to slide two if I may.

Turning back to our permitting role, the PUC implements our statutory mandates through General Order 131 D, which determines if a permit is required and what type of permit is required. The criteria in 131 D are triggered. If they're triggered, the transmission owner must submit an application for a Certificate of Public Convenience and Necessity, or CPCN, or for smaller projects, a Permit to Construct or PTC. If not, the project is exempt.

Is project exempt from the PUC permit process and seeks approval via an informal advice letter filing, which typically takes up to 45 days to complete and by and large, no further PUC oversight is required. A CPCN is required for construction of major electric transmission line facilities designed for operation at 200 kilovolts or more, and a CPCN is a higher bar than a PTC and requires a showing of cost and need and an assessment of non-wires alternatives pursuant to Public Utilities Code 1002.3.

A PTC is required for construction of power lines designated for operation at 50 to 200 kV, or substations that are designed to operate below 50 kV unless they're part of a project with a transmission line above 200 kV. There are many exceptions from needing a PTC, including replacement of existing power lines with equivalent facilities, minor relocation of existing power line facilities, adding conductors, insulators, and other accessories to existing structures, conversion of existing overhead lines to underground, and other exemptions.

Could you please skip forward to slide four? To give a sense of how many projects fall into these permitting pathways, from 2004 to 2022, about 80% of projects submitted to the PUC, 428 out of 535 were exempt from the permitting process. For the 20% of projects that historically go through permitting, the process typically takes under two years. As shown in the figure to the right, the CEQA Environmental Review is performed in parallel with the PUC permitting proceeding to save time.

The PUC has processed 107 permits since 2004. Only a third of these permits, or 35, have taken more than two years to be issued, and the primary reasons for those longer timelines were substantial public opposition to the application and related environmental evaluations, applicants making substantial changes to their applications triggering changes in the related SQID document, applicants providing insufficient project need justifications, which creates challenges in developing the CEQA document and results in preceding delays and delays resulting from coordination with federal NEPA processes in an effort to prepare joint NEPA CEQA documents as required by Title 14 of the California Code of Regulations.

The PUC has opened a proceeding to update and amend GO 131D pursuant to the requirements of Senate Bill 529 from last year, which exempts any extensions, expansions, upgrades, or other modification of an existing transmission line or substation from the requirement of a CPCN and instead directs the use of the PTC for the more streamlined process.

We are also considering other changes based upon staff's experience implementing the General Order to provide a clearer, more efficient, and consistent permitting process while complying with SB 529 and other applicable laws, policies, and orders. Changes to General Order 131D being considered include creating a distinct process for battery storage permitting, increasing transparency on costs, providing better notice to local governments, and reflecting changes that have occurred since 131D was last amended in 1995.

Last slide, please. Another way of looking at the impact of PUC permitting projects is to look at it in dollar terms. This is my final slide showing total investment in transmission for the large three utilities and the statewide total. In six years from 2016 to 2021, the total value of transmission projects that went into operation is over 12 billion. Of this, nearly 7 billion is so-called utility self-approved, meaning the utility-identified projects that repair and replace existing transmission assets.

Over the same period, about 5 billion in CAISO-approved projects went into operation, and of these, less than 2 billion required PUC permits only about 15% of the total. Looking forward, the CAISO estimates through their transmission conceptual outlook significant investments in transmission at utility ratepayer cost and as we build out the grid, we must be mindful of rate pressures by ensuring that transmission owners demonstrate cost discipline.

One such strategy is the PUC's newly adopted transmission project review process. The PUC advocates for California rate fares at FERC on transmission owner rate cases where transmission costs go into rates, but by then it's typically too late to challenge any of the cost overruns or imprudently managed projects. So the TPR process subjects the three major transmission owners to semiannual data collection and analysis, discovery, and stakeholder review. Importantly, as I said earlier, this does not interfere with the project development process.

To recap, the PUC permitting process is only triggering on a small percentage of projects. For those projects, the PUC has tracking efforts in place to do what we can to expeditiously move them along, but we can only assist developers with some barriers they face. Many issues are outside our control, such as obtaining project financing, land acquisition, workforce development, and availability and equipment shortages, to name a few. Thank you very much for this opportunity. That concludes my remarks.

Thank you, Mr. Baker. We'll go on to Estela de Llanos with SDG&E. Welcome.

Thank you and good afternoon Chairman Garcia and honorable Members of this Committee. My name is Estela de Llanos and I am the Vice President of Energy Procurement and Sustainability for San Diego Gas and Electric Company. I'm pleased to appear before you today to provide SDG&E's perspective on building transmission for the clean energy transition. SDG&E is a regulated public utility that serves 3.7 million people in San Diego and southern Orange counties.

Our service territory spans over 4,000 sq. miles and our system includes over 1,800 miles of electric transmission lines and over 17,000 miles of electric distribution lines. We have extensive experience with planning, permitting, constructing, and maintaining safe and reliable electric infrastructure throughout the communities we serve, which include some of the state's most fire-prone and environmentally sensitive areas. The climate-driven extreme heat events in 2020 and 2022, longer and worsening wildfire seasons, and losses of life and property make it plain that climate change is accelerating and we have no time to waste.

California has set ambitious climate goals to achieve economywide carbon neutrality by 2045, and attached to my testimony is a summary of key milestone dates that illustrate our collective attention is focused on getting to net zero. To meet this goal, the state must decarbonize 4.5 times faster than it has over the past decade.

SDG&E strongly supports the state's goals, and in 2022, we developed a roadmap that examines the implications of this transition for energy system reliability and resiliency. As California reduces its dependence on fossil fuels in favor of clean electricity, we estimate that electric generation capacity will need to increase approximately four times the capacity that existed in 2020 to reliably meet the growing electricity demand. This increase stems largely from widespread electrification of vehicles, buildings, and select industrial processes.

In order to meet our climate goals, unprecedented amounts of electricity must be delivered to customers, and to do that, we must build the infrastructure needed faster than ever before. The path to building transmission is long and complicated. It can take 10 to 15 years or longer to forecast customer demand, plan the system, and finally construct the infrastructure. We're encouraged by the recent MOU between CAISO, the CEC, and the CPUC to coordinate more closely on identifying and approving needed clean energy infrastructure.

Yet the challenges the state faces for new transmission are unprecedented. CAISO's new transmission plan identifies 45 projects for system expansion statewide and upgrades in the next 10 years, the largest tranche of new transmission in CAISO's planning history.

And this does not account for the transmission needed over the longer term to access resources like offshore wind. SDG&E is grateful for the work being done by legislators at the state and federal level, the governor's office, and across the various agencies that are responsible for planning and implementing California's energy transition. But perhaps the biggest challenge in developing transmission infrastructure quickly is the complex and lengthy permitting and environmental review process, particularly for linear facilities, which often cross many jurisdictions.

