I NTRODUCTION
This report presents Jones & Madhavan’s assessment and recommendations for renovation of the pool mechanical equipment. The purpose of the analysis is to assess the feasibility of renovating the aging equipment to increase useful li fe, ensure current code compliance, and address the City of Buena Park’s (City) operation and maintenance issues.
The aquatic facility was originally constructed in 1960 and includes a 50- meter swimming pool and bathhouse building with mechanical equipment rooms. The facility has been renovated several times including a chemical/storage room addition in 1978 and mechanical equipment and piping replacement in 2000.
Information for this analysis was gathered from o n-site examination of the faci lity on March 19, 2025. City Staff provided information regar ding equipment operation, maintenance, and repair history. As-built construction and renovation drawings were also reviewed.
The primary components of the aquatic facility include:
Swimming Pool – The pool is 164 feet long by 65 feet wide with depths ranging from
3.5 feet at each end to 12 feet in the center. The pool volume is 447,000 gallons and mechanical equipment is sized for a 6- hour turnover rate of 1,250 gallons per minute.
Peak Park Pool Equipment
Feasibility Study
April 10, 2025
The pool was renovated in 2024 to replace the plaster finish and concrete deck.
Equipment Room – T he mechanical equi pment room is located at the west end of the buil ding with the chemical/storage room adjacent on the south . The surge chamber, pump pit, and backwash pit are inside the room. Equipment includes a 25 hp vertically mounted circulation pump with a variable frequency drive (VFD), high- rate sand filter system with three horizontal tanks and 81 square foot filter area, two 1,530,000 BTU natural gas heaters, chemical controller, chemical feed pumps, and liquid chlorine and acid storage tanks.
Peak Park Pool Equipment
Feasibility Study
April 10, 2025
ANALYSIS
Pool mechanical system components were analyzed to establish their existing condition, estimate remaining useful life, and evaluate with respect to the f acility’s long-term operation.
Applicable California B uilding and H ealth Codes relating swimmi ng pool design standards and chemical storage requirements were also reviewed.
City operation and maintenance concerns include lack of adequate space for access to the pump and heaters in the cr owded equipment room, access and safety issues related to chemical delivery t o tanks through th e storage room, and increased maintenance requirements for aging equipment, electrical controls, piping and valves. The City would like to incorporate a dual circulation pump system to eliminate pool closure pr oblems that have occurred with pump breakdowns.
FILTER SYSTEM
Condition The Stark SS3-96 high-rate sand filter system is 25 years old and at the end of its useful life. Some diaphragm valves have been rep laced and sand media was recently replaced after sand leaked into the pool through cracked gaskets on the internal piping. Th e influent pressure gauge is malfunctioning, the automatic backwash controller is not used and the procedure is manually controlled.
Options 1. R eplace filters with a four tank 80 square foot high-rate sand system, which will in crease available space beh ind the tanks by 24 inches .
The filter effluent piping should be routed around the pump pit to allow for overhead maintenance access.
Cost: Sand Filter System $176,000
Plumbing and Valves 19,000
Construction Total $195,000
Owners Contingency - 10% 19,500
Soft Cost - 25% (A&E, PC, T&I) 48,750
Budget Estimate $263,250
2. Replace filters with a reg enerative media single t ank filter system.
This option has the smallest footpri nt and will free up addit ional Peak Park Pool Equipment
Feasibility Study
April 10, 2025
space in the room. These filters use perlite media and provide finer filtration down to 1 micron, compared to 10- 15 microns for sand, improving water quality . The filter will also s ave water and only use 10% of that required for backwashing sand filters.
Cost: Regenerative Media Filter $2 22,500
Plumbing and Valves 32,500
Construction Total $255,000
Owners Contingency - 10% 25,5 00
Soft Cost - 25% (A&E, PC, T&I) 63 ,750
Budget Estimate $344,250
CIRCULATION SYSTEM
Condition The c irculation pump has been serviced and m aintained in working order since original installation. The filter effluent and backwash piping run above the pump making i t difficult to remove for ser vice. The pump’s VFD is intended to control the pump speed an maint ain the required 1,250 gpm flow rate for energy savings, however the VFD has not been used in this capacity for several years.
Options 1. To achieve the City’s objective for a dual pump system, the pump pit should be en larged and two 25 hp horizontally mounted pumps installed with necessary valves for isolation. Horizontal pumps are easier to service in place than vertical pumps. Also, plastic pumps designed for the commercial poo l market are available and less susceptible to chemical corrosion. The VFD and flow sensor would be rep laced and programmed to operate with the new equipment.
Peak Park Pool Equipment
Feasibility Study
April 10, 2025
With a proper pump and o verhead piping layout, a davit crane can be install ed adjacent to the p it to ea se pump installation and removal. New ladders and gu ardrails woul d be installed with removable sections at the crane.
Cost: Pump Pit Modifications $ 31,000
P umps and Strainer 46,000
Piping and Valves 34,000
Variable Frequency Drive 30,000
Davit Crane 6,000
Construction Total $147,000
Owners Contingency - 10% 14,700
Soft Cost - 25% (A&E, PC, T&I) 36,750
Budget Estimate $198,450
2. Same as Option 1 with alt ernate pit layout which provides additional space at floor level for pump removal.
HEATING SYSTEM
Condition The Raypak 1532B heaters appear to be about 10 years old a nd in reasonable condition. The heaters are hor izontal style with 85% ef ficiency and don’t have the m anufacturer’s minimum recommended 24 inch service clearance at each e nd. Some of Raypak ’s latest heaters are ver tical s tyle with smaller footprints that will provide better service clearances.
Peak Park Pool Equipment
Feasibility Study
April 10, 2025
Options 1. R eplace the heaters with 97% efficiency vertical heaters and install with the required manufact urer’s clearances. This type heater will reduce natural gas costs.
Cost: Heaters and Vents $183,000
Plumbing and Valves 10,000
Construction Total $193,000
Owners Contingency - 10% 19,300
Soft Cost - 25% (A&E, PC, T&I) 48,250
Budget Estimate $260,550
2. R eplace the heaters with 96% efficiency vertical indirect heaters and install with the required manufact urer’s clearances. This type heater includes a secondary heat exchanger, so the chemically treated pool water never enters the heater. Thi s will extend heater life and eliminate the common problem of heat exchanger corrosion.
Fiberglass grating would be installed at the backwash pit and end of the pump pit to provide the required service clearance.
Cost: Heaters and Vents $296,000
Plumbing and Valves 18,000
Grating 7,000
Construction Total $321,000
Owners Contingency - 10% 32,1 00
Soft Cost - 25% (A&E, PC, T&I) 80, 250
Budget Estimate $433,350
3. A third option if cost is the priority, would be to r eplace the heaters with 83% efficiency vertical heaters which have the smallest footprint.
Cost: Heaters and Vents $138,000
Plumbing and Valves 7,000
Construction Total $145,000
Owners Contingency - 10% 14,5 00
Soft Cost - 25% (A&E, PC, T&I) 36, 250
Budget Estimate $195,750
Peak Park Pool Equipment
Feasibility Study
April 10, 2025
CHEMICAL SYSTEM
Condition The Chemtrol PC3000 chemical controller appears to be less th an 10 years old and in good condition. Chemical tank location inside the storage ro om causes access issue s for delivery and ex poses stor ed items to corrosion.
Chemical feed pumps ar e a combination of var ious aged di aphragm a nd peristaltic pumps, with two pumps behind each tank making access difficul t.
The tanks and pumps could be reused, but because of the ir various ages and exposure to corrosion, the best long-term solution is replacement.
Options 1. Re use existing chemical controller , and replace feed pumps and storage tanks. Separate acid and chlorine rooms would be constructed with doors to the exterior. Separate rooms will reduce the storage room ar ea by 20 square feet, but will also free up space since clearances won’t be needed to access the tanks. A single properly sized feed pump at each tank would reduce cost a nd maintenance. The emergency eyewash and shower would be relocated from the equipment room.
