Agenda Packet — Redding City Council, March 3, 2026 (part 2 of 2)

Cost Per City
Lamp Size Installed Lamp Effective Date 01/01/2029
175 watts mercury vapor ........................................................ $41.09 250 watts mercury vapor ........................................................ $46.14 400 watts mercury vapor ........................................................ $51.18 1,000 watts mercury vapor ........................................................ $72.51 1,500 watts mercury vapor ........................................................ $98.91

Cost Per City
Lamp Size Installed Lamp Effective Date 01/01/2029
20-35 watts light emitting diode .............................................. $28.66 35-50 watts light emitting diode .............................................. $32.64 50-65 watts light emitting diode .............................................. $35.93 65-80 watts light emitting diode .............................................. $37.42 80-95 watts light emitting diode .............................................. $40.80 95-110 watts light emitting diode ............................................ $42.62 110-135 watts light emitting diode ............................................ $44.80 135-170 watts light emitting diode ............................................ $48.98 170-225 watts light emitting diode ............................................ $51.92 225-350 watts light emitting diode ............................................ $58.49 350-500 watts light emitting diode ............................................ $68.80

Mercury vapor lamps described above are no longer available for new installations. For lighting efficiency and energy conservation, all existing mercury vapor lamps will be replaced with comparable high -pressure sodium vapor lamps when servicing is necessary.

APPLICABILITY

This service is applicable to all unmetered outdoor lights maintained by REU on streets and highways and for all individual customers who request night lighting on private property where adequate City -owned facilities for light fixture mounting already exist.

Packet Pg. 340
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

Electric Service A-13 Effective January 1, 2029
STREETLIGHT (NIGHTLIGHT) SERVICE (continued)

CHARACTER OF SERVICE

This service is characterized as single -phase, 60 hertz, three -wire, nominal 120/240 volts (or three -wire, 120/208 volts at certain locations as are now or hereafter may be established by REU. The lamp, luminaries, control device, bracket, and pole/standard will be maintained by REU. A lamp will be controlled to operate from dusk to dawn each night giving approximately 333 hours of lighting service per month.

Packet Pg. 341
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

Electric Service A-14 Effective January 1, 2029

STANDBY DEMAND SERVICE

APPLICABILITY

This service is applicable, at REU’s option, to all customers on the Large Commercial Service rate schedule who utilize their own generation to meet any portion of their electrical supply needs with an electric generation resource that is: 1) installed on the Customer’s side of the delivery point; 2) and interconnected with load that REU may be required to serve on an as needed basis . The customer’s generation system will be used to offset the customer’s energy and if applicable, demand requirements, supplied by REU to the customer. REU reserves the right to limit the number of Customers allowed to interconnect generation systems and equipment on an individual electric circuit or substation.

CHARGES

The customer will be billed for all energy service purchased from REU under the applicable rate schedule.

In addition, the Standby Demand charge shown below will be included on each of the Customer’s periodic utility bills:

Effective Date: January 1, 2029

$14.74 per kW

This charge will be a monthly charge based on the Standby Demand as determined below.

CHARACTER OF SERVICE

The service is characterized by single -phase or three-phase, 60 hertz, and at one standard nominal voltage as mutually agreed by REU and the Customer and subject to availability at the point of delivery.

STANDBY DEMAND

The highest monthly recorded d emand reading for a 12 -month period directly preceding the customer’s transition to the Standby Demand Service regardless of the time of day or the day of week of the reading. If monthly demand readings are not available for each of the 12 months preceding the customers’ transition to the Standby Demand Service, REU will estimate the maximum demand based on the customer’s existing kwh usage and/or comparison of similar loads within the REU system. REU will reevaluate this Standby Demand on an annual basis and will increase or decrease the Standby Demand as appropriate.

Packet Pg. 342
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

Electric Service A-15 Effective January 1, 2029

ECONOMIC DEVELOPMENT SERVICE (EDS)

APPLICABILITY

This service is applicable to any new customer whose monthly billing demand is expected to exceed 100 kW for 3 months out of a consecutive 12 -month period or to any existing customer whose monthly billing demand is expected to increase by 100 kW for 3 months out of a consecutive 12-month period.

For the purpose of this service, a customer is defined as a business bringing entirely new electric load into the City. A business that changes location within the service territory or a business enterprise under ownership does not qualify as new a business.

This service is not applicable to or available for resale, standby, or auxiliary service.

Qualified customers will be eligible for any and all service discounts available to commercial service customers including, but not limited to, the Primary/Transmission Service Discount and the Power Factor Adjustment.

EDS DISCOUNT

The monthly bill at the commercial rate, plus or minus any adjustments incorporated in this rate schedule or supplement hereto will be discounted as follows:

Discount: Year 1 (Billing cycle 1 through 12) = 25%
Year 2 (Billing cycle 13 through 24) = 20%
Year 3 (Billing cycle 25 through 36) = 15%
Year 4 (Billing cycle 37 through 48) = 10%
Year 5 (Billing cycle 49 through 60) = 5%

The Discount will end after 60 billing cycles.

In no event shall the cost of power to the customer fall below REU’s average cost to supply power to that customer.

SPECIAL CONDITIONS

The customer will be required to sign a 5 -year contract. If a customer covered under this schedule leaves before the expiration of the contract, penalties as established in the Council Policy regarding electric incentives for economic development shall apply.

A customer wishing to avail themselves of this service must apply for service within one year of becoming eligible, or lose that eligibility.

CHARACTER OF SERVICE

The service is characterized as single -phase or three-phase, 60 hertz, and at one standard nominal voltage as mutually agreed by REU and the customer and subject to availability at the point of delivery. All meter - recording equipment shall be supplied and maintained by REU. Any expense to modify the customer's facilities to accommodate the meter-recording equipment shall be paid by the customer.

Packet Pg. 343
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

Electric Service A-16 Effective January 1, 2029

ECONOMIC ATTRACTION SERVICE

APPLICABILITY

This service is applicable to any customer who is considered a manufacturing or industrial company, and who expects their billing demand in the monthly billing period to be at least 25 kW for 6 months out of a 12- month period or 75 kW in any month out of a 12-month period. In addition, the Economic Attraction Service is not designed for those customers in a retail sales business.

Not applicable to, or available for, resale, standby, or auxiliary service.

CHARGES

A monthly bill will be provided at a rate mutually agreed upon by the company and the REU Director. This rate is negotiated and shall include all costs incurred in serving this customer. The rate shall include all relevant distribution and transmission-related costs, including fixed costs and power supply.

In no event shall the cost of power to the customer fall below the incremental cost of power to REU calculated on a per-kWh basis.

SPECIAL CONDITIONS

A customer on this schedule will be required to sign a contract. The length of the contract is negotiable. The intention of the Economic Attraction Service is to create a relationship with the customer, and for both parties to honor the terms of the negotiated contract. If, however, a customer covered under this schedule does not honor the terms of the contract, and leaves the REU system for another supplier, the customer may be required to pay a Competitive Transition Charge (CTC).

A customer who wishes to be serviced under this schedule must apply for service within one year of becoming eligible or lose that eligibility.

CHARACTER OF SERVICE

Packet Pg. 344
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

Electric Service A-17 Effective January 1, 2029
RENEWABLE RESOURCE NET METERING SERVICE – (E*NET)

APPLICABILITY

Effective January 1, 2020, this rate is no longer available for new generators.

The renewable resource net metering tariff is applicable to residential customers and commercial customers where a part or all of the electrical requirements of the customer can be supplied from a solar , wind, or other eligible customer generator as defined in SB489 and SBX1 2 of not more than 1,000 kilowatts that is owned and operated by the customer. The generator must be connected for parallel operation with the service of REU, it must be located on the customer's premises, and it must be intended to offset part or all of the customer's electrical requirements.

Customers on this tariff will be net metered. Net energy metering measures the difference between the electricity supplied through the electric grid and the electricity generated by an eligible customer -generator and fed back to the grid over a 12-month period.

Customers whose solar and/or wind power production source’s rated capacity or capability exceeds 10 kW, up to 1,000 kW or 1 megawatt, could require development of a co -metering tariff with REU, per statutory requirements, at the sole discretion of REU.

CHARGES

A monthly statement on the applicable residential or commercial service, energy and demand charges will be established for all customers operating under the Net Metering Tariff, plus or minus any adjustments incorporated in this rate schedule or supplement hereto.

The eligible customer -generator shall be billed each month for the applicable monthly Fixed Charges .

Residential and small commercial customers operating under this service will receive an estimate of net energy charges and/or demand charges due to REU. At the end of the twelve (12) billing cycles following the date of the generator’s final interconnection with the Utility’s system and at the end of each successive twelve (12) billing cycles thereafter, the customer shall receive a bill for any applicable charges for electricity used during the previous 12-month period that are unpaid. The customer -generator shall be compensated for any net surplus energy transmitted during the previ ous 12-month period per Special Conditions #3 below. Large Commercial customers will be provided monthly bills for all applicable services, per State Law.

SPECIAL CONDITIONS

1. Generation Interconnection Agreement : An interconnection agreement with the customer is required for service under this schedule. The customer must comply with conditions and terms set forth by REU for the safe and efficient interconnection of equipment with the REU electrical system.

2. Net Energy : Net energy is E S minus E F, where E S is energy supplied by REU and E F is energy generated by the customer and fed back into REU's system at such times as customer generation exceeds customer requirements. If the net energy value resulting from the above computation is positive, an energy charge shall be applied at the rates specified below. If the calculation of net energy yields a negative result, all such net surplus energy shall be considered net surplus energy transmitted and shall be treated as stated in Special Condition No. 3 below. The components of net energy, E S and EF, shall be determined by the use of metering equipment best suited for each facility

Packet Pg. 345
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

Electric Service A-18 Effective January 1, 2029
RENEWABLE RESOURCE NET-METERING SERVICE (Continued)

or location, as determined by REU. All necessary labor, equipment, materials, and related facilities costs in addition to, or in substitution for, standard City facilities that are required in order to take and sell power through one-meter socket, will be at the customer's expense.

3. Net Surplus Energy Transmitted : Net energy transmitted occurs when the cumulative value of E F exceeds the cumulative value of E S during the entire billing period and is the amount by which the energy generated by the customer and fed back into REU's system exceeds the energy supplied by REU over an entire billing period. In the event the energy generated exceeds the energy consumed during the 12-month period, payment will be made for the net surplus energy delivered to REU’s grid.

This compensation will be based on REU’s current avoided cost for energy ($0.0608 per kWh effective January 1, 2020) and is updated administratively on an annual basis.

4. Payment: Statements of any and all monthly service costs will be provided monthly and bills for service will be rendered annually to customers receiving service under the Residential or Small Commercial tariffs outlined herein, per State Law. However, such customers operating under this rate schedule will be allowed to provide periodic (e.g. monthly or bi -monthly) payments for services rendered, if applicable, to avoid an unbudgeted utility expense. Large Commercial customers will be provided monthly bills for all services received under this service, per State Law.

Packet Pg. 346
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

Electric Service A-19 Effective January 1, 2029
ZERO NET ENERGY SERVICE – (E*ZNE)

CHARGES

This service will be billed monthly at the applicable residential or commercial service and net of a credit applied for any surplus energy transmitted ( $0.0608 per kWh effective January 1, 2020 ). Surplus energy transmitted occurs when on-site generation exceeds on-site consumption and energy is transmitted to the grid (real-time customer energy generation exceeds real-time customer energy consumption). When a customer’s on-site generation meets their on -site consumption, the customer avoids the full utility retail rate. When a customer’s on-site generation does not meet their on -site consumption, the customer is charged at the full retail rate.

APPLICABILITY

The net metering successor tariff is applicable to residential customers and commercial customers where a part or all of the electrical requirements of the customer can be supplied from a solar , wind, or other eligible customer generator as defined in SB489 and SBX1 2 of not more than 1,000 kilowatts that is owned and operated by the customer. The generator must be connected for parallel operation with the service of REU, it must be located on the customer's premises, and it must be intended to offset part or all of the customer's electrical requirements.

Customers whose solar and/or wind power production source’s rated capacity or capability exceeds 10 kW, up to 1,000 kW or 1 megawatt, could require the development of a co-metering tariff with REU, per statutory requirements, at the sole discretion of REU.

CHARACTER OF SERVICE

Each service is characterized by the applicable residential or commercial service.

SPECIAL CONDITIONS

Generation Interconnection Agreement : An interconnection agreement with the customer is required for service under this schedule. The customer must comply with conditions and terms set forth by REU for the safe and efficient interconnection of equipment with the REU electrical system.

Packet Pg. 347
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

Electric Service A-20 Effective January 1, 2029
POWER COST ADJUSTMENT – (PCA)

PURPOSE

The purpose of this adjustment is to appropriately adjust for increases in REU’s wholesale power costs due to the Revenue Adjustment Clause (RAC) associated with purchases by REU from the Department of Energy, Western Area Power Administration (Western).

APPLICATION OF POWER COST ADJUSTMENT

The monthly Power Cost Adjustment (PCA) dollar amount to be added to each bill shall be obtained by multiplying the number of kilowatt-hours for which the bill is rendered by the applicable monthly PCA Factor. This has not been used since the Interim Rate Surcharge was implemented in 1997.

CALCULATION OF THE POWER COST ADJUSTMENT FACTORS

1. The PCA Factor will be calculated and made effective every June 15 and December 15 to reflect any changes in Western's RAC.

2. If Western's RAC amount, in dollars, is a debit (monies owed to Western by Redding), then:

a. Western's RAC debit will be adjusted by:

(1) Subtracting any amount, in dollars, that is over the PCA Balancing Account's minimum balance of $300,000 as recorded 2 months prior to the effective date of the PCA Factor being calculated; however,

(2) If the 2 months' prior balance of the PCA Balancing Account is below $300,000, then the necessary dollar amount required to restore the account to $300,000 will be added to Western's RAC debit.

b. The adjusted debit dollar amount (as referenced in Section 2.a.) will be divided by the adjusted sum of all retail kilowatt-hour sales for the 6-month period beginning 12 months prior to the effective date of the PCA Factor.

c. The adjusted sum of retail kilowatt-hour sales (as referenced in Section 2.b.) will be determined by multiplying the historical total kilowatt-hour sales by a historical 3-year average annual energy growth factor to reflect REU’s rate of growth in kilowatt-hour sales.

d. The PCA Factor resulting from the calculations in Section 2.b. will be applied as a charge to all retail kilowatt-hour sales on a monthly billing-cycle basis beginning with the effective date of the PCA Factor being calculated.

Packet Pg. 348
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

Electric Service A-21 Effective January 1, 2029

POWER COST ADJUSTMENT (continued)

e. If the calculation of the PCA Factor results in a debit of less than 0.01 cents per kilowatt-hour, then the PCA Factor will be 0.00 cents per kilowatt-hour. The RAC debits from Western will be paid from the PCA Balancing Account.

3. A PCA Balancing Account shall be maintained as an operating account for the purposes of accommodating the cash-flow fluctuations inherent in the PCA process.

a. Each month when a power bill is rendered from Western, which includes any adjustment for Western's RAC, the account's balance will be calculated as follows:

(1) Subtract Western's monthly RAC charge, in dollars, from the balance which existed at the end of the prior month.

(2) Add the amount, in dollars, recovered from the application of the PCA Factor, which was effective during the prior month. Such amount shall be the product of kilowatt-hours of energy billed during the month and the applicable PCA Factor.

(3) Add the amount, in dollars, of all interest earned on the average balance of the funds in the PCA Balancing Account.

(a) Funds from the monthly collection of the PCA will be invested by the City along with the City's other cash accounts and, therefore, will accrue interest at the average monthly rate paid on the City's variable investment account.

b. Best efforts will be made to maintain a minimum balance in the PCA Balancing Account of $300,000.

Packet Pg. 349
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

Electric Service A-22 Effective January 1, 2029
FEDERAL ENVIRONMENTAL SURCHARGE – (FES)

APPLICABILITY

This surcharge is applicable to the entire City of Redding service area for all kilowatt-hours billed under all rate schedules.

PURPOSE

The purpose of this surcharge is to appropriately adjust for increases and decreases in the REU’s wholesale power costs due to the Federal Environmental Surcharge (FES) imposed by HR429 of the 1993 statutes, which is associated with purchases by the City of Redding from the Department of Energy, Western Area Power Administration (Western).

SURCHARGE

The monthly FES dollar amount to be added to or subtracted from each bill, shall be obtained by multiplying the number of kilowatt-hours for which the bill is rendered by the applicable monthly FES Rate. The FES Rate will become effective the first day of the month for which Western imposes the FES and will change from time to time thereafter, when changes in the FES are imposed by Western.

CALCULATION OF THE SURCHARGE

1. The FES Rate will be determined by multiplying the retail kilowatt-hour purchases of Western energy for the following 6-month period as defined in Section 1.A. by the FES rate charged by Western, then by subtracting from the resultant product the FES Balancing Account as defined in Paragraph 2, the difference will then be divided by the total projected retail kilowatt-hour sales as defined in Section

1.A.

a. Projected kilowatt-hour sales and purchases for FES calculation purposes shall be those amounts projected most recently by REU.

b. If the calculation of the FES Rate results in a surcharge of less than 0.01 cents per kilowatt-hour, then the FES Rate will be 0.00 cents per kilowatt-hour.

2. A FES Balancing Account shall be maintained as an operating account for the purposes of accommodating the cash-flow fluctuations inherent in the FES process.

Each month when a power bill is rendered from Western, which includes any adjustment for Western's FES, the account's balance will be calculated as follows:

a. Subtract Western's monthly FES charge, in dollars, from the balance which existed at the end of the prior month.

Packet Pg. 350
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

Electric Service A-23 Effective January 1, 2029
FEDERAL ENVIRONMENTAL SURCHARGE (continued)

b. Add the amount, in dollars, recovered from the application of the FES Rate which was effective during the prior month. Such amount shall be the product of kilowatt-hours of energy billed during the month and the applicable FES Rate.

c. Add the amount, in dollars, of all interest earned on the average balance of the funds in the FES Balancing Account.

Funds from the monthly collection of the FES will be invested by the City along with the City's other cash accounts and, therefore, will accrue interest at the average monthly rate paid on the City's variable investment account.

Packet Pg. 351
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

Electric Service A-24 Effective January 1, 2029
STATE REGULATORY SURCHARGE – (STATE)

PURPOSE

The State Regulatory surcharge or Energy Commission tax was established in 1975 by the State Board of Equalization, pursuant to Sections 40031 et seq., of the Revenue and Taxation Code of the State of California, to provide funding for the California Energy Commission.

SURCHARGE

The monthly dollar amount to be added to or subtracted from each bill shall be obtained by multiplying the number of kilowatt-hours for which the bill is rendered by the applicable monthly State surcharge rate. The State surcharge rate will become effective the first day of t he month for which the State imposes the surcharge, and will change from time to time thereafter when changes to the rate are made by the State.

As of January, 2021, the surcharge is set at $0.0003 per kWh.

This rate is subject to revision from time to time by the California State Board of Equalization. The surcharge does not apply to electric service for federal government and certain other agencies. (E*US) Packet Pg. 352
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

Electric Service A-25 Effective January 1, 2029

GLOSSARY OF TERMS

Demand The average rate over a given period of time that a customer requires delivery of electric energy from the Utility system. Demand is another term for power.

Electric Current The movement of charged particles (e.g. electrons) in a material (e.g. power lines). Current is measured in units called Amperes or Amps.

Kilowatt (kW) One thousand (1,000) watts. Kilowatt is a nominal or standard measurement/rating of the capacity of electric lines or equipment and demand or power.

Kilowatt-hour (kWh) Kilowatt-hour is the standard measurement of electric energy. One kilowatt-hour is the amount of energy it takes to run a 100-watt light bulb for 10 hours. (100 watts X 10 hours = 1,000 watt-hours = 1 kilowatt-hour.)

Load Any device that can convert the energy from electric current into some other useful form of energy, such as light, heat, sound, or mechanical motion. In electrical terms, load also refers to the amount of electric demand or power that the device uses or is rated to use.

Load Factor The ratio of the actual energy consumed and the maximum potential energy available during a specified time period, usually expressed as a percentage. e.g. 10,000 kWh/mo = 10,000 kWh/mo = 69.4% 20 kW Demand x 720 hours/mo 14,400 kWh/mo Load Factor

Fixed Charge The monthly charge established for each customer for access to the electric distribution system. This includes the costs of installing and maintaining the electric lines and transformers necessary to provide electricity to the customer’s location. This charge also includes the costs of installing, maintaining and reading the meter, as well as all other billing and customer service related functions provided by the Utility.

Power The rate at which electric energy is delivered by an electric current. Power is equal to the product of voltage and current (Volts X Amps = Watts).

Voltage The force that moves charged particles (e.g. electrons) in material. It is measured in units called Volts.

Watt (W) The standard measurement of electric power. One hundred watts is the rate of energy transfer equal to 10 amps flowing under the influence of 10 volts .

Packet Pg. 353
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

Packet Pg. 354
Attachment: Rate Book January 2029 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

ELECTRIC UTILITY DEPARTMENT

ORGANIZATION CHART
City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 123 Back to TOCPacket Pg. 355
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

ELECTRIC UTILITY DEPARTMENT

ORGANIZATION CHART
City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 124 Back to TOCPacket Pg. 356
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

ELECTRIC UTILITY DEPARTMENT

ORGANIZATION CHART
City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 125 Back to TOCPacket Pg. 357
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

ELECTRIC UTILITY DEPARTMENT

ORGANIZATION CHART
City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 126 Back to TOCPacket Pg. 358
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

ELECTRIC UTILITY DEPARTMENT

ORGANIZATION CHART
City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 127 Back to TOCPacket Pg. 359
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

ELECTRIC UTILITY DEPARTMENT

ORGANIZATION CHART
City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 128 Back to TOCPacket Pg. 360
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

ELECTRIC UTILITY DEPARTMENT

ORGANIZATION CHART
City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 129 Back to TOCPacket Pg. 361
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) This page left intentionally blank.