We know this challenge well from building the Sunrise Powerlink, a 500 kV high voltage transmission line carrying 1000 MW of power that runs approximately 120 miles across the state from our Imperial Valley substation into San Diego. The planning for the Sunrise Powerlink began in 2004 after a CEC study found that, quote, transmission upgrades, and expansions are critical to ensuring a robust and reliable electric system.

The process at CPUC required SDG&E to litigate the need for the project before an administrative law judge and to undergo a comprehensive environmental review. Ultimately, the project underwent approximately five years of environmental review and permitting alone. The CPUC's environmental impact report was approximately 11,000 pages and evaluated over 100 alternatives. The project required 70 different permits from over 28 different agencies, not just the CPUC.

Our originally proposed northern route along an already existing transmission corridor was blocked due to siding constraints across state lands, adding significant delay and evaluation of additional routing options. Ultimately, the US Forest Service approved the line through the Cleveland National Forest. Years of litigation in both state and federal court followed. The line took 21 months to construct and was eventually energized in 2012. SDG&E appreciates the various efforts underway to expedite and streamline the processes of planning and building electric transmission.

Unfortunately, we worry that CAISO's 10-year plan will not be built within 10 years, but we see opportunities to improve the process.

These include the following. Number one, leveraging the work done during the CAISO planning process to avoid duplicative need determinations. Number two, streamlining CEQA review for designated clean energy electrical infrastructure projects and wildfire risk mitigation. Number three, expediting the processes for natural resource conservation and species protection. And number four, expanding existing rights of way through state-owned lands to advance clean energy goals and to meet modern-day safety and reliability standards.

Just as the impacts of climate change continue to accelerate, so must we accelerate our review of clean energy projects. We see opportunities to provide a clean, safe, reliable energy future while protecting environmental resources and community values, and we stand ready to work with you and everyone on this panel to achieve the state's goals for the benefit of future generations. That concludes my testimony. Thank you again for the opportunity to be here today.

Thank you very much. We'll go with the last presenter, Natalie Manitius, with the Clean Energy Clean Air Task Force. Welcome.

Thank you. I don't need my slides actually. Thank you. Good afternoon, Chair Garcia and Members of the Assembly Committee, thank you for the opportunity to testify today. My name is Natalie Manitius. I am a Clean Energy Setting Associate at the Clean Air Task Force, CATF. We are a nonprofit organization working in the US and globally to reduce air pollution and greenhouse gas emissions quickly, affordably, and equitably.

CATF has been asked to speak to the challenges California faces in building the electric transmission system required to meet its clean energy policy goals. Our comments seek to convey the scale of the challenges at hand, provide insights into extensive project delays and their implications, and identify where areas of policy reform may reduce deployment challenges.

As I'm sure you all know, California has set ambitious climate and clean energy goals with the passage of SB 100 in 2018, the state has required 100% of its retail electricity need be supplied with renewable and zero carbon resources by 2045. Meeting this goal will require an unprecedented buildout of zero-emitting generation facilities, but this action will fall short if not matched with the transmission capacity needed to connect these resources to the grid.

According to the 20-year transmission outlook published last year by the California Independent System Operator, CAISO, more than $30 billion in new transmission capacity will be needed over the next two decades. Additionally, a 2021 study released by Princeton University suggests that in the State of California, transmission capacity may need to triple by 2050 in order to reach full decarbonization across all sectors through a combination of upgrading existing power lines and building new facilities.

The needed capacity additions in California are huge, but the buildout pace is slowing at the exact moment it needs to ramp up dramatically. Project timelines are lengthy and regularly face uncertainties and delays. For context on the development process in whole, transmission projects are identified annually in the CAISO's transmission planning process for either public policy, economic, or reliability need, with a few of these projects made eligible for competitive solicitation.

Most major projects must then obtain permits through the CPUC, who leads two simultaneous permitting processes, an environmental review under CEQA and a project needs and cost review, often called a CPCN. For larger projects with all necessary permits from state agencies, projects are free to construct. Our fact sheet and presentation distributed to you today goes in-depth into each step of this process. Last year, CATF published a report called Growing the Grid, which identified challenges California will face in building the scale of clean energy needed.

In that report, we examined timelines from proposal to completion for every major transmission project identified in the CAISO's transmission plans from the last decade. These projects are projects with costs in excess of $50 million that CAISO deemed necessary for state needs. We found that each of these 24 projects required a decade or more to plan, permit, and construct.

On average, they took more than five years longer to complete than CAISO anticipated, and we also found that 15 projects slated for completion within the next three years have taken nearly three times longer than anticipated. This year, we did a deeper dive, assessing the development of 13 major transmission projects, breaking down the timeline into each step of the process. We found the following. First, this analysis reinforced our previous findings that projects frequently stretch beyond significantly beyond their initial completion dates.

Second, we noticed that delays are particularly severe in two parts of the process. First, in the time it takes to submit project applications to the CPUC to begin the permitting process and also the second, in the time it takes to complete the environmental review.

Another CATF analysis found that the CPUC's statutory timeline for approving a CPCN is the longest of all Western states, at 19 months, that there are no avenues for expediting a CPCN review like there are in similar statewide grids such as New York or Texas, and that a CPCN process requires a duplicative no project alternative analysis. Finally, given their added complexity, we found that multistate projects tended to take longer to complete.

The impacts of transmission delays not only have impacts on the climate, but also on ratepayers due to rising project costs. This is illuminated by findings from the Brattle Group and the CPUC. Brattle estimates that, on average, projects in California are 33% higher than their original cost estimates. In addition, CPUC findings show that transmission revenue requirements increased nearly 40% between 2016 and 2021. All of this will have impacts on ratepayers, with rates expected to be 10 to 20% higher than the rate of inflation by 2030.

However, developers are currently not required to report costs, making it challenging to fully assess these impacts. And the Brattle Group also found that projects that undergo competitive solicitation tended to be lower in cost, about 30% less costly compared to the costs anticipated from an incumbent utility today. I will conclude with three main policy challenges that emerge from our analysis, along with some considerations of where policy reform could be helpful. First, transmission permitting is slow and regularly faces delays and uncertainties.

To accelerate this permitting process, the CPUC can reclassify the level of permitting review required to modern standards and reduce redundancies. Following the passage of SB 529, the CPUC has begun the process to rewrite General Order 131D, which dictates the level of review for permitting projects and could provide needed updates. You may also consider whether models like AB 205, which transfer CEQA review to the California Energy Commission and Accelerate Review for some clean energy projects, could also be extended to transmission.