Cost: C hemical Pumps $4,000
S torage Tanks 24,000
Piping and Valves 6,000
Construction Total $34,000
O wners Contingency - 10% 3,4 00
Soft Cost - 25% (A&E, PC, T&I) 8, 500
Budget Estimate $45,900
(Building construction costs are included in Architect’s estimate) Peak Park Pool Equipment
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April 10, 2025
2. Same as Option 1 and includes replacing the chemical controller to provide all new equipment for the mechanical system a nd ensure the longest useful life. A new controller could in corporate the latest technology like wireless remote monitoring.
Cost: Chemical Controller $24,000
Chemical Pumps $4,000
S torage Tanks 24,000
Piping and Valves 6,000
Construction Total $58,000
O wners Contingency - 10% 5,8 00
Soft Cost - 25% (A&E, PC, T&I) 14,500
Budget Estimate $78,300
(Building construction costs are included in Architect’s estimate)
Peak Park Pool Equipment
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April 10, 2025
BUDGET SUMMARY
POOL EQUIPMENT – OPTION 1
1. Filtration System $195,000
2. Circulation System $147,000
3. Heating System $193,000
4. Chemical System $34,000
Construction Total $569,000
Owners Contingency - 10% 56,900
Soft Cost - 25% (A&E, PC, T&I) 142,250
Budget Estimate $768,150
POOL EQUIPMENT – OPTION 2
1. Filtration System $255,000
2. Circulation System $147,000
3. Heating System $321,000
4. Chemical System $58,000
Construction Total $781,000
Owners Contingency - 10% 78,100
Soft Cost - 25% (A&E, PC, T&I) 195,250
Budget Estimate $1,054,350
HEATERS – OPTION 3
1. Heating System $145,000
Construction Total $145,000
Owners Contingency - 10% 14,500
Soft Cost - 25% (A&E, PC, T&I) 36,250
Budget Estimate $195,750
U sing this heater with Option 1 will reduce the Construction Cost by $48,000 and by $176,000 if used with Option 2.
Peak Park Pool Equipment
Feasibility Study
April 10, 2025
R ECOMMENDATIONS
If recommendations identified in the previous sections are addressed, th e new pool mechanical system will address the City ’s o perational issues, comply with c urrent code requirements, and have an increased lifespan. Each of the proposed equipment options is a viable choice with slightly different maintenance and operation requirements.
Equipment room plans and c ut sheets for possible equipment options are included in t he Appendix for reference.
Peak Park Pool Equipment
Feasibility Study
April 10, 2025
APPENDIX
66 FILTERS - COMMERCIAL
HORIZONAL SAND FILTRATION SYSTEMS
Ordering Information
STARK™ SS SERIES FILTERS
The S tark S S S eries F ilter S ystems a re d esigned w ith e ase o f ins
tallation, m
aintenance, an
d m
inimal fl
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pace in m
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essels
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w
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m
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a
ccess
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t
he
e
nds
a
nd
a
ll
p
iping
a
bove
t
he
v
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ll
p
iping
s
hips
f
ully
s
olvent-welded
a
nd
p
re-
assembled
to
ensure
fit.
100
psi
vessel
pressure
rating.
• All vessel models are NSF 50 certified from
5 -20
gpm/sq.ft
•
End-manways
provide
easy
access
for
service and maintenance
•
Schedule
80 Face
Piping
is
fully
assembled
in our factory for ease of installation
•
Stark
valves
and
several
control
options
make backwashing simple
•
Unparalleled
tank
construction
and
exterior
a
ll-weather c
oating
Featured Highlights
System Tank
Filtra/g415on
Area
Flow
(GPM)
Flow
(GPM)
Backwash
Valve
Total
Media
Opera/g415ng
Weight
Shipping
Weight
Number Size (Sq. Ft.) 12 gpm/sf 15 gpm/sf Size/Type 'W' 'L' 'Hs' (cu /g332) (lbs.) (lbs.) RS1-60-04 36" x 60" 13. 5 162 203 4" 38" 63"6 8" 15.5 4,600 845 RS1-72-04 36" x 72" 17. 2 206 258 4" 38" 75"6 8" 19.0 5,500 915 SS1-48-04 42" x 48" 12. 8 154 192 4" 44" 51"7 4" 16.5 4,900 805 SS1-72-06 42" x 72" 20. 0 240 300 6" 44" 75"8 6" 26.0 7,500 1,105 SS1-96-06 42" x 96" 27. 0 324 405 6" 44" 99"8 6" 36.0 9,800 1,240 RS2-60-06 36" x 60" 27. 0 324 405 4" 77" 63"7 0" 31.0 9,400 1,650 RS2-72-06 36" x 72" 34. 4 413 516 4" 77" 75"7 0" 38.0 11,000 1,830 SS2-48-06 42" x 48" 25. 6 307 384 4" 90" 51"7 6" 33.0 10,000 1,650 SS2-72-06 42" x 72" 40. 0 480 600 6" 90" 75"8 7" 52.0 14,800 2,060 SS2-96-06 42" x 96" 54. 0 648 810 6" 90" 99"8 7" 72.0 19,400 2,380 RS3-60-06 36" x 60" 40. 5 486 608 4" 116"6 3" 70"4 6.51 4,200 2,420 RS3-72-06 36" x 72" 51. 6 619 774 4" 116"7 5" 70"5 7.01 6,800 2,670 SS3-48-06 42" x 48" 38. 4 648 576 4" 136"5 1" 76"4 9.51 4,900 2,420 SS3-72-08 42" x 72" 60. 0 720 900 6" 136 "7 5" 88"7 8.02 2,400 3,140 SS3-96-08 42" x 96" 81. 0 972 1215 6" 136"9 9" 88"1 08.02 9,400 3,620 RS4-60-06 36" x 60" 54. 0 648 810 4" 155"6 3" 70"6 2.01 8,900 3,200 RS4-72-08 36" x 72" 68. 8 826 1032 4" 155"7 5" 76"7 6.02 2,300 3,560 SS4-48-06 42" x 48" 51. 2 614 768 4" 182"5 1" 76"6 6.01 9,900 3,200 SS4-72-08 42" x 72" 80. 0 960 1200 6" 182"7 5" 88"1 04.03 0,200 4,470 SS4-96-10 42" x 96" 108. 0 1296 1620 6" 182"9 9" 88"1 44.03 9,900 5,145 SS5-72-10 42" x 72" 100. 0 1200 1500 6" 229"7 5" 88"1 30.03 8,400 5,650 SS5-96-10 42" x 96" 135. 0 1620 2025 6" 229"9 9" 88"1 80.04 9,900 6,450 SS6-72-10 42" x 72" 120. 0 1440 1800 6" 275"7 5" 88"1 56.04 6,000 6,800 SS6-96-12 42" x 96" 162. 0 1944 2430 6" 275"9 9" 97"2 16.06 0,800 7,900
CAPACITY INFORMATION
# Tanks
5 6
3 2
1 4
WARNING: Cancer and Reproductive Harm.
P/N 200174.Awww.p65warnings.ca.gov.
ADVERTENCIA: Cáncer y Daño Reproductivo.
CALIFORNIA PROPOSITION 65 WARNING
AVERTISSEMENT: Peut Causer le Cancer
et des Dommages au Système Reproducteur.
SEE PAGE 329 FOR REPLACEMENT PARTS
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Options 1 & 2
PORTABLE DAVIT CRANE
COMMANDER®
1000
thern .co
Made in USA
m
(507) 454-2996
Options 1 & 2
HYBRID
DESIGN
MAXIMUM
EFFICIENCY
XTHERM
®
POOL HEATER
VERSA IC
®
WITH
RAYMOTE
™
Option 1
Time honored technology unites with cutting edge
advancement.
The XTherm combines the proven capability of a finned cupronickel tube heat exchanger with a stainless steel condensing heat exchanger to maximize thermal efficiency (97-97.7%) and provide long-term reliability.
Raypak’s XTherm is built with commercial-grade components and materials. From our steel channel base to our stainless steel flue wrapper and condensing heat exchanger, you can tell the XTherm is built to last. It’s easy to handle and install, but still user-friendly to service.