City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 130 Back to TOCPacket Pg. 362
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

ELECTRIC UTILITY DEPARTMENT
Expenditure Comparisons (In Thousands)
2023-24, Actual 2024-25, Adopted 2024-25, Amended 2025-26, Adopted 2026-27, Adopted 0 $30,000
$60,000
$90,000
$120,000
$150,000
$180,000
$210,000
Electric Utility Customer Service Field Service
City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 131 Back to TOCPacket Pg. 363
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) This page left intentionally blank.

City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 132 Back to TOCPacket Pg. 364
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

ELECTRIC UTILITY DEPARTMENT (REU)
Overview
The Redding Electric Utility Department (REU) is a community-owned utility that provides safe, reliable, and affordable electricity to approximately 45,000 residential and commercial customers within the City of Redding. The department’s primary functions are Generation and Distribution, Customer Service, and Field Services.

The primary objectives guiding Electric’s budget development for 2025-26 (FY26) and 2026-27 (FY27) are to enhance system reliability, mitigate operational and financial risks, ensure compliance with regulatory requirements, and maintain affordable rates for customers. Additional priorities include containing expense growth, adhering to the existing five-year financial forecast, and actively engaging customers in developing solutions to address major challenges.

The table below categorizes the expenditure budget based on primary functions: Electric Generation and Distribution, Customer Service, and Field Services:

Description FY 2023-24 FY 2024-25 FY 2024-25 FY 2025-26 Increase FY 2026-27 Increase Actual Adopted Amended* Adopted (Decrease) Adopted (Decrease) Electric Utility $ 178,509,694 $ 169,547,340 $ 188,575,430 $ 186,061,021 $ (2,514,409) $ 190,087,126 $ 4,026,105 Customer Service 8,651,851 8,830,540 9,282,190 8,329,734 (952,456) 8,631,168 301,434 Field Service 1,324,553 2,697,430 2,697,490 1,504,233 (1,193,257) 1,554,392 50,159 Total $ 188,486,099 $ 181,075,310 $ 200,555,110 $ 195,894,988 $ (4,660,122) $ 200,272,686 $ 4,377,698 Every effort is made to manage and contain costs despite external challenges, including rising power supply costs due to regulatory mandates and market conditions, inflation, and increased demand. In addition to addressing the repair and replacement of aging, critical utility infrastructure, and to ensure the continued financial stability of the utility, as well as to protect public health and safety, the following rate adjustments are incorporated into the Utility’s five-year plan:
2023-24 2024-25 2025-26 2026-27
Rate Adjustments Actual Estimated Projected Projected
2025 Financial Plan 4.00% 4.00% 5.00% 5.00%
2023 Financial Plan 4.00% 4.00% 4.00% 4.00%
City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 133 Back to TOCPacket Pg. 365
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) The following table presents the Department’s budget allocations, categorized by principal expenditure classifications:

Materials,
Division Supplies & Capital Debt
Personnel Services Outlay Service Total
FY 2026-27 Adopted $ 46,951,916 $ 103,502,160 $ 20,140,000 $ 19,493,050 $ 190,087,126 FY 2025-26 Adopted 47,610,841 100,864,380 18,952,000 18,633,800 186,061,021 FY 2024-25 Amended 37,296,080 98,360,600 38,619,230 14,299,520 188,575,430 Electric Utility
FY 2023-24 Actual 44,430,319 105,765,883 14,014,972 14,298,520 178,509,694 FY 2026-27 Adopted 2,769,038 5,862,130 - - 8,631,168
FY 2025-26 Adopted 2,681,154 5,648,580 - - 8,329,734
FY 2024-25 Amended 3,717,160 5,565,030 - - 9,282,190
Customer Service
FY 2023-24 Actual 3,103,329 5,548,523 - - 8,651,851
FY 2026-27 Adopted 1,115,012 439,380 - - 1,554,392
FY 2025-26 Adopted 1,091,283 412,950 - - 1,504,233
FY 2024-25 Amended 2,409,990 287,500 - - 2,697,490
Field Service
FY 2023-24 Actual 1,028,388 272,487 23,678 - 1,324,553
FY 2026-27 Adopted $ 50,835,966 $ 109,803,670 $ 20,140,000 $ 19,493,050 $ 200,272,686 FY 2025-26 Adopted $ 51,383,278 $ 106,925,910 $ 18,952,000 $ 18,633,800 $ 195,894,988 FY 2024-25 Amended $ 43,423,230 $ 104,213,130 $ 38,619,230 $ 14,299,520 $ 200,555,110 Total
FY 2023-24 Actual $ 48,562,036 $ 111,586,893 $ 14,038,650 $ 14,298,520 $ 188,486,099 Personnel
The proposed budget maintains the current staffing level of 202 full-time equivalent (FTE) positions and does not include any new position requests. Leadership remains committed to identifying opportunities to optimize staffing and achieve cost savings within the existing budget. Electric personnel costs for FY26 have increased by only 3.8% when adjusted in line with the assumptions outlined in the previous financial plan. While the FY26 budget reflects an 18.1% increase over the FY25 adopted budget, followed by a modest 2.2% increase in FY27, these variances are primarily driven by key personnel-related changes that were not anticipated during the previous budget development. Full-time equivalent totals calculated for Electric’s full- time, part-time, and total staffing levels for FY 2023-24 through FY 2026-27 are as follows:

FY 2023-24 FY 2024-25 FY 2024-25 FY 2025-26 Increase FY 2026-27 Increase Actual Adopted Amended Adopted (Decrease) Adopted (Decrease) F/T 166.00 166.00 166.00 173.00 7.00 173.00 -
P/T 1.00 1.00 1.00 0.50 (0.50) 0.50 -Electric Utility
Total 167.00 167.00 167.00 173.50 6.50 173.50 -
F/T 18.00 18.00 18.00 18.00 - 18.00 -
P/T 0.50 0.50 0.50 0.50 - 0.50 -Customer Service
Total 18.50 18.50 18.50 18.50 - 18.50 -
F/T 15.00 15.00 15.00 8.00 (7.00) 8.00 -
P/T 2.00 2.00 2.00 2.00 - 2.00 -Field Service
Total 17.00 17.00 17.00 10.00 (7.00) 10.00 -
F/T 199.00 199.00 199.00 199.00 - 199.00 -
P/T 3.50 3.50 3.50 3.00 (0.50) 3.00 -Total Fund
Total 202.50 202.50 202.50 202.00 (0.50) 202.00 -
City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 134 Back to TOCPacket Pg. 366
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) The following paragraphs provide an overview of key budget components, including personnel, operations and maintenance, debt service, capital outlays funded by revenue and bonds, major plant maintenance, and rolling stock replacement.

Significant Issues
Leadership remains focused on proactively addressing the following complex and potentially costly challenges outlined in the 2021-2026 Strategic Plan: wildfire risk and safety compliance; grid reliability and resource adequacy; cybersecurity and grid modernization; state clean energy mandates; rising energy costs and market volatility; electrification demands, equity and affordability; and supply chain disruptions, including trade-related cost pressures on critical materials and equipment. Increased expenses for imported items such as transformers, steel, and essential components elevate financial risk by driving up project costs, delaying infrastructure upgrades, and complicating efforts to meet clean energy goals and maintain stable rates.

While the Utility is not requesting additional positions, successfully replacing and modernizing an aging distribution system is expected to require the use of contract line crews for several years. These costs are included in the Utility’s Capital Outlay request as the Overhead/Underground Infrastructure project.

Operation and Maintenance
Operation and Maintenance (O&M) expenses are categorized into two groups: (1) Specific O&M expenses, which include operating materials and the cost of power, and (2) Interdepartmental Charges. Interdepartmental Charges consist of fixed charges from other City departments, such as Electric’s portion of the General Fund Cost Allocation, in-lieu fees, and rent for the Corporation Yard. O&M expenses are requested to increase by $7.6 million (9.1%) for FY26, followed by a small increase of $1.6 million (1.7%) for FY27, primarily due to increased power supply costs and wildfire/vegetation management.

Power supply costs are a primary driver of operating materials expenses. In the upcoming biennial budget forecast, rising fuel expenditures are the key factor contributing to the projected increase in overall power supply costs of $3.2 million (5.6%) for FY26, followed by an increase of 1.0% in FY27. Approximately 38% of the increase in power supply costs is attributed to a rise in load demand. Additionally, the cost increase is influenced by a reduced reliance on spot market purchases, as the narrowing gap between gas and energy market prices has made power plant operations more cost-effective. Importantly, the rise in load is accompanied by a corresponding increase in revenue, which is expected to offset the additional costs associated with meeting the higher demand.

In the past, the Electric Department experienced a period of relatively stable resource portfolio, largely due to sustained and strategic investment in long-term resource planning. However, recent developments, such as changes in customer demand, evolving regulatory requirements and compliance, and emerging energy and capacity deficits, now pose significant challenges to REU’s long-term resource planning strategies, regulatory compliance, and customer rates. These pressures may drive costs upward, but every effort will be made to mitigate the impact on customers. In response to these challenges, the Long-Term Resource Planning team (Resources) has evaluated available resource options and development recommendations to ensure the utility continues to meet customer demand reliably and cost-effectively.

O&M also includes REU’s continued wildfire mitigation efforts through a collaborative partnership with the Fire and Community Services Departments. To ensure a timely and capable emergency response, REU funds 15 full-time firefighter positions to maintain appropriate coverage levels and improve fire suppression readiness, particularly in high-risk areas served by REU’s electric system. In addition, REU funds six full-time Parks field positions and one Parks Superintendent to support proactive vegetation management in REU’s electric utility corridors and around substations. Key activities include mastication, weed abatement, ladder fuel removal, and utility pole wrapping to reduce the risk of wildfire ignition and improve system resilience. For the upcoming biennial budget cycle, REU will fund an additional 1/3 of a crew proposing to expand this partnership by leveraging a Cal Fire grant, which will allow REU to receive additional crew time dedicated to utility-focused vegetation work. The proposed funding for positions in the Fire and Parks Departments is approximately $4.0 million per year.

Overall, the $740,900 (5.9%) decrease in Interdepartmental Charges during the first year of the proposed budget is primarily driven by a reduction in Electric’s general and payment-in-lieu-of-tax to the General Fund. In the second year of the budget request, however, Interdepartmental Charges are projected to increase by $1,324,950 (11.3%), mainly due to higher Electric’s payment-in-lieu-of-tax and increased risk management costs to the General Fund.

City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 135 Back to TOC
Packet Pg. 367
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Debt Service
The Electric Utility Debt Service budget requests $18.8 million in FY26 and $19.6 million in FY27. For FY23 to FY25, Debt Service has stayed flat at approximately $14.4 million. The increase in debt service cost of approximately $4.4 million in FY26 and an additional increase of $0.8 million in FY27 is due to the issuance of $70.0 million Electric System Revenue Bonds, 2025 Series A in March 2025. This bond issuance was for financing the additions, betterments, extensions, and improvements to the electric utility system, including significant replacement and upgrades to overhead and underground infrastructure systems, and construction of a maintenance building at the Redding Power Plant.

Capital Outlay
The table below presents the components of the Capital Outlay requests for FY26 and FY27 compared with the actual FY24 expenditures and the adopted and amended FY25 Budget (excluding carryover amounts). 2023-24 2024-25 2025-26 2026-27
Actual Estimated Projected Projected
General System Improvements $6,961,574 $6,585,000 $8,750,000 $8,750,000 Projects, Programs & Equipment and Furnishings 5,957,420 15,315,000 10,202,000 11,390,000 Total Capital Outlay $12,918,994 $21,900,000 $18,952,000 $20,140,000 Most capital outlay requests fall under the categories of Projects, Programs, Equipment, and Furnishings. General System Improvements include annual, recurring expenditures necessary to install infrastructure that ensures reliable electric service for both new developments and existing customers. These improvements are carried out by Electric utility crews and contractors and typically involve the installation of key facilities such as transformers, poles, overhead and underground conductors, trenching, conduit, and vaults. This budget cycle emphasizes the continuation of overhead/underground infrastructure, substation security, power plant renovation projects, back-up power control center relocation and enhancements, and technology upgrades/replacements. As General System Improvements, Projects, and Programs are on “existing facilities of an investor and publicly owned utilities used to provide electric power, natural gas, sewerage, or other public utility services,” these types of projects are exempt from review under the California Environmental Quality Act (CEQA) guidelines Section 15301.

General System Improvements include the continuation of REU’s meter modernization effort of approximately $500,000 per year due to the age of the utility’s mechanical meters. As the City continues to expand and modernize its overhead and underground electric infrastructure, the need for additional materials and resources has grown. This includes increased demand for conductors, transformers, conduit, poles, switchgear, and other essential components.

The capital items for projects and programs are as follows:

FY26
Overhead/Underground Infrastructure $ 5,372,000
Power Plant Renovation $ 2,140,000
Substation Security $ 1,190,000
GIS Utility Network Upgrade/Software Replace $ 1,500,000 FY27
Overhead/Underground Infrastructure $ 5,200,000
Power Plant Renovation $ 2,140,000
Substation Security $ 1,190,000
Back-Up Power Control Center Relocation and Enhance $ 1,540,000 GIS Utility Network Upgrade/Software Replace $ 500,000 PI Implementation $ 820,000
The Utility anticipates that the majority of these projects, including General System Improvements, will be bond-funded.

City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 136 Back to TOCPacket Pg. 368
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Major Maintenance and Rolling Stock Funds
In addition to the regular Capital Outlay Budget, a “Special Purpose Fund” has been established for the periodic major maintenance of the Electric Utility’s power-generating equipment (Major Maintenance Fund). The annual contributions to this fund are designed to support a balanced 10-year maintenance plan. Maintenance expenses are budgeted in the fund and recognized in the year the work is completed. For FY25, the adopted funding amount for Major Maintenance was $1.6 million.

To maintain adequate funding levels, the budget for FY26 is $3.6 million and $1.8 million in FY27. The higher funding request in FY26 is primarily due to two large planned projects on Generator Units 5 and 6.

The Major Maintenance Fund is allocated for significant, periodic expenditures arising from the wear and tear that generating units experience due to regular use. These expenses are not included in the typical Operations & Maintenance budget because of their occasional and unpredictable nature. From a risk management perspective, it is considered sound utility practice to follow manufacturers' maintenance guidelines to ensure the continued, reliable operation of the generating units. Failure to adhere to preventive and periodic maintenance schedules could lead to catastrophic generator failures, resulting in substantial repair costs and the need for replacement power purchases, potentially amounting to millions of dollars.

The Rolling Stock Replacement Fund operates similarly to the Power Plant Major Maintenance Fund. The adopted FY25 funding amount for the Rolling Stock Replacement Fund was $1,100,000. However, the budget proposal calls for $1,200,000 annually for FY26 and FY27 to maintain adequate funding levels. This increase is primarily due to higher-than-expected inflation in the auto and electric equipment sectors.

The Rolling Stock Replacement Fund for Field Services requests increased from $55,000 in FY25 to $58,000 in FY26 and $58,000 in FY27. The increase is primarily due to higher-than-projected replacement costs of trucks.

The request for the Rolling Stock Replacement Fund is based on the Electric Utility’s established need for the scheduled, periodic replacement and upgrade of heavy rolling stock, such as line trucks, as well as vehicles like sedans, light trucks, and trailers. Fleet maintenance has confirmed the need for these replacements as appropriate. The Rolling Stock Replacement Fund should be maintained at the proposed levels to address the demonstrated and projected needs of the Utility.

Electric is not requesting any new vehicles during this budget cycle.

Public Benefits Program (2025-2027)
Electric’s Public Benefits Program has been effective and well-received in the Redding community since its inception. The Public Benefits Program provides financial incentives and support in four areas of electric utility operations and fulfills requirements mandated by state law:
• Demand-side Management (energy efficiency and carbon reduction) • Low-income assistance
• Research, Development and Demonstration (RD&D) of emerging electric technologies • Building Electrification
The budget year ending June 2024 applied only 4% of PBP funds to Demand-side management project expenses. The projects included commercial rebates to commercial and residential customers for energy-efficient upgrades. Low-income assistance spending (through the CARES program and Residential Energy Discounts) was the largest area of the Public Benefits Program expenditures at 85%. In prior years, the directive focused on expanding bill payment assistance for income-qualified customers, demonstrating the City's continued commitment to easing the financial burden of utility bills. In conjunction with this effort, additional support will be directed toward increased investment in energy efficiency projects.

Existing RD&D projects have most recently been focused on community outreach and education. These Public Benefits Programs will continue to provide wide-ranging benefits for the Redding community and customers.

City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 137 Back to TOC
Packet Pg. 369
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) The following summarizes the components of the expected FY25 expenditures and the adopted FY26 and FY27 expenditures for continuing the Public Benefits Program. The expenditures are based on 2.85 percent of forecasted retail revenue in the future fiscal years.
2023-24 2024-25 2025-26 2026-27
Public Benefits Program Actual Estimated Projected Projected Demand-Side Management - - - -
Project Expenses $17,000 $10,000 $500,000 $500,000
Low-Income Assistance - - - -
Project Expenses 1,980,000 1,800,000 2,600,000 2,600,000 Research, Development & Demonstration - - - -
Project Expenses 73,000 60,000 200,000 200,000
Building Electrification - - - -
Project Expenses 110,000 430,000 500,000 750,000
PBP Labor 250,000 270,000 300,000 300,000
Total PBP Charges $2,430,000 $2,570,000 $4,100,000 $4,350,000 City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 138 Back to TOCPacket Pg. 370
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Five-Year Financial Plan (2025-2030)
The Electric Utility’s financial plan, outlined below for the current year and the subsequent five years is summarized in the table below
Five-Year Plan FY 2025-26 FY 2026-27 FY 2027-28 FY 2028-29 FY 2029-30 Electric Utility Fund Beginning Balance ($ Mil) $ 59.4 $ 59.2 $ 64.7 $ 62.9 $ 58.7 Rate Adjustments 5% 5% 5% 5% 5%
Revenues ($ Mil)
Retail Electric Sales 146.7 155.7 165.7 177.2 189.9
Wholesale Electric Sales 13.4 12.6 13.8 17.1 16.9
Miscellaneous Income 8.8 9.0 9.3 9.5 9.8
Total 168.9 177.3 188.9 203.8 216.6
Operating Expenses ($ Mil)
Power Supply 81.4 82.4 92.4 101.1 104.5
System Administration 24.7 25.2 25.9 26.7 27.5
Transmission and Distribution 34.6 35.7 36.8 37.9 39.1
Total 140.7 143.4 155.2 165.8 171.0
Net Operating Revenue 28.3 34.0 33.7 38.0 45.6
Total Net Debt Service 18.6 19.5 18.5 19.1 19.6
Revenue Remaining after Debt Service 9.6 14.5 15.1 18.9 26.0 Other Revenues & Expenses
Miscellaneous 1.0 1.0 1.0 1.0 1.0
Bond Proceeds 19.0 20.1 7.3 - -
Capital Projects (19.0) (20.1) (15.2) (14.0) (14.0)
In-Lieu (6.0) (6.9) (7.1) (7.3) (7.4)
Rolling Stock, Major Plant Maintenance (4.9) (3.1) (3.0) (3.0) (3.1) Total (9.9) (9.0) (16.9) (23.2) (23.5)
Increase (Decrease) in Funds ($ Mil) (0.2) 5.5 (1.8) (4.2) 2.5 Electric Utility Fund Ending Balance ($ Mil) $ 59.2 $ 64.7 $ 62.9 $ 58.7 $ 61.2 Reserves (Days of Cash on Hand) 148 161 145 127 128
Debt Service Coverage Ratio 1.57 1.79 1.87 2.04 2.38
Affordability KPI (Target <2.5% of Median Income) 1.84% 1.91% 1.99% 2.07% 2.16% A key assumption in the previous plan was a return to the Federal Reserve's long-run inflation target of 2%. While the Fed remains committed to this target, recent economic conditions have introduced uncertainties. As of early 2025, inflation has moderated but remains slightly above the 2% target, with core Personal Consumption Expenditures (PCE) inflation at 2.8%.

Consequently, the current five-year plan uses a target inflation rate of 3%. Assuming 3% for future projections is a prudent approach, considering ongoing inflationary pressures and uncertainties related to global supply chains, recent tariff implementations, and geopolitical factors. Other assumptions include bond-funding capital outlay, and excluding Power Supply, only expending approximately 90% of O&M and Personnel appropriations. The days of cash on hand are projected to be 148 days in FY26 and 161 days in FY27. While both projections exceed the required minimum level of 75 days, in FY26, it falls below the goal of 150 days. The debt service coverage ratio is expected to be 1.57 times in FY26 and 1.79 times in FY27. Although the FY26 and FY27 projections are below the required minimum of 1.80 times, the Financial Policy recognizes a practical range of acceptable results, balancing cash flow needs with reserve levels. The Utility’s Affordability KPI remains well within the target range throughout the five years.

City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 139 Back to TOC
Packet Pg. 371
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Performance Measures and Workload Indicators
Workload Indicators
The table below indicates various measures of growth in the number of customers to be served, the level of service required in capacity and energy, and the continued development of the City’s electric service territory.