The second policy challenge is that project costs are increasing and having rates on impacts on ratepayers who already face high prices. To help manage ratepayer impacts, the CPUC could require cost reporting of transmission projects developed by regulated utilities, providing more transparency and public scrutiny of infrastructure costs. There is also potential to expand opportunities for competitive solicitation given the cost savings that Brattle found, and it is our understanding that the CAISO has the authority to reform its tariff to change which projects are eligible for this.

You may also consider whether state financing options for projects that are required to meet state goals. The Public Advocates Office found that state financing could save up to 25% for ratepayers, which could amount to $28 billion in savings over the coming decades. We also encourage CAISO and others to fully consider options for increasing the capacity of existing transmission lines as an alternative to new greenfield development, as CAISO is doing in this year's transmission plan.

Finally, proactive planning processes that ensure transmission is ready and available to be used when and where generation is built will be crucial. We commend CAISO on moving towards greater proactivity in its recent transmission plans. In summary, the transmission development process is failing to set California on the path to a clean energy future. Without revisions to current planning and permitting processes, it will be tremendously difficult for California to connect new generation to the grid in time to meet its climate-clean energy goals. Thank you.

I welcome any questions you may have, and we are happy to talk more with you after the hearing on any matter.

Thank you very much. I know we have a couple of colleagues that are ready to ask some questions, Mrs. Calderon. Then I'll look to my right over here, see if anyone else wants to get in line.

Thank you, Mr. Chair. I understand that the process to forecast, plan, and build, it's very complex because you also have to take into consideration the environment, the communities, and public health. And so I guess my question is, what can the legislature do to help SDG&E and other developers when it comes to permitting and some of the other challenges that you identified?

Thank you, Assembly Member Calderon. I assume that question was for me. Okay.

I think one thing to consider is we're talking about transmission projects. That is a specific kind of challenge. These are long, linear projects. They go through multiple jurisdictions and state agencies as well as federal entities. Forums like this one, frankly, are helpful. I'm happy to be here today, and I promise you I will be following up with my co-panelists to see what we can do and how we can work together.

But with respect to the legislature, the themes that we are currently focused on at SDG&E are around the CPUC's CEQA and permitting process. And as Mr. Baker referenced, there is an open proceeding. We will be participating constructively in that proceeding. But we believe that there might be some changes that are appropriate within CEQA itself as a statute to provide clarity to the CPUC staff who are, I have to assume, good intentions trying to comply with CEQA.

So sensible amendments to CEQA are one opportunity for us. Turning to some of the other agencies that are involved. Resource planning, natural resource impacts are often biological impacts, in particular, are often a constraint that we encounter. And so there are potential amendments to the Fish and Game Code that could help provide some consistency between the federal habitat conservation planning approaches and the state natural resource conservation planning statutes that exist.

I think that's an area of opportunity for streamlining that would benefit SDG&E for sure, potentially other entities as well. And then another area of opportunity that I think the legislature could help with is specific to rights of way. State-owned lands are often implicated in these routes, and the state has an opportunity to help address the climate crisis by creating corridors or at least acknowledging the existing rights of way that utilities have had for decades that exist for the purpose of electric transmission.

These rights of way were created at a time when we did not know about the changes of extreme winds and fire risk, and so they do not meet the standard width for health and safety and climate resiliency that we need today under the design standards. So an expression of intent and perhaps an expansion of existing utility rights of way with environmental impact mitigation and with notice and with just compensation. I think those are opportunities where the state might be able to make a meaningful difference.

Okay. Assembly Member Carillo.

Thank you, Mr. Chair. My question is for Mr. Baker with the PUC. Can you elaborate a little bit more on the timeliness that you describe related to the applications? Does the timeliness begin when you receive the application, or at what point do you make the application as deemed complete?

Thank you for the question. There's a really important step, which is the project proponent's environmental assessment, the PEA. It's essentially the document that provides PUC staff and our consultants, all the staff, that's all the information that's needed for the application to be deemed complete, for us to be able to begin the environmental review process. As I mentioned earlier, many times the timelines get tripped up because it takes a while for that to come together and to be deemed complete.

And so the timelines that I spoke to earlier in my presentation were from the time that it's deemed complete to the completion of the project.

As a follow-up, what is the average length of time? But when you get the application, as to when you deem it complete, when you need to get all those pieces together, what does that look like?

I don't have the exact answer for you. I do have somebody with me that could provide that answer.

Okay, great.

I'll call my colleague forward, Elaine Sison-Lebrilla.

Unfortunately, I don't know.

Thank you. Unfortunately, I don't have that specific answer for you. Actually, it depends. When we are given a preliminary information, we take a look at what the developer decides is appropriate and we evaluate it to see if it's complete. And usually we turn that around in 30 days, depending on the back and forth that is done by the developer and CEC staff. It varies. I can probably try to find you a typical average, but I can't do that right now.

Thank you very much and thank you, Mr. Chair. I think if you can, I think it would be very helpful for the Legislature to understand the timeliness and timeline process and the average time that it takes to get from step a through the completion process. And if there's ways that the Legislature can be helpful in ensuring that that's done in a more proactive and timely manner to meet our goals, I think that would be very beneficial. I would love to hear from you as well. Please.

Thank you, Assemblymember Carrillo, in the applicant's experience, and I'm speaking now as someone who was formerly an environmental and CEQA attorney prior to coming to the investor owned utility. The CEQA process at the Public Utilities Commission is very unique with respect to this PEA requirement. The timeframe that it takes an applicant to prepare the proponent's environmental assessment is akin to preparing an environmental impact report. Under CQA.

It is very similar, if not duplicative, and it takes about a year for an applicant, on average, to put together the pEa that is the application for the CPUC. The CPUC has a very robust PEA checklist that it utilizes to make sure that the application is complete, and it is rarely complete. Upon the first submittal to the CPUC, there is often usually a back and forth between the applicant and the CPUC, and that takes time.

We can follow up with some of the timeframes in our experience of applications that then had to be resubmitted. And sometimes it is on us, sometimes it might be on agency staff. This is not about assigning any sort of blamE, but I do want to acknowledge that that process is very cumbersome. And then on the other end of it, the CPUC, per General Order 131, will initiate an environmental review process.

So they will rely on, I'm sure, the PEA, but there's an entire CEQA process that follows. That is, again, not my experience prior to coming to the utility.

Assembly Member Connolly

Thanks, Chair. Just a quick follow up on the issue that was raised around CEQA. According to the CPUC, from 2012 to 2023, of a total of 664 projects that required CPUC review, 608 projects were actually exempt from CEQA. So I guess the question is, with so many projects exempt, is it really accurate to say that CEQA is not the main issue that is delaying the approval or construction of transmission projects?

Is that a question to me? Assembly Member?

Sure.

Thank you. To be candid, whatever has happened to date is a little bit irrelevant because the scope and the scale of what we're looking at moving forward is unprecedented.