Cold Water Run
System
316L stainless steel
condensing heat
exchanger
Vertical non-condensing
heat exchanger
CPVC water
manifolds
7 “ touchscreen
display
Low voltage
wiring terminal
ENGINEERED TO PERFORM.
PROFESSIONAL INDIRECT
™
POOL HEATER POWERED BY XTHERM
®
VERSA IC
®
WITH
RAYMOTE
™
CORROSION
RESISTANT
TIME/LABOR
SAVINGS
96% THERMAL
EFFICIENCY
Option 2
Pre-plumbed boiler loop
w/ system pump and
expansion tank
Reversible PVC venting
PVC vent connection is factory standard. PVC
venting can save thousands in venting costs,
and is easier to handle and install.
The Most Durable Pool Heater Available
The Professional Indirect Pool Heater, utilizes Raypak’s ultra-high-efficiency XTherm boiler which drives a highly efficient indirect heat exchanger. The Professional Indirect is corrosion resistant and comes as a factory built skid system, so no set-up is required. It is easy to install and commission. The Professional Indirect provides high-efficiency heating with minimal maintenance, perfect for heavy commercial usage, such as competition pools.
Cupronickel or
titanium indirect heat
exchanger
Condensate
treatment kit
ENGINEERED TO PERFORM.
VENTING
VERSATILITY
COMPACT
DESIGN
MVB
®
POOL HEATER
VERSA IC
®
WITH
RAYMOTE
™
Option 3
Modulating vertical pool heater with venting
flexibility.
The MVB pool heater provides installation flexibility, ease-of-commissioning, reliability and long-term performance. The vertical design allows for the MVB’s small footprint, making it the perfect solution for small spaces and retrofit projects. Cupronickel, finned water tube heat exchanger construction allows for easy maintenance and serviceability.
Vertical non-condensing
multi-pass heat
exchanger
Combustion air
blower (not shown) Gas valve
MERV 8 combustion
air filter (not shown)
Vent pressure switch
Water connections
Combustion air
connection
Power supply
connection
Gas connection
Pressure relief valve
(PRV)
Vent connection
7” color touchscreen
display
Low voltage
wiring terminal
(not shown)
Status light and
on/off switch
ENGINEERED TO PERFORM.
Architecture Buena Park Peak Park Pool Building P age 32
APPENDIX B
Architecture Buena Park Peak Park Pool Building P age 33
COST OPTION #1
Architecture Buena Park Peak Park Pool Building P age 34
Architecture Buena Park Peak Park Pool Building P age 35
COST OPTION #2
Architecture Buena Park Peak Park Pool Building P age 36
Architecture Buena Park Peak Park Pool Building P age 37
Architecture Buena Park Peak Park Pool Building P age 38
Architecture Buena Park Peak Park Pool Building P age 39
Architecture Buena Park Peak Park Pool Building P age 40
COST OPTION #3
Architecture Buena Park Peak Park Pool Building P age 41
August 12, 2025
STUDY SESSION
Item No. 9C.
City Council Agenda Report
DISCUSS AND PROVIDE DIRECTION ON AN AGREEMENT WITH CENTRALIA ELEMENTARY SCHOOLDISTRICT FOR AN AFTER-SCHOOL EXPANDED LEARNING OPPORTUNITIES PROGRAM (ELO-P)
PREPARED BY PRESENTED BY
Dale Kurata, Community Services Supervisor Dale Kurata, Community Services Supervisor
DEPARTMENT HEAD APPROVAL CITY MANAGER APPROVAL
Jim Box, Director of Community Services Aaron France, City Manager
DISCUSSION
The City of Buena Park is proposing a partnership with the Centralia Elementary School District ("District") for an Expanded Learning After School Program. The District's Expanded Learning Division provides a diverse range ofenrichment opportunities for students in Transitional Kindergarten (TK) through 6th grade. Their programs includeChild Care, After School Education and Safety (ASES), and the Expanded Learning Opportunities Program (ELO-P). Students can engage in a variety of activities such as arts and crafts, coding, reading comprehension,assemblies, rallies, and various clubs, all designed to foster creativity, critical thinking, and social development.
The District is the lead agency in the on-site program. The City could be a part of the overall program and provide avaried recreation program comprised of sports, a food program, and a dance & cheer program conducted bothindoors and outdoors.
The District would coordinate registration and provide District chaperones to lead youth to the City programs. Youthwill be divided into two (2) groups of twenty (20) and attend the City program for one (1) hour each. Groups could be divided into grades TK-3 and 4-6. Potential City programs could include the following scheduled days andlocations from 3:00-5:00 p.m.:
Elementary School Sports* Food Program Dance & Cheer
Raymond Temple Monday/Wednesday Tuesday Thursday
Dysinger Monday/Wednesday Tuesday Thursday
Buena Terra Tuesday/Thursday Friday Monday
San Marino Tuesday/Thursday Friday Monday
*Sports games between schools could be scheduled on a rotating school site. Games could be scheduled on twoFridays during each of the three (3), ten (10) week sessions. The District would provide the necessary bustransportation for youth.
Under the proposed program, the City would provide a Community Services Coordinator full-time staff hours toplan and oversee the programs.
The City would provide the following part-time staff for direct supervision for each program: one (1) SeniorCommunity Services Leader to lead activities and at least two (2) Community Service Leader I's, as necessary tomaintain a 10:1 leader to child ratio to assist with operating the program.
BUDGET IMPACT
With this proposal, the District will reimburse the City for all costs incurred associated with the program.
Full-time salaries/benefits $51,410
Part-time salaries/benefits $83,670
Recreation Supplies $18,000
Total $153,080
August 12, 2025
STUDY SESSION
Item No. 9D.
City Council Agenda Report
DISCUSS AND PROVIDE DIRECTION REGARDING SUPPORT FOR AB 825 (PETRIE-NORRIS)
PREPARED BY PRESENTED BY
Jessica Fewer, Senior Management AnalystJessica Fewer, Senior Management Analyst
DEPARTMENT HEAD APPROVAL CITY MANAGER APPROVAL
Eddie Fenton, Assistant City Manager/HR Director Aaron France, City Manager
DISCUSSION
This item was brought forward by Council Member Sonne and is being added as an urgency item due to a deadline in the advocacy process. Staff has reached out to the City's public affairs consultant, Townsend Public Affairs (TPA), to provide a overview of the legislation. Below is a summary of AB 825 from TPA:
AB 825 (Petrie-Norris) proposes a range of policies affecting electrical corporations, with the author’s stated goal being to address rising utility bills. The bill passed the Assembly on the third reading with 59 Democrats voting yes and all Republicans and a few Democrats voting no or abstaining. AB 825 was double referred to the Senate Energy, Utilities, and Communications Committee and the Business, Professions and Economic Development Committee. It does not currently have a hearing date set.
Below are a list of a few of the policies that AB 825 proposes:
1. Prohibits IOUs from including in their equity base rate their share of the first $15 billion expended in aggregate on undergrounding projects
2. Creates the Public Transmission Financing Fund within the State Treasury to finance critical transmission projects while helping to reduce costs that would otherwise be passed on to ratepayers
3. Provides an incentive program, the Permitting Local Assistance for Clean Energy (PLACE) which would:
1. Require the CEC to establish a state central pool of clean energy project siting experts that local permitting agencies can use for no cost.
2. Create a match fund to supplement the cost a developer pays to the agency so the developer is encouraged to apply through local channels.
3. Create a monetary incentive to the local permitting agency for every 100 megawatts permitted through the program.
4. Broadens the authority of the California Infrastructure and Economic Development Bank (I-Bank) to support public financing for eligible transmission projects.
CalCities currently lists a "watch" position for this bill. However, staff believes this legislation aligns with the goals in the City's draft Climate Action and Adaptation Plan (CAAP) as the draft CAAP sets goals that include citywide electrification, which are limited by the affordability of electricity. Environmental groups appear to be in support of this bill due to its focus on increasing transparency, accountability, and ratepayer protections in California's energy system. In contrast, opponents feel the bill will have a potential impact on their profits, particularly regarding public financing of grid infrastructures and limitations on their ability to include certain capital investment in their rate base. Other concerns include increased regulation, the cost of electrification, and local permitting processes for clean energy projects.