Utility
2023-24 2024-25 2025-26 2026-27
Workload Indicators Actual Estimated Projected Projected Peak Demand (MW) 234 241 235 235
Gigawatt-Hour Sales 737 771 743 751
Subtransmission Line Miles 72 72 72 72
Distribution Line Miles 761 765 769 773
Customer Service
2023
-24 2024-25 2025
-26 2026
-27
Workload I
ndicators
Actual Estimated Projected Projected
Electric customer
s billed monthly 45,834 47,454 48,300 49,200
Water custome
rs billed monthly 29,288 30,480 31,050 31,700
Total amou
nt billed (all utilities) $222
,964,224 $248
,234,107 $260
,000,000 $280
,000,000
Payme
nt transactions - credit card 244,85
5 262,91
6 273,75
0 28,500
Electronic fund
s transfer/EBox payment 184,46
8 203,86
8 217,20
0 230,00
0 Total w
alk-in traffic - cashiers 26,671 18,335
* 18,000 16,500
Payme
nt transactions - mailed 115,79
7 106,36
3 97,400 90,000
Customer
Service phone calls received 84,417 85,000 82,000 80,000 Call Center's ave
rage wait time (minutes:seconds) 0:28 0:35 0:40 0:40
Call Center's ave
rage time per call (minutes:seconds) 5:33 5:45 5:05 5:05 Call Center's calls abandoned 3.2% 2.90% 5.0% 5.0%
Call Center's ave
rage grade of service 82% 84% 80% 80%
Electric mete
r reads 573,36
0 577,62
5 586,30
0 595,00
0 Water me
ter reads 376,15
6 378,12
0 380,70
0 383,30
0 Utility service
requests 43,577 46,917 50,000 52,000
Utility service
miles logged 139,23
8 145,00
0 145,00
0 145,00
0 Error ratio per 1,000
meters read 0.53 0.52 0.50 0.50
City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 140 Back to TOCPacket Pg. 372
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Performance Measures
The table below shows numerous standard measurements of utility performance. The measures include staff ’s effectiveness in providing safe, reliable electric service at competitive prices to consumers and various ratios showing the utility’s financial health.
2023-24 2024-25 2025-26 2026-27
Performance Measures Actual Estimated Projected Projected Subtransmission and distribution system expense per customer (1) $768 $769 $979 $977 Electric retail kWh sales/electric worker hours (3) 1,737 1,824 1,767 1,789 Number of customers per electric employee (2) 225 235 239 244 Electric service reliability (4)(5) 99.998 99.999 99.999 99.999 SAIFI (includes major events) (5)(6)(9) 0.26 0.41 0.39 0.37 SAIDI (includes major events) (5)(7)(9) 34.0 37.5 35.6 33.8 CAIDI (includes major events) (5)(8)(9) 165.40 84 79.80 75.81 Redding Power Plant availability % 87.6 90 90 90
Redding Power startup success % 95.2 95 95 95
System average retail rates (ȼ/kWh) 17.8 18.7 19.8 20.7 Total retail GWh available for use 730 766 743 751
Cost of power, cents/kWh (10) 4.15 5.78 6.25 6.43
Debt to total assets ratio 0.26 0.4 0.37 0.33
Total operating expenses to total expense ratio 0.92 0.9 0.89 0.89 Days of cash on hand 110 155 148 161
Retail revenue as a percent of total revenue 78% 84% 87% 88% Notes:

1. Total O&M expenses and all General System Improvements, excluding debt service, capital projects, and In-lieu payments.

2. The number of workers represents the full-time equivalent of Electric Utility employees. Therefore, all authorized positions are represented but may not necessarily be filled. Part-time employees are included based on their proportional number of hours worked compared to full- time employees.

3. Worker hours are computed by multiplying the number of full-time equivalent employees by 2080 hours.

4. Total customer minutes minus total customer outage minutes, and the resultant divided by the total customer minutes and expressed in percent. U.S. Energy Information Administration’s Annual Electric Power Industry Report regional average for 2023 was 99.9843.

5. Based upon a calendar year summary.

6. SAIFI - System Average Interruption Frequency Index. The total number of customer interruptions is divided by the total number of customers served. The U.S. Energy Information Administration’s Annual Electric Power Industry Report regional average for 2023 was

0.64. 7. SAIDI – System Average Interruption Duration Index. This is the sum of all interruption durations divided by the total number of customers. The U.S. Energy Information Administration’s Annual Electric Power Industry Report regional average for 2023 was 82.85.

8. CAIDI – Customer Average Interruption Duration Index. This is the sum of all interruption durations divided by the total number of customer interruptions. The U.S. Energy Information Administration’s Annual Electric Power Industry Report regional average for 2023 was 136.74.

9. Major events/storms are defined as an event where 10 percent or more of City customers were “outaged” during a 48-hour period.

10. Based on line 108 of the Production Cost Model FY26-FY30 of April 1, 2025.

11. Projected values exclude events requiring mutual aid.

City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 141 Back to TOCPacket Pg. 373
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) This page left intentionally blank.

City of Redding Biennial Budget - Fiscal Years Ending June 30, 2026 and 2027 142 Back to TOCPacket Pg. 374
Attachment: 2026-2027 Biennial Budget - REU ONLY (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

P.O. Box 496701 3611 Avtech Parkway, Redding, California, 96049-6071 530.339.7300 Fax 530.339.7389

POWERING A STRONG COMMUNITY
reupower.com

Date: Feb 11, 2026

From: Nick Zettel, Director of Electric Utility
Through: Kari Kibler, Interim City Manager
To: Honorable Mayor and City Council
Subject: Update on 2026 Rate Case

Honorable Mayor and City Council Members:

The purpose of this memo is to provide an update on the utility’s proposed rate increase. REU’s current biennial budget, adopted by the Council on June 17, 2025, included a five-year financial plan that assumed 5% annual rate increases through 2030. After several months of detailed cost-reduction efforts and engagement with community members, the Utility has reduced the proposed rate increases to below

4.5% annually through 2029, with a 2% inflationary estimate in 2030. These cost savings efforts have resulted in a total 5% rate reduction over the 5-year planning term. Only the 4.5% annual rate increases through 2029 are being proposed at this time.

Why a Rate Adjustment is Essential
REU is committed to providing safe and dependable power, but several critical factors are driving a necessary increase in the cost of service to maintain system stability.

1. Surging Power Supply Costs: The cost of generating and purchasing electricity is projected to exceed $100 million annually by 2030, an increase of more than $20 million per year. These rising costs are driven by factors largely outside the City's control (supply down, demand up, and incentives gone).

2. Modernizing Aging Infrastructure: Much of Redding’s electric system was built a half-century ago and has reached the end of its useful life. Major capital outlay is required to replace and modernize this infrastructure to reduce outages, improve safety, and prevent costly emergency repairs. The Utility issued $70 million of debt in 2025 to meet these needs, with average annual payments of $4 million.

3. Unfunded Regulatory Mandates: REU must comply with extensive California clean energy requirements, such as the Renewable Portfolio Standard (RPS) and Greenhouse Gas (GHG) reduction goals. These mandates are unfunded, meaning the utility must cover the continuous investment required through its rate structure.

4. Wildfire Mitigation and Grid Safety: To protect the community, REU is significantly increasing investments in vegetation management, grid hardening, and technology solutions. Annual costs for wildfire mitigation efforts alone are projected to increase by $2.0 million by 2027, including an additional $1.3 million for Redding Fire Department and Community Services (Parks) staffing.

5. Inflation and Operational Pressures: Global inflation has drastically increased the price of essential materials. For example, the purchase cost for utility trucks and equipment saw a 75% increase between 2020 and 2025, and the cost of electric system materials and supplies have increased between 35% (poles) and 100% (transformers).

Without these periodic adjustments, the utility risks credit downgrades due to liquidity issues and debt covenants, reduced reliability, and deferred maintenance. Even with these changes, REU is committed to offering the community the lowest residential rates compared to neighboring providers.

Packet Pg. 375
Attachment: Council Memo - REU Rates 2026 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

P.O. Box 496701 3611 Avtech Parkway, Redding, California, 96049-6071 530.339.7300 Fax 530.339.7389

POWERING A STRONG COMMUNITY
reupower.com

Community Engagement Panel
As part of the Utility’s proactive outreach, community members representing a cross-section of REU’s customer makeup participated in a two-part meeting series to discuss the foundations of not-for-profit public power, evaluate REU’s cost of service and review the proposed rate plan. This followed their participation in the development of the Utility’s Strategic Plan. The committee members were as follows:

Organization Name
North State Climate Action (Environmental) David Ledger (Board Member) Redding Rancheria (Large Commercial) Miranda Edwards-Favorite (Senior Director) Redding Chamber of Commerce (Commercial) Todd Jones, (President and CEO) Independent CPA Kurt Swanson (Owner)
Community Rev. & Dev. Corp (Low-income) Shelby Marocco (Vice President)

The panel’s charge was to answer the question: Does the Utility’s case for increasing rates make sense, and is the proposal fair and equitable?
Results
• Meeting #1 (Jan 26, 2026): Focused on Cost of Service and the technical basis for utility costs and revenue requirements. Meeting #2 (Jan 29, 2026): Focused on Rate Design and allocation of costs among customer classes to promote fairness.
• Staff presented a 4% annual increase plan; the panel viewed it as insufficient given power - supply volatility and external risks (e.g., drought). The panel unanimously supported a 4.5% annual target, primarily through volumetric charges, with most addition al revenue from the residential class, and to mitigate the impact to income-qualified households with Public Benefit Funds.
• After revised assumptions, added operating efficiencies, and deferral/cancellation of certain capital projects, staff incorporated ~4.25% average annual increases into the current plan. • Resulting average class impacts:
o Residential: 4.5% (avg. $6.75/mo), 1.7% for Residential discount program ($1.38/mo); o Small Commercial: 4.25%; and
o Large Commercial: 4.0%.
• The panel's consensus was yes, the Utility’s case for increasing rates makes sense, and the proposal is fair and equitable.

Next Steps
At the February 17, 2026, Council meeting, I will ask the Council to set a public hearing for March 3, 2026.

On February 26, 2026, workshops will be held in the Community Room at 12:00pm and 5:00pm, and information will be provided directly to community-based organizations. All rate information, including calculators, will be available on the City’s at cityofredding.gov/electricrates. In addition, notices will be posted in the Redding Record Searchlight.

Packet Pg. 376
Attachment: Council Memo - REU Rates 2026 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

P.O. Box 496701 3611 Avtech Parkway, Redding, California, 96049-6071 530.339.7300 Fax 530.339.7389

POWERING A STRONG COMMUNITY
reupower.com

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2024 AVERAGE COMMERCIAL RATE
(CENTS/KWH)
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Attachment: Council Memo - REU Rates 2026 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

P.O. Box 496701 3611 Avtech Parkway, Redding, California, 96049-6071 530.339.7300 Fax 530.339.7389

POWERING A STRONG COMMUNITY
reupower.com
2026 BUDGET

2029 FORECAST

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Attachment: Council Memo - REU Rates 2026 (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Total Monthly Usage (kWh) 500 700 800 900 1,000 1,100
CURRENT BILL 2025
Network Access Charge ($40.00/Month) 40.00 $ 40.00 $ 40.00 $ 40.00 $ 40.00 $ 40.00 $ Energy Charge ($0.1492/kWh) 74.60 $ 104.44 $ 119.36 $ 134.28 $ 149.20 $ 164.12 $ Federal Environmental Charge ($.0010/kWh) 0.50 $ 0.70 $ 0.80 $ 0.90 $ 1.00 $ 1.10 $ State Surcharge ($.0003/kWh) 0.15 $ 0.21 $ 0.24 $ 0.27 $ 0.30 $ 0.33 $ Total Electic Bill $ 115.25$ 145.35 $ 160.40 $ 175.45 $ 190.50 $ 205.55 $ PROPOSED BILL 2026
Network Access Charge ($41.00/Month) 41.00 $ 41.00 $ 41.00 $ 41.00 $ 41.00 $ 41.00 $ Energy Charge ($0.1563/kWh) 78.14 $ 109.40 $ 125.03 $ 140.66 $ 156.29 $ 171.92 $ Federal Environmental Charge ($.0010/kWh) 0.50 $ 0.70 $ 0.80 $ 0.90 $ 1.00 $ 1.10 $ State Surcharge ($.0003/kWh) 0.15 $ 0.21 $ 0.24 $ 0.27 $ 0.30 $ 0.33 $ Total Electric Bill $ 119.79$ 151.31 $ 167.07 $ 182.83 $ 198.59 $ 214.35 $ $ Change In Total Electric Bill in 2026 4.54$ 5.96 $ 6.67 $ 7.38 $ 8.09 $ 8.80 $ PROPOSED BILL 2027
Network Access Charge ($42.00/Month) 42.00 $ 42.00 $ 42.00 $ 42.00 $ 42.00 $ 42.00 $ Energy Charge ($0.1637/kWh) 81.86 $ 114.60 $ 130.97 $ 147.34 $ 163.71 $ 180.08 $ Federal Environmental Charge ($.0010/kWh) 0.50 $ 0.70 $ 0.80 $ 0.90 $ 1.00 $ 1.10 $ State Surcharge ($.0003/kWh) 0.15 $ 0.21 $ 0.24 $ 0.27 $ 0.30 $ 0.33 $ Total Electric Bill $ 124.51$ 157.51 $ 174.01 $ 190.51 $ 207.01 $ 223.51 $ $ Change In Total Electric Bill in 2027 4.71$ 6.20 $ 6.94 $ 7.68 $ 8.42 $ 9.17 $ PROPOSED BILL 2028
Network Access Charge ($43.00/Month) 43.00 $ 43.00 $ 43.00 $ 43.00 $ 43.00 $ 43.00 $ Energy Charge ($0.1723/kWh) 86.15 $ 120.61 $ 137.84 $ 155.07 $ 172.31 $ 189.54 $ Federal Environmental Charge ($.0010/kWh) 0.50 $ 0.70 $ 0.80 $ 0.90 $ 1.00 $ 1.10 $ State Surcharge ($.0003/kWh) 0.15 $ 0.21 $ 0.24 $ 0.27 $ 0.30 $ 0.33 $ Total Electric Bill $ 129.80$ 164.52 $ 181.88 $ 199.24 $ 216.61 $ 233.97 $ $ Change In Total Electric Bill in 2028 5.30$ 7.02 $ 7.88 $ 8.74 $ 9.59 $ 10.45 $ PROPOSED BILL 2029
Network Access Charge ($44.00/Month) 44.00 $ 44.00 $ 44.00 $ 44.00 $ 44.00 $ 44.00 $ Energy Charge ($0.1814/kWh) 90.68 $ 126.95 $ 145.08 $ 163.22 $ 181.35 $ 199.49 $ Federal Environmental Charge ($.0010/kWh) 0.50 $ 0.70 $ 0.80 $ 0.90 $ 1.00 $ 1.10 $ State Surcharge ($.0003/kWh) 0.15 $ 0.21 $ 0.24 $ 0.27 $ 0.30 $ 0.33 $ Total Electric Bill $ 135.33$ 171.86 $ 190.12 $ 208.39 $ 226.65 $ 244.92 $ $ Change In Total Electric Bill in 2029 5.52$ 7.33 $ 8.24 $ 9.14 $ 10.05 $ 10.95 $ Residential Bill Calculation Example
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Attachment: 2026 Residential Rates Example (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Total Monthly Usage (kWh) 500 600 800 900 1,000 1,100
CURRENT BILL 2025
Network Access Charge ($40.00/Month) 40.00$ 40.00$ 40.00$ 40.00$ 40.00$ 40.00$ Network Access Charge Credit ($20.00/Month) (20.00)$ (20.00)$ (20.00)$ (20.00)$ (20.00)$ (20.00)$ Energy Charge ($0.1492/kWh) 74.60$ 89.52$ 119.36$ 134.28$ 149.20$ 164.12$ Energy Discount ($0.0522/kWh) [450 kWh max] (23.50)$ (23.50)$ (23.50)$ (23.50)$ (23.50)$ (23.50)$ Federal Environmental Charge ($.0010/kWh) 0.50$ 0.60$ 0.80$ 0.90$ 1.00$ 1.10$ State Surcharge ($.0003/kWh) 0.15$ 0.18$ 0.24$ 0.27$ 0.30$ 0.33$ Total Electic Bill $ 71.75$ 86.80$ 116.90$ 131.95$ 147.00$ 162.05$ PROPOSED BILL 2026
Network Access Charge ($41.00/Month) 41.00$ 41.00$ 41.00$ 41.00$ 41.00$ 41.00$ Network Access Charge Credit ($21.00/Month) (21.00)$ (21.00)$ (21.00)$ (21.00)$ (21.00)$ (21.00)$ Energy Charge ($0.1563/kWh) 78.14$ 93.77$ 125.03$ 140.66$ 156.29$ 171.92$ Energy Discount ($0.0586/kWh) [450 kWh max] (26.37)$ (26.37)$ (26.37)$ (26.37)$ (26.37)$ (26.37)$ Federal Environmental Charge ($.0010/kWh) 0.50$ 0.60$ 0.80$ 0.90$ 1.00$ 1.10$ State Surcharge ($.0003/kWh) 0.15$ 0.18$ 0.24$ 0.27$ 0.30$ 0.33$ Total Electric Bill $ 72.42$ 88.18$ 119.70$ 135.45$ 151.21$ 166.97$ $ Change In Total Electric Bill in 2026 0.67$ 1.38$ 2.80$ 3.50$ 4.21$ 4.92$ PROPOSED BILL 2027
Network Access Charge ($42.00/Month) 42.00$ 42.00$ 42.00$ 42.00$ 42.00$ 42.00$ Network Access Charge Credit ($22.00/Month) (22.00)$ (22.00)$ (22.00)$ (22.00)$ (22.00)$ (22.00)$ Energy Charge ($0.1637/kWh) 81.86$ 98.23$ 130.97$ 147.34$ 163.71$ 180.08$ Energy Discount ($0.0655/kWh) [450 kWh max] (29.47)$ (29.47)$ (29.47)$ (29.47)$ (29.47)$ (29.47)$ Federal Environmental Charge ($.0010/kWh) 0.50$ 0.60$ 0.80$ 0.90$ 1.00$ 1.10$ State Surcharge ($.0003/kWh) 0.15$ 0.18$ 0.24$ 0.27$ 0.30$ 0.33$ Total Electric Bill $ 73.04$ 89.54$ 122.54$ 139.04$ 155.54$ 172.04$ $ Change In Total Electric Bill in 2027 0.62$ 1.36$ 2.84$ 3.59$ 4.33$ 5.07$ PROPOSED BILL 2028
Network Access Charge ($43.00/Month) 43.00$ 43.00$ 43.00$ 43.00$ 43.00$ 43.00$ Network Access Charge Credit ($23.00/Month) (23.00)$ (23.00)$ (23.00)$ (23.00)$ (23.00)$ (23.00)$ Energy Charge ($0.1723/kWh) 86.15$ 103.38$ 137.84$ 155.07$ 172.31$ 189.54$ Energy Discount ($0.0732/kWh) [450 kWh max] (32.95)$ (32.95)$ (32.95)$ (32.95)$ (32.95)$ (32.95)$ Federal Environmental Charge ($.0010/kWh) 0.50$ 0.60$ 0.80$ 0.90$ 1.00$ 1.10$ State Surcharge ($.0003/kWh) 0.15$ 0.18$ 0.24$ 0.27$ 0.30$ 0.33$ Total Electric Bill $ 73.85$ 91.21$ 125.93$ 143.29$ 160.65$ 178.01$ $ Change In Total Electric Bill in 2028 0.81$ 1.67$ 3.39$ 4.25$ 5.11$ 5.97$ PROPOSED BILL 2029
Network Access Charge ($44.00/Month) 44.00$ 44.00$ 44.00$ 44.00$ 44.00$ 44.00$ Network Access Charge Credit ($24.00/Month) (24.00)$ (24.00)$ (24.00)$ (24.00)$ (24.00)$ (24.00)$ Energy Charge ($0.1814/kWh) 90.68$ 108.81$ 145.08$ 163.22$ 181.35$ 199.49$ Energy Discount ($0.0816/kWh) [450 kWh max] (36.72)$ (36.72)$ (36.72)$ (36.72)$ (36.72)$ (36.72)$ Federal Environmental Charge ($.0010/kWh) 0.50$ 0.60$ 0.80$ 0.90$ 1.00$ 1.10$ State Surcharge ($.0003/kWh) 0.15$ 0.18$ 0.24$ 0.27$ 0.30$ 0.33$ Total Electric Bill $ 74.60$ 92.87$ 129.40$ 147.66$ 165.93$ 184.19$ $ Change In Total Electric Bill in 2029 0.75$ 1.66$ 3.47$ 4.37$ 5.28$ 6.18$ Residential Energy Discount Bill Calculation Example
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Attachment: 2026 Residential Energy Discount Example (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Total Monthly Usage (kWh) 2,000 2,500 3,000 3,500 15,000 0 CURRENT BILL 2025
Network Access Charge ($70.00/Month) 70.00 $ 70.00 $ 70.00 $ 70.00 $ 70.00 $ 70.00 $ Energy Charge ($0.1649/kWh) 329.80 $ 412.25 $ 494.70 $ 577.15 $ 2,473.50$ - $ Federal Environmental Charge ($.0010/kWh) 2.00 $ 2.50 $ 3.00 $ 3.50 $ 15.00 $ - $ State Surcharge ($.0003/kWh) 0.60 $ 0.75 $ 0.90 $ 1.05 $ 4.50 $ - $ Total Electic Bill $ 402.40$ 485.50 $ 568.60 $ 651.70 $ 2,563.00$ 70.00 $ PROPOSED BILL 2026
Network Access Charge ($72.00/Month) 72.00 $ 72.00 $ 72.00 $ 72.00 $ 72.00 $ 72.00 $ Energy Charge ($0.1725/kWh) 344.97 $ 431.21 $ 517.46 $ 603.70 $ 2,587.28$ - $ Federal Environmental Charge ($.0010/kWh) 2.00 $ 2.50 $ 3.00 $ 3.50 $ 15.00 $ - $ State Surcharge ($.0003/kWh) 0.60 $ 0.75 $ 0.90 $ 1.05 $ 4.50 $ - $ Total Electric Bill $ 419.57$ 506.46 $ 593.36 $ 680.25 $ 2,678.78$ 72.00 $ $ Change In Total Electric Bill in 2026 17.17$ 20.96 $ 24.76 $ 28.55 $ 115.78 $ 2.00 $ PROPOSED BILL 2027
Network Access Charge ($74.00/Month) 74.00 $ 74.00 $ 74.00 $ 74.00 $ 74.00 $ 74.00 $ Energy Charge ($0.1804/kWh) 360.84 $ 451.05 $ 541.26 $ 631.47 $ 2,706.30$ - $ Federal Environmental Charge ($.0010/kWh) 2.00 $ 2.50 $ 3.00 $ 3.50 $ 15.00 $ - $ State Surcharge ($.0003/kWh) 0.60 $ 0.75 $ 0.90 $ 1.05 $ 4.50 $ - $ Total Electric Bill $ 437.44$ 528.30 $ 619.16 $ 710.02 $ 2,799.80$ 74.00 $ $ Change In Total Electric Bill in 2027 17.87$ 21.84 $ 25.80 $ 29.77 $ 121.01 $ 2.00 $ PROPOSED BILL 2028
Network Access Charge ($77.00/Month) 77.00 $ 77.00 $ 77.00 $ 77.00 $ 77.00 $ 77.00 $ Energy Charge ($0.1885/kWh) 377.08 $ 471.35 $ 565.62 $ 659.89 $ 2,828.08$ - $ Federal Environmental Charge ($.0010/kWh) 2.00 $ 2.50 $ 3.00 $ 3.50 $ 15.00 $ - $ State Surcharge ($.0003/kWh) 0.60 $ 0.75 $ 0.90 $ 1.05 $ 4.50 $ - $ Total Electric Bill $ 456.68$ 551.60 $ 646.52 $ 741.44 $ 2,924.58$ 77.00 $ $ Change In Total Electric Bill in 2028 19.24$ 23.30 $ 27.36 $ 31.42 $ 124.78 $ 3.00 $ PROPOSED BILL 2029
Network Access Charge ($80.00/Month) 80.00 $ 80.00 $ 80.00 $ 80.00 $ 80.00 $ 80.00 $ Energy Charge ($0.1970/kWh) 394.05 $ 492.56 $ 591.07 $ 689.58 $ 2,955.34$ - $ Federal Environmental Charge ($.0010/kWh) 2.00 $ 2.50 $ 3.00 $ 3.50 $ 15.00 $ - $ State Surcharge ($.0003/kWh) 0.60 $ 0.75 $ 0.90 $ 1.05 $ 4.50 $ - $ Total Electric Bill $ 476.65$ 575.81 $ 674.97 $ 774.13 $ 3,054.84$ 80.00 $ $ Change In Total Electric Bill in 2029 19.97$ 24.21 $ 28.45 $ 32.69 $ 130.26 $ 3.00 $ Small Commercial Bill (E2) Calculation Example
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Attachment: 2026 Small Commercial Calculator Example (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Total Monthly Usage (kWh) 15,000 25,000 35,000 40,000 45,000 0 Total Demand Usage (kW) 90 90 90 90 90 0
CURRENT BILL 2025
Network Access Charge ($95.00/Month) 95.00 $ 95.00 $ 95.00 $ 95.00 $ 95.00 $ 95.00 $ Demand Charge ($21.50/kW) 1,935.0 0$ 1,935.0 0$ 1,935.0 0$ 1,935.0 0$ 1,935.0 0$ - $ Energy Charge ($0.1086/kWh) 1,629.0 0$ 2,715.0 0$ 3,801.0 0$ 4,344.0 0$ 4,887.0 0$ - $ Federal Environmental Charge ($.0010/kWh) 15.00 $ 25.00 $ 35.00 $ 40.00 $ 45.00 $ - $ State Surcharge ($.0003/kWh) 4.50$ 7.50 $ 10.50 $ 12.00 $ 13.50 $ - $ Total Electic Bill $ 3,678.50$ 4,777.50 $ 5,876.50 $ 6,426.00 $ 6,975.50 $ 95.00 $ PROPOSED BILL 2026
Network Access Charge ($95.00/Month) 95.00 $ 95.00 $ 95.00 $ 95.00 $ 95.00 $ 95.00 $ Demand Charge ($21.50/kW) 1,935.0 0$ 1,935.0 0$ 1,935.0 0$ 1,935.0 0$ 1,935.0 0$ - $ Energy Charge ($0.1158/kWh) 1,736.51 $ 2,894.19 $ 4,051.87 $ 4,630.7 0$ 5,209.5 4$ - $ Federal Environmental Charge ($.0010/kWh) 15.00 $ 25.00 $ 35.00 $ 40.00 $ 45.00 $ - $ State Surcharge ($.0003/kWh) 4.50$ 7.50 $ 10.50 $ 12.00 $ 13.50 $ - $ Total Electric Bill $ 3,786.01$ 4,956.69 $ 6,127.37 $ 6,712.70 $ 7,298.04 $ 95.00 $ $ Change In Total Electric Bill in 2026 107.51$ 179.19 $ 250.87 $ 286.7 0$ 322.5 4$ - $ PROPOSED BILL 2027
Network Access Charge ($95.00/Month) 95.00 $ 95.00 $ 95.00 $ 95.00 $ 95.00 $ 95.00 $ Demand Charge ($21.50/kW) 1,935.0 0$ 1,935.0 0$ 1,935.0 0$ 1,935.0 0$ 1,935.0 0$ - $ Energy Charge ($0.1234/kWh) 1,851.12 $ 3,085.21 $ 4,319.29 $ 4,936.33 $ 5,553.37 $ - $ Federal Environmental Charge ($.0010/kWh) 15.00 $ 25.00 $ 35.00 $ 40.00 $ 45.00 $ - $ State Surcharge ($.0003/kWh) 4.50$ 7.50 $ 10.50 $ 12.00 $ 13.50 $ - $ Total Electric Bill $ 3,900.62$ 5,147.71 $ 6,394.79 $ 7,018.33 $ 7,641.87 $ 95.00 $ $ Change In Total Electric Bill in 2027 114.61$ 191.02 $ 267.42 $ 305.63 $ 343.83 $ - $ PROPOSED BILL 2028
Network Access Charge ($95.00/Month) 95.00 $ 95.00 $ 95.00 $ 95.00 $ 95.00 $ 95.00 $ Demand Charge ($21.75/kW) 1,957.5 0$ 1,957.5 0$ 1,957.5 0$ 1,957.5 0$ 1,957.5 0$ - $ Energy Charge ($0.1308/kWh) 1,962.19 $ 3,270.32 $ 4,578.45 $ 5,232.51 $ 5,886.57 $ - $ Federal Environmental Charge ($.0010/kWh) 15.00 $ 25.00 $ 35.00 $ 40.00 $ 45.00 $ - $ State Surcharge ($.0003/kWh) 4.50$ 7.50 $ 10.50 $ 12.00 $ 13.50 $ - $ Total Electric Bill $ 4,034.19$ 5,355.32 $ 6,676.45 $ 7,337.01 $ 7,997.57 $ 95.00 $ $ Change In Total Electric Bill in 2028 133.57$ 207.61 $ 281.6 6$ 318.6 8$ 355.7 0$ - $ PROPOSED BILL 2029
Network Access Charge ($95.00/Month) 95.00 $ 95.00 $ 95.00 $ 95.00 $ 95.00 $ 95.00 $ Demand Charge ($22.00/kW) 1,980.0 0$ 1,980.0 0$ 1,980.0 0$ 1,980.0 0$ 1,980.0 0$ - $ Energy Charge ($0.1387/kWh) 2,079.92 $ 3,466.5 4$ 4,853.15 $ 5,546.4 6$ 6,239.77 $ - $ Federal Environmental Charge ($.0010/kWh) 15.00 $ 25.00 $ 35.00 $ 40.00 $ 45.00 $ - $ State Surcharge ($.0003/kWh) 4.50$ 7.50 $ 10.50 $ 12.00 $ 13.50 $ - $ Total Electric Bill $ 4,174.42$ 5,574.04 $ 6,973.65 $ 7,673.46 $ 8,373.27 $ 95.00 $ $ Change In Total Electric Bill in 2029 140.23$ 218.72 $ 297.21 $ 336.45 $ 375.69 $ - $ Large Commercial Bill Calculation Example
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Attachment: 2026 Large Commercial Calculator Example (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