And so I can tell you that from the perspective of managing a team of environmental professionals within the utility, I think about what resources do I have and do I need moving forward to prepare the applications, to conduct the work, to comply with even outside of the CPUC's requirements, the environmental compliance issues and permitting that are implicated in these kinds of projects. That is just to say that, again, whatever experience we've had to date. May not apply in the future as we move forward and we look at 45 projects statewide, the scale of which we have not seen before.

Yeah, and we recognize the challenge. It's a daunting task as more and more of these transmission projects are coming to us from the Kaiso transmission planning process. And they're going to be bigger projects, too.

And it's the bigger projects that tend to be the more complex ones, the ones that face the litany of issues that I mentioned earlier that have hung up some projects in the past on their timelines, particularly with public opposition, some changes to routes which come up sometimes, as was mentioned earlier, with regard to sunrise, there was a necessity to change the route, and then you kind of start over with the environmental document there. So we're very cognizant of the challenge that's before us. And we think that our 131 D review process will provide one opportunity for us to take a look at what can be done to tighten up our permitting processes.

One thing that I did want to mention with regard to the PEA is that it does provide our staff the robust information that we believe that we need to be able to do a solid CEQA document so that our proceeding and the information that's in the record of the proceeding and the basis on which the decision is made by the Commission holds up on Judicial review. Because many times these decisions, they face appeal and they go to judicial review.

And I think you'll find that the PUC has a pretty good record as far as having our decisions on permitting projects hold up to judicial review.

Great. And one more question. How can we ensure that transmission improvements do not fall on electrical consumers who are already paying extremely high rates. As we know.

That's the great challenge of the day. I work a lot on rates issues, and we submit a report to the Legislature, the SB 695 report, on actions to limit cost and rate increases. It's something we've been very focused on for years now, is looking at trends and rates that are now exceeding the rate of inflation, and we're pursuing a number of different strategies to address that. I will say that I think that policymakers would be wise to look at this kind of from a total pocketbook or total wallet perspective.

So what will happen over time is that as the sales of electricity increases, the rate is going to go down, and in addition, the reduced consumption of gasoline and of natural gas, because building electrification is going to happen, more and more will also help to offset so, looked at on a total wallet basis, I think the picture is better, but we have to be very disciplined about cost control, and that's why we are very focused on bringing as much transparency as possible to the costs of these assets as they're being reviewed through our processes.

And another reason why our proceedings really do focus on justification of the need, ensuring that it's the most cost effective way to get the electrons delivered to where they need to be.

I'd like to open it up to others that may want to chime in on that kind of to lend perspective on that, if anyone wants to please.

Yeah, if I may. I think I'll reiterate some of the opportunities for policy reform that I mentioned in my testimony. One is that cost transparency and requiring cost reporting would be very helpful to organizations like us who would like to be able to get more insights into where project cost increases are coming from and how they will impact ratepayers as well. There's opportunities to look into expanding competitive solicitation for these major transmission line projects that we've seen.

Competitive solicitation across the country can get projects built faster sometimes, and at a lower cost as well. I would recommend looking into state financing options that could reduce impact for ratepayers, and then we may also consider options, like I said, of expanding existing transmission line capacity and preventing new greenfield development.

I would also just like to tag on to some earlier comments about in our transmission planning processes, we're focusing on finding the most efficient and cost effective way to deliver that energy mapped out through the CPUC's resource planning processes to serve load.

The overall optimization was already based on the input of transmission cost information into the CPUC's processes, so that people ask us quite frequently about how we're taking that into account, and it's through the collaboration with the state agency's resource planning that once that decision is made, those are the good areas. We then look to optimize the solution to find the most effective way to get the power from those areas to serve customers.

I'd like to piggyback on that and underscore it because in addition to the environmental review striking me as duplicative, uniquely at the CPUC, the determination of need I talked about the Sunrise Powerlink project, but a lot has changed since the Sunrise Powerlink project.

The fact that we had to look at so many alternatives in that case at that time was in part because we did not have this robust process at the CPUC and at KaiSO for determining the need, identifying the resources, then planning the transmission to bring those resources online. I think we have an opportunity at this moment in time, with the General order being opened up, to reevaluate how the Commission evaluates need.

It does not, I would submit, need to be what it has looked like to date. I'd also like to just touch on the judicial review. There's something else that is special and unique about the Commission. There are many things that are special and unique about the Commission, but one thing is that on CEQA challenges, that litigation gets filed at the Supreme Court, and the Commission enjoys a unique amount of deference to their underlying CEQA decision. That does not happen in other places, in other contexts.

I think you consider CEQA reform that involves judicial review to the Court of Appeal instead of the Superior Court, and the Commission already enjoys that privilege. I am not aware of any instance where the Supreme Court has reevaluated a Commission CEQA determination in the last decade. So I think that gives staff a fair amount of confidence that their decision on CEQA is not going to be disturbed in litigation.

Thank you for that, Mr. Muratsuchi

Thank you. We talk a lot about how we recognize that we need to, what is it? Triple quadruple transmission build out to meet our climate goals. And I especially appreciate SCG E and the Task force for providing recommendations, because we're all about trying to be part of the solution rather than part of the problem. And so I wanted to go down the list of some of the proposals that I heard first for the Clean Air Task Force.

You had as one of your proposals to proactively plan and develop transmission. Isn't that what Kaiso is doing? And if not, what more do you want to see than what KaIso is doing?

Yes, we commend Kaiso on their efforts and especially in the last transmission plan to proactively plan. I think that all in all, we can see more coordination across existing agencies to identify, particularly areas where generation most urgently needs transmission, to carry that energy and potentially identify specific corridors or specific lines that would be most beneficial to the state's needs.

Okay, so you just want to see more of what Kaiso of what you've seen?

Yes, and potentially identification and to expedite, identify to plan for lines that could be potentially also expedited to make sure that those are built and prioritized first.

So turning to Kaiso, is that your plan? Do you expect whether we need to double triple our transmission efforts to identify priority quarters?

Yes. In terms of prioritizing, this is what we actually set out to accomplish when we put out the 20 year outlook in the spring of last year was to set out that longer term game plan of what it took to achieve the longer term goals at the time 2040. This year, we'll be doing another update to that outlook, looking at out to 2045 to help set the context and then help people understand why we're prioritizing certain areas.

In this year's transmission plan, we were able to move on a lot of the development in the south that went beyond the basic requirements of the 40 gigawatt portfolio. But we also knew and were already doing some work for next year. We know there will be a big emphasis on the offshore wind development, so we see that type of longer term, more academic work.

That's helped setting the context, but then prioritizing within each year's transmission plan, which are the projects we need to move forward with now, and how can we work with industry to get those accomplishEd. So like I said, we see the 20 year outlook dovetailing with an annual approval process to actually enable that prioritization. And the prioritization also comes into effect.