Attached is the official bill language.
Attachments
AB-825-Petrie-Norris.pdf
AB 825
Date of Hearing: June 3, 2025
ASSEMBLY COMMITTEE ON UTILITIES AND ENERGY
Cottie Petrie-Norris, Chair
AB 825 (Petrie-Norris) – As Amended June 2, 2025
SUBJECT: Energy: electricity
SUMMARY: Proposes a range of policies affecting electrical corporations, specifically measures to address rising utility bills, including a prohibition on allowing electrical corporations to include $15 billion in undergrounding capital investments in their rate base for purposes of earning equity returns; establishing a public financing mechanism to reduce costs associated with the development of eligible transmission projects; establishing a task force to review various customer demand side management programs; creating a local permitting program to provide incentives and a pool of experts to aide local agencies in siting clean energy projects; and revising wildfire mitigation planning.
Specifically, this bill:
1) Relevant to underground infrastructure coordination:
a. Requires the California Underground Facilities Safe Excavation Board (“Underground Safety Board”) to set standard timelines and procedures, by December 31, 2026, for how excavators share planning and design information of electrical undergrounding projects with operators of subsurface infrastructure in the area to be dug.
b. Requires the regional notification centers to facilitate the information exchange between the excavators and operators.
c. Specifies the notifications are required if the excavator is submitting a volume of concurrent notifications in excess of the capacity of the operators in the area to complete their responsibilities to locate and mark their subsurface infrastructure within the minimum legal excavation start date and time. d. Prohibits the Underground Safety Board from adopting regulations that restrict the ability of the excavators to submit notifications, including emergency notifications, under standard timelines.
e. Requires regional notification centers to notify California Native American tribes, upon request, of proposed excavations related to electrical undergrounding projects within the geographic area with which the tribe is traditionally and culturally affiliated.
f. Requires the Underground Safety Board to report to the Legislature on developing a website for facilitating these communication efforts. 2) Relevant to public financing for transmission projects:
a. Creates the Public Transmission Financing Fund, and directs the California Infrastructure and Economic Development Bank (I-Bank) to administer the Public AB 825
Transmission Financing Program to use monies in the fund to provide financial assistance for eligible transmission projects.
b. Defines “eligible transmission project” for the purposes of public financing as a:
i. “competitive transmission project” – a new transmission line located, at least in part in the state and identified by the California Independent System Operator (CAISO) in its transmission planning process as a project subject to competitive bidding;
ii. “merchant transmission project” – a transmission project where the costs are not eligible for recovery through the CAISO transmission access charge; or
iii. “utility transmission project” – a transmission project where an electrical corporation (IOU) or local publicly owned electric utility (POU) has the primary responsibility for construction and ownership.
c. Requires eligible entities – called “participating parties” in this measure – to either apply for financing from I-Bank in conjunction with a governmental sponsor or be itself a public owner of any portion of a new transmission project – called “public transmission sponsors” in this measure. Public transmission sponsors may include state agencies (including the Department of Water Resources), the California Consumer Power and Conservation Financing Authority (CPA), local public agencies, tribal organizations, or joint powers authorities. Additionally, reauthorizes the CPA, removes its $5 billion bond limit, and removes restrictions on approving new programs after 2007. d. Authorizes I-Bank to provide financial assistance under the Program to any public transmission sponsor or participating party so long as the project is owned or financed, in whole or in part, by a public transmission sponsor. e. Prohibits I-Bank from financing an eligible transmission project unless the IOU or POU has selected their employees for the construction of the project; the public transmission sponsor has selected only a prime contractor who has served as such for at least two transmission projects in the state during the prior 10 years; or the IOU, POU, or public transmission sponsor has only selected a contractor who has frequently performed electrical transmission infrastructure maintenance work for an IOU during the prior 10 years. Additionally prohibits the I-Bank from financing any project unless it complies with the California Public Utilities Commission’s (CPUC) General Order 95.
f. Requires public transmission sponsors that participate in the Program to participate in the Wildfire Fund, as specified, and submit wildfire mitigation plans to the Office of Energy Infrastructure Safety.
g. Requires IOUs, as part of the CPUC evaluation of the necessity for a proposed transmission project, to identify any public transmission sponsors that can provide public financing and assume a minority ownership interest in the project; and evaluate the ratepayer savings from the partnership with a public transmission AB 825
sponsor. The ratepayer savings calculation shall be standardized in a CPUC proceeding.
h. Requires the CPUC to direct an IOU to partner with a public transmission partner to finance a proposed transmission project if the sponsor is available and the ratepayer savings is material.
3) Relevant to local permitting support for clean energy:
a. Establishes the Permitting Local Assistance for Clean Energy (PLACE) Program at the California Energy Commission (CEC), to include a central pool of subject matter experts on project siting and permitting available to local permitting authorities upon request; matching funds available to local permitting authorities that participate in the PLACE program to supplement the permitting costs that would otherwise be paid entirely by the project applicant; and awards to local permitting authorities for each 100 megawatts generated by participating projects that meet permitting timelines established by the CEC.
b. Establishes the PLACE Fund in the State Treasury to support the Program, upon appropriation. Specifies that monies made available as part of the Clean Energy Reliability Investment Plan – pursuant to SB 846 (Dodd, Chapter 239, Statutes of 2022) – may be deposited into the fund.
4) Relevant to statewide demand side management program review:
a. Establishes a statewide demand side management (DSM) task force within the CEC made up of seven members, one each from the CEC, CPUC, the Department of Community Services and Development, the California Air Resources Board, the California Alternative Energy and Advanced Transportation Financing Authority, and ex-officio members from the Assembly and Senate.
b. Requires the task force to meet monthly, starting no later than January 31, 2026, to identify all energy efficiency and demand response programs deployed throughout the state (including IOU and POU programs); evaluate each program, as specified; identify whether each program individually advances specified goals or metrics, or duplicates other programs; establish simple rules for DSM project investment; recommend by July 31, 2026, consolidation or closure of programs that do not meet specified goals or metrics; consult with various entities in developing their recommendations; and submit a report to the Legislature by December 31, 2027 on its findings and recommendations.
c. Requires agencies or program administrators to consolidate or close programs recommended by the task force by January 1, 2027, after a period of public comment and appeal.
d. Declares the provisions of the bill place no limitation on the authority of POUs or community choice aggregators to set rates and establish programs.
e. Requires the CPUC to implement the recommendations of the task force when determining the availability of cost-effective, reliable, and feasible DSM resources for the purposes of IOU resource procurement.
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5) Relevant to IOU financing for undergrounding projects:
a. Authorizes electric IOUs to finance undergrounding costs through a fixed charge on customers' electric utility bills, also known as “securitization;” and sunsets this authorization in ten years.
b. Prohibits IOUs from including in their equity rate base their share of the first $15 billion expended in aggregate on undergrounding projects.
6) Relevant to IOU wildfire mitigation plans (WMPs):
a. Requires actions related to wildfire mitigation by IOUs to take into account the time required to implement proposed mitigations and the amount of risk reduced for the cost and risk remaining.
b. Requires each IOU to submit a WMP to the Office of Energy Infrastructure Safety (Energy Safety) for review at least once every four years (instead of every three years).
c. Requires IOUs, by January 1, 2026, to submit preliminary WMPs to Energy Safety at the earliest date of one year before its GRC filing or concurrent with its Risk Assessment Mitigation Phase application filing.
d. Requires IOUs to include, as part of a list that identifies and prioritizes all wildfire risk in the WMP, particular risks associated with the speed with which mitigation measures can be deployed, and a value of cost-per avoided ignition for each risk. e. Repeals various references to the Wildfire Safety Division.