City of Redding Electric Utility Rates FAQ's

1. What does my City of Redding Utility bill cover?
a. Your City of Redding Utility Bill includes Electricity, Water, Garbage (Solid Waste), and Wastewater Collection & Treatment (Sewer). To learn more about your utility statement, visit the Understanding My Bill page.

b. Only your Electric rates would be impacted by this proposed rate increase.

However, the City Council has adopted rate increases for other utilities and may propose additional increases for those utilities in the future.

2. Why is the City of Redding proposing to increase electric utility rates?

a. HIGHER POWER SUPPLY COSTS – Electricity generation and purchase costs continue to rise due to weather variability, reduced hydropower deliveries, and higher natural gas generation costs. Annual power supply expenses— including Redding Power Plant operations — are expected to increase by more than $20 million, surpassing $100 million by 2030.

b. STRATEGIC INVESTMENT IN RESILIENT AND SUSTAINABLE
INFRASTRUCTURE COSTS – Investing in the replacement and modernization of aging electric infrastructure is essential to maintaining safe and reliable service for our customers. Much of the utility’s system was built decades ago and requires ongoing reinvestment to reduce outages, improve safety, and ensure dependable power delivery as equipment reaches the end of its useful life. Proactive infrastructure investment helps prevent costly emergency repairs, stre ngthens system resilience, and ensures Redding Electric Utility can continue providing reliable service today and well into the future.

c. INFLATION AND OPERATIONAL PRESSURES & REGULATORY MANDATES Rising costs driven by inflation and California clean energy mandates continue to impact electric utility operations. Increased prices for labor, materials, equipment, and contracted services have raised the cost of maintaining and operating the electric system. At the same time, state clean energy and emissions reduction requirements require ongoing investment in renewable resources, grid upgrades, and regulatory compliance, placing additional upwar d pressure on costs while maintaining reliable service.

3. How much would this rate increase impact my bill?
On average, standard residential customers are expected to see a monthly increase of approximately $6.75 beginning in 2026, followed by additional average monthly increases of approximately $7.00-$8.25 in 2027-2029.

Packet Pg. 383
Attachment: 2026 REU Rate Increase FAQs (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

4. Will these rate changes have the same impact on commercial customers as they do on residential?
a. Commercial customers will experience varying impacts due to differences in energy usage and business size. Please visit the following webpage to see how these rate increases would affect your monthly bill.

5. When would the proposed rate increase go into effect? a. If approved, the rate increase will go into effect on April 1, 2026.

6. How does my bill compare to other local electric utility providers? a. Below is a chart reflective of current residential and estimated future rates compared to PG&E and Shasta Lake City. The City of Redding will continue offering our community the lowest residential rates.

7. How do I learn more about this proposed rate increase? a. You can visit the website at City of Redding Rates Website or call Customer Service at (530) 339-7200 for additional information.

8. Are there cost-saving opportunities?
a. REU offers programs and services to help you manage and better understand your electric bill. To find out more about our Residential Energy Discount program, please visit our website at Rates & Fees or Payment Assistance Programs.

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Attachment: 2026 REU Rate Increase FAQs (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

3611 AVTECH PARKWAY
PO BOX 496071
REDDING, CA 96002

FOR IMMEDIATE RELEASE
February 18, 2026
CONTACT:

Joseph Bowers, Assistant Director – Resources
530-339-7377

Redding Electric Utility to Discuss Proposed Rate Adjustments for 2026-2029 The City of Redding’s Electric Utility (REU) is committed to managing costs responsibly and operating efficiently while continuing to provide safe, reliable, and affordable electric service to the community. As a community - owned, not-for-profit utility, REU exists solely to serve local customers and maintain long-term financial stability.

To preserve its strong record of electric reliability, invest in critical infrastructure, manage rising power supply and operating costs, and comply with California clean energy requirements, the City of Redding will present recommended electric rate adjustments at a public hearing on Tuesday, March 3, 2026, at 6:00 p.m. in the Redding City Council Chambers, located at 777 Cypress Avenue.

Why is it necessary to consider rate adjustments at this time? • HIGHER POWER SUPPLY COSTS – The cost of generating and purchasing electricity continues to rise due to factors largely outside the City’s control. Increased weather variability, drought conditions, and higher natural gas prices have significantly driven up fuel and power costs. Annual power supply costs, including Redding Power Plant operations and maintenance, are projected to increase by more than $20 million, exceeding $100 million by 2030.
• STRATEGIC INVESTMENT IN RESILIENT AND SUSTAINABLE INFRASTRUCTURE COSTS – Investing in the replacement and modernization of aging electric infrastructure is essential to maintaining safe and reliable service for our customers. Much of the utility’s system was built decades ago and requires ongoing reinvestment to reduce outages, improve safety, and ensure dependable power delivery as equipment reaches the end of its useful life. Proactive infrastructure investment helps prevent costly emergency repairs, strengthens system resilience, and ensures Redding Electric Utility can continue providing reliable service today and well into the future. • INFLATION AND OPERATIONAL PRESSURES & REGULATORY MANDATES – Rising costs driven by inflation and California clean energy mandates continue to impact electric utility operations. Increased prices for labor, materials, equipment, and contracted services have raised the cost of maintaining and operating the electric system. At the same time, state clean energy and emissions reduction requirements require ongoing investment in renewable resources, grid upgrades, and regulatory compliance, placing additional upward pressure on costs while maintaining reliable service.

If approved, REU would implement an average electric rate increase of 4.25% effective April 1, 2026, followed by additional 4.25% adjustments on January 1 of 2027 -2029. For a typical residential customer, this equates to an average increase of approximately $6.75 per month beginning in 2026, with additional average increases of about Packet Pg. 385
Attachment: 2026 Rates Press Release (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments)

3611 AVTECH PARKWAY
PO BOX 496071
REDDING, CA 96002

$7.00-$8.25 per month in each subsequent year. Even with these proposed adjustments, Redding Electric Utility rates are expected to remain among the most affordable in California.

Recognizing the impacts of elevated inflation, REU remains committed to supporting low-income households. To help mitigate bill impacts, staff will recommend increases to the benefits provided through the Residential Energy Discount program for eligible customers. REU also encourages customers to take advantage of available energy - efficiency programs, conservation tools, and practical tips to help manage energy use at home and in the workplace.

REU is committed to transparency and partnership with the community throughout this rate review process.

Additional information regarding the proposed rate adjustments, anticipated customer impacts, and available programs and services can be found at cityofredding.gov/electricrates. Community members are also encouraged to attend upcoming public workshops or participate in the public hearing to learn more and share input.

Public workshops are scheduled for:

Thursday, February 26, 2026
12:00 PM and 5:00 PM
Redding City Hall,
Community Room
777 Cypress Avenue
Redding, CA 96001

Packet Pg. 386
Attachment: 2026 Rates Press Release (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Division Personnel (1)
Materials,
Supplies &
Services
Capital
Outlay (2)
Debt
Service (3) Total Wholesale Sales
Maintenance, Supplies
& Services Less
Wholesale Sales (4)
FY 2029-30 Projected 50,189,796$ 121,805,390 $ 9,286,000 $ 19,190,795 $ 200,471,982 $ 16,928,010 $ 104,877,380 $ FY 2028-29 Projected 49,205,683$ 118,303,676 $ 9,104,000 $ 18,690,295 $ 195,303,654 $ 17,103,420 $ 101,200,256 $ FY 2027-28 Projected 48,240,865$ 110,070,540 $ 8,925,000 $ 18,139,545 $ 185,375,950 $ 13,839,450 $ 96,231,090 $ FY 2026-27 Requested * 47,294,966$ 99,986,830 $ 11,610,000 $ 19,093,045 $ 177,984,841 $ 12,610,000 $ 87,376,830 $ FY 2025-26 Requested * 47,883,325$ 97,425,590 $ 18,952,000 $ 18,633,795 $ 182,894,710 $ 13,419,000 $ 84,006,590 $ FY 2024-25 Actual * 44,592,574$ 98,589,892 $ 15,996,001 $ 14,762,143 $ 173,940,610 $ 23,734,315 $ 74,855,577 $ FY 2023-24 Actual * 44,430,319$ 102,544,363 $ 14,014,972 $ 14,298,520 $ 175,288,174 $ 31,849,696 $ 70,694,667 $ FY 2022-23 Actual 33,349,452 $ 131,259,526 $ 13,292,383 $ 14,304,520 $ 192,205,881 $ 45,737,091 $ 85,522,435 $ FY 2021-22 Actual 31,159,294 $ 108,738,056 $ 14,467,688 $ 12,785,570 $ 167,150,608 $ 29,586,524 $ 79,151,532 $ FY 2020-21 Actual 28,747,244 $ 101,383,522 $ 15,008,200 $ 12,780,320 $ 157,919,286 $ 25,011,185 $ 76,372,337 $ FY 2029-30 Projected 2,991,270$ 6,288,916 $ - $ - $ 9,280,185$ FY 2028-29 Projected 2,929,745$ 6,159,565 $ - $ - $ 9,089,310$ FY 2027-28 Projected 2,869,486$ 6,032,875 $ - $ - $ 8,902,360$ FY 2026-27 Requested * 2,810,466$ 5,908,790 $ - $ - $ 8,719,256$ FY 2025-26 Requested * 2,703,606$ 5,653,230 $ - $ - $ 8,356,836$ FY 2024-25 Actual * 2,659,425$ 5,383,775 $ - $ - $ 8,043,200$ FY 2023-24 Actual * 3,103,329$ 5,548,523 $ - $ - $ 8,651,852$ FY 2022-23 Actual 3,042,794 $ 4,615,508 $ - $ - $ 7,658,302$ FY 2021-22 Actual 2,705,547 $ 4,088,316 $ - $ - $ 6,793,863$ FY 2020-21 Actual 2,363,121 $ 4,119,546 $ - $ - $ 6,482,667$ FY 2029-30 Projected 1,190,506$ 472,436 $ - $ - $ 1,662,941$ FY 2028-29 Projected 1,166,019$ 462,719 $ - $ - $ 1,628,738$ FY 2027-28 Projected 1,142,036$ 453,201 $ - $ - $ 1,595,238$ FY 2026-27 Requested * 1,118,547$ 443,880 $ - $ - $ 1,562,427$ FY 2025-26 Requested * 1,094,366$ 412,952 $ - $ - $ 1,507,318$ FY 2024-25 Actual * 1,091,043$ 230,219 $ - $ - $ 1,321,262$ FY 2023-24 Actual * 1,028,388$ 272,487 $ 23,678 $ - $ 1,324,553$ FY 2022-23 Actual 2,159,723 $ 252,888 $ - $ - $ 2,412,611$ FY 2021-22 Actual 1,913,943 $ 416,703 $ 4,499 $ - $ 2,335,145$ FY 2020-21 Actual 1,678,396 $ 227,064 $ - $ - $ 1,905,460$ FY 2029-30 Projected 54,371,572$ 128,566,742 $ 9,286,000 $ 19,190,795 $ 211,415,108 $ 16,928,010 $ 104,877,380 $ FY 2028-29 Projected 53,301,447$ 124,925,960 $ 9,104,000 $ 18,690,295 $ 206,021,701 $ 17,103,420 $ 101,200,256 $ FY 2027-28 Projected 52,252,388$ 116,556,616 $ 8,925,000 $ 18,139,545 $ 195,873,548 $ 13,839,450 $ 96,231,090 $ FY 2026-27 Requested * 51,223,979$ 106,339,500 $ 11,610,000 $ 19,093,045 $ 188,266,524 $ 12,610,000 $ 87,376,830 $ FY 2025-26 Requested * 51,681,297$ 103,491,772 $ 18,952,000 $ 18,633,795 $ 192,758,864 $ 13,419,000 $ 84,006,590 $ FY 2024-25 Actual * 48,343,042$ 104,203,886 $ 15,996,001 $ 14,762,143 $ 183,305,072 $ 23,734,315 $ 74,855,577 $ FY 2023-24 Actual * 48,562,036$ 108,365,373 $ 14,038,650 $ 14,298,520 $ 185,264,579 $ 31,849,696 $ 70,694,667 $ FY 2022-23 Actual 38,551,969 $ 136,127,922 $ 13,292,383 $ 14,304,520 $ 202,276,794 $ 45,737,091 $ 85,522,435 $ FY 2021-22 Actual 35,778,784 $ 113,243,075 $ 14,472,187 $ 12,785,570 $ 176,279,616 $ 29,586,524 $ 79,151,532 $ FY 2020-21 Actual 32,788,761 $ 105,730,132 $ 15,008,200 $ 12,780,320 $ 166,307,413 $ 25,011,185 $ 76,372,337 $ * FY 2027 Requested Personnel includes corrections for clerical errors made during the budget development. City Finance plans to correct these errors at mid-cycle. (1) 2027-2030 includes leaving select vacancies unfilled and not backfilling certain planned retirements, generating approximately $1.6 million in annual savings. (2) 2026-2030 include reductions to planned capital outlay by approximately $24 million over the five-year planning horizon. (3) 2027-2030 Includes assumed savings from Refinancing the Utility's 2015 bonds, which became callable in December 2025. * FY 2024-2027 Materials, Supplies & Services: includes corrections for clerical errors made during the budget development. (4) It is very important to note that Materials, Supplies, and Services are higher in prior years due to wholesale activity. To truly trend out the rising cost of materials, supplies, and services, you must net them against wholesale sales earned through the purchase of additional resources to make those sales.