Aside from the timeline challenges with some of the major projects, a growing concern for us is actually the time it takes for some of the smaller, more localized projects that those are harder to deal with through a proactive transmission planning process because many of those upgrades actually depend on within even a tight geographic zone.

There might be 20 projects applying to connect, only three or four of which are actually going to get contracts, but the local upgrades depend on which of those projects actually get a contract and move forward. So those have actually become even a bigger challenge for us to manage and prioritize with the utilities because we only really get the green light to move on those when the generators get contracts and give the notice to proceed and actually engage.

So those smaller projects can actually be a barrier as well.

And the smaller projects, you're talking not just interconnection, but also transmission, smaller local.

Upgrades that are within the zone, within the area. But they also need the large projects to get the power to a major load center. But even within the area, we have these smaller upgrades that can become an impediment. Those ones, I have to admit, we're having more trouble trying to proactively plan for.

And that's why we're trying to look for improving the linkages between our transmission planning, our interconnection, and the load serving entity's procurement processes so that we can get better signals earlier about which projects are really serious in the area and get going earlier, because it's all about the timing for us, prioritizing and timing.

Okay, thank you. Turning to SCG&E, your number one proposal was to avoid, I think I wrote down what you said. Basically avoid duplicative permitting. When you're talking duplicative permitting, are you talking cities, states, federal? All of the above.

So it really is around the CPUC's process as it exists today. The last time the rules at the CPUC were considered, it was 1995. This General order that is now being opened and reconsidered, this is very much a live issue. That process is duplicative in two ways, in my experience. One is the cequa process is duplicative. We have to file, essentially we file an EIR and then an EIR is developed. There seems to be an opportunity there, from my perspective.

The second is with respect to the need determination, do we need to build this transmission or can we get away with non wires alternatives? I would suggest that in the past we did not have the robust IRP process and the transmission planning process and other good work by the state such that we haven't had the opportunity to avoid that duplication. And perhaps today we can revisit the need determination in addition to the CEQA determination.

Okay, so that is all taking place at the CPUC. Okay.

In addition to that, there are overlapping opportunities, for example, with respect to natural resources, because we have federal protections, we have state protections, and so perhaps better coordination. Or if, for example, the state could determine that once you have a federal habitat conservation plan, we will maximize the value of that. That's a blanket permit to protect resources and species throughout, for example, a service, territory or an area, can the state determine that we're consistent with that versus having to get a separate permit from the state?

Is that part of your suggestion number three, expediting natural resources planning, it is. Okay. And given that you talked about coordinating federal and state planning, is that within the control of the state government, or are we dependent on the Federal Government to coordinate that?

I think there is an Independence. The Federal Government will do whatever it wants, but we can certainly encourage and try to work together.

So going to your avoiding duplicative permitting, this is the General Order 131 D rewrite that you're talking about what's happening now. So did you say that SDG&E has to prepare an EIR and the PUC also prepares its own EIR?

Essentially. So the proponent's environmental assessment walks through the same checklist of resources and impacts. It's a very extensive application.

Okay, to what extent when you're talking about duplicative permitting, to what extent are you talking about local versus state permitting?

So one advantage of the General order, the CPUC's General order, is that it preempts local discretionary actions. So many permits are preempted, we don't have to typically get a use permit from a county. However, there are often arguments that some aspect of our project triggers a local permit. Sunrise is a good example. We needed to utilize water that met a certain standard for a mitigation measure, and we had to get a local permit for the use of reclaimed water that met the right standard.

We were unable to do that. We ended up having to truck water long distances to use for dust suppression and other site prep work. That process of the water use for a mitigation measure was a subsequent permit that was not preempted.

Who called for that additional permit or that local permit?

It was a condition of approval of our environmental impact report that the CPUC approved. So the CPUC will conduct environmental review. It will then identify mitigation measures, and those mitigation measures often require subsequent action by a different agency.

Okay, but it's not a separate permit as much as a requirement that the CPUC imposed.

It can be a separate permit. We may be required to go and get another permit to mitigate an environmental impact from a different agency.

In that example you just shared, where did the additional permit have to be? Where did that additional permit come from?

Water agency. I believe we attempted to get it from the State Water Resources Control Board. We were unable to do so, and we ended up working with the City of San Diego. I believe that's how that worked out.

So this goes back to a question that I raised in our last mean. I asked, is there a need for a more centralized like a central permitting agency? I thought I heard the PUC representative saying, well, that's us. But you're saying that with the PUC permitting these projects, they may trigger additional permits that need to be issued by the City of San Diego or by the state water resources.

You can you theoretically envision any kind of like a central permitting agency at the state level that would, that would be able to avoid those kind of additional hoops?

Potentially. I think there is an opportunity to coordinate the review of certain projects. What that looks like, we would need to talk about as it exists today, the CPUC is the lead agency for environmental review, and they preempt a lot of the local discretionary permits. But depending upon the scope of the project, what are the jurisdictions that it goes through, what are the resources that it impacts, and what are the land rights that we need to acquire from other agencies?

The CPUC may not be able to preempt, and we may still need to go to those agencies, which can be federal or state. So could another agency function to serve as the CEQA lead? Potentially. Could the Legislature identify that the range of alternatives that needs to be evaluated for certain projects can be narrow that would help, I think, reduce some of what's looked at or preempt further the need for some permits under some circumstances? I think there's opportunity there.

I go back to Assemblymember Gomez Reyes's words at the beginning of this information session today that we're going to need a suite of options. Probably. This is a complex issue.

Okay. Moving to your next recommendation, streamlining SQA for clean energy projects as well as wildfire mitigation. I think that was the basic gist, yeah. Is that along the lines of what the Governor is proposing in the budget trailer bills, or are you calling for more?

It's been a while since I looked at the budget trailer bills, but I did not see that that got us very much in terms of streamlining these kinds of transmission projects. That is more along the lines of, as I just mentioned, if we had narrower range of alternatives. CEQA says you have to look at a reasonable range of alternatives to your project, including a no project alternative. That's in CEQA, and the Commission follows CEQA when it implements its General order.

If we designated these projects and determined that the purpose is to assess and mitigate environmental impacts, we don't have to spend a whole lot of time investigating alternatives that we know are not feasible, such as multiple non wires alternatives. If the state has determined that we need transmission, we shouldn't have to evaluate speculative alternatives that we know are not going to meet the transmission function, and that in the past, again, that opportunity hasn't existed.

But perhaps either through legislation of CEQA or in the General order process, or both, we could make some improvements there.

If I could just add in there too. So state law, Public Utilities Code 1002.3 does require for CPCNs to go through a review of essentially non wireless alternatives. So our GO 131 D reform process can make reforms within our discretion. Under current law, that law does require us to do an assessment of non wires alternatives.