EXISTING LAW:
1) Establishes and vests the California Public Utilities Commission (CPUC) with regulatory authority over public utilities, including electric IOUs. Authorizes the CPUC to fix the rates and charges for every public utility and requires that those rates and charges be just and reasonable. (Article XII of the California Constitution and Public Utilities Code § 451)
2) Authorizes the CPUC to supervise and regulate every public utility in the state and do all things, whether specifically designated in this part or in addition thereto, which are necessary and convenient in the exercise of such power and jurisdiction. (Public Utilities Code § 701)
3) Establishes the CEC, and requires the CEC to assess trends in energy consumption and analyze the social, economic, and environmental consequences of trends. (Public Resources Code § 25200 et seq.)
4) Establishes Energy Safety within the Natural Resources Agency which, as of July 1, 2021, subsumed the Wildfire Safety Division (WSD) responsibilities at the CPUC, including to review the WMPs of IOUs. (Government Code §§ 15740 et seq. and 15475.6, Public Utilities Code §§ 326 and 8385)
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5) Establishes the Underground Safety Board within Energy Safety to coordinate education and outreach activities that encourage safe excavation practices, along with developing standards and investigating violations, as specified. (Government Code § 4216.12) 6) Authorizes the California Consumer Power and Conservation Financing Authority (CPA) to establish, finance, purchase, lease, own, operate, or construct generating facilities and other energy-related projects to supplement California's power supply. (Public Utilities Code § 3310)
7) Establishes the California Independent System Operator as a nonprofit, public benefit corporation to manage the transmission grid and related energy markets, as provided. (Public Utilities Code § 345 et seq.)
8) Establishes the policy (100% Clean Energy Policy, or SB 100 Policy) of the state that eligible renewable energy resources and zero-carbon resources supply 90% of all retail sales of electricity to California end-use customers by December 31, 2035, 95% of all retail sales of electricity to California end-use customers by December 31, 2040, 100% of all retail sales of electricity to California end-use customers by December 31, 2045, and 100% of electricity procured to serve all state agencies by December 31, 2035. (Public Utilities Code § 454.53)
9) Permits the California Public Utilities Commission (CPUC) to allow for the recovery of costs and expenses arising from a covered wildfire occurring after January 1, 2019, if the CPUC finds the costs and expenses just and reasonable. Establishes a standard of reasonable conduct of an IOU, for purposes of cost recovery, based on whether a reasonable utility would have undertaken the action in good faith under similar circumstances. Specifies the IOU bears the burden to demonstrate that its conduct was reasonable, unless it has a valid safety certificate; at which point, the IOU’s conduct is deemed reasonable unless a third party creates serious doubt as to the reasonableness of the IOU’s conduct. (Public Utilities Code § 451.1)
10) Authorizes an IOU to request the CPUC issue a financing order to authorize the recovery, through securitization, of costs and expenses related to a catastrophic wildfire (with an ignition date in 2017 or after January 1, 2019) or undercollection amounts accrued in 2020. (Public Utilities Code § 850)
11) Authorizes an IOU to request securitization to finance its share of the first $5 billion of approved wildfire mitigation capital expenditures and the debt financing costs of those expenditures. Prohibits the CPUC from allowing the large IOUs to earn a return on equity on the mandated fire risk mitigation capital expenditures. (Public Utilities Code § 8386.3) 12) Requires the CPUC to create an expedited program for undergrounding utility distribution infrastructure to reduce wildfire risk. Only large electrical corporations can participate. To join, a utility must submit a detailed 10-year undergrounding plan to the Office of Energy Infrastructure Safety (Energy Safety), prioritizing projects in high fire- risk areas and justifying undergrounding over other mitigation methods. If Energy Safety approves the plan, the IOU must then seek the CPUC’s conditional approval of the plan’s costs and targets. Once approved, the utility must regularly report progress, hire an independent monitor to oversee compliance, and apply for external funding to offset costs AB 825
to ratepayers. The office and CPUC have the authority to require corrections or impose penalties if the utility fails to meet its plan objectives. (Public Utilities Code § 8388.5) 13) Requires each IOU to annually prepare and submit to Energy Safety a WMP for review and approval. Requires the WMP to include a description of preventative strategies and programs to minimize the risk of catastrophic wildfire, including consideration of dynamic climate change risk; a description of the metrics used to evaluate the plan’s performance and underlying assumptions for the use of those metrics; and a list that identifies, describes, and prioritizes all wildfire risks and drivers of those risks throughout the IOU’s service territory. (Public Utilities Code § 8386)
FISCAL EFFECT: Unknown. This bill is keyed fiscal. An earlier version of this bill – which is retained and expanded in the current measure – was estimated to cost approximately $330 million from Proposition 4, to establish and fund the transmission authority. Another bill (AB 745, Irwin), also included in this current measure, was estimated to cost the CPUC approximately $586,000 annually.
CUSTOMER COST IMPACTS: This measure seeks to provide a suite of tools to reduce overall cost to electric ratepayers. The full impact of these efforts is unknown to this committee.
BACKGROUND:
Ballooning Utility Costs. According to a recent report by the Legislative Analyst’s Office, residential electricity rates in California are nearly twice the national average, largely due to high charges by the state’s three major IOUs.1 These rates have been rising quickly, outpacing both inflation and rate growth in other states, and this upward trend is expected to continue.
While the exact contributions of each factor are hard to quantify, according to an analysis by the Public Advocates Office, the primary drivers for these cost increases arise from wildfire mitigation work, transmission and distribution investments, and rooftop solar incentives.2 A 2023 report by the State Auditor had similar findings.3 Wildfire costs, including insurance, was noted as a key factor in increased utility expenses. Decreasing electricity sales due to solar system adoption was noted to have led to IOUs raising rates to recover fixed costs. Further, the 2023 audit found increases in IOU operating costs, which may be inclusive of these other categories, as contributing to increased rates; specifically distribution costs for Pacific Gas & Electric (PG&E), administrative costs for Southern California Edison (SCE), and higher property and non-income taxes for San Diego Gas & Electric (SDG&E).4 These factors tend to affect IOU customers more than those served by POUs. Additionally, within a single utility, residential rates can vary significantly due to subsidies for low-income households and rooftop solar users; costs that are passed on to other ratepayers.
1 Helen Kerstein, Legislative Analyst’s Office; Assessing California’s Climate Policies – Residential Electricity Rates in California; January 2025; https://lao.ca.gov/reports/2025/4950/Residential-Electricity-Rates-010725.pdf 2 Slide 6, PAO slidedeck “Q4 2023 Electric Rates Report;” January 19, 2024; https://www.publicadvocates.cpuc.ca.gov/-/media/cal-advocates-website/files/press-room/reports-and- analyses/240119-caladvocates-q4-2023-quarterly-rate-report.pdf 3 State Auditor, 2023; Ibid.
4 Pg. 1; State Auditor, 2023; Ibid.
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Rising electricity rates place growing financial pressure on households, especially those with lower incomes or those living in hotter parts of the state. These high costs also undermine California’s climate goals by discouraging people from switching to electric vehicles and appliances, slowing the transition away from fossil fuels.
Several emerging challenges could push rates even higher, including more aggressive GHG targets, increased electricity demand, and escalating wildfire-related expenses. Higher rates would add to the cost burden on Californians and make electrification – key to meeting the state’s climate goals – more difficult. As a result, the Legislature faces tough decisions about how to manage electricity rates while advancing affordability, resilience, and climate policy objectives.