Department's Projections/Budgets/Actuals Separated into Major Expenditure Groups Electric
Customer Service
Field Services
Total
Packet Pg. 387
Attachment: FY2021-FY2030 Budget_Actuals Table (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

1 From Long-Term Resources
To Joseph Bowers, Assistant Director - Resources
Title Production Cost Model 10-Year Outlook, FY26-FY35
Date February 19, 2026
Background
Long-term Resources prepares an annual forecast of power supply cost that covers FY+5, referred to as the Production Cost Model. Leadership requested a supplemental expanded model that covers FY+10 for a longer outlook on potential retail rate impacts. This memo aims to provide insight and clarity into the driving factors of power supply cost in the extended Production Cost Model. Each section describes a line item in the Production Cost Model forecast and provides background on how it is determined, as well as some of the factors driving the forecast.

Market Forwards
Market forecasts come from a combination of sources, including ICE, Ascend, and internal forecasting.

RPP Generation
RPP generation costs are forecasted to include gas, gas transport, LTP costs, and carbon allowances (Figure 1).
• The gas forecast utilizes ICE forwards for PG&E City Gate, as long as they are available (through CY2030), and then transitions to Ascend's long-term forecast. • The PG&E gas transport rate is developed using an internal forecast and assumes that we will maintain our current negotiated rate structure.
• Required gas volumes for purchase and transport for generation are based on a heat rate of [redacted] Dth/MWh.
• The LTP costs utilize a public CPI forecast, followed by an escalator and an average generation rate (30 MW U5 or U6 + 12 MW U4).
• Ascend prepares the carbon price forecast, and we use an average emissions rate for RPP of [redacted] metric tons of CO2e per megawatt-hour (mTCO2e/MWh) to determine the carbon cost. One carbon allowance is required for every metric ton of CO2e (mTCO2e) emitted.
• The equation for the RPP marginal rate is:

𝑅𝑅𝑅𝑅𝑅𝑅 𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀 𝑅𝑅𝑀𝑀𝑅𝑅𝑅𝑅 � $
𝑀𝑀𝑀𝑀ℎ� = �𝑅𝑅𝑃𝑃&𝐸𝐸 𝐶𝐶𝑃𝑃 � $
𝐷𝐷𝑅𝑅ℎ� + 𝑅𝑅𝑃𝑃&𝐸𝐸 𝑇𝑇𝑀𝑀𝑀𝑀𝑀𝑀𝑇𝑇. � $
𝐷𝐷𝑅𝑅ℎ�� ∗ 𝑅𝑅𝑅𝑅𝑅𝑅 𝐻𝐻𝑅𝑅 � 𝐷𝐷𝑅𝑅ℎ
𝑀𝑀𝑀𝑀ℎ�
+𝐶𝐶𝐶𝐶𝐶𝐶 � $
𝑚𝑚𝑇𝑇𝐶𝐶𝑚𝑚2𝑅𝑅� ∗ 𝑅𝑅𝑅𝑅𝑅𝑅 𝐸𝐸𝑅𝑅 �𝑚𝑚𝑇𝑇𝐶𝐶𝑚𝑚2𝑅𝑅
𝑀𝑀𝑀𝑀ℎ � +
𝑅𝑅𝑅𝑅𝑅𝑅 𝐿𝐿𝑇𝑇𝑅𝑅 � $
ℎ𝑀𝑀�
𝐶𝐶𝐴𝐴𝑀𝑀 𝑈𝑈5 6⁄ [𝑀𝑀𝑀𝑀] + 𝐶𝐶𝐴𝐴𝑀𝑀 𝑈𝑈4 [𝑀𝑀𝑀𝑀]
Packet Pg. 388
Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

2 Figure 1 - RPP Marginal Price Forecast
The gas price forecast is relatively flat, while gas transport and carbon are driving up the RPP marginal rate in the long term.

Energy Markets
The energy price forecast for NP15 utilizes ICE for as long as it is available, then transitions to Ascend's long-term forecast. COB is forecasted by Ascend using a weighted average of NP15 and Mid-C forecasts. The NP-15 price includes a TAC adder that TANC prepares. The COB forecast includes carbon allowances required when importing energy and utilizes Ascend's carbon forecast (Figure 2).

Figure 2 - Market Forwards

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PG&E CG Gas ($/Dth) Carbon Allowance ($/mTCo2e) NP-15 ($/MWh) COB ($/MWh) RPP Marginal Cost ($/MWh) PG&E Transport ($/Dth) ICE Market Forwards Ascend Long-term Forecast
Packet Pg. 389
Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

3 The forecasted energy price for both NP15 and COB is very close. Coincidentally, the carbon cost at COB and the TAC for NP15 are also very close. As a result, the NP15+TAC and COB+carbon forecasts are relatively close. Both are trending up (Figure 3).

The RPP marginal cost is consistently higher on an annual average than NP15+TAC and COB+carbon. At the monthly level, there are periods where RPP is cheaper; no graph is included, however, this typically occurs during the winter months.

Figure 3 - Energy Market Rates
Line #56 – Wholesale Sales
Wholesale sales are made up of Wholesale Power Sales, Carbon Allowance Sales, TANC Revenue, CAISO Market Revenue, Natural Gas Sales, and Natural Gas Transmission Revenue. Overall, wholesale sales are trending up, driven mainly by increased power sales from an assumed solar project (in this case, [redacted]) and carbon allowances.

Figure 4 - #56 - Wholesale Sales

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Natural Gas Sales - Wholesale Natural Gas Transmission Revenue Packet Pg. 390
Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

4 Power Sales

Figure 5 - Power Sales
Wholesale Power Sales
Wholesale Power Sales include short-term market energy sales, COSL capacity charges, COSL Base Resource pass-through, COSL scheduling services, and net revenues from generating resources in CAISO ([redacted] solar was used for this forecast).

The forecast does not include short-term market sales unless we are long on power. The sales jump up in FY2029 once [redacted] is assumed to come online. [Redacted] revenues are determined in a long-term model from Ascend and added directly to the Power Supply forecast.

An example of the market interactions for [redacted] and Trolley is shown in Figure 6 below. In the model, it is easier to treat solar and storage as separate objects that operate independently (this also aligns with reality, as they are distinct projects). However, when the battery is charging and the solar is generating, the costs and revenues will cancel each other out. Regardless, we still represent this as an energy cost for the charging and the revenue from sales in the Production Cost Model. $0
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Wholesale Power Sales Carbon Allowance Sales
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Packet Pg. 391
Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

5 Figure 6 - Example of [redacted] Gen. and Trolley Dispatch Carbon Allowance Sales
Carbon allowance revenues assume that we will sell all of our allocated allowances. We assume that all of the allocations will be sold so that the cost of RPP can include allowances, and the model will buy back any allowances needed (at the same price they were sold, so they will net with allocated allowances). The calculation is based on our forecasted allowances from CARB, which are trending down, multiplied by the carbon price forecast, which is trending up (Figure 2).

TANC Revenue
TANC revenue is derived from short-term transmission sales and is based on a historical average, as there is no discernible pattern in sales. The forecast is flat.

CAISO Market Revenue
CAISO Market revenues are used for tracking settlements from actual CAISO purchases and sales, as well as EIM. It is not used for forecasting, as we do not consider these in the budget forecast. These are assumed to be $0 for the forecast.

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Packet Pg. 392
Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

6 Natural Gas Sales

Figure 7 - Natural Gas Sales
Wholesale Natural Gas Sales
Wholesale gas sales include the assumed sales of hedge gas, which is purchased to fix the price of pre-pay gas. Assume sale of 5,000 Dth/day at the forecasted gas price. There is an equivalent purchase of the same volume at the same price to net these out, representing the physical mechanism used to hedge pre-pay gas.

It also includes any short-term gas sales. Gas is only sold in the short term in the model if storage is full and we have excess gas.

The gas price forecast is relatively flat.

Natural Gas Transmission Revenue
As of 2025, REU has been completely divested from its gas transmission assets. We no longer include any gas transmission revenues in the forecast. The sale of the last remaining asset of GTN pipeline capacity was made in 2021 (effective 2025). We have not been including gas transmission revenues post-2024 since 2021.

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Wholesale Natural Gas Sales Natural Gas Transmission Revenue Packet Pg. 393
Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

7 Line #65 – Purchased Power
Purchased power is trending upward significantly. The [redacted] and Trolley costs start in FY29 (some of the costs are offset through wholesale power sales). The most significant increase over the long term is from WSPP Agreements purchased (this represents spot market purchases).

Figure 8 - #65 - Purchased Power

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Base Resource Allocation WAPA Financial Transmission Losses WAPA - Ancillary Service WAPA Regulation Service Charge Independent System Operator WSPP Agreements Purchased
COSL Supplemental Energy Offset PPM Energy - Long Term
Trolley Storage PPA Carbon Allowance Purchase
REC Purchase - Short Term Shell Index+ Long-Term
Packet Pg. 394
Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

8 WAPA – Long Term

Figure 9 - WAPA Long-Term
Base Resource Allocation
Base resource costs include the forecasted Base Resource charge from WAPA for REU, COSL, and Rancheria. There is an offsetting pass-through charge to COSL for their portion of Wholesale Sales.

WAPA annually provides a 5-year Power Revenue Requirement (PRR) forecast that indicates expected Base Resource costs. WAPA also provides a mid-year update to the PRR, incorporating adjustments if any significant changes have occurred.

The mid-year letter for FY25 increased PPR by $12M (for the total Base Resource project). The increase was due to a $20M COTP capacitor project prepayment. There will be one more charge of $11.1 M in FY26 for this project (including interest and financing fees). After this, the PRR should revert to the PRR forecast as provided. Since the PRR forecast only covers 5 years, it was extended by using the average increase over the forecast period, which is 4.3%.

WAPA Financial Transmission Losses
Financially settled losses with WAPA include forecasted losses on both CVP and COTP transmission.

While the losses are typically settled at WAPA's generation or energy purchase cost, the model assumes the losses are paid at the same price as the energy delivered (we do not have a forecast for WAPA's generation cost).

Losses scale with energy imports. In the next few years, we are hedged for gas and are budgeting for load with RPP. Additionally, Big Horn imports are expected to stop in FY27. Further out, imports become more economical, so loss paybacks increase as the volume of imported market purchases increases.
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WAPA Long-Term
Base Resource Allocation WAPA Financial Transmission Losses WAPA - Ancillary Service WAPA Regulation Service Charge Packet Pg. 395
Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

9 WAPA – Ancillary Service
These are the deviation band and other ancillary services from WAPA.

We maintain a 6 MW deviation band purchased from WAPA. The pricing utilizes the Regulation and Frequency Response Service rate (CV-RFS4) with a 3% escalation (also reflected in the TRR forecast).

The ancillary services are the sum of WAMPTD: Frequency Response Reserve Purchase Cost (based on load-ratio share in WAPA sub-BA, fixed for the year), Contingency Reserve Purchase Cost & COI Mitigation Purchase Cost (buy when we need (can self-supply), determined by WAPA based on L-R share), and Resource Sufficiency (buy when we need (can self-supply), balancing/flex up-down, typically buy during outages or if we need unit capacity). The forecast uses historic averages and assumes a 5% escalation. These were formerly known as Spin and Non-Spin Reserves.

WAPA Regulation Service Charge
Expired starting FY21. Should be removed from the forecast.

Purchase Power ISO Uplift

Figure 10 - Purchase Power ISO Uplift
Independent System Operator
Net CAISO transactions including: RDG1 - MRTU market (bilateral transactions in CAISO); RDG2 - EIM generation (units called on for economic market & imbalance of base schedule v. actual); BANC EIM - load settlements (load forecast v. actual). Replaces 'WRDG ISO Credits & Charges.' These lines are used for tracking actuals only and are not included in the forecast, as EIM activity is not included in the forecast. Any short-term purchases would be covered under "Purchase Power – Other."

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Packet Pg. 396
Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

10 Purchase Power – Other

Figure 11 - Purchase Power - Other
WSPP Agreements Purchased
WSPP purchases include short-term energy purchases on the market. Historically, only forecasted for April, May, and October based on RPP planned maintenance. Before FY21, it was assumed that all load would be met with RPP. Currently, market purchases are compared against the RPP marginal generation cost, and the cheaper option is selected. In future years, energy markets generally beat RPP, and market purchases increase. Assumes the lesser of NP-15 and COB market rates. Forward assumptions are discussed under "Market Forwards".

Additionally, market purchases include energy required to charge the Trolley battery storage project, as determined by the Ascend model.

COSL Supplemental Energy Offset
Redding provides energy to COSL according to a contract schedule set on an annual basis. It is assumed that this energy will be sold at cost, so this item represents a purchase offset at the same rate as the supplemental sale (the sale is included in Wholesale Power Sales).

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WSPP Agreements Purchased COSL Supplemental Energy Offset Packet Pg. 397
Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

11 PPM – Long Term

Figure 12 - PPM - Long-Term
PPM Energy - Long Term
The Big Horn Wind project costs include energy, firming and shaping, and wind integration charges.

The project is scheduled to end in September 2026, early in FY27. (The original contract for Big Horn was with PPM Energy.)
[Redacted] Solar PPA
The forecast assumed the [redacted] project would come online in FY28, as we were in active negotiations with the developer. While this project is now unlikely to move forward, we are seeking a similar replacement. The costs in the forecast are calculated by multiplying the forecasted energy by the assumed PPA price of $[redacted]/MWh. The costs capture the PPA charges for purchasing energy from [redacted] (or a similar project). The energy is delivered to CAISO. Based on Ascend modeling, some of it is brought to load, and some is liquidated in the CAISO market. These revenues are captured in "Wholesale Power Sales". Includes $30,000/yr in admin fees to NCPA.

Trolley Storage PPA
The Trolley Storage project is expected to come online in late FY28. The costs for Trolley are a fixed tolling agreement of $12.71/kW-mo multiplied by the project capacity of 45 MW. The costs for charging and revenues for charging are determined by the Ascend model and are captured in "WSPP Agreements Purchased" and "Wholesale Power Sales," respectively. Includes $30,000/yr in admin fees to NCPA.

Carbon Allowance Purchase
To evaluate the true marginal cost of running RPP, it is assumed that we will need to purchase all allowances required to generate with RPP. Using a fixed emissions factor based on historical performance, the model assumes we will buy all necessary allowances from RPP generation. $0
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PPM Energy - Long Term Trolley Storage PPA Carbon Allowance Purchase REC Purchase - Short Term Shell Index+ Long-Term
Packet Pg. 398
Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

12 REC Purchase - Short Term
Occasionally, we will need to purchase short-term RECs to close short RPS positions. Although we are likely to be short in future years with the current portfolio, we are not forecasting short-term REC purchases at this time, as we are currently navigating long-term procurements.

Shell Index+ Long-Term
The Shell Index+ is the fixed cost purchase of long-term RECs from Shell Energy.

Line #67 - Fuel & Variable O&M Generation Costs
Fuel and O&M costs comprise gas purchases for energy generation, gas purchases for prepayment, and PG&E gas transport costs (included in the wholesale gas purchase).

Figure 13 - #67 - Fuel & Variable O&M Generation Costs (stacked area)

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CT Fuel Burner (U1-U6) Wholesale Gas Purchase Prepay Gas Purchases Packet Pg. 399
Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

13 Figure 14 - #67 - Fuel & Variable O&M Generation Costs (line chart) CT Fuel Burner
CT Fuel Burner (U1-U6)
Includes fuel purchases required for generation with RPP (including any fixed gas hedge purchases). Excess gas is stored, and the stored gas is used before spot gas purchases are made.

Based on forecasted RPP generation multiplied by the RPP average heat rate of [redacted] Dth/MWh. RPP generation assumes that we will burn a minimum average of 5,000 Dth/day to satisfy the pre-pay gas requirement. Additional RPP generation occurs only for months where the RPP marginal cost is lower than both COB+carbon and NP15+TAC. Assumes PG&E City-Gate Gas Price. Forward assumptions are discussed under "Market Forwards".

WHOLESALE GAS PURCHASE
Wholesale Gas Purchase [PG&E Gas Transport]
Charges for PG&E gas transport. Includes usage and customer charges. Determined by the amount of fuel delivered to RPP from "CT Fuel Burner (U1-U6)" multiplied by our internal forecast for PG&E's gas transport rate. The forecast assumes that we will maintain a negotiated structure where the local transport charges are primarily collected through a fixed charge.

PRE-PAY GAS EXPENSE
Pre-pay Gas Purchases
Gas purchase for our pre-pay obligation. Assume 5,000 Dth/day purchased at the gas forecast price.

There is an offset sale in "Wholesale Natural Gas Sales" as we are using physical gas hedges to fix our pre-pay gas price.

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CT Fuel Burner (U1-U6) Wholesale Gas Purchase Prepay Gas Purchases Packet Pg. 400
Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

14 Line #69 – M-S-R Expense
M-S-R Expenses include services for San Juan, Renewables, and the Energy Authority. There are some persistent admin costs for San Juan. The costs for M-S-R Renewables are related to Big Horn and are expected to expire when the Big Horn contract ends. The M-S-R costs originate from the M- S-R budget forecast and are then escalated at the average growth rate in the forecast.

Figure 15 - #69 - MSR Expense
Line #70 - TANC Expense
The TANC expenses include COTP transmission costs under TANC and SOT costs. Starting with the Trolley and [redacted] (or similar) projects in FY29, SOT transmission usage costs are also included. The Transmission TANC Assessment forecast is derived from TANC, and the SOT usage costs are calculated by multiplying the expected energy scheduled on SOT by our fixed transmission usage rate of approximately $5/MWh.

Figure 16 - #70 - TANC Expense

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MSR/SAN JUAN GENERATION MSR SAN JUAN GENERATION DEBT

MSR RENEWABLES MSR ENERGY AUTHORITY
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Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

15 Line #71 - Other Fixed Transmission Costs (WAPA, COTP, Whiskeytown) Other transmission costs include COTP O&M, WAPA long-term transmission, and WAPA transmission for Whiskeytown. The COTP costs should be moved under TANC, but at the time of the report, the TANC budget had not been updated to include these costs. They will be moved in the next Production Cost update. Whiskeytown and WAPA's long-term transmission costs are derived from the fixed transmission purchase amounts (4 MW and 187 MW, respectively) multiplied by the WAPA point-to-point transmission rate. WAPA's forecast was used when available; otherwise, it was escalated at the average growth rate for future years.

Figure 17 - #71 - Other Fixed Transmission Costs (WAPA, COTP, Whiskeytown) Line #72 - Fixed Generation A&G and O&M (Non-Fuel)
Fixed generation costs are the Siemens LTP costs for Units 5 & 6. Despite the name, these are not fixed and depend on the expected RPP generation. Generation is converted to run hours and multiplied by the LTP rate escalated by a CPI. The CPI is forecast using a public forecast, then continues to escalate at ~2% beyond the forecast. The costs are split evenly between Unit 5 and Unit 6.

Figure 18 - #72 - Fixed Generation A&G and O&M (Non-Fuel)

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Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

16 Load and Resources
Load Forecast
Through a professional services agreement with Itron, Inc., REU receives its load forecast. The first 36 months utilize the Itron 36-month hourly forecast, while the remainder uses the Itron long-term forecast. Traditionally, only the long-term forecast was used. The 36-month forecast was included for this special update.

Generation Forecast
RPP
RPP gen is set at a minimum average gas burn of 5,000 Dth/day. Generation above that only occurs when the RPP price is cheaper than the market energy price.

Base Resource
WAPA Base Resource is forecasted using the WAPA 12-month rolling forecast for the first 12 months, followed by our rolling 5-year average estimates for the remainder. The water year cycle typically begins in October at the beginning of the “rainy” season, which extends through April. The February 12-month rolling forecast is typically used for the Production Cost Model.

WAPA relies on water forecast data from the USBR to prepare its forecast, and the USBR water data lags by 1-2 months. For example, the February 2026 forecast was based on precipitation and inflow data from late Dec. 2025, early Jan. 2026. Using precipitation trend data in Figure 19 through early January, it is difficult to say where the water year will end up as previous years with a similar January precipitation ended up with greatly different precipitation totals by the end of the water year.

The forecast can be adjusted slightly to account for this using averages and historical trends, but the adjustments will miss key assumptions regarding CVP project use, water storage, environmental, and other operational factors present in the USBR model and WAPA forecasts. As a result, the Base Resource forecast is difficult to forecast, even in the near-term 12-month window.

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Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

17 Figure 19 - Norther Sierra Precipitation:8-Station Index (https://cdec.water.ca.gov/precipapp/get8SIPrecipIndex.action) [Redacted] and Trolley
Trolley charging and [redacted] net generation (after wholesales to CAISO) are determined using a long-term production cost model from Ascend.

Balance of Load
Any short positions are filled using the cheapest of RPP, NP15+TAC, and COB+carbon, based on on- and off-peak monthly forecasts.

Market purchases are expected to increase as the load grows and market prices are cheaper than RPP.