So that could be another potential in the suite of reforms to eliminate that requirement. Is that what you're suggesting?

I'm not suggesting it. I'm noting you're flagging the issue.

I wouldn't mind you looking at that.

Okay. Ah, you're jumping to your number four from SDG&E, expanding the rights of way over state. That is that something that KaISo is already looking at.

So when it comes to the use of rights of way, we do recognize that there's a lot of opportunity there to expand the capacity in certain rights of way to make better use of the rights of way we already have. That's always a key area of concern when we're looking at the transmission planning we have.

Also, at times they'll run into the cases where, because the system is already so heavily loaded, taking transmission lines out of service for some number of months to rebuild them to a higher voltage. Sometimes that's just not practical. So the use of expanded rights of way is an opportunity that we look at in all of our planning work.

It doesn't always work, but it's something that we're always considering the issue about even having to pursue a slightly wider right of way, that in itself can trigger a very lengthy process. We've had a few cases in the past where utilities were upgrading the conductors on certain transmission lines, needing to raise a tower here or there to accommodate, and realized that they were going to require.

And the one case was a foot of extra right of way because of the higher tower, and it was faster and lower cost to go back and reengineer the tower designs just to pull the height down a hair to avoid that extra foot of right of way. So that in itself triggering a major CEQA process was just a third rail that was too hot to touch.

So there are these cases where the requirements are so specific that we have to be very careful in the opportunities we pursue. I think some of the wording we're already seeing in legislation about better use of right of way might allow us a bit more latitude on some of those areas, but I'm not sure how that'll play out yet.

But the comment you just made about the expanding the right of way triggering a major CEQA review, I guess I would go back to my colleague from Marin County. Out of over 600 or 535 transmission projects, only 35 required a sequel process. This would be one of them that.

Would have triggered a sequel process, and that's what we avoided because we had generators that were looking for service. So it was what can we do to make sure we avoid triggering a lengthier permitting?

So among all these options, recommendations, ideas that have been identified in this hearing, is there one that kind of stands out as the one that would be most impactful in terms of speeding up the process of building out our grid? Maybe I'll start with SDG.

That's the higher and better use once it's gone through the process. But we don't have that same opportunity through state lands. And so if the state were to determine that the climate crisis is a crisis and that there needs to be an optimization, I'll call it, of existing utility rights of way. I suspect that that would create some opportunities throughout the state to fully utilize those corridors, or more fully utilize those corridors and avoid some of the public proceedings that have to take place.

If, for example, state parks has to grant a right of way, and I'm not suggesting that we should do that without mitigating for environmental impacts or providing compensation, but there's a way to do that that I think could facilitate utilization of those rights of way more fully.

Okay, the Clean Air Task Force.

Yes, I'll emphasize that I do think that there is a suite of options that should be necessary and that there are Low hanging fruit like the 131 rewrite, that there's plenty of opportunities there to utilize existing processes for reform. I'll also mention that I think that there's opportunity to designate some high priority transmission lines for fast tracked state review, potentially expanding models like AB 205, which currently allows developers to opt in to a CEC certifying process for energy projects.

And that would allow, if you expand that to larger transmission projects, then there could be opportunity to fast track these really high priority, high cost projects through the environmental review process.

So I think when it comes to the permitting process, our direct experience is more involved with the need determination. We also see the situation transmission owners are going through on the SQA side of the table, but we don't have direct involvement with that part of the process. So I was going to stay out of those comments. But when it comes to the need determination, we also see and live the duplication of the need determination exercise.

For the last 12 years, I've been consistently the policy witness in CPUC proceedings where the need for the, when it does go to a hearing where the need for the transmission is actually being revisited, and the irony isn't lost on us that we're defending the need for the transmission based on portfolios provided by the Public Utilities Commission for resource Planning to achieve state policy goals and state environmental goals. You know, we just live that duplication every time out.

We see it adding time and cost to the process and anything that can be done there to tighten that up to save time and money. I don't think anyone's suggesting in any of this work relaxing any of the environmental standards that are maintained in the state. But we do see opportunities to save time and money because an extended regulatory process itself adds considerable to the project cost. Engineering dollars have been spent that are racking up, carrying costs, keeping staff engaged, and so on. So that's where we'd also be strongly encouraging any potential reform.

And that needs assessment is also being addressed in this 131D rewrite?

I don't believe yet. At that point, I think that does require some legislative change, and we have seen different pieces of legislation touching on that, and there are different bills out, I believe, right now in the process, but I think it would take more than the 131D review that the CPUC has underway.

Okay, thank you. And last question. Thank you for your indulgence, Mr. Chair. When is the 131D rewrite process expecting to be concluded?

Well, we typically have an 18 month timeline, is kind of our standard timeline for a new rulemaking.

So when would that 18 month period be reached?

Elaine, the docket is open already, right? Yes. So the order instituting rulemaking was initiated fairly recently. So about 18 months from now.

Okay, so because we are under SB 529 requirements, it's a little bit complicated. SB 529 requires certain things and requires that GO 131 D be completed by the 1 January of 2024. However, we're in a proceeding, and we have two options out where we would do the bare minimum per 529 and have a more extensive change as an option B that we hope we can do all together before January 2024. But we're hoping we can do a more rigorous update of DO 131 D after.

So we were trying to strategize meeting the legislation, but also making the changes that need to be changed with input from stakeholders.

Okay. Thank you very much.

Thank you. I have a question to SDG and E Rep and Clean Air Task Force mentioned in our opening remarks about the MOU signed by CPUC, CEC, and CAISO. So I'm curious to know what your expectations are of that MOU and greater coordination between those three entities. I'd like to kind of get a sense of what expectations are out there for us, for you as it relates to the conversation about accelerating things, particularly transmission build out.

So I'm just curious to get your thoughts on that.

Well, and I have not looked at the MOU in a while, but my recollection is that there's an improvement with respect to the forecasting and a single forecast at the very beginning of this process. We start with what is the demand that we anticipate? And so the MOU was streamlining that and improving that. And I think we are seeing, we're very encouraged about what we see so far. Other aspects of the MOU are escaping me.

In General, I think we feel that it is a positive step forward and certainly if we feel that there's room for improvement, we will not be shy. We are trying to be very constructive in this process and we will let our thoughts be known.

I echo those remarks and there's also a part of the MOU, also have not read it in a long time, that gives greater weight to the determination of need found by CAISO.

And so I think there's opportunity there to greater coordinate on this revision of the duplicative need process, given that the MOU recognizes that as well.

CAISO and CPUC.

I would like to just jump in and say one of the big parts of, I totally agree with what was already said. One of the other parts for us that was really critical was establishing. I mentioned the Q challenges we're dealing with a larger number of projects competing. Applying for interconnection so that they can compete in procurement doesn't in itself increase the amount of procurement that will actually happen.