Wildfire Spending.5 Over the last five years6 $16 billion of wildfire mitigation costs have been authorized to be collected from customers, in addition to approximately $11 billion for wildfire insurance premiums and catastrophic event costs.7 Collectively, these “wildfire-related” costs resulted in over $5 billion per year over the last 5 years, when averaged amongst the three largest IOUs.8 These wildfire-related costs have amounted to roughly 18% of overall system costs9 for PG&E, 12% for SCE, and 9% for SDG&E,10 as of 2023 as shown in Figure 1. For residential customers, these wildfire-
related costs have led to a
monthly $24 increase on
the average 2023 bill for
PG&E, a $18 increase for
SCE, and a $13 increase
for SDG&E; comprising
between 7-12% of total
monthly bills.11
While wildfire-related
operating expenses, such
as vegetation
management and liability
insurance coverage, make
up the majority of these
recent cost increases,
wildfire-related capital expenses are anticipated to grow in time. Capital-related expenses, such as installing covered conductor or undergrounding portions of a distribution system, have a
5 Much of this section is taken from the CPUC’s 2024 SB 695 Report (citation #30), starting on pg. 47; Figure 2 is Figure 22 on pg. 53 of this CPUC 2024 SB 695 Report. https://www.cpuc.ca.gov/ -/media/cpuc- website/divisions/office-of-governmental-affairs-division/reports/2024/2024-sb-695-report.pdf 6 2019 to Q4 2023; pg. 49, CPUC; 2024 Senate Bill 695 Report; July 2024; https://www.cpuc.ca.gov/-/media/cpuc- website/divisions/office-of-governmental-affairs-division/reports/2024/2024-sb-695-report.pdf 7 Pg. 50, Table 6; CPUC; 2024 Senate Bill 695 Report; July 2024; https://www.cpuc.ca.gov/-/media/cpuc- website/divisions/office-of-governmental-affairs-division/reports/2024/2024-sb-695-report.pdf 8 PG&E, SCE, and SDG&E
9 “system costs” means revenue requirement
10 Pg. 52; Ibid.
11 Table 8, pg. 53; Ibid.
Figure 1: Wildfire-Related Costs Relative to Total System Costs (Year-End, $ millions)55
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larger cumulative impact on rates relative to operating expenses, as capital costs are recovered over a much longer time horizon during which the IOUs also earn an authorized profit.
Ratepayers have been shielded from some of the cost impacts of these capital expenses due to two provisions of AB 1054 (Holden, Chapter 79, Statutes of 2019): 1) the first $5 billion of capital spending is excluded from earning a Return on Equity (i.e. shareholder profit); and 2) the first $5 billion of capital spending may also be securitized through a CPUC financing order rather than through more traditional unsecured bond offerings. The equity rate base exclusion of #1 is estimated to save ratepayers as much as $2 billion over the life of those capital assets.12 The securitization of #2 benefits ratepayers by allowing the IOUs to financing wildfire-related capital projects with lower interest rates than would otherwise be available;13 the overall anticipated savings from this securitization is currently unknown by this Committee.
CPUC Response to Governor Executive Order N-5-24. On October 30, 2024, Governor Newsom issued Executive Order N-5-24 to address California’s rising electricity costs and broader affordability concerns.14 The order directed the CPUC and the CEC to conduct a comprehensive review of all electric ratepayer-funded programs under their jurisdiction, identifying those that drive up rates without delivering proportional benefits. It also calls for immediate action to sunset or modify underperforming or underutilized programs and return unused funds to ratepayers through bill credits. Additionally, the order instructs the CPUC and the California Air Resources Board (CARB) to propose improvements to the California Climate Credit, particularly for low-income customers, and requires Energy Safety and the CPUC to recommend adjustments to wildfire oversight processes to improve cost-effectiveness. All agencies were directed to report their findings and proposed actions to the Governor by January 1, 2025.
In February, the CPUC’s response the EO N-5-24 was released.15 The CPUC’s report noted three areas as “opportunities to control costs and reduce electricity bills.” These included 1) controlling the growth in utility spending; 2) find cost-sharing opportunities; and 3) implementing equitable rates to recover wildfire, public purpose program, and fixed costs. The report concluded with seven specific strategies:
1) All energy–related mandates should be assessed for overall cost-effectiveness; 2) Wildfire and emergency response costs should be paid for by non-ratepayer sources; 3) Integrate WMP strategies more fully into General Rate Case processes; 4) Refine Net Energy Metering;
5) Redistribute the Climate Credit volumetrically;
12 Finding of Fact 2 of each CPUC Financing Order states the estimated Net Present Value (NPV) savings of each bond issuance authorized. D.20-11-007: $173 million; D.21-06-030: $633 million; D.21-10-025: $403 million; D.22-08-004: $659 million; D.23- 02-023: $493 million; D.24-02-011: $465 million. The CPUC also approved SDG&E AL 4078-E that demonstrated $84.3 million NPV savings. 13 D.21-06-030 approved PG&E’s first AB 1054 financing order requesting $1.2 billion in AB 1054 CapEx, of which bonds representing about $850 million were issued, D.22 -08-004 approved its second AB 1054 financing order totaling about $1.4 billion in AB 1054 CapEx, of which bonds representing about $975 million were issued; and D.24-02-011 approved PG&E’s request to securitize the remaining $1.385 billion AB 1054 CapEx---the bonds have not yet been issued at this time. D.20-11- 007, D.21-10-025 and D.23-02-023 approved SCE’s first, second and third (final) AB 1054 financing orders totaling about $1.575 billion in AB 1054 CapEx of which bonds representing the same amount of CapEx were issued. Recovery bond financing costs apply to all AB 1054 securitizations. 14 https://www.gov.ca.gov/wp-content/uploads/2024/10/energy-EO-10-30-24.pdf 15 https://www.cpuc.ca.gov/-/media/cpuc-website/industries-and-topics/reports/cpuc-response-to-executive-order-n- 5-24.pdf
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6) Fund cost-shifting programs from non-ratepayer sources; and 7) Ensure programs benefitting all electric customers are supported by all customers, including POU customers.
COMMENTS:
1) Author’s statement. According to the author, “California’s ambitious clean energy goals require that renewable and zero-carbon energy resources supply 100 percent of electric retail sales to customers by 2045. In addition to needing to quadruple clean energy capacity, improving our infrastructure to adapt to climate change as well as electrifying all aspects of our economy will require an enormous expansion in new infrastructure.
Unfortunately, it is becoming increasingly likely that relying solely on the traditional investor-owned utility financing and development model for deployment of this multi- billion-dollar infrastructure portfolio will result in substantial increased costs to ratepayers. AB 825 offers a handful of solutions to reduce electric costs and drive down customer bills. These include preventing utilities from earning profits on the first $15 billion they spend on undergrounding power lines, setting up a public financing program to help fund new transmission projects at lower cost, creating a task force to evaluate energy efficiency and demand-side programs for customers, launching a new program to help local governments permit clean energy projects with expert support and incentives, and updating the state’s wildfire safety planning requirements.”
2) Public Transmission Financing. This legislation establishes the Public Transmission Financing Fund within the State Treasury to finance critical transmission projects needed to meet California’s clean energy goals, while helping to reduce or offset costs that would otherwise be passed on to ratepayers. For administration purposes, the bill also creates the Public Transmission Financing Program, administered by I-Bank to support the financing of public partnerships of transmission projects. This measure provides that the Program and the Fund would be available to a range of public sponsors including state agencies, local public agencies, tribal organizations or joint powers authorities.
Securing low-cost financing for transmission projects often requires customized approaches that account for diverse project risks and structures. Therefore, flexibility is critical because transmission projects are typically large, complex, and capital-intensive, with financing needs that may vary significantly depending on project size, ownership structure, and development timeline. By authorizing the I-Bank to operate either independently or in syndication with other lenders, AB 825 encourages co-investment from private and public financing entities, broadening the pool of available capital and helping to accelerate the development of transmission infrastructure beyond what state resources alone could support.
This measure also proposes to expand the authority of the California Consumer Power and Conservation Financing Authority (CPA). For background, CPA was originally established in 2001 in response to the state’s energy crisis.16 Its statutory mandate was to ensure a reliable supply of electricity, promote energy efficiency, and facilitate the development of clean, affordable power generation including to construct, own, and
16 Public Utilities Code § 3300 et seq
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operate electric power facilities, and finance energy conservation projects.17 The CPA was authorized to issue up to $5 billion in revenue bonds to finance new infrastructure, including power plants and conservation programs, and to enter into public-private partnerships to accelerate grid development.
However, as noted by the Legislative Analyst’s Office (LAO) in multiple reports, the CPA struggled to establish a strong operational role amidst its overlapping functions with other agencies. By 2004, it had failed to develop or finance any major generation facilities, largely due to unfavorable market conditions and the absence of long-term power contracts. Its limited impact and overlapping functions ultimately led to its de facto dissolution. As such, its statutory authority, including its bond issuance powers, was formally repealed by SB 1222 (Hertzberg, Chapter 842, Statutes of 2016). This bill grants new authority to the CPA beyond its original 2001 statute, which primarily focused on developing power generation facilities rather than transmission infrastructure.