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Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Memo

18 Figure 20 - Load and Resource Forecast (monthly)

Figure 21 - Resource Forecast (annual)
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WHISKEYTOWN FORWARD POWER PURCHASES
REDDING POWER: SPOT GAS PRE-PAY REDDING POWER: SPOT GAS ECONOMIC REDDING POWER: HEDGE GAS SPOT POWER PURCHASES

REDDING ENERGY DEMAND
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REDDING POWER: SPOT GAS PRE-PAY REDDING POWER: SPOT GAS ECONOMIC REDDING POWER: HEDGE GAS SPOT POWER PURCHASES
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Attachment: Production Cost Model 10-Year Outlook (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Actual / Forecast Actual Actual Actual Actual Actual Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Fiscal Year: 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 #56- Wholesale Sales $12,729,385 $22,247,424 $31,476,608 $25,237,868 $19,569,880 $16,770,782 $16,285,087 $17,471,512 $20,919,950 $20,994,520 $21,834,116 $22,845,955 $23,011,271 $23,106,583 $23,808,170 POWER SALES - WHOLESALE $4,834,503 $8,357,185 $7,707,794 $13,865,541 $9,047,264 $9,037,632 $8,138,940 $9,449,810 $12,990,593 $13,165,321 $13,843,866 $14,533,740 $15,067,900 $15,254,212 $15,644,104 Power Sales - Wholesale $4,446,422 $7,719,540 $7,297,194 $12,607,742 $8,807,423 $4,384,140 $3,497,371 $4,624,050 $7,944,415 $7,900,714 $7,743,416 $7,531,980 $7,783,121 $7,674,317 $7,756,476 Carbon Allowance Sales - Wholesale $0 $0 $0 $0 $0 $4,272,015 $4,260,091 $4,444,283 $4,664,700 $4,883,129 $5,718,973 $6,620,283 $6,903,302 $7,198,418 $7,506,151 TANC Revenue $388,081 $637,645 $410,600 $1,257,799 $239,842 $381,477 $381,477 $381,477 $381,477 $381,477 $381,477 $381,477 $381,477 $381,477 $381,477 CAISO Market Revenue $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 NATURAL GAS SALES - WHOLESALE $7,894,882 $13,890,239 $23,768,814 $11,372,327 $10,522,616 $7,733,150 $8,146,147 $8,021,703 $7,929,357 $7,829,200 $7,990,250 $8,312,215 $7,943,371 $7,852,371 $8,164,067 Natural Gas Sales - Wholesale $7,203,664 $13,199,021 $23,077,595 $11,139,396 $10,522,616 $7,733,150 $8,146,147 $8,021,703 $7,929,357 $7,829,200 $7,990,250 $8,312,215 $7,943,371 $7,852,371 $8,164,067 Natural Gas Transmission Revenue $691,219 $691,219 $691,219 $232,931 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 #65 - Purchased Power $28,383,239 $27,664,433 $26,522,686 $18,766,333 $26,570,111 $27,480,909 $22,700,862 $33,896,677 $43,575,745 $48,468,043 $51,936,292 $56,600,285 $59,813,885 $59,971,125 $66,439,008 WAPA - LONG TERM $6,849,103 $7,592,126 $7,644,602 $5,483,379 $5,961,193 $6,041,052 $5,605,161 $5,281,652 $5,306,427 $5,649,571 $6,176,938 $6,693,240 $7,052,900 $7,207,181 $7,623,633 Base Resource Allocation $5,906,868 $5,749,045 $5,133,785 $4,117,620 $4,449,308 $4,886,483 $4,571,443 $4,351,517 $4,431,980 $4,672,426 $4,922,465 $5,130,290 $5,347,015 $5,573,021 $5,808,705 WAPA Financial Transmission Losses $336,779 $1,246,458 $1,566,396 $777,824 $899,177 $517,005 $367,920 $239,130 $157,152 $233,010 $482,424 $761,873 $874,615 $771,483 $919,578 WAPA - Ancillary Service $605,456 $596,622 $944,421 $587,935 $612,707 $637,564 $665,797 $691,005 $717,295 $744,136 $772,048 $801,077 $831,270 $862,677 $895,350 WAPA Regulation Service Charge $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 PURCHASE POWER ISO UPLIFT -$2,120,789 -$1,907,557 -$5,768,278 -$183,131 $3,442,875 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Independent System Operator -$2,120,789 -$1,907,557 -$5,768,278 -$183,131 $3,442,875 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 PURCHASE POWER - OTHER $10,484,965 $7,514,167 $11,593,784 $1,393,252 $4,902,152 $1,944,418 $6,770,042 $14,082,144 $10,121,383 $14,748,168 $16,902,038 $19,920,310 $21,813,493 $21,413,593 $28,793,390 WSPP Agreements Purchased $10,484,965 $7,514,167 $11,593,784 $1,393,252 $4,902,152 $1,255,374 $6,770,042 $14,082,144 $10,121,383 $14,748,168 $16,902,038 $19,920,310 $21,813,493 $21,413,593 $28,793,390 COSL Supplemental Energy Offset $0 $0 $0 $0 $0 $689,044 $0 $0 $0 $0 $0 $0 $0 $0 $0 PPM - LONG TERM $13,169,960 $14,465,697 $13,052,578 $12,072,834 $12,263,892 $19,495,439 $10,325,659 $14,532,881 $28,147,935 $28,070,303 $28,857,316 $29,986,736 $30,947,491 $31,350,351 $30,021,985 PPM Energy - Long Term $13,169,960 $12,556,497 $11,073,656 $11,153,252 $10,920,142 $11,996,283 $2,633,023 $0 $0 $0 $0 $0 $0 $0 $0 Solar PPA $0 $0 $0 $0 $0 $0 $0 $6,621,120 $14,137,543 $14,098,797 $14,089,520 $14,071,465 $13,986,556 $13,962,492 $13,894,523 Trolley Storage PPA $0 $0 $0 $0 $0 $0 $0 $574,450 $6,893,400 $6,893,400 $6,893,400 $6,893,400 $6,893,400 $6,893,400 $6,893,400 Carbon Allowance Purchase $0 $609,200 $1,978,922 $919,583 $0 $4,811,656 $5,005,136 $4,637,311 $4,404,492 $4,365,606 $5,161,896 $6,309,371 $7,355,035 $7,781,959 $7,877,813 REC Purchase - Short Term $0 $1,300,000 $0 $0 $375,000 $750,000 $750,000 $375,000 $0 $0 $0 $0 $0 $0 $0 Shell Index+ Long-Term $0 $0 $0 $0 $968,750 $1,937,500 $1,937,500 $2,325,000 $2,712,500 $2,712,500 $2,712,500 $2,712,500 $2,712,500 $2,712,500 $1,356,250 #67 - Fuel & Variable O&M Generation Costs $22,699,512 $27,925,681 $42,716,969 $25,816,309 $20,174,940 $25,650,639 $30,373,177 $27,963,063 $24,696,651 $22,984,012 $24,115,017 $25,811,583 $26,510,738 $29,232,009 $28,293,392 CT Fuel Burner $13,551,787 $13,576,776 $26,087,008 $15,577,811 $10,787,384 $14,107,154 $16,945,009 $14,488,586 $10,875,022 $9,128,458 $9,179,624 $9,685,826 $9,706,711 $10,781,867 $9,805,214 CT Fuel Burner (U1-U6) $13,551,787 $13,576,776 $26,087,008 $15,577,811 $10,787,384 $14,107,154 $16,945,009 $14,488,586 $10,875,022 $9,128,458 $9,179,624 $9,685,826 $9,706,711 $10,781,867 $9,805,214 WHOLESALE GAS PURCHASE $2,587,700 $2,199,030 $3,080,273 $2,292,772 $2,922,157 $3,810,336 $5,282,020 $5,452,775 $5,892,272 $6,026,355 $6,945,144 $7,813,542 $8,860,656 $10,597,772 $10,324,111 Wholesale Gas Purchase $2,587,700 $2,199,030 $3,080,273 $2,292,772 $2,922,157 $3,810,336 $5,282,020 $5,452,775 $5,892,272 $6,026,355 $6,945,144 $7,813,542 $8,860,656 $10,597,772 $10,324,111 PREPAY GAS EXPENSE $6,560,025 $12,149,875 $13,549,689 $7,945,725 $6,465,400 $7,733,150 $8,146,147 $8,021,703 $7,929,357 $7,829,200 $7,990,250 $8,312,215 $7,943,371 $7,852,371 $8,164,067 Prepay Gas Purchases $6,560,025 $12,149,875 $13,549,689 $7,945,725 $6,465,400 $7,733,150 $8,146,147 $8,021,703 $7,929,357 $7,829,200 $7,990,250 $8,312,215 $7,943,371 $7,852,371 $8,164,067 #69 - MSR Expense $4,429,027 $4,139,443 $354,574 $281,135 $321,857 $424,500 $84,200 $86,800 $89,500 $92,200 $94,915 $97,711 $100,592 $103,559 $106,614 MSR/SAN JUAN GENERATION $16,614 $50,694 $29,294 $10,256 $11,557 $32,600 $33,600 $34,700 $35,800 $36,900 $38,007 $39,147 $40,322 $41,531 $42,777 MSR Agency Admin. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 MSR Capital Expense $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 MSR SJ O&M $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 MSR SJ Admin. $16,614 $50,694 $29,294 $10,256 $11,557 $32,600 $33,600 $34,700 $35,800 $36,900 $38,007 $39,147 $40,322 $41,531 $42,777 MSR SAN JUAN GENERATION DEBT $4,169,482 $3,819,417 -$1,315 -$656 $0 $1,700 $1,700 $1,700 $1,700 $1,700 $1,700 $1,700 $1,700 $1,700 $1,700 MSR Gen. Debt Service Taxable $4,162,419 $3,815,109 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 MSR Debt Admin. $7,063 $4,308 -$1,315 -$656 $0 $1,700 $1,700 $1,700 $1,700 $1,700 $1,700 $1,700 $1,700 $1,700 $1,700 MSR RENEWABLES $242,931 $269,332 $326,594 $271,535 $310,300 $342,800 $0 $0 $0 $0 $0 $0 $0 $0 $0 MSR Renewables - Admin. $87,591 $105,542 $124,834 $74,182 $99,680 $119,100 $0 $0 $0 $0 $0 $0 $0 $0 $0 Agency Administration $50,036 $59,259 $76,702 $67,301 $74,520 $82,000 $0 $0 $0 $0 $0 $0 $0 $0 $0 Coordinating Services $93,276 $94,443 $109,727 $113,674 $119,500 $120,700 $0 $0 $0 $0 $0 $0 $0 $0 $0 Regulatory Compliance $12,028 $10,087 $15,331 $16,379 $16,600 $21,000 $0 $0 $0 $0 $0 $0 $0 $0 $0 MSR ENERGY AUTHORITY $0 $0 $0 $0 $0 $47,400 $48,900 $50,400 $52,000 $53,600 $55,208 $56,864 $58,570 $60,327 $62,137 MSR Energy Authority $0 $0 $0 $0 $0 $47,400 $48,900 $50,400 $52,000 $53,600 $55,208 $56,864 $58,570 $60,327 $62,137 TRANSMISSION MSR DEBT $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Debt Service - Transmission $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 MSR Debt Amin. - Transmission $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Packet Pg. 406
Attachment: Production Cost Model (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Actual / Forecast Actual Actual Actual Actual Actual Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast #70 - TANC Expense $3,653,765 $3,583,120 $3,822,930 $3,842,375 $4,271,238 $3,195,800 $3,262,100 $3,280,000 $3,366,400 $3,529,600 $3,634,400 $3,744,400 $3,859,700 $3,980,400 $4,107,000 TRANSMISSION TANC ASSESSMENT $3,605,858 $3,546,786 $3,785,458 $3,792,172 $4,222,852 $3,131,500 $3,196,400 $3,212,900 $3,297,900 $3,459,500 $3,562,700 $3,670,900 $3,784,400 $3,903,300 $4,027,900 Transmission TANC Assessment $3,605,858 $3,546,786 $3,785,458 $3,792,172 $4,222,852 $3,131,500 $3,196,400 $3,212,900 $3,297,900 $3,459,500 $3,562,700 $3,670,900 $3,784,400 $3,903,300 $4,027,900 SOT TRANSMISSION SERVICE $47,907 $36,334 $37,472 $50,203 $48,386 $64,300 $65,700 $351,217 $969,093 $969,339 $974,848 $980,756 $977,739 $982,788 $982,328 TANC SOT Admin. $12,897 $6,874 $3,938 $9,688 $6,478 $13,400 $14,100 $14,800 $15,500 $16,300 $17,100 $18,000 $18,900 $19,800 $20,800 TANC SOT Facilities $19,058 $12,181 $14,842 $18,635 $18,635 $18,800 $18,800 $18,800 $18,800 $18,800 $18,800 $18,800 $18,800 $18,800 $18,800 TANC SOT Debt Service $15,952 $17,280 $18,693 $21,879 $23,272 $32,100 $32,800 $33,500 $34,200 $35,000 $35,800 $36,700 $37,600 $38,500 $39,500 TANC SOT Usage Charges $0 $0 $0 $0 $0 $0 $0 $284,117 $900,593 $899,239 $903,148 $907,256 $902,439 $905,688 $903,228 #71 - Other Fixed Transmission Costs (WAPA, COTP, Whiskeytown) $5,143,095 $4,903,341 $4,872,728 $5,026,354 $6,000,652 $4,409,620 $4,750,260 $4,976,230 $5,206,746 $5,480,033 $5,745,729 $6,031,536 $6,331,583 $6,646,632 $6,977,378 TRANSMISSION COTP $329,955 $301,947 $346,119 $408,204 $1,827,011 $375,700 $384,000 $386,500 $403,000 $436,100 $449,600 $470,600 $492,600 $515,700 $539,900 Transmission COTP $329,955 $301,947 $346,119 $408,204 $1,827,011 $375,700 $384,000 $386,500 $403,000 $436,100 $449,600 $470,600 $492,600 $515,700 $539,900 TRANSMISSION WHISKEYTOWN WHEELING $91,920 $87,360 $85,560 $87,240 $82,440 $84,480 $91,440 $96,120 $100,602 $105,632 $110,914 $116,459 $122,282 $128,396 $134,816 Transmission Whiskeytown Wheeling $91,920 $87,360 $85,560 $87,240 $82,440 $84,480 $91,440 $96,120 $100,602 $105,632 $110,914 $116,459 $122,282 $128,396 $134,816 TRANSMISSION WAPA $4,721,220 $4,514,034 $4,441,049 $4,530,910 $4,091,201 $3,949,440 $4,274,820 $4,493,610 $4,703,144 $4,938,301 $5,185,216 $5,444,476 $5,716,700 $6,002,535 $6,302,662 Transmission WAPA $4,721,220 $4,514,034 $4,441,049 $4,530,910 $4,091,201 $3,949,440 $4,274,820 $4,493,610 $4,703,144 $4,938,301 $5,185,216 $5,444,476 $5,716,700 $6,002,535 $6,302,662 #72 - Fixed Generation A&G and O&M (Non-Fuel) $2,992,388 $3,134,395 $5,161,974 $4,748,473 $6,034,161 $3,707,189 $4,752,629 $3,763,394 $3,380,880 $2,949,887 $3,086,507 $3,178,072 $3,354,197 $3,824,962 $3,390,235 UNIT 5 LTP ENGINE HR EXP $1,444,438 $1,641,479 $2,548,604 $2,374,236 $3,428,943 $1,853,594 $2,376,315 $1,881,697 $1,690,440 $1,474,943 $1,543,253 $1,589,036 $1,677,098 $1,912,481 $1,695,117 Unit 5 LTP Engine HR Exp $1,444,438 $1,641,479 $2,548,604 $2,374,236 $3,428,943 $1,853,594 $2,376,315 $1,881,697 $1,690,440 $1,474,943 $1,543,253 $1,589,036 $1,677,098 $1,912,481 $1,695,117 UNIT 6 LTP ENGINE HR EXP $1,547,950 $1,492,915 $2,613,370 $2,374,236 $2,605,218 $1,853,594 $2,376,315 $1,881,697 $1,690,440 $1,474,943 $1,543,253 $1,589,036 $1,677,098 $1,912,481 $1,695,117 Unit 6 LTP Engine HR Exp $1,547,950 $1,492,915 $2,613,370 $2,374,236 $2,605,218 $1,853,594 $2,376,315 $1,881,697 $1,690,440 $1,474,943 $1,543,253 $1,589,036 $1,677,098 $1,912,481 $1,695,117 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Redding System Energy Demand (MWh) 789,467 755,289 778,980 766,057 783,446 764,981 774,214 786,276 801,300 820,202 841,172 862,939 886,171 912,016 939,206 Western Base Resource (MWh) 178,909 122,059 128,052 285,228 254,277 219,299 192,697 192,697 192,697 192,697 192,697 192,697 192,697 192,697 192,697 Big Horn (MWh) 191,648 191,907 185,739 154,352 165,942 173,338 38,199 - - - - - - - - Whiskeytown (MWh) 22,166 22,827 25,418 23,731 7,203 23,947 23,947 24,022 23,947 23,947 23,947 24,022 23,947 23,947 23,947 Net Solar+Storage (MWh) - - - 56,454 178,948 178,679 179,456 180,272 179,315 179,961 179,472 Market Power Purchases (MWh) 350,302 386,322 351,576 292,804 221,384 25,388 115,918 205,449 138,613 161,871 177,562 224,574 239,659 233,729 299,115 RPP Spot Gas (MWh) - 70,629 228,453 231,623 226,997 231,564 205,335 214,351 245,222 208,970 RPP Hedge Gas (MWh) 339,794 385,018 434,552 360,793 342,564 323,008 332,824 79,200 35,472 36,011 35,947 36,039 36,203 36,461 35,006 Remaining Energy / Spot Sales (MWh) (293,353) (352,843) (346,357) (350,850) (207,925) - - - - - - - - - - Hedge Gas Volume (Dth/day) 7,250 8,208 7,167 7,417 8,188 7,479 7,383 1,750 0 0 0 0 0 0 0 Melded Hedge Gas Price ($/Dth) $4.05 $4.09 $4.15 $4.24 $4.85 $5.15 $4.82 $5.48 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 Equivalent Energy Price Current Forecast ($/kWh) 0.06287$ 0.06411$ 0.07185$ 0.07412$ 0.07621$ 0.07939$ 0.08415$ 0.08684$ 0.08843$ 0.09104$ Equivalent Energy Price Actual ($/kWh) 0.06912$ 0.06501$ 0.06672$ 0.04340$ 0.05591$ Equivalent Energy Price from Corresponding Year Forecast ($/kWh) 0.06281$ 0.06026$ 0.05947$ 0.05635$ 0.05662$ Equivalent Energy Price from 2023 Forecast ($/kWh) 0.06082$ 0.06126$ 0.06407$ 0.06656$ 0.06819$ Net Power Supply Cost Current Forecast ($) 48,097,876$ 49,638,141$ 56,494,652$ 59,395,972$ 62,509,255$ 66,778,744$ 72,617,633$ 76,959,423$ 80,652,104$ 85,505,457$ Net Power Supply Cost Actual ($) 54,571,641$ 49,102,989$ 51,975,253$ 33,243,111$ 43,803,079$ Net Power Supply Cost from Corresponding Year Forecast ($) 46,169,420$ 44,172,764$ 43,367,734$ 41,352,763$ 42,817,924$ Net Power Supply from 2023 Forecast ($/kWh) 44,325,477$ 44,575,055$ 46,692,851$ 48,828,966$ 50,202,393$ Base Resource Current Forecast (MWh) 219,299 192,697 192,697 192,697 192,697 192,697 192,697 192,697 192,697 192,697 Base Resource Actual (MWh) 178,909 122,059 128,052 285,228 254,277 Base Resource Forecast from Corresponding Year (MWh) 200,439 189,028 161,718 198,865 232,022 Base Resource Forecast from 2023 Forecast (MWh) 200,114 198,231 198,231 198,231 198,231 Redding Energy Demand Forecast (MWh) 764,981 774,214 786,276 801,300 820,202 841,172 862,939 886,171 912,016 939,206 Redding Energy Demand Actual (MWh) 789,467 755,289 778,980 766,057 783,446 Redding Energy Demand from Corresponding Year Forecast ($) 735,071 733,058 729,207 733,867 756,223 Redding Energy Demand Forecast from 2023 Forecast (MWh) 728,780 727,587 728,792 733,554 736,180 Packet Pg. 407
Attachment: Production Cost Model (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) $0
$5,000,000
$10,000,000
$15,000,000
$20,000,000
$25,000,000
$30,000,000
$35,000,000
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Operating Revenue
Power Sales - Wholesale TANC Revenue CAISO Market Revenue Natural Gas Sales - Wholesale Natural Gas Transmission Revenue $0
$10,000,000
$20,000,000
$30,000,000
$40,000,000
$50,000,000
$60,000,000
$70,000,000
$80,000,000
$90,000,000
$100,000,000
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Operating Costs

MSR/SAN JUAN GENERATION MSR SAN JUAN GENERATION DEBT MSR RENEWABLES

MSR ENERGY AUTHORITY TRANSMISSION MSR DEBT TRANSMISSION TANC ASSESSMENT

SOT TRANSMISSION SERVICE TRANSMISSION COTP TRANSMISSION WHISKEYTOWN WHEELING TRANSMISSION WAPA UNIT 5 LTP ENGINE HR EXP UNIT 6 LTP ENGINE HR EXP

WAPA - LONG TERM PURCHASE POWER ISO UPLIFT PURCHASE POWER - OTHER PPM - LONG TERM CT Fuel Burner WHOLESALE GAS PURCHASE

PREPAY GAS EXPENSE
Assumptions:

Big Horn
Contract expires after Sept. 2026
Western
Year 1: 12-month rolling forecast (220,000 MWh for FY)
All other years: 5-year average of historical (193,000 MWh) The mid-year letter increased PPR by $12M (total project).The increase was due to a $20M COTP capacitor project prepayment. There will be one more charge of $11.1 M in FY26 (including interest and financing fees). After this, the PRR should revert to the PRR forecast and should reduce the Base Resource Cost by ~$3M compared to the draft shared earlier. [Redacted] (Solar)
The project starts Feb 2028
We purchase all energy at a PPA price of [redacted]
Used Ascend model to determine energy sales to CAISO for energy not delivered to load Add ~$5/MWh for all energy brought to load on SOT
$30,000/yr in contract admin fees.