So we are dealing with a case where a very overheated hyperlevel of competition in the resource development community and the MOU helped us establish what we see as the strategic direction for how to deal with that challenge. By tightening the linkages between the CPUC's resource planning processes, our transmission planning and interconnection work, and the load serving entity's actual procurement. That that's what we've been communicating with our stakeholders. We've triggered our major stakeholder process now to make enhancements to our interconnection process.

And we've been very clear with stakeholders that we're open to a wide range of options of how that takes place. But the strategic direction to tighten those linkages was established through that MOU. So that's a very important part to us. The other part of the MOU that I don't think was mentioned before was it also set a direction that a lot of the Energy Commission's longer term analysis of future resource needs and so forth. There isn't a direct path into the CPUC's resource planning processes.

So the MOU also signaled the intention to draw tighter linkages between the Energy Commission's longer term analysis, and that is an input into the Public Utilities Commission's resource planning work, which we also saw as really valuable.

Thank you. Please.

Yeah, just to add on a little bit to what Neil said, and also with regard to some of the proactive planning that was mentioned earlier.

So that resource portfolio that was sent to the CAISO, that is now resulting in significantly more transmission needs and setting us on a footing to begin that build out that really started with the Energy Commission's load forecast. And so there was some significant steps that were made, actually amongst the three agencies, the CAISO, the PUC, the CEC, and CARB, through a collaborative process called the Joint Agency Steering Committee. It's a staff coordination process where we discuss inputs to the Energy Commission load forecast.

And some significant changes were made to the Energy Commission's load forecast recently to incorporate much higher levels of electrification. Even two levels assumed that regulations at CARB, which were still pending would in fact be adopted. So in some ways, it was a break from precedent to go ahead and assume that pending regulations would be adopted and that therefore, infrastructure with real dollars associated should be built to meet those expected demands.

Thank you very much. Not seeing any other questions from colleagues. I'm going to wrap this up by maybe going back to the top of the list of presenters, including those who are remotely to maybe just take a moment to make some closing remarks based on the discussion that you've heard today. And we really just appreciate you taking the time to being with us. So please, we'll start with representative from Department of Energy and then work our way down the agenda.

Thank you very much. This has been a really interesting hearing. I would like to flag that much of the work that you talked about today and the need for coordination in transmission siding and permitting processes, as well as the need to reduce duplication and ensure that applicants are ready for permitting processes when they enter them, are the kinds of opportunities that we are working on at the Department of Energy as well.

I'd mentioned earlier our efforts to coordinate federal permitting among the myriad federal agencies that often have a role in permitting of transmission projects, particularly in the west, where there are many federal lands and resources.

We are certainly working on efforts like those you've talked about to enhance coordination between those entities, reduce duplication, and ultimately reduce the timeline that it takes to cite those projects without short circuiting important environmental reviews or the ability of individual federal agencies to make inherently federal decisions that they need to make under authorizing statutes, be it National Environmental Policy act, the Clean Water Act, or other important statutes.

So did want to flag that as something that we are working on and that there may be some opportunity for us to share lessons learned and ideas as we move forward. But I think with that, I will conclude and thank you for the opportunity and to again offer us as a resource.

And also just note that our door is open if you have questions about any of the work we're doing, whether it's on siteing and permitting, which was a big focus of today, or those planning and commercial facilitation efforts that I mentioned. Thank you again for the opportunity.

Thank you again. We'll go on with the next presenter, Christina Hayes.

Good afternoon. Thank you again for hearing from the federal perspective today. Really appreciate that. I want to echo what Mr. Dennis said from the Department of Energy about the need for coordinated siding and permitting.

I was glad to hear that that was such a focus of today's conversation, where there is a federal process and a state process that both need to take place if there's any way to have them operate concurrently so that there aren't these drawn out, subsequent siding and permitting processes that can make projects take a very long time.

And in some cases, it can be detrimental to concluding those projects because there's not always the time and the money to wait for these extended siding and permitting processes that can take upwards of 15 years when they need to take place one at a time. I applaud your work in being proactive. I know that California independent system operator has done a terrific job looking at the needs within California as well as needs within the Western region to complement the energy needs within California.

And so that interregional look is really proactive, especially where the Federal Government hasn't updated its transmission planning rules in a number of years. And so that proactive look that you're able to take is very helpful. And I also encourage you to look at this issue with some urgency.

Building out the transmission grid is very important to bringing on new resources in a way that's cost effective and reliable for meeting, I would say future needs, but frankly, needs that are here today in terms of electrified vehicles, electrified buildings and dealing with the changing resource mix. So I am very grateful that you are addressing transmission today and encourage you to keep doing so.

And I would like to echo Mr. Dennis's comments about feel free to reach out to us as a resource if we can ever be of.

Thank you. Mr. Millar.

Thank you. First off, I'd also like to thank you for the opportunity to speak today. There were a few things I'd just like to put a particular finer point on. While we're not directly involved in some aspects of the permitting process, especially the sequest stage, we have been seeing enthusiasm around modifying our processes so that we would be approving projects even further out than the 10 year need.

And we see that as a poor alternative to being able to count on faster permitting and construction so that that actually isn't necessary. So that's one way to address an outcome. But obviously, if we can make decisions based on the less best available information, where we don't need to reach out beyond the 10 years to actually approve a transmission project, we feel that's actually a better outcome overall.

I also just wanted to mention that we're also working with Mr. Dennis, both with his Grid Deployment Office as well as with the DOE's loan programs office, looking for opportunities to access federal funding. Whether we need the transmission in any event or not, the goal there is to keep the transmission costs down. Mr. Dennis mentioned some of their programs focus on transmission that wouldn't otherwise be developed. But we do see that we need transmission.

But if we can access federal funding to bring the cost down to California consumers, we're exploring those options for where that funding might be available. So I just wanted to make a highlight of that point, and thank you.

Thank you. Mr. Baker.

Yeah. I really appreciate the opportunity to be here today and appreciate the oversight and the inquiry into the PUC's processes and the laws and statutes that guide what we do as we turn to our update of the General Order 131 D process to streamline permitting there.

We know that we're going to hear from parties in our formal process, and further ideas will come up there, and I think that we'll have more thoughts on what would be useful directions based on what we hear from stakeholders in that process. I do want to again emphasize that what we've talked about here today is the smallest part of the pie.

About 15% of the new transmission efforts over the past six years required a PUC permit, and many of the delays and challenges are unrelated to the permit process. I flagged a few of those issues earlier in my comments. We haven't talked very much about that today. We have ongoing processes working with other state agencies to bring attention to those things and do what we can to move those projects along.