New provisions of this bill, since it was heard in this Committee on April 30th, include expansion of “eligible transmission projects” to include new transmission lines identified by CAISO in its transmission planning process as a project subject to competitive bidding; and a transmission project where the costs are not eligible for recovery through the CAISO transmission access charge (i.e., “merchant” projects). Additionally this bill now prohibits I-Bank from financing an eligible transmission project unless the IOU or POU has selected their employees for the construction of the project; the public transmission sponsor has selected only a prime contractor who has served as such for at least two transmission projects in the state during the prior 10 years; or the IOU, POU, or public transmission sponsor has only selected a contractor who has frequently performed electrical transmission infrastructure maintenance work for an IOU during the prior 10 years. Additionally prohibits the I-Bank from financing any project unless it complies with the California Public Utilities Commission’s (CPUC) General Order 95. 3) IOU Undergrounding Programs. While undergrounding is the most effective way to reduce wildfire risk, it is also the slowest, most expensive way to do so. According to the Public Advocates Office, covered conductors generally take 1-2 years to install compared to 3-4 years for undergrounding and is approximately one-third of the cost. They note, for the cost of undergrounding 1 mile of power lines, a utility can protect almost 4 miles with covered conductors.18 Covered conductor is also a proven mitigation, as it has been installed on thousands of miles across California. The CPUC has noted construction feasibility is a significant concern with PG&E’s 10,000-mile undergrounding plan,19 as unknowns around the availability of material and labor place an unreasonably high level of uncertainty around PG&E’s ability to execute its plans and realize efficiencies of scale meant to drive down cost.20
17 U.S. Energy Information Administration; “Subsequent Events California's Energy Crisis”; https://www.eia.gov/electricity/policies/legislation/california/subsequentevents.html
18 Matt Baker, “Why we support the levels of undergrounding approved in PG&E’s General Rate Case;” November 17, 2023; https://www.publicadvocates.cpuc.ca.gov/press-room/commentary/231117-undergrounding-pge-grc 19 https://www.pge.com/content/dam/pge/docs/outages-and-safety/safety/pge-10k-undergrounding-program-city- county-maps-202307.pdf
20 Pg. 295, CPUC Decision D. 23-11-069
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Pursuant to SB 884 (McGuire, Chapter 819, Statutes of 2022) large IOUs may submit a 10-year distribution infrastructure undergrounding plan to Energy Safety for review.
Energy Safety must approve, modify, or deny the plan within nine months of submission.
Energy Safety may only approve the plan if it finds that the IOU’s plan will achieve, at the least, both substantial increases to reliability by reducing use of public safety power shutoffs, enhanced powerline safety settings, de-energization events, and other outage programs; and substantial reduction of wildfire risk. If Energy Safety approves the plan, the IOU must submit to the CPUC, within 60 days Energy Safety’s approval, a copy of the plan and an application requesting review and conditional approval of the plan’s costs. The CPUC must approve, modify, or deny the application within nine months of submission.
In February 2025, Energy Safety adopted guidelines for the IOUs’ 10-year electrical underground plans.21 The CPUC also adopted program guidelines in March 2024, which address the process and requirements for the CPUC’s review of the undergrounding plans.22 While these plans are still in development, the CPUC has estimated the portion of 2023 average monthly bills going to underground work to be $0.27 for PG&E and $0.10 for SCE, representing less than 0.1% of total bills.23 It is likely that these percentages will increase, perhaps significantly, as the SB 884 Plans are incorporated.
This bill seeks remedies to what is estimated to be significant future IOU undergrounding costs. The bill proposes rate design strategies to redistribute the costs, via securitization, so that the direct impact on customer bills is lessened. The bill also prevents IOUs from including in their equity rate base their share of the first $15 billion expended in aggregate on undergrounding projects. The CPUC estimates undergrounding distribution lines at $2.3-$5.6 million per mile, while transmission lines are approximately $140 million per mile.24 With costs ranging from $92-$224 billion to underground every IOU distribution line in high fire threat areas,25 opportunities to reduce costs to ratepayers will be critical. Even if such extensive undergrounding work is unlikely and unnecessary,26 some degree of undergrounding will be part of IOUs’ long-term wildfire mitigation strategy, as noted in the recent examples for PG&E and SCE above.
This bill additionally seeks information sharing and efficiency in IOU undergrounding planning, by requiring the Underground Safety Board to issue regulations to determine timelines and scope for IOUs to share their undergrounding plans with operators of subsurface infrastructure in the area and tribal governments. The desire is to avoid overwhelming operators (sometimes small water utilities or other municipalities) with large volume of requests to locate and mark, with only two days’ notice. This has been a
21 https://efiling.energysafety.ca.gov/eFiling/Getfile.aspx?fileid=58006&shareable=true 22 CPUC Resolution SPD-15; March 7, 2024;
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M526/K984/526984185.pdf 23 Pg. 54; CPUC’s 2024 SB 695 Report;
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M526/K984/526984185.pdf 24 Pg. 23; CPUC; Response to Executive Order N-5-24; February 18, 2025; https://www.cpuc.ca.gov/-/media/cpuc- website/industries-and-topics/reports/cpuc-response-to-executive-order-n-5-24.pdf 25 Pg. 23; CPUC; Response to Executive Order N-5-24; February 18, 2025; https://www.cpuc.ca.gov/-/media/cpuc- website/industries-and-topics/reports/cpuc-response-to-executive-order-n-5-24.pdf 26 Fowlie, Meredith. “Fighting Fires in the Power Sector” Energy Institute Blog, UC Berkeley, February 20, 2024, https://energyathaas.wordpress.com/2024/02/20/fighting-fires-in-the-power-sector/ AB 825
recommendation of the Underground Safety Board in their annual reports,27 and – most recently – in the CPUC’s response to Governor Newsom’s Executive Order N-5-24.28 4) PLACE’ing Your Projects. The permitting regime that governs energy infrastructure construction and operation is complex. Depending on type, location, and scope, a project may be subject to review or approval of any of several state agencies, local governments, federal land managers, branches of the United States military, and tribal authorities. This is especially true of transmission projects, which, by their linear nature, are likely to cross multiple jurisdictions and a variety of sensitive lands and draw the attention of various local stakeholders.
Local governments exercise significant authority over the siting and permitting of clean energy projects through their control of land use, zoning, and building regulations. This authority enables them to influence the deployment of renewable energy infrastructure in ways that reflect local priorities and planning objectives. However, given the pace and scale of the state’s clean energy and decarbonization targets, the role of local siting decisions has come under greater scrutiny. In recent years, the Legislature has sought to simplify or otherwise streamline the permitting regimes governing the construction and operation of electricity generation resources. For example, AB 205 (Committee on Budget, Chapter 61, Statutes of 2022) allows an applicant to seek permitting for certain types of clean energy projects from the CEC instead of local permitting authorities or agencies, and according to an expedited permitting schedule. SB 149 (Caballero, Chapter 60, Statutes of 2023) provides expedited administrative and judicial review of CEQA challenges to certain energy infrastructure projects.
CEC data show ~16 gigawatts (GWs) of new energy resources, mostly solar and storage capacity, has come online since 202029 – on the order of hundreds of projects.30 With the state’s AB 205 “opt-in” program only introduced in late 2022, virtually all of that 16 GWs were subject to local review, and successfully locally permitted. Moreover, many local officials note that permitting these large solar farms and storage sites is routine.31 However, given the enormous increases in clean energy development needed to meet our statewide goals – approximately 6 GW of new solar, wind, and battery storage needed annually for the next two decades; an unprecedented pace – locals may start to see energy development in unexpected parts of California. That expansion is likely to challenge local hospitality of these projects. For example, utility-scale battery storage is a relatively recent technology. As a result, many local governments have been either reluctant or uncertain of siting large battery storage facilities within their communities due to
27 Pg. 15; 2022 Annual Report; https://energysafety.ca.gov/wp-content/uploads/2023/11/underground-safety-board- 2022-annual-report_small.pdf
28 Pgs. 25-26; https://www.cpuc.ca.gov/-/media/cpuc-website/industries-and-topics/reports/cpuc-response-to- executive-order-n-5-24.pdf
29 CEC Press Release, “New Data Shows Investments to Build California’s Clean Energy Grid of the Future are Paying Off;” May 9, 2024; https://www.energy.ca.gov/news/2024-05/new-data-shows-investments-build- californias-clean-energy-grid-future-are-paying
30 Based on a rough average capacity of ~ 20 MW per project; though large solar projects such as Westlands are exceptional cases.