Trolley (Storage)
Project start Jun 2028
We pay a tolling fee of $12.71/kW-mo
89% round-trip efficiency
Purchase energy to maximize SOT use (based on Ascend model results) Add ~$5/MWh for all energy brought to load on SOT
$30,000/yr in contract admin fees
RPS
No additional RECs are purchased
Load Forecast
Updated load forecast using 36 month hourly from Sept 2025 Market Pricing
Energy and gas markets use ICE forwards, updated Sept 2025 Carbon is from Ascend, updated Sept 2025
LTP and PG&E transport use our internal forecasts, updated Sept 2025 Wildcat and Trolley market interactions assume the actual costs/revenues predicted in the latest long-term model run.

JPAs
M-S-R, TANC, and COTP forecasts have not been updated since last year and are identical to the FY25 PCM forecast.Extended to FY35 using 3- 5% escalators depending on category
Packet Pg. 408
Attachment: Production Cost Model (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) $-
$0.010
$0.020
$0.030
$0.040
$0.050
$0.060
$0.070
$0.080
$0.090
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Power Supply Equivalent Energy Price ($/kWh)
Equivalent Energy Price Current Forecast ($/kWh) Equivalent Energy Price Actual ($/kWh) Equivalent Energy Price from Corresponding Year Forecast ($/kWh) Equivalent Energy Price from 2023 Forecast ($/kWh) $-
$10,000,000
$20,000,000
$30,000,000
$40,000,000
$50,000,000
$60,000,000
$70,000,000
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Net Power Supply Cost ($)
Net Power Supply Cost Current Forecast ($) Net Power Supply Cost Actual ($) Net Power Supply Cost from Corresponding Year Forecast ($) Net Power Supply from 2023 Forecast ($/kWh) -
50,000
100,000
150,000
200,000
250,000
300,000
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Base Resource Generation (MWh)
Base Resource Current Forecast (MWh) Base Resource Actual (MWh) Base Resource Forecast from Corresponding Year (MWh) Base Resource Forecast from 2023 Forecast (MWh) -
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
900,000
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Redding Energy Demand (MWh)
Redding Energy Demand Forecast (MWh) Redding Energy Demand Actual (MWh) Redding Energy Demand from Corresponding Year Forecast ($) Redding Energy Demand Forecast from 2023 Forecast (MWh) Packet Pg. 409
Attachment: Production Cost Model (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) 1 Accountant 100% 1.00 $ 167,840 2 Cyber Security Officer 75% 0.75 $ 184,410 3 GIS Manager 75% 0.75 $ 186,700 4 Computer Support Specialist 60% 0.60 $ 85,330 5 Assistant City Attorney 100% 1.00 $ 273,120 897,400$ 6 Firefighter* 100% 1.00 $ 178,013 7 Firefighter* 100% 1.00 $ 186,059 8 Firefighter* 100% 1.00 $ 161,751 9 Firefighter* 100% 1.00 $ 170,362 10 Firefighter* 100% 1.00 $ 166,775 11 Firefighter* 100% 1.00 $ 198,328 12 Firefighter* 100% 1.00 $ 161,751 13 Firefighter* 100% 1.00 $ 170,362 14 Firefighter* 100% 1.00 $ 170,362 15 Firefighter* 100% 1.00 $ 166,775 16 Firefighter* 100% 1.00 $ 178,013 17 Firefighter* 100% 1.00 $ 174,227 18 Firefighter* 100% 1.00 $ 183,537 19 Firefighter* 100% 1.00 $ 153,497 20 Firefighter* 100% 1.00 $ 177,127 21 Arborist Lead Worker* 100% 1.00 $ 135,430 22 Arborist Lead Worker* 100% 1.00 $ 135,430 23 Public Works Maintenance Worker* 100% 1.00 $ 120,688 24 Public Works Maintenance Worker* 100% 1.00 $ 120,688 25 Public Works Maintenance Worker* 100% 1.00 $ 99,439 26 Public Works Maintenance Worker* 100% 1.00 $ 120,688 3,329,302$ SB901 27 Parks Superintendent** 100% 1.00 $ 141,795 28 Accounting Specialist** 10% 0.10 $ 10,273 29 Working Supervisor - Parks** 23% 0.23 $ 34,422 30 Public Works Maintenance Worker** 33% 0.33 $ 85,573 31 Public Works Maintenance Worker** 13% 0.13 $ 34,229 306,293$ CALFIRE/Parks Grant TOTAL 26.89 4,532,995$
*Council Action 9.5(b)- 12.03.2019 -Consider 2019
Redding Electric Utility Wildfire Mitigation Plan
Funding for the Wildfire Prevention and Improved
Response Program, which is primarily Fire and Parks
Division labor.
**Council Action 4.6(a)- 08.04.2025 -Adopt
Resolution Authorizing Submittal of an Application for
the CAL FIRE Wildfire Prevention Grant Program

REU INDIRECT POSITIONS
# of
Positions Position % Paid by REU Full-Time Equivalent FY26 Position Cost Packet Pg. 410
Attachment: REU Indirect Position Increases Since 2016 (6.1--Public Hearing Regarding Electric Utility Salary Benefit *
1/1/2016 190
9/9/2016 188 (2)
Delete: (2) P/T Clerks
Delete: P/T Customer Service Representative
Add: F/T Customer Service Representative
To improve operational efficiencies.
*P/T Clerk-(2)$47,771, P/T CSR-$44,870, F/T CSR-
$106,230 $ (34,182)
1/25/2017 187 (1)
Delete: P/T E/U Distribution Technician
Delete: P/T E/U Engineering Assistant
Add: Electrician
To improve operational efficiencies.
*P/T Distrib. Tech-$76,000(EST.), P/T Eng. Asst.-
$86,000(EST), Electrician-$277,880 $ 115,880 12/13/2017 186 (1)
Converted REU Account Clerk III (Administration) to
Records Clerk in the City of Redding Clerk's Department - Records Management.

Requisition dated 12/13/17. Additional workload related to archiving and imaging REU records.
*Account Clerk III-$105,000(EST.) $ (105,000) 12/20/2017 185 (1) Converted REU Account Clerk III (Customer Service) to Accountant in the City of Redding Finance Department.

Requisition dated 12/20/17. Additional workload related to rebating and accounting functions required of REU
*Account Clerk III-$105,000(EST.) $ (105,000) 6/27/2019 186 1 Add: Utility Field Services Technician
Completed in FY20 budget request. Increased workload
expected of meter modernization and to improve
operational efficiencies.
*Utility Field Services Technician-$144,154 $ 85,717 $ 58,437 $ 144,154 Utility Arborist $ 102,190 $ 70,006 172,196$ Utility Arborist $ 102,190 $ 70,006 172,196$ E/U Analyst - Compliance $ 130,337 $ 66,313 196,650$ E/U Analyst - Finance $ 142,054 $ 70,693 212,747$ E/U Dist. Plnr/Sys.Insp. $ 120,009 $ 60,788 180,797$ EPS - Service Planning $ 181,626 $ 83,138 264,764$ 12/15/2020 Council Action, 9.5(e)
Four positions related to registration as a Transmission Owner/Transmission Operator (TO/TOP).
*E/U Compliance-$196,650, E/U Finance-$212,747,E/U
DPSI-$180,797,
Supervisor Service Planning-$264,764 $ 574,026 $ 280,932 $ 854,958 EPS - Energy Mgmt $ 169,562 $ 86,605 256,167$ EPS - System Ops. $ 218,936 $ 93,473 312,409$ Ops/Compliance Engineer $ 156,180 $ 80,846 237,026$ Ops/Compliance Engineer $ 156,180 $ 80,846 237,026$ 1/19/2021 Council Action, 9.5(c)
Four additional positions related to registration as a
Transmission Owner/Transmission Operator (TO/TOP).
*Supervisor Energy Mgmt.-$256,167, Supervisor Ops-
$312,409, (2) Compliance Engineers-$237,026 $ 700,858 $ 341,770 $ 1,042,628 7/1/2021 195 (1) Delete: GIS Manager - FY22 Budget
Completed in FY22 budget request. To improve
operational Efficiencies
*GIS Manager-$233,375 $ (233,375)
Linemen-Certified $ 169,816 $ 95,115 264,931$ Linemen-Certified $ 169,816 $ 95,115 264,931$ Linemen-Certified $ 169,816 $ 95,115 264,931$ Linemen-Certified $ 169,816 $ 95,115 264,931$ 8/17/2021 Council Action, 9.5(d)
The Council was asked to accept the Five-Year Capital
Improvement Plan by Ulteig, as well as the creation of
four additional line personnel positions.
*Linemen-Certified-(4)$264,931 $ 679,264 $ 380,460 $ 1,059,724 Electrical Engineer $ 176,550 $ 82,375 258,925$ Electrical Engineer $ 176,550 $ 82,375 258,925$ E/U Senior Project Engineer $ 199,035 $ 88,825 287,860$ E/U Engineering Assistant I $ 111,100 $ 57,804 168,904$ Electric Manager - Resources $ 228,448 $ 96,922 325,370$ Electric Manager - Technology $ 230,277 $ 109,970 340,247$ 4/5/2022 Council Action, 9.15(a)
Six additional positions related to the Five-Year Capital Improvement Plan.
*Electrical Engineers-(2)$258,925, Senior Project
Engineer-$287,860, Engineering Asst.-$168,904,Electric
Manager Resources-$325,370, Electric Manager
Technology-$340,247 $ 1,121,960 $ 518,271 $ 1,640,231 FY 2023 205 0 No Position Increases in FY 2023 $ - FY 2024 205 0 No Position Increases in FY 2024 $ - FY 2025 205 0 No Position Increases in FY 2025 $ - FY 2026 205 0 No Position Increases in FY 2026 $ - TOTAL 4,724,410$
5/5/2020 188 2 Add: (2) Utility Arborists
FY26 Position Costs
$ 204,380 $ 140,012 344,392$

REU POSITION HISTORY
Date Position
Count
+ / - Description of Position Count Adjustment Justification 4/5/2022 205 6
Add: (2) Electrical Engineers
Add: Electric Utility Senior Project Engineer
Add: Electric Utility Engineering Assistant I
Add: Electric Manager - Resources
Add: Electric Manager - Technology
8/17/2021 199 4 Add: (4) Linemen-Certified
* NOTE: Benefit costs include medical, dental, vision, and retirement contributions. Retirement expenses reflect both the current cost of benefits earned by employees and required payments toward unfunded liabilities from prior years. Increases in health insurance and pension costs reflect broader statewide trends affecting public agencies, not unique local policy changes.
5/5/2020 Council Action, 4.15(a)
Two Utility Arborist positions to perform necessary line clearance work.
*Utility Arborist-(2)$172,196
1/19/2021 196 4
Add: Electric Program Supervisor - Energy Management
Add: Electric Program Supervisor - System Operations
Add: (2) Operations/Compliance Engineers
12/15/2020 192 4
Add: E/U Analyst Compliance
Add: E/U Analyst Finance
Add: E/U Distribution Planner/System Inspector
Add: Electric Program Supervisor - Service Planning

9.15(a) 6 New
Positions Related to Capita

4.15(a)--Adjust
IBEW – Electric Salary Sc

9.5(e) TO.TOP
Additional 4 Positions - 12

9.5(c) Creation of
Four Additional Positi

9.5(d)Resolution
No 6- 08.17.2021.pdf
Packet Pg. 411
Attachment: REU Position Increases Since 2016 (6.1--Public Hearing Regarding Electric Utility Rate

Economics | Strategy | Stakeholders | Sustainability www.newgenstrategies.net
225 Union Boulevard
Suite 450
Lakewood, CO 80228
Phone: (720) 633-9514

February 25, 2026
via email

Holly Spaner
Electric Manager – Financial
Redding Electric Utility
3611 Avtech Parkway
Redding, CA 96002

Subject: 2026 Rate Study Results and Recommendations
Dear Ms. Spaner:

In July 2025, the City of Redding (City) retained NewGen Strategies and Solutions, LLC (NewGen) to update the 2024 Cost of Service (COS) and Rate Design Study. This report summarizes the analyses conducted by NewGen on behalf of Redding Electric Utility (REU) in support of the updated COS and rate design efforts, referred to herein as the “2026 Rate Study.”
The 2026 Rate Study evaluated the total cost of providing electric service, allocated those costs among the various customer classes, and developed rate designs for existing and projected customer classes, as described in this report . The total cost of providing services primarily consists of operations and maintenance (O&M) expenses, debt service, and capital outlays required to operate and maintain the system with high reliability. The 2026 Rate Study included an analysis of projected revenue requirements, an unbundled COS analysis based on the forecasted expenses, a rate revenue analysis, and the development of proposed new electric rates. The Test Year (TY) for this 2026 Rate Study was defined as the average for fiscal year (FY) 2026 through 2029 (a four-year average), which is consistent with the four- year rate plan as proposed by REU.

Summary of Findings

1. The COS for the TY is approximately $ 157 million. The projected rate revenue for the TY at current rates is approximately $146.7 million, representing a shortfall of $10.5 million, or approximately a 7% systemwide revenue deficiency.

2. Distribution expenses in the 2026 Rate Study are projected to increase by approximately $7 million over the TY period, primarily due to increased investment required to maintain REU’s aging distribution infrastructure.

3. The purchased power expense in the 2026 Rate Study is projected to increase by approximately $14 million over the TY period, primarily due to rising wholesale energy costs and overall increases in market prices. These increases are largely driven by the expiration of the Big Horn wind contract and the addition of new battery storage and solar renewable projects coming online in FY 2028.

4. The COS results indicate that certain customer classes are projected to under recover their TY COS, while others are projected to over recover. Under current rates, the Residential and Small Commercial classes are projected to under recover their associated costs by approximately 19 % and 7 %, Docusign Envelope ID: DFAF6B5F-7EE3-481A-B145-933121AA50BB Packet Pg. 412
Attachment: REU_Letter Report_Final (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Ms. Holly Spaner
February 25, 2026

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REU_Letter Report_Final_02.25.26
respectively. Conversely, the Large Commercial class is projected to over recover its associated costs by approximately 19% in the TY.

5. REU is planning to implement a four-year rate plan that results in a 4.5% system-level annual revenue increase, beginning April 1, 2026, and continuing January 1, 2027 ; January 1, 2028; and January 1, 2029. Rate adjustments will be structured such that customer classes currently under recovering their costs, namely Residential and Small Commercial, will experience relatively larger increases, while the Large Commercial class, which is currently over recoverin g, will experience comparatively smaller increases.

Usage Characteristics by Class – TY
The COS analysis examines detailed customer usage characteristics by customer class. Table 1 summarizes these characteristics on a TY basis for the customer classes currently served by REU, including projected retail sales ( provided in megawatt-hours [MWh], which is equivalent to 1,000 kilowatt-hours [kWh]), number of customers in each class , and estimated contribution to peak demand based on the four coincident peak (4CP) methodology utilized for the 2026 Rate Study.

Peak demand represents the highest level of electricity usage in each period (month), which is measured in kilowatts (kW). The 4CP demand measures the contribution of each customer class to the system-level monthly peak for the four highest demand months of the year. This 4CP demand measurement is used to allocate fixed costs associated with serving customers during the system peaks.

Energy and customer p rojections were provided by Itron, a technology company that provides electric load forecasts for utilities, among other services. The class-level 4CP demand was based on a regression analysis of REU’s distribution feeder data.

Table 1
TY Summary of Electric Utility Characteristics by Customer Class (1) Class/Service (2)
Retail
Sales (MWh)
Number of
Customers
Contribution Peak
Demand (kW) (3)
Residential Service 376,277 39,330 472,881
Small Commercial 85,720 6,236 73,636
Large Commercial 296,268 748 192,821
Fixed Usage and Lighting (4) 434 361 134
Total (5) 758,698 46,675 N/A
(1) Based on monthly projections provided by Itron.
(2) Multi-Family Residential (E1M), Residential Master-Metered (E5), and Residential Lifeline (E1LP) are included in the Residential Class above. (3) Contribution to Peak Demand based on 4CP methodology. (4) Lighting includes city-owned and customer-owned streetlights, which are typically not on during the summer peak. (5) Numbers may not add due to rounding.

Docusign Envelope ID: DFAF6B5F-7EE3-481A-B145-933121AA50BB Packet Pg. 413
Attachment: REU_Letter Report_Final (6.1--Public Hearing Regarding Electric Utility Rate Increases and Adjustments) Ms. Holly Spaner
February 25, 2026

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REU_Letter Report_Final_02.25.26
REU System Revenue Requirement
The TY annual revenue requirement for the 2026 Rate Study is projected to be $157,230,155. A summary of the accounts included in the TY revenue requirement is provided in Table 2. Please note that this figure does not include capital expenditures, which will be funded via REU’s 2025 debt issuance.

Table 2
REU System Revenue Requirement
Line Item
FY 2025
Actuals Adjustment TY Value
Total O&M Expenses $138,487,381 $7,152,559 $145,639,940 Total Debt Service $14,762,143 $4,177,027 $18,939,170 Total Taxes Other than Income $6,614,200 $164,637 $6,778,837 Total Capital Paid from Current Earnings $2,700,000 $760,000 $3,460,000 Total Less Other Income (1) ($29,330,424) $11,742,632 ($17,587,793) Total (2) $133,233,300 $23,996,856 $157,230,155
(1) Includes other revenues and adjustments.
(2) Numbers may not add due to rounding.

The following summarizes the COS methodology utilized in the 2026 Rate Study and applied to the REU system revenue requirement to determine the COS results, as presented herein.

1. Functionalization and Sub-functionalization of Costs – The revenue requirement was assigned to the particular function or subfunction of the utility . Fully integrated utilities like REU typically have production, transmission, distribution, and customer services functions . Subfunctions may include different sources of power supply (generation infrastructure, purchased power, etc.) and transmission infrastructure at different voltage levels . Distribution subfunctions may include distribution infrastructure by voltage, metering, billing, collection, etc.

2. Classification of Costs – Once costs were functionalized, they were classified based on their underlying nature. Of particular importance is the determination of fixed versus variable costs. Fixed costs remain a financial obligation of the utility regardless of the amount of energy produced , whereas variable costs fluctuate based on system energy requirements. Further, fixed and variable costs are associated with utility requirements to meet customer demand, energy, and customer service needs.

3. Allocation of Costs – Once costs were classified, they were allocated to the various customer classes.

Allocation factors align with cost classification . For example, demand-related costs are allocated on measures of class demand such as class contribution to the system peak. Energy allocation factors are based on the energy consumed by customers. Customer allocation factors are based on the number of customers within each class.

COS Results
The results of the COS analysis provided a detailed assessment of the costs required to serve each of the customer classes. These customer class costs were unbundled into utility functions and classified into demand, energy, and customer components. Customer class costs were compared to the projected Docusign Envelope ID: DFAF6B5F-7EE3-481A-B145-933121AA50BB Packet Pg. 414
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revenues under current rates to determine if current rates are sufficient to meet costs. Upon completion, the COS serves as the basis for the proposed rate design.

A comparison of the TY revenue requirement by class is shown in Table 3.

Table 3
TY Revenue Requirement by Class (1)
Class/Service
TY Revenue
Requirement
Residential Service $90,379,529
Small Commercial $20,901,707
Large Commercial $45,457,972
Fixed Usage and Lighting (2) $490,947
Total (3) $157,230,155
(1) Allocated share of TY revenue requirement by customer class/group. (2) Lighting includes city-owned and customer-owned streetlights. (3) Numbers may not add due to rounding.

The COS analysis resulted in the determination of cost-based “bundled” service charges consisting of three components: a Customer Charge, a Demand Rate, and an Energy Rate.

The Customer Charge is designed to recover costs associated with serving customers, including metering, billing, customer service, and other customer -related expenses. The Customer Charge derived from the COS analysis is synonymous with the existing Network Access Charge in REU’s current tariffs.

The Demand Rate is intended to recover fixed costs associated with the production and delivery of power for customer classes equipped with demand meters . For REU, this currently applies to the Large Commercial customer class.

For customer classes that do not incur a Demand Charge, production -related fixed costs are recovered through the Energy Rate, while distribution -related fixed costs are recovered through the Customer Charge.

A summary of the bundled COS charges is presented in Table 4.

Table 4
Bundled COS
Class/Service
Residential
Service
Small
Commercial
Large
Commercial Fixed Usage (1)
Customer Charge ($/customer-month) (2) $74.36 $112.01 $84.20 $3.16 Demand Rate ($/kW) N/A N/A $24.34 N/A
Energy Rate ($/kWh) (3) $0.1420 $0.1465 $0.0669 $0.1266 (1) Fixed Usage class achieves cost recovery via a minimum monthly bill charge. (2) Distribution demand-related costs are recovered in the Customer Charge for the Residential, Small Commercial, and Fixed Usage customer classes but are recovered in the Demand Rate for the Large Commercial Class. (3) Production demand-related costs are recovered in the Energy Rate for the Residential, Small Commercial, and Fixed Usage customer classes but are recovered in the Demand Rate for the Large Commercial Class.