But I do think that attention needs to be paid to those other things as well, and we understand that this new investment in transmission and the streamlining permitting processes is needed to reach our climate goals while being mindful of the cost to California ratepayers. Thank you so much.

Thank you very much.

I think a lot about the things that are accelerating. I see the impacts of climate and the risks to our system and the public are accelerating. I see projections of demand accelerating. I see projections of what infrastructure is needed also accelerating, such that whatever we've done in the past is not how we should be doing things in the future.

I also see a lot of opportunity that is once in a generation, the opening of General Order 131 D is a once in a generation opportunity to accelerate our processes. The level of collaboration and the willingness to roll up sleeves and be constructive I think is also different, and I find that to be very encouraging. So I look forward to the next steps on this. SDG and E is certainly willing to support with whatever ideas, creativity and resources we can bring to the table. Yes.

I would just like to thank Chair Garcia and the Committee for the Opportunity to speak today. We commend you on recognizing the importance of transmission in this hearing and urge you to continue your work forward on the reforms necessary to provide clean, reliable and affordable electricity to Californians. And CATF is also very happy to be a resource to you all in any of the matters discussed today. Thank you.

Thank you too to both of you who are kind of non public agencies. We certainly look to you to provide us some additional feedback and input on today's hearing, as well as the proposed acceleration plans that are in front of us through budget trailer bills that the Administration has put forward. We're wanting to be able to take a much more aggressive and I guess, comprehensive approach than what's in front of us as it relates to energy CEQA acceleration.

So we look forward to hearing from you and other stakeholders who may be listening or watching. With that, we will conclude this part of the agenda. Thank you again to those remotely and those here present. We'll open up the public comments now so we'll hear from those who are with us today. Please state your name, affiliation, and just perspective. If you'll limit your comments to a minute or so, we greatly appreciate it.

Afternoon, Mr. Chair. Alex Jackson with the American Clean Power Association. We're a trade group representing renewable energy companies across multiple technologies, but we are united in underscoring the need for more transmission and the need to streamline the current development process. Mr. Millar, I hear your desire for solutions. I think we've fully established the problem statement. It is now time to really focus on how can we do better. I think we're encouraged by the approvals that we've seen from the CAISO and the most recent TPP, the enhanced coordination among the agencies.

But the Legislature does have a role to play on permitting in particular. So I want to highlight three areas that I think emerged as themes from the panel today. One, eliminating or at least reducing the duplicative need inquiry as part of the PUC's review. Two, addressing the no project alternative under CEQA and three, just providing the same pathway for transmission projects under AB 205 as clean energy projects. Thank you.

Thank you. Anyone else?

Mr. Chair and Members, John White with a Clean Power Campaign. First of all, I want to thank the Chairman and the Committee staff for an excellent hearing. It's really timely. There's a really urgent problem in particular. I think the thing you have to get in mind is if we approve transmission projects and build them at the rate we've been building them, there's no transition to clean energy without transmission.

And the scale of the buildout, as was referenced by the witness from San Diego Gas Electric, is beyond anything we've ever done before. And our process doesn't lend itself to looking at multiple projects at the same time. Right now, we know six or seven lines that we absolutely need to build and that are urgent. We don't need to take two years studying whether we need them or not. Again. Okay? So I think the other thing is we need to have a sense of managing these projects.

As I said, it's usually done case by case, but right now, you don't have a dashboard where you can go and say, where are we on these projects? What's their status? What's the completion date? Where are we on interconnections? What's going on? Where's the utility performance in building out the projects? Why are they late? What's the estimate?

And so manage this whole portfolio of transmission, and not just one at a time, exhaustive review, as if it's because the other thing about cost is that even though there's multiple billions of dollars that it's going to cost us to build all this transmission, it's going to save us money, particularly if we do it right with joint projects with the municipal utilities, the gentlemen from the Federal Government. There's federal funding that we should be seeking to apply.

And on another occasion, we need to have a conversation about PG E, because PG E is at the moment broken and not performing its job on a range of these issues. And there's a need for some oversight just on that. Thank you.

Thank you.

Thank you. Melissa Cortez, on behalf of the California Wind Energy Association, I want to thank you for this very thoughtful hearing and for the background paper that was put together. There were a lot of issues outlined both by the panelists and in the background paper. Revisiting our, or revising our current transmission planning process is critical for California to meet the clean energy goals that we've set.

We want to urge this Committee to focus on the added one to three years that it takes for the PUC to determine whether transmission upgrades already approved by CAISO is needed. Eliminating this duplication would significantly reduce the timeline to get transmission built. It's an issue you've heard a lot about today. We've spoken actually at length with Committee staff about this issue, and we hope to see it addressed this legislative year. Thank you.

Patrick Welch, California Municipal Utilities Association we support achieving the state's goals and our members' complementary, local goals as well. And transmission is certainly important to that. Just wanted to bring one thing to the conversation and emphasize something a little bit more, and that's the impact to consumers. While certainly we need to build out more transmission to deliver more resources, the transmission rates in California are the highest in the nation in 2011. The transmission access rate, which is just the high voltage part.

So a lot of what's been talked about today is high voltage, but there's also a low voltage portion as well. So when you make changes to the high voltage system, you often have to make corresponding changes to low voltage. The transmission access charge in Northern California was around $11.70 in 2011. It's now by 2022. So last year was $34.10.

By 2030, we estimate that an average Northern California customer could be paying $37 as part of their Bill and $54 just for transmission in 2040. In the Central Valley, where the higher usage customers could be paying $90 a month just for transmission services, up from around $45 today. So it's important in our perspective that as we build out this transmission, we're not just looking at the high voltage, we're looking at the Low voltage.

We're looking at the self approved project, making process improvements where we need to, to bring projects along faster and save costs, but also being really conscious and aware of those consumer impacts, because that cost is growing and will continue to grow, and customers will ultimately pay for that. Thank you.

Thank you very much, Mr. Chairman. My name is Dan Jacobson with Environment California.

I'll keep my comments really brief just to say I'm really excited to see this Committee doing this work, as we've set goals over the past number of years to get to 20%, 33%, now 100% clean energy. We've also needed to upgrade the transmission process, and that hasn't happened. And we really can't let the bureaucracy slow down our fight on climate change.

And we have so many opportunities to really bring on new clean energy projects, whether it's geothermal, whether it's offshore wind, whether it's solar in the Central Valley. But transmission is the key to doing all of those pieces.

And we've got to make sure that as we tackle that we can really do it affordably, so that we don't hurt the ratepayer, but that we can do it in a timely manner so that we don't continue to suffer through the worst impacts of climate change, and that we build a more resilient grid as we go forward. Thank you very much.

Thank you. See no one else in line. Just want to thank all the panelists that were with us today and colleagues that attended, will adjourn this meeting. Thank you.