31 Julie Cart, “Wrangling over renewables: Counties push back on Newsom administration usurping local control;” CalMatters; August 4, 2022; https://calmatters.org/environment/2022/08/renewable-energy-california-counties/ AB 825
unknowns of project safety, durability, and other unforeseen risks. These concerns have only intensified since the recent fire at the Moss Landing battery facility.32 This bill provides an incentive program (the Permitting Local Assistance for Clean Energy or “PLACE” Program) to both supplement local government expertise and to motivate more clean energy development. It proposes to do this by offering three incentives: 1) requiring the CEC to establish a state central pool of experts in clean energy project siting and permitting that local permitting agencies can utilize at no cost to the agency; 2) a match fund to supplement the cost a developer pays to the agency so that the developer is encouraged to apply through local channels; and 3) a monetary incentive to the local permitting agency for every 100 megawatts permitted through the program under CEC-determined timelines.
5) Join (task) Forces. As part of AB 3264 (Petrie-Norris, Chapter 762, Statutes of 2024), the Legislature updated an existing CPUC report on energy efficiency programs to include all demand-side management (DSM) programs, and required assessments of each program's bill savings to ratepayers, cost-effectiveness, and impacts, among other requirements.
These evaluations were sought to help policymakers track the activity levels of these programs – particularly bringing awareness to programs that may not be attracting participation or are not being actively managed – and adjust their needs or budgets, which, if reduced or recouped, could provide relief to ratepayers. The updated report is due to the Legislature before July 1, 2025; however, the actual expected delivery date of the report is currently unknown.
Among the many requests in Governor Newsom’s October 2024 Executive Order N-5-24 to address California’s rising electricity costs and broader affordability concerns,33 was a directive to the CPUC and the CEC to conduct a comprehensive review of all electric ratepayer-funded programs under their jurisdiction, identifying those that drive up rates without delivering proportional benefits. While the CEC identified a few, the CPUC spoke generally about programs needing to benefit all electric customers or otherwise be funded by other non-ratepayer sources; as well as noted that “all energy-related mandates should be assessed for overall cost-effectiveness.”34 Given the CPUC program budget is approximately $4.3 billion for 4 years (2024-2027) for energy efficiency alone,35 and other sources of non-ratepayer funding – such as the Greenhouse Gas Reduction Fund, the state General Fund, and federal monies – are also used for energy efficiency and demand response programs, it may benefit policymakers to have a system-wide assessment of all DSM programs, as proposed under this bill. The timelines for the DSM task force to complete their study and make recommendations are ambitions, but build off the work already underway for similar programmatic review at the CPUC pursuant to AB 3264.
6) Related Legislation.
32 County of Monterey presentation; “Moss300 BESS Structure Fire & HAZMAT Incident;” March 18, 2025 update; https://www.countyofmonterey.gov/home/showdocument?id=139292&t=638780880911175868 . 33 https://www.gov.ca.gov/wp-content/uploads/2024/10/energy-EO-10-30-24.pdf 34 Pg. 17; https://www.cpuc.ca.gov/-/media/cpuc-website/industries-and-topics/reports/cpuc-response-to-executive- order-n-5-24.pdf
35 https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-adopts-milestone-investment-in-energy-efficiency- 2023
AB 825
AB 745 (Irwin, 2025) an earlier version of this measure would have authorized IOUs to finance undergrounding costs through a fixed charge on customers' electric utility bills, also known as "securitization;" and sunsets this authorization in ten years. Also prohibited IOUs from including in their equity rate base any undergrounding activities.
Status: has been significantly amended and now related to the electric California Climate Credit. Referred to the Assembly Committee on Utilities and Energy pursuant to Assembly Rule 77.2, to be heard on June 3, 2025.
AB 915 (Petrie-Norris, 2025) would require the CEC to prepare and submit a report to the Governor and Legislature, by July 1, 2026, on the status of electrical transmission and distribution grid infrastructure manufacturing in California. Status: Assembly Floor, 3rd Reading.
SB 254 (Becker, 2025) proposes various policies related to electrical corporations, including changes to: wildfire mitigation regulatory framework, the allocation to customers of the Climate Credit, electric transmission infrastructure permitting and deployment, permitting of clean energy infrastructure, including energy storage facilities, and various proposals to address electricity utility bills, including prohibiting equity rate basing by electrical corporations of $15 billion in capital investments. Status: Senate Floor, 3rd Reading.
SB 330 (Padilla, 2025) would authorize the Governor to establish one or more pilot projects to develop, finance, or operate electrical transmission infrastructure that meet the specified criteria, including, among other things, that the transmission line is identified by the CAISO in its transmission planning process as necessary to support clean energy generation to meet the state’s clean energy goals. Status: Senate Floor, 3rd Reading.
SB 769 (Caballero, 2025) would establish the Golden State Infrastructure Corporation (Corporation) within the State Treasurer’s Office as a not-for-profit corporation for the purpose of financing infrastructure projects. Status: Assembly Desk.
7) Prior Legislation.
AB 3264 (Petrie-Norris), requires a suite of actions by the CPUC to help address energy costs, including developing a total energy framework to be used to evaluate IOU spending requests; requiring IOUs to publish visual representations of certain cost categories; studying alternative financing for transmission infrastructure; and broadening the triennial CPUC report on energy efficiency and conservation programs to include specified metrics and criteria. Status: Chapter 762, Statutes of 2024.
SB 1003 (Dodd, 2024) modified timelines relevant to the submission and approval of wildfire mitigation plans (WMPs) by IOUs to the Office of Energy Infrastructure Safety and the CPUC. Requires IOUs to take into account, in their WMP, both the time required to implement an action and the amount of risk reduced for the cost and risk remaining.
Status: Died – Assembly, 3rd Reading.
SB 1032 (Becker, 2022) creates the Clean Energy Infrastructure Authority as a public instrumentality of the state for the purpose of leading the state’s efforts to build critical AB 825
electrical transmission infrastructure necessary to enable the state to transition to 100 percent clean energy, as specified. Status: Held under submission in the Assembly Committee on Appropriations.
SB 1020 (Laird) establishes interim targets to the statewide 100% clean energy policy.
Additionally requires state agencies to accelerate their 100% clean energy policy goal by 10 years. An early version of the bill sought to establish the California Affordable Decarbonization Authority as a nonprofit public benefit organization as a mechanism to help fund various electric utility-related programs and activities. Status: Chapter 361, Statutes of 2022.
SB 100 (De León) established the 100 Percent Clean Energy Act of 2018 which increases the RPS requirement from 50 percent by 2030 to 60 percent, and created the policy of planning to meet all of the state's retail electricity supply with a mix of RPS-eligible and zero-carbon resources by December 31, 2045, for a total of 100 percent clean energy.
Status: Chapter 312, Statutes of 2018.
AB 1954 (Skinner) authorizes the CPUC to approve in advance the recovery through electricity rates of the costs of a transmission project proposed to meet the state’s RPS goals. The bill provides that ultimate rate recovery is still subject to review by the CPUC to ensure that the utility incurred the costs reasonably and prudently. Status: Chapter 460, Statutes of 2010.
REGISTERED SUPPORT / OPPOSITION:
Support
This bill has been significantly amended since these support letters have been received by the committee. It is unclear how positions might have changed.
Advanced Energy United
California Environmental Voters (formerly CLCV)
Net-zero California
The Utility Reform Network (TURN)
Opposition
None on file.
Analysis Prepared by: Laura Shybut / U. & E. / (916) 319-2083