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REU Revenue Shortfall/Reserve Impact Analysis
REU intends to invest approximately $53 million into revitalizing its aging infrastructure during the TY, the majority of which is funded by REU’s debt issue in 2025 and recovered through rates via the debt service payments. REU’s financial management policy require s that REU maintain a minimum cash reserve balance which exceeds 75 days of working capital.

Based on financial projections through FY 2029, 4.5% annual revenue increases are required for REU to maintain its cash reserve minimum balance target of 75 days of working capital. This was determined by forecasting REU’s expenses and debt issuances through FY 2029 and determining the minimum rate increases which resulted in maintaining at least 75 days of cash on hand (DCOH). The cash flow forecast reflecting 4.5% annual revenue increases beginning April 1, 2026, is included in the Operating Revenues shown in Table 5. Table 5 also includes actual ending cash reserves for FY 2025 and projected ending cash reserves for FYs 2026–2029.

Table 5
Cash Flow Forecast (1)

FY 2025
Actual
FY 2026
Forecast
FY 2027
Forecast
FY 2028
Forecast
FY 2029
Forecast
Operating Revenues $172,501,421 $164,464,285 $172,019,873 $180,295,889 $190,923,213 Operating Expenses (2) ($138,487,381) ($135,918,142) ($138,600,208) ($149,494,798) ($158,555,844) Net Revenues $34,014,040 $28,546,143 $33,419,665 $30,801,091 $32,367,369 Debt Service Expense ($14,762,143) ($18,633,795) ($19,493,045) ($18,539,545) ($19,090,295) In-Lieu of Taxes, Rolling Stock,
Major Maint.
($9,314,200) ($10,854,600) ($9,951,800) ($10,000,570) ($10,148,380) Balance Available for Capital
Expenditures
$9,937,697 ($942,252) $3,974,820 $2,260,976 $3,128,694

Capital Expenditures ($15,996,546) ($14,062,000) ($11,610,000) ($9,960,000) ($8,750,000) Net Change in Cash ($6,058,849) ($15,004,252) ($7,635,180) ($7,699,024) ($5,621,306)

Debt Issuance $19,761,492 $19,303,051 $11,610,000 $9,960,000 $8,750,000 Cash Reserves (End of Year-
EOY) (3)
$45,230,405 $49,529,203 $53,504,023 $55,765,000 $58,893,694 Days of Cash on Hand (4) 117 128 138 134 133
(1) Numbers may not add due to rounding.
(2) Non-fuel O&M/administrative and general (A&G) expenses were forecasted at 90% of their projected budgets to keep in line with the historical trend. City of Redding customer/field services expenses were prorated proportionally to REU’s contribution. (3) EOY reserves are equal to previous EOY balance plus net change in cash plus debt issuance. (4) Target minimum days of cash is 75 days.

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Figure 1. Rate Increases versus DCOH Projection
Figure 1 provides a projection of DCOH using constant system percentage revenue increases from FY 2025 actual (FY25A) and for each forecasted FY. The DCOH was calculated by dividing cash reserves at the end of the F Y by the average operating expenses per day . As discussed and as shown in Figure 1, annual system-level revenue increases of at least 4% are necessary to maintain REU’s cash reserve balance target minimum through FY 2029.

Rate Design by Class
The following sections describe the proposed changes to the existing REU rates by class. REU intends to increase its annual system revenue by 4.5% for each year of the rate plan (2026 is prorated for the April 1 start date). The highest percentage increases are proposed for classes that are expected to under recover their costs throughout the TY . REU proposes to implement the FY 2026 rate increase effective April 1, 2026. Following this initial implementation date, REU proposes to transition to a calendar year schedule, with future rate adjustments going into effect on January 1 of each year (2027, 2028, and 2029).

Residential (E1)
The results of the COS study indicate that the Residential Class is expected to under collect its associated costs by approximately 19% during the TY without a rate change. The proposed rate changes are intended to reduce the class-level under recovery of costs. For Residential rates (E1), rate changes will target a class- level revenue increase of 5.2% per calendar year in 2026 (prorated) through 2029.

This revenue change is proposed to be collected by primarily increasing the Energy Charge . The Energy Charge is proposed to increase from $0.1492 per kWh to $0.1563 per kWh on April 1, 2026, with additional increases to $0.1637 per kWh in 2027, $0.1723 per kWh in 2028, and $0.1814 per kWh in 2029.

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An increase in the Network Access Charge from $40.00 per month to $41.00 per month is also proposed, effective April 1, 2026. Subsequent adjustments result in proposed Network Access Charges of $42.00, $43.00, and $44.00 per month effective January 1, 2027; January 1, 2028; and January 1, 2029, respectively.

Table 6 provides a summary of the proposed rate changes to the Residential (E1) rate.

Table 6
Proposed Residential Rates (E1) and COS Analysis Results Rate Component Current Rate
Proposed
4/1/26
Proposed
1/1/27
Proposed
1/1/28
Proposed
1/1/29 COS (1)
Customer Charge ($/meter) $40.00 $41.00 $42.00 $43.00 $44.00 $74.36 Energy Charge ($/kWh) $0.1492 $0.1563 $0.1637 $0.1723 $0.1814 $0.1420 (1) Distribution demand-related costs are included in the Network Access Charge, and Production Demand-related costs are included in the Energy Charge.

Small Commercial (E2)
The results of the COS study indicate that the Small Commercial Class is expected to under collect its associated costs by approximately 7% during the TY without a rate change . The proposed rate changes are intended to reduce the class -level under recovery of costs . For Small Commercial rates (E2), rate changes will target a class -level revenue increase of 5.1 % per calendar year in 2026 (prorated) through 2029.

The Small Commercial (E2) Energy Charge is proposed to increase from $0.1649 per kWh to $0.1725 per kWh on April 1, 2026, with additional increases to $0.1804 per kWh in 2027, $0.1885 per kWh in 2028, and $0.1970 per kWh in 2029.

An increase in the Network Access Charge from $70.00 per month to $72.00 per month is proposed for April 1, 2026. Subsequent increases to the Network Access Charge result in proposed charges of $74.00, $77.00, and $80.00 per month effective January 1, 2027; January 1, 2028; and January 1, 2029, respectively.

Table 7 provides a summary of the proposed rate changes to the Small Commercial (E2) rate.

Table 7
Proposed Small Commercial Rates (E2) and COS Analysis Results Rate Component
Current
Rate
Proposed
4/1/26
Proposed
1/1/27
Proposed
1/1/28
Proposed
1/1/29 COS (1)
Customer Charge ($/meter) $70.00 $72.00 $74.00 $77.00 $80.00 $112.01 Energy Charge ($/kWh) $0.1649 $0.1725 $0.1804 $0.1885 $0.1970 $0.1465 (1) Distribution demand-related costs are included in the Network Access Charge, and Production Demand-related costs are included in the Energy Charge.

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Large Commercial (E7 & E8)
Large Commercial customers (E7 or E8) are customers who had a demand greater than 25 kW for 6 months of the preceding 12 -month period or who exceed 75 kW for 1 month during that period . For the Large Commercial Class (E7 and E8), rate changes will target a class-level revenue increase of 4.7% per calendar year in 2026 (prorated) through 2029.

This rate change will be made primarily by increasing the Energy Charge while maintaining the Network Access Charge as it exists and gradually increasing the Demand Charge. The Network Access Charge will remain at $95.00 per month throughout the four-year rate plan period (2026–2029).

The Energy Charge is proposed to increase from $0.1086 per kWh to $0.1158 per kWh on April 1, 2026, with additional increases to $0.1234 per kWh in 2027, $0.1308 per kWh in 2028, and $0.1387 per kWh in 2029. The Demand Charge is proposed to remain at $21.50 per kW in 2026 and 2027 and to increase to $21.75 per kW in 2028 and $22.00 per kW in 2029.

Table 8 provides a summary of the proposed rate changes to the Large Commercial rate (E7 & E8).

Table 8
Proposed Large Commercial Rates (E7 & E8) and COS Analysis Results Rate Component
Current
Rate
Proposed
4/1/26
Proposed
1/1/27
Proposed
1/1/28
Proposed
1/1/29 COS
Customer Charge ($/meter) $95.00 $95.00 $95.00 $95.00 $95.00 $84.20 Energy Charge ($/kWh) $0.1086 $0.1158 $0.1234 $0.1308 $0.1387 $0.0669 Demand Charge ($/kW) $21.50 $21.50 $21.50 $21.75 $22.00 $24.34

Lighting Rates (Proposed)
The proposed Lighting rate adjustment consists of a 4.5% increase per calendar year. This adjustment aligns with the systemwide revenue increases planned by REU, which ensures that the Lighting class continues to recover its share of increasing system costs.

Conclusions
Based on the results of the analysis completed for th e 2026 Rate Study, NewGen presents the following conclusions:
 REU seeks to advance the City’s mission to provide high-quality and reliable electric utility services to its customers. This mission is detailed in the infrastructure improvements and upgrades identified in REU’s capital plan . REU’s current rates and rate structures are insufficient to provide the revenue necessary to support these required system improvements . Annual 4.5% system-level revenue increases are required to fund the capital plan while simultaneously meeting REU’s DCOH requirement.
 REU requires additional revenue to meet its financial obligations, maintain service reliability, and support planned system investments. As a result, changes to retail rates are necessary to meet these revenue needs.

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Recommendations
Based on the conclusions and supporting analyses presented herein, NewGen makes the following recommendations:
 REU should adopt retail rates as described and proposed in this report.  REU should implement a four-year rate plan to provide revenue sufficiency and rate stability.  REU should continue to monitor cash flow and financial performance to ensure compliance with established cash metrics, including DCOH targets.
 REU should ensure adequate capital funding to support future investments, including anticipated 2028/2029 power costs.
 REU should continue to invest in infrastructure, equipment, and personnel to ensure its ability to maintain a reliable power supply.

We appreciate the opportunity to be of service to you and REU . If you have any questions regarding this report, please contact me directly at (720) 259-1762 or [email protected].

Sincerely,
NewGen Strategies and Solutions, LLC

Scott Burnham
Partner
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CITY OF REDDING

REPORT TO THE CITY COUNCIL

Recommendation

Pursuant to City Council direction on February 17, 2026, staff presents the following options for Council consideration:
(1) Option A – Introduce Ordinance for Kool April Nites Cruise Event If the City Council desires to proceed with temporarily authorizing a Hilltop Drive Entertainment Zone for the Kool April Nites Cruise event on April 24, 2026, authorize and approve the following actions:
(a) Offer Uncodified Ordinance amending Redding Municip al Code Title 6 (Business Taxes, Licenses and Regulations ) Chapter 6.42 (Entertainment Zone) by amending Section 6.42 for first reading by title only and waive the full reading;
(b) Authorize the City Attorney to prepare and the City Clerk to publish a summar y of the ordinance; and
(c) Find that the adoption of the ordinance is exempt from environmental review pursuant to California Environmental Quality Act guidelines 15060(c)(2) and 15061(b)(3) and further find that the passage of the ordinance will have no foreseeable direct or indirect physical change in the environment; or (2) Option B – Provide Alternative Direction
Provide direction to staff and continue this item to a future meeting for further consideration and discussion for the event next year.

Fiscal Impact

The Hilltop Entertainment Zone has an estimated, initial fiscal impact of not more than $5,000 for signage materials. Staff costs associated with making and installing signs are included within the current Public Works budget. Staff time from the City Manager’s office, Redding Police Department, Public Works, and Community Services will be required to provide background to stakeholders and the public, in the form of educational meetings, container distribution logistics MEETING DATE: March 3, 2026
ITEM NO. 9.1(a)
FROM:

***APPROVED BY***

[email protected]

[email protected]
SUBJECT: 9.1(a)--Consider Uncodified Ordinance amending Redding Municipal Code Title

6.42 (Entertainment Zones) to add the Hilltop Entertainment Zone.

Jason Gibilisco, Management
Assistant to the City Manager
Packet Pg. 421
Report to Redding City Council February 26, 2026
Re: 9.1(a)--Consider Ordinance regarding an Entertainment Zone along Hilltop Drive Page 2

and coordination, and enforcemen t needs. Increased business activity within the Hilltop Entertainment Zone could potentially stimulate more taxable sales, offsetting the initial costs.

Alternative Action

The City Council (Council) could decline to pursue an Entertainment Zone for Hilltop Drive at this time ; direct staff to modify the Entertainment Zone parameters; or provide staff alternate direction.

Background/Analysis

Senate Bill 969, effective January 1, 2025, authorizes California cities to create designated public "entertainment zones," where individuals, aged 21 and over, may legally possess and consume open containers of alcoholic beverages purchased from licensed participating businesses. The goal of this legislation is to stimulate local economies, enhance cultural and social activities, and promote downtown vibrancy through well-regulated public spaces.

On September 2, 2025, Redding City Council adopted a Downtown Entertainment Zone, which became active in December 2025. The Downtown Entertainment Zone is active from 10 :000 a.m. to 10:00 p.m. and is active seven days a week. Various businesses are taking part in the Entertainment Zone and the consensus is that it has been overall a success for downtown.

On February 17, 2026, City Council directed staff during Agenda Item 12, Suggestions from Council Members relative to potential topics for future City Council Meetings, to bring back an ordinance for Hilltop Drive that can be activated for the Kool April Nites Cruise. Staff met with Redding Police Department and the City Attor ney’s Office and collectively identified the following parameters which are proposed in the ordinance:

• Geographic Boundaries: The proposed Entertainment Zone is bordered by Cypress Ave to the South and the Highway 44 over crossing to the North. Participating businesses must be located on Hilltop Drive between Cypress Ave nue and the Highway 44 overcrossing.
• Days of Operation: The Hilltop Entertainment Zone would operate for a single day for the Kool April Nites Cruise on April 24, 2026.
• Hours of Operatio n: Alcohol consumption would be permitted from 6:00 p.m. to 9:00 p.m., allowing for viewers of the cruise to enjoy early set up and early evening enjoyment while minimizing late-night disturbances.
• Allowable Open Alcoholic Beverage Containers: The City w ill determine a standardized container for alcohol consumption within the zone. At present, staff is considering a clear plastic cup which is in line with the California Department of Alcoholic Beverage Control ( ABC) Guidelines, affixed with a recognizable sticker or marking, issued by licensed participating vendors, to easily identify compliant containers.

This would be the same requirement as the Downtown Entertainment Zone. • Alcohol Type: The type of alcoholic beverage permitted will not be restricted, a llowing beer, wine, and spirits to be served in accordance with individual business licenses and state law.
• Signage: The Hilltop Entertainment Zone boundaries will be clearly marked by visible signage as necessary. The signage will instruct patrons not to carry alcoholic beverages outside the zone.
• Post Event Review: The operation of the Hilltop Entertainment Zone will be reviewed after the event and brought back to City Council for changes and/ or updates.

Packet Pg. 422
Report to Redding City Council February 26, 2026
Re: 9.1(a)--Consider Ordinance regarding an Entertainment Zone along Hilltop Drive Page 3

Staff anticipates challenges should this ordinance be adopted. The Hilltop Entertainment Zone is limited to Hilltop Drive only. As t he cruise extends beyond Hilltop Drive, staff anticipates potential confusion among patrons regarding where container consumption is permitted. It is likely that attendees may reasonably assume the entire cruise route is the entertainment zone.

The Cruise has been historically an alcohol -free and family friendly event. Designating a Hilltop Entertainment Zone will require more communication with the public to provide ba ckground on the specifics of the zone.

Generally, when an Item 12 is presented, staff returns at a subsequent meeting to provide detailed background and a well formulated recommendation for City Council’s consideration and direction. Due to time constraints associated with the adoption of an ordinance, this step has been eliminated as the ordinance must be adopted “as is” in order to be in effect for the Kool April Nites Cruise on Friday, April 24, 2026.

There are also challenges with providing informatio n in a timely manner to potential participating vendors and businesses located in the proposed Hilltop Entertainment Zone .

Businesses choosing to participate must apply to ABC as a participating business. Due to the event date, being less than two months a way, it may result in some businesses not applying and/or receiving approval to participate in time for this event

The Redding Police Department (RPD) has indicated that all available officers will be assigned to traffic control, event operations, and co mmand post staffing during the cruise and will have extremely limited availability to provide proactive enforcement.

If the ordinance is adopted, staff will work to conduct outreach with Hilltop Drive businesses, RPD, ABC, and community members to present information regardi ng zone logistics , participating vendor requirements, and ensure alignment with public safety and operational needs. Businesses will need time to purchase the required cups, stickers, and wristbands.

Environmental Review

This action is not considered a project under the California Environmental Quality Act (CEQA) and is therefore exempt from CEQA review at this stage.

Council Priority/City Manager Goals

• Economic Development - “Facilitate and become a catalyst for economic developm ent in Redding to create jobs, retain current businesses and attract new ones, and encourage investment in the community.

• Government of the 21 st Century – “Be relevant and proactive to the opportunities and challenges of today’s residents and workforce. Anticipate the future to make better decisions today.

Attachments
Hilltop Entertainment District Map
Entertainment Zone Ordinance Draft
Packet Pg. 423
Packet Pg. 424
Attachment: Hilltop Entertainment District Map (9.1(a)--Consider Ordinance regarding an Entertainment Zone along Hilltop Drive)

DRAFT NEW ORDINANCE

ORDINANCE NO.______

AN UNCODIFIED ORDINANCE OF THE CITY OF REDDING

ESTABLISHING A TEMPORARY ENTERTAINMENT ZONE ON

PORTIONS OF HILLTOP DRIVE

WHEREAS, Senate Bill 969 (2024) authorizes local jurisdictions to create “entertainment zones” where people may buy open container drinks (alcoholic drinks "to -go") from local bars, restaurants, wineries, and breweries and enjoy them outside in common spaces such as plazas, sidewalks, and streets during certain hours for the purposes of creating active, commercial corridors, to stimulate the economy; and

WHEREAS, the Redding City Council has previously adopted Chapter 6.42 of the Redding Municipal Code creating a Downtown Entertainment Zone; and

WHEREAS, the Redding City Council wishes to create a temporary entertainment zone along a portion of Hilltop Drive between the hours of 6 P.M. and 9 P.M. on April 24 th, 2026, in order to allow the consumption alcoholic drinks from local bars, restaurants, wineries, and breweries during a portion of the Kool April Nights event;

NOW THEREFORE, THE CITY COUNCIL OF THE CITY OF REDDING DOES ORDAIN AS FOLLOWS:

Section 1. There is hereby created a Temporary Entertainment Zone on all public streets, public rights -of-way, alleys and sidewalks in front of storefronts, and all establishments holding permits or licenses from ABC that are located within the delineated area in Exhibit A.

This Temporary Entertainment Zone shall exist only between the hours of 6 P.M. and 9 P.M. on April 24 th, 2026. The following types of alcoholic beverages are permitted within the Temporary Entertainment Zone:

(1) Beer;
(2) Wine; and
(3) Mixed spirits

All open alcoholic beverages consumed in the Temporary Entertainment Zone shall be purchased only from a premises located within the Temporary Entertainment Zone that is authorized under California Business and Professions Code Section 23357, 23358, or 23396, as may be amended from time to time, to permit consumers to leave the premises with open containers of alcoholic beverages for consumption off the premises, or an organization that is authorized by ABC special event permit or license to make such sales within the Downtown Entertainment Zone.

Packet Pg. 425
Attachment: Entertainment Zone Ordinance Draft (9.1(a)--Consider Ordinance regarding an Entertainment Zone along Hilltop Drive)

Open alcoholic beverages must be kept within a standardized open container complying with ABC’s guidelines and approved by the City Manager after coordination with Redding Police Department Chief . The container will be easily identifiable and affixed with a recognizable marking or sticker issued by a licensed participating vendor in the Downtown Entertainment Zone.

No alcoholic beverages purchased at a licensed premises may leave the premises in an open glass or metal container for consumption in the Downtown Entertainment Zone.

Section 2. The Council hereby finds and determines that the enactment of this Ordinance is exempt from the requirements of the CEQA pursuant to the “common sense” exemption (14 CCR Section 15061(b)(3) of the CEQA Guidelines, as it can be seen with certainty that there is no possibility that the adoption of the Ordinance will have a significant effect on the environment.

Section 3. Severability. If any provision of this Ordinance or the application thereof to any person or circumstances is held invalid, the remainder of the Ordinance and the application of such provision will remain in effect to the extent permitted by law.

Section 4. This Ordinance shall take effect thirty (30) calendar days after the date of its adoptio n, and the City Clerk shall certify to the adoption thereof and cause publication according to law.

I HEREBY CERTIFY the foregoing ordinance was introduced by the Council of the City of Redding at a regular meeting on the 3rd day of March, 2026 and passed and adopted on the 17th of March, 2026, by the following roll call votes:

AYES: COUNCIL MEMBERS:

NOES: COUNCIL MEMBERS:

ABSENT: COUNCIL MEMBERS:

ABSTAINING: COUNCIL MEMBERS:

___________________________________
MIKE LITTAU, Mayor

ATTEST: FORM APPROVED:

_____________________________ ___________________________________ SHARLENE TIPTON, City Clerk CHRISTIAN M. CURTIS, City Attorney Packet Pg. 426
Attachment: Entertainment Zone Ordinance Draft (9.1(a)--Consider Ordinance regarding an Entertainment Zone along Hilltop Drive)

Redding City CouncilMarch 3, 2026

Redding City Council
March 3, 